Table of ContentsIndex to Financial Statements

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia~~STATEMENTS OF OPERATIONS

For the Years Ended December 31, 2019, 2018, and 2017

Mississippi Power Company ~~2016~~2019 Annual Report

~~Other Income (Expense), Net~~

In 2016, other income (expense), net decreased $23 million compared to the prior year primarily due to decreases of $8 million in customer contributions in aid of construction, $6 million in wholesale operating fee revenue, and $4 million in gains on purchases of state tax credits.

In 2015, other income (expense), net increased $38 million compared to the prior year primarily due to increases of $9 million in wholesale operating fee revenue and $9 million in customer contributions in aid of construction, as well as a $9 million decrease in donations.

~~Income Taxes~~

Income taxes increased $11 million, or 1.4%, in 2016 compared to the prior year primarily due to higher pre-tax earnings, partially offset by decreases in non-deductible book depreciation and increased state investment tax credits.

Income taxes increased $40 million, or 5.5%, in 2015 compared to the prior year primarily due to higher pre-tax earnings and the recognition in 2014 of tax benefits related to emissions allowances and state apportionment.

~~Effects of Inflation~~



	2019			2018			2017
	(in millions)
Operating Revenues:
Retail revenues	$	877		$	889		$	854
Wholesale revenues, non-affiliates	237			263			259
Wholesale revenues, affiliates	132			91			56
Other revenues	18			22			18
Total operating revenues	1,264			1,265			1,187
Operating Expenses:
Fuel	407			405			395
Purchased power	20			41			25
Other operations and maintenance	283			313			291
Depreciation and amortization	192			169			161
Taxes other than income taxes	113			107			104
Estimated loss on Kemper IGCC	24			37			3,362
Total operating expenses	1,039			1,072			4,338
Operating Income (Loss)	225			193			(3,151		)
Other Income and (Expense):
Allowance for equity funds used during construction	1			—			72
Interest expense, net of amounts capitalized	(69		)	(76		)	(42		)
Other income (expense), net	12			17			1
Total other income and (expense)	(56		)	(59		)	31
Earnings (Loss) Before Income Taxes	169			134			(3,120		)
Income taxes (benefit)	30			(102		)	(532		)
Net Income (Loss)	139			236			(2,588		)
Dividends on Preferred Stock	—			1			2
Net Income (Loss) After Dividends on Preferred Stock	$	139		$	235		$	(2,590	)

The ~~Company is subject to rate regulation that is generally based on the recovery~~accompanying notes are an integral part of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years.these financial statements.

~~FUTURE EARNINGS POTENTIAL~~

~~General~~

The Company operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located in the State of Georgia and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Georgia PSC under cost-based regulatory principles. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Utility Regulation" herein and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information about regulatory matters.

The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's business of selling electricity. These factors include the Company's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. The completion and subsequent operation of ongoing construction projects, primarily Plant Vogtle Units 3 and 4, also are major factors. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and higher multi-family home construction. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability of nuclear PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on the Company's financial statements.

~~Environmental Matters~~

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. The Company's Environmental Compliance Cost Recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal

Table of ContentsIndex to Financial Statements

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia~~STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2019, 2018, and 2017

Mississippi Power Company ~~2016~~2019 Annual Report

regulations. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See Note 3 to the financial statements under "Environmental Matters" for additional information.

~~Environmental Statutes and Regulations~~

~~General~~

The Company's operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; the Migratory Bird Treaty Act; the Bald and Golden Eagle Protection Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2016, the Company had invested approximately $5.2 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of approximately $0.2 billion, $0.3 billion, and $0.4 billion for 2016, 2015, and 2014, respectively. The Company expects that capital expenditures to comply with environmental statutes and regulations will total approximately $1.2 billion from 2017 through 2021, with annual totals of approximately $0.4 billion, $0.3 billion, $0.1 billion, $0.2 billion, and $0.2 billion for 2017, 2018, 2019, 2020, and 2021, respectively. These estimated expenditures do not include any potential capital expenditures that may arise from the EPA's final rules and guidelines or future state plans that would limit CO₂ emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. The Company also anticipates costs associated with ash pond closure and ground water monitoring under the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are reflected in the Company's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Cost of Removal" for additional information.



	2019		2018			2017
	(in millions)
Net Income (Loss)	$	139	$	236		$	(2,588	)
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(1), and $(1), respectively	—		(1		)	(1		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, and $1, respectively	1		1			1
Total other comprehensive income (loss)	1		—			—
Comprehensive Income (Loss)	$	140	$	236		$	(2,588	)

The Company's ultimate environmental compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations, including the environmental regulations described below; the time periods over which compliance with regulations is required; individual state implementation of regulations, as applicable; the outcome of any legal challenges to the environmental rules; any additional rulemaking activities in response to legal challenges and court decisions; the cost, availability, and existing inventory of emissions allowances; the impact of future changes in generation and emissions-related technology; the Company's fuel mix; and environmental remediation requirements. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. The ultimate outcomeaccompanying notes are an integral part of these ~~matters cannot be determined at this time.~~financial statements.

Compliance with any new federal or state legislation or regulations relating to air, water, and land resources or other environmental and health concerns could significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company's operations, the full impact of any such changes cannot be determined at this time. Additionally, many of the Company's commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity.

~~Air Quality~~

~~Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company.~~

In 2012, the EPA finalized the Mercury and Air Toxics Standards (MATS) rule, which imposes stringent emissions limits for acid gases, mercury, and particulate matter on coal- and oil-fired electric utility steam generating units. The implementation strategy for the MATS rule included emission controls, retirements, and fuel conversions at affected units. All of the Company's units that are subject to the MATS rule completed the measures necessary to achieve compliance with this rule or were retired prior to or during 2016.

The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone National Ambient Air Quality Standard (NAAQS). In 2008, the EPA adopted a revised eight-hour ozone NAAQS and published its final area designations in 2012. The only area within the Company's service territory designated as an ozone nonattainment area for the 2008 standard is a 15-county area within metropolitan Atlanta, which on December 23, 2016, the EPA proposed to redesignate to attainment. In October 2015, the EPA published a more stringent eight-hour ozone NAAQS. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. States were required to recommend area designations by October 2016, and the only area within the

Table of ContentsIndex to Financial Statements

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia~~STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2019, 2018, and 2017

Mississippi Power Company ~~2016~~2019 Annual Report

Company's service territory that was proposed for designation is an eight-county area within the Atlanta metropolitan area in Georgia. The EPA is expected to finalize area designations by October 2017.



	2019			2018			2017
	(in millions)
Operating Activities:
Net income (loss)	$	139		$	236		$	(2,588	)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	197			177			198
Deferred income taxes	37			475			(727		)
Allowance for equity funds used during construction	(1		)	—			(72		)
Pension and postretirement funding	(54		)	—			—
Settlement of asset retirement obligations	(35		)	(35		)	(23		)
Estimated loss on Kemper IGCC	15			33			3,179
Other, net	21			18			(8		)
Changes in certain current assets and liabilities —
-Receivables	6			(19		)	540
-Fossil fuel stock	(6		)	(3		)	24
-Prepaid income taxes	12			(12		)	—
-Other current assets	(2		)	(7		)	(13		)
-Accounts payable	3			15			(3		)
-Accrued interest	—			(1		)	(29		)
-Accrued taxes	11			(46		)	80
-Over recovered regulatory clause revenues	16			14			(51		)
-Other current liabilities	(20		)	(41		)	(4		)
Net cash provided from operating activities	339			804			503
Investing Activities:
Property additions	(202		)	(188		)	(429		)
Construction payables	(1		)	4			(47		)
Payments pursuant to LTSAs	(23		)	(29		)	(10		)
Other investing activities	(37		)	(19		)	(18		)
Net cash used for investing activities	(263		)	(232		)	(504		)
Financing Activities:
Decrease in notes payable, net	—			(4		)	(18		)
Proceeds —
Capital contributions from parent company	51			15			1,002
Senior notes	—			600			—
Long-term debt issuance to parent company	—			—			40
Short-term borrowings	—			300			109
Pollution control revenue bonds	43			—			—
Redemptions —
Preferred stock	—			(33		)	—
Pollution control revenue bonds	—			(43		)	—
Short-term borrowings	—			(300		)	(109		)
Long-term debt to parent company	—			—			(591		)
Capital leases	—			—			(71		)
Senior notes	(25		)	(155		)	(35		)
Other long-term debt	—			(900		)	(300		)
Return of capital to parent company	(150		)	—			—
Other financing activities	(2		)	(7		)	(2		)
Net cash provided from (used for) financing activities	(83		)	(527		)	25
Net Change in Cash, Cash Equivalents, and Restricted Cash	(7		)	45			24
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	293			248			224
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	286		$	293		$	248
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $(1), $-, and $29 capitalized, respectively)	$	71		$	80		$	65
Income taxes (net of refunds)	(27		)	(525		)	(424		)
Noncash transactions — Accrued property additions at year-end	35			35			32

The ~~EPA regulates fine particulate matter concentrations through~~accompanying notes are an annual and 24-hour average NAAQS, based on standards promulgated in 1997, 2006, and 2012. All areas in which the Company's generating units are located have been determined by the EPA to be in attainment with those standards.integral part of these financial statements.

~~In 2010, the EPA revised the NAAQS for sulfur dioxide (SO~~₂), establishing a new one-hour standard. No areas within the Company's service territory have been designated as nonattainment under this standard. However, in 2015, the EPA finalized a data requirements rule to support final EPA designation decisions for all remaining areas under the SO₂ ~~standard, which could result in nonattainment designations for areas within the Company's service territory. Nonattainment designations could require additional reductions in SO~~₂ ~~emissions and increased compliance and operational costs.~~

In 2014, the EPA proposed to delete from the Alabama State Implementation Plan (SIP) the Alabama opacity rule that the EPA approved in 2008, which provides operational flexibility to affected units, including units owned by SEGCO, which is jointly owned by Alabama Power and the Company. In 2013, the U.S. Court of Appeals for the Eleventh Circuit ruled in favor of Alabama Power and the Company and vacated an earlier attempt by the EPA to rescind its 2008 approval. The EPA's latest proposal characterizes the proposed deletion as an error correction within the meaning of the Clean Air Act. Alabama Power and the Company believe this interpretation of the Clean Air Act to be incorrect. If finalized, this proposed action could affect unit availability and result in increased operations and maintenance costs for SEGCO. See Note 4 to the financial statements for additional information regarding SEGCO.

~~On July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR is an emissions trading program that limits SO~~₂ ~~and nitrogen oxide (NO~~_x~~) emissions from power plants in two phases – Phase 1 in 2015 and Phase 2 in 2017. On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season NO~~_x program, beginning in 2017, and establishes more stringent ozone-season emissions budgets in Alabama. The State of Georgia's emission budget was not affected by the revisions, but interstate emissions trading is restricted unless the state decides to voluntarily adopt a reduced budget. Georgia and Alabama are also in the CSAPR annual SO₂ ~~and NO~~_x ~~programs.~~

The EPA finalized regional haze regulations in 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of best available retrofit technology to certain sources, including fossil fuel-fired generating facilities, built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter. On December 14, 2016, the EPA finalized revisions to the regional haze regulations. These regulations establish a deadline of July 31, 2021 for states to submit revised SIPs to the EPA demonstrating reasonable progress toward the statutory goal of achieving natural background conditions by 2064. State implementation of the reasonable progress requirements defined in this final rule could require further reductions in SO₂ ~~or NO~~_x ~~emissions.~~

In June 2015, the EPA published a final rule requiring certain states (including Georgia and Alabama) to revise or remove the provisions of their SIPs relating to the regulation of excess emissions at industrial facilities, including fossil fuel-fired generating facilities, during periods of startup, shut-down, or malfunction (SSM), and the State of Georgia has submitted proposed SIP revisions in response to the rule.

The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the current and proposed environmental requirements discussed above. These regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through PPAs. The ultimate impact of the eight-hour ozone and SO₂ NAAQS, Alabama opacity rule, CSAPR, regional haze regulations, and SSM rule will depend on various factors, such as implementation, adoption, or other action at the state level, and the outcome of pending and/or future legal challenges, and cannot be determined at this time.

~~Water Quality~~

The EPA's final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities became effective in 2014. The effect of this final rule will depend on the results of additional studies that are currently underway and implementation of the rule by regulators based on site-specific factors. National Pollutant Discharge Elimination System (NPDES) permits issued after July 14, 2018 must include conditions to implement and ensure compliance with the standards and protective measures required by the rule.

Table of ContentsIndex to Financial Statements

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia~~BALANCE SHEETS

At December 31, 2019 and 2018

Mississippi Power Company ~~2016~~2019 Annual Report

~~incorporated into future renewals~~



Assets	2019		2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	286	$	293
Receivables —
Customer accounts receivable	35		34
Unbilled revenues	39		41
Affiliated	27		21
Other accounts and notes receivable	26		31
Fossil fuel stock	26		20
Materials and supplies	61		53
Other regulatory assets	99		116
Prepaid income taxes	—		12
Other current assets	10		7
Total current assets	609		628
Property, Plant, and Equipment:
In service	4,857		4,900
Less: Accumulated provision for depreciation	1,463		1,429
Plant in service, net of depreciation	3,394		3,471
Construction work in progress	126		103
Total property, plant, and equipment	3,520		3,574
Other Property and Investments	131		24
Deferred Charges and Other Assets:
Deferred charges related to income taxes	32		33
Regulatory assets – asset retirement obligations	210		143
Other regulatory assets, deferred	360		331
Accumulated deferred income taxes	139		150
Other deferred charges and assets	34		3
Total deferred charges and other assets	775		660
Total Assets	$	5,035	$	4,886

The accompanying notes are an integral part of ~~NPDES permits at affected units and may require the installation and operation~~these financial statements.

Table of ~~multiple technologies sufficient~~ContentsIndex to ~~ensure compliance with applicable new numeric wastewater compliance limits. Compliance deadlines between November 1, 2018 and~~ Financial Statements

BALANCE SHEETS

At December 31, ~~2023 will be established in permits based on information provided for each applicable wastestream.~~2019 and 2018

~~In 2015,~~Mississippi Power Company 2019 Annual Report



Liabilities and Stockholder's Equity	2019		2018
	(in millions)
Current Liabilities:
Securities due within one year	$	281	$	40
Accounts payable —
Affiliated	76		60
Other	75		90
Accrued taxes	105		95
Accrued interest	15		15
Accrued compensation	35		38
Accrued plant closure costs	15		29
Asset retirement obligations	33		34
Other regulatory liabilities	21		12
Over recovered regulatory clause liabilities	29		14
Other current liabilities	49		28
Total current liabilities	734		455
Long-Term Debt (See accompanying statements)	1,308		1,539
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	424		378
Deferred credits related to income taxes	352		382
Employee benefit obligations	99		115
Asset retirement obligations, deferred	157		126
Other cost of removal obligations	189		185
Other regulatory liabilities, deferred	76		81
Other deferred credits and liabilities	44		16
Total deferred credits and other liabilities	1,341		1,283
Total Liabilities	3,383		3,277
Common Stockholder's Equity (See accompanying statements)	1,652		1,609
Total Liabilities and Stockholder's Equity	$	5,035	$	4,886
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these financial statements.

Table of ContentsIndex to Financial Statements

STATEMENTS OF CAPITALIZATION

At December 31, 2019 and 2018

Mississippi Power Company 2019 Annual Report



	Weighted Average Interest Rate at December 31, 2019	2019			2018			2019		2018
		(in millions)						(percent of total)
Long-Term Debt:
Long-term notes payable —
Due 2028-2042	4.16%	$	950		$	950
Adjustable rate due 2020	2.59%	275			300
Total long-term notes payable		1,225			1,250
Other long-term debt —
Pollution control revenue bonds —
Due 2028	3.20%	43			—
Variable rate due 2020	1.80%	7			40
Variable rate due 2025-2028	1.80%	33			—
Plant Daniel revenue bonds due 2021	7.13%	270			270
Total other long-term debt		353			310
Unamortized debt premium (discount), net		19			27
Unamortized debt issuance expense		(8		)	(8		)
Total long-term debt		1,589			1,579
Less amount due within one year		281			40
Long-term debt excluding amount due within one year		1,308			1,539			44.2	%	48.9	%
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 1,130,000 shares
Outstanding — 1,121,000 shares		38			38
Paid-in capital		4,449			4,546
Accumulated deficit		(2,832		)	(2,971		)
Accumulated other comprehensive loss		(3		)	(4		)
Total common stockholder's equity		1,652			1,609			55.8		51.1
Total Capitalization		$	2,960		$	3,148		100.0	%	100.0	%

The accompanying notes are an integral part of these financial statements.

Table of ContentsIndex to Financial Statements

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

For the ~~EPA~~Years Ended December 31, 2019, 2018, and 2017

Mississippi Power Company 2019 Annual Report



	Number of Common Shares Issued	Common Stock		Paid-In Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2016	1	$	38	$	3,525		$	(616	)	$	(4	)	$	2,943
Net loss after dividends on preferred stock	—	—		—			(2,590		)	—			(2,590		)
Capital contributions from parent company	—	—		1,004			—			—			1,004
Other	—	—		—			1			—			1
Balance at December 31, 2017	1	38		4,529			(3,205		)	(4		)	1,358
Net income after dividends on preferred stock	—	—		—			235			—			235
Capital contributions from parent company	—	—		17			—			—			17
Other	—	—		—			(1		)	—			(1		)
Balance at December 31, 2018	1	38		4,546			(2,971		)	(4		)	1,609
Net income after dividends on preferred stock	—	—		—			139			—			139
Return of capital to parent company	—	—		(150		)	—			—			(150		)
Capital contributions from parent company	—	—		53			—			—			53
Other comprehensive income	—	—		—			—			1			1
Balance at December 31, 2019	1	$	38	$	4,449		$	(2,832	)	$	(3	)	$	1,652

The accompanying notes are an integral part of these financial statements.

Table of ContentsIndex to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the ~~U.S. Army Corps~~Board of ~~Engineers jointly published a final rule revising the regulatory definition~~Directors of ~~waters of the U.S. for all Clean Water Act (CWA) programs. The final rule significantly expands the scope of federal jurisdiction under the CWA~~Southern Power Company and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. The rule became effective in August 2015 but, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The case is held in abeyance pending review by the U.S. Supreme Court of challenges to the U.S. Court of Appeals for the Sixth Circuit's jurisdiction in the case.Subsidiary Companies

These water quality regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions and decisions on infrastructure expansion and improvements. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs. The ultimate impact of these final rules will depend on various factors, such as pending and/or future legal challenges, compliance dates, and implementation of the rules, and cannot be determined at this time.

~~Coal Combustion Residuals~~

The Company currently manages CCR at onsite storage units consisting of landfills and surface impoundments (CCR Units) at 12 current or former electric generating plants. In addition to on-site storage, the Company also sells a portion of its CCR to third parties for beneficial reuse. Individual states regulate CCR and the State of Georgia has its own regulatory requirements. The Company has an inspection program in place to assist in maintaining the integrity of its coal ash surface impoundments.

The CCR Rule became effective in October 2015. The CCR Rule regulates the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in CCR Units at active generating power plants. The CCR Rule does not automatically require closure of CCR Units but includes minimum criteria for active and inactive surface impoundments containing CCR and liquids, lateral expansions of existing units, and active landfills. Failure to meet the minimum criteria can result in the required closure of a CCR Unit. On December 16, 2016, President Obama signed the Water Infrastructure Improvements for the Nation Act (WIIN Act). The WIIN Act allows states to establish permit programs for implementing the CCR Rule, if the EPA approves the program, and allows for federal permits and EPA enforcement where a state permitting program does not exist. On October 26, 2016, the Georgia Department of Natural Resources approved amendments to its state solid waste regulations to incorporate the requirements of the CCR Rule and establish additional requirements for all of the Company's onsite storage units consisting of landfills and surface impoundments.

Based on current cost estimates for closure and monitoring of ash ponds pursuant to the CCR Rule, the Company has recorded incremental AROs related to the CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing with respect to compliance activities, the Company expects to continue to periodically update these estimates. The Company has posted closure and post-closure care plans to its public website as required by the CCR Rule; however, the ultimate impact of the CCR Rule will dependOpinion on the ~~results~~Financial Statements

We have audited the accompanying consolidated balance sheets of ~~initial~~Southern Power Company and ~~ongoing minimum criteria assessments and implementation~~subsidiary companies (Southern Power) (a wholly-owned subsidiary of ~~state or federal permit programs.~~ The ~~Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates.~~

~~See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information regarding the Company's AROs~~Southern Company) as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Southern Power as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of Southern Power's management. Our responsibility is to express an opinion on Southern Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Southern Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Southern Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Southern Power's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 19, 2020

We have served as Southern Power's auditor since 2002.

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CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2019, 2018, and 2017

Southern Power Company and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	1,528		$	1,757		$	1,671
Wholesale revenues, affiliates	398			435			392
Other revenues	12			13			12
Total operating revenues	1,938			2,205			2,075
Operating Expenses:
Fuel	577			699			621
Purchased power	108			176			149
Other operations and maintenance	359			395			386
Depreciation and amortization	479			493			503
Taxes other than income taxes	40			46			48
Asset impairment	3			156			—
Gain on dispositions, net	(23		)	(2		)	—
Total operating expenses	1,543			1,963			1,707
Operating Income	395			242			368
Other Income and (Expense):
Interest expense, net of amounts capitalized	(169		)	(183		)	(191		)
Other income (expense), net	47			23			1
Total other income and (expense)	(122		)	(160		)	(190		)
Earnings Before Income Taxes	273			82			178
Income taxes (benefit)	(56		)	(164		)	(939		)
Net Income	329			246			1,117
Net income (loss) attributable to noncontrolling interests	(10		)	59			46
Net Income Attributable to Southern Power	$	339		$	187		$	1,071

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2019, 2018, and 2017

Southern Power Company and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Net Income	$	329		$	246		$	1,117
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(22), $(17), and $39, respectively	(66		)	(51		)	63
Reclassification adjustment for amounts included in net income, net of tax of $14, $19, and $(46), respectively	41			58			(73		)
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax of $(6), $2, and $-, respectively	(17		)	5			—
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, and $-, respectively	—			2			—
Total other comprehensive income (loss)	(42		)	14			(10		)
Comprehensive income (loss) attributable to noncontrolling interests	(10		)	59			46
Comprehensive Income Attributable to Southern Power	$	297		$	201		$	1,061

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2019, 2018, and 2017

Southern Power Company and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Activities:
Net income	$	329		$	246		$	1,117
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	505			524			536
Deferred income taxes	(74		)	(244		)	(263		)
Utilization of federal investment tax credits	734			5			—
Amortization of investment tax credits	(151		)	(58		)	(57		)
Accrued income taxes, non-current	—			(14		)	14
Income taxes receivable, non-current	25			42			(61		)
Pension and postretirement funding	(24		)	—			—
Asset impairment	3			156			—
Other, net	(33		)	7			(13		)
Changes in certain current assets and liabilities —
-Receivables	72			(20		)	(60		)
-Prepaid income taxes	39			25			24
-Other current assets	(8		)	(26		)	(28		)
-Accrued taxes	6			7			(55		)
-Other current liabilities	(38		)	(19		)	1
Net cash provided from operating activities	1,385			631			1,155
Investing Activities:
Business acquisitions. net of cash acquired	(50		)	(65		)	(1,016		)
Property additions	(489		)	(315		)	(268		)
Change in construction payables	7			(6		)	(153		)
Investment in unconsolidated subsidiaries	(116		)	—			—
Proceeds from dispositions and asset sales	572			203			—
Payments pursuant to LTSAs and for equipment not yet received	(104		)	(75		)	(203		)
Other investing activities	13			31			15
Net cash used for investing activities	(167		)	(227		)	(1,625		)
Financing Activities:
Increase (decrease) in notes payable, net	449			(105		)	(104		)
Proceeds —
Short-term borrowings	100			200			—
Capital contributions from parent company	64			2			—
Senior notes	—			—			525
Other long-term debt	—			—			43
Redemptions —
Senior notes	(600		)	(350		)	(500		)
Other long-term debt	—			(420		)	(18		)
Short-term borrowings	(100		)	(100		)	—
Return of capital to parent company	(755		)	(1,650		)	—
Distributions to noncontrolling interests	(256		)	(153		)	(119		)
Capital contributions from noncontrolling interests	196			2,551			80
Purchase of membership interests from noncontrolling interests	—			—			(59		)
Payment of common stock dividends	(206		)	(312		)	(317		)
Other financing activities	(12		)	(26		)	(33		)
Net cash used for financing activities	(1,120		)	(363		)	(502		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	98			41			(972		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	181			140			1,112
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	279		$	181		$	140
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $15, $17, and $11 capitalized, respectively)	$	167		$	173		$	189
Income taxes (net of refunds and investment tax credits)	(664		)	79			(487		)
Noncash transactions — Accrued property additions at year-end	57			31			32

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and 2018

Southern Power Company and Subsidiary Companies 2019 Annual Report



Assets	2019		2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	279	$	181
Receivables —
Customer accounts receivable	107		111
Affiliated	30		55
Other	73		116
Materials and supplies	191		220
Prepaid income taxes	36		25
Other current assets	43		37
Total current assets	759		745
Property, Plant, and Equipment:
In service	13,270		13,271
Less: Accumulated provision for depreciation	2,464		2,171
Plant in service, net of depreciation	10,806		11,100
Construction work in progress	515		430
Total property, plant, and equipment	11,321		11,530
Other Property and Investments:
Intangible assets, net of amortization of $69 and $61 at December 31, 2019 and December 31, 2018, respectively	322		345
Equity investments in unconsolidated subsidiaries	28		—
Total other property and investments	350		345
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	369		—
Prepaid LTSAs	128		98
Accumulated deferred income taxes	551		1,186
Income taxes receivable, non-current	5		30
Assets held for sale	601		576
Other deferred charges and assets	216		373
Total deferred charges and other assets	1,870		2,263
Total Assets	$	14,300	$	14,883

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and 2018

Southern Power Company and Subsidiary Companies 2019 Annual Report



Liabilities and Stockholders' Equity	2019			2018
	(in millions)
Current Liabilities:
Securities due within one year	$	824		$	599
Notes payable	549			100
Accounts payable —
Affiliated	56			92
Other	85			77
Accrued taxes	26			6
Accrued interest	32			36
Other current liabilities	132			121
Total current liabilities	1,704			1,031
Long-Term Debt:
Senior notes —
2.375% due 2020	—			300
2.50% due 2021	300			300
1.00% due 2022	674			687
2.75% due 2023	290			290
Weighted average interest rate 4.12% at 12/31/19 due 2025-2046	2,337			2,348
Other long-term debt —
Variable rate (3.34% at 12/31/18) due 2020	—			525
Unamortized debt premium (discount), net	(8		)	(9		)
Unamortized debt issuance expense	(19		)	(23		)
Total long-term debt	3,574			4,418
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	115			105
Accumulated deferred ITCs	1,731			1,832
Operating lease obligations	376			—
Other deferred credits and liabilities	178			213
Total deferred credits and other liabilities	2,400			2,150
Total Liabilities	7,678			7,599
Common Stockholder's Equity:
Common stock, par value $0.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares	—			—
Paid-in capital	909			1,600
Retained earnings	1,485			1,352
Accumulated other comprehensive income (loss)	(26		)	16
Total common stockholder's equity	2,368			2,968
Noncontrolling Interests	4,254			4,316
Total Stockholders' Equity	6,622			7,284
Total Liabilities and Stockholders' Equity	$	14,300		$	14,883
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

For the Years Ended December 31, 2019, 2018, and 2017

Southern Power Company and Subsidiary Companies 2019 Annual Report



	Number of Common Shares Issued	Common Stock		Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income			Total Common Stockholder's Equity			Noncontrolling Interests^(a)			Total
	(in millions)
Balance at December 31, 2016	—	$	—	$	3,671		$	724		$	35		$	4,430		$	1,245		$	5,675
Net income attributable to Southern Power	—	—		—			1,071			—			1,071			—			1,071
Capital contributions to parent company, net	—	—		(2		)	—			—			(2		)	—			(2		)
Other comprehensive income (loss)	—	—		—			—			(10		)	(10		)	—			(10		)
Cash dividends on common stock	—	—		—			(317		)	—			(317		)	—			(317		)
Other comprehensive income transfer from SCS^(b)	—	—		—			—			(27		)	(27		)	—			(27		)
Capital contributions from noncontrolling interests	—	—		—			—			—			—			79			79
Distributions to noncontrolling interests	—	—		—			—			—			—			(122		)	(122		)
Net income attributable to noncontrolling interests	—	—		—			—			—			—			44			44
Reclassification from redeemable noncontrolling interests	—	—		—			—			—			—			114			114
Other	—	—		(7		)	—			—			(7		)	—			(7		)
Balance at December 31, 2017	—	—		3,662			1,478			(2		)	5,138			1,360			6,498
Net income attributable to Southern Power	—	—		—			187			—			187			—			187
Return of capital to parent company	—	—		(1,650		)	—			—			(1,650		)	—			(1,650		)
Capital contributions from parent company	—	—		2			—			—			2			—			2
Other comprehensive income	—	—		—			—			14			14			—			14
Cash dividends on common stock	—	—		—			(312		)	—			(312		)	—			(312		)
Capital contributions from noncontrolling interests	—	—		—			—			—			—			1,372			1,372
Distributions to noncontrolling interests	—	—		—			—			—			—			(164		)	(164		)
Net income attributable to noncontrolling interests	—	—		—			—			—			—			59			59
Sale of noncontrolling interests^(c)	—	—		(417		)	—			—			(417		)	1,690			1,273
Other	—	—		3			(1		)	4			6			(1		)	5
Balance at December 31, 2018	—	—		1,600			1,352			16			2,968			4,316			7,284
Net income attributable to Southern Power	—	—		—			339			—			339			—			339
Return of capital to parent company	—	—		(755		)	—			—			(755		)	—			(755		)
Capital contributions from parent company	—	—		64			—			—			64			—			64
Other comprehensive income (loss)	—	—		—			—			(42		)	(42		)	—			(42		)
Cash dividends on common stock	—	—		—			(206		)	—			(206		)	—			(206		)
Capital contributions from noncontrolling interests	—	—		—			—			—			—			276			276
Distributions to noncontrolling interests	—	—		—			—			—			—			(327		)	(327		)
Net income (loss) attributable to noncontrolling interests	—	—		—			—			—			—			(10		)	(10		)
Other	—	—		—			—			—			—			(1		)	(1		)
Balance at December 31, 2019	—	$	—	$	909		$	1,485		$	(26	)	$	2,368		$	4,254		$	6,622


(a)	Excludes redeemable noncontrolling interests. See Note 7 to the financial statements under "Noncontrolling Interests" for additional information.


(b)	In connection with Southern Power becoming a participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of other comprehensive income, net of tax of $9 million, was transferred from SCS.


(c)	See Note 15 under "Southern Power - Sales of Renewable Facility Interests" for additional information.

The accompanying notes are an integral part of these consolidated financial statements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Southern Company Gas and Subsidiary Companies

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southern Company Gas and subsidiary companies (Southern Company Gas) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Southern Company Gas as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We did not audit the financial statements of Southern Natural Gas Company, L.L.C. (SNG), Southern Company Gas' investment which is accounted for by the use of the equity method. The accompanying consolidated financial statements of Southern Company Gas include its equity investment in SNG of $1,137 million and $1,261 million as of December 31, 2019 and December 31, 2018, respectively, and its earnings from its equity method investment in SNG of $141 million, $131 million, and $88 million for the years ended December 31, 2019, 2018, and 2017, respectively. Those statements were audited by other auditors whose reports (which express unqualified opinions on SNG's financial statements and contain an emphasis of matter paragraph calling attention to SNG's significant transactions with related parties) have been furnished to us, and our opinion, insofar as it relates to the amounts included for SNG, is based solely on the reports of the other auditors.

Basis for Opinion

These financial statements are the responsibility of Southern Company Gas' management. Our responsibility is to express an opinion on Southern Company Gas' financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Southern Company Gas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Southern Company Gas is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Southern Company Gas' internal control over financial reporting. Accordingly, we express no such opinion.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 19, 2020

We have served as Southern Company Gas' auditor since 2016.

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CONSOLIDATED STATEMENTS OF INCOME

Southern Company Gas and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of $117, $114, and $100 for the periods presented, respectively)	$	3,793		$	3,874		$	3,787
Alternative revenue programs	(1		)	(20		)	4
Other revenues	—			55			129
Total operating revenues	3,792			3,909			3,920
Operating Expenses:
Cost of natural gas	1,319			1,539			1,601
Cost of other sales	—			12			29
Other operations and maintenance	888			981			945
Depreciation and amortization	487			500			501
Taxes other than income taxes	213			211			184
Impairment charges	115			42			—
(Gain) loss on dispositions, net	—			(291		)	—
Total operating expenses	3,022			2,994			3,260
Operating Income	770			915			660
Other Income and (Expense):
Earnings from equity method investments	157			148			106
Interest expense, net of amounts capitalized	(232		)	(228		)	(200		)
Other income (expense), net	20			1			44
Total other income and (expense)	(55		)	(79		)	(50		)
Earnings Before Income Taxes	715			836			610
Income taxes	130			464			367
Net Income	$	585		$	372		$	243

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Southern Company Gas and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Net Income	$	585		$	372		$	243
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(2), $2, and $(3), respectively	(5		)	5			(5		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $(1), and $-, respectively	2			(1		)	1
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax of $(14), $-, and $-, respectively	(16		)	—			(1		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $3, and $-, respectively	—			(2		)	—
Total other comprehensive income (loss)	(19		)	2			(5		)
Comprehensive Income	$	566		$	374		$	238

The accompanying notes are an integral part of these consolidated financial statements.

Table of ContentsIndex to Financial Statements

CONSOLIDATED STATEMENTS OF CASH FLOWS

Southern Company Gas and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Activities:
Net income	$	585		$	372		$	243
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	487			500			501
Deferred income taxes	213			(1		)	236
Pension and postretirement funding	(145		)	—			—
Impairment charges	115			42			—
(Gain) loss on dispositions, net	—			(291		)	—
Mark-to-market adjustments	(56		)	(19		)	(24		)
Other, net	(55		)	(24		)	(51		)
Changes in certain current assets and liabilities —
-Receivables	467			(218		)	(94		)
-Natural gas for sale	44			49			36
-Prepaid income taxes	40			(42		)	(39		)
-Other current assets	31			4			(24		)
-Accounts payable	(520		)	372			(20		)
-Accrued taxes	(69		)	10			110
-Accrued compensation	1			32			15
-Other current liabilities	(71		)	(22		)	(8		)
Net cash provided from operating activities	1,067			764			881
Investing Activities:
Property additions	(1,408		)	(1,388		)	(1,514		)
Cost of removal, net of salvage	(82		)	(96		)	(66		)
Change in construction payables, net	24			(37		)	72
Investments in unconsolidated subsidiaries	(31		)	(110		)	(145		)
Returned investment in unconsolidated subsidiaries	67			20			80
Proceeds from dispositions and asset sales	32			2,609			—
Other investing activities	12			—			5
Net cash provided from (used for) investing activities	(1,386		)	998			(1,568		)
Financing Activities:
Increase (decrease) in notes payable, net	—			(868		)	262
Proceeds —
First mortgage bonds	300			300			400
Capital contributions from parent company	821			24			103
Senior notes	—			—			450
Redemptions and repurchases —
Gas facility revenue bonds	—			(200		)	—
Medium-term notes	—			—			(22		)
First mortgage bonds	(50		)	—			—
Senior notes	(300		)	(155		)	—
Return of capital to parent company	—			(400		)	—
Payment of common stock dividends	(471		)	(468		)	(443		)
Other financing activities	(2		)	(3		)	(9		)
Net cash provided from (used for) financing activities	298			(1,770		)	741
Net Change in Cash, Cash Equivalents, and Restricted Cash	(21		)	(8		)	54
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	70			78			24
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	49		$	70		$	78
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $6, $7, and $11 capitalized, respectively)	$	251		$	249		$	223
Income taxes (net of refunds)	(41		)	524			72
Noncash transactions — Accrued property additions at year-end	122			97			135

The accompanying notes are an integral part of these consolidated financial statements.

Table of ContentsIndex to Financial Statements

CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and 2018

Southern Company Gas and Subsidiary Companies 2019 Annual Report



Assets	2019			2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	46		$	64
Receivables —
Energy marketing receivable	428			801
Customer accounts receivable	323			370
Unbilled revenues	183			213
Affiliated	5			11
Other accounts and notes receivable	114			142
Accumulated provision for uncollectible accounts	(18		)	(30		)
Natural gas for sale	479			524
Prepaid expenses	65			118
Assets from risk management activities, net of collateral	177			219
Other regulatory assets	92			73
Assets held for sale	171			—
Other current assets	41			50
Total current assets	2,106			2,555
Property, Plant, and Equipment:
In service	16,344			15,177
Less: Accumulated depreciation	4,650			4,400
Plant in service, net of depreciation	11,694			10,777
Construction work in progress	613			580
Total property, plant, and equipment	12,307			11,357
Other Property and Investments:
Goodwill	5,015			5,015
Equity investments in unconsolidated subsidiaries	1,251			1,538
Other intangible assets, net of amortization of $176 and $145 at December 31, 2019 and December 31, 2018, respectively	70			101
Miscellaneous property and investments	20			20
Total other property and investments	6,356			6,674
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	93			—
Other regulatory assets, deferred	618			669
Other deferred charges and assets	207			193
Total deferred charges and other assets	918			862
Total Assets	$	21,687		$	21,448

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and 2018

Southern Company Gas and Subsidiary Companies 2019 Annual Report



Liabilities and Stockholder's Equity	2019		2018
	(in millions)
Current Liabilities:
Securities due within one year	$	—	$	357
Notes payable	650		650
Energy marketing trade payables	442		856
Accounts payable —
Affiliated	41		45
Other	315		402
Customer deposits	96		133
Accrued taxes —
Accrued income taxes	—		66
Other accrued taxes	71		75
Accrued interest	52		55
Accrued compensation	100		100
Liabilities from risk management activities, net of collateral	21		76
Other regulatory liabilities	94		79
Other current liabilities	128		130
Total current liabilities	2,010		3,024
Long-term Debt (See accompanying statements)	5,845		5,583
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,219		1,016
Deferred credits related to income taxes	874		940
Employee benefit obligations	265		357
Operating lease obligations	78		—
Other cost of removal obligations	1,606		1,585
Accrued environmental remediation	233		268
Other deferred credits and liabilities	51		105
Total deferred credits and other liabilities	4,326		4,271
Total Liabilities	12,181		12,878
Common Stockholder's Equity (See accompanying statements)	9,506		8,570
Total Liabilities and Stockholder's Equity	$	21,687	$	21,448
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CAPITALIZATION

At December 31, 2019 and 2018

Southern Company Gas and Subsidiary Companies 2019 Annual Report



	Weighted Average Interest Rate at December 31, 2019	2019			2018			2019		2018
		(in millions)						(percent of total)
Long-Term Debt:
Long-term notes payable —
Maturity
2019	—	$	—		$	300
2021	4.01%	330			330
2022	8.63%	46			46
2023	2.45%	350			350
2025-2047	4.68%	3,134			3,134
Total long-term notes payable		3,860			4,160
Other long-term debt —
First mortgage bonds —
Maturity
2019	—	—			50
2023	5.80%	50			50
2026-2059	3.94%	1,525			1,225
Total other long-term debt		1,575			1,325
Unamortized fair value adjustment of long-term debt		430			474
Unamortized debt discount		(20		)	(19		)
Total long-term debt		5,845			5,940
Less amount due within one year		—			357
Long-term debt excluding amount due within one year		5,845			5,583			38.1	%	39.4	%
Common Stockholder's Equity:
Common stock — par value $0.01 per share
Authorized — 100 million shares
Outstanding — 100 shares
Paid-in capital		9,697			8,856
Accumulated deficit		(198		)	(312		)
Accumulated other comprehensive income		7			26
Total common stockholder's equity		9,506			8,570			61.9		60.6
Total Capitalization		$	15,351		$	14,153		100.0	%	100.0	%

The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

Southern Company Gas and Subsidiary Companies 2019 Annual Report



	Number of Common Shares Issued	Common Stock		Paid-In Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2016	—	$	—	$	9,095		$	(12	)	$	26		$	9,109
Net income	—	—		—			243			—			243
Capital contributions from parent company	—	—		117			—			—			117
Other comprehensive income (loss)	—	—		—			—			(5		)	(5		)
Cash dividends on common stock	—	—		—			(443		)	—			(443		)
Other	—	—		2			—			(1		)	1
Balance at December 31, 2017	—	—		9,214			(212		)	20			9,022
Net income	—	—		—			372			—			372
Return of capital to parent company	—	—		(400		)	—			—			(400		)
Capital contributions from parent company	—	—		42			—			—			42
Other comprehensive income	—	—		—			—			2			2
Cash dividends on common stock	—	—		—			(468		)	—			(468		)
Other	—	—		—			(4		)	4			—
Balance at December 31, 2018	—	—		8,856			(312		)	26			8,570
Net income	—	—		—			585			—			585
Capital contributions from parent company	—	—		841			—			—			841
Other comprehensive income (loss)	—	—		—			—			(19		)	(19		)
Cash dividends on common stock	—	—		—			(471		)	—			(471		)
Balance at December 31, 2019	—	$	—	$	9,697		$	(198	)	$	7		$	9,506

The accompanying notes are an integral part of these consolidated financial statements.

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COMBINED NOTES TO FINANCIAL STATEMENTS

Southern Company and Subsidiary Companies 2019 Annual Report

Notes to the Financial Statements

for

The Southern Company and Subsidiary Companies

Alabama Power Company

Environmental Remediation

The Southern Company system must comply with ~~other~~ environmental laws and regulations ~~that cover~~governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company ~~may also~~system could incur substantial costs to clean up affected sites. The traditional electric operating companies and Southern Company ~~conducts~~Gas conduct studies to determine the extent of any required cleanup and ~~has~~have recognized ~~in its financial statements~~ the estimated costs to clean up known impacted ~~sites.~~sites in their financial statements. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia (which represent substantially all of Southern Company Gas' accrued remediation costs) have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies. The traditional electric operating companies and Southern Company Gas may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See ~~Notes 1 and~~Note 3 to the financial statements under ~~"Environmental Remediation Recovery" and "Environmental Matters –~~ "Environmental Remediation" ~~respectively,~~ for additional information.

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

Global Climate Issues

~~In October 2015,~~On July 8, 2019, the EPA published ~~two final actions that would limit CO~~₂ ~~emissions from fossil fuel-fired electric generating units. One of~~ the final ~~actions contains specific emission standards governing CO~~₂ ~~emissions from new, modified,~~Affordable Clean Energy rule (ACE Rule) to repeal and ~~reconstructed units.~~replace the CPP. The ~~other final action, known as the Clean Power Plan, establishes guidelines for~~ACE Rule requires states to develop ~~plans to meet EPA-mandated~~unit-specific CO₂ emission ~~rates or emission reduction goals~~rate standards for existing ~~units.~~coal-fired units based on heat-rate efficiency improvements. The ~~EPA's final guidelines require state plans to meet interim CO~~₂ ~~performance rates between 2022~~ACE Rule is being challenged in the D.C. Circuit Court of Appeals and ~~2029 and final rates~~Georgia Power is an intervenor in ~~2030 and thereafter. At~~ the ~~same time, the EPA published a proposed federal plan and model rule that, when finalized, states can adopt or that would be put~~litigation in ~~place if a state either does not submit a state plan or its plan is not approved by the EPA. On February 9, 2016, the U.S. Supreme Court granted a stay~~support of the ~~Clean Power Plan, pending disposition of petitions for review with the courts. The stay will remain in effect through the resolution of the litigation, including any review by the U.S. Supreme Court.~~

These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions and decisions on infrastructure expansion and improvements. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costsrule, as are not recovered through regulated rates or through PPAs. However, the ultimate financial and operational impact of the final rules on the Company cannot be determined at this time and will depend upon numerous factors, including the outcome of pending legal challenges, including legal challenges filed by the traditional electric operating companies, and any individual state implementation of the EPA's final guidelines in the event the rule is upheld and implemented.

In December 2015, parties to the United Nations Framework Convention on Climate Change – including the United States – adopted the Paris Agreement, which establishes a non-binding universal framework for addressing greenhouse gas emissions based on nationally determined contributions. It also sets in place a process for tracking progress toward the goals every five years.other industry parties. The ultimate impact of ~~this agreement depends~~the ACE Rule to the Southern Company system will depend on ~~its~~state implementation ~~by participating countries~~plan requirements and the outcome of associated legal challenges and cannot be determined at this time.

Additional GHG policies, including legislation, may emerge in the future requiring the United States to transition to a lower GHG emitting economy; however, associated impacts are currently unknown. The ~~EPA's greenhouse~~Southern Company system has transitioned from an electric generating mix of 70% coal and 15% natural gas ~~reporting rule requires annual reporting~~in 2007 to a mix of ~~greenhouse~~22% coal and 52% natural gas ~~emissions expressed~~ in ~~terms~~2019, along with over 8,300 MWs of renewable resources. This transition has been supported in part by the Southern Company system retiring over 5,600 MWs of coal- and oil-fired generating capacity since 2010 and converting over 3,400 MWs of generating capacity from coal to natural gas since 2015. In addition, Southern Company Gas has replaced approximately 5,600 miles of bare steel and

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

cast-iron pipe, resulting in removal of approximately 2.5 million metric tons of CO₂ ~~equivalent~~GHG from its natural gas distribution system since 1998.

The following table provides the Registrants' 2018 and preliminary 2019 GHG emissions ~~for a company's operational control of facilities. Based~~based on ownership or financial control of ~~facilities,~~facilities:



	2018	Preliminary 2019
	(in million metric tons of CO₂ equivalent)
Southern Company^(a)(b)	102	88
Alabama Power	36	32
Georgia Power	30	27
Mississippi Power	8	9
Southern Power^(b)	14	13
Southern Company Gas^(b)	1	1


(a)	Includes non-registrant subsidiaries.


(b)	The 2018 and preliminary 2019 amounts include GHG emissions attributable to disposed assets through the date of the applicable disposition. See Note 15 to the financial statements for additional information regarding disposition activities.

Based on the ~~Company's 2015 greenhouse~~preliminary 2019 amount above, the Southern Company system has achieved an estimated GHG emission reduction of 44% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. The Southern Company system's ability to achieve these goals depends on many external factors, including supportive national energy policies, low natural gas ~~emissions were approximately 32 million metric tons~~prices, and the development, deployment, and advancement of CO₂ ~~equivalent.~~relevant energy technologies. The ~~preliminary estimate~~Southern Company system expects to continue cost-effectively growing its renewable energy portfolio, optimizing technology advancements to modernize its transmission and distribution systems, increasing the use of natural gas for generation, completing Plant Vogtle Units 3 and 4, investing in energy efficiency, and continuing research and development efforts focused on technologies to lower GHG emissions. The Southern Company system is also evaluating methods of removing carbon from the atmosphere.

Regulatory Matters

Alabama Power

Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the ~~Company's 2016 greenhouse gas emissions on the same basis is approximately 33 million metric tons of CO~~₂ ~~equivalent. The level of greenhouse gas emissions from year to year will depend on the level of generation, the mix of fuel sources, and other factors.~~

~~FERC Matters~~

~~The Company has authority~~Alabama PSC. Alabama Power currently recovers its costs from the ~~FERC~~regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to ~~sell electricity at market-based rates. Since 2008, that authority,~~address current events impacting Alabama Power. See Note 2 to the financial statements under "Alabama Power" for ~~certain balancing authority areas, has been conditioned on compliance with the requirements~~additional information regarding Alabama Power's rate mechanisms and accounting orders.

Petition for Certificate of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company)Convenience and ~~Southern~~Necessity

On September 6, 2019, Alabama Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to providepetition for a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing in May 2015 and in June 2015 filed their responseCCN with the ~~FERC.~~

~~On December 9, 2016,~~Alabama PSC for authorization to procure additional generating capacity through the ~~traditional electric operating companies (including~~turnkey construction of a new combined cycle facility and long-term contracts for the ~~Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction,~~purchase of power from others, both as more fully described below, as well as ~~several non-tariff changes. On February 2, 2017,~~ the ~~FERC issued~~Autauga Combined Cycle Acquisition. In addition, Alabama Power will pursue approximately 200 MWs of certain demand side management and distributed energy resource programs. This filing was predicated on the results of Alabama Power's 2019 IRP provided to the Alabama PSC, which identified an ~~order accepting all such changes~~approximately 2,400-MW resource need for Alabama Power, driven by the need for additional winter reserve capacity. See Note 15 to the financial statements under "Alabama Power" for additional information regarding the Autauga Combined Cycle Acquisition.

The procurement of these resources is subject to ~~an additional condition~~the satisfaction or waiver of ~~cost-based price caps for~~ certain ~~sales outside~~conditions, including, among other customary conditions, approval by the Alabama PSC. The completion of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potentialAutauga Combined Cycle Acquisition is also subject to ~~exert market power in certain areas served~~approval by the ~~traditional electric operating companies (including~~FERC. Alabama Power expects to obtain all regulatory approvals by the ~~Company)~~end of the third quarter 2020.

On May 8, 2019, Alabama Power entered into an Agreement for Engineering, Procurement, and Construction with Mitsubishi Hitachi Power Systems Americas, Inc. and Black & Veatch Construction, Inc. to construct an approximately 720-MW combined cycle facility at Plant Barry (Plant Barry Unit 8), which is expected to be placed in ~~some adjacent areas.~~ service by the end of 2023.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

The ~~traditional electric operating companies (including~~capital investment associated with the ~~Company)~~construction of Plant Barry Unit 8 and ~~Southern~~the Autauga Combined Cycle Acquisition is currently estimated to total approximately $1.1 billion.

Alabama Power ~~expect~~entered into additional long-term PPAs totaling approximately 640 MWs of generating capacity consisting of approximately 240 MWs of combined cycle generation expected to ~~make a compliance filing within 30 days accepting the~~begin later in 2020 and approximately 400 MWs of solar generation coupled with battery energy storage systems (solar/battery systems) expected to begin in 2022 through 2024. The terms of the ~~order. While~~agreements for the ~~FERC's February 2, 2017 order references~~solar/battery systems permit Alabama Power to use the ~~market~~energy and retire the associated renewable energy credits (REC) in service of customers or to sell RECs, separately or bundled with energy.

Upon certification, Alabama Power expects to recover costs associated with Plant Barry Unit 8 pursuant to its Rate CNP New Plant. Additionally, Alabama Power expects to recover costs associated with the Autauga Combined Cycle Acquisition through the inclusion in Rate RSE of revenues from the existing power ~~proceeding discussed above, it remains a separate, ongoing matter.~~sales agreement and, on expiration of that agreement, pursuant to Rate CNP New Plant. The recovery of costs associated with laws, regulations, and other such mandates directed at the utility industry are expected to be recovered through Rate CNP Compliance. Alabama Power expects to recover the capacity-related costs associated with the PPAs through its Rate CNP PPA. In addition, fuel and energy-related costs are expected to be recovered through Rate ECR. Any remaining costs associated with the Autauga Combined Cycle Acquisition and Plant Barry Unit 8 will be incorporated through the annual filing of Rate RSE.

The ultimate outcome of these matters cannot be determined at this time.

Construction Work in Progress Accounting Order

On October 1, 2019, the Alabama PSC acknowledged that Alabama Power would begin certain limited preparatory activities associated with Plant Barry Unit 8 construction to meet the target in-service date by authorizing Alabama Power to record the related costs as CWIP prior to the issuance of an order on the CCN petition. Should a CCN not be granted and Alabama Power does not proceed with the related construction of Plant Barry Unit 8, Alabama Power may transfer those costs and any costs that directly result from the non-issuance of the CCN to a regulatory asset which would be amortized over a five-year period. If the balance of incurred costs reaches 5% of the estimated in-service cost of the total project prior to issuance of an order on the CCN petition, Alabama Power will confer with the Alabama PSC regarding the appropriateness of additional authorization. The Sierra Club subsequently filed a petition for reconsideration of the accounting order. The Alabama PSC voted to deny the petition for reconsideration on January 7, 2020.

Rate RSE

The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power's projected weighted common equity return (WCER) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. When the projected WCER is under the allowed range, there is an adjusting point of 5.98% and eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCER adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey. If Alabama Power's actual retail return is above the allowed WCER range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCER range. Prior to January 2019, retail rates remained unchanged when the WCER range was between 5.75% and 6.21%.

In May 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At December 31, 2019, Alabama Power's equity ratio was approximately 50%.

The approved modifications to Rate RSE began for billings in January 2019. The modifications include reducing the top of the allowed WCER range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

~~Georgia Power~~Southern Company ~~2016~~and Subsidiary Companies 2019 Annual Report

~~Retail Regulatory Matters~~with a Rate RSE upward adjustment, if Alabama Power's actual WCER exceeds 6.15%, customers receive 50% of the amount between 6.15% and 6.90% and all amounts in excess of an actual WCER of 6.90%.

In conjunction with these modifications to Rate RSE, in May 2018, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020 and to return $50 million to customers through bill credits in 2019.

On November 27, 2019, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2020. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remain unchanged for 2020.

During 2019, Alabama Power provided to the Alabama PSC and the Alabama Office of the Attorney General information related to the operation and utilization of Rate RSE, in accordance with the rules governing the operation of Rate RSE. The ultimate outcome of this matter cannot be determined at this time.

At December 31, 2019, Alabama Power's WCER exceeded 6.15%, resulting in Alabama Power establishing a current regulatory liability of $53 million for Rate RSE refunds, which will be refunded to customers through bill credits in April 2020.

Rate CNP New Plant

Rate CNP New Plant allows for recovery of Alabama Power's retail costs associated with newly developed or acquired certificated generating facilities placed into retail service. No adjustments to Rate CNP New Plant occurred during the period 2017 through 2019. See Note 2 to the financial statements under "Alabama Power – Petition for Certificate of Convenience and Necessity" for additional information.

Rate CNP PPA

Rate CNP Compliance

Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to factors that are calculated and submitted to the Alabama PSC by December 1 with rates effective for the following calendar year. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on Southern Company's or Alabama Power's revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.

On November 27, 2019, Alabama Power submitted calculations associated with its cost of complying with governmental mandates, as provided under Rate CNP Compliance. The filing reflected a projected over recovered retail revenue requirement for governmental mandates, which resulted in a rate decrease of approximately $68 million that became effective for the billing month of January 2020.

Rate ECR

Rate ECR recovers Alabama Power's retail energy costs based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed gives rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on Southern Company's or Alabama Power's net income but will impact operating cash flows. The Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.

On December 3, 2019, the Alabama PSC approved a decrease to Rate ECR from 2.353 to 2.160 cents per KWH, equal to 1.82%, or approximately $102 million annually, effective January 1, 2020. The rate will adjust to 5.910 cents per KWH in January 2021 absent a further order from the Alabama PSC.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Tax Reform Accounting Order

In May 2018, the Alabama PSC approved an accounting order that authorized Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ended December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. The final excess deferred tax liability for the year ended December 31, 2018 totaled approximately $69 million, of which $30 million was used to offset the Rate ECR under recovered balance. On December 3, 2019, the Alabama PSC issued an order authorizing Alabama Power to apply the remaining deferred balance of approximately $39 million to increase the balance in the NDR. See "Rate NDR" herein and Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information.

Plant Greene County

Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 5 to the financial statements under "Joint Ownership Agreements" for additional information regarding the joint ownership agreement. On December 31, 2019, Mississippi Power updated its proposed Reserve Margin Plan (RMP), originally filed in August 2018 with the Mississippi PSC. The RMP proposed a four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. Mississippi Power's proposed Plant Greene County unit retirements would require the completion of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will continue to monitor the status of Mississippi Power's proposed RMP and associated regulatory process as well as the proposed transmission and system reliability improvements. Alabama Power will review all the facts and circumstances and will evaluate all its alternatives prior to reaching a final determination on the ongoing operations of Plant Greene County. The ultimate outcome of this matter cannot be determined at this time.

Rate NDR

Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million.

The ~~Company's~~second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR enhance Alabama Power's ability to mitigate the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.

As discussed herein under "Tax Reform Accounting Order," in accordance with an Alabama PSC order issued on December 3, 2019, Alabama Power applied the remaining excess deferred income tax regulatory liability balance of approximately $39 million to increase the balance in the NDR. Alabama Power also accrued an additional $84 million to the NDR in December 2019 resulting in an accumulated balance of $150 million at December 31, 2019. Of this amount, Alabama Power designated $37 million to be applied to budgeted reliability-related expenditures for 2020, which is included in other regulatory liabilities, current. The remaining NDR balance of $113 million is included in other regulatory liabilities, deferred on the balance sheet.

In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated and collected approximately $16 million annually through 2019. Effective with the March 2020 billings, the reserve establishment charge will be suspended and the reserve maintenance charge will be activated as a result of the NDR balance exceeding $75 million. Alabama Power expects to collect approximately $5 million in 2020 and $3 million annually thereafter unless the NDR balance falls below $50 million.

As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Environmental Accounting Order

Based on an order from the Alabama PSC (Environmental Accounting Order), Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. The regulatory asset is being amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance.

On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. At December 31, 2019, the related regulatory assets totaled $649 million. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power" and Note 6 to the financial statements for additional information.

Georgia Power

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. ~~The Company~~Georgia Power currently recovers its costs from the regulated retail business through ~~the 2013 ARP,~~an alternate rate plan, which includes traditional base ~~tariff rates,~~tariffs, Demand-Side Management (DSM) tariffs, the ECCR ~~tariffs,~~tariff, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs ~~related to the~~on certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery ~~tariffs.~~tariff. See Note 32 to the financial statements under ~~"Retail Regulatory Matters"~~"Georgia Power – Rate Plans," " – Fuel Cost Recovery," and " – Nuclear Construction" for additional information.

Rate Plans

2019 ARP

On December 17, 2019, the Georgia PSC voted to approve the 2019 ARP, under which Georgia Power increased its rates on January 1, 2020 and will increase rates annually for 2021 and 2022 as detailed below based on compliance filings to be made at least 90 days prior to the effective date. Georgia Power will recover estimated increases through its existing tariffs as follows:



Tariff	2020		2021		2022
	(in millions)
Traditional base	$	—	$	120	$	192
ECCR^(a)	318		55		184
DSM	12		1		1
MFF	12		4		9
Total^(b)	$	342	$	181	$	386


(a)	Effective January 1, 2020, CCR AROs will be recovered through the ECCR tariff. See "Integrated Resource Plan" herein for additional information on recovery of compliance costs for CCR AROs.


(b)	Totals may not add due to rounding.

Further, under the 2019 ARP, Georgia Power's retail ROE is set at 10.50%, and earnings will be evaluated against a retail ROE range of 9.50% to 12.00%. The Georgia PSC also approved an increase in the retail equity ratio to 56% from 55%. Any retail earnings above 12.00% will be shared, with 40% being applied to reduce regulatory assets, 40% directly refunded to customers, and the remaining 20% retained by Georgia Power. There will be no recovery of any earnings shortfall below 9.50% on an actual basis. However, if at any time during the term of the 2019 ARP, Georgia Power projects that its retail earnings will be below 9.50% for any calendar year, it could petition the Georgia PSC for implementation of the Interim Cost Recovery (ICR) tariff to adjust Georgia Power's retail rates to achieve a 9.50% ROE. The Georgia PSC would have 90 days to rule on Georgia Power's request. The ICR tariff would expire at the earlier of January 1, 2023 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR tariff, Georgia Power may file a full rate case.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

(approximately $50 million) will be refunded to customers in 2020 and (ii) Georgia Power will forgo its share of 2019 earnings in excess of the earnings band so that 50% (approximately $60 million) of all earnings over the 2019 band will be refunded to customers and 50% (approximately $60 million) were used to reduce regulatory assets.

Except as provided above, Georgia Power will not file for a general base rate increase while the 2019 ARP is in effect. Georgia Power is required to file a general base rate case by July 1, 2022, in response to which the Georgia PSC would be expected to determine whether the 2019 ARP should be continued, modified, or discontinued.

2013 ARP

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC ~~on April 14,~~in 2016, the 2013 ARP ~~will continue~~continued in effect until December 31, ~~2019, and the Company will be required to file its next base rate case by July 1,~~ 2019. Furthermore, through December 31, 2019, ~~the Company and Atlanta Gas Light Company each will retain their respective~~Georgia Power retained its merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings ~~applicable to each~~ will be shared on a 60/40 basis with ~~their respective~~ customers; thereafter, all merger savings will be retained by customers. ~~See Note 3~~

There were no changes to ~~the financial statements under "Retail Regulatory Matters – Rate Plans" for additional information regarding the 2013 ARP.~~

~~In accordance with the 2013 ARP, the~~ Georgia ~~PSC approved increases to tariffs effective January 1, 2015 and 2016 as follows: (1)~~Power's traditional base ~~tariff rates by approximately $107 million and $49 million, respectively; (2)~~tariffs, ECCR tariff, ~~by approximately $23 million and $75 million, respectively; (3)~~ DSM tariffs, ~~by approximately $3 million~~or MFF tariffs in ~~each year; and (4) MFF tariff by approximately $3 million and $13 million, respectively, for a total increase in base revenues of approximately $136 million and $140 million, respectively.~~2017, 2018, or 2019.

Under the 2013 ARP, ~~the Company's~~Georgia Power's retail ROE iswas set at 10.95% and earnings ~~are~~were evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% ~~will~~were to be directly refunded to customers, with the remaining one-third retained by Georgia Power. On February 5, 2019, the ~~Company. There will be no recovery~~Georgia PSC approved a settlement between Georgia Power and the staff of ~~any earnings shortfall below 10.00% on an actual basis.~~the Georgia PSC under which Georgia Power's retail ROE for 2017 was stipulated to exceed 12.00% and Georgia Power reduced certain regulatory assets by approximately $4 million in lieu of providing refunds to retail customers. In ~~2014, the Company's~~2019 and 2018, Georgia Power's retail ROE exceeded 12.00%, and, under the ~~Company refunded~~modified sharing mechanism pursuant to ~~retail customers~~the 2019 ARP, Georgia Power has reduced regulatory assets by a total of approximately ~~$11~~$110 million ~~in 2016, as approved by the Georgia PSC on February 18, 2016. In 2015, the Company's retail ROE was within the allowed retail ROE range. In 2016, the Company's retail ROE exceeded 12.00%,~~ and ~~the Company~~ expects to refund a total of approximately $110 million to ~~retail~~ customers, ~~approximately $40 million,~~ subject to review and approval by the Georgia PSC. ~~The ultimate outcome of this matter cannot be determined at this time.~~

~~Renewables~~

In 2014, the Georgia PSC approved the Company's application for the certification of two PPAs executed in 2013 for the purchase of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that began in 2016See "2019 ARP" and ~~have 20-year terms.~~

As part of the Georgia Power Advanced Solar Initiative (ASI), in 2014, the Georgia PSC approved PPAs executed since April 2015 for the purchase of energy from 555 MWs of solar capacity that began in 2015 and 2016 and have terms ranging from 20 to 30 years. As a result of certain acquisitions by Southern Power, 249 MWs of this contracted capacity is being provided from solar facilities owned by Southern Power through five PPAs that began in 2016. Ownership of any associated renewable energy credits (REC) is specified in each respective PPA. The party that owns the RECs retains the right to use them.

In 2014, the Georgia PSC approved the Company's request to build, own, and operate 30-MW solar generation facilities at three U.S. Army bases and one U.S. Navy base by the end of 2016. One of the four solar generation facilities began commercial operation in December 2015 and the remaining three began in the fourth quarter 2016. In December 2015, the Georgia PSC approved the Company's request to build, own, and operate a 31-MW solar generation facility at a U.S. Marine Corps base that is expected to begin commercial operation by summer 2017 and a 15-MW solar generation facility at a yet-to-be-determined U.S. military base. The ultimate outcome of this matter cannot be determined at this time.

~~Two PPAs for biomass generation capacity of 58 MWs each were executed in June 2015 and November 2015 and are expected to begin in 2019.~~

~~See~~ "Integrated Resource Plan" herein for additional ~~information on renewables.~~information.

Tax Reform Settlement Agreement

In April 2018, the Georgia PSC approved the Georgia Power Tax Reform Settlement Agreement. To reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power issued bill credits of approximately $95 million and $130 million in 2019 and 2018, respectively, and is issuing bill credits of approximately $105 million in February 2020, for a total of $330 million. In addition, Georgia Power deferred as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of federal and state excess accumulated deferred income taxes. At December 31, 2019, the related regulatory liability balance totaled $659 million, which is being amortized over a three-year period ending December 31, 2022 in accordance with the 2019 ARP.

To address some of the negative cash flow and credit quality impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until the Georgia PSC approved the 2019 ARP. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers were retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.

See "2019 ARP" herein for additional information.

Integrated Resource Plan

See ~~"Environmental Matters"~~"Environmental Matters" herein for additional information regarding proposed and final EPA rules and regulations, including ~~the MATS rule for coal- and oil-fired electric utility steam generating units,~~ revisions to ~~effluent limitations guidelines~~ELG for steam

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

electric power plants and additional regulations of CCR and CO₂~~; and the Company's analysis of the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations.~~.

On July ~~28, 2016,~~16, 2019, the Georgia PSC voted to approve Georgia Power's modified triennial IRP (Georgia Power 2019 IRP). In the Georgia Power 2019 IRP, the Georgia PSC approved ~~the 2016 IRP including~~ the decertification and retirement of Plant ~~Mitchell~~Hammond Units ~~3, 4A, and 4B (217~~1 through 4 (840 MWs) and Plant ~~Kraft~~McIntosh Unit 1 ~~(17~~(142.5 MWs)~~, as well as~~ effective July 29, 2019. In accordance with the ~~decertification~~2019 ARP, the remaining net book values at December 31, 2019 of ~~the Intercession City unit (143 MWs total capacity). On August 2, 2016,~~$488 million for the Plant ~~Mitchell~~Hammond units are being recovered over a period equal to the respective unit's remaining useful life, which varies between 2024 and ~~Plant Kraft units were retired. On August 31, 2016, the Company sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC.~~

~~Additionally, the Georgia PSC approved the Company's environmental compliance strategy~~2035, and ~~related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures~~$30 million for Plant McIntosh Unit 1 ~~and Plant Hammond Units 1 through 4.~~

~~The Georgia PSC approved the reclassification~~is being recovered over a three-year period ending December 31, 2022. In addition, approximately $20 million of ~~the remaining net book value of Plant Mitchell Unit 3 and costs associated with~~related unusable materials and supplies ~~remaining at the unit~~inventory balances and approximately $295 million of net capitalized asset retirement ~~date~~costs were reclassified to a regulatory asset. ~~Recovery of~~In accordance with the ~~unit's net book value will continue through December 31, 2019, as provided~~modifications to the earnings sharing mechanism approved in the ~~2013 ARP. The timing of~~2019 ARP, Georgia Power fully amortized the ~~recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs~~regulatory assets associated with these unusable materials and supplies ~~remaining at the unit retirement date was deferred for consideration in the Company's~~inventory

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 ~~base rate case.~~Annual Report

The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by the Company was approved,

balances as well as ~~consideration~~a regulatory asset of approximately $50 million related to costs for ~~no more than 200 MWs of capacity as part of a renewable commercial and industrial program.~~

~~The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear as an option at~~ a future generation site in Stewart County, Georgia. ~~The timing of cost recovery will be determined by~~See "Rate Plans – 2019 ARP" herein for additional information.

Also in the Georgia Power 2019 IRP, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the 2019 ARP, the Georgia PSC approved recovery of the estimated under recovered balance of these compliance costs at December 31, 2019 over a three-year period ending December 31, 2022 and recovery of estimated compliance costs for 2020, 2021, and 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively, with recovery of construction contingency beginning in the year following actual expenditure. The under recovered balance at December 31, 2019 was $175 million and the estimated compliance costs expected to be incurred in 2020, 2021, and 2022 are $265 million, $290 million, and $390 million, respectively. The ECCR tariff is expected to be revised for actual expenditures and updated estimates through future annual compliance filings. See "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements" and "Contractual Obligations" herein and Note 6 to the financial statements for additional information regarding Georgia Power's AROs.

On February 4, 2020, the Georgia PSC voted to deny a motion for reconsideration filed by the Sierra Club regarding the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs.

Additionally, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future ~~base rate case.~~ IRP.

The ~~ultimate outcome~~Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of ~~this matter cannot be determined at this time.~~renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.

Fuel Cost Recovery

~~The Company~~Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. ~~In December 2015, the~~ Georgia ~~PSC approved the Company's request~~Power is scheduled to ~~lower annual billings by approximately $350 million effective January 1, 2016. On May 17, 2016, the Georgia PSC approved the Company's request~~file its next fuel case no later than March 16, 2020, with new rates, if any, to ~~further lower annual billings by approximately $313 million~~be effective June 1, ~~2016. On December 6, 2016, the~~2020. Georgia PSC approved the delay of the Company's next fuel case, which was previously scheduled to be filed by February 28, 2017. The Georgia PSC will review the Company's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case unless the Company deems it necessary to file a fuel case at an earlier time. Under an Interim Fuel Rider, the CompanyPower continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. At December 31, 2019, Georgia Power's over recovered fuel balance was $73 million.

~~The Company's~~Georgia Power's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48-month time ~~horizon effective January 1, 2016.~~horizon.

Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on ~~the~~Southern Company's or Georgia Power's revenues or net income but will affect operating cash ~~flow.~~flows.

Storm Damage Recovery

As of December 31, 2016, the balance in the Company's regulatory asset related to storm damage was $206 million. During October 2016, Hurricane Matthew caused significant damage to the Company's transmission and distribution facilities. As of December 31, 2016, the Company had recorded incremental restoration cost related to this hurricane of $121 million, of which approximately $116 million was charged to the storm damage reserve and the remainder was capitalized. The CompanyBeginning January 1, 2020, Georgia Power is ~~accruing $30~~recovering $213 million annually through December 31, ~~2019,~~2022, as provided in the ~~2013~~2019 ARP, ~~to the storm damage reserve to cover the~~for incremental operations and maintenance costs of ~~damages~~damage from major storms to its transmission and distribution ~~facilities, which is recoverable through base rates.~~facilities. At December 31, 2019, the balance in the regulatory asset related to storm damage was $410 million. The rate of ~~recovery of~~ storm damage ~~costs after December 31, 2019~~cost recovery is expected to be adjusted in ~~the Company's 2019 base rate case.~~future regulatory proceedings as necessary. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on ~~the~~Southern Company's or Georgia Power's financial statements. See Note 12 to the financial statements under ~~"Storm~~"Georgia Power – Storm Damage ~~Recovery"~~Recovery" for additional information regarding Georgia Power's storm damage reserve.

Mississippi Power

Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates. See Note 2 to the financial statements under "Mississippi Power" for additional information.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

2019 Base Rate Case

On November 26, 2019, Mississippi Power filed the Mississippi Power 2019 Base Rate Case with the Mississippi PSC. The filing includes a requested annual decrease in Mississippi Power's retail rates of $5.8 million, or 0.6%, which is driven primarily by changes in the amortization rates of certain regulatory assets and liabilities and cost reductions, partially offset by an increase in Mississippi Power's requested return on investment and depreciation associated with the filing of an updated depreciation study. The revenue requirements included in the filing are based on a projected test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, and a 7.728% return on investment. The filing reflects the elimination of separate rates for costs associated with the Kemper County energy facility and energy efficiency initiatives; those costs are proposed to be included in the PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. On December 10, 2019, the Mississippi PSC suspended the base rate case filing through no later than March 25, 2020. If no further action is taken by the Mississippi PSC, the proposed rates may be effective beginning on March 26, 2020. The ultimate outcome of this matter cannot be determined at this time.

Operations Review

In August 2018, the Mississippi PSC began an operations review of Mississippi Power, for which the final report is expected prior to the conclusion of the Mississippi Power 2019 Base Rate Case. The review includes, but is not limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.

Reserve Margin Plan

On December 31, 2019, Mississippi Power updated its proposed RMP, originally filed in August 2018, as required by the Mississippi PSC. In 2018, Mississippi Power had proposed alternatives to reduce its reserve margin and lower or avoid operating costs, with the most economic alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. The December 2019 update noted that Plant Daniel Units 1 and 2 currently have long-term economics similar to Plant Watson Unit 5. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. A decision by the Mississippi PSC that does not include recovery of the remaining book value of any generating units retired could have a material impact on Southern Company's and Mississippi Power's financial statements. The ultimate outcome of this matter cannot be determined at this time. See Note 3 to the financial statements under "Other Matters– Mississippi Power" for additional information on Plant Daniel Units 1 and 2.

Performance Evaluation Plan

Mississippi Power's retail base rates generally are set under the PEP, a rate plan approved by the Mississippi PSC. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, PEP includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed ROE. PEP measures Mississippi Power's performance on a 10-point scale as a weighted average of results in three areas: average customer price, as compared to prices of other regional utilities (weighted at 40%); service reliability, measured in percentage of time customers had electric service (40%); and customer satisfaction, measured in a survey of residential customers (20%). Typically, two PEP filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on a projected revenue requirement, and the PEP lookback filing, which is filed after the end of the year and allows for review of the actual revenue requirement compared to the projected filing.

In February 2018, Mississippi Power revised its annual projected PEP filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requested an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. In July 2018, Mississippi Power and the MPUS entered into a settlement agreement, which was approved by the Mississippi PSC in August 2018 (PEP Settlement Agreement). Rates under the PEP Settlement Agreement became effective with the first billing cycle of September 2018. The PEP Settlement Agreement provided for an increase of approximately $21.6 million in annual base retail revenues, which excluded certain compensation costs contested by the MPUS, as well as approximately $2 million subsequently approved for recovery through the 2018 Energy Efficiency Cost Rider. Under the PEP Settlement Agreement, Mississippi Power deferred a portion of the contested compensation costs for 2018 and 2019 as a regulatory asset, which totaled $4 million as of December 31, 2019 and is included in other regulatory assets,

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

deferred on the balance sheet. The Mississippi PSC is expected to rule on the appropriate treatment for such costs in connection with the Mississippi Power 2019 Base Rate Case. The ultimate outcome of this matter cannot be determined at this time.

Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE is 9.31% and its allowed equity ratio is capped at 51%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation until the conclusion of the Mississippi Power 2019 Base Rate Case. Further, Mississippi Power agreed to seek equity contributions sufficient to restore its equity ratio to 50% by December 31, 2018. Since Mississippi Power's actual average equity ratio for 2018 was more than 1% lower than the 50% target, Mississippi Power deferred the corresponding difference in its revenue requirement of approximately $4 million as a regulatory liability for resolution in the Mississippi Power 2019 Base Rate Case. Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the Mississippi Power 2019 Base Rate Case and Mississippi Power was not required to make any PEP filings for regulatory years 2018, 2019, and 2020.

Energy Efficiency

On February 5, 2019, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider 2019 compliance filing, which included a slight decrease in annual retail revenues, effective with the first billing cycle in March 2019.

As part of the Mississippi Power 2019 Base Rate Case, Mississippi Power has proposed that the Energy Efficiency Cost Rider be eliminated and those costs be included in the PEP. The ultimate outcome of this matter cannot be determined at this time.

Environmental Compliance Overview Plan

In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. The Mississippi PSC approved $41 million and $17 million of costs that were reclassified to regulatory assets associated with the fuel conversion of Plant Watson and Plant Greene County, respectively, for amortization over five-year periods ending in July 2021 and July 2022, respectively.

In August 2018, the Mississippi PSC approved an annual increase in revenues related to the ECO Plan of approximately $17 million, effective with the first billing cycle for September 2018. This increase represented the maximum 2% annual increase in revenues and primarily related to the carryforward from the prior year.

The increase was the result of Mississippi PSC approval of an agreement between Mississippi Power and the MPUS to settle the 2018 ECO Plan filing (ECO Settlement Agreement) and was sufficient to recover costs through 2019, including remaining amounts deferred from prior years along with the related carrying costs. In accordance with the ECO Settlement Agreement, ECO Plan proceedings are suspended until after the conclusion of the Mississippi Power 2019 Base Rate Case and Mississippi Power was not required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary adjustments reflected in the Mississippi Power 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio. At December 31, 2019, Mississippi Power has recorded $2 million in other regulatory liabilities, deferred on the balance sheet related to the actual December 31, 2018 average equity ratio differential from target applicable to the ECO Plan.

On October 24, 2019, the Mississippi PSC approved Mississippi Power's July 9, 2019 request for a CPCN to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of approximately $66 million being proposed for recovery through its ECO Plan. Approximately $17 million of Mississippi Power's share is associated with ash pond closure and is reflected in Mississippi Power's ARO liabilities. See Note 6 to the financial statements for additional information on AROs and Note 3 to the financial statements under "Other Matters – Mississippi Power" for additional information on Gulf Power's ownership in Plant Daniel.

Fuel Cost Recovery

Mississippi Power annually establishes and is required to file for an adjustment to the retail fuel cost recovery factor that is approved by the Mississippi PSC. The Mississippi PSC approved decreases of $35 million and $24 million, effective in February 2019 and 2020, respectively. At December 31, 2019 and 2018, over recovered retail fuel costs included in other current liabilities on Southern Company's balance sheets and over recovered regulatory clause liabilities on Mississippi Power's balance sheets were approximately $23 million and $8 million, respectively.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Mississippi Power has wholesale MRA and Market Based (MB) fuel cost recovery factors. Effective with the first billing cycle for January 2019, the wholesale MRA fuel rate increased $16 million annually and the wholesale MB fuel rate decreased by an immaterial amount. Effective January 1, 2020, the wholesale MRA fuel rate increased $1 million annually and the wholesale MB fuel rate decreased by an immaterial amount. At December 31, 2019 and 2018, over recovered wholesale MRA fuel costs included in other current liabilities on Southern Company's balance sheets and over recovered regulatory clause liabilities on Mississippi Power's balance sheets were approximately $6 million. At December 31, 2019 and 2018, over/under recovered wholesale MB fuel costs included in the balance sheets were immaterial.

Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income but will affect operating cash flows.

Kemper County Energy Facility

Overview

The Kemper County energy facility was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper County energy facility.

Schedule and Cost Estimate

In 2012, the Mississippi PSC issued an order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper County energy facility. The order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper County energy facility was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper County energy facility in service in August 2014. The combined cycle and associated common facilities portions of the Kemper County energy facility were dedicated as Plant Ratcliffe in April 2018.

In June 2017, the Mississippi PSC stated its intent to issue an order, which occurred in July 2017, directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility. The order established a new docket for the purpose of pursuing a global settlement of the related costs (Kemper Settlement Docket). In June 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future.

At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, net of $137 million in additional grants from the DOE received in April 2016. In the aggregate, Mississippi Power had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 2017.

Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasification portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below.

In 2019, Mississippi Power recorded pre-tax and after-tax charges to income of $24 million, primarily associated with the expected close out of a related DOE contract, as well as other abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets. The after-tax amount for 2019 includes an adjustment related to the tax abandonment of the Kemper IGCC following the filing of the 2018 tax return. In 2018, Mississippi Power recorded pre-tax charges to income of $37 million ($68 million benefit after tax), primarily associated with abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets, as well as the impact of a change in the valuation allowance for the related state income tax NOL carryforward.

Mississippi Power expects to substantially complete mine reclamation activities in 2020 and dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2024. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion,

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

and property taxes, are estimated to total $17 million in 2020, $15 million to $16 million annually in 2021 through 2023, and $5 million in 2024.

See Note 10 to the financial statements for additional information.

Rate Recovery

In February 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement), which resolved all cost recovery issues, modified the CPCN to limit the Kemper County energy facility to natural gas combined cycle operation, and provided for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which included the impact of the Tax Reform Legislation. The revenue requirement was based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).

Under the Kemper Settlement Agreement, retail customer rates were reduced by approximately $26.8 million annually, effective with the first billing cycle of April 2018, and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date.

On November 26, 2019, Mississippi Power filed the Mississippi Power 2019 Base Rate Case, which reflects the elimination of separate rates for costs associated with the Kemper County energy facility; these costs are proposed to be included in rates for PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. The ultimate outcome of this matter cannot be determined at this time.

Lignite Mine and CO₂ Pipeline Facilities

Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. The mine started commercial operation in June 2013. In connection with the Kemper County energy facility construction, Mississippi Power also constructed a pipeline for the transport of captured CO₂.

In 2010, Mississippi Power executed a management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020, with monitoring expected to continue through 2027. See Note 6 to the financial statements for additional information.

On December 31, 2019, Mississippi Power transferred ownership of the CO₂pipeline to an unrelated gas pipeline company, with no resulting impact on income. In conjunction with the transfer of the CO₂pipeline, the parties agreed to enter into a 15-year firm transportation agreement, which is expected to be signed by March 2020, providing for the conversion by the pipeline company of the CO₂pipeline to a natural gas pipeline to be used for the delivery of natural gas to Plant Ratcliffe. The agreement will be treated as a finance lease for accounting purposes upon commencement, which is expected to occur by August 2020. See Note 9 to the financial statements for additional information.

Government Grants

In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper County energy facility through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2. In 2016, additional DOE grants in the amount of $137 million were awarded to the Kemper County energy facility. Through December 31, 2018, Mississippi Power received total DOE grants of $387 million, of which $382 million reduced the construction costs of the Kemper County energy facility and $5 million reimbursed Mississippi Power for expenses associated with DOE reporting. In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power expects to close out the DOE contract related to the Kemper County energy facility in 2020. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the Kemper County energy facility. The ultimate outcome of this matter cannot be determined at this time; however, it could have a material impact on Southern Company's and Mississippi Power's financial statements.

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Southern Company and Subsidiary Companies 2019 Annual Report

Municipal and Rural Associations Tariff

Mississippi Power provides wholesale electric service to Cooperative Energy, East Mississippi Electric Power Association, and the City of Collins, all located in southeastern Mississippi, under a long-term, cost-based, FERC-regulated MRA tariff.

In 2017, Mississippi Power and Cooperative Energy executed, and the FERC accepted, a Shared Service Agreement (SSA), as part of the MRA tariff, under which Mississippi Power and Cooperative Energy will share in providing electricity to the Cooperative Energy delivery points under the tariff, effective January 1, 2018. The SSA may be cancelled by Cooperative Energy with 10 years notice after December 31, 2020. As of December 31, 2019, Cooperative Energy has the option to decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5% annually, with required notice, up to a maximum total reduction of 11%, or approximately $9 million in cumulative annual base revenues.

On May 7, 2019, the FERC accepted Mississippi Power's requested $3.7 million annual decrease in MRA base rates effective January 1, 2019, as agreed upon in the MRA Settlement Agreement, resolving all matters related to the Kemper County energy facility, similar to the retail rate settlement agreement approved by the Mississippi PSC in February 2018, and reflecting the impacts of the Tax Reform Legislation.

Cooperative Energy Power Supply Agreement

Effective April 1, 2018, Mississippi Power and Cooperative Energy amended and extended a previous power supply agreement through March 31, 2021, which was subsequently extended through May 31, 2021. The amendment increased the total capacity from 86 MWs to 286 MWs.

Cooperative Energy also has a 10-year network integration transmission service agreement (NITSA) with SCS for transmission service to certain delivery points on Mississippi Power's transmission system through March 31, 2021. As a result of the PSA amendment, Cooperative Energy and SCS also amended the terms of the NITSA, which the FERC approved, to provide for the purchase of incremental transmission capacity from April 1, 2018 through March 31, 2021.

Southern Company Gas

Utility Regulation and Rate Design

The natural gas distribution utilities are subject to regulations and oversight by their respective state regulatory agencies. Rates charged to customers vary according to customer class (residential, commercial, or industrial) and rate jurisdiction. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE. Rate base generally consists of the original cost of the utility plant in service, working capital, and certain other assets, less accumulated depreciation on the utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.

The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, Marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. The Marketers file their rates monthly with the Georgia PSC. As a result of operating in a deregulated environment, Atlanta Gas Light's role includes:

distributing natural gas for Marketers;

constructing, operating, and maintaining the gas system infrastructure, including responding to customer service calls and leaks;

reading meters and maintaining underlying customer premise information for Marketers; and

planning and contracting for capacity on interstate transportation and storage systems.

Atlanta Gas Light earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically. The Marketers add these fixed charges when billing customers. This mechanism, called a straight-fixed-variable rate design, minimizes the seasonality of Atlanta Gas Light's revenues since the monthly fixed charge is not volumetric or directly weather dependent. See "GRAM" and "PRP" herein for additional information.

With the exception of Atlanta Gas Light, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are largely a function of weather conditions and price levels for natural gas. Specifically, customer demand substantially increases during the Heating Season when natural gas is used for heating purposes. Southern Company Gas has various mechanisms, such as weather and revenue normalization mechanisms and weather derivative instruments, that limit exposure to weather changes within typical ranges in these utilities' respective service territories.

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Southern Company and Subsidiary Companies 2019 Annual Report

cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company Gas' revenues or net income, but will affect cash flows. Since Atlanta Gas Light does not sell natural gas directly to its end-use customers, it does not utilize a traditional natural gas cost recovery mechanism. However, Atlanta Gas Light does maintain natural gas inventory for the Marketers in Georgia and recovers the cost through recovery mechanisms approved by the Georgia PSC specific to Georgia's deregulated market. In addition to natural gas recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs as well as environmental remediation and energy efficiency plans. In traditional rate designs, utilities recover a significant portion of the fixed customer service and pipeline infrastructure costs based on assumed natural gas volumes used by customers. The utilities, including Nicor Gas beginning in November 2019, have decoupled regulatory mechanisms that Southern Company Gas believes encourage conservation by separating the recoverable amount of these fixed costs from the amounts of natural gas used by customers. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" for additional information. Also see "Construction Programs – Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" for additional information regarding infrastructure replacement programs at certain of the natural gas distribution utilities.

The following table provides regulatory information for Southern Company Gas' natural gas distribution utilities:



	Nicor Gas	Atlanta Gas Light	Virginia Natural Gas	Chattanooga Gas
Authorized ROE^(a)	9.73%	10.25%	9.50%	9.80%
Authorized ROErange^(a)	N/A	10.05% - 10.45%	9.00% - 10.00%	N/A
Weather normalization mechanisms^(b)			ü	ü
Decoupled, including straight-fixed-variable rates^(c)	ü	ü	ü
Regulatory infrastructure program rates^(d)	ü		ü
Bad debt rider^(e)	ü		ü	ü
Energy efficiency plan^(f)	ü		ü
Annual base rate adjustment mechanism^(g)		ü		ü
Year of last rate decision	2019	2019	2018	2018


(a)	Atlanta Gas Light's authorized ROE and ROE range became effective on January 1, 2020. Atlanta Gas Light's ROE for 2019 was 10.75%.

(b)

Regulatory mechanisms that allow recovery of costs in the event of unseasonal weather, but are not direct offsets to the potential impacts on earnings of weather and customer consumption. These mechanisms are designed to help stabilize operating results by increasing base rate amounts charged to customers when weather is warmer than normal and decreasing amounts charged when weather is colder than normal.


(c)	Allows for recovery of fixed customer service costs separately from assumed natural gas volumes used by customers. On October 2, 2019, Nicor Gas received approval for a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a monthly benchmark level of revenue per rate class for recovery.


(d)	Programs that update or expand distribution systems and LNG facilities.


(e)	The recovery (refund) of bad debt expense over (under) an established benchmark expense. Nicor Gas, Virginia Natural Gas, and Chattanooga Gas recover the gas portion of bad debt expense through their purchased gas adjustment mechanisms.


(f)	Recovery of costs associated with plans to achieve specified energy savings goals.


(g)	Regulatory mechanism allowing annual adjustments to base rates up or down based on authorized ROE and/or ROE range.

GRAM

In December 2019, the Georgia PSC approved the continuation of GRAM as part of Atlanta Gas Light's 2019 rate case order. Various infrastructure programs previously authorized by the Georgia PSC, including the Integrated Vintage Plastic Replacement Program (i-VPR) to replace aging plastic pipe and the Integrated System Reinforcement Program (i-SRP) to upgrade Atlanta Gas Light's distribution system and LNG facilities in Georgia, continue under GRAM and the recovery of and return on the infrastructure program investments are included in annual base rate adjustments. The future expected costs to be recovered through rates related to allowed, but not incurred, costs are recognized in an unrecognized ratemaking amount that is not reflected on the balance sheets. This allowed cost is primarily the equity return on the capital investment under the infrastructure programs in place prior to GRAM. See "Unrecognized Ratemaking Amounts" herein for additional information. The Georgia PSC reviews Atlanta Gas Light's performance annually under GRAM. See "Rate Proceedings" herein for additional information.

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Southern Company and Subsidiary Companies 2019 Annual Report

Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation of the Integrated Customer Growth Program to extend pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. As a result, a new tariff was created, effective October 10, 2017, to provide up to $15 million annually for Atlanta Gas Light to commit to strategic economic development projects. Projects under this tariff must be approved by the Georgia PSC.

PRP

Atlanta Gas Light previously recovered PRP costs through a PRP surcharge established in 2015 to address recovery of the under recovered PRP balance and the related carrying costs. Effective January 2018, PRP costs are being recovered through GRAM and base rates until the earlier of the full recovery of the under recovered amount or December 31, 2025. The under recovered balance at December 31, 2019 was $135 million, including $70 million of unrecognized equity return. See "Rate Proceedings" and "Unrecognized Ratemaking Amounts" herein for additional information.

Rate Proceedings

Nicor Gas

In January 2018, the Illinois Commission approved a $137 million increase in annual base rate revenues, including $93 million related to the recovery of investments under the Investing in Illinois program, effective in February 2018, based on a ROE of 9.8%. In May 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. The benefits of the Tax Reform Legislation from January 25, 2018 through May 4, 2018 were refunded to customers via bill credits and concluded in the second quarter 2019.

In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission. On October 2, 2019, the Illinois Commission approved a $168 million annual base rate increase effective October 8, 2019. The base rate increase included $65 million related to the recovery of program costs under the Investing in Illinois program and was based on a ROE of 9.73% and an equity ratio of 54.2%. Additionally, the Illinois Commission approved a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a monthly benchmark level of revenue per rate class for recovery.

Atlanta Gas Light

On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC. On December 19, 2019, the Georgia PSC approved a $65 million annual base rate increase, effective January 1, 2020, based on a ROE of 10.25% and an equity ratio of 56%. Earnings will be evaluated against a ROE range of 10.05% to 10.45%, with disposition of any earnings above 10.45% to be determined by the Georgia PSC. Additionally, the Georgia PSC approved continuation of the previously authorized inclusion in base rates of the recovery of and return on the infrastructure program investments, including, but not limited to, GRAM adjustments, and a reauthorization and continuation of GRAM until terminated by the Georgia PSC. GRAM filing rate adjustments will be based on the authorized ROE of 10.25%. GRAM adjustments for 2021 may not exceed 5% of 2020 base rates. The 5% limitation does not set a precedent in any future rate proceedings by Atlanta Gas Light.

On January 31, 2020, in accordance with the Georgia PSC's order for the 2019 rate case, Atlanta Gas Light filed a recommended notice of proposed rulemaking for a long-range planning tool. The proposal provides for participating natural gas utilities to file a comprehensive capacity supply and related infrastructure delivery plan for a 10-year period, including capital and related operations and maintenance expense budgets. Participating natural gas utilities would file an updated 10-year plan at least once every third year under the proposal. Related costs of implementing an approved comprehensive plan would be included in the utility's next rate case or GRAM filing. The rulemaking process is expected to be completed during 2020.

Virginia Natural Gas

In December 2018, the Virginia Commission approved Virginia Natural Gas' annual information form filing, which reduced annual base rates by $14 million effective January 1, 2019 due to lower tax expense as a result of the Tax Reform Legislation, along with customer refunds, via bill credits, for $14 million related to 2018 tax benefits deferred as a regulatory liability at December 31, 2018. These customer refunds were completed in the first quarter 2019.

On February 3, 2020, Virginia Natural Gas filed a notice of intent with the Virginia Commission as required prior to the filing of a base rate case, which will occur between April 3, 2020 and April 30, 2020. The ultimate outcome of this matter cannot be determined at this time.

See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" for additional information.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Affiliate Asset Management Agreements

With the exception of Nicor Gas, the natural gas distribution utilities use asset management agreements with an affiliate, Sequent, for the primary purpose of reducing utility customers' gas cost recovery rates through payments to the utilities by Sequent. For Atlanta Gas Light, these payments are controlled by the Georgia PSC and are utilized for infrastructure improvements and to fund heating assistance programs, rather than as a reduction to gas cost recovery rates. Under these asset management agreements, Sequent supplies natural gas to the utility and markets available pipeline and storage capacity to improve the overall cost of supplying gas to the utility customers. Currently, the natural gas distribution utilities primarily purchase their gas from Sequent. The purchase agreements require Sequent to provide firm gas to the natural gas distribution utilities, but these natural gas distribution utilities maintain the right and ability to make their own long-term supply arrangements if they believe it is in the best interest of their customers.

Each agreement provides for Sequent to make payments to the natural gas distribution utility through either an annual minimum guarantee within a profit sharing structure, a profit sharing structure without an annual minimum guarantee, or a fixed fee.

Unrecognized Ratemaking Amounts

The following table illustrates Southern Company Gas' authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain regulatory infrastructure programs. These amounts will be recognized as revenues in Southern Company Gas' financial statements in the periods they are billable to customers, the majority of which will be recovered by 2025.



	December 31, 2019		December 31, 2018
	(in millions)
Atlanta Gas Light	$	70	$	95
Virginia Natural Gas	10		11
Nicor Gas	2		4
Total	$	82	$	110

Construction Programs

The Registrants are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations.

For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4. See "Nuclear Construction" herein for additional information. Also see "Regulatory Matters – Alabama Power" herein for information regarding Alabama Power's construction of Plant Barry Unit 8.

While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See "Southern Power" herein, "Acquisitions and Dispositions – Southern Power" herein, and Note 15 to the financial statements under "Southern Power" for additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities.

Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See "Southern Company Gas" herein for additional information regarding infrastructure improvement programs at the natural gas distribution utilities and certain pipeline construction projects.

See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements" herein for additional information regarding the ~~Company's storm damage reserve.~~Registrants' capital requirements for their construction programs, including estimated totals for each of the next five years.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

Nuclear Construction

In ~~2008,~~2009, the ~~Company, acting for itself~~Georgia PSC certified construction of Plant Vogtle Units 3 and ~~as agent for Oglethorpe~~4. Georgia Power ~~Corporation (OPC),~~holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. In 2012, the ~~Municipal Electric Authority~~NRC issued the related combined construction and operating licenses, which allowed full construction of ~~Georgia (MEAG Power), and~~ the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, Vogtle Owners), entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (WECTEC) (Westinghouse and WECTEC, collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities atto begin. Until March 2017, construction on Plant Vogtle ~~(Vogtle~~Units 3 and 4 ~~Agreement).~~

~~Under the terms of~~continued under the Vogtle 3 and 4 Agreement,

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Southern Company and Subsidiary Companies 2019 Annual Report

which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle ~~Owners agreed to pay~~Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a ~~purchase price subject to certain price escalations~~time and ~~adjustments, including fixed escalation amounts~~materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and ~~index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The~~testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees, subject to an aggregate cap of 10% of the contract price, or approximately $920 million to $930 million. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharingis terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for ~~Contractor~~itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs ~~under certain conditions (which the Company has not been notified have occurred) with maximum additional capital costs under this provision attributable~~plus a base fee and an at-risk fee, which is subject to ~~the Company (based~~adjustment based on ~~the Company's ownership interest) of approximately $114 million.~~Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally ~~(and not~~(not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to ~~the Contractor~~Bechtel under the ~~Vogtle 3 and 4~~Bechtel Agreement. The ~~Company's proportionate share is 45.7%. In~~Vogtle Owners may terminate the ~~event of certain credit rating downgrades of~~Bechtel Agreement at any time for their convenience, provided that the Vogtle ~~Owner, such Vogtle Owner~~Owners will be required to ~~provide a letter of credit or other credit enhancement.~~

~~Certain obligations of Westinghouse have been guaranteed by Toshiba Corporation (Toshiba), Westinghouse's parent company. In~~pay amounts related to work performed prior to the event of certain credit rating downgrades of Toshiba, Westinghouse is required to provide letters of credit or other credit enhancement. In December 2015, Toshiba experienced credit rating downgrades and Westinghouse providedtermination (including the ~~Vogtle Owners with $920 million of letters of credit. These letters of credit remain in place in accordance with the terms~~applicable portion of the ~~Vogtle 3~~base fee), certain termination-related costs, and, ~~4 Agreement.~~

~~On February 14, 2017, Toshiba announced preliminary earnings results for the period ended December 31, 2016, which included a substantial goodwill impairment charge~~ at Westinghouse attributed to increased cost estimates to complete its U.S. nuclear projects, including Plant Vogtle Units 3 and 4. Toshiba also warned that it will likely be in a negative equity position as a resultcertain stages of the ~~charges. At~~work, the same time, Toshiba reaffirmed its commitment to its U.S. nuclear projects with implementation of management changes and increased oversight. An inability or failure by the Contractor to perform its obligations under the Vogtle 3 and 4 Agreement could have a material impact on the construction of Plant Vogtle Units 3 and 4.

~~Under the terms~~applicable portion of the ~~Vogtle 3 and 4 Agreement, the Contractor does not have a right to terminate the Vogtle 3 and 4 Agreement for convenience. The Contractor~~at-risk fee. Bechtel may terminate the ~~Vogtle 3 and 4~~Bechtel Agreement under certain circumstances, including certain Vogtle Owner ~~suspension or delays~~suspensions of ~~work, action by a governmental authority to permanently stop~~ work, certain breaches of the ~~Vogtle 3 and 4~~Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. In

See Note 8 to the ~~event~~financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of ~~an abandonment of work by the Contractor, the maximum liability~~default, mandatory prepayment events, and conditions to borrowing.

Cost and Schedule

Georgia Power's approximate proportionate share of the ~~Contractor under the~~remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 ~~Agreement~~by the expected in-service dates of November 2021 and November 2022, respectively, is ~~increased significantly, but remains subject~~as follows:



	(in billions)
Base project capital cost forecast^(a)(b)	$	8.2
Construction contingency estimate	0.2
Total project capital cost forecast^(a)(b)	8.4
Net investment as of December 31, 2019^(b)	(5.9		)
Remaining estimate to complete^(a)	$	2.5


(a)	Excludes financing costs expected to be capitalized through AFUDC of approximately $300 million, of which $23 million had been accrued through December 31, 2019.


(b)	Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.

As of December 31, 2019, approximately $140 million of the $366 million construction contingency estimate established in the second quarter 2018 was allocated to ~~limitations. The Vogtle Owners~~the base capital cost forecast for cost risks including, among other factors, construction productivity; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. As and when construction contingency is spent, Georgia Power may ~~terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs.~~

~~In 2009,~~request the Georgia PSC ~~voted~~ to ~~certify~~evaluate those expenditures for rate recovery.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 ~~with~~will total approximately $3.1 billion, of which $2.2 billion had been incurred through December 31, 2019.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a ~~certified capital cost~~regular basis to incorporate current information available, particularly in the areas of ~~$4.418 billion.~~ commodity installation, system turnovers, and workforce statistics.

In ~~addition, in 2009~~April 2019, Southern Nuclear established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the ~~Georgia PSC approved inclusion~~regulatory-approved in-service dates of ~~the Plant Vogtle Units~~November 2021 for Unit 3 and ~~4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows the Company to recover financing costs~~November 2022 for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period.Unit 4. The ~~Georgia PSC approved an NCCR tariff of $368 million for 2014, as well as increases to the NCCR tariff of approximately $27 million and $19 million effective January 1, 2015 and 2016, respectively.~~

~~The Company is required to file semi-annual Vogtle Construction Monitoring (VCM) reports~~project has faced challenges with the ~~Georgia PSC by February 28~~April 2019 aggressive strategy targets, including, but not limited to, electrical and ~~August 31 each year. In accordance with~~pipefitting labor productivity and closure rates for work packages, which resulted in a backlog of activities and completion percentages below the 2009 certification order, the Company requested amendments to the Plant Vogtle Units 3 and 4 certificate in both the February 2013 (eighth VCM) and February 2015 (twelfth VCM) filings, when projected construction capital costs to be borne by the Company increased by 5% above the certified costs and estimated in-service dates were extended. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between the Company and the Georgia PSC Staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and the Company. In April ~~2015, the Georgia PSC recognized that the certified cost and the 2013 Stipulation did not constitute a cost recovery cap and deemed the amendment~~2019 aggressive strategy targets. However,

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~~Georgia Power~~Southern Company ~~2016~~and Subsidiary Companies 2019 Annual Report

~~requested in~~Southern Nuclear and Georgia Power believe that existing productivity levels and pace of activity completion are sufficient to meet the regulatory-approved in-service dates.

In February ~~2015 filing unnecessary~~2020, Southern Nuclear updated its cost and ~~withdrawn until~~schedule forecast, which did not change the ~~completion~~projected overall capital cost forecast and confirmed the expected in-service dates of ~~construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation.~~

On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Effective December 31, 2015, the Company, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to June 30, 2019November 2021 for Unit 3 and ~~June 30, 2020~~November 2022 for Unit ~~4; (iv) provide~~4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. Other milestone dates did not change. Achievement of the aggressive site work plan relies on meeting increased monthly production and activity target values during 2020. To meet these 2020 targets, existing craft, including subcontractors, construction productivity must improve and be sustained above historical average levels, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, must be maintained, and additional supervision and other field support resources must be retained. Southern Nuclear and Georgia Power continue to believe that ~~delay liquidated damages will commence if~~pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the ~~nuclear fuel loading date for each unit does not occur~~units by ~~December 31, 2018 for Unit 3~~their regulatory-approved in-service dates.

As construction, including subcontract work, continues and ~~December 31, 2019 for Unit 4;~~testing and ~~(v) provide that~~system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related craft labor productivity, particularly in the ~~Company,~~installation of electrical and mechanical commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on ~~its ownership interest, will pay to~~new technology that only within the ~~Contractor and capitalize to~~last few years began initial operation in the ~~project cost approximately $350 million,~~global nuclear industry at this scale), or regional transmission upgrades, any of which ~~approximately $263 million had been paid as of December 31, 2016. In addition,~~may require additional labor and/or materials; or other issues could arise and change the ~~Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3~~projected schedule and ~~4 Agreement, including cyber security,~~for which costs are reflected in the Company's current in-service forecast of $5.440 billion. Further, as part of the settlement and Westinghouse's acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor and (ii) the Vogtle Owners, Chicago Bridge & Iron Co, N.V., and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.estimated cost.

On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above the Company's current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) the Company would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be the Company's average cost of long-term debt. If the Georgia PSC adjusts the Company's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be the Company's average cost of long-term debt.

Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or when placed in service, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than the Company's base rate case required to be filed by July 1, 2019.

The Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which through that date totaled $3.7 billion. The Company expects to file the sixteenth VCM report, covering the period from July 1 through December 31, 2016, requesting approval of $222 million of construction capital costs incurred during that period, with the Georgia PSC by February 28, 2017. The Company's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.9 billion as of December 31, 2016, and the Company had incurred $1.3 billion in financing costs through December 31, 2016.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

As of December 31, 2016, the Company had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between the Company and the DOE and a multi-advance credit facility among the Company, the DOE, and the FFB. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, and mandatory prepayment events.

There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may ~~arise as construction proceeds.~~arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely ~~resolution~~submittal by Southern Nuclear of ~~Inspections, Tests, Analyses, and Acceptance Criteria~~the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, ~~as construction proceeds,~~ which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved project schedule is currently estimated to result in additional base capital costs ~~either~~of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners ~~or the Contractor or~~entered into an amendment to ~~both.~~

In addition to Toshiba's reaffirmation of its commitment, the Contractor provided the Company with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. The Company is currently reviewing a preliminary summary schedule supporting these dates that ultimately must be reconciled to a detailed integrated project schedule. As construction continues, the risk remains that challenges with Contractor performance including labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. The Company expects the Contractor to employ mitigation efforts and believes the Contractor is responsible for any related costs under the Vogtle 3 and 4 Agreement. The Company estimates its financing coststheir joint ownership agreements for Plant Vogtle Units 3 and 4 to ~~be approximately $30 million per month,~~provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with ~~total construction period financing costs~~the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of ~~approximately $2.5 billion. Additionally, the Company estimates its owner's costs to be approximately $6 million per month, net~~Georgia Power and/or Southern Nuclear as agent, except in cases of ~~delay liquidated damages.~~willful misconduct.

~~The revised forecasted in-service dates are within the timeframe contemplated~~As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle ~~Cost Settlement Agreement~~Units 3 and ~~would enable both units~~4 were required to ~~qualify for production tax credits~~vote to continue construction. In September 2018, the ~~IRS has allocated~~Vogtle Owners unanimously voted to ~~each~~continue construction of Plant Vogtle Units 3 and 4.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 ~~which require~~under certain circumstances. On January 14, 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the ~~applicable unit to be placed in service before 2021. The net present value~~provisions of the ~~production tax credits is estimated at approximately $400 million per unit.~~

~~Future claims by~~MEAG Term Sheet. On February 18, 2019, Georgia Power, the ~~Contractor or~~other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the ~~Company (on behalf~~Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.Owner Term Sheet.

The ultimate outcome of these matters cannot be determined at this time.

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At December 31, 2019, Georgia Power had recovered approximately $2.2 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. On December 17, 2019, the Georgia PSC approved Georgia Power's request to decrease the NCCR tariff by $62 million annually, effective January 1, 2020.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $75 million,

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

$100 million, and $25 million in 2019, 2018, and 2017, respectively, and are estimated to have negative earnings impacts of approximately $140 million, $240 million, and $190 million in 2020, 2021, and 2022, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. On October 29, 2019, the Georgia Court of Appeals issued an opinion affirming the Fulton County Superior Court's ruling that the Georgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, the Georgia Court of Appeals remanded the case to the Fulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy. Georgia Power believes the petitions have no merit; however, an adverse outcome in the litigation combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.

On February 18, 2020, the Georgia PSC approved Georgia Power's twentieth VCM report and its concurrently-filed twenty-first VCM report, including approval of (i) $1.2 billion of construction capital costs incurred from July 1, 2018 through June 30, 2019 and (ii) $21.5 million of expenditures related to Georgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings (which expenditures had previously been deferred by the Georgia PSC for later approval). Through the twenty-first VCM, the Georgia PSC has approved total construction capital costs incurred through June 30, 2019 of $6.7 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). On February 19, 2020, Georgia Power filed its twenty-second VCM report with the Georgia PSC covering the period from July 1, 2019 through December 31, 2019, requesting approval of $674 million of construction capital costs incurred during that period.

The ultimate outcome of these matters cannot be determined at this time.

Southern Power



Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Counterparties	PPA Contract Period
Projects Completed During the Year Ended December 31, 2019
Mankato expansion^(a)	Natural Gas	385	Mankato, MN	May 2019	Northern States Power Company	20 years
Wildhorse Mountain ^(b)	Wind	100	Pushmataha County, OK	December 2019	Arkansas Electric Cooperative Corporation	20 years
Projects Under Construction at December 31, 2019
Reading^(c)	Wind	200	Osage and Lyon Counties, KS	Second quarter 2020	Royal Caribbean Cruises LTD	12 years
Skookumchuck^(d)	Wind	136	Lewis and Thurston Counties, WA	Second quarter 2020	Puget Sound Energy	20 years

(a)

Southern Power completed the sale of its equity interests in Plant Mankato, including the expansion, to a subsidiary of Xcel on January 17, 2020. The expansion unit started providing energy under a PPA with Northern States Power on June 1, 2019. See "Acquisitions and Dispositions – Southern Power – Sales of Natural Gas and Biomass Plants" herein and Note 15 to the financial statements under "Southern Power" and "Assets Held for Sale" for additional information.


(b)	In May 2018, Southern Power purchased 100% of the membership interests of the Wildhorse Mountain facility. In December 2019, Southern Power entered into a tax equity partnership and, as a result, owns 100% of the Class B membership interests.


(c)	In August 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the Class B membership interests. The ultimate outcome of this matter cannot be determined at this time.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

(d)

In October 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. In December 2019, Southern Power entered into a tax equity agreement as the Class B member with funding of the tax equity amounts expected to occur upon commercial operation. Shortly after commercial operation, Southern Power may sell a noncontrolling interest in these Class B membership interests to another partner. The ultimate outcome of this matter cannot be determined at this time.

Total aggregate construction costs for the two projects under construction at December 31, 2019, excluding acquisition costs, are expected to be between $490 million and $535 million. At December 31, 2019, total costs of construction incurred for these projects were $417 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Southern Company Gas

Infrastructure Replacement Programs and Capital Projects

Southern Company Gas continues to focus on capital discipline and cost control while pursuing projects and initiatives that are expected to have current and future benefits to customers, provide an appropriate return on invested capital, and help ensure the safety and reliability of the utility infrastructure. In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide timely recovery of capital expenditures for specific infrastructure replacement programs. Total capital expenditures incurred during 2019 for gas distribution operations were $1.4 billion.

The following table and discussions provide updates on the infrastructure replacement programs and capital projects at the natural gas distribution utilities at December 31, 2019. These programs are risk-based and designed to update and replace cast iron, bare steel, and mid-vintage plastic materials or expand Southern Company Gas' distribution systems to improve reliability and meet operational flexibility and growth. The anticipated expenditures for these programs in 2020 are quantified in the discussion below.



Utility	Program	Recovery	Expenditures in 2019		Expenditures Since Project Inception		Pipe Installed Since Project Inception	Scope of Program	Program Duration	Last Year of Program
			(in millions)				(miles)	(miles)	(years)
Nicor Gas	Investing in Illinois(*)	Rider	$	396	$	1,712	843	1,450	9	2023
Virginia Natural Gas	Steps to Advance Virginia's Energy (SAVE and SAVE II)	Rider	45		244		363	770	13	2024
Total			$	441	$	1,956	1,206	2,220


(*)	Includes replacement of pipes, compressors, and transmission mains along with other improvements such as new meters. Scope of program miles is an estimate and subject to change.

Nicor Gas

In conjunction with the base rate case order issued by the Illinois Commission in January 2018, Nicor Gas is recovering program costs incurred prior to December 31, 2017 through base rates. Additionally, the Illinois Commission's approval of Nicor Gas' rate case on October 2, 2019 included $65 million in annual revenues related to the recovery of program costs from January 1, 2018 through September 30, 2019 under the Investing in Illinois program. See "Regulatory Matters – Southern Company Gas – Rate Proceedings" herein for additional information.

Virginia Natural Gas

In 2012, the Virginia Commission approved the SAVE program, an accelerated infrastructure replacement program. In 2016 and on September 25, 2019, the Virginia Commission approved amendments and extensions to the SAVE program. The latest extension allows Virginia Natural Gas to continue replacing aging pipeline infrastructure through 2024 and increases its authorized investment under the previously-approved plan from $35 million to $40 million in 2019 with additional annual investments of $50 million in 2020, $60 million in 2021, $70 million in each year from 2022 through 2024, and a total potential

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

variance of up to $5 million allowed for the program, for a maximum total investment over the six-year term (2019 through 2024) of $365 million. Virginia Natural Gas expects to invest $50 million under this program in 2020.

The SAVE program is subject to annual review by the Virginia Commission. In accordance with the base rate case order issued by the Virginia Commission in 2017, Virginia Natural Gas is recovering program costs incurred prior to September 1, 2017 through base rates. Program costs incurred subsequent to September 1, 2017 are currently recovered through a separate rider and are subject to future base rate case proceedings.

On December 6, 2019, Virginia Natural Gas filed an application with the Virginia Commission for a 24.1-mile header improvement project to improve resiliency and increase the supply of natural gas delivered to energy suppliers, including Virginia Natural Gas. The cost of the project is expected to total $346 million. The Virginia Commission is expected to rule on this application in the second quarter 2020. Construction is expected to begin in June 2021 and the project is expected to be placed in service in the fourth quarter 2022. The ultimate outcome of this matter cannot be determined at this time.

Atlanta Gas Light

As discussed under "Regulatory Matters – Southern Company Gas – Utility Regulation and Rate Design" herein, i-SRP and i-VPR will continue under GRAM and the recovery of and return on current and future infrastructure program capital investments will be included in base rates.

Pipeline Construction Projects

The Atlantic Coast Pipeline has experienced challenges to its permits since construction began in 2018. During the third and fourth quarters 2018, a FERC stop work order, together with delays in obtaining permits necessary for construction and construction delays due to judicial actions, impacted the cost and schedule for the project. Project cost estimates are approximately $8.0 billion ($400 million for Southern Company Gas), excluding financing costs. On October 4, 2019, the U.S. Supreme Court agreed to hear Atlantic Coast Pipeline's appeal of a lower court ruling that overturned a key permit for the project. On January 7, 2020, the U.S. Court of Appeals for the Fourth Circuit vacated another key permit. The operator of the joint venture has indicated that it currently expects to complete construction by the end of 2021 and place the project in service shortly thereafter.

On February 7, 2020, Southern Company Gas entered into an agreement with Dominion Atlantic Coast Pipeline, LLC for the sale of its interest in Atlantic Coast Pipeline. The transaction is expected to be completed in the first half of 2020; however, the ultimate outcome cannot be determined at this time. See Note 15 to the financial statements under "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline" for additional information.

Also in 2014, Southern Company Gas entered into a partnership in which it holds a 20% ownership interest in the PennEast Pipeline, an interstate pipeline company formed to develop and operate an approximate 118-mile natural gas pipeline between New Jersey and Pennsylvania. The expected initial transportation capacity of 1.0 Bcf per day is under long-term contracts, mainly with public utilities and other market-serving entities, such as electric generation companies, in New Jersey, Pennsylvania, and New York. Southern Company Gas believes this pipeline will alleviate takeaway constraints in the Marcellus region and help mitigate some of the price volatility experienced during recent winters.

Expected project costs related to the PennEast Pipeline for Southern Company Gas total approximately $300 million, excluding financing costs. In January 2018, the PennEast Pipeline received initial FERC approval. Work continues with state and federal agencies to obtain the required permits to begin construction. On September 10, 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On February 18, 2020, PennEast Pipeline filed a petition for a writ of certiorari to seek U.S. Supreme Court review of the appellate court decision. On December 30, 2019, PennEast Pipeline filed a two-year extension request with the FERC to complete the project by January 19, 2022.

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Southern Company and Subsidiary Companies 2019 Annual Report

Additionally, on January 30, 2020, PennEast Pipeline filed an amendment with the FERC to construct the pipeline project in two phases. The first phase would consist of 68 miles of pipe, constructed entirely within Pennsylvania, which is expected to be completed by November 2021. The second phase would include the remaining route in Pennsylvania and New Jersey and is targeted for completion in 2023. FERC approval of the amended plan is required prior to beginning the first phase.

The ultimate outcome of these matters cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project cancellation, any of which could result in an impairment of one or both of Southern Company Gas' investments and could have a material impact on Southern Company's and Southern Company Gas' financial statements. Southern Company Gas evaluated its investments and determined there was no impairment as of December 31, 2019.

See Notes 3 and 7 to the financial statements under "Guarantees" and "Southern Company Gas – Equity Method Investments," respectively, for additional information on these pipeline projects.

Southern Power's Power Sales Agreements

General

Southern Power has PPAs with some of the traditional electric operating companies, other investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers. The PPAs are expected to provide Southern Power with a stable source of revenue during their respective terms.

Many of Southern Power's PPAs have provisions that require Southern Power or the counterparty to post collateral or an acceptable substitute guarantee in the event that S&P or Moody's downgrades the credit ratings of the respective company to an unacceptable credit rating or if the counterparty is not rated or fails to maintain a minimum coverage ratio.

On January 29, 2019, Pacific Gas & Electric Company (PG&E) filed petitions to reorganize under Chapter 11 of the U.S. Bankruptcy Code. Southern Power, together with its noncontrolling partners, owns four solar facilities where PG&E is the energy off-taker for approximately 207 MWs of capacity under long-term PPAs. PG&E is also the transmission provider for these four facilities and two of Southern Power's other solar facilities. At December 31, 2019, Southern Power had outstanding accounts receivables due from PG&E of $2 million related to the PPAs and $33 million related to the transmission interconnections (of which $27 million is classified in receivables – other and $6 million is classified in other deferred charges and assets). Subsequent to December 31, 2019, Southern Power received $15 million in accordance with a November 2019 bankruptcy court order granting payment of transmission interconnections for amounts due and owing. Southern Power continues to evaluate the recoverability of its investments in these solar facilities under various scenarios, including selling the related energy into the competitive markets, and has concluded that these solar facilities are not impaired. PG&E has continued to perform under the terms of the PPAs. Southern Power does not expect a material impact to its financial statements if, as a result of the bankruptcy proceedings, PG&E does not perform in accordance with the PPAs or the terms of the PPAs are renegotiated; however, the ultimate outcome of this matter cannot be determined at this time.

Southern Power is working to maintain and expand its share of the wholesale markets. During 2019, Southern Power saw an increase in the demand for energy and capacity that can be served from natural gas generating facilities, especially in the Southeast, and expects that this increase in demand will continue in the near term (2020-2022), with timing varying depending on the market. During 2019, Southern Power successfully remarketed approximately 190 to 650 MWs of annual natural gas generation capacity to load-serving entities through several PPAs extending over the next nine years. Southern Power calculates an investment coverage ratio for its generating assets, including those owned with various partners, based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction) as the investment amount. With the inclusion of investments associated with the wind facilities currently under construction, as well as other capacity and energy contracts, and excluding Plant Mankato, which was sold on January 17, 2020, Southern Power's average investment coverage ratio at December 31, 2019 was 93% through 2024 and 90% through 2029, with an average remaining contract duration of approximately 14 years. See "Acquisitions and Dispositions – Southern Power" and "Construction Programs – Southern Power" herein for additional information.

Natural Gas

Southern Power's electricity sales from natural gas facilities are primarily through long-term PPAs that consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated generating unit where all or a portion of the generation from that unit is reserved for that customer. Southern Power typically has the ability to serve the unit or block sale customer from an alternate resource. The second type, referred to as requirements service, provides that Southern Power serve the customer's capacity and energy requirements from a combination of the customer's own generating units and

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from Southern Power resources not dedicated to serve unit or block sales. Southern Power has rights to purchase power provided by the requirements customers' resources when economically viable.

As a general matter, substantially all of the PPAs provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel or purchased power relating to the energy delivered under such PPAs. To the extent a particular generating facility does not meet the operational requirements contemplated in the PPAs, Southern Power may be responsible for excess fuel costs. With respect to fuel transportation risk, most of Southern Power's PPAs provide that the counterparties are responsible for the availability of fuel transportation to the particular generating facility.

Capacity charges that form part of the PPA payments are designed to recover fixed and variable operation and maintenance costs based on dollars-per-kilowatt year. In general, to reduce Southern Power's exposure to certain operation and maintenance costs, Southern Power has LTSAs. See Note 1 to the financial statements under "Long-Term Service Agreements" for additional information.

Solar and Wind

Southern Power's electricity sales from solar and wind (renewable) generating facilities are also primarily through long-term PPAs; however, these solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or provide Southern Power a certain fixed price for the electricity sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Generally, under the renewable generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.

Income Tax Matters

~~Bonus Depreciation~~Consolidated Income Taxes

On behalf of the Registrants, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In ~~December 2015,~~accordance with IRS regulations, each company is jointly and severally liable for the ~~Protecting Americans from~~ federal tax liability.

The impact of certain tax events at Southern Company and/or its other subsidiaries can, and does, affect each Registrant's ability to utilize certain tax credits. See "Tax ~~Hikes (PATH) Act~~Credits" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein and Note 10 to the financial statements for additional information.

Federal Tax Reform Legislation

In 2017, the Tax Reform Legislation was signed into ~~law.~~ law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduced the federal corporate income tax rate to 21%, retained normalization provisions for public utility property and existing renewable energy incentives, and repealed the corporate alternative minimum tax. In addition, under the Tax Reform Legislation, NOLs generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year. The projected reduction of Southern Company's consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards. See "Consolidated Income Taxes" herein and Note 10 to the financial statements for information on Southern Company's joint consolidated income tax allocation agreement.

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Bonus ~~depreciation was extended for qualified property~~Depreciation

Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service ~~through 2020. The PATH Act allows~~after September 27, 2017 remain eligible for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. ~~The extension of~~Based on provisional estimates, bonus depreciation ~~included in the PATH Act~~ is expected to result in ~~approximately $300 million of~~ positive cash flows for the ~~2016 tax year and approximately $210 million for the 2017 tax year.~~ Registrants as follows:



	2019 Tax Year		2020 Tax Year
	(in millions)
Southern Company	$	989	$	382
Alabama Power	180		68
Georgia Power	314		56
Mississippi Power	7		2
Southern Power^(*)	87		95
Southern Company Gas	190		58


(*)	Cash flows resulting from bonus depreciation for Southern Power would also be impacted by Southern Power's use of tax equity partnerships.

See Note 510 to the financial statements under "Current and Deferred Income Taxes" for additional information. The ultimate outcome of this matter cannot be determined at this time.

~~Other~~Tax Credits

The Tax Reform Legislation retained solar energy incentives of 30% ITC for projects that commenced construction by December 31, 2019; 26% ITC for projects that commence construction in 2020; 22% ITC for projects that commence construction in 2021; and a permanent 10% ITC for projects that commence construction on or after January 1, 2022. In addition, the Tax Reform Legislation retained wind energy incentives of 100% PTC for projects that commenced construction in 2016; 80% PTC for projects that commenced construction in 2017; 60% PTC for projects that commenced construction in 2018; and 40% PTC for projects that commenced construction in 2019. As a result of a tax extenders bill passed in December 2019, projects that begin construction in 2020 will be entitled to 60% PTC. Projects commencing construction after 2020 will not be entitled to any PTCs. Southern Company has received ITCs and PTCs in connection with investments in solar, wind, and biomass facilities primarily at Southern Power and Georgia Power.

Southern Power's ITCs relate to its investment in new solar facilities acquired or constructed and its PTCs relate to the first 10 years of energy production from its wind facilities, which have had, and may continue to have, a material impact on Southern Power's cash flows and net income. At December 31, 2019, Southern Company and Southern Power had approximately $1.8 billion and $1.4 billion, respectively, of unutilized ITCs and PTCs, which are currently expected to be fully utilized by 2024, but could be further delayed. Since 2018, Southern Power has been utilizing tax equity partnerships for wind and solar projects, where the tax partner takes significantly all of the respective federal tax benefits. These tax equity partnerships are consolidated in Southern Company's and Southern Power's financial statements using the HLBV methodology to allocate partnership gains and losses. See Note 1 to the financial statements under "General" for additional information on the HLBV methodology and Note 1 to the financial statements under "Income Taxes" and Note 10 to the financial statements under "Deferred Tax Assets and Liabilities – Tax Credit Carryforwards" and "Effective Tax Rate" for additional information regarding utilization and amortization of credits and the tax benefit related to associated basis differences.

General Litigation Matters

The ~~Company is~~Registrants are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ ~~and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.~~

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

The ultimate outcome of such pending or potential litigation or regulatory matters against ~~the Company~~each Registrant and any subsidiaries cannot be ~~predicted~~determined at this time; however, for current proceedings not specifically reported herein or in ~~Note~~Notes 2 and 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on ~~the Company's~~such Registrant's financial statements. See ~~Note~~Notes 2 and 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.

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Southern Company ~~regularly evaluates~~and Subsidiary Companies 2019 Annual Report

Southern Company

In January 2017, a securities class action complaint was filed against Southern Company, certain of its ~~operations~~officers, and ~~costs. Primarily~~certain former Mississippi Power officers in ~~response~~the U.S. District Court for the Northern District of Georgia by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. Also in 2017, the defendants filed a motion to ~~changing customer expectations~~dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In March 2018, the court issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and ~~payment patterns, including electronic payments~~Mississippi Power and ~~alternative payment locations,~~dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and ~~on-going efforts~~denied a motion to ~~increase overall operating efficiencies,~~certify the issue for interlocutory appeal. On August 22, 2019, the court certified the plaintiffs' proposed class. On September 5, 2019, the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. On December 19, 2019, the U.S. District Court for the Northern District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expires on March 31, 2020.

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, ~~initiated~~certain of its directors, certain of its officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost ~~containment activities throughout~~and schedule. Further, the ~~enterprise~~complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in ~~July 2016, including~~bringing the ~~closure~~lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In April 2018, the court entered an order staying this lawsuit until 30 days after the resolution of ~~104 local offices~~any dispositive motions or any settlement, whichever is earlier, in the securities class action.

In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and ~~an employee attrition plan affecting approximately 300 positions. Charges~~certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost ~~containment activities did~~and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. In May 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. On August 5, 2019, the court granted a motion filed by the plaintiff on July 17, 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.

Georgia Power

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application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. On October 23, 2019, the Georgia PSC issued an order that found and concluded that Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 6, 2019, Georgia Power filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities.

Mississippi Power

In May 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf of Martin Transport, Inc. (Martin Transport), an affiliate of Martin. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019. On September 27, 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court of Kemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel, and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with the Martin arbitration case and the separate court case was dismissed. On December 16, 2019, Southern Company and Mississippi Power each filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel granted Southern Company's motion and dismissed Southern Company from the arbitration. An adverse outcome in this proceeding could have a material impact on Southern Company's and Mississippi Power's financial statements.

In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and three members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint on March 14, 2019. The amended complaint included four additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.

See Note 2 to the financial statements under "Kemper County Energy Facility" for additional information.

Other Matters

Southern Company

A subsidiary of Southern Holdings has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. See Note 1 to the financial statements under "Leveraged Leases" for additional information.

The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. In 2017, the financial and operational performance of one of the lessees and the associated generation assets raised significant concerns about the short-term ability of the generation assets to produce cash flows sufficient to support ongoing operations and the lessee's contractual obligations and its ability to make the remaining semi-annual lease payments through the end of the lease term in 2047. In addition, following the expiration of the existing power offtake agreement in 2032, the lessee also is exposed to remarketing risk, which encompasses the price and availability of alternative sources of generation.

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While all lease payments through December 31, 2019 have been paid in full due to recent operational improvements, operational and remarketing risks and the resulting cash liquidity challenges persist, and significant concerns continue regarding the lessee's ability to make the remaining semi-annual lease payments. These challenges may also impact the expected residual value of the generation assets. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets under various scenarios. Based on current forecasts of energy prices in the years following the expiration of the existing PPA, Southern Company concluded that it is no longer probable that all of the associated rental payments will be received over the term of the lease. As a result, during the fourth quarter 2019, Southern Company revised the estimate of cash flows to be received under the leveraged lease, which resulted in an impairment charge of $17 million ($13 million after tax). If any future lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which totaled approximately $76 million at December 31, 2019. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments. The ultimate outcome of this matter cannot be determined at this time.

Mississippi Power

In conjunction with Southern Company's sale of Gulf Power, NextEra Energy held back $75 million of the purchase price pending Mississippi Power and Gulf Power negotiating a mutually acceptable revised operating agreement for Plant Daniel. In addition, Mississippi Power and Gulf Power committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. The ultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including by the FERC and the Mississippi PSC, and cannot be determined at this time. See Note 15 to the financial statements under "Southern Company" for information regarding the sale of Gulf Power.

Southern Company Gas

A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early.

In the third quarter 2019, management determined that it no longer planned to obtain the core samples during 2020 that are necessary to determine the composition of the sheath surrounding the edge of the salt dome. Core sampling is a requirement of the Louisiana DNR to put the cavern back in service; as a result, the cavern will not return to service by 2021. This change in plan, which affects the future operation of the entire storage facility, resulted in a pre-tax impairment charge of $91 million ($69 million after-tax) recorded by Southern Company Gas in 2019. Southern Company Gas continues to monitor the pressure and overall structural integrity of the entire facility pending any future decisions regarding decommissioning.

Southern Company Gas has two other natural gas storage facilities located in California and Texas, which could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Sustained diminished natural gas storage values could trigger impairment of either or both of these natural gas storage facilities, which have a combined net book value of $326 million at December 31, 2019.

The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on the ~~Company's results~~financial statements of ~~operations, financial position, or cash flows. The cost containment activities are expected to reduce operating costs in 2017.~~Southern Company and Southern Company Gas.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

The ~~Company prepares its~~Registrants prepare their financial statements in accordance with GAAP. Significant accounting policies are described in ~~Note 1~~the notes to the financial statements. In the application of these policies, certain estimates are made that may have a material impact

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on the ~~Company's~~ results of operations and related ~~disclosures.~~disclosures of the applicable Registrants (as indicated in the section descriptions herein). Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.

Utility Regulation (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

The ~~Company is~~traditional electric operating companies and the natural gas distribution utilities are subject to retail regulation by ~~the Georgia PSC~~their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by the FERC. These regulatory agencies set the rates the ~~Company is~~traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable ~~costs.~~costs, including a reasonable ROE. As a result, the ~~Company applies~~traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards ~~has a further effect on the Company's~~for rate regulated entities also impacts their financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the ~~Company;~~traditional electric operating companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the ~~Company's~~ results of operations and financial condition of the applicable Registrants than they would on a non-regulated company.

Revenues related to regulated utility operations as a percentage of total operating revenues in 2019 for the applicable Registrants were as follows: 87% for Southern Company, 99% for Alabama Power, 97% for Georgia Power, 100% for Mississippi Power, and 80% for Southern Company Gas.

As reflected in Note 12 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the financial statements of the applicable Registrants.

Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4

(Southern Company and Georgia Power)

In 2016, the Georgia PSC approved the Vogtle Cost Settlement Agreement, which resolved certain prudency matters in connection with Georgia Power's fifteenth VCM report. In 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor, as well as a modification of the Vogtle Cost Settlement Agreement. The Georgia PSC's related order stated that under the modified Vogtle Cost Settlement Agreement, (i) none of the $3.3 billion of costs incurred through December 31, 2015 should be disallowed as imprudent; (ii) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs; (iii) Georgia Power would have the burden of proof to show that any capital costs above $5.68 billion were prudent; (iv) Georgia Power's total project capital cost forecast of $7.3 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds) was found reasonable and did not represent a cost cap; and (v) prudence decisions would be made subsequent to achieving fuel load for Unit 4.

In its order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

In the second quarter 2018, Georgia Power revised its base cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power did not seek rate recovery for the $0.7 billion increase in costs included in the base capital cost forecast in the nineteenth VCM report. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory

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proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.

Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4.

As of December 31, 2019, approximately $140 million of the $366 million construction contingency estimate established in the second quarter 2018 was allocated to the base capital cost forecast for cost risks including, among other factors, construction productivity; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. As and when construction contingency is spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of commodity installation, system turnovers, and workforce statistics.

In April 2019, Southern Nuclear established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. The project has faced challenges with the April 2019 aggressive strategy targets, including, but not limited to, electrical and pipefitting labor productivity and closure rates for work packages, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets. However, Southern Nuclear and Georgia Power believe that existing productivity levels and pace of activity completion are sufficient to meet the regulatory-approved in-service dates.

In February 2020, Southern Nuclear updated its cost and schedule forecast, which did not change the projected overall capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. Other milestone dates did not change. Achievement of the aggressive site work plan relies on meeting increased monthly production and activity target values during 2020. To meet these 2020 targets, existing craft, including subcontractors, construction productivity must improve and be sustained above historical average levels, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, must be maintained, and additional supervision and other field support resources must be retained. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates.

There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

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Southern Company and Subsidiary Companies 2019 Annual Report

not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Given the significant complexity involved in estimating the future costs to complete construction and start-up of Plant Vogtle Units 3 and 4 and the significant management judgment necessary to assess the related uncertainties surrounding future rate recovery of any projected cost increases, as well as the potential impact on results of operations and cash flows, Southern Company and Georgia Power consider these items to be critical accounting estimates. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.

Accounting for Income Taxes (Southern Company, Mississippi Power, Southern Power, and Southern Company Gas)

The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Southern Company system operates.

On behalf of its subsidiaries, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited or utilized at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of Southern Company's and its subsidiaries' current financial ~~statements.~~position and results of operations, including currently available information about future years, to estimate when future taxable income will be realized.

Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets, or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on the financial statements of the applicable Registrants.

Given the significant judgment involved in estimating NOL and tax credit carryforwards and multi-state apportionments for all subsidiaries, the applicable Registrants consider deferred income tax liabilities and assets to be critical accounting estimates.

Asset Retirement Obligations (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

AROs are computed as the ~~fair~~present value of the estimated ~~ultimate~~ costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.

The ~~liability~~ARO liabilities for ~~AROs~~the traditional electric operating companies primarily ~~relates~~relate to facilities that are subject to the CCR Rule and the related state rules, principally ash ponds. In addition, Alabama Power and Georgia Power have retirement obligations related to the decommissioning of ~~the Company's~~ nuclear facilities ~~which include the Company's~~(Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and ~~2, and facilities that are subject to the CCR Rule, principally ash ponds. In addition, the Company has retirement obligations~~2). The traditional electric operating companies also have AROs related to various landfill sites, asbestos removal, and underground storage tanks, as well as, for Alabama Power, disposal of polychlorinated biphenyls in certain transformers and ~~asbestos removal.~~ sulfur hexafluoride gas in certain substation breakers, for Georgia Power, gypsum cells and restoration of land at the end of long-term land leases for solar facilities, and for Mississippi Power, mine reclamation and water wells.

The traditional electric operating companies and Southern Company Gas also ~~has~~have identified other retirement obligations, such as obligations related to certain electric transmission and distribution facilities, ~~including~~certain asbestos-containing material within long-term assets not subject to ongoing repair and maintenance activities, certain wireless communication towers, the disposal of polychlorinated biphenyls in certain ~~transformers;~~transformers, leasehold ~~improvements;~~improvements, equipment on customer ~~property;~~property, and property associated with the ~~Company's~~Southern Company system's rail lines and natural gas pipelines. However, liabilities for the removal of these

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~The Company previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule discussed above.~~ The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule ~~requirements for closure. As further analysis is performed, including evaluation of~~and the ~~expected method of compliance, refinement of assumptions underlying the~~related state rules. The traditional electric operating companies expect to update their ARO cost estimates ~~such~~periodically as additional information related to these assumptions becomes available. See Note 6 to the ~~quantities of CCR at each site, and the determination of timing with respect~~financial statements for additional information, including increases to ~~compliance activities, including the potential for closing~~AROs related to ash ponds prior to the end of their currently anticipated useful life, the Company expects to continue to periodically update these estimates. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals" herein for additional information.recorded during 2019 by certain Registrants.

Given the significant judgment involved in estimating AROs, the ~~Company considers~~applicable Registrants consider the liabilities for AROs to be critical accounting estimates.

~~See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.~~

Pension and Other Postretirement Benefits (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

The ~~Company's calculation~~applicable Registrants' calculations of pension and other postretirement benefits expense isare dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term rate of return (LRR) on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the ~~Company believes that~~applicable Registrants believe the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect ~~its~~their pension and other postretirement ~~benefits~~benefit costs and obligations.

Key elements in determining the ~~Company's~~applicable Registrants' pension and other postretirement benefit expense are the ~~expected long-term return on plan assets~~LRR and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. For purposes of determining ~~its liability~~the applicable Registrants' liabilities related to the pension and other postretirement benefit plans, ~~the~~Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. ~~For 2015~~The discount rate assumption impacts both the service cost and ~~prior years,~~non-service costs components of net periodic benefit costs as well as the ~~Company computed the interest cost component of its net periodic~~projected benefit obligations.

The LRR on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, historical experience, and expectations that consider external actuarial advice, and represents the average rate of earnings expected over the long term on the assets invested to provide for anticipated future benefit payments. Southern Company determines the amount of the expected return on plan assets component of non-service costs by applying the LRR of various asset classes to Southern Company's target asset allocation. The LRR only impacts the non-service costs component of net periodic benefit costs for the following year and is set annually at the beginning of the year.

For 2019, the LRR assumption for qualified pension plan assets was reduced from 7.95% to 7.75% for purposes of determining net periodic pension expense ~~using~~as a result of changes in the ~~same single-point discount rate. For 2016,~~economic outlook used in estimating the ~~Company adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year.~~expected returns as of December 31, 2018. As a result of the ~~interest cost~~decrease in the LRR, the non-service costs component of net periodic pension expense increased by $24 million for the Southern Company system in 2019. See the table below for the impact on each Registrant.

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Southern Company and ~~other postretirement benefit plan~~Subsidiary Companies 2019 Annual Report

For 2020, net periodic pension expense ~~decreased~~will be impacted by ~~approximately $35 million in 2016.~~

~~A 25 basis point~~two factors: a change in the approach used to determine the LRR assumption and cash contributions totaling $1.1 billion to the qualified pension plan made in December 2019. Historically, Southern Company has set the LRR assumption using asset return modeling based on geometric returns that reflect the compound average returns for dependent annual periods. Beginning in 2020, Southern Company will set the LRR assumption using an arithmetic mean which represents the expected simple average return to be earned by the pension plan assets over any ~~significant~~one year. Southern Company believes the use of the arithmetic mean is more compatible with the LRR's function of estimating a single year's investment return. Excluding the additional pension contribution in December 2019, the change in the LRR assumption ~~(discount~~will reduce the non-service costs component of net periodic pension expense by $78 million for the Southern Company system in 2020. See the table below for the impact on each Registrant. The contributions in 2019 will further reduce expense by $88 million for the Southern Company system in 2020.



	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions)
Increase (decrease) in pension expense:
2019	$	24		$	5		$	8		$	1		$	2
2020	(78		)	(18		)	(25		)	(4		)	(7		)

The following table illustrates the sensitivity to changes in the applicable Registrants' long-term assumptions with respect to the discount rate, ~~salaries, or~~salary increases, and the long-term rate of return on plan ~~assets) would result in a $10 million or less change in total annual benefit expense and a $147 million or less change in projected obligations.~~assets:



	Increase/(Decrease) in
25 Basis Point Change in:	Total Benefit Expense for 2020	Projected Obligation for Pension Plan at December 31, 2019	Projected Obligation for Other Postretirement Benefit Plans at December 31, 2019
	(in millions)
Discount rate:
Southern Company	$41/$(39)	$549/$(518)	$57/$(54)
Alabama Power	$10/$(10)	$131/$(123)	$14/$(13)
Georgia Power	$12/$(11)	$166/$(156)	$21/$(20)
Mississippi Power	$2/$(2)	$25/$(23)	$2/$(2)
Southern Company Gas	$1/$(1)	$38/$(36)	$6/$(6)
Salaries:
Southern Company	$23/$(22)	$118/$(113)	$–/$–
Alabama Power	$6/$(6)	$33/$(32)	$–/$–
Georgia Power	$6/$(6)	$34/$(33)	$–/$–
Mississippi Power	$1/$(1)	$5/$(5)	$–/$–
Southern Company Gas	$1/$(1)	$3/$(3)	$–/$–
Long-term return on plan assets:
Southern Company	$35/$(35)	N/A	N/A
Alabama Power	$9/$(9)	N/A	N/A
Georgia Power	$11/$(11)	N/A	N/A
Mississippi Power	$2/$(2)	N/A	N/A
Southern Company Gas	$3/$(3)	N/A	N/A

See Note 211 to the financial statements for additional information regarding pension and other postretirement benefits.

~~Contingent Obligations~~

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Southern Company and Subsidiary Companies 2019 Annual Report

Asset Impairment (Southern Company, Southern Power, and Southern Company Gas)

Goodwill (Southern Company and Southern Company Gas)

The acquisition method of accounting requires the assets acquired and liabilities assumed to be recorded at the date of acquisition at their respective estimated fair values. The applicable Registrants have recognized goodwill as of the date of their acquisitions, as a residual over the fair values of the identifiable net assets acquired. Goodwill is tested for impairment at the reporting unit level on an annual basis in the fourth quarter of the year as well as on an interim basis as events and changes in circumstances occur, including, but not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. A reporting unit is the operating segment, or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by management. Components are aggregated if they have similar economic characteristics.

As part of the impairment tests, the applicable Registrant may perform an initial qualitative assessment to determine whether it is more likely than not that the fair value of each reporting unit is less than its carrying amount before applying the quantitative goodwill impairment test. If the applicable Registrant elects to perform the qualitative assessment, it evaluates relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events, and events specific to each reporting unit. If the applicable Registrant determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or it elects not to perform a qualitative assessment, it compares the fair value of the reporting unit to its carrying value to determine if the fair value is greater than its carrying value.

Goodwill for Southern Company and Southern Company Gas was $5.3 billion and $5.0 billion, respectively, at December 31, 2019. For its 2019 and 2018 annual impairment tests, Southern Company Gas performed the qualitative assessment and determined that it was more likely than not that the fair value of all of its reporting units with goodwill exceeded their carrying amounts, and therefore no quantitative analysis was required. For its 2017 annual impairment test, Southern Company Gas performed the quantitative assessment, which resulted in the fair value of all of its reporting units that have goodwill exceeding their carrying value. For its annual impairment tests for PowerSecure, Southern Company performed the quantitative assessment, which resulted in the fair value of goodwill at PowerSecure exceeding its carrying value in all years presented. However, Southern Company recorded goodwill impairment charges totaling $34 million in 2019 as a result of its decision to sell certain PowerSecure business units. See Note 15 to the financial statements under "Southern Company" for additional information.

The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact the applicable Registrant's results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the asset, the various characteristics of the asset, and projected cash flows. As the determination of an asset's fair value and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the applicable Registrants consider these estimates to be critical accounting estimates.

See Note 1 to the financial statements under "Goodwill and Other Intangible Assets and Liabilities" for additional information regarding the applicable Registrants' goodwill.

Long-Lived Assets (Southern Company, Southern Power, and Southern Company Gas)

Impairments of long-lived assets of the traditional electric utilities and natural gas distribution utilities are generally related to specific regulatory disallowances. The applicable Registrants assess their other long-lived assets for impairment whenever events or changes in circumstances indicate that an asset's carrying amount may not be recoverable. If an indicator exists, the asset is tested for recoverability by comparing the asset carrying value to the sum of the undiscounted expected future cash flows directly attributable to the asset's use and eventual disposition. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded equal to the difference between the carrying value and the fair value of the asset. In addition, when assets are identified as held for sale, an impairment loss is recognized to the extent the carrying value of the assets or asset group exceeds their fair value less cost to sell. A high degree of judgment is required in developing estimates related to these evaluations, which are based on projections of various factors, some of which have been quite volatile in recent years.

Southern Power's investments in long-lived assets are primarily generation assets, whether in service or under construction. Excluding the natural gas distribution utilities, Southern Company Gas' investments in long-lived assets are primarily natural gas transportation and storage facility assets, whether in service or under construction. In addition, exclusive of the traditional electric operating companies and natural gas distribution utilities, Southern Company's investments in long-lived assets also include investments in leveraged leases.

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Southern Company and Subsidiary Companies 2019 Annual Report

For Southern Power, examples of impairment indicators could include significant changes in construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, the inability to remarket generating capacity for an extended period, the unplanned termination of a customer contract or the inability of a customer to perform under the terms of the contract, or the inability to deploy wind turbine equipment to a development project. For Southern Company Gas, examples of impairment indicators could include, but are not limited to, significant changes in the U.S. natural gas storage market, construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, the inability to renew or extend customer contracts or the inability of a customer to perform under the terms of the contract, attrition rates, or the inability to deploy a development project. For Southern Company's investments in leveraged leases, impairment indicators include changes in estimates of future rental payments to be received under the lease as well as the residual value of the leased asset at the end of the lease.

As the determination of the expected future cash flows generated from an asset, an asset's fair value, and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the applicable Registrants consider these estimates to be critical accounting estimates.

See Note 3 to the financial statements under "Other Matters" and Note 15 to the financial statements for information on certain assets recently evaluated for impairment.

Derivatives and Hedging Activities (Southern Company and Southern Company Gas)

Determining whether a contract meets the definition of a derivative instrument, contains an embedded derivative requiring bifurcation, or qualifies for hedge accounting treatment is complex. The treatment of a single contract may vary from period to period depending upon accounting elections, changes in the applicable Registrant's assessment of the likelihood of future hedged transactions, or new interpretations of accounting guidance. As a result, judgment is required in determining the appropriate accounting treatment. In addition, the estimated fair value of derivative instruments may change significantly from period to period depending upon market conditions, and changes in hedge effectiveness may impact the accounting treatment.

Derivative instruments (including certain derivative instruments embedded in other contracts) are recorded on the balance sheets as either assets or liabilities measured at their fair value. If the transaction qualifies for, and is designated as, a normal purchase or normal sale, it is exempt from fair value accounting treatment and is, instead, subject to traditional accrual accounting. The applicable Registrant utilizes market data or assumptions that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique.

Changes in the derivatives' fair value are recognized concurrently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, derivative gains and losses offset related results of the hedged item in the income statement in the case of a fair value hedge, or gains and losses are deferred in OCI on the balance sheets until the hedged transaction affects earnings in the case of a cash flow hedge. Additionally, a company is required to formally designate a derivative as a hedge as well as document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting treatment.

Southern Company Gas uses derivative instruments primarily to reduce the impact to its results of operations due to the risk of changes in the price of natural gas and, to a lesser extent, Southern Company Gas hedges against warmer-than-normal weather and interest rates. The fair value of natural gas derivative instruments used to manage exposure to changing natural gas prices reflects the estimated amounts that Southern Company Gas would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. For derivatives utilized at gas marketing services and wholesale gas services that are not designated as accounting hedges, changes in fair value are reported as gains or losses in results of operations in the period of change. Gas marketing services records derivative gains or losses arising from cash flow hedges in OCI and reclassifies them into earnings in the same period that the underlying hedged item is recognized in earnings.

Derivative assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The determination of the fair value of the derivative instruments incorporates various required factors. These factors include:

the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);

events specific to a given counterparty; and

the impact of nonperformance risk on liabilities.

A significant change in the underlying market prices or pricing assumptions used in pricing derivative assets or liabilities may result in a significant financial statement impact.

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Southern Company and Subsidiary Companies 2019 Annual Report

Given the assumptions used in pricing the derivative asset or liability, Southern Company and Southern Company Gas consider the valuation of derivative assets and liabilities a critical accounting estimate. See FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein and Note 14 to the financial statements for more information.

Revenue Recognition (Southern Power)

Southern Power's power sale transactions, which include PPAs, are classified in one of four general categories: leases, non-derivatives or normal sale derivatives, derivatives designated as cash flow hedges, and derivatives not designated as hedges, as described further below. For more information on derivative transactions, see FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein and Notes 1 and 14 to the financial statements. Southern Power's revenues are dependent upon significant judgments used to determine the appropriate transaction classification, which must be documented upon the inception of each contract.

Lease Transactions

Southern Power considers the following factors to determine whether the sales contract is a lease:

Assessing whether specific property is explicitly or implicitly identified in the agreement;

Determining whether the fulfillment of the arrangement is dependent on the use of the identified property; and

Assessing whether the arrangement conveys to the counterparty substantially all of the economic benefits and the right to direct the use of the asset.

If the contract meets the above criteria for a lease, Southern Power performs further analysis as to whether the lease is classified as operating, financing, or sales-type. All of Southern Power's power sales contracts that are determined to be leases are accounted for as operating leases and the capacity revenue is recognized on a straight-line basis over the term of the contract and is included in Southern Power's operating revenues. Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. See Note 9 to the financial statements for additional information.

Non-Derivative and Normal Sale Derivative Transactions

If the power sales contract is not classified as a lease, Southern Power further considers the following factors to determine proper classification:

Assessing whether the contract meets the definition of a derivative;

Assessing whether the contract meets the definition of a capacity contract;

Assessing the probability at inception and throughout the term of the individual contract that the contract will result in physical delivery; and

Ensuring that the contract quantities do not exceed available generating capacity (including purchased capacity).

Contracts that do not meet the definition of a derivative or are designated as normal sales (i.e. capacity contracts which provide for the sale of electricity that involve physical delivery in quantities within Southern Power's available generating capacity) are accounted for as executory contracts. For contracts that have a capacity charge, the revenue is generally recognized in the period that it becomes billable. Revenues related to energy and ancillary services are recognized in the period the energy is delivered or the service is rendered. See Note 4 to the financial statements for additional information.

Cash Flow Hedge Transactions

Southern Power further considers the following in designating other derivative contracts for the sale of electricity as cash flow hedges of anticipated sale transactions:

Identifying the hedging instrument, the forecasted hedged transaction, and the nature of the risk being hedged; and

Assessing hedge effectiveness at inception and throughout the contract term.

These contracts are accounted for on a fair value basis and are recorded in AOCI over the life of the contract. Realized gains and losses are then recognized in operating revenues as incurred.

Derivative (Non-Hedge) Transactions

Contracts for sales of electricity, which meet the definition of a derivative and that either do not qualify or are not designated as normal sales or as cash flow hedges, are accounted for on a fair value basis and are recorded in operating revenues.

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Southern Company and Subsidiary Companies 2019 Annual Report

Acquisition Accounting (Southern Power)

Southern Power may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, Southern Power will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, the purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets, primarily related to acquired PPAs). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired.

Determining the fair value of assets acquired and liabilities assumed requires management judgment and Southern Power may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by Southern Power for potential or successful acquisitions are expensed as incurred.

Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, Southern Power fair values the arrangement with any changes recorded in the consolidated statements of income. See Note 13 to the financial statements for additional fair value information and Note 15 to the financial statements for additional information on recent acquisitions.

Variable Interest Entities (Southern Power)

Southern Power enters into partnerships with varying ownership structures. Upon entering into such arrangements, membership interests and other variable interests are evaluated to determine if the legal entity is a VIE. If the legal entity is a VIE, Southern Power will assess if it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE, making it the primary beneficiary. Making this determination may require significant management judgment.

If Southern Power is the primary beneficiary, the assets, liabilities, and results of operations of the entity are consolidated. If Southern Power is not the primary beneficiary, the legal entity is generally accounted for under the equity method of accounting. Southern Power reconsiders its conclusions as to whether the legal entity is a VIE and whether it is the primary beneficiary for events that impact the rights of variable interests, such as ownership changes in membership interests.

Southern Power has partial ownership in certain legal entities for which the contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. For these arrangements, the noncontrolling interest is accounted for under a balance sheet approach utilizing the HLBV method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a HLBV at the end of the period compared to the beginning of the period.

Contingent Obligations (All Registrants)

The Registrants are subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject itthem to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and ~~Note~~Notes 2 and 3 to the financial statements for more information regarding certain of these contingencies. The ~~Company~~Registrants periodically ~~evaluates its~~evaluate their exposure to such risks and ~~records~~record reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the ~~Company's~~ results of operations, cash flows, or financial ~~condition.~~condition of the Registrants.

Recently Issued Accounting Standards

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalentSee Note 1 to the ~~electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition~~financial statements under "Recently Adopted Accounting Standards" for ~~such sales.~~additional information.

The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it is expected to have a material impact on the Company's financial statements.

~~On February 25,~~ 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively ~~unchanged. ASU 2016-02~~unchanged and there is ~~effective~~no change to the accounting for ~~fiscal years beginning after December 15, 2018, with early adoption permitted.~~existing leveraged leases. The ~~Company is currently evaluating~~Registrants adopted the new standard ~~and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.~~

~~On March 30, 2016, the FASB issued ASU No. 2016-09,~~ ~~Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting~~ ~~(ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions~~ effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company.2019. See ~~Notes 5, 8, and 12~~Note 9 to the financial statements for ~~disclosures impacted by ASU 2016-09.~~

~~On October 24, 2016, the FASB issued ASU No. 2016-16,~~ ~~Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory~~ ~~(ASU 2016-16). Current GAAP prohibits the recognition of current~~additional information and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact.related disclosures.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

FINANCIAL CONDITION AND LIQUIDITY

Overview

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units and closures of ash ponds, to expand and improve transmission and distribution facilities, and for restoration following major storms. Southern Power's capital expenditures and other investing activities may include acquisitions or new construction associated with its overall growth strategy and to maintain its existing generation fleet's performance. Southern Company Gas' capital expenditures and other investing activities include investments to meet projected long-term demand requirements, to maintain existing natural gas distribution systems as well as to update and expand these systems, and to comply with environmental regulations.

Operating cash flows provide a substantial portion of the ~~Company's~~Registrants' cash needs. During 2019, Southern Power utilized tax credits, which provided $734 million in operating cash flows. For the three-year period from ~~2017~~2020 through ~~2019, the Company's~~2022, each Registrant's projected ~~common~~ stock dividends, capital expenditures, and debt maturities, as well as distributions to noncontrolling interests for Southern Power, are expected to exceed its operating cash flows. ~~The~~Southern Company plans to finance future cash needs in excess of its operating cash flows primarily ~~through securities issuances, capital contributions from Southern Company,~~by accessing borrowings from financial institutions and issuing debt and hybrid securities in the capital markets. Each Subsidiary Registrant plans to finance its future cash needs in excess of its operating cash flows primarily through external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Georgia Power plans to utilize borrowings through the ~~FFB.~~FFB and Southern Power plans to utilize tax equity partnership contributions. The ~~Company intends~~Registrants plan to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs and continue to monitor ~~its~~their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. See ~~"Sources~~"Sources of Capital," ~~"Financing~~"Financing Activities," "Capital Requirements," and ~~"Capital Requirements and~~ "Contractual ~~Obligations"~~Obligations" herein for additional information.

The ~~Company's~~Registrants' investments in ~~the~~their qualified pension ~~plan~~plans and Alabama Power's and Georgia Power's investments in their nuclear decommissioning trust funds increased in value ~~as of~~at December 31, ~~2016~~2019 as compared to December 31, ~~2015. On~~2018. In December ~~19, 2016,~~2019, the ~~Company~~Registrants voluntarily contributed ~~$287 million~~the following amounts to the qualified pension ~~plan.~~ plan:



	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Contributions to qualified pension plan	$	1,136	$	362	$	200	$	54	$	24	$	145

No mandatory contributions to the qualified pension ~~plan~~plans are anticipated during ~~2017. The Company also funded approximately $5 million to its nuclear decommissioning trust funds in 2016.~~2020. See ~~"Contractual Obligations"~~"Contractual Obligations" herein and Notes 16 and 211 to the financial statements under ~~"Nuclear Decommissioning"~~"Nuclear Decommissioning" and ~~"Pension~~"Pension Plans," respectively, for additional information.

At the end of 2019, the market price of Southern Company's common stock was $63.70 per share (based on the closing price as reported on the NYSE) and the book value was $26.11 per share, representing a market-to-book value ratio of 244%, compared to $43.92, $23.91, and 184%, respectively, at the end of 2018.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Analysis of Cash Flows

Net cash flows provided from (used for) operating, activities totaled $2.4 billion in 2016, a decrease of $92 million from 2015, primarily due to the voluntary contribution to the qualified pension plan, partially offset by the timing of vendor payments. Net cash provided from operating activities totaled $2.5 billion in 2015, an increase of $154 million from 2014, primarily due to increased fuel cost recovery, partially offset by the timing of vendor payments.

~~Net cash used for~~ investing, ~~activities totaled $2.3 billion, $1.9 billion,~~ and $2.2 billion in 2016, 2015, and 2014, respectively, due to gross property additions primarily related to installation of equipment to comply with environmental standards; construction of generation, transmission, and distribution facilities; and purchase of nuclear fuel. The majority of funds needed for gross property additions for the last several years has been provided from operating activities, capital contributions from Southern Company, and the issuance of debt. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information.

~~Net cash used for~~ financing activities ~~totaled $142 million, $530 million,~~in 2019 and ~~$163 million for 2016, 2015, and 2014, respectively. The decrease~~2018 are presented in cash used in 2016 compared to 2015 was primarily due to higher capital contributions from Southern Company, a decrease in redemptions and maturities of senior notes, and an increase in short-term debt, partially offset by higher common stock dividends and a decrease in borrowings from the ~~FFB for construction of Plant Vogtle Units 3 and 4. The increase in cash used in 2015 compared to 2014 was primarily due to the redemption and maturity of senior notes in 2015.~~ following table:



Net cash provided from (used for):	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
2019
Operating activities	$	5,781		$	1,779		$	2,907		$	339		$	1,385		$	1,067
Investing activities	(3,392		)	(1,963		)	(3,885		)	(263		)	(167		)	(1,386		)
Financing activities	(1,930		)	765			918			(83		)	(1,120		)	298

2018
Operating activities	$	6,945		$	1,881		$	2,769		$	804		$	631		$	764
Investing activities	(5,760		)	(2,289		)	(3,109		)	(232		)	(227		)	998
Financing activities	(1,813		)	177			(400		)	(527		)	(363		)	(1,770		)

Fluctuations in cash ~~flow~~flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

~~Significant balance sheet changes~~

Southern Company

Net cash provided from operating activities decreased $1.2 billion in ~~2016 included an increase~~2019 as compared to 2018 primarily due to the voluntary contribution to the qualified pension plan and the timing of vendor payments.

The net cash used for investing activities in ~~property, plant,~~2019 and ~~equipment~~2018 was primarily due to the traditional electric operating companies' construction of ~~$1.6 billion~~electric generation, transmission, and distribution facilities, including installation of equipment to comply with environmental standards, and capital expenditures for Southern Company Gas' infrastructure replacement programs, partially offset by proceeds from the sale transactions described in Note 15 to the financial statements, which totaled $5.1 billion and $3.0 billion in 2019 and 2018, respectively.

The net cash used for financing activities in 2019 was primarily due to common stock dividend payments and net repayments of short-term bank debt and commercial paper, partially offset by net issuances of long-term debt and the issuance of common stock. The net cash used for financing activities in 2018 was primarily due to net redemptions and repurchases of long-term debt, common stock dividend payments, and a decrease in commercial paper borrowings, partially offset by net issuances of short-term bank debt, proceeds from Southern Power's sales of non-controlling equity interests in entities indirectly owning substantially all of its solar facilities and eight of its wind facilities, and the issuance of common stock.

Alabama Power

Net cash provided from operating activities decreased $102 million in 2019 as compared to 2018primarily due to the voluntary contribution to the qualified pension plan, partially offset by the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation and increased fuel cost recovery.

The net cash used for investing activities in 2019 and 2018 was primarily due to gross property additions.

The net cash provided from financing activities in 2019 was primarily due to capital contributions from Southern Company and a long-term debt issuance, partially offset by payments of common stock dividends and a maturity of long-term debt. The net cash provided from financing activities in 2018 was primarily due to issuances of long-term debt and additional capital contributions from Southern Company, partially offset by the payment of common stock dividends and a maturity of long-term debt.

Georgia Power

Net cash provided from operating activities increased $138 million in 2019 as compared to 2018 primarily due to lower customer refunds and increased fuel cost recovery, partially offset by the voluntary contribution to the qualified pension plan.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

The net cash used for investing activities in 2019 and 2018 was primarily due to gross property additions, including a total of $2.5 billion related to the construction of Plant Vogtle Units 3 and 4. See FUTURE EARNINGS POTENTIAL – "Construction Programs – Nuclear Construction" herein for additional information on construction of Plant Vogtle Units 3 and 4.

The net cash provided from financing activities in 2019 was primarily due to borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, issuances of senior notes, capital contributions from Southern Company, and pollution control revenue bonds reoffered to the public, partially offset by payment of common stock dividends and the maturity of senior notes. The net cash used for financing activities in 2018 was primarily due to the redemption and repurchase of senior notes, payment of common stock dividends, and pollution control revenue bond repurchases, partially offset by capital contributions from Southern Company.

Mississippi Power

Net cash provided from operating activities decreased $465 million in 2019 as compared to 2018 primarily due to higher income tax refunds in 2018 as a result of the tax impact of the abandonment of the Kemper IGCC and the voluntary contribution to the qualified pension plan in 2019.

The net cash used for investing activities in 2019 and 2018 was primarily due to gross property additions.

The net cash used for financing activities in 2019 was primarily due to a return of capital to Southern Company and the redemption of senior notes, partially offset by capital contributions from Southern Company and pollution control revenue bonds reoffered to the public. The net cash used for financing activities in 2018 was primarily due to the redemption of preferred stock, long-term bank debt, short-term borrowings, and senior notes, partially offset by the issuance of senior notes and short-term borrowings.

Southern Power

Net cash provided from operating activities increased $754 million in 2019 as compared to 2018 primarily due to the utilization of federal ITCs totaling $734 million in 2019. At December 31, 2019, Southern Power had $1.4 billion of unutilized ITCs and PTCs which are expected to be fully utilized by 2024. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Tax Credits" herein for additional information.

The net cash used for investing activities in 2019 was primarily due to Southern Power's investment in DSGP and ongoing construction activities, largely offset by proceeds from the sales of Plant Nacogdoches and certain wind turbine equipment. The net cash used for investing activities in 2018 was primarily due to the construction of generating facilities and payments for renewable acquisitions, partially offset by proceeds from the disposition of the Florida Plants. See FUTURE EARNINGS POTENTIAL – "Acquisitions and Dispositions" and "Construction Programs" herein and Note 15 to the financial statements for additional information.

The net cash used for financing activities in 2019 was primarily due to returns of capital to Southern Company, the repayment at maturity of senior notes, payments of common stock dividends, and distributions to noncontrolling interests, partially offset by proceeds from net issuances of commercial paper. The net cash used for financing activities in 2018 was primarily due to returns of capital to Southern Company, payments of common stock dividends, and distributions to noncontrolling interests, partially offset by capital contributions from noncontrolling interests.

Southern Company Gas

Net cash provided from operating activities increased $303 million in 2019 as compared to 2018 primarily due to the timing of collection of customer receivables and lower income tax payments, partially offset by the timing of vendor payments and the voluntary contribution to the qualified pension plan.

The net cash used for investing activities in 2019 was primarily due to gross property additions related to utility capital expenditures and infrastructure investments recovered through replacement programs at gas distribution operations and capital contributed to equity method pipeline investments, partially offset by proceeds from the sale of Triton and capital distributions in excess of earnings from equity method pipeline investments. The net cash provided from investing activities in 2018 was primarily due to proceeds from the Southern Company Gas Dispositions, partially offset by gross property additions primarily related to utility capital expenditures and pre-approved rider and infrastructure investments recovered through replacement programs at gas distribution operations as well as net capital contributions to equity method pipeline investments.

The net cash provided from financing activities in 2019 was primarily due to capital contributions from Southern Company and proceeds from the issuance of first mortgage bonds, partially offset by the redemption of long-term debt and payments of common stock dividends. The net cash used for financing activities in 2018 was primarily due to payments of common stock dividends to

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Southern Company, return of capital to Southern Company, redemptions of gas facility revenue bonds and senior notes, and repayments of commercial paper borrowings and long-term debt, partially offset by debt issuances and capital contributions from Southern Company.

Significant Balance Sheet Changes

Southern Company

Significant balance sheet changes in 2019 for Southern Company included:

decreases in assets and liabilities held for sale of $5.0 billion and $3.3 billion, respectively, and an increase of $2.7 billion in total stockholders' equity primarily related to the sale of Gulf Power;

an increase of $2.3 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' construction of electric generation, transmission, and distribution facilities, ~~increases~~including installation of equipment to comply with environmental standards, net of $1.2 billion and $1.0 billion reclassified to other regulatory assets and regulatory assets associated with AROs, respectively, as a result of generating unit retirements at Alabama Power and Georgia Power;

an increase in other regulatory assets ~~deferred~~ of ~~$622 million and current and deferred ARO liabilities of $616 million~~$1.8 billion primarily related to ~~changes~~the $1.2 billion reclassification from property, plant, and equipment discussed above and a $0.8 billion increase in ~~ash pond closure strategy,~~ regulatory assets associated with retiree benefit plans primarily resulting from a decrease in the overall discount rate used to calculate benefit obligations;

increases in operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.8 billion, recorded upon the adoption of ASC 842;

an increase of ~~$373 million~~$1.4 billion in regulatory assets associated with AROs primarily related to the $1.0 billion reclassification from property, plant, and equipment discussed above and ARO revisions at Alabama Power and Mississippi Power related to the CCR Rule;

an increase of $1.3 billion in accumulated deferred income taxes primarily related to the expected utilization of tax credit carryforwards in the 2019 tax year as a result of ~~bonus depreciation,~~increased taxable income from the sale of Gulf Power; and ~~an increase~~

a decrease of ~~$357 million~~$0.9 billion in ~~long-term~~notes payable related to net repayments of short-term bank debt ~~due to issuances exceeding maturities.~~ and commercial paper.

See ~~Note 1~~Notes 2, 5, 6, 8, 9, 10, 11, and 15 to the financial statements for additional information.

~~The Company's ratio~~

Alabama Power

Significant balance sheet changes in 2019 for Alabama Power included:

an increase of $1.5 billion in total common stockholder's equity primarily due to ~~total capitalization plus short-term debt, was 50.0% at December 31, 2016~~a $1.2 billion capital contribution from Southern Company;

increases of $0.9 billion in regulatory assets associated with AROs and ~~49.9% at December 31, 2015.~~ $0.7 billion in other regulatory assets, deferred primarily due to the impacts of retiring and reclassifying Plant Gorgas Units 8, 9, and 10;

an increase of $0.6 billion in cash and cash equivalents; and

an increase of $0.3 billion in AROs, deferred primarily due to an increase in the ARO estimate related to ash pond facilities.

See ~~Note~~Notes 2 and 6 to the financial statements for additional information.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Georgia Power

Significant balance sheet changes in 2019 for Georgia Power included:

an increase of $1.8 billion in long-term debt (including securities due within one year) primarily due to borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, issuances of senior notes, and pollution control revenue bonds being reoffered to the public;

an increase of $1.6 billion in property, plant, and equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, net of approximately $0.8 billion reclassified to regulatory assets due to the retirement of certain generating units as approved in the Georgia Power 2019 IRP;

increases in operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.4 billion, recorded upon the adoption of ASC 842;

an increase of $1.2 billion in regulatory assets primarily due to the $0.8 billion reclassification from property, plant, and equipment discussed above and $0.2 billion associated with retiree benefit plans primarily as a result of a decrease in the overall discount rate used to calculate benefit obligations; and

an increase of $742 million in total common stockholder's equity primarily due to capital contributions from Southern Company.

See Notes 2, 8, 9, and 11 to the financial statements for additional information.

Mississippi Power

Significant balance sheet changes in 2019 for Mississippi Power included:

a decrease of $231 million in long-term debt, primarily due to the reclassification of $249 million of senior notes to securities due within one year and the redemption of $25 million of senior notes, partially offset by $43 million in pollution control revenue bonds reoffered to the public;

an increase of $107 million in other property and investments primarily due to a new tolling arrangement accounted for as a sales-type lease;

increases of $67 million in regulatory assets associated with AROs and $31 million in AROs, deferred primarily due to ARO revisions; and


•	a net change of $57 million in accumulated deferred income tax assets and liabilities primarily due to the recognition of a tax loss on the CO₂ pipeline transfer and the alternative minimum tax carryforward from prior years.

See Notes 2, 6, 8, 9, and 10 to the financial statements for additional information.

Southern Power

Significant balance sheet changes in 2019for Southern Power included:

a $662 million decrease in stockholders' equity due to returns of capital to Southern Company;

a $635 million decrease in accumulated deferred income tax assets primarily related to the utilization of tax credits for the 2019 tax year;

a $619 million decrease in long-term debt (including securities due within one year) related to the maturity of $600 million in senior notes;

a $449 million increase in notes payable due to net issuances of commercial paper; and

increases in operating lease right-of-use assets, net of amortization and operating lease obligations totaling $369 million and $376 million, respectively, recorded upon the adoption of ASC 842.

See Notes 8, 9, and 10 to the financial statements for additional information.

Southern Company Gas

Significant balance sheet changes in 2019 for Southern Company Gas included:

an increase of $950 million in property, plant, and equipment primarily due to utility capital expenditures and infrastructure investments recovered through replacement programs, partially offset by $115 million of asset impairment charges;

additional paid-in-capital of $841 million primarily related to capital contributions from Southern Company;

decreases of $373 million and $414 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and volumes of natural gas sold;

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

a $287 million decrease in equity investments in unconsolidated subsidiaries primarily due to $151 million associated with Pivotal LNG and Atlantic Coast Pipeline reclassified to assets held for sale, as well as distributions from SNG and the sale of Triton;

a $203 million increase in accumulated deferred income taxes primarily due to accelerated tax depreciation and other timing differences;

reclassification of $171 million in total assets held for sale associated with Pivotal LNG and Atlantic Coast Pipeline;

a $95 million decrease in long-term debt primarily due to the redemption of $300 million in senior notes and the repayment of $50 million in first mortgage bonds, partially offset by the issuance of $300 million in first mortgage bonds; and

increases of $93 million in operating right-of-use assets and $92 million in operating lease obligations, respectively, related to the adoption of ASC 842.

See Notes 3, 7, 8, 9, 10, and 15 to the financial statements for additional information.

Sources of Capital

Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. Southern Company does not expect to issue any equity in the capital markets through 2024.

The ~~Company plans~~Subsidiary Registrants plan to obtain the funds ~~required for construction and other purposes~~to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, ~~short-term debt,~~ external ~~security~~securities issuances, ~~term loans,~~ borrowings from ~~the FFB,~~financial institutions, and equity contributions from Southern Company. ~~However,~~In addition, Georgia Power plans to utilize borrowings from the FFB, as discussed further in Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings," Southern Power plans to utilize tax equity partnership contributions, as discussed further herein, and Southern Company Gas plans to utilize proceeds from the pending sale of its interests in Pivotal LNG and Atlantic Coast Pipeline, as discussed further in Note 15 to the financial statements under "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline."

The amount, type, and timing of any ~~future~~ financings ~~if needed,~~in 2020, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon ~~regulatory approvals,~~ prevailing market conditions, regulatory approvals (for the Subsidiary Registrants), and other factors. See "Capital Requirements" herein for additional information.

~~The Company may make borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between~~

Southern Power utilizes tax equity partnerships as one of its financing sources, where the ~~Company~~tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. During 2019, Southern Power obtained tax equity funding for the ~~DOE, the~~Wildhorse Mountain wind project and received proceeds of ~~which may be used to reimburse the Company for a portion of certain costs of construction relating to Plant Vogtle Units 3~~$97 million. See Notes 1 and 4 that are eligible for financing under the Loan Guarantee Agreement (Eligible Project Costs). Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by the Company under a multi-advance credit facility (FFB Credit Facility) among the Company, the DOE, and the FFB. Eligible Project Costs incurred through December 31, 2016 would allow for borrowings of up to $2.7 billion under the FFB Credit Facility, of which the Company has borrowed $2.6 billion. See Note 615 to the financial statements under ~~"DOE Loan Guarantee Borrowings"~~"General" and "Southern Power," respectively, for additional ~~information regarding the Loan Guarantee Agreement and Note 3 to the~~information.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~financial statements under "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.~~

The issuance of ~~long-term~~ securities by the ~~Company~~traditional electric operating companies and Nicor Gas is generally subject to the approval of the ~~Georgia PSC. In addition, the~~applicable state PSC or other applicable state regulatory agency. The issuance of ~~short-term debt~~all securities by ~~the Company~~Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company, the traditional electric operating companies, and Southern Power (excluding its subsidiaries), Southern Company ~~files~~Gas Capital, and Southern Company Gas (excluding its other subsidiaries) file registration statements with the SEC under the Securities Act of 1933, as ~~amended.~~amended (1933 Act). The amounts of securities authorized by the ~~Georgia PSC and~~appropriate regulatory authorities, as well as the ~~FERC~~securities registered under the 1933 Act, are ~~continuously~~closely monitored and appropriate filings are made to ensure flexibility in the capital markets.

The ~~Company obtains~~Registrants generally obtain financing separately without credit support from any affiliate. See Note 68 to the financial statements under ~~"Bank~~"Bank Credit ~~Arrangements"~~Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of ~~the Company~~each company are not commingled with funds of any other company in the Southern Company ~~system.~~system, except in the case of Southern Company Gas, as described below.

The traditional electric operating companies and SEGCO may utilize a Southern Company subsidiary organized to issue and sell commercial paper at their request and for their benefit. Proceeds from such issuances for the benefit of an individual company are loaned directly to that company. The obligations of each traditional electric operating company and SEGCO under these arrangements are several and there is no cross-affiliate credit support. Alabama Power also maintains its own separate commercial paper program.

Southern Company Gas Capital obtains external financing for Southern Company Gas and its subsidiaries, other than Nicor Gas, which obtains financing separately without credit support from any affiliates. Southern Company Gas maintains commercial

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

paper programs at Southern Company Gas Capital and Nicor Gas. Nicor Gas' commercial paper program supports its working capital needs as Nicor Gas is not permitted to make money pool loans to affiliates. All of the other Southern Company Gas subsidiaries benefit from Southern Company Gas Capital's commercial paper program.

By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At December 31, ~~2016,~~2019, the ~~Company's current liabilities exceeded current assets by $1.5 billion.~~ amount of subsidiary retained earnings restricted to dividend totaled $951 million. This restriction did not impact Southern Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.

The ~~Company's~~Registrants' current liabilities frequently exceed their current assets because of ~~scheduled maturities of~~ long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. See Note 8 to the financial statements for additional information. Also see "Financing Activities" herein for information on issuances of long-term debt subsequent to December 31, 2019. At December 31, 2019, the following Registrants' current liabilities exceeded their current assets, primarily as a result of securities due within one year and notes payable, as shown in the table below:



At December 31, 2019	Southern Company^(*)		Georgia Power		Mississippi Power		Southern Power
	(in millions)
Current liabilities in excess of current assets	$	2,729	$	1,902	$	125	$	945
Securities due within one year	2,989		1,025		281		824
Notes payable	2,055		365		—		549


(*)	Includes $600 million and $465 million of securities due within one year and notes payable, respectively, at the parent company.

The ~~Company intends to utilize~~Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as ~~FFB borrowings,~~ commercial paper, lines of credit, and short-term bank notes, ~~and external securities issuances,~~ as market conditions ~~permit, and~~permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company to fund its short-term capital needs. The Company has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs.Company.

Bank Credit Arrangements

At December 31, ~~2016,~~2019, the ~~Company had approximately $3 million of cash and cash equivalents. A~~Registrants' unused committed credit ~~arrangement~~arrangements with banks ~~at December 31, 2016 was $1.75 billion of which $1.73 billion was unused. This credit arrangement expires in 2020.~~were as follows:

This bank credit arrangement contains a covenant that limits debt levels and contains a cross acceleration provision to other indebtedness (including guarantee obligations) of the Company. Such cross acceleration provision to other indebtedness would trigger an event of default if the Company defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2016, the Company was in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.



At December 31, 2019	Southern Company parent		Alabama Power		Georgia Power		Mississippi Power		Southern Power^(a)		Southern Company Gas^(b)		SEGCO		Southern Company
	(in millions)
Unused committed credit	$	1,999	$	1,328	$	1,733	$	150	$	591	$	1,745	$	30	$	7,576

(a)

At December 31, 2019, Southern Power also had a continuing letter of credit facility for standby letters of credit, of which $23 million was unused. Subsequent to December 31, 2019, Southern Power entered into an additional $60 million continuing letter of credit facility for standby letters of credit. Southern Power's subsidiaries are not parties to its bank credit arrangement or to the letter of credit facilities.


(b)	Includes $1.245 billion and $500 million at Southern Company Gas Capital and Nicor Gas, respectively.

Subject to applicable market conditions, the ~~Company expects~~Registrants, Nicor Gas, and SEGCO expect to renew or replace ~~this~~their bank credit ~~arrangement,~~arrangements as needed, prior to expiration. In connection therewith, the ~~Company~~Registrants, Nicor Gas, and SEGCO may extend the maturity ~~date~~dates and/or increase or decrease the lending commitments thereunder.

~~See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.~~

A portion of the unused credit with banks is allocated to provide liquidity support to the ~~Company's pollution control~~ revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.

Short-term Borrowings

The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2016 was approximately $868 million. In addition, at December 31, 2016, the Company had $250 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional electric operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Commercial paper isand short-term bank term loans are included in notes payable in the balance sheets.

~~Table~~ Details of ~~ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~Details of~~the Registrants' short-term borrowings were as follows:

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Short-term Debt at the End of the Period
Short-term Debt During the Period ^(*)
Amount Outstanding Weighted Average Interest Rate Average Amount Outstanding Weighted Average Interest Rate Maximum Amount Outstanding
(in millions) (in millions) (in millions)
December 31, 2016:
Commercial paper $ 392
1.1 % $ 87
0.8 % $ 443
December 31, 2015:
Commercial paper $ 158
0.6 % $ 234
0.3 % $ 678
Short-term bank debt —
— % 62
0.8 % 250
Total $ 158
0.6 % $ 296
0.4 %
December 31, 2014:
Commercial paper $ 156
0.3 % $ 280
0.2 % $ 703
Short-term bank debt —
— % 56
0.9 % 400
Total $ 156
0.3 % $ 336
0.3 %



	Short-term Debt at the End of the Period
	Amount Outstanding						Weighted Average Interest Rate
	December 31,						December 31,
	2019		2018		2017		2019		2018		2017
	(in millions)
Southern Company	$	2,055	$	2,915	$	2,439	2.1	%	3.1	%	1.9	%
Alabama Power	—		—		3		—		—		3.7
Georgia Power	365		294		150		2.2		3.1		2.2
Mississippi Power	—		—		4		—		—		3.8
Southern Power	549		100		105		2.2		3.1		2.0
Southern Company Gas:
Southern Company Gas Capital	$	372	$	403	$	1,243	2.1	%	3.1	%	1.7	%
Nicor Gas	278		247		275		1.8		3.0		1.8
Southern Company Gas Total	$	650	$	650	$	1,518	2.0	%	3.0	%	1.8	%



	Short-term Debt During the Period^(*)
	Average Amount Outstanding						Weighted Average Interest Rate						Maximum Amount Outstanding
	2019		2018		2017		2019		2018		2017		2019		2018		2017
	(in millions)												(in millions)
Southern Company	$	1,240	$	3,377	$	2,672	2.6	%	2.6	%	1.5	%	$	2,914	$	5,447	$	3,668
Alabama Power	17		27		25		2.6		2.3		1.3		190		258		223
Georgia Power	371		139		427		2.7		2.5		1.8		935		710		1,460
Mississippi Power	—		68		18		—		2.0		3.0		—		300		36
Southern Power	76		188		232		2.7		2.5		1.4		578		385		419
Southern Company Gas:
Southern Company Gas Capital	$	302	$	520	$	723	2.6	%	2.3	%	1.4	%	$	490	$	1,361	$	1,243
Nicor Gas	91		123		176		2.3		2.2		1.1		278		275		525
Southern Company Gas Total	$	393	$	643	$	899	2.5	%	2.3	%	1.4	%


(*)	Average and maximum amounts are based upon daily balances during the ~~twelve-month~~12-month periods ended December 31, ~~2016, 2015,~~2019, 2018, and ~~2014.~~2017.

~~The~~

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company ~~believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank notes,~~ and ~~operating cash flows.~~Subsidiary Companies 2019 Annual Report

Financing Activities

The following table outlines the Registrants' long-term debt financing activities for the year ended December 31, 2019:



Company	Senior Note Issuances		Senior Note Maturities, Redemptions, and Repurchases		Revenue Bond Issuances and Reofferings of Purchased Bonds		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities^(a)
	(in millions)
Southern Company parent	$	—	$	2,400	$	—	$	—	$	1,725	$	—
Alabama Power	600		200		—		—		—		1
Georgia Power	750		500		584		223		1,218		13
Mississippi Power	—		25		43		—		—		—
Southern Power	—		600		—		—		—		—
Southern Company Gas	—		300		—		—		300		50
Other	—		—		—		25		—		17
Elimination^(b)	—		—		—		—		—		(7		)
Southern Company	$	1,350	$	4,025	$	627	$	248	$	3,243	$	74


(a)	Includes reductions in finance lease obligations resulting from cash payments under finance leases.


(b)	Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements.

Except as otherwise described herein, the Registrants used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The Subsidiary Registrants also used the proceeds for their construction programs.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the ~~Company plans~~Registrants plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

~~Senior~~

Southern Company

During 2019, Southern Company issued approximately 19.5 million shares of common stock through employee equity compensation plans and received proceeds of approximately $844 million.

In addition, in August 2019, Southern Company issued 34.5 million 2019 Series A Equity Units (Equity Units), initially in the form of corporate units (Corporate Units), at a stated amount of $50 per Corporate Unit, for a total stated amount of $1.725 billion. Net proceeds from the issuance were approximately $1.682 billion. Each Corporate Unit is comprised of (i) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019A Remarketable Junior Subordinated Notes due 2024, (ii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019B Remarketable Junior Subordinated Notes due 2027, and (iii) a stock purchase contract, which obligates the holder to purchase from Southern Company, no later than August 1, 2022, a certain number of shares of Southern Company's common stock for $50 in cash. See Note 8 to the financial statements under "Equity Units" for additional information.

In ~~March 2016, the~~January 2019, Southern Company ~~issued $325~~repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.

In 2019, Southern Company, through repurchases and redemptions, retired all $1.0 billion aggregate principal amount of its 1.85% Senior Notes due July 1, 2019, $350 million aggregate principal amount of its Series ~~2016A 3.25%~~2014B 2.15% Senior Notes due ~~April~~September 1, ~~2026 and $325~~2019, $750 million aggregate principal amount of its Series ~~2016B 2.40% Senior~~2018A Floating Rate Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A 3.25% Senior Notes due April 1, 2026 is being allocated to eligible green expenditures, including financing of or investments in solar generating facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar or wind generating facilities. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250February 14, 2020, and $300 million aggregate principal amount of ~~the Company's~~its Series ~~2013B~~2017A Floating Rate Senior Notes due ~~March 15, 2016,~~September 30, 2020.

Subsequent to ~~repay a portion of the Company's short-term indebtedness, and for general corporate purposes, including the Company's continuous construction program.~~

~~In April 2016, the Company's $250 million~~December 31, 2019, Southern Company issued $1.0 billion aggregate principal amount of Series ~~2011B 3.00% Senior~~2020A 4.95% Junior Subordinated Notes ~~were~~due January 30, 2080.

Alabama Power

In February 2019, Alabama Power repaid at ~~maturity.~~

~~In August 2016, the Company's~~maturity $200 million aggregate principal amount of Series ~~2013C Floating Rate~~Z 5.125% Senior Notes ~~were repaid at maturity.~~due February 15, 2019.

~~Pollution Control Revenue Bonds~~

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Southern Company and Subsidiary Companies 2019 Annual Report

In ~~January 2016, $4.085~~September 2019, Alabama Power issued $600 million aggregate principal amount of ~~Savannah Economic Development Authority Pollution Control Revenue Bonds (Savannah Electric and~~Series 2019A 3.45% Senior Notes due October 1, 2049.

Subsequent to December 31, 2019, Alabama Power ~~Company Project), First Series 1993 were repaid at maturity.~~received a capital contribution totaling $610 million from Southern Company.

~~DOE Loan Guarantee Borrowings~~

Georgia Power

In ~~June~~March and December ~~2016, the Company~~2019, Georgia Power made ~~additional~~ borrowings under the ~~FFB Credit Facility~~multi-advance credit facilities related to the Amended and Restated Loan Guarantee Agreement in an aggregate principal amount of ~~$300~~$835 million and ~~$125~~$383 million, ~~respectively. The~~respectively, with applicable interest ~~rate applicable~~rates of 3.213% and 2.537%, respectively, both for an interest period that extends to the ~~$300 million principal amount is 2.571% and the interest rate applicable to the $125 million principal amount is 3.142%, both for interest periods that extend to th~~e final maturity date of February 20, 2044. The proceeds were used to reimburse ~~the Company~~Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" for additional information.

In June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.

In September 2019, Georgia Power issued $400 million aggregate principal amount of Series 2019A 2.20% Senior Notes due September 15, 2024 and $350 million aggregate principal amount of Series 2019B 2.65% Senior Notes due September 15, 2029.

Subsequent to December 31, 2019, Georgia Power issued $700 million aggregate principal amount of Series 2020A 2.10% Senior Notes due July 30, 2023, $500 million aggregate principal amount of Series 2020B 3.70% Senior Notes due January 30, 2050, and an additional $300 million aggregate principal amount of Series 2019B 2.65% Senior Notes due September 15, 2029.

During 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and were held by Georgia Power at December 31, 2018:

$173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009;

approximately $105 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013;

$65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008;

$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994; and

approximately $72 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2013.

During 2019, Georgia Power purchased, held, and subsequently reoffered to the public an additional $115 million of pollution control revenue bonds.

In January 2019, Georgia Power redeemed approximately $13 million, $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1992, Eighth Series 1994, and Second Series 1995, respectively.

In December 2019, Georgia Power repaid at maturity $500 million aggregate principal amount of its Series 2009B 4.25% Senior Notes.

Subsequent to December 31, 2019, Georgia Power received a capital contribution totaling $500 million from Southern Company and announced the redemption of all $500 million aggregate principal amount of its Series 2017C 2.00% Senior Notes due September 8, 2020.

Mississippi Power

In March 2019, Mississippi Power reoffered to the public approximately $43 million of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased and held by Mississippi Power.

In December 2019, Mississippi Power redeemed $25 million aggregate principal amount of its Series 2018A Floating Rate Senior Notes due March 27, 2020.

Southern Power

In May 2019, Southern Power repaid at maturity a $100 million short-term floating rate bank loan.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

~~Georgia Power~~Southern Company ~~2016~~and Subsidiary Companies 2019 Annual Report

Under the Loan Guarantee Agreement, the Company is subject to customary events of default, as well as cross-defaults to other indebtedness and events of default relating to any failure to make payments under the engineering, procurement, and construction contract, as amended, relating to Plant Vogtle Units 3 and 4 or certain other agreements providing intellectual property rights for Plant Vogtle Units 3 and 4. The Loan Guarantee Agreement also includes events of default specific to the DOE loan guarantee program, including the failure of the Company orIn December 2019, Southern Nuclear to comply with requirements of law or DOE loan guarantee program requirements. In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and the Company will be required to prepay the outstandingPower repaid at maturity $600 million aggregate principal amount of ~~all borrowings under~~its Series 2016D 1.95% Senior Notes.

Also in December 2019, Southern Power entered into a short-term floating rate bank loan in the ~~FFB Credit Facility over~~aggregate principal amount of $100 million, bearing interest based on one-month LIBOR. Subsequent to December 31, 2019, Southern Power repaid the bank loan.

Southern Company Gas

In July 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of its 4.7% first mortgage bonds.

In August 2019, Southern Company Gas Capital repaid at maturity $300 million aggregate principal amount of its 5.25% Senior Notes.

In August and October 2019, Nicor Gas issued $200 million and $100 million, respectively, aggregate principal amount of first mortgage bonds in a ~~period of five years (with level principal amortization). See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information.~~private placement.

~~Credit Rating Risk~~Storm Damage Recovery

Beginning January 1, 2020, Georgia Power is recovering $213 million annually through December 31, 2022, as provided in the 2019 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. At December 31, ~~2016,~~2019, the balance in the regulatory asset related to storm damage was $410 million. The rate of storm damage cost recovery is expected to be adjusted in future regulatory proceedings as necessary. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" for additional information regarding Georgia Power's storm damage reserve.

Mississippi Power

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company ~~did~~and Subsidiary Companies 2019 Annual Report

2019 Base Rate Case

Operations Review

Reserve Margin Plan

On December 31, 2019, Mississippi Power updated its proposed RMP, originally filed in August 2018, as required by the Mississippi PSC. In 2018, Mississippi Power had proposed alternatives to reduce its reserve margin and lower or avoid operating costs, with the most economic alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. The December 2019 update noted that Plant Daniel Units 1 and 2 currently have ~~any credit arrangements that~~long-term economics similar to Plant Watson Unit 5. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. A decision by the Mississippi PSC that does not include recovery of the remaining book value of any generating units retired could have a material impact on Southern Company's and Mississippi Power's financial statements. The ultimate outcome of this matter cannot be determined at this time. See Note 3 to the financial statements under "Other Matters– Mississippi Power" for additional information on Plant Daniel Units 1 and 2.

Performance Evaluation Plan

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Energy Efficiency

Environmental Compliance Overview Plan

Fuel Cost Recovery

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in ~~payment schedules~~the billing factor should have no significant effect on Mississippi Power's revenues or ~~terminations~~net income but will affect operating cash flows.

Kemper County Energy Facility

Overview

Schedule and Cost Estimate

~~There are certain contracts that could require collateral, but not accelerated payment,~~changes in the ~~event~~cost estimate above the cost cap for the Kemper IGCC through May 2017.

In 2019, Mississippi Power recorded pre-tax and after-tax charges to income of $24 million, primarily associated with the expected close out of a ~~credit rating~~related DOE contract, as well as other abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets. The after-tax amount for 2019 includes an adjustment related to the tax abandonment of the Kemper IGCC following the filing of the 2018 tax return. In 2018, Mississippi Power recorded pre-tax charges to income of $37 million ($68 million benefit after tax), primarily associated with abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets, as well as the impact of a change in the valuation allowance for the related state income tax NOL carryforward.

Mississippi Power expects to ~~BBB- and/~~substantially complete mine reclamation activities in 2020 and dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2024. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion,

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Southern Company and Subsidiary Companies 2019 Annual Report

and property taxes, are estimated to total $17 million in 2020, $15 million to $16 million annually in 2021 through 2023, and $5 million in 2024.

See Note 10 to the financial statements for additional information.

Rate Recovery

Lignite Mine and CO₂ Pipeline Facilities

Government Grants

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Municipal and Rural Associations Tariff

In 2017, Mississippi Power and Cooperative Energy executed, and the FERC accepted, a Shared Service Agreement (SSA), as part of the MRA tariff, under which Mississippi Power and Cooperative Energy will share in providing electricity to the Cooperative Energy delivery points under the tariff, effective January 1, 2018. The SSA may be cancelled by Cooperative Energy with 10 years notice after December 31, 2020. As of December 31, 2019, Cooperative Energy has the option to decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5% annually, with required notice, up to a maximum total reduction of 11%, or ~~below.~~approximately $9 million in cumulative annual base revenues.

Cooperative Energy Power Supply Agreement

Southern Company Gas

Utility Regulation and Rate Design

The natural gas distribution utilities are subject to regulations and oversight by their respective state regulatory agencies. Rates charged to customers vary according to customer class (residential, commercial, or industrial) and rate jurisdiction. These ~~contracts are~~agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE. Rate base generally consists of the original cost of the utility plant in service, working capital, and certain other assets, less accumulated depreciation on the utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.

The natural gas market for ~~physical electricity purchases~~Atlanta Gas Light was deregulated in 1997. Accordingly, Marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and ~~sales, fuel purchases, fuel~~handle customer billing functions. The Marketers file their rates monthly with the Georgia PSC. As a result of operating in a deregulated environment, Atlanta Gas Light's role includes:

distributing natural gas for Marketers;

constructing, operating, and maintaining the gas system infrastructure, including responding to customer service calls and leaks;

reading meters and maintaining underlying customer premise information for Marketers; and

planning and contracting for capacity on interstate transportation and storage systems.

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Southern Company and Subsidiary Companies 2019 Annual Report

cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company Gas' revenues or net income, but will affect cash flows. Since Atlanta Gas Light does not sell natural gas directly to its end-use customers, it does not utilize a traditional natural gas cost recovery mechanism. However, Atlanta Gas Light does maintain natural gas inventory for the Marketers in Georgia and recovers the cost through recovery mechanisms approved by the Georgia PSC specific to Georgia's deregulated market. In addition to natural gas recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs as well as environmental remediation and energy ~~price risk~~efficiency plans. In traditional rate designs, utilities recover a significant portion of the fixed customer service and pipeline infrastructure costs based on assumed natural gas volumes used by customers. The utilities, including Nicor Gas beginning in November 2019, have decoupled regulatory mechanisms that Southern Company Gas believes encourage conservation by separating the recoverable amount of these fixed costs from the amounts of natural gas used by customers. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" for additional information. Also see "Construction Programs – Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" for additional information regarding infrastructure replacement programs at certain of the natural gas distribution utilities.

The following table provides regulatory information for Southern Company Gas' natural gas distribution utilities:



	Nicor Gas	Atlanta Gas Light	Virginia Natural Gas	Chattanooga Gas
Authorized ROE^(a)	9.73%	10.25%	9.50%	9.80%
Authorized ROErange^(a)	N/A	10.05% - 10.45%	9.00% - 10.00%	N/A
Weather normalization mechanisms^(b)			ü	ü
Decoupled, including straight-fixed-variable rates^(c)	ü	ü	ü
Regulatory infrastructure program rates^(d)	ü		ü
Bad debt rider^(e)	ü		ü	ü
Energy efficiency plan^(f)	ü		ü
Annual base rate adjustment mechanism^(g)		ü		ü
Year of last rate decision	2019	2019	2018	2018


(a)	Atlanta Gas Light's authorized ROE and ROE range became effective on January 1, 2020. Atlanta Gas Light's ROE for 2019 was 10.75%.

(b)


(c)	Allows for recovery of fixed customer service costs separately from assumed natural gas volumes used by customers. On October 2, 2019, Nicor Gas received approval for a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a monthly benchmark level of revenue per rate class for recovery.


(d)	Programs that update or expand distribution systems and LNG facilities.


(e)	The recovery (refund) of bad debt expense over (under) an established benchmark expense. Nicor Gas, Virginia Natural Gas, and Chattanooga Gas recover the gas portion of bad debt expense through their purchased gas adjustment mechanisms.


(f)	Recovery of costs associated with plans to achieve specified energy savings goals.


(g)	Regulatory mechanism allowing annual adjustments to base rates up or down based on authorized ROE and/or ROE range.

GRAM

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Southern Company and Subsidiary Companies 2019 Annual Report

PRP

Rate Proceedings

Nicor Gas

Atlanta Gas Light

Virginia Natural Gas

See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" for additional information.

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Southern Company and Subsidiary Companies 2019 Annual Report

Affiliate Asset Management Agreements

Unrecognized Ratemaking Amounts



	December 31, 2019		December 31, 2018
	(in millions)
Atlanta Gas Light	$	70	$	95
Virginia Natural Gas	10		11
Nicor Gas	2		4
Total	$	82	$	110

Construction Programs

See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements" herein for additional information regarding the Registrants' capital requirements for their construction programs, including estimated totals for each of the next five years.

Nuclear Construction

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement,

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Southern Company and Subsidiary Companies 2019 Annual Report

which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:



	(in billions)
Base project capital cost forecast^(a)(b)	$	8.2
Construction contingency estimate	0.2
Total project capital cost forecast^(a)(b)	8.4
Net investment as of December 31, 2019^(b)	(5.9		)
Remaining estimate to complete^(a)	$	2.5


(a)	Excludes financing costs expected to be capitalized through AFUDC of approximately $300 million, of which $23 million had been accrued through December 31, 2019.


(b)	Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.2 billion had been incurred through December 31, 2019.

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Southern Company and Subsidiary Companies 2019 Annual Report

Southern Nuclear and Georgia Power believe that existing productivity levels and pace of activity completion are sufficient to meet the regulatory-approved in-service dates.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.

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Southern Company and Subsidiary Companies 2019 Annual Report

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet.

The ~~maximum potential collateral requirements~~ultimate outcome of these matters cannot be determined at this time.

Regulatory Matters

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Southern Company and Subsidiary Companies 2019 Annual Report

The ultimate outcome of these ~~contracts~~matters cannot be determined at this time.

Southern Power



Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Counterparties	PPA Contract Period
Projects Completed During the Year Ended December 31, 2019
Mankato expansion^(a)	Natural Gas	385	Mankato, MN	May 2019	Northern States Power Company	20 years
Wildhorse Mountain ^(b)	Wind	100	Pushmataha County, OK	December 2019	Arkansas Electric Cooperative Corporation	20 years
Projects Under Construction at December 31, 2019
Reading^(c)	Wind	200	Osage and Lyon Counties, KS	Second quarter 2020	Royal Caribbean Cruises LTD	12 years
Skookumchuck^(d)	Wind	136	Lewis and Thurston Counties, WA	Second quarter 2020	Puget Sound Energy	20 years

(a)


(b)	In May 2018, Southern Power purchased 100% of the membership interests of the Wildhorse Mountain facility. In December 2019, Southern Power entered into a tax equity partnership and, as a result, owns 100% of the Class B membership interests.


(c)	In August 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the Class B membership interests. The ultimate outcome of this matter cannot be determined at this time.

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Southern Company and Subsidiary Companies 2019 Annual Report

(d)

Total aggregate construction costs for the two projects under construction at December 31, ~~2016~~2019, excluding acquisition costs, are expected to be between $490 million and $535 million. At December 31, 2019, total costs of construction incurred for these projects were ~~as follows:~~$417 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Southern Company Gas

Infrastructure Replacement Programs and Capital Projects

Credit Ratings
Maximum
Potential
Collateral
Requirements
(in millions)
At BBB- and/or Baa3 $ 93
Below BBB- and/or Baa3 $ 1,258



Utility	Program	Recovery	Expenditures in 2019		Expenditures Since Project Inception		Pipe Installed Since Project Inception	Scope of Program	Program Duration	Last Year of Program
			(in millions)				(miles)	(miles)	(years)
Nicor Gas	Investing in Illinois(*)	Rider	$	396	$	1,712	843	1,450	9	2023
Virginia Natural Gas	Steps to Advance Virginia's Energy (SAVE and SAVE II)	Rider	45		244		363	770	13	2024
Total			$	441	$	1,956	1,206	2,220


(*)	Includes replacement of pipes, compressors, and transmission mains along with other improvements such as new meters. Scope of program miles is an estimate and subject to change.

Nicor Gas

~~Included~~In 2013, Illinois enacted legislation that allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system. The legislation stipulates that rate increases to customers as a result of any infrastructure investments shall not exceed a cumulative annual average of 4.0% or, in any given year, 5.5% of base rate revenues. In 2014, the Illinois Commission approved the nine-year regulatory infrastructure program, Investing in Illinois, subject to annual review. Nicor Gas expects to place into service $400 million of qualifying projects under Investing in Illinois in 2020.

Virginia Natural Gas

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Southern Company and Subsidiary Companies 2019 Annual Report

Atlanta Gas Light

Pipeline Construction Projects

On February 7, 2020, Southern Company Gas entered into an agreement with Dominion Atlantic Coast Pipeline, LLC for the sale of its interest in Atlantic Coast Pipeline. The transaction is expected to be completed in the first half of 2020; however, the ultimate outcome cannot be determined at this time. See Note 15 to the financial statements under "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline" for additional information.

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Southern Company and Subsidiary Companies 2019 Annual Report

The ultimate outcome of these ~~amounts~~matters cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project cancellation, any of which could result in an impairment of one or both of Southern Company Gas' investments and could have a material impact on Southern Company's and Southern Company Gas' financial statements. Southern Company Gas evaluated its investments and determined there was no impairment as of December 31, 2019.

See Notes 3 and 7 to the financial statements under "Guarantees" and "Southern Company Gas – Equity Method Investments," respectively, for additional information on these pipeline projects.

Southern Power's Power Sales Agreements

General

Southern Power has PPAs with some of the traditional electric operating companies, other investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers. The PPAs are ~~certain agreements~~expected to provide Southern Power with a stable source of revenue during their respective terms.

Many of Southern Power's PPAs have provisions that ~~could~~ require Southern Power or the counterparty to post collateral or an acceptable substitute guarantee in the event that S&P or Moody's downgrades the credit ratings of the respective company to an unacceptable credit rating or if the counterparty is not rated or fails to maintain a minimum coverage ratio.

On January 29, 2019, Pacific Gas & Electric Company (PG&E) filed petitions to reorganize under Chapter 11 of the U.S. Bankruptcy Code. Southern Power, together with its noncontrolling partners, owns four solar facilities where PG&E is the energy off-taker for approximately 207 MWs of capacity under long-term PPAs. PG&E is also the transmission provider for these four facilities and two of Southern Power's other solar facilities. At December 31, 2019, Southern Power had outstanding accounts receivables due from PG&E of $2 million related to the PPAs and $33 million related to the transmission interconnections (of which $27 million is classified in receivables – other and $6 million is classified in other deferred charges and assets). Subsequent to December 31, 2019, Southern Power received $15 million in accordance with a November 2019 bankruptcy court order granting payment of transmission interconnections for amounts due and owing. Southern Power continues to evaluate the recoverability of its investments in these solar facilities under various scenarios, including selling the related energy into the competitive markets, and has concluded that these solar facilities are not impaired. PG&E has continued to perform under the terms of the PPAs. Southern Power does not expect a material impact to its financial statements if, as a result of the bankruptcy proceedings, PG&E does not perform in accordance with the PPAs or ~~Alabama~~the terms of the PPAs are renegotiated; however, the ultimate outcome of this matter cannot be determined at this time.

Natural Gas

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Southern Company and Subsidiary Companies 2019 Annual Report

from Southern Power resources not dedicated to serve unit or block sales. Southern Power has rights to purchase power provided by the requirements customers' resources when economically viable.

As a ~~credit rating change~~general matter, substantially all of the PPAs provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel or purchased power relating to ~~below investment grade. Generally, collateral~~the energy delivered under such PPAs. To the extent a particular generating facility does not meet the operational requirements contemplated in the PPAs, Southern Power may be ~~provided by a~~responsible for excess fuel costs. With respect to fuel transportation risk, most of Southern ~~Company guaranty, letter~~Power's PPAs provide that the counterparties are responsible for the availability of ~~credit, or cash. Additionally, a credit rating downgrade could impact~~fuel transportation to the ~~ability~~particular generating facility.

Capacity charges that form part of the ~~Company~~PPA payments are designed to ~~access capital markets~~recover fixed and ~~would be likely~~variable operation and maintenance costs based on dollars-per-kilowatt year. In general, to ~~impact the cost at which it does so.~~

~~On January 10, 2017, S&P revised its consolidated credit rating outlook for~~reduce Southern ~~Company (including the Company) from negative to stable.~~

~~Market Price Risk~~

~~Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited~~Power's exposure to ~~market volatility in interest rates, commodity fuel prices,~~certain operation and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.

To mitigate future exposure to changes in interest rates, the Company may enter into derivatives designated as hedges. The weighted average interest rate on $1.8 billion of long-term variable interest rate exposure at January 1, 2017 was 1.91%. If the Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $18 million at January 1, 2017.maintenance costs, Southern Power has LTSAs. See Note 1 to the financial statements under ~~"Financial Instruments"~~"Long-Term Service Agreements" for additional information.

Solar and Wind

Income Tax Matters

Consolidated Income Taxes

On behalf of the Registrants, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.

The impact of certain tax events at Southern Company and/or its other subsidiaries can, and does, affect each Registrant's ability to utilize certain tax credits. See "Tax Credits" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein and Note 1110 to the financial statements for additional information.

~~To mitigate residual risks relative~~Federal Tax Reform Legislation

In 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduced the federal corporate income tax rate to ~~movements in electricity prices,~~21%, retained normalization provisions for public utility property and existing renewable energy incentives, and repealed the ~~Company enters into physical fixed-price contracts for~~corporate alternative minimum tax. In addition, under the ~~purchase and sale~~Tax Reform Legislation, NOLs generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. The Company continues to manage a fuel-hedging program implemented per the guidelinestaxable income of the ~~Georgia PSC.~~subsequent tax year. The ~~Company had no material change in market risk exposure for~~projected reduction of Southern Company's consolidated income tax liability resulting from the ~~year ended December 31, 2016 when compared~~tax rate reduction also delays the expected utilization of existing tax credit carryforwards. See "Consolidated Income Taxes" herein and Note 10 to the ~~December 31, 2015 reporting period.~~financial statements for information on Southern Company's joint consolidated income tax allocation agreement.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

~~Georgia Power~~Southern Company ~~2016~~and Subsidiary Companies 2019 Annual Report

~~The changes~~Bonus Depreciation

Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in ~~fair value of energy-related derivative contracts are substantially attributable~~service after September 27, 2017 remain eligible for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, bonus depreciation is expected to ~~both~~result in positive cash flows for the ~~volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were~~Registrants as follows:

2016
Changes

2015
Changes
Fair Value
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net $ (13 ) $ (20 )
Contracts realized or settled:
Swaps realized or settled (2 ) 2
Options realized or settled 11
18
Current period changes^(*):

Swaps 31
—
Options 9
(13 )
Contracts outstanding at the end of the period, assets (liabilities), net $ 36
$ (13 )



	2019 Tax Year		2020 Tax Year
	(in millions)
Southern Company	$	989	$	382
Alabama Power	180		68
Georgia Power	314		56
Mississippi Power	7		2
Southern Power^(*)	87		95
Southern Company Gas	190		58


(*)	~~Current period changes~~Cash flows resulting from bonus depreciation for Southern Power would also ~~include the changes in fair value~~be impacted by Southern Power's use of ~~new contracts entered into during the period, if any.~~tax equity partnerships.

~~The net hedge volumes of energy-related derivative contracts for the years ended December 31 were as follows:~~

2016 2015
mmBtu Volume
(in millions)
Commodity – Natural gas swaps 128
—
Commodity – Natural gas options 27
50
Total hedge volume 155
50

The weighted average swap contract cost below market prices was approximately $0.23 per mmBtu as of December 31, 2016. There were no swaps outstanding as of December 31, 2015. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. All natural gas hedge gains and losses are recovered through the Company's fuel cost recovery mechanism.

At December 31, 2016 and 2015, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Through December 31, 2015, the Company's fuel-hedging program had a time horizon up to 24 months. Effective January 1, 2016, the Georgia PSC approved changes to the Company's hedging program allowing it to use an array of derivative instruments within a 48-month time horizon. Hedging gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery mechanism. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy.~~ See Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information. The ultimate outcome of this matter cannot be determined at this time.

Tax Credits

Southern Power's ITCs relate to its investment in new solar facilities acquired or constructed and its PTCs relate to the first 10 years of energy production from its wind facilities, which have had, and may continue to have, a material impact on Southern Power's cash flows and net income. At December 31, 2019, Southern Company and Southern Power had approximately $1.8 billion and $1.4 billion, respectively, of unutilized ITCs and PTCs, which are currently expected to be fully utilized by 2024, but could be further ~~discussion of fair value measurements. The maturities~~delayed. Since 2018, Southern Power has been utilizing tax equity partnerships for wind and solar projects, where the tax partner takes significantly all of the ~~energy-related derivative contracts, which~~respective federal tax benefits. These tax equity partnerships are ~~all Level 2 of~~consolidated in Southern Company's and Southern Power's financial statements using the ~~fair value hierarchy, at December 31, 2016 were as follows:~~

Fair Value Measurements
December 31, 2016
Total Maturity
Fair Value Year 1 Years 2&3
(in millions)
Level 1 $ —
$ —
$ —
Level 2 36
28
8
Level 3 —
—
—
Fair value of contracts outstanding at end of period $ 36
$ 28
$ 8

~~The Company is exposed~~HLBV methodology to ~~market price risk in the event of nonperformance by counterparties to the energy-related~~allocate partnership gains and interest rate derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, seelosses. See Note 1 to the financial statements under ~~"Financial Instruments"~~"General" for additional information on the HLBV methodology and Note 111 to the financial ~~statements.~~statements under "Income Taxes" and Note 10 to the financial statements under "Deferred Tax Assets and Liabilities – Tax Credit Carryforwards" and "Effective Tax Rate" for additional information regarding utilization and amortization of credits and the tax benefit related to associated basis differences.

~~Capital Requirements~~

General Litigation Matters

The Registrants are involved in various other matters being litigated and ~~Contractual Obligations~~regulatory matters that could affect future earnings. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein or in Notes 2 and 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such Registrant's financial statements. See Notes 2 and 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

The ~~construction program~~Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.

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Southern Company and Subsidiary Companies 2019 Annual Report

Southern Company

In January 2017, a securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In March 2018, the court issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal. On August 22, 2019, the court certified the plaintiffs' proposed class. On September 5, 2019, the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. On December 19, 2019, the U.S. District Court for the Northern District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expires on March 31, 2020.

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In April 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is ~~currently estimated~~earlier, in the securities class action.

In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. In May 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. On August 5, 2019, the court granted a motion filed by the plaintiff on July 17, 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.

Georgia Power

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Mississippi Power

See Note 2 to the financial statements under "Kemper County Energy Facility" for additional information.

Other Matters

Southern Company

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Southern Company and Subsidiary Companies 2019 Annual Report

Mississippi Power

Southern Company Gas

The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on the financial statements of Southern Company and Southern Company Gas.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

The Registrants prepare their financial statements in accordance with GAAP. Significant accounting policies are described in the notes to the financial statements. In the application of these policies, certain estimates are made that may have a material impact

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Southern Company and Subsidiary Companies 2019 Annual Report

on the results of operations and related disclosures of the applicable Registrants (as indicated in the section descriptions herein). Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.

Utility Regulation (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

The traditional electric operating companies and the natural gas distribution utilities are subject to retail regulation by their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, the traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards for rate regulated entities also impacts their financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional electric operating companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the results of operations and financial condition of the applicable Registrants than they would on a non-regulated company.

Revenues related to regulated utility operations as a percentage of total ~~$2.6~~operating revenues in 2019 for the applicable Registrants were as follows: 87% for Southern Company, 99% for Alabama Power, 97% for Georgia Power, 100% for Mississippi Power, and 80% for Southern Company Gas.

As reflected in Note 2 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the financial statements of the applicable Registrants.

Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4

(Southern Company and Georgia Power)

In 2016, the Georgia PSC approved the Vogtle Cost Settlement Agreement, which resolved certain prudency matters in connection with Georgia Power's fifteenth VCM report. In 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor, as well as a modification of the Vogtle Cost Settlement Agreement. The Georgia PSC's related order stated that under the modified Vogtle Cost Settlement Agreement, (i) none of the $3.3 billion ~~for 2017, $2.7~~of costs incurred through December 31, 2015 should be disallowed as imprudent; (ii) capital costs incurred up to $5.68 billion ~~for 2018, $2.1~~would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs; (iii) Georgia Power would have the burden of proof to show that any capital costs above $5.68 billion ~~for 2019, $1.9~~were prudent; (iv) Georgia Power's total project capital cost forecast of $7.3 billion ~~for 2020, and~~(net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds) was found reasonable and did not represent a cost cap; and (v) prudence decisions would be made subsequent to achieving fuel load for ~~2021. These amounts include expenditures~~Unit 4.

In the second quarter 2018, Georgia Power revised its base cost forecast and estimated contingency to complete construction and start-up of ~~approximately $0.7 billion, $0.5 billion, $0.3~~Plant Vogtle Units 3 and 4 to $8.0 billion and ~~$0.1~~$0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power did not seek rate recovery for the $0.7 billion increase in 2017, 2018, 2019, and 2020, respectively. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental statutes and regulationscosts included in these amounts are $0.4 billion, $0.3 billion, $0.1 billion, $0.2 billion, and $0.2 billion for 2017, 2018, 2019, 2020, and 2021, respectively. These estimated expenditures do not include any potential compliance costs that may arise from the ~~EPA's final rules and guidelines or future state plans that would limit CO~~₂ emissions from new, existing, modified, or reconstructed fossil-fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" and "– Global Climate Issues" herein for additional information.

~~The Company also anticipates costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected~~base capital cost forecast in the ~~Company's ARO liabilities. These~~nineteenth VCM report. After considering the significant level of uncertainty that exists regarding the future recoverability of costs ~~which could change as~~included in the ~~Company continues to refine its assumptions underlying~~construction contingency estimate since the ~~cost estimates and evaluate the method and timing~~ultimate outcome of compliance activities, are estimated to be $0.3 billion for 2017 and $0.2 billion per year for 2018 through 2021. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.

~~The construction program~~these matters is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.

Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4.

There have been technical and procedural challenges to ~~environmental rules; changes~~the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in ~~generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units,~~place that are designed to ~~meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes~~assure compliance with the requirements specified in the ~~expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts;~~Westinghouse Design Control Document and the ~~cost of capital. In addition, there can be no assurance~~combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements under "Retail Regulatory Matters – Nuclear Construction" for information regarding additional factors that may impact construction expenditures.

occur throughout construction. As a result of ~~requirements~~such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company ~~has established external trust funds for nuclear decommissioning costs. For additional information, see Note 1~~and Subsidiary Companies 2019 Annual Report

not to seek recovery. Any further changes to the ~~financial statements under "Nuclear Decommissioning."~~capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

~~In addition,~~Given the significant complexity involved in estimating the future costs to complete construction and start-up of Plant Vogtle Units 3 and 4 and the significant management judgment necessary to assess the related uncertainties surrounding future rate recovery of any projected cost increases, as ~~discussed in~~well as the potential impact on results of operations and cash flows, Southern Company and Georgia Power consider these items to be critical accounting estimates. See Note 2 to the financial statements ~~the~~under "Georgia Power – Nuclear Construction" for additional information.

Accounting for Income Taxes (Southern Company, ~~provides postretirement benefits to substantially all employees~~Mississippi Power, Southern Power, and ~~funds trusts to the extent required by the Georgia PSC~~Southern Company Gas)

The consolidated income tax provision and ~~the FERC.~~

~~Other funding requirements related to obligations associated with scheduled maturities of long-term debt,~~deferred income tax assets and liabilities, as well as ~~the related interest, derivative obligations, preferred and preference stock dividends, leases, other purchase commitments, and trusts are~~

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~detailed in the contractual obligations table that follows. See Notes 1, 2, 6, 7, and 11 to the financial statements for additional information.~~

~~Contractual Obligations~~

~~Contractual obligations at December 31, 2016 were as follows:~~

2017
2018-
2019

2020-
2021

After
2021
Total
(in millions)
Long-term debt^(a) —

Principal $ 450
$ 1,250
$ 413
$ 8,533
$ 10,646
Interest 383
698
628
5,112
6,821
Preferred and preference stock dividends^(b)
17
35
35
—
87
Financial derivative obligations^(c)
1
6
1
—
8
Operating leases^(d)
19
22
17
15
73
Capital leases^(d)
9
17
7
—
33
Purchase commitments —
Capital^(e)
2,412
4,347
2,941
—
9,700
Fuel^(f)
1,628
1,681
878
6,320
10,507
Purchased power^(g)
320
595
539
2,543
3,997
Other^(h)
108
141
126
361
736
Trusts —
Nuclear decommissioning⁽ⁱ⁾
5
11
11
99
126
Pension and other postretirement benefit plans^(j)
46
90
—
—
136
Total $ 5,398
$ 8,893
$ 5,596
$ 22,983
$ 42,870

~~(a)~~

All amounts are reflected based on final maturity dates except for amounts related to FFB borrowings. As it relates to the FFB borrowings, the final maturity date is February 20, 2044; however, principal amortization is reflected beginning in 2020. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).


~~(b)~~	~~Preferred and preference stock do not mature; therefore, amounts provided are for the next five years only.~~


~~(c)~~	~~Includes derivative liabilities related to energy-related derivatives. For additional information, see Notes 1 and 11 to the financial statements.~~


~~(d)~~	~~Excludes PPAs that are accounted for as leases and included in "Purchased power."~~

~~(e)~~

The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements which are reflected in "Fuel" and "Other," respectively. At December 31, 2016, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" and "Retail Regulatory Matters – Nuclear Construction" herein for additional information.

~~(f)~~

Includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2016.

~~(g)~~

Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities. Includes a total of $292 million of biomass PPAs that is contingent upon the counterparties meeting specified contract dates for commercial operation. Subsequent to December 31, 2016, the specified contract dates for commercial operation were extended from 2017 to 2019 and may change further as a result of regulatory action. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" herein for additional information.


~~(h)~~	~~Includes long-term service agreements and contracts for the procurement of limestone. Long-term service agreements include price escalation based on inflation indices.~~


~~(i)~~	~~Projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2013 ARP~~. ~~See Note 1 to the financial statements under "Nuclear Decommissioning" for additional information.~~

~~(j)~~

The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets.

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~Cautionary Statement Regarding Forward-Looking Statements~~

The Company's 2016 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of construction projects, filings with state and federal regulatory authorities, impact of the PATH Act, federal incomeany unrecognized tax benefits ~~estimated sales~~ and ~~purchases under power sale~~valuation allowances, require significant judgment and ~~purchase agreements,~~estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negativeinterpretations of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

~~the impact of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in~~applicable tax ~~and other~~ laws and regulations ~~to which~~across multiple taxing jurisdictions. The effective tax rate reflects the ~~Company is subject, including potential~~statutory tax ~~reform legislation, as well as changes in application of existing laws~~rates and ~~regulations;~~

~~current and future litigation, regulatory investigations, proceedings, or inquiries;~~

calculated apportionments for the ~~effects, extent, and timing of the entry of additional competition in the markets~~various states in which ~~the Company operates;~~

variations in demand for electricity, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

~~available sources and costs of fuels;~~

~~effects of inflation;~~

the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system ~~upon completion~~operates.

On behalf of ~~construction;~~

~~investment performance~~its subsidiaries, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited or utilized at the ~~Company's employee~~consolidated or combined level resulting in NOL and ~~retiree benefit plans~~tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and ~~nuclear decommissioning trust funds;~~

~~advances in technology;~~

~~state and federal rate regulations~~tax credit carryforwards and the ~~impact~~assessment of ~~pending~~valuation allowances are based on significant judgment and ~~future rate cases and negotiations, including rate cases related to fuel and other cost recovery mechanisms;~~

~~the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;~~

~~legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;~~

~~the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;~~

~~internal restructuring or other restructuring options that may be pursued;~~

~~potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;~~

~~the ability of counterparties of the Company to make payments as and when due and to perform as required;~~

~~the ability to obtain new short- and long-term contracts with wholesale customers;~~

~~the direct or indirect effect on the Company's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;~~

~~interest rate fluctuations and financial market conditions and the results of financing efforts;~~

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;~~

the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;

~~the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;~~

~~catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;~~

~~the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;~~

~~the effect of accounting pronouncements issued periodically by standard-setting bodies; and~~

~~other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.~~

~~The Company expressly disclaims any obligation to update any forward-looking statements.~~

~~Table of ContentsIndex to Financial Statements~~

~~STATEMENTS OF INCOME~~

~~For the Years Ended~~ ~~December 31, 2016~~, ~~2015, and~~ ~~2014~~

~~Georgia Power Company 2016 Annual Report~~

2016
2015
2014
(in millions)
Operating Revenues:
Retail revenues $ 7,772
$ 7,727
$ 8,240
Wholesale revenues, non-affiliates 175
215
335
Wholesale revenues, affiliates 42
20
42
Other revenues 394
364
371
Total operating revenues 8,383
8,326
8,988
Operating Expenses:
Fuel 1,807
2,033
2,547
Purchased power, non-affiliates 361
289
287
Purchased power, affiliates 518
575
701
Other operations and maintenance 1,960
1,844
1,902
Depreciation and amortization 855
846
846
Taxes other than income taxes 405
391
409
Total operating expenses 5,906
5,978
6,692
Operating Income 2,477
2,348
2,296
Other Income and (Expense):
Interest expense, net of amounts capitalized (388 ) (363 ) (348 )
Other income (expense), net 38
61
23
Total other income and (expense) (350 ) (302 ) (325 )
Earnings Before Income Taxes 2,127
2,046
1,971
Income taxes 780
769
729
Net Income 1,347
1,277
1,242
Dividends on Preferred and Preference Stock 17
17
17
Net Income After Dividends on Preferred and Preference Stock $ 1,330
$ 1,260
$ 1,225

~~The accompanying notes are an integral part of these financial statements.~~

~~Table of ContentsIndex to Financial Statements~~

~~STATEMENTS OF COMPREHENSIVE INCOME~~

~~For the Years Ended~~ ~~December 31, 2016~~, ~~2015, and~~ ~~2014~~

~~Georgia Power Company 2016 Annual Report~~

2016
2015
2014
(in millions)
Net Income $ 1,347
$ 1,277
$ 1,242
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(6), and $(3),
respectively —
(9 ) (5 )
Reclassification adjustment for amounts included in net income,
net of tax of $2, $1, and $1, respectively 2
2
2
Total other comprehensive income (loss) 2
(7 ) (3 )
Comprehensive Income $ 1,349
$ 1,270
$ 1,239

~~The accompanying notes are an integral part of these financial statements.~~

~~Table of ContentsIndex to Financial Statements~~

~~STATEMENTS OF CASH FLOWS~~

~~For the Years Ended~~ ~~December 31, 2016~~, ~~2015, and~~ ~~2014~~

~~Georgia Power Company 2016 Annual Report~~

2016
2015
2014
(in millions)
Operating Activities:
Net income $ 1,347
$ 1,277
$ 1,242
Adjustments to reconcile net income
to net cash provided from operating activities —
Depreciation and amortization, total 1,063
1,029
1,019
Deferred income taxes 383
173
352
Allowance for equity funds used during construction (48 ) (40 ) (45 )
Retail fuel cost over-recovery — long-term —
106
(44 )
Pension and postretirement funding (287 ) (7 ) (156 )
Settlement of asset retirement obligations (123 ) (29 ) (12 )
Other deferred charges — affiliated (111 ) —
—
Other, net (10 ) 10
70
Changes in certain current assets and liabilities —
-Receivables 60
187
(248 )
-Fossil fuel stock 104
37
303
-Prepaid income taxes —
89
(216 )
-Other current assets (38 ) (62 ) (37 )
-Accounts payable (42 ) (259 ) 16
-Accrued taxes 131
25
17
-Accrued compensation (5 ) (17 ) 62
-Other current liabilities 1
(2 ) 40
Net cash provided from operating activities 2,425
2,517
2,363
Investing Activities:
Property additions (2,223 ) (2,091 ) (2,023 )
Nuclear decommissioning trust fund purchases (808 ) (985 ) (671 )
Nuclear decommissioning trust fund sales 803
980
669
Cost of removal, net of salvage (83 ) (71 ) (65 )
Change in construction payables, net of joint owner portion (35 ) 217
(54 )
Prepaid long-term service agreements (34 ) (66 ) (70 )
Sale of property 10
70
7
Other investing activities 23
2
1
Net cash used for investing activities (2,347 ) (1,944 ) (2,206 )
Financing Activities:
Increase (decrease) in notes payable, net 234
2
(891 )
Proceeds —
Senior notes 650
500
—
FFB loan 425
1,000
1,200
Pollution control revenue bonds issuances and remarketings —
409
40
Capital contributions from parent company 594
62
549
Short-term borrowings —
250
—
Redemptions and repurchases —
Senior notes (700 ) (1,175 ) —
Pollution control revenue bonds (4 ) (268 ) (37 )
Short-term borrowings —
(250 ) —
Payment of common stock dividends (1,305 ) (1,034 ) (954 )
Other financing activities (36 ) (26 ) (70 )
Net cash used for financing activities (142 ) (530 ) (163 )
Net Change in Cash and Cash Equivalents (64 ) 43
(6 )
Cash and Cash Equivalents at Beginning of Year 67
24
30
Cash and Cash Equivalents at End of Year $ 3
$ 67
$ 24
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $20, $16, and $18 capitalized, respectively) $ 375
$ 353
$ 319
Income taxes (net of refunds) 170
506
507
Noncash transactions —
Accrued property additions at year-end 336
387
154
Capital lease obligation —
149
—

~~The accompanying notes are an integral part of these financial statements.~~

~~Table of ContentsIndex to Financial Statements~~

~~BALANCE SHEETS~~

At ~~December 31, 2016~~ ~~and~~ ~~2015~~

~~Georgia Power Company 2016 Annual Report~~

Assets 2016
2015
(in millions)
Current Assets:
Cash and cash equivalents $ 3
$ 67
Receivables —
Customer accounts receivable 523
541
Unbilled revenues 224
188
Joint owner accounts receivable 57
227
Income taxes receivable, current —
114
Other accounts and notes receivable 81
57
Affiliated 18
18
Accumulated provision for uncollectible accounts (3 ) (2 )
Fossil fuel stock 298
402
Materials and supplies 479
449
Prepaid expenses 105
230
Other regulatory assets, current 193
213
Other current assets 38
19
Total current assets 2,016
2,523
Property, Plant, and Equipment:
In service 33,841
31,841
Less accumulated provision for depreciation 11,317
10,903
Plant in service, net of depreciation 22,524
20,938
Other utility plant, net —
171
Nuclear fuel, at amortized cost 569
572
Construction work in progress 4,939
4,775
Total property, plant, and equipment 28,032
26,456
Other Property and Investments:
Equity investments in unconsolidated subsidiaries 60
64
Nuclear decommissioning trusts, at fair value 814
775
Miscellaneous property and investments 46
43
Total other property and investments 920
882
Deferred Charges and Other Assets:
Deferred charges related to income taxes 676
679
Other regulatory assets, deferred 2,774
2,152
Other deferred charges and assets 417
173
Total deferred charges and other assets 3,867
3,004
Total Assets $ 34,835
$ 32,865

~~The accompanying notes are an integral part of these financial statements.~~

~~Table of ContentsIndex to Financial Statements~~

~~BALANCE SHEETS~~

At ~~December 31, 2016~~ ~~and~~ ~~2015~~

~~Georgia Power Company 2016 Annual Report~~

Liabilities and Stockholder's Equity 2016
2015
(in millions)
Current Liabilities:
Securities due within one year $ 460
$ 712
Notes payable 391
158
Accounts payable —
Affiliated 438
411
Other 589
750
Customer deposits 265
264
Accrued taxes —
Accrued income taxes 17
12
Other accrued taxes 390
325
Accrued interest 106
99
Accrued compensation 224
205
Asset retirement obligations, current 299
179
Other regulatory liabilities, current 31
16
Over recovered regulatory clause revenues, current 84
10
Other current liabilities 182
154
Total current liabilities 3,476
3,295
Long-Term Debt (See accompanying statements)
10,225
9,616
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 6,000
5,627
Deferred credits related to income taxes 121
105
Accumulated deferred investment tax credits 256
204
Employee benefit obligations 703
949
Asset retirement obligations, deferred 2,233
1,737
Other deferred credits and liabilities 199
347
Total deferred credits and other liabilities 9,512
8,969
Total Liabilities 23,213
21,880
Preferred Stock (See accompanying statements)
45
45
Preference Stock (See accompanying statements)
221
221
Common Stockholder's Equity (See accompanying statements)
11,356
10,719
Total Liabilities and Stockholder's Equity $ 34,835
$ 32,865
Commitments and Contingent Matters (See notes)

~~The accompanying notes are an integral part of these financial statements.~~

~~Table of ContentsIndex to Financial Statements~~

~~STATEMENTS OF CAPITALIZATION~~

At ~~December 31, 2016~~ ~~and~~ ~~2015~~

~~Georgia Power Company 2016 Annual Report~~

2016
2015
2016
2015
(in millions) (percent of total)
Long-Term Debt:
Long-term notes payable —
Variable rates (0.76% to 0.83% at 1/1/16) due 2016 $ —
$ 450

3.00% due 2016 —
250

5.70% due 2017 450
450

1.95% to 5.40% due 2018 748
747

4.25% due 2019 500
502

2.40% due 2021 325
—

2.85% to 5.95% due 2022-2043 4,175
3,850

Total long-term notes payable 6,198
6,249

Other long-term debt —
Pollution control revenue bonds —
1.38% to 4.00% due 2022-2049 952
952

Variable rate (0.22% at 1/1/16) due 2016 —
4

Variable rates (0.77% to 0.87% at 1/1/17) due 2022-2053 868
868

FFB loans —
2.57% to 3.86% due 2020 44
37

2.57% to 3.86% due 2021 44
37

2.57% to 3.86% due 2022-2044 2,537
2,126

Total other long-term debt 4,445
4,024

Capitalized lease obligations 169
183

Unamortized debt premium (discount), net (10 ) (10 )
Unamortized debt issuance expense (117 ) (118 )
Total long-term debt (annual interest requirement — $402 million) 10,685
10,328

Less amount due within one year 460
712

Long-term debt excluding amount due within one year 10,225
9,616
46.8 % 46.7 %
Preferred and Preference Stock:
Non-cumulative preferred stock
$25 par value — 6.125%
Authorized — 50,000,000 shares
Outstanding — 1,800,000 shares 45
45

Non-cumulative preference stock
$100 par value — 6.50%
Authorized — 15,000,000 shares
Outstanding — 2,250,000 shares 221
221

Total preferred and preference stock
(annual dividend requirement — $17 million) 266
266
1.2
1.3
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares

Outstanding — 9,261,500 shares 398
398

Paid-in capital 6,885
6,275

Retained earnings 4,086
4,061

Accumulated other comprehensive loss (13 ) (15 )
Total common stockholder's equity 11,356
10,719
52.0
52.0
Total Capitalization $ 21,847
$ 20,601
100.0 % 100.0 %

~~The accompanying notes are an integral part of these financial statements.~~

~~Table of ContentsIndex to Financial Statements~~

~~STATEMENTS OF COMMON STOCKHOLDER'S EQUITY~~

~~For the Years Ended December 31, 2016, 2015, and 2014~~

~~Georgia Power Company 2016 Annual Report~~

Number of Common Shares Issued Common Stock Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total
(in millions)
Balance at December 31, 2013 9
$ 398
$ 5,633
$ 3,565
$ (5 ) $ 9,591
Net income after dividends on preferred
and preference stock
—
—
—
1,225
—
1,225
Capital contributions from parent company —
—
563
—
—
563
Other comprehensive income (loss) —
—
—
—
(3 ) (3 )
Cash dividends on common stock —
—
—
(954 ) —
(954 )
Other —
—
—
(1 ) —
(1 )
Balance at December 31, 2014 9
398
6,196
3,835
(8 ) 10,421
Net income after dividends on preferred
and preference stock
—
—
—
1,260
—
1,260
Capital contributions from parent company —
—
79
—
—
79
Other comprehensive income (loss) —
—
—
—
(7 ) (7 )
Cash dividends on common stock —
—
—
(1,034 ) —
(1,034 )
Balance at December 31, 2015 9
398
6,275
4,061
(15 ) 10,719
Net income after dividends on preferred
and preference stock
—
—
—
1,330
—
1,330
Capital contributions from parent company —
—
610
—
—
610
Other comprehensive income (loss) —
—
—
—
2
2
Cash dividends on common stock —
—
—
(1,305 ) —
(1,305 )
Balance at December 31, 2016 9
$ 398
$ 6,885
$ 4,086
$ (13 ) $ 11,356

~~The accompanying notes are an integral part of these financial statements.~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES TO FINANCIAL STATEMENTS~~

~~Georgia Power Company~~ ~~2016~~ ~~Annual Report~~

~~Index to the Notes to Financial Statements~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~

~~General~~

~~Georgia Power Company (the Company) is a wholly-owned subsidiary~~extensive analysis of Southern Company, which is the parent company of the Company and three other traditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Alabama Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern CompanyCompany's and its ~~subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company~~subsidiaries' current financial position and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Hatch and Plant Vogtle. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure.

~~The equity method is used for subsidiaries in which the Company has significant influence but does not control.~~

The Company is subject to regulation by the FERC and the Georgia PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.

In June 2015, the Company identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the second quarter 2015, the Company recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. The Company evaluated the effects of this error on the interim and annual periods that included the billing error. Based on an analysis of qualitative and quantitative factors, the Company determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required.

~~Recently Issued Accounting Standards~~

~~In 2014, the FASB issued ASC 606,~~ ~~Revenue from Contracts with Customers,~~ replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~On February 25, 2016, the FASB issued ASU No. 2016-02,~~ ~~Leases (Topic 842)~~ (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.

~~On March 30, 2016, the FASB issued ASU No. 2016-09,~~ ~~Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting~~ (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, ~~financial position, or cash flows of the Company. See Notes 5, 8, and 12 for disclosures impacted by ASU 2016-09.~~including currently available information about future years, to estimate when future taxable income will be realized.

~~On October 24, 2016, the FASB issued ASU No. 2016-16,~~ ~~Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory~~ ~~(ASU 2016-16).~~ Current ~~GAAP prohibits the recognition of current~~ and deferred state income ~~taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize~~tax liabilities and assets are estimated based on laws of multiple states that determine the income ~~tax consequences~~to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of ~~an affiliate transfer of an asset other than inventory when~~taxable income, primarily using sales, assets, or payroll within the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact.

~~Affiliate Transactions~~

~~The Company has an agreement with SCS under which the following services are rendered~~jurisdiction compared to the ~~Company at direct~~consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or ~~allocated cost: general~~unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $606 million, $585 million, and $555 million in 2016, 2015, and 2014, respectively. Cost allocationfiling methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.

The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services; general operations, management, and technical services; administrative services including procurement, accounting, employee relations, systems, and procedures services; strategic planning and budgeting services; and other services with respect to business, operations, and construction management. Costs for these services amounted to $666 million, $681 million, and $643 million in 2016, 2015, and 2014, respectively.

The Company has entered into several PPAs with Southern Power for capacity and energy. Expenses associated with these PPAs were $265 million, $179 million, and $144 million in 2016, 2015, and 2014, respectively. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.

The Company has a joint ownership agreement with Gulf Power under which Gulf Power owns a 25% portion of Plant Scherer Unit 3. Under this agreement, the Company operates Plant Scherer Unit 3 and Gulf Power reimburses the Company for its 25% proportionate share of the related non-fuel expenses, which were $8 million, $12 million, and $9 million in 2016, 2015, and 2014, respectively. See Note 4 for additional information.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

In 2014, prior to Southern Company's acquisition of PowerSecure on May 9, 2016, the Company entered into agreements with PowerSecure to build solar power generation facilities at two U.S. Army bases, as approved by the Georgia PSC. On October 4, 2016, the two facilities began commercial operation. Payments of approximately $118 million made by the Company to PowerSecure under the agreements since 2014 are included in utility plant in service at December 31, 2016.

On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016, transportation costs under this agreement were approximately $35 million.

Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. For the period subsequent to Southern Company's acquisition of Southern Company Gas through December 31, 2016, natural gas purchases made by the Company from Southern Company Gas' subsidiaries were approximately $10 million.

The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2016, 2015, or 2014.

The traditional electric operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.

~~Regulatory Assets and Liabilities~~

~~The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs~~ that are expected to ~~be recovered from customers through~~apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on the ~~ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:~~

2016 2015 Note
(in millions)
Retiree benefit plans $ 1,348
$ 1,307
(a, j)
Deferred income tax charges 681
683
(b, j)
Loss on reacquired debt 137
150
(c, j)
Asset retirement obligations 893
411
(b, j)
Vacation pay 91
91
(d, j)
Cancelled construction projects 44
56
(e)
Remaining net book value of retired assets 166
171
(f)
Storm damage reserves 206
92
(g)
Other regulatory assets 97
110
(h)
Other cost of removal obligations 3
(31 ) (b)
Deferred income tax credits (121 ) (105 ) (b, j)
Other regulatory liabilities (39 ) (2 ) (i, j)
Total regulatory assets (liabilities), net $ 3,506
$ 2,933

~~Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:~~


~~(a)~~	~~Recovered and amortized over the average remaining service period which may range up to 13 years. See Note 2 for additional information.~~

~~(b)~~

Asset retirement and other cost of removal obligations and deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. Included in the deferred income tax assets is $26 million for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Georgia PSC, through 2022.


~~(c)~~	~~Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which currently does not exceed 36 years.~~


~~(d)~~	~~Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.~~


~~(e)~~	Costs associated with construction of environmental controls that will not be completed as a result of unit retirements are being amortized as approved by the Georgia PSC over periods not exceeding nine years or through 2022.

~~(f)~~

Amortized as approved by the Georgia PSC over periods not exceeding 10 years or through 2024. The net book value of Plant Mitchell Unit 3 at December 31, 2016 was $12 million, which will continue to be amortized through December 31, 2019 as provided in the 2013 ARP. Amortization of the remaining net book value of Plant Mitchell Unit 3 at December 31, 2019, which is expected to be approximately $5 million, and $31 million related to obsolete inventories of certain retired units will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Retail Regulatory Matters – Integrated Resource Plan" for additional information.


~~(g)~~	Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $185 million related to the under-recovery from January 2014 through December 2016 will be determined by the Georgia PSC in the 2019 base rate case. See Note 3 for additional information.

~~(h)~~

Comprised of several components including deferred nuclear outages, environmental remediation, building lease, and demand-side management tariff under-recovery. Deferred nuclear outages are recorded and recovered or amortized over the outage cycles of each nuclear unit, which does not exceed 24 months. The building lease is recorded and recovered or amortized as approved by the Georgia PSC through 2020. The amortization of environmental remediation and demand-side management tariff under-recovery of $46 million at December 31, 2016 will be determined by the Georgia PSC in the 2019 base rate case.


~~(i)~~	~~Comprised primarily of fuel-hedging gains, which upon final settlement are refunded through the Company's fuel cost recovery mechanism.~~


~~(j)~~	~~Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability.~~

~~In the event that a portion~~financial statements of the ~~Company's operations is no longer subject to~~ applicable ~~accounting rules for rate regulation,~~Registrants.

Given the ~~Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets~~significant judgment involved in estimating NOL and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information.

~~Revenues~~

Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between the actual recoverable costs and amounts billed in current regulated rates.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.~~

~~Fuel Costs~~

~~Income and Other Taxes~~

The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

Federal ITCs utilized are deferred and amortized to income as a credit to reduce depreciation over the average life of the related property. The Company had $83 million in federal ITCs at December 31, 2016 that will expire by 2036. State ITCs are recognized in the period in which the credits are generated. The Company had state investment and other tax credit carryforwards ~~totaling $345 million at December 31, 2016, which will expire between 2019~~ and ~~2027~~multi-state apportionments for all subsidiaries, the applicable Registrants consider deferred income tax liabilities and ~~are expected~~assets to be ~~fully utilized by 2023.~~critical accounting estimates.

The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.

~~Property, Plant, and Equipment~~

Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the cost of equity and debt funds used during construction.

~~The Company's property, plant, and equipment in service consisted of the following at December 31:~~

2016 2015
(in millions)
Generation $ 16,668
$ 15,386
Transmission 5,779
5,355
Distribution 9,553
9,151
General 1,813
1,921
Plant acquisition adjustment 28
28
Total plant in service $ 33,841
$ 31,841

The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of certain generating plant maintenance costs. As mandated by the Georgia PSC, the Company defers and amortizes nuclear refueling outage costs over the unit's operating cycle. The refueling cycles are 18 and 24 months for Plant Vogtle Units 1 and 2 and Plant Hatch Units 1 and 2, respectively.

~~Depreciation and Amortization~~

~~Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.8% in~~ ~~2016~~, ~~2.7%~~ in ~~2015, and~~ ~~2.7%~~ in ~~2014~~. Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC and the FERC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.

~~Under the terms of the 2013 ARP, the Company amortized approximately $14 million in each of 2014, 2015, and 2016 of its remaining regulatory liability related to other cost of removal obligations.~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

Asset Retirement Obligations (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and ~~Other Costs of Removal~~Southern Company Gas)

AROs are computed as the present value of the estimated ~~ultimate~~ costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual and recovery of other retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for future obligations are reflected in the balance sheets as a regulatory liability and amounts to be recovered are reflected in the balance sheets as a regulatory asset.

The ARO ~~liability~~liabilities for the traditional electric operating companies primarily ~~relates~~relate to ~~the Company's ash ponds, landfills, and gypsum cells~~facilities that are subject to the ~~Disposal of Coal Combustion Residuals from Electric Utilities final rule published by~~CCR Rule and the ~~EPA in April 2015 (CCR Rule).~~related state rules, principally ash ponds. In addition, ~~the Company has~~Alabama Power and Georgia Power have retirement obligations related to the decommissioning of ~~the Company's~~ nuclear facilities ~~which include the Company's~~(Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2,2). The traditional electric operating companies also have AROs related to various landfill sites, asbestos removal, and underground storage tanks, as well as, for Alabama Power, disposal of polychlorinated biphenyls in certain transformers and ~~asbestos removal.~~ sulfur hexafluoride gas in certain substation breakers, for Georgia Power, gypsum cells and restoration of land at the end of long-term land leases for solar facilities, and for Mississippi Power, mine reclamation and water wells.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

assets have not been recorded because the settlement timing for ~~the~~certain retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these ~~AROs~~retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability in the balance sheets as ordered by the Georgia PSC. See "Nuclear Decommissioning" herein for additional information on amounts included in rates.

~~Details of the AROs included in the balance sheets are as follows:~~

2016 2015
(in millions)
Balance at beginning of year $ 1,916
$ 1,255
Liabilities incurred —
6
Liabilities settled (123 ) (30 )
Accretion 77
56
Cash flow revisions 662
629
Balance at end of year $ 2,532
$ 1,916

~~The increase in cash flow revisions in 2016 is primarily related to changes to the Company's closure strategy for ash ponds, landfills, and gypsum cells AROs.~~

The increase in cash flow revisions in 2015 is primarily related to changes to the Company's ash ponds, landfills, and gypsum cells ARO closure dollar and timing estimates associated with the CCR Rule and revisions to the nuclear decommissioning AROs based on the latest decommissioning study.

The cost estimates for AROs related to the disposal of CCR ~~Rule~~ are based on information ~~as of December 31, 2016~~ using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule ~~requirements for closure. As further analysis is performed, including evaluation of~~and the ~~expected method of compliance, refinement of assumptions underlying the~~related state rules. The traditional electric operating companies expect to update their ARO cost estimates ~~such~~periodically as additional information related to these assumptions becomes available. See Note 6 to the ~~quantities~~financial statements for additional information, including increases to AROs related to ash ponds recorded during 2019 by certain Registrants.

Given the significant judgment involved in estimating AROs, the applicable Registrants consider the liabilities for AROs to be critical accounting estimates.

Pension and Other Postretirement Benefits (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

The applicable Registrants' calculations of ~~CCR at each site,~~pension and other postretirement benefits expense are dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term rate of return (LRR) on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the ~~determination~~recorded obligation in future periods. While the applicable Registrants believe the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect their pension and other postretirement benefit costs and obligations.

Key elements in determining the applicable Registrants' pension and other postretirement benefit expense are the LRR and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. For purposes of ~~timing with respect to compliance activities, including~~determining the ~~potential for closing ash ponds prior~~applicable Registrants' liabilities related to the ~~end~~pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of ~~their currently anticipated useful life,~~market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. The discount rate assumption impacts both the ~~Company expects to continue to periodically update these estimates.~~

~~Nuclear Decommissioning~~

~~The NRC requires licensees~~service cost and non-service costs components of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Georgia PSC,net periodic benefit costs as well as the ~~IRS. While~~projected benefit obligations.

For 2019, the LRR assumption for qualified pension plan assets was reduced from 7.95% to 7.75% for purposes of determining net periodic pension expense as a result of changes in the economic outlook used in estimating the expected returns as of December 31, 2018. As a result of the decrease in the LRR, the non-service costs component of net periodic pension expense increased by $24 million for the Southern Company system in 2019. See the table below for the impact on each Registrant.

Table of ContentsIndex to Financial Statements

~~NOTES~~COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

~~Georgia Power~~Southern Company ~~2016~~and Subsidiary Companies 2019 Annual Report

~~Company is allowed~~For 2020, net periodic pension expense will be impacted by two factors: a change in the approach used to ~~prescribe an overall investment policy~~determine the LRR assumption and cash contributions totaling $1.1 billion to the ~~Funds' managers,~~qualified pension plan made in December 2019. Historically, Southern Company has set the LRR assumption using asset return modeling based on geometric returns that reflect the compound average returns for dependent annual periods. Beginning in 2020, Southern Company will set the LRR assumption using an arithmetic mean which represents the expected simple average return to be earned by the pension plan assets over any one year. Southern Company believes the use of the arithmetic mean is more compatible with the LRR's function of estimating a single year's investment return. Excluding the additional pension contribution in December 2019, the change in the LRR assumption will reduce the non-service costs component of net periodic pension expense by $78 million for the Southern Company system in 2020. See the table below for the impact on each Registrant. The contributions in 2019 will further reduce expense by $88 million for the Southern Company system in 2020.



	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions)
Increase (decrease) in pension expense:
2019	$	24		$	5		$	8		$	1		$	2
2020	(78		)	(18		)	(25		)	(4		)	(7		)

The following table illustrates the sensitivity to changes in the applicable Registrants' long-term assumptions with respect to the discount rate, salary increases, and the long-term rate of return on plan assets:



	Increase/(Decrease) in
25 Basis Point Change in:	Total Benefit Expense for 2020	Projected Obligation for Pension Plan at December 31, 2019	Projected Obligation for Other Postretirement Benefit Plans at December 31, 2019
	(in millions)
Discount rate:
Southern Company	$41/$(39)	$549/$(518)	$57/$(54)
Alabama Power	$10/$(10)	$131/$(123)	$14/$(13)
Georgia Power	$12/$(11)	$166/$(156)	$21/$(20)
Mississippi Power	$2/$(2)	$25/$(23)	$2/$(2)
Southern Company Gas	$1/$(1)	$38/$(36)	$6/$(6)
Salaries:
Southern Company	$23/$(22)	$118/$(113)	$–/$–
Alabama Power	$6/$(6)	$33/$(32)	$–/$–
Georgia Power	$6/$(6)	$34/$(33)	$–/$–
Mississippi Power	$1/$(1)	$5/$(5)	$–/$–
Southern Company Gas	$1/$(1)	$3/$(3)	$–/$–
Long-term return on plan assets:
Southern Company	$35/$(35)	N/A	N/A
Alabama Power	$9/$(9)	N/A	N/A
Georgia Power	$11/$(11)	N/A	N/A
Mississippi Power	$2/$(2)	N/A	N/A
Southern Company Gas	$3/$(3)	N/A	N/A

See Note 11 to the financial statements for additional information regarding pension and other postretirement benefits.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and ~~its affiliates are not allowed~~Subsidiary Companies 2019 Annual Report

Asset Impairment (Southern Company, Southern Power, and Southern Company Gas)

Goodwill (Southern Company and Southern Company Gas)

The acquisition method of accounting requires the assets acquired and liabilities assumed to ~~engage~~be recorded at the date of acquisition at their respective estimated fair values. The applicable Registrants have recognized goodwill as of the date of their acquisitions, as a residual over the fair values of the identifiable net assets acquired. Goodwill is tested for impairment at the reporting unit level on an annual basis in the ~~day-to-day management~~fourth quarter of the ~~Funds~~year as well as on an interim basis as events and changes in circumstances occur, including, but not limited to, a significant change in operating performance, the business climate, legal or ~~to mandate individual investment decisions. Day-to-day management~~regulatory factors, or a planned sale or disposition of a significant portion of the ~~investments in~~business. A reporting unit is the ~~Funds~~operating segment, or a business one level below the operating segment (a component), if discrete financial information is ~~delegated to unrelated third party managers with oversight~~prepared and regularly reviewed by ~~the management~~management. Components are aggregated if they have similar economic characteristics.

As part of the ~~Company. The Funds' managers are authorized, within certain investment guidelines,~~impairment tests, the applicable Registrant may perform an initial qualitative assessment to ~~actively buy and sell securities at their own discretion in order to maximize~~determine whether it is more likely than not that the ~~return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.~~

~~The Company records the investment securities held in the Funds at~~ fair value ~~as disclosed in Note 10, as management believes~~of each reporting unit is less than its carrying amount before applying the quantitative goodwill impairment test. If the applicable Registrant elects to perform the qualitative assessment, it evaluates relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events, and events specific to each reporting unit. If the applicable Registrant determines that it is more likely than not that the fair value ~~best represents~~of a reporting unit is less than its carrying amount, or it elects not to perform a qualitative assessment, it compares the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis.

The Funds participate in a securities lending program through the managers of the Funds. Under this program, the Funds' investment securities are loaned to institutional investors for a fee. Securities loaned are fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. As of ~~December 31, 2016~~ ~~and~~ ~~2015~~, approximately $56 million and $76 million, respectively, of the fair market value of the Funds' securities were on loan and pledged to creditors under the Funds' managers' securities lending program. The fair value of the ~~collateral received~~reporting unit to its carrying value to determine if the fair value is greater than its carrying value.

Goodwill for Southern Company and Southern Company Gas was ~~approximately $58 million~~$5.3 billion and ~~$78 million~~$5.0 billion, respectively, at December 31, ~~2016~~2019. For its 2019 and ~~2015, respectively,~~2018 annual impairment tests, Southern Company Gas performed the qualitative assessment and determined that it was more likely than not that the fair value of all of its reporting units with goodwill exceeded their carrying amounts, and therefore no quantitative analysis was required. For its 2017 annual impairment test, Southern Company Gas performed the quantitative assessment, which resulted in the fair value of all of its reporting units that have goodwill exceeding their carrying value. For its annual impairment tests for PowerSecure, Southern Company performed the quantitative assessment, which resulted in the fair value of goodwill at PowerSecure exceeding its carrying value in all years presented. However, Southern Company recorded goodwill impairment charges totaling $34 million in 2019 as a result of its decision to sell certain PowerSecure business units. See Note 15 to the financial statements under "Southern Company" for additional information.

The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can ~~only be sold by~~significantly impact the ~~borrower upon~~applicable Registrant's results of operations. Fair values and useful lives are determined based on, among other factors, the ~~return~~expected future period of benefit of the ~~loaned securities. The collateral received is treated as a non-cash item in~~asset, the ~~statements of cash flows.~~

At December 31, 2016, investment securities in the Funds totaled $814 million, consisting of equity securities of $326 million, debt securities of $477 million, and $11 million of other securities. At December 31, 2015, investment securities in the Funds totaled $775 million, consisting of equity securities of $296 million, debt securities of $463 million, and $16 million of other securities. These amounts include the investment securities pledged to creditors and collateral received, and exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases and the lending pool.

~~Sales~~various characteristics of the ~~securities held in~~asset, and projected cash flows. As the ~~Funds resulted in cash proceeds~~determination of ~~$803 million, $980 million, and $669 million in 2016, 2015, and 2014, respectively, all of which were reinvested. For 2016,~~an asset's fair value ~~increases, including reinvested interest~~ and ~~dividends~~useful life involves management making certain estimates and ~~excluding~~because these estimates form the ~~Funds' expenses, were $38 million, which included $14 million related to unrealized gains on securities held in~~basis for the ~~Funds at December 31, 2016. For 2015, fair value increases, including reinvested interest and dividends and excluding~~determination of whether or not an impairment charge should be recorded, the Funds' expenses, were $3 million, which included $26 million related to unrealized losses on securities held in the Funds at December 31, 2015. For 2014, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $44 million, which included an immaterial amount related to unrealized gains and losses on securities held in the Funds at ~~December 31, 2014. While the investment securities held in the Funds are reported as trading securities, the Funds continue~~applicable Registrants consider these estimates to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired.critical accounting estimates.

The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning are based on the most current study performed in 2015. The site study costs and external trust funds for decommissioning as of ~~December 31, 2016~~ ~~based on the Company's ownership interests were as follows:~~

Plant Hatch
Plant Vogtle
Units 1 and 2
Decommissioning periods:
Beginning year 2034
2047
Completion year 2075
2079
(in millions)
Site study costs:
Radiated structures $ 678
$ 568
Spent fuel management 160
147
Non-radiated structures 64
89
Total site study costs $ 902
$ 804
External trust funds $ 511
$ 303

For ratemaking purposes, the Company's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved annual decommissioning cost for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 2.4% and an estimated trust earnings rate of 4.4%. The Company expects the Georgia PSC to review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs in the Company's 2019 base rate case.

~~Allowance for Funds Used During Construction~~

The Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. For the years ~~2016~~, ~~2015, and~~ ~~2014, the average AFUDC rates were 6.9%, 6.5%, and 5.6%, respectively, and AFUDC capitalized was $68 million, $56 million, and~~ ~~$62 million, respectively. AFUDC, net of income taxes, was 4.6%,~~ ~~3.9%, and~~ ~~4.6%~~ ~~of net income after dividends on preferred and preference stock for~~ ~~2016~~, ~~2015, and~~ ~~2014, respectively.~~ See Note 31 to the financial statements under ~~"Retail Regulatory Matters – Nuclear Construction"~~"Goodwill and Other Intangible Assets and Liabilities" for additional information onregarding the ~~inclusion~~applicable Registrants' goodwill.

Long-Lived Assets (Southern Company, Southern Power, and Southern Company Gas)

Impairments of ~~construction costs~~long-lived assets of the traditional electric utilities and natural gas distribution utilities are generally related to ~~Plant Vogtle Units 3 and 4 in rate base effective January 1, 2011.~~

~~Impairment of Long-Lived Assets and Intangibles~~

specific regulatory disallowances. The ~~Company evaluates~~applicable Registrants assess their other long-lived assets for impairment ~~when~~whenever events or changes in circumstances indicate that ~~the~~an asset's carrying ~~value of such assets~~amount may not be recoverable. ~~The determination~~If an indicator exists, the asset is tested for recoverability by comparing the asset carrying value to the sum of ~~whether an impairment has occurred is based on either a specific regulatory disallowance or an~~the undiscounted expected future cash flows directly attributable to the asset's use and eventual disposition. If the estimate of undiscounted future cash flows ~~attributable to the assets, as compared with~~is less than the carrying value of the ~~assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating~~asset, the fair value of the ~~assets~~asset is determined and ~~recording~~ a loss ifis recorded equal to the difference between the carrying value ~~is greater than~~and the fair ~~value. For~~value of the asset. In addition, when assets are identified as held for sale, an impairment loss is recognized to the extent the carrying value of the assets or asset group exceeds their fair value less cost to sell. A high degree of judgment is ~~compared~~required in developing estimates related to these evaluations, which are based on projections of various factors, some of which have been quite volatile in recent years.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

See Note 3 to the financial statements under "Other Matters" and Note 15 to the financial statements for information on certain assets recently evaluated for impairment.

Derivatives and Hedging Activities (Southern Company and Southern Company Gas)

Determining whether a contract meets the definition of a derivative instrument, contains an embedded derivative requiring bifurcation, or qualifies for hedge accounting treatment is complex. The treatment of a single contract may vary from period to period depending upon accounting elections, changes in the applicable Registrant's assessment of the likelihood of future hedged transactions, or new interpretations of accounting guidance. As a result, judgment is required in determining the appropriate accounting treatment. In addition, the estimated fair value ~~less~~of derivative instruments may change significantly from period to period depending upon market conditions, and changes in hedge effectiveness may impact the ~~cost~~accounting treatment.

Derivative instruments (including certain derivative instruments embedded in other contracts) are recorded on the balance sheets as either assets or liabilities measured at their fair value. If the transaction qualifies for, and is designated as, a normal purchase or normal sale, it is exempt from fair value accounting treatment and is, instead, subject to ~~sell~~traditional accrual accounting. The applicable Registrant utilizes market data or assumptions that market participants would use in ~~order~~pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique.

the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);

events specific to a given counterparty; and

the impact of nonperformance risk on liabilities.

A significant change in the underlying market prices or pricing assumptions used in pricing derivative assets or liabilities may result in a significant financial statement impact.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Revenue Recognition (Southern Power)

Lease Transactions

Southern Power considers the following factors to determine whether the sales contract is a lease:

Assessing whether specific property is explicitly or implicitly identified in the agreement;

Determining whether the fulfillment of the arrangement is dependent on the use of the identified property; and

Assessing whether the arrangement conveys to the counterparty substantially all of the economic benefits and the right to direct the use of the asset.

Non-Derivative and Normal Sale Derivative Transactions

If the power sales contract is not classified as a lease, Southern Power further considers the following factors to determine proper classification:

Assessing whether the contract meets the definition of a derivative;

Assessing whether the contract meets the definition of a capacity contract;

Assessing the probability at inception and throughout the term of the individual contract that the contract will result in physical delivery; and

Ensuring that the contract quantities do not exceed available generating capacity (including purchased capacity).

Cash Flow Hedge Transactions

Southern Power further considers the following in designating other derivative contracts for the sale of electricity as cash flow hedges of anticipated sale transactions:

Identifying the hedging instrument, the forecasted hedged transaction, and the nature of the risk being hedged; and

Assessing hedge effectiveness at inception and throughout the contract term.

These contracts are accounted for on a fair value basis and are recorded in AOCI over the life of the contract. Realized gains and losses are then recognized in operating revenues as incurred.

Derivative (Non-Hedge) Transactions

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Acquisition Accounting (Southern Power)

Variable Interest Entities (Southern Power)

Southern Power enters into partnerships with varying ownership structures. Upon entering into such arrangements, membership interests and other variable interests are evaluated to determine if ~~an impairment~~the legal entity is a VIE. If the legal entity is a VIE, Southern Power will assess if it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE, making it the primary beneficiary. Making this determination may require significant management judgment.

Contingent Obligations (All Registrants)

The Registrants are subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject them to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Notes 2 and 3 to the financial statements for more information regarding certain of these contingencies. The Registrants periodically evaluate their exposure to such risks and record reserves for those matters where a non-tax-related loss is ~~required. Until~~considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the results of operations, cash flows, or financial condition of the Registrants.

Recently Issued Accounting Standards

See Note 1 to the financial statements under "Recently Adopted Accounting Standards" for additional information.

In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. The Registrants adopted the new standard effective January 1, 2019. See Note 9 to the financial statements for additional information and related disclosures.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

FINANCIAL CONDITION AND LIQUIDITY

Overview

The financial condition of each Registrant remained stable at December 31, 2019. The Registrants' cash requirements primarily consist of funding ongoing operations, including unconsolidated subsidiaries, as well as common stock dividends, capital expenditures, and debt maturities. Southern Power's cash requirements also include distributions to noncontrolling interests. Capital expenditures and other investing activities for the traditional electric operating companies include investments to meet projected long-term demand requirements, including to build new generation facilities, to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units and closures of ash ponds, to expand and improve transmission and distribution facilities, and for restoration following major storms. Southern Power's capital expenditures and other investing activities may include acquisitions or new construction associated with its overall growth strategy and to maintain its existing generation fleet's performance. Southern Company Gas' capital expenditures and other investing activities include investments to meet projected long-term demand requirements, to maintain existing natural gas distribution systems as well as to update and expand these systems, and to comply with environmental regulations.

Operating cash flows provide a substantial portion of the Registrants' cash needs. During 2019, Southern Power utilized tax credits, which provided $734 million in operating cash flows. For the three-year period from 2020 through 2022, each Registrant's projected stock dividends, capital expenditures, and debt maturities, as well as distributions to noncontrolling interests for Southern Power, are expected to exceed its operating cash flows. Southern Company plans to finance future cash needs in excess of its operating cash flows primarily by accessing borrowings from financial institutions and issuing debt and hybrid securities in the capital markets. Each Subsidiary Registrant plans to finance its future cash needs in excess of its operating cash flows primarily through external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Georgia Power plans to utilize borrowings through the FFB and Southern Power plans to utilize tax equity partnership contributions. The Registrants plan to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs and continue to monitor their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," "Capital Requirements," and "Contractual Obligations" herein for additional information.

The Registrants' investments in their qualified pension plans and Alabama Power's and Georgia Power's investments in their nuclear decommissioning trust funds increased in value at December 31, 2019 as compared to December 31, 2018. In December 2019, the Registrants voluntarily contributed the following amounts to the qualified pension plan:



	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Contributions to qualified pension plan	$	1,136	$	362	$	200	$	54	$	24	$	145

No mandatory contributions to the qualified pension plans are anticipated during 2020. See "Contractual Obligations" herein and Notes 6 and 11 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Analysis of Cash Flows

Net cash flows provided from (used for) operating, investing, and financing activities in 2019 and 2018 are presented in the following table:



Net cash provided from (used for):	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
2019
Operating activities	$	5,781		$	1,779		$	2,907		$	339		$	1,385		$	1,067
Investing activities	(3,392		)	(1,963		)	(3,885		)	(263		)	(167		)	(1,386		)
Financing activities	(1,930		)	765			918			(83		)	(1,120		)	298

2018
Operating activities	$	6,945		$	1,881		$	2,769		$	804		$	631		$	764
Investing activities	(5,760		)	(2,289		)	(3,109		)	(232		)	(227		)	998
Financing activities	(1,813		)	177			(400		)	(527		)	(363		)	(1,770		)

Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Southern Company

Net cash provided from operating activities decreased $1.2 billion in 2019 as compared to 2018 primarily due to the voluntary contribution to the qualified pension plan and the timing of vendor payments.

The net cash used for investing activities in 2019 and 2018 was primarily due to the traditional electric operating companies' construction of electric generation, transmission, and distribution facilities, including installation of equipment to comply with environmental standards, and capital expenditures for Southern Company Gas' infrastructure replacement programs, partially offset by proceeds from the sale transactions described in Note 15 to the financial statements, which totaled $5.1 billion and $3.0 billion in 2019 and 2018, respectively.

Alabama Power

The net cash used for investing activities in 2019 and 2018 was primarily due to gross property additions.

Georgia Power

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Mississippi Power

The net cash used for investing activities in 2019 and 2018 was primarily due to gross property additions.

Southern Power

Southern Company Gas

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Significant Balance Sheet Changes

Southern Company

Significant balance sheet changes in 2019 for Southern Company included:

an increase of $2.3 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' construction of electric generation, transmission, and distribution facilities, including installation of equipment to comply with environmental standards, net of $1.2 billion and $1.0 billion reclassified to other regulatory assets and regulatory assets associated with AROs, respectively, as a result of generating unit retirements at Alabama Power and Georgia Power;

an increase in other regulatory assets of $1.8 billion primarily related to the $1.2 billion reclassification from property, plant, and equipment discussed above and a $0.8 billion increase in regulatory assets associated with retiree benefit plans primarily resulting from a decrease in the overall discount rate used to calculate benefit obligations;

increases in operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.8 billion, recorded upon the adoption of ASC 842;

an increase of $1.4 billion in regulatory assets associated with AROs primarily related to the $1.0 billion reclassification from property, plant, and equipment discussed above and ARO revisions at Alabama Power and Mississippi Power related to the CCR Rule;

an increase of $1.3 billion in accumulated deferred income taxes primarily related to the expected utilization of tax credit carryforwards in the 2019 tax year as a result of increased taxable income from the sale of Gulf Power; and

a decrease of $0.9 billion in notes payable related to net repayments of short-term bank debt and commercial paper.

See Notes 2, 5, 6, 8, 9, 10, 11, and 15 to the financial statements for additional information.

Alabama Power

Significant balance sheet changes in 2019 for Alabama Power included:

an increase of $1.5 billion in total common stockholder's equity primarily due to a $1.2 billion capital contribution from Southern Company;

increases of $0.9 billion in regulatory assets associated with AROs and $0.7 billion in other regulatory assets, deferred primarily due to the impacts of retiring and reclassifying Plant Gorgas Units 8, 9, and 10;

an increase of $0.6 billion in cash and cash equivalents; and

an increase of $0.3 billion in AROs, deferred primarily due to an increase in the ARO estimate related to ash pond facilities.

See Notes 2 and 6 to the financial statements for additional information.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Georgia Power

Significant balance sheet changes in 2019 for Georgia Power included:

increases in operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.4 billion, recorded upon the adoption of ASC 842;

an increase of $742 million in total common stockholder's equity primarily due to capital contributions from Southern Company.

See Notes 2, 8, 9, and 11 to the financial statements for additional information.

Mississippi Power

Significant balance sheet changes in 2019 for Mississippi Power included:

an increase of $107 million in other property and investments primarily due to a new tolling arrangement accounted for as a sales-type lease;

increases of $67 million in regulatory assets associated with AROs and $31 million in AROs, deferred primarily due to ARO revisions; and


•	a net change of $57 million in accumulated deferred income tax assets and liabilities primarily due to the recognition of a tax loss on the CO₂ pipeline transfer and the alternative minimum tax carryforward from prior years.

See Notes 2, 6, 8, 9, and 10 to the financial statements for additional information.

Southern Power

Significant balance sheet changes in 2019for Southern Power included:

a $662 million decrease in stockholders' equity due to returns of capital to Southern Company;

a $635 million decrease in accumulated deferred income tax assets primarily related to the utilization of tax credits for the 2019 tax year;

a $619 million decrease in long-term debt (including securities due within one year) related to the maturity of $600 million in senior notes;

a $449 million increase in notes payable due to net issuances of commercial paper; and

increases in operating lease right-of-use assets, net of amortization and operating lease obligations totaling $369 million and $376 million, respectively, recorded upon the adoption of ASC 842.

See Notes 8, 9, and 10 to the financial statements for additional information.

Southern Company Gas

Significant balance sheet changes in 2019 for Southern Company Gas included:

additional paid-in-capital of $841 million primarily related to capital contributions from Southern Company;

decreases of $373 million and $414 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and volumes of natural gas sold;

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

a $203 million increase in accumulated deferred income taxes primarily due to accelerated tax depreciation and other timing differences;

reclassification of $171 million in total assets held for sale associated with Pivotal LNG and Atlantic Coast Pipeline;

increases of $93 million in operating right-of-use assets and $92 million in operating lease obligations, respectively, related to the adoption of ASC 842.

See Notes 3, 7, 8, 9, 10, and 15 to the financial statements for additional information.

Sources of Capital

The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Georgia Power plans to utilize borrowings from the FFB, as discussed further in Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings," Southern Power plans to utilize tax equity partnership contributions, as discussed further herein, and Southern Company Gas plans to utilize proceeds from the pending sale of its interests in Pivotal LNG and Atlantic Coast Pipeline, as discussed further in Note 15 to the financial statements under "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline."

The amount, type, and timing of any financings in 2020, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals (for the Subsidiary Registrants), and other factors. See "Capital Requirements" herein for additional information.

Southern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are ~~disposed~~consolidated in Southern Power's financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. During 2019, Southern Power obtained tax equity funding for the Wildhorse Mountain wind project and received proceeds of $97 million. See Notes 1 and 15 to the financial statements under "General" and "Southern Power," respectively, for additional information.

The issuance of securities by the traditional electric operating companies and Nicor Gas is generally subject to the approval of the applicable state PSC or other applicable state regulatory agency. The issuance of all securities by Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company, the traditional electric operating companies, and Southern Power (excluding its subsidiaries), Southern Company Gas Capital, and Southern Company Gas (excluding its other subsidiaries) file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the securities registered under the 1933 Act, are closely monitored and appropriate filings are made to ensure flexibility in the capital markets.

The Registrants generally obtain financing separately without credit support from any affiliate. See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company in the Southern Company system, except in the case of Southern Company Gas, as described below.

The traditional electric operating companies and SEGCO may utilize a Southern Company subsidiary organized to issue and sell commercial paper at their ~~estimated fair value~~request and for their benefit. Proceeds from such issuances for the benefit of an individual company are loaned directly to that company. The obligations of each traditional electric operating company and SEGCO under these arrangements are several and there is ~~re-evaluated~~no cross-affiliate credit support. Alabama Power also maintains its own separate commercial paper program.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At December 31, 2019, the amount of subsidiary retained earnings restricted to dividend totaled $951 million. This restriction did not impact Southern Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.

The Registrants' current liabilities frequently exceed their current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. See Note 8 to the financial statements for additional information. Also see "Financing Activities" herein for information on issuances of long-term debt subsequent to December 31, 2019. At December 31, 2019, the following Registrants' current liabilities exceeded their current assets, primarily as a result of securities due within one year and notes payable, as shown in the table below:



At December 31, 2019	Southern Company^(*)		Georgia Power		Mississippi Power		Southern Power
	(in millions)
Current liabilities in excess of current assets	$	2,729	$	1,902	$	125	$	945
Securities due within one year	2,989		1,025		281		824
Notes payable	2,055		365		—		549


(*)	Includes $600 million and $465 million of securities due within one year and notes payable, respectively, at the parent company.

The Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as commercial paper, lines of credit, and short-term bank notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company.

Bank Credit Arrangements

At December 31, 2019, the Registrants' unused committed credit arrangements with banks were as follows:



At December 31, 2019	Southern Company parent		Alabama Power		Georgia Power		Mississippi Power		Southern Power^(a)		Southern Company Gas^(b)		SEGCO		Southern Company
	(in millions)
Unused committed credit	$	1,999	$	1,328	$	1,733	$	150	$	591	$	1,745	$	30	$	7,576

(a)


(b)	Includes $1.245 billion and $500 million at Southern Company Gas Capital and Nicor Gas, respectively.

Subject to applicable market conditions, the Registrants, Nicor Gas, and SEGCO expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, the Registrants, Nicor Gas, and SEGCO may extend the maturity dates and/or increase or decrease the lending commitments thereunder. A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.

Short-term Borrowings

The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its commercial paper program. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of the Registrants' short-term borrowings were as follows:

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report



	Short-term Debt at the End of the Period
	Amount Outstanding						Weighted Average Interest Rate
	December 31,						December 31,
	2019		2018		2017		2019		2018		2017
	(in millions)
Southern Company	$	2,055	$	2,915	$	2,439	2.1	%	3.1	%	1.9	%
Alabama Power	—		—		3		—		—		3.7
Georgia Power	365		294		150		2.2		3.1		2.2
Mississippi Power	—		—		4		—		—		3.8
Southern Power	549		100		105		2.2		3.1		2.0
Southern Company Gas:
Southern Company Gas Capital	$	372	$	403	$	1,243	2.1	%	3.1	%	1.7	%
Nicor Gas	278		247		275		1.8		3.0		1.8
Southern Company Gas Total	$	650	$	650	$	1,518	2.0	%	3.0	%	1.8	%



	Short-term Debt During the Period^(*)
	Average Amount Outstanding						Weighted Average Interest Rate						Maximum Amount Outstanding
	2019		2018		2017		2019		2018		2017		2019		2018		2017
	(in millions)												(in millions)
Southern Company	$	1,240	$	3,377	$	2,672	2.6	%	2.6	%	1.5	%	$	2,914	$	5,447	$	3,668
Alabama Power	17		27		25		2.6		2.3		1.3		190		258		223
Georgia Power	371		139		427		2.7		2.5		1.8		935		710		1,460
Mississippi Power	—		68		18		—		2.0		3.0		—		300		36
Southern Power	76		188		232		2.7		2.5		1.4		578		385		419
Southern Company Gas:
Southern Company Gas Capital	$	302	$	520	$	723	2.6	%	2.3	%	1.4	%	$	490	$	1,361	$	1,243
Nicor Gas	91		123		176		2.3		2.2		1.1		278		275		525
Southern Company Gas Total	$	393	$	643	$	899	2.5	%	2.3	%	1.4	%


(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2019, 2018, and 2017.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Financing Activities

The following table outlines the Registrants' long-term debt financing activities for the year ended December 31, 2019:



Company	Senior Note Issuances		Senior Note Maturities, Redemptions, and Repurchases		Revenue Bond Issuances and Reofferings of Purchased Bonds		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities^(a)
	(in millions)
Southern Company parent	$	—	$	2,400	$	—	$	—	$	1,725	$	—
Alabama Power	600		200		—		—		—		1
Georgia Power	750		500		584		223		1,218		13
Mississippi Power	—		25		43		—		—		—
Southern Power	—		600		—		—		—		—
Southern Company Gas	—		300		—		—		300		50
Other	—		—		—		25		—		17
Elimination^(b)	—		—		—		—		—		(7		)
Southern Company	$	1,350	$	4,025	$	627	$	248	$	3,243	$	74


(a)	Includes reductions in finance lease obligations resulting from cash payments under finance leases.


(b)	Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Registrants plan to continue, when ~~circumstances or events change.~~economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Southern Company

During 2019, Southern Company issued approximately 19.5 million shares of common stock through employee equity compensation plans and received proceeds of approximately $844 million.

In January 2019, Southern Company repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.

In 2019, Southern Company, through repurchases and redemptions, retired all $1.0 billion aggregate principal amount of its 1.85% Senior Notes due July 1, 2019, $350 million aggregate principal amount of its Series 2014B 2.15% Senior Notes due September 1, 2019, $750 million aggregate principal amount of its Series 2018A Floating Rate Notes due February 14, 2020, and $300 million aggregate principal amount of its Series 2017A Floating Rate Senior Notes due September 30, 2020.

Subsequent to December 31, 2019, Southern Company issued $1.0 billion aggregate principal amount of Series 2020A 4.95% Junior Subordinated Notes due January 30, 2080.

Alabama Power

In February 2019, Alabama Power repaid at maturity $200 million aggregate principal amount of Series Z 5.125% Senior Notes due February 15, 2019.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

In September 2019, Alabama Power issued $600 million aggregate principal amount of Series 2019A 3.45% Senior Notes due October 1, 2049.

Subsequent to December 31, 2019, Alabama Power received a capital contribution totaling $610 million from Southern Company.

Georgia Power

In March and December 2019, Georgia Power made borrowings under the multi-advance credit facilities related to the Amended and Restated Loan Guarantee Agreement in an aggregate principal amount of $835 million and $383 million, respectively, with applicable interest rates of 3.213% and 2.537%, respectively, both for an interest period that extends to the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" for additional information.

In June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.

During 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and were held by Georgia Power at December 31, 2018:

$173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009;

$65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008;

$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994; and

During 2019, Georgia Power purchased, held, and subsequently reoffered to the public an additional $115 million of pollution control revenue bonds.

In December 2019, Georgia Power repaid at maturity $500 million aggregate principal amount of its Series 2009B 4.25% Senior Notes.

Mississippi Power

In December 2019, Mississippi Power redeemed $25 million aggregate principal amount of its Series 2018A Floating Rate Senior Notes due March 27, 2020.

Southern Power

In May 2019, Southern Power repaid at maturity a $100 million short-term floating rate bank loan.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

In December 2019, Southern Power repaid at maturity $600 million aggregate principal amount of its Series 2016D 1.95% Senior Notes.

Also in December 2019, Southern Power entered into a short-term floating rate bank loan in the aggregate principal amount of $100 million, bearing interest based on one-month LIBOR. Subsequent to December 31, 2019, Southern Power repaid the bank loan.

Southern Company Gas

In July 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of its 4.7% first mortgage bonds.

In August 2019, Southern Company Gas Capital repaid at maturity $300 million aggregate principal amount of its 5.25% Senior Notes.

In August and October 2019, Nicor Gas issued $200 million and $100 million, respectively, aggregate principal amount of first mortgage bonds in a private placement.

Storm Damage Recovery

~~The Company defers~~Beginning January 1, 2020, Georgia Power is recovering $213 million annually through December 31, 2022, as provided in the 2019 ARP, for incremental operations and ~~recovers certain~~maintenance costs ~~related to damages~~of damage from major storms ~~as mandated by the Georgia PSC. Beginning January 1, 2014, the Company is accruing $30 million annually under the 2013 ARP that is recoverable through base rates. As of~~to its transmission and distribution facilities. At December 31, ~~2016 and December 31, 2015,~~2019, the balance in the regulatory asset related to storm damage was $206 million and $92 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $176 million and $62 million included in other regulatory assets, deferred, respectively. The annual recovery amount is expected to be reviewed by the Georgia PSC and adjusted in future regulatory proceedings. As a result of this

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

regulatory treatment, costs related to storms are generally not expected to have a material impact on the Company's earnings. See Note 3 under "Retail Regulatory Matters – Storm Damage Recovery" for additional information.

~~Environmental Remediation Recovery~~

The Company maintains a reserve for environmental remediation as mandated by the Georgia PSC. In December 2013, the Georgia PSC approved the 2013 ARP including the recovery of approximately $2 million annually through the environmental compliance cost recovery (ECCR) tariff. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reduces the reserve as expenditures are incurred. Any difference between the liabilities accrued and cost recovered through rates is deferred as a regulatory asset or liability. The annual recovery amount is expected to be reviewed by the Georgia PSC and adjusted in future regulatory proceedings. As a result of this regulatory treatment, environmental remediation liabilities generally are not expected to have a material impact on the Company's earnings. As of ~~December 31, 2016~~, the balance of the environmental remediation liability was $17 million, with approximately $2 million included in other regulatory assets, current and approximately $33 million included as other regulatory assets, deferred. See Note 3 under "Environmental Matters – Environmental Remediation" for additional information.

~~Cash and Cash Equivalents~~

~~For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.~~

~~Materials and Supplies~~

Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.

~~Fuel Inventory~~

Fuel inventory includes the average cost of coal, natural gas, and oil, as well as transportation and emissions allowances. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates approved by the Georgia PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.

~~Financial Instruments~~

The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Georgia PSC-approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives.

Beginning in 2016, the Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under netting arrangements. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at ~~December 31, 2016~~.

The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.

~~Comprehensive Income~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~2. RETIREMENT BENEFITS~~

The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). On December 19, 2016, the Company voluntarily contributed $287 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2017. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the Georgia PSC and the FERC. For the year ending December 31, 2017, no other postretirement trust contributions are expected.

~~Actuarial Assumptions~~

The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below.

Assumptions used to determine net periodic costs: 2016 2015 2014
Pension plans
Discount rate – benefit obligations 4.65 % 4.18 % 5.02 %
Discount rate – interest costs 3.86
4.18
5.02
Discount rate – service costs 5.03
4.49
5.02
Expected long-term return on plan assets 8.20
8.20
8.20
Annual salary increase 4.46
3.59
3.59
Other postretirement benefit plans
Discount rate – benefit obligations 4.49 % 4.03 % 4.85 %
Discount rate – interest costs 3.67
4.03
4.85
Discount rate – service costs 4.88
4.39
4.85
Expected long-term return on plan assets 6.27
6.48
6.75
Annual salary increase 4.46
3.59
3.59

Assumptions used to determine benefit obligations: 2016
2015
Pension plans

Discount rate 4.40 %
4.65 %
Annual salary increase 4.46

4.46
Other postretirement benefit plans

Discount rate 4.23 %
4.49 %
Annual salary increase 4.46

4.46

The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2016 were as follows:

Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached
Pre-65 6.50 % 4.50 % 2025
Post-65 medical 5.00
4.50
2025
Post-65 prescription 10.00
4.50
2025

~~An annual increase or decrease in the assumed medical care cost trend rate of~~ 1% ~~would affect the APBO and the service and interest cost components at~~ ~~December 31, 2016~~ ~~as follows:~~

1 Percent
Increase

1 Percent
Decrease
(in millions)
Benefit obligation $ 55
$ 48
Service and interest costs 2
2

~~Pension Plans~~

~~The total accumulated benefit obligation for the pension plans was $3.5 billion at~~ ~~December 31, 2016~~ ~~and~~ ~~$3.3 billion~~ at ~~December 31, 2015. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~were as follows:~~

2016 2015
(in millions)
Change in benefit obligation
Benefit obligation at beginning of year $ 3,615
$ 3,781
Service cost 70
73
Interest cost 136
154
Benefits paid (164 ) (188 )
Actuarial (gain) loss 143
(205 )
Balance at end of year 3,800
3,615
Change in plan assets
Fair value of plan assets at beginning of year 3,196
3,383
Actual return (loss) on plan assets 288
(13 )
Employer contributions 301
14
Benefits paid (164 ) (188 )
Fair value of plan assets at end of year 3,621
3,196
Accrued liability $ (179 ) $ (419 )

At ~~December 31, 2016~~, the projected benefit obligations for the qualified and non-qualified pension plans were $3.6 billion and $152 million, respectively. All pension plan assets are related to the qualified pension plan.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~Amounts recognized in the balance sheets at~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~related to the Company's pension plans consist of the following:~~

2016 2015
(in millions)
Other regulatory assets, deferred $ 1,129
$ 1,076
Other current liabilities (14 ) (13 )
Employee benefit obligations (165 ) (406 )

~~Presented below are the amounts included in regulatory assets at~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2017.~~

2016 2015
Estimated
Amortization
in 2017
(in millions)
Prior service cost $ 17
$ 8
$ 3
Net (gain) loss 1,112
1,068
57
Regulatory assets $ 1,129
$ 1,076

~~The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~are presented in the following table:~~

2016 2015
(in millions)
Regulatory assets:
Beginning balance $ 1,076
$ 1,102
Net (gain) loss 99
59
Change in prior service costs 14
—
Reclassification adjustments:
Amortization of prior service costs (5 ) (9 )
Amortization of net gain (loss) (55 ) (76 )
Total reclassification adjustments (60 ) (85 )
Total change 53
(26 )
Ending balance $ 1,129
$ 1,076

~~Components of net periodic pension cost were as follows:~~

2016 2015 2014
(in millions)
Service cost $ 70
$ 73
$ 62
Interest cost 136
154
153
Expected return on plan assets (258 ) (251 ) (228 )
Recognized net (gain) loss 55
76
41
Net amortization 5
9
10
Net periodic pension cost $ 8
$ 61
$ 38

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.

~~Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At~~ ~~December 31, 2016, estimated benefit payments were as follows:~~

Benefit
Payments
(in millions)
2017 $ 184
2018 190
2019 196
2020 202
2021 206
2022 to 2026 1,126

~~Other Postretirement Benefits~~

~~Changes in the APBO and in the fair value of plan assets during the plan years ended~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~were as follows:~~

2016 2015
(in millions)
Change in benefit obligation
Benefit obligation at beginning of year $ 854
$ 864
Service cost 6
7
Interest cost 30
34
Benefits paid (45 ) (45 )
Actuarial (gain) loss (1 ) (22 )
Plan amendment —
12
Retiree drug subsidy 3
4
Balance at end of year 847
854
Change in plan assets
Fair value of plan assets at beginning of year 358
395
Actual return (loss) on plan assets 21
(6 )
Employer contributions 17
10
Benefits paid (42 ) (41 )
Fair value of plan assets at end of year 354
358
Accrued liability $ (493 ) $ (496 )

~~Amounts recognized in the balance sheets at~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~related to the Company's other postretirement benefit plans consist of the following:~~

2016 2015
(in millions)
Other regulatory assets, deferred $ 213
$ 223
Employee benefit obligations (493 ) (496 )

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~Presented below are the amounts included in regulatory assets at~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2017.~~

2016 2015
Estimated
Amortization
in 2017
(in millions)
Prior service cost $ 6
$ 8
$ 1
Net (gain) loss 207
215
8
Regulatory assets $ 213
$ 223

~~The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~are presented in the following table:~~

2016 2015
(in millions)
Regulatory assets:
Beginning balance $ 223
$ 213
Net (gain) loss —
9
Change in prior service costs —
12
Reclassification adjustments:
Amortization of prior service costs (1 ) —
Amortization of net gain (loss) (9 ) (11 )
Total reclassification adjustments (10 ) (11 )
Total change (10 ) 10
Ending balance $ 213
$ 223

~~Components of the other postretirement benefit plans' net periodic cost were as follows:~~

2016 2015 2014
(in millions)
Service cost $ 6
$ 7
$ 6
Interest cost 30
34
34
Expected return on plan assets (22 ) (24 ) (25 )
Net amortization 10
11
2
Net periodic postretirement benefit cost $ 24
$ 28
$ 17

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:

Benefit
Payments

Subsidy
Receipts
Total
(in millions)
2017 $ 54
$ (4 ) $ 50
2018 56
(5 ) 51
2019 58
(5 ) 53
2020 59
(5 ) 54
2021 60
(6 ) 54
2022 to 2026 303
(32 ) 271

~~Benefit Plan Assets~~

Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.

~~The composition of the Company's pension plan and other postretirement benefit plan assets as of~~ ~~December 31, 2016~~ ~~and~~ ~~2015, along with the targeted mix of assets for each plan, is presented below:~~

Target 2016 2015
Pension plan assets:
Domestic equity 26 % 29 % 30 %
International equity 25
22
23
Fixed income 23
29
23
Special situations 3
2
2
Real estate investments 14
13
16
Private equity 9
5
6
Total 100 % 100 % 100 %
Other postretirement benefit plan assets:
Domestic equity 36 % 35 % 34 %
International equity 24
24
27
Domestic fixed income 33
35
25
Global fixed income

8
Special situations 1
1
—
Real estate investments 4
4
4
Private equity 2
1
2
Total 100 % 100 % 100 %

The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices.~~

~~Investment Strategies~~

~~Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above:~~

~~Domestic equity.~~ ~~A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.~~

~~International equity.~~ ~~A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.~~

~~Fixed income.~~ ~~A mix of domestic and international bonds.~~

~~Trust-owned life insurance (TOLI).~~ ~~Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio.~~

~~Special situations.~~ Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.

~~Real estate investments.~~ ~~Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.~~

~~Private equity.~~ Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.

~~Benefit Plan Asset Fair Values~~

~~Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

~~Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:~~

~~Domestic and international equity.~~Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.

~~Fixed income.~~Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.

~~TOLI.~~ Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.

~~Real estate investments, private equity, and special situations investments.~~Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~The fair values of pension plan assets as of~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2015, investments in special situations were presented in the table below based on the nature of the investment.

Fair Value Measurements Using
Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient
As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Assets:
Domestic equity^(*)
$ 686
$ 317
$ —
$ —
$ 1,003
International equity^(*)
420
380
—
—
800
Fixed income:
U.S. Treasury, government, and agency bonds —
201
—
—
201
Mortgage- and asset-backed securities —
4
—
—
4
Corporate bonds —
338
—
—
338
Pooled funds ��
179
—
—
179
Cash equivalents and other 340
1
—
—
341
Real estate investments 106
—
—
394
500
Special situations —
—
—
61
61
Private equity —
—
—
188
188
Total $ 1,552
$ 1,420
$ —
$ 643
$ 3,615


~~(*)~~	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

Fair Value Measurements Using
Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient
As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Assets:
Domestic equity^(*)
$ 565
$ 236
$ —
$ —
$ 801
International equity^(*)
412
343
—
—
755
Fixed income:
U.S. Treasury, government, and agency bonds —
157
—
—
157
Mortgage- and asset-backed securities —
69
—
—
69
Corporate bonds —
394
—
—
394
Pooled funds —
173
—
—
173
Cash equivalents and other —
50
—
—
50
Real estate investments 103
—
—
421
524
Private equity —
—
—
220
220
Total $ 1,080
$ 1,422
$ —
$ 641
$ 3,143

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~


~~(*)~~	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

The fair values of other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2015, investments in special situations were presented in the table below based on the nature of the investment.

Fair Value Measurements Using
Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient
As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Assets:
Domestic equity^(*)
$ 45
$ 9
$ —
$ —
$ 54
International equity^(*)
11
37
—
—
48
Fixed income:
U.S. Treasury, government, and agency bonds —
5
—
—
5
Mortgage- and asset-backed securities —
—
—
—
—
Corporate bonds —
9
—
—
9
Pooled funds —
38
—
—
38
Cash equivalents and other 15
—
—
—
15
Trust-owned life insurance —
162
—
—
162
Real estate investments 3
—
—
11
14
Special situations —
—
—
2
2
Private equity —
—
—
5
5
Total $ 74
$ 260
$ —
$ 18
$ 352


~~(*)~~	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

Fair Value Measurements Using
Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient
As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Assets:
Domestic equity^(*)
$ 30
$ 36
$ —
$ —
$ 66
International equity^(*)
12
41
—
—
53
Fixed income:
U.S. Treasury, government, and agency bonds —
5
—
—
5
Mortgage- and asset-backed securities —
2
—
—
2
Corporate bonds —
12
—
—
12
Pooled funds —
30
—
—
30
Cash equivalents and other 10
6
—
—
16
Trust-owned life insurance —
158
—
—
158
Real estate investments 3
—
—
12
15
Private equity —
—
—
7
7
Total $ 55
$ 290
$ —
$ 19
$ 364


~~(*)~~	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

~~Employee Savings Plan~~

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2016, 2015, and 2014 were $27 million, $26 million, and ~~$25 million, respectively.~~

~~3. CONTINGENCIES AND REGULATORY MATTERS~~

~~General Litigation Matters~~

In 2011, plaintiffs filed a putative class action against the Company in the Superior Court of Fulton County, Georgia alleging that the Company's collection in rates of municipal franchise fees (all of which are remitted to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. On November 16, 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court for further proceedings. The Company has filed a petition for writ of certiorari with the Georgia Supreme Court. The Company believes the plaintiffs' claims have no merit and intends to vigorously defend itself in this matter. The ultimate outcome of this matter cannot be determined at this time.

The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~Environmental Matters~~

~~Environmental Remediation~~

The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up affected sites. See Note 1 under "Environmental Remediation Recovery" for additional information.

~~The Company's environmental remediation liability as of December 31, 2016 was $17~~$410 million. The Company has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

The ultimate outcome of these matters cannot be determined at this time; however, as a result of the Company's regulatory treatment for environmental remediation expenses described in Note 1 under "Environmental Remediation Recovery," these matters are not expected to have a material impact on the Company's financial statements.

~~Nuclear Fuel Disposal Costs~~

Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with the Company that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plant Hatch and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, the Company pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract.

In 2014, the Court of Federal Claims entered a judgment in favor of the Company in its spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. In March 2015, the Company recovered approximately $18 million, based on its ownership interests, which was credited to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers.

In 2014, the Company filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plant Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2016 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on the Company's net income is expected.

~~On-site dry spent fuel storage facilities are operational at Plant Vogtle Units 1 and 2 and Plant Hatch. Facilities can be expanded to accommodate spent fuel through the expected life of each plant.~~

~~FERC Matters~~

The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing in May 2015 and in June 2015 filed their response with the FERC.

On December 9, 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. The traditional electric operating companies (including the Company) and Southern Power expect to make a

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

compliance filing within 30 days accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Retail Regulatory Matters~~

~~Rate Plans~~

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, the 2013 ARP will continue in effect until December 31, 2019, and the Company will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, the Company and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60/40 basis with their respective customers; thereafter, all merger savings will be retained by customers.

In accordance with the 2013 ARP, the Georgia PSC approved increases to tariffs effective January 1, 2015 and 2016 as follows: (1) traditional base tariff rates by approximately $107 million and $49 million, respectively; (2) ECCR tariff by approximately $23 million and $75 million, respectively; (3) Demand-Side Management tariffs by approximately $3 million in each year; and (4) Municipal Franchise Fee tariff by approximately $3 million and $13 million, respectively, for a total increase in base revenues of approximately $136 million and $140 million, respectively.

Under the 2013 ARP, the Company's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by the Company. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2014, the Company's retail ROE exceeded 12.00%, and the Company refunded to retail customers approximately $11 million in 2016, as approved by the Georgia PSC on February 18, 2016. In 2015, the Company's retail ROE was within the allowed retail ROE range. In 2016, the Company's retail ROE exceeded 12.00%, and the Company expects to refund to retail customers approximately $40 million, subject to review and approval by the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time.

~~Integrated Resource Plan~~

On July 28, 2016, the Georgia PSC approved the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, the Company sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC.

Additionally, the Georgia PSC approved the Company's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.

The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in the Company's 2019 base rate case.

The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear as an option at a future generation site in Stewart County, Georgia. The timing of cost recovery will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.

~~Fuel Cost Recovery~~

The Company has established fuel cost recovery rates approved by the Georgia PSC. In December 2015, the Georgia PSC approved the Company's request to lower annual billings by approximately $350 million effective January 1, 2016. On May 17, 2016, the Georgia PSC approved the Company's request to further lower annual billings by approximately $313 million effective

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

June 1, 2016. On December 6, 2016, the Georgia PSC approved the delay of the Company's next fuel case, which was previously scheduled to be filed by February 28, 2017. The Georgia PSC will review the Company's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case unless the Company deems it necessary to file a fuel case at an earlier time. Under an Interim Fuel Rider, the Company continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under recovered fuel balance exceeds $200 million.

The Company's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48-month time horizon effective January 1, 2016.

The Company's over recovered fuel balance totaled approximately $84 million at December 31, 2016 and is included in over recovered regulatory clause revenues, current. At December 31, 2015, the Company's over recovered fuel balance totaled approximately $116 million, including $10 million in over recovered regulatory clause revenues, current and $106 million in other deferred credits and liabilities.

Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on the Company's revenues or net income, but will affect cash flow.

~~Storm Damage Recovery~~

As of December 31, 2016, the balance in the Company's regulatory asset related to storm damage was $206 million. During October 2016, Hurricane Matthew caused significant damage to the Company's transmission and distribution facilities. As of December 31, 2016, the Company had recorded incremental restoration cost related to this hurricane of $121 million, of which approximately $116 million was charged to the storm damage reserve and the remainder was capitalized. The Company is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operations and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of ~~recovery of~~ storm damage ~~costs after December 31, 2019~~cost recovery is expected to be adjusted in ~~the Company's 2019 base rate case.~~future regulatory proceedings as necessary. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on ~~the~~Southern Company's or Georgia Power's financial statements. See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" for additional information regarding Georgia Power's storm damage reserve.

Mississippi Power

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

2019 Base Rate Case

Operations Review

Reserve Margin Plan

On December 31, 2019, Mississippi Power updated its proposed RMP, originally filed in August 2018, as required by the Mississippi PSC. In 2018, Mississippi Power had proposed alternatives to reduce its reserve margin and lower or avoid operating costs, with the most economic alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. The December 2019 update noted that Plant Daniel Units 1 and 2 currently have long-term economics similar to Plant Watson Unit 5. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. A decision by the Mississippi PSC that does not include recovery of the remaining book value of any generating units retired could have a material impact on Southern Company's and Mississippi Power's financial statements. The ultimate outcome of this matter cannot be determined at this time. See Note 3 to the financial statements under ~~"Storm Damage Recovery"~~"Other Matters– Mississippi Power" for additional information on Plant Daniel Units 1 and 2.

Performance Evaluation Plan

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Southern Company and Subsidiary Companies 2019 Annual Report

Energy Efficiency

Environmental Compliance Overview Plan

Fuel Cost Recovery

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Kemper County Energy Facility

Overview

Schedule and Cost Estimate

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Southern Company and Subsidiary Companies 2019 Annual Report

and property taxes, are estimated to total $17 million in 2020, $15 million to $16 million annually in 2021 through 2023, and $5 million in 2024.

See Note 10 to the financial statements for additional information.

Rate Recovery

Lignite Mine and CO₂ Pipeline Facilities

Government Grants

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Southern Company and Subsidiary Companies 2019 Annual Report

Municipal and Rural Associations Tariff

Cooperative Energy Power Supply Agreement

Southern Company Gas

Utility Regulation and Rate Design

distributing natural gas for Marketers;

constructing, operating, and maintaining the gas system infrastructure, including responding to customer service calls and leaks;

reading meters and maintaining underlying customer premise information for Marketers; and

planning and contracting for capacity on interstate transportation and storage systems.

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Southern Company and Subsidiary Companies 2019 Annual Report

The following table provides regulatory information for Southern Company Gas' natural gas distribution utilities:



	Nicor Gas	Atlanta Gas Light	Virginia Natural Gas	Chattanooga Gas
Authorized ROE^(a)	9.73%	10.25%	9.50%	9.80%
Authorized ROErange^(a)	N/A	10.05% - 10.45%	9.00% - 10.00%	N/A
Weather normalization mechanisms^(b)			ü	ü
Decoupled, including straight-fixed-variable rates^(c)	ü	ü	ü
Regulatory infrastructure program rates^(d)	ü		ü
Bad debt rider^(e)	ü		ü	ü
Energy efficiency plan^(f)	ü		ü
Annual base rate adjustment mechanism^(g)		ü		ü
Year of last rate decision	2019	2019	2018	2018


(a)	Atlanta Gas Light's authorized ROE and ROE range became effective on January 1, 2020. Atlanta Gas Light's ROE for 2019 was 10.75%.

(b)


(c)	Allows for recovery of fixed customer service costs separately from assumed natural gas volumes used by customers. On October 2, 2019, Nicor Gas received approval for a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a monthly benchmark level of revenue per rate class for recovery.


(d)	Programs that update or expand distribution systems and LNG facilities.


(e)	The recovery (refund) of bad debt expense over (under) an established benchmark expense. Nicor Gas, Virginia Natural Gas, and Chattanooga Gas recover the gas portion of bad debt expense through their purchased gas adjustment mechanisms.


(f)	Recovery of costs associated with plans to achieve specified energy savings goals.


(g)	Regulatory mechanism allowing annual adjustments to base rates up or down based on authorized ROE and/or ROE range.

GRAM

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Southern Company and Subsidiary Companies 2019 Annual Report

PRP

Rate Proceedings

Nicor Gas

Atlanta Gas Light

Virginia Natural Gas

See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" for additional information.

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Southern Company and Subsidiary Companies 2019 Annual Report

Affiliate Asset Management Agreements

Unrecognized Ratemaking Amounts



	December 31, 2019		December 31, 2018
	(in millions)
Atlanta Gas Light	$	70	$	95
Virginia Natural Gas	10		11
Nicor Gas	2		4
Total	$	82	$	110

Construction Programs

Nuclear Construction

~~Under the terms of~~continued under the Vogtle 3 and 4 Agreement,

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Southern Company and Subsidiary Companies 2019 Annual Report

which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

Cost and Schedule



	(in billions)
Base project capital cost forecast^(a)(b)	$	8.2
Construction contingency estimate	0.2
Total project capital cost forecast^(a)(b)	8.4
Net investment as of December 31, 2019^(b)	(5.9		)
Remaining estimate to complete^(a)	$	2.5


(a)	Excludes financing costs expected to be capitalized through AFUDC of approximately $300 million, of which $23 million had been accrued through December 31, 2019.


(b)	Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.

~~In 2009,~~request the Georgia PSC ~~voted~~ to ~~certify~~evaluate those expenditures for rate recovery.

In ~~addition, in 2009 the Georgia PSC approved inclusion~~April 2019, Southern Nuclear established aggressive target values for monthly construction production and system turnover activities as part of ~~the Plant Vogtle Units 3~~a strategy to maintain and, 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows the Company to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustmentswhere possible, build margin to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved an NCCR tariff of $368 million for 2014, as well as increases to the NCCR tariff of approximately $27 million and $19 million effective January 1, 2015 and 2016, respectively.

The Company is required to file semi-annual Vogtle Construction Monitoring (VCM) reports with the Georgia PSC by February 28 and August 31 each year. In accordance with the 2009 certification order, the Company requested amendments to the Plant Vogtle Units 3 and 4 certificate in both the February 2013 (eighth VCM) and February 2015 (twelfth VCM) filings, when projected construction capital costs to be borne by the Company increased by 5% above the certified costs and estimatedregulatory-approved in-service dates were extended. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between the Company and the Georgia PSC Staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and the Company. In April 2015, the Georgia PSC recognized that the certified cost and the 2013 Stipulation did not constitute a cost recovery cap and deemed the amendment requested in the February 2015 filing unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation.

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Southern Company and Subsidiary Companies 2019 Annual Report

Southern Nuclear and Georgia Power believe that ~~delay liquidated damages will commence if~~existing productivity levels and pace of activity completion are sufficient to meet the ~~nuclear fuel loading date for each unit does~~regulatory-approved in-service dates.

In February 2020, Southern Nuclear updated its cost and schedule forecast, which did not ~~occur by December 31, 2018~~change the projected overall capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and ~~December 31, 2019~~November 2022 for Unit 4;4. This update included initiatives to improve productivity while refining and ~~(v) provide~~extending system turnover plans and certain near-term milestone dates. Other milestone dates did not change. Achievement of the aggressive site work plan relies on meeting increased monthly production and activity target values during 2020. To meet these 2020 targets, existing craft, including subcontractors, construction productivity must improve and be sustained above historical average levels, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, must be maintained, and additional supervision and other field support resources must be retained. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the ~~Company,~~units by their regulatory-approved in-service dates.

As construction, including subcontract work, continues and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related craft labor productivity, particularly in the installation of electrical and mechanical commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on ~~its ownership interest, will pay to~~new technology that only within the ~~Contractor and capitalize to~~last few years began initial operation in the ~~project cost approximately $350 million,~~global nuclear industry at this scale), or regional transmission upgrades, any of which ~~approximately $263 million had been paid as of December 31, 2016. In addition,~~may require additional labor and/or materials; or other issues could arise and change the ~~Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3~~projected schedule and ~~4 Agreement, including cyber security,~~for which costs are reflected in the Company's current in-service forecast of $5.440 billion. Further, as part of the settlement and Westinghouse's acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor and (ii) the Vogtle Owners, Chicago Bridge & Iron Co, N.V., and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.estimated cost.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above the Company's current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) the Company would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be the Company's average cost of long-term debt. If the Georgia PSC adjusts the Company's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be the Company's average cost of long-term debt.

As of December 31, 2016, the Company had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between the Company and the DOE and a multi-advance credit facility among the Company, the DOE, and the FFB. See Note 6 under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, and mandatory prepayment events.

Joint Owner Contracts

In November 2017, the Vogtle Owners ~~or the Contractor or~~entered into an amendment to ~~both.~~

~~In addition to Toshiba's reaffirmation of its commitment, the Contractor provided the Company with revised forecasted in-service dates of December 2019 and September 2020~~their joint ownership agreements for Plant Vogtle Units 3 and 4 ~~respectively. The Company is currently reviewing a preliminary summary schedule supporting these dates~~to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that ~~ultimately must be reconciled to a detailed integrated project schedule. As construction continues,~~require the ~~risk remains that challenges with Contractor performance including labor productivity, fabrication, delivery, assembly, and installation~~vote of ~~plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. The Company expects~~ the ~~Contractor to employ mitigation efforts and believes~~holders of at least 90% of the ~~Contractor is responsible for any related costs under the~~ownership interests in Plant Vogtle Units 3 and 4 ~~Agreement.~~to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company ~~estimates its~~and Subsidiary Companies 2019 Annual Report

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet.

The ultimate outcome of these matters cannot be determined at this time.

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 44. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At December 31, 2019, Georgia Power had recovered approximately $2.2 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected to be ~~approximately $30~~recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. On December 17, 2019, the Georgia PSC approved Georgia Power's request to decrease the NCCR tariff by $62 million per month, with total construction period financing costs of approximately $2.5 billion. Additionally, the Company estimates its owner's costs to be approximately $6 million per month, net of delay liquidated damages.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~annually, effective January 1, 2020.

Georgia Power ~~Company~~is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, ~~Annual Report~~

~~The revised forecasted in-service dates are within~~ the ~~timeframe contemplated~~Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and ~~would enable both units to qualify for production tax credits the IRS has allocated to each~~related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 ~~which require the applicable unit to~~should be ~~placed in service before 2021. The net present value of the production tax credits is estimated at approximately $400 million per unit.~~

~~Future claims by the Contractor or the Company (on behalf of the~~completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle ~~Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle~~Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $75 million,

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

On February 18, 2020, the Georgia PSC approved Georgia Power's twentieth VCM report and its concurrently-filed twenty-first VCM report, including approval of (i) $1.2 billion of construction capital costs incurred from July 1, 2018 through June 30, 2019 and (ii) $21.5 million of expenditures related to Georgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings (which expenditures had previously been deferred by the Georgia PSC for later approval). Through the twenty-first VCM, the Georgia PSC has approved total construction capital costs incurred through June 30, 2019 of $6.7 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and ~~under~~approximately $188 million in related customer refunds). On February 19, 2020, Georgia Power filed its twenty-second VCM report with the ~~enhanced dispute resolution procedures, may be resolved~~Georgia PSC covering the period from July 1, 2019 through ~~litigation after the completion~~December 31, 2019, requesting approval of ~~nuclear fuel load for both units.~~$674 million of construction capital costs incurred during that period.

The ultimate outcome of these matters cannot be determined at this time.

~~4. JOINT OWNERSHIP AGREEMENTS~~Southern Power



Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Counterparties	PPA Contract Period
Projects Completed During the Year Ended December 31, 2019
Mankato expansion^(a)	Natural Gas	385	Mankato, MN	May 2019	Northern States Power Company	20 years
Wildhorse Mountain ^(b)	Wind	100	Pushmataha County, OK	December 2019	Arkansas Electric Cooperative Corporation	20 years
Projects Under Construction at December 31, 2019
Reading^(c)	Wind	200	Osage and Lyon Counties, KS	Second quarter 2020	Royal Caribbean Cruises LTD	12 years
Skookumchuck^(d)	Wind	136	Lewis and Thurston Counties, WA	Second quarter 2020	Puget Sound Energy	20 years

(a)


(b)	In May 2018, Southern Power purchased 100% of the membership interests of the Wildhorse Mountain facility. In December 2019, Southern Power entered into a tax equity partnership and, as a result, owns 100% of the Class B membership interests.


(c)	In August 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the Class B membership interests. The ultimate outcome of this matter cannot be determined at this time.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and ~~Alabama Power own equally all~~Subsidiary Companies 2019 Annual Report

(d)

Southern Company Gas

Infrastructure Replacement Programs and Capital Projects

Southern Company Gas continues to focus on capital discipline and cost control while pursuing projects and initiatives that are expected to have current and future benefits to customers, provide an appropriate return on invested capital, and help ensure the safety and reliability of the ~~outstanding~~utility infrastructure. In addition to capital ~~stock~~expenditures recovered through base rates by each of ~~SEGCO, which owns electric generating units~~the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide timely recovery of capital expenditures for specific infrastructure replacement programs. Total capital expenditures incurred during 2019 for gas distribution operations were $1.4 billion.



Utility	Program	Recovery	Expenditures in 2019		Expenditures Since Project Inception		Pipe Installed Since Project Inception	Scope of Program	Program Duration	Last Year of Program
			(in millions)				(miles)	(miles)	(years)
Nicor Gas	Investing in Illinois(*)	Rider	$	396	$	1,712	843	1,450	9	2023
Virginia Natural Gas	Steps to Advance Virginia's Energy (SAVE and SAVE II)	Rider	45		244		363	770	13	2024
Total			$	441	$	1,956	1,206	2,220


(*)	Includes replacement of pipes, compressors, and transmission mains along with other improvements such as new meters. Scope of program miles is an estimate and subject to change.

Nicor Gas

Virginia Natural Gas

Table of ~~1,020 MWs, as well as associated transmission facilities. The capacity of these units is sold equally~~ContentsIndex to ~~the~~Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and ~~Alabama Power~~Subsidiary Companies 2019 Annual Report

The SAVE program is subject to annual review by the Virginia Commission. In accordance with the base rate case order issued by the Virginia Commission in 2017, Virginia Natural Gas is recovering program costs incurred prior to September 1, 2017 through base rates. Program costs incurred subsequent to September 1, 2017 are currently recovered through a ~~power contract.~~separate rider and are subject to future base rate case proceedings.

Atlanta Gas Light

As discussed under "Regulatory Matters – Southern Company Gas – Utility Regulation and ~~Alabama Power make payments sufficient~~Rate Design" herein, i-SRP and i-VPR will continue under GRAM and the recovery of and return on current and future infrastructure program capital investments will be included in base rates.

Pipeline Construction Projects

Southern Company Gas is involved in two significant pipeline construction projects within its gas pipeline investments segment. These projects, along with Southern Company Gas' existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for ~~the operating expenses, taxes, interest expense,~~new capacity, enhance system reliability, and ~~a ROE. The Company's share of purchased power totaled $57 million in~~ ~~2016~~, ~~$78 million~~ in ~~2015, and~~ ~~$84 million~~ in ~~2014~~ ~~and is included in purchased power, affiliates~~generate economic development in the ~~statements of income. The~~areas served.

In 2014, Southern Company ~~accounts for SEGCO using the equity method. See Note 7 under "Guarantees" for additional information.~~

The Company owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, Dalton, Florida Power & Light Company, Jacksonville Electric Authority, and Gulf Power. Under these agreements, the Company has been contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third party claims related to these plants. In addition, the Company jointly owns the Rocky Mountain pumped storage hydroelectric plant with OPC, which is the operator of the plant. On August 31, 2016, the Company sold its 33%Gas entered into a joint venture, whereby it holds a 5% ownership interest in the ~~Intercession City combustion turbine unit~~Atlantic Coast Pipeline, an interstate pipeline company formed to ~~Duke Energy Florida, LLC.~~develop and operate an approximate 605-mile natural gas pipeline in North Carolina, Virginia, and West Virginia with expected initial transportation capacity of 1.5 Bcf per day. The proposed pipeline project is expected to transport natural gas to customers in Virginia. In 2017, the Atlantic Coast Pipeline received FERC approval.

At The Atlantic Coast Pipeline has experienced challenges to its permits since construction began in 2018. During the third and fourth quarters 2018, a FERC stop work order, together with delays in obtaining permits necessary for construction and construction delays due to judicial actions, impacted the cost and schedule for the project. Project cost estimates are approximately $8.0 billion ($400 million for Southern Company Gas), excluding financing costs. On October 4, 2019, the U.S. Supreme Court agreed to hear Atlantic Coast Pipeline's appeal of a lower court ruling that overturned a key permit for the project. On January 7, 2020, the U.S. Court of Appeals for the Fourth Circuit vacated another key permit. The operator of the joint venture has indicated that it currently expects to complete construction by the end of 2021 and place the project in service shortly thereafter.

On February 7, 2020, Southern Company Gas entered into an agreement with Dominion Atlantic Coast Pipeline, LLC for the sale of its interest in Atlantic Coast Pipeline. The transaction is expected to be completed in the first half of 2020; however, the ultimate outcome cannot be determined at this time. See Note 15 to the financial statements under "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline" for additional information.

Expected project costs related to the PennEast Pipeline for Southern Company Gas total approximately $300 million, excluding financing costs. In January 2018, the PennEast Pipeline received initial FERC approval. Work continues with state and federal agencies to obtain the required permits to begin construction. On September 10, 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On February 18, 2020, PennEast Pipeline filed a petition for a writ of certiorari to seek U.S. Supreme Court review of the appellate court decision. On December ~~31, 2016, the Company's percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation~~30, 2019, PennEast Pipeline filed a two-year extension request with the ~~above entities were as follows:~~FERC to complete the project by January 19, 2022.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Facility (Type) Company Ownership Plant in Service Accumulated Depreciation CWIP
(in millions)
Plant Vogtle (nuclear)
Units 1 and 2 45.7 % $ 3,545
$ 2,111
$ 74
Plant Hatch (nuclear) 50.1
1,297
585
81
Plant Wansley (coal) 53.5
1,046
308
12
Plant Scherer (coal)
Units 1 and 2 8.4
258
90
3
Unit 3 75.0
1,203
458
23
Rocky Mountain (pumped storage) 25.4
181
129
—

The ultimate outcome of these matters cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project cancellation, any of which could result in an impairment of one or both of Southern Company Gas' investments and could have a material impact on Southern Company's ~~proportionate share of~~and Southern Company Gas' financial statements. Southern Company Gas evaluated its ~~plant operating expenses is included in the corresponding operating expenses in the statements of income~~investments and ~~the Company is responsible for providing its own financing.~~

~~The Company also owns 45.7% of Plant Vogtle Units 3 and 4, which are currently under construction and had a CWIP balance of approximately $3.9 billion~~determined there was no impairment as of December 31, ~~2016.~~ 2019.

See ~~Note~~Notes 3 and 7 to the financial statements under ~~"Retail Regulatory Matters~~"Guarantees" and "Southern Company Gas – ~~Nuclear Construction"~~Equity Method Investments," respectively, for additional ~~information.~~information on these pipeline projects.

~~5. INCOME TAXES~~Southern Power's Power Sales Agreements

General

Natural Gas

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

from Southern Power resources not dedicated to serve unit or block sales. Southern Power has rights to purchase power provided by the requirements customers' resources when economically viable.

Solar and Wind

Income Tax Matters

Consolidated Income Taxes

On behalf of the ~~Company,~~Registrants, Southern Company files a consolidated federal income tax return and various ~~combined and separate~~ state income tax ~~returns.~~returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.

~~Table~~The impact of ~~ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~Current and Deferred Income Taxes~~

~~Details of income~~certain tax ~~provisions are as follows:~~

2016 2015 2014
(in millions)
Federal –
Current $ 391
$ 515
$ 295
Deferred 319
176
366
710
691
661
State –
Current 6
81
82
Deferred 64
(3 ) (14 )
70
78
68
Total $ 780
$ 769
$ 729

The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:

2016 2015
(in millions)
Deferred tax liabilities –
Accelerated depreciation $ 5,266
$ 4,909
Property basis differences 957
1,003
Employee benefit obligations 428
310
Premium on reacquired debt 56
61
Regulatory assets –
Storm damage reserves 83
37
Employee benefit obligations 546
528
Asset retirement obligations 726
545
Retired assets 55
58
Asset retirement obligations 182
161
Other 83
92
Total 8,382
7,704
Deferred tax assets –
Federal effect of state deferred taxes 173
150
Employee benefit obligations 661
642
Other property basis differences 105
88
Other deferred costs 100
83
State investment tax credit carryforward 201
216
Federal tax credit carryforward 84
3
Unbilled fuel revenue 47
47
Regulatory liabilities associated with asset retirement obligations 33
60
Asset retirement obligations 908
706
Other 70
82
Total 2,382
2,077
Accumulated deferred income taxes $ 6,000
$ 5,627

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~The application of bonus depreciation provisions in current tax law significantly increased deferred tax liabilities related to accelerated depreciation in 2016 and 2015.~~

At December 31, 2016, tax-related regulatory assets to be recovered from customers were $681 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years and deferred taxes previously recognizedevents at ~~rates lower than the current enacted tax law.~~

At December 31, 2016, tax-related regulatory liabilities to be credited to customers were $121 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law.

In accordance with regulatory requirements, utilized federal ITCs are deferred and amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $10 million in each of 2016, 2015, and 2014. State investment tax credits are recognized in the period in which the credits are generated and totaled $42 million in 2016, $33 million in 2015, and $34 million in 2014. At December 31, 2016, the Company had $83 million in federal ITC carryforwards that will expire by 2036 and $201 million in state ITC carryforwards that will expire between 2019 and 2027.

~~Effective Tax Rate~~

~~A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:~~

2016 2015 2014
Federal statutory rate 35.0 % 35.0 % 35.0 %
State income tax, net of federal deduction 2.1
2.5
2.2
Non-deductible book depreciation 0.8
1.2
1.3
AFUDC equity (0.8 ) (0.7 ) (0.8 )
Other (0.4 ) (0.4 ) (0.7 )
Effective income tax rate 36.7 % 37.6 % 37.0 %

On March 30, 2016, the FASB issued ASU 2016-09, which changes the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information.

~~Unrecognized Tax Benefits~~

~~The Company had no unrecognized tax benefits as of December 31, 2016 and no material changes in unrecognized tax benefits for any year presented.~~

~~The Company classifies interest on tax uncertainties as interest expense; however, the Company did not have any accrued interest or penalties for unrecognized tax benefits for any year presented.~~

It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

~~The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012.~~ Southern Company ~~has filed~~and/or its ~~2013 through 2015 federal income tax returns~~other subsidiaries can, and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~6. FINANCING~~

~~Securities Due Within One Year~~

~~A summary of scheduled maturities of long-term debt due within one year at December 31 was as follows:~~

2016 2015
(in millions)
Senior notes $ 450
$ 700
Pollution control revenue bonds —
4
Capital leases 10
8
Total $ 460
$ 712

~~Maturities through 2021 applicable to total long-term debt are as follows: $460 million in 2017; $762 million in 2018; $513 million in 2019; $57 million in 2020; and $376 million in 2021.~~

~~Senior Notes~~

In March 2016, the Company issued $325 million aggregate principal amount of Series 2016A 3.25% Senior Notes due April 1, 2026 and $325 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A 3.25% Senior Notes due April 1, 2026 is being allocated to eligible green expenditures, including financing of or investments in solar generating facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar or wind generating facilities. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250 million aggregate principal amount of the Company's Series 2013B Floating Rate Senior Notes due March 15, 2016, to repay a portion of the Company's short-term indebtedness, and for general corporate purposes, including the Company's continuous construction program.

At ~~December 31, 2016~~ ~~and~~ ~~2015~~, the Company had $6.2 billion and $6.3 billion of senior notes outstanding, respectively, which included senior notes due within one year. These senior notes are effectively subordinated to all secured debt of the Company, which aggregated $2.8 billion and $2.4 billion at December 31, 2016 and 2015, respectively. As of December 31, 2016, the Company's secured debt included borrowings of $2.6 billion guaranteed by the DOE and capital lease obligations of $169 million. As of December 31, 2015, the Company's secured debt included borrowings of $2.2 billion guaranteed by the DOE and capital lease obligations of $183 million. See Note 7 and "DOE Loan Guarantee Borrowings" herein for additional information.

~~Pollution Control Revenue Bonds~~

Pollution control revenue bond obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bond obligations outstanding at both ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~was $1.8 billion.~~

~~DOE Loan Guarantee Borrowings~~

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), the Company and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement) in February 2014, under which the DOE agreed to guarantee the obligations of the Company under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, the Company, and the FFB and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which the Company may make term loan borrowings through the FFB.

Proceeds of advances made under the FFB Credit Facility are used to reimburse the Company for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) ~~70%~~ ~~of Eligible Project Costs or (ii) approximately~~ ~~$3.46 billion~~.

All borrowings under the FFB Credit Facility are full recourse to the Company, and the Company is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. The Company's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) the Company's ~~45.7%~~ ~~undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~core) and (ii) the Company's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on the Company's~~does, affect each Registrant's ability to ~~grant liens on other property.~~

Advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterlyutilize certain tax credits. See "Tax Credits" and ~~principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.~~

~~In connection with its entry into the agreements with the DOE~~ACCOUNTING POLICIES – "Application of Critical Accounting Policies and ~~the FFB, the Company incurred issuance costs of approximately $66 million, which are being amortized over the life of the borrowings under the FFB Credit Facility.~~

In June and December 2016, the Company made borrowings under the FFB Credit Facility in an aggregate principal amount of $300 million and $125 million, respectively. The interest rate applicable to the $300 million principal amount is 2.571% and the interest rate applicable to the $125 million principal amount is 3.142%, both for an interest period that extends to the final maturity date of February 20, 2044.

At December 31, 2016 and 2015, the Company had $2.6 billion and $2.2 billion of borrowings outstanding under the FFB Credit Facility, respectively. Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.

Under the Loan Guarantee Agreement, the Company is subject to customary borrower affirmative and negative covenants and events of default. In addition, the Company is subject to project-related reporting requirements and other project-specific covenants and events of default.

In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and the Company will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of ~~five years~~ (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle 3 and 4 Agreement; (ii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by the Company if authorized by the Georgia PSC; and (iii) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or the Company's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. The Company also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Promissory Note, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.

In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume the Company's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of the Company's ownership interest in Plant Vogtle Units 3 and 4.

~~Capital Leases~~

Assets acquired under capital leases are recorded in the balance sheets as utility plant in service, and the related obligations are classified as long-term debt. At December 31, 2016 and 2015, the Company had a capital lease asset for its corporate headquarters building of $61 million, with accumulated depreciation at December 31, 2016 and 2015 of $33 million and $26 million, respectively. At ~~December 31, 2016~~ ~~and~~ ~~2015, the capitalized lease obligation was $28 million and~~ ~~$35 million~~, respectively, with an annual interest rate of 7.9% for both years. For ratemaking purposes, the Georgia PSC has allowed the lease payments in cost of service with no return on the capital lease asset. The difference between the depreciation and the lease payments allowed for ratemaking purposes is recovered as operating expenses as ordered by the Georgia PSC. The annual operating expense incurred for this capital lease was not material for any year presented.

At December 31, 2016 and 2015, the Company had capital lease assets related to two PPAs with Southern Power of $149 million, with accumulated amortization at December 31, 2016 and 2015 of $19 million and $10 million, respectively. At December 31, 2016 and 2015, the related capitalized lease obligations were $141 million and $148 million, respectively. The annual interest rates range from 10% to 11% for these two capital lease PPAs. For ratemaking purposes, the Georgia PSC has included the capital lease asset amortization in cost of service and the interest in the Company's cost of debt. See Note 1 under "Affiliate Transactions" and Note 7 under "Fuel and Purchased Power Agreements" for additional information.

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~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~Assets Subject to Lien~~

See "DOE Loan Guarantee Borrowings" above for information regarding certain borrowings of the Company that are secured by a first priority lien on (i) the Company's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) the Company's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4.

~~See "Capital Leases" above for information regarding certain assets held under capital leases.~~

~~Outstanding Classes of Capital Stock~~

The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company has shares of its Class A preferred stock, preference stock, and common stock outstanding. The Company's Class A preferred stock ranks senior to the Company's preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. The Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. The outstanding series of the Class A preferred stock is subject to redemption at the option of the Company at any time at a redemption price equal to 100% of the par value. In addition, on or after October 1, 2017, the Company may redeem the outstanding series of the preference stock at a redemption price equal to 100% of the par value. With respect to any redemption of the preference stock prior to October 1, 2017, the redemption price includes a make-whole premium based on the present value of the liquidation amount and future dividends through the first par redemption date.

~~Dividend Restrictions~~

~~The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.~~

~~Bank Credit Arrangements~~

~~At December 31, 2016, the Company had a $1.75 billion committed credit arrangement with banks, of which $1.73 billion was unused. This credit arrangement expires in 2020.~~

~~This bank credit arrangement requires payment of commitment fees based on the unused portion of the commitments. Commitment fees average less than~~ ¹/4 ~~of 1% for the Company.~~

This bank credit arrangement contains a covenant that limits the Company's debt levels to 65% of total capitalization, as defined in the agreement. For purposes of this definition, debt excludes certain hybrid securities. At December 31, 2016, the Company was in compliance with the debt limit covenant.

Subject to applicable market conditions, the Company expects to renew this bank credit arrangement, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitments thereunder.

A portion of the $1.73 billion unused credit with banks is allocated to provide liquidity support to the Company's pollution control revenue bonds and its commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2016 was $868 million. In addition, at December 31, 2016, the Company had $250 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.

The Company makes short-term borrowings primarily through a commercial paper program that has the liquidity support of the Company's committed bank credit arrangement described above. Commercial paper is included in notes payable in the balance sheets.

~~Details of commercial paper borrowings outstanding were as follows:~~

Commercial Paper at the End of the Period

Amount
Outstanding
Weighted Average Interest Rate
(in millions)
December 31, 2016 $ 392
1.1 %
December 31, 2015 $ 158
0.6 %

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~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~7. COMMITMENTS~~

~~Fuel and Purchased Power Agreements~~

To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2016, 2015, and 2014, the Company incurred fuel expense of $1.8 billion, $2.0 billion, and ~~$2.5 billion~~, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments.

The Company has commitments regarding a portion of a 5% interest in the original cost of Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the latter of the retirement of the plant or the latest stated maturity date of MEAG Power's bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. The energy cost is a function of each unit's variable operating costs. Portions of the capacity payments relate to costs in excess of MEAG Power's Plant Vogtle Units 1 and 2 allowed investment for ratemaking purposes. The present value of these portions at the time of the disallowance was written off. Generally, the cost of such capacity and energy is included in purchased power, non-affiliates in the statements of income. Capacity payments totaled $11 million, $10 million, and ~~$19 million~~ ~~in 2016, 2015, and 2014, respectively.~~

The Company has also entered into various long-term PPAs, some of which are accounted for as capital or operating leases. Total capacity expense under PPAs accounted for as operating leases was $217 million, $203 million, and ~~$167 million~~ ~~for 2016, 2015, and 2014, respectively. Estimated total long-term obligations at December 31, 2016 were as follows:~~

Affiliate Capital Leases Affiliate Operating Leases
Non-Affiliate
Operating
Leases^(c)

Vogtle
Units 1 and 2
Capacity
Payments
Total
(in millions)
2017 $ 22
$ 72
$ 123
$ 8
$ 225
2018 22
63
126
7
218
2019 23
64
127
6
220
2020 23
65
123
5
216
2021 24
66
124
5
219
2022 and thereafter 204
479
882
43
1,608
Total $ 318
$ 809
$ 1,505
$ 74
$ 2,706
Less: amounts representing executory costs^(a)
48

Net minimum lease payments 270

Less: amounts representing interest^(b)
128

Present value of net minimum lease payments $ 142


~~(a)~~	~~Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon)~~ a~~re estimated and included in total minimum lease payments.~~


~~(b)~~	~~Calculated using an adjusted incremental borrowing rate to reduce the present value of the net minimum lease payments to fair value.~~


~~(c)~~	A total of $197 million of biomass PPAs included under the non-affiliate operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation. Subsequent to December 31, 2016, the specified contract dates for commercial operation were extended from 2017 to 2019 and may change further as a result of regulatory action.

SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional electric operating companies and Southern Power. Under these agreements, each of the traditional electric operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional electric operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~Operating Leases~~

~~In addition to the PPA operating leases discussed above, the Company has other operating lease agreements with various terms and expiration dates. Total rent expense was $28 million for~~ ~~2016~~, ~~$29 million~~ ~~for~~ ~~2015, and~~ ~~$28 million~~ ~~for~~ ~~2014. The Company includes any step rents, fixed escalations, and lease concessions in its computation of minimum lease payments.~~

~~As of December 31, 2016, estimated minimum lease payments under operating leases were as follows:~~

Minimum Lease Payments
Railcars Other Total
(in millions)
2017 $ 12
$ 7
$ 19
2018 6
7
13
2019 3
6
9
2020 3
6
9
2021 2
6
8
2022 and thereafter 2
13
15
Total $ 28
$ 45
$ 73

Railcar minimum lease payments are disclosed at 100% of railcar lease obligations; however, a portion of these obligations is shared with the joint owners of Plants Scherer and Wansley. A majority of the rental expenses related to the railcar leases are recoverable through the fuel cost recovery clause as ordered by the Georgia PSC and the remaining portion is recovered through base rates.

In addition to the above rental commitments, the Company has obligations upon expiration of certain railcar leases with respect to the residual value of the leased property. These leases have terms expiring through 2024 with maximum obligations under these leases of $32 million. At the termination of the leases, the lessee may either renew the lease, exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company's payments under the residual value obligations.

~~Guarantees~~

Alabama Power has guaranteed the obligations of SEGCO for $25 million of pollution control revenue bonds issued in 2001, which mature in June 2019, and also $100 million of senior notes issued in 2013, which mature in December 2018. The Company has agreed to reimburse Alabama Power for the pro rata portion of such obligations corresponding to the Company's then proportionate ownership of SEGCO's stock if Alabama Power is called upon to make such payment under its guarantee. See Note 4 for additional information.

In addition, in 2013, the Company entered into an agreement that requires the Company to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years. The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2018. In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million.

~~As discussed earlier in this Note under "Operating Leases,~~Estimates" ~~the Company has entered into certain residual value guarantees related to railcar leases.~~

~~8. STOCK COMPENSATION~~

~~Stock-Based Compensation~~

Stock-based compensation primarily in the form of Southern Company performance share units may be granted through the Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. As of December 31, 2016, there were 990 current and former employees participating in the stock option and performance share unit programs.

~~Stock Options~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

or death of the employee. Options expire no later than 10 years after the grant date. All unvested stock options vest immediately upon a change in control where Southern Company is not the surviving corporation. Compensation expense is generally recognized on a straight-line basis over the three-year vesting period with the exception of employees that are retirement eligible at the grant date and employees that will become retirement eligible during the vesting period. Compensation expense in those instances is recognized at the grant date for employees that are retirement eligible and through the date of retirement eligibility for those employees that become retirement eligible during the vesting period. In 2015, Southern Company discontinued the granting of stock options.

~~The weighted average grant-date fair value of stock options granted during 2014 derived using the Black-Scholes stock option pricing model was $2.20.~~

The compensation cost related to the grant of Southern Company stock options to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. Compensation cost and related tax benefits recognized in the Company's financial statements were not material for any year presented. As of December 31, 2016, the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial.

~~The total intrinsic value of options exercised during the years ended~~ ~~December 31, 2016~~, ~~2015, and~~ ~~2014~~ was $18 million, $9 million, and $19 million, respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $7 million, $4 million, and $7 million for the years ended December 31, 2016, 2015, and 2014, respectively. Prior to the adoption of ASU 2016-09, the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2016, the aggregate intrinsic value for the options outstanding and options exercisable was $46 million and $41 million, respectively.

~~Performance Share Units~~

From 2010 through 2014, stock-based compensation granted to employees included performance share units in addition to stock options. Beginning in 2015, stock-based compensation consisted exclusively of performance share units. Performance share units granted to employees vest at the end of a three-year performance period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.

The performance goal for all performance share units issued from 2010 through 2014 was based on the total shareholder return (TSR) for Southern Company common stock during the three-year performance period as compared to a group of industry peers. For these performance share units, at the end of three years, active employees receive shares based on Southern Company's performance while retired employees receive a pro rata number of shares based on the actual months of service during the performance period prior to retirement. The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement.

Beginning in 2015, Southern Company issued two additional types of performance share units to employees in addition to the TSR-based awards. These included performance share units with performance goals based on cumulative earnings per share (EPS) over the performance period and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period. The EPS-based and ROE-based awards each represent 25% of total target grant date fair value of the performance share unit awards granted. The remaining 50% of the target grant date fair value consists of TSR-based awards. In contrast to the Monte Carlo simulation model used to determine the fair value of the TSR-based awards, the fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three-year performance period initially assuming a 100% payout at the end of the performance period. The TSR-based performance share units, along with the EPS-based and ROE-based awards, vest immediately upon the retirement of the employee. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period.

For the years ended December 31, 2016, 2015, and 2014, employees of the Company were granted performance share units of 261,434, 236,804, and 176,224, respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2016, 2015, and 2014, determined using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period, was $45.17, $46.41, and $37.54, respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2016 and 2015 was $48.84 and $47.78, respectively.

~~For the years ended~~ ~~December 31, 2016~~, ~~2015, and~~ ~~2014~~, total compensation cost for performance share units recognized in income was $15 million, $15 million, and $6 million, respectively, with the related tax benefit also recognized in income of $6 million, $6 million, and $2 million, respectively. The compensation cost related to the grant of Southern Company performance share units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2016, $4 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 22 months.

~~9. NUCLEAR INSURANCE~~

Under the Price-Anderson Amendments Act (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Hatch and Plant Vogtle Units 1 and 2. The Act provides funds up to $13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. The Company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company, based on its ownership and buyback interests in all licensed reactors, is $247 million per incident, but not more than an aggregate of $37 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than September 10, 2018. See Note 4 for additional information on joint ownership agreements.

The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, the Company has NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses in excess of the $1.5 billion primary coverage. In April 2014, NEIL introduced a new excess non-nuclear policy providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage.

NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases limits based on the projected full cost of replacement power, subject to ownership limitations, and has elected a 12-week deductible waiting period for each facility.

A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Vogtle Owners up to $2.75 billion for accidental property damage occurring during construction.

Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The maximum annual assessments for the Company as of December 31, 2016 under the NEIL policies would be $82 million.

Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by the Company and could have a material effect on the Company's financial condition and results of operations.

~~All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.~~

~~10. FAIR VALUE MEASUREMENTS~~

Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.

~~Level 1 consists of observable market data in an active market for identical assets or liabilities.~~

~~Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.~~

Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.

In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.

~~As of~~ ~~December 31, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:~~

Fair Value Measurements Using
Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs
As of December 31, 2016: (Level 1) (Level 2) (Level 3) Total
(in millions)
Assets:
Energy-related derivatives $ —
$ 44
$ —
$ 44
Interest rate derivatives —
2
—
2
Nuclear decommissioning trusts:^(*)

Domestic equity 204
1
—
205
Foreign equity —
121
—
121
U.S. Treasury and government agency securities —
71
—
71
Municipal bonds —
73
—
73
Corporate bonds —
164
—
164
Mortgage and asset backed securities —
164
—
164
Other 11
5
—
16
Total $ 215
$ 645
$ —
$ 860
Liabilities:
Energy-related derivatives $ —
$ 8
$ —
$ 8
Interest rate derivatives —
3
—
3
Total $ —
$ 11
$ —
$ 11


~~(*)~~	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~As of December 31, 2015, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:~~

Fair Value Measurements Using
Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs
As of December 31, 2015: (Level 1) (Level 2) (Level 3) Total
(in millions)
Assets:
Energy-related derivatives $ —
$ 2
$ —
$ 2
Interest rate derivatives —
5
—
5
Nuclear decommissioning trusts:^(*)

Domestic equity 182
1
—
183
Foreign equity —
113

—
113
U.S. Treasury and government agency securities —
125
—
125
Municipal bonds —
64
—
64
Corporate bonds —
143
—
143
Mortgage and asset backed securities —
127
—
127
Other 16
4
—
20
Cash equivalents 63
—
—
63
Total $ 261
$ 584
$ —
$ 845
Liabilities:
Energy-related derivatives $ —
$ 15
$ —
$ 15
Interest rate derivatives —
6
—
6
Total $ —
$ 21
$ —
$ 21


~~(*)~~	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.

~~Valuation Methodologies~~

The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 1 under "Nuclear Decommissioning" for additional information.

~~As of~~ ~~December 31, 2016~~ ~~and~~ ~~2015, other financial instruments for which the carrying amount did not equal fair value were as follows:~~

Carrying
Amount

Fair
Value
(in millions)
Long-term debt, including securities due within one year:
2016 $ 10,516
$ 11,034
2015 $ 10,145
$ 10,480

~~The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on current rates available to the Company.~~

~~11. DERIVATIVES~~

The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.

~~Energy-Related Derivatives~~

The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in energy-related commodity prices. The Company manages a fuel-hedging program through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. At December 31, 2016 and 2015, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Through December 31, 2015, the Company's fuel-hedging program had a time horizon up to 24 months. Effective January 1, 2016, the Georgia PSC approved changes to the Company's hedging program allowing it to use an array of derivative instruments within a 48-month time horizon.

~~Energy-related derivative contracts are accounted for under one of two methods:~~

~~Regulatory Hedges~~ – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging program, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery mechanism.

~~Not Designated~~ ~~– Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.~~

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

~~At December 31, 2016, the net volume of energy-related derivative contracts for natural gas positions totaled 155 million mmBtu, all of which expire by 2020, which is the longest hedge date.~~

In addition to the volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The expected volume of natural gas subject to such a feature is 3 million mmBtu for the Company.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~Interest Rate Derivatives~~

The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. At December 31, 2016, there were no cash flow hedges outstanding. Derivatives related to fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains and losses and the hedged items' fair value gains and losses attributable to interest rate risk are both recorded directly to earnings, providing an offset, with any differences representing ineffectiveness.

At ~~December 31, 2016, the following interest rate derivatives were outstanding:~~

Notional
Amount Interest
Rate
Received Weighted Average Interest
Rate Paid Hedge
Maturity
Date Fair Value
Gain (Loss)
December 31,
2016
(in millions) (in millions)
Fair Value Hedges of Existing Debt
$ 250
5.40% 3-month LIBOR + 4.02% June 2018 $ —
500
1.95% 3-month LIBOR + 0.76% December 2018 (2 )
200
4.25% 3-month LIBOR + 2.46% December 2019 1
Total $ 950
$ (1 )

~~The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the 12-month period ending~~ ~~December 31, 2017~~ ~~total $4 million. Deferred gains and losses related to interest rate derivative settlements of cash flow hedges are expected to be amortized into earnings through 2037.~~

~~Derivative Financial Statement Presentation and Amounts~~

The Company enters into energy-related and interest rate derivative contracts that may contain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. At December 31, 2016, fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties. At December 31, 2015, the fair value amounts of derivative instruments were presented gross on the balance sheets.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

At ~~December 31, 2016~~ ~~and 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:~~

2016 2015
Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities
(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities $ 30
$ 1
$ 2
$ 12
Other deferred charges and assets/Other deferred credits and liabilities 14
7
—
3
Total derivatives designated as hedging instruments for regulatory purposes $ 44
$ 8
$ 2
$ 15
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities $ 2
$ —
$ 5
$ —
Other deferred charges and assets/Other deferred credits and liabilities —
3
—
6
Total derivatives designated as hedging instruments in cash flow and fair value hedges $ 2
$ 3
$ 5
$ 6
Gross amounts recognized $ 46
$ 11
$ 7
$ 21
Gross amounts offset $ (8 ) $ (8 ) $ (6 ) $ (6 )
Net amounts recognized in the Balance Sheets^(*)
$ 38
$ 3
$ 1
$ 15


~~(*)~~	~~At December 31, 2015, the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet.~~

~~Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2016 and 2015.~~

At ~~December 31, 2016~~ ~~and~~ ~~2015, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows:~~

Unrealized Losses Unrealized Gains
Derivative Category Balance Sheet Location 2016 2015 Balance Sheet Location 2016 2015
(in millions) (in millions)
Energy-related derivatives:^(*)
Other regulatory assets, current $ —
$ (12 ) Other regulatory liabilities, current $ 29
$ 2
Other regulatory assets, deferred —
(3 ) Other deferred credits and liabilities 7
—
Total energy-related derivative gains (losses) $ —
$ (15 ) $ 36
$ 2


~~(*)~~	At December 31, 2016, the unrealized gains and losses for energy-related derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015, the unrealized gains and losses for energy-related derivative contracts subject to netting arrangements were presented gross on the balance sheet.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~For the years ended December 31, 2016, 2015, and 2014, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:~~

Derivatives in Cash Flow Hedging Relationships Gain (Loss) Recognized in OCI on Derivative (Effective Portion) Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Amount
Derivative Category 2016 2015 2014 Statements of Income Location 2016 2015 2014
(in millions) (in millions)
Interest rate derivatives $ —
$ (15 ) $ (8 ) Interest expense, net of amounts capitalized $ (4 ) $ (3 ) $ (3 )

For the years ended December 31, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on the statements of income were immaterial on a gross basis for the Company. Furthermore, the pre-tax effect of interest rate derivatives designated as fair value hedging instruments on the Company's statements of income were offset by changes to the carrying value of long-term debt. The gains and losses related to interest rate derivative settlements of fair value hedges are recorded directly to earnings.

There was no material ineffectiveness recorded in earnings for any period presented. The pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was immaterial for all years presented.

~~Contingent Features~~

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At ~~December 31, 2016, the Company's collateral posted with its derivative counterparties was immaterial.~~

At ~~December 31, 2016~~, the fair value of derivative liabilities with contingent features, including certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade because of joint and several liability features underlying these derivatives, was immaterial.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Georgia Power Company 2016 Annual Report~~

~~12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)~~

~~Summarized quarterly financial information for~~ ~~2016~~ ~~and~~ ~~2015~~ ~~is as follows:~~

Quarter Ended Operating Revenues Operating Income Net Income After Dividends on Preferred and Preference Stock
(in millions)
March 2016 $ 1,872
$ 509
$ 269
June 2016 2,051
656
349
September 2016 2,698
1,054
599
December 2016 1,762
258
113

March 2015 $ 1,978
$ 454
$ 236
June 2015 2,016
554
277
September 2015 2,691
964
551
December 2015 1,641
376
196

In accordance with the adoption of ASU 2016-09 (see Note 1 under "Recently Issued Accounting Standards"), previously reported amounts for income tax expense were reduced by $1 million in the third quarter 2016, $2 million in the second quarter 2016, and $1 million in the first quarter 2016.

~~The Company's business is influenced by seasonal weather conditions.~~

~~Table of ContentsIndex to Financial Statements~~

~~SELECTED FINANCIAL AND OPERATING DATA 2012-2016~~

~~Georgia Power Company 2016 Annual Report~~

2016
2015
2014
2013
2012
Operating Revenues (in millions) $ 8,383
$ 8,326
$ 8,988
$ 8,274
$ 7,998
Net Income After Dividends
on Preferred and Preference Stock (in millions)
$ 1,330
$ 1,260
$ 1,225
$ 1,174
$ 1,168
Cash Dividends on Common Stock (in millions) $ 1,305
$ 1,034
$ 954
$ 907
$ 983
Return on Average Common Equity (percent) 12.05
11.92
12.24
12.45
12.76
Total Assets (in millions)^(a)(b)
$ 34,835
$ 32,865
$ 30,872
$ 28,776
$ 28,618
Gross Property Additions (in millions) $ 2,314
$ 2,332
$ 2,146
$ 1,906
$ 1,838
Capitalization (in millions):
Common stock equity $ 11,356
$ 10,719
$ 10,421
$ 9,591
$ 9,273
Preferred and preference stock 266
266
266
266
266
Long-term debt^(a)
10,225
9,616
8,563
8,571
7,928
Total (excluding amounts due within one year) $ 21,847
$ 20,601
$ 19,250
$ 18,428
$ 17,467
Capitalization Ratios (percent):
Common stock equity 52.0
52.0
54.1
52.0
53.1
Preferred and preference stock 1.2
1.3
1.4
1.4
1.5
Long-term debt^(a)
46.8
46.7
44.5
46.6
45.4
Total (excluding amounts due within one year) 100.0
100.0
100.0
100.0
100.0
Customers (year-end):
Residential 2,155,945
2,127,658
2,102,673
2,080,358
2,062,040
Commercial^(c)
305,488
302,891
300,186
297,493
295,523
Industrial^(c)
10,537
10,429
10,192
10,063
10,017
Other 9,585
9,261
9,003
8,623
7,724
Total 2,481,555
2,450,239
2,422,054
2,396,537
2,375,304
Employees (year-end) 7,527
7,989
7,909
7,886
8,094



~~(a)~~	A reclassification of debt issuance costs from Total Assets to Long-term debt of $124 million, $62 million, and $67 million is reflected for years 2014, 2013, and 2012, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively.
~~(b)~~	A reclassification of deferred tax assets from Total Assets of $34 million, $68 million, and $117 million is reflected for years 2014, 2013, and 2012, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively.
~~(c)~~	A reclassification of customers from commercial to industrial is reflected for years 2012-2015 to be consistent with the rate structure approved by the Georgia PSC. The impact to operating revenues, kilowatt-hour sales, and average revenue per kilowatt-hour by class is not material.

~~Table of ContentsIndex to Financial Statements~~

~~SELECTED FINANCIAL AND OPERATING DATA 2012-2016 (continued)~~

~~Georgia Power Company 2016 Annual Report~~

2016
2015
2014
2013
2012
Operating Revenues (in millions):
Residential $ 3,318
$ 3,240
$ 3,350
$ 3,058
$ 2,986
Commercial 3,077
3,094
3,271
3,077
2,965
Industrial 1,291
1,305
1,525
1,391
1,322
Other 86
88
94
94
89
Total retail 7,772
7,727
8,240
7,620
7,362
Wholesale — non-affiliates 175
215
335
281
281
Wholesale — affiliates 42
20
42
20
20
Total revenues from sales of electricity 7,989
7,962
8,617
7,921
7,663
Other revenues 394
364
371
353
335
Total $ 8,383
$ 8,326
$ 8,988
$ 8,274
$ 7,998
Kilowatt-Hour Sales (in millions):
Residential 27,585
26,649
27,132
25,479
25,742
Commercial 32,932
32,719
32,426
31,984
32,270
Industrial 23,746
23,805
23,549
23,087
23,089
Other 610
632
633
630
641
Total retail 84,873
83,805
83,740
81,180
81,742
Wholesale — non-affiliates 3,415
3,501
4,323
3,029
2,934
Wholesale — affiliates 1,398
552
1,117
496
600
Total 89,686
87,858
89,180
84,705
85,276
Average Revenue Per Kilowatt-Hour (cents):
Residential 12.03
12.16
12.35
12.00
11.60
Commercial 9.34
9.46
10.09
9.62
9.19
Industrial 5.44
5.48
6.48
6.03
5.73
Total retail 9.16
9.22
9.84
9.39
9.01
Wholesale 4.51
5.80
6.93
8.54
8.52
Total sales 8.91
9.06
9.66
9.35
8.99
Residential Average Annual
Kilowatt-Hour Use Per Customer
12,864
12,582
12,969
12,293
12,509
Residential Average Annual
Revenue Per Customer
$ 1,557
$ 1,529
$ 1,605
$ 1,475
$ 1,451
Plant Nameplate Capacity
Ratings (year-end) (megawatts)
15,274
15,455
17,593
17,586
17,984
Maximum Peak-Hour Demand (megawatts):
Winter 14,527
15,735
16,308
12,767
14,104
Summer 16,244
16,104
15,777
15,228
16,440
Annual Load Factor (percent) 61.9
61.9
61.2
63.5
59.1
Plant Availability (percent):
Fossil-steam 87.4
85.6
86.3
87.1
90.3
Nuclear 95.6
94.1
90.8
91.8
94.1
Source of Energy Supply (percent):
Coal 26.4
24.5
30.9
26.4
26.6
Nuclear 17.6
17.6
16.7
17.7
18.3
Hydro 1.1
1.6
1.3
2.0
0.7
Oil and gas 28.2
28.3
26.3
29.6
22.0
Purchased power —
From non-affiliates 6.7
5.0
3.8
3.3
6.8
From affiliates 20.0
23.0
21.0
21.0
25.6
Total 100.0
100.0
100.0
100.0
100.0

~~Table of ContentsIndex to Financial Statements~~

~~GULF POWER COMPANY~~

~~FINANCIAL SECTION~~

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING~~

~~Gulf Power Company 2016 Annual Report~~

The management of Gulf Power Company (the Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

~~Under management's supervision, an evaluation of the design and effectiveness of the Company's internal control over financial reporting was conducted based on the framework in~~ ~~Internal Control—Integrated Framework (2013)~~ issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2016.

~~/s/ S. W. Connally, Jr.~~

~~S. W. Connally, Jr.~~

~~Chairman, President, and Chief Executive Officer~~

~~/s/ Xia Liu~~

~~Xia Liu~~

~~Vice President and Chief Financial Officer~~

~~February 21, 2017~~

~~Table of ContentsIndex to Financial Statements~~

~~REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM~~

~~To the Board of Directors of~~

~~Gulf Power Company~~

We have audited the accompanying balance sheets and statements of capitalization of Gulf Power Company (the Company) (a wholly owned subsidiary of The Southern Company) as of December 31, 2016 and 2015, and the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements (pages II-342 to II-379) present fairly, in all material respects, the financial position of Gulf Power Company as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

~~/s/ Deloitte & Touche LLP~~

~~Atlanta, Georgia~~

~~February 21, 2017~~

~~Table of ContentsIndex to Financial Statements~~

~~DEFINITIONS~~



~~Term~~	~~Meaning~~
~~AFUDC~~	~~Allowance for funds used during construction~~
~~Alabama Power~~	~~Alabama Power Company~~
~~ARO~~	~~Asset retirement obligation~~
~~ASC~~	~~Accounting Standards Codification~~
~~ASU~~	~~Accounting Standards Update~~
~~CCR~~	~~Coal combustion residuals~~
~~Clean Air Act~~	~~Clean Air Act Amendments of 1990~~
CO₂	~~Carbon dioxide~~
~~EPA~~	~~U.S. Environmental Protection Agency~~
~~FASB~~	~~Financial Accounting Standards Board~~
~~FERC~~	~~Federal Energy Regulatory Commission~~
~~GAAP~~	~~U.S. generally accepted accounting principles~~
~~Georgia Power~~	~~Georgia Power Company~~
~~IRS~~	~~Internal Revenue Service~~
~~ITC~~	~~Investment tax credit~~
~~KWH~~	~~Kilowatt-hour~~
~~Mississippi Power~~	~~Mississippi Power Company~~
~~mmBtu~~	~~Million British thermal units~~
~~Moody's~~	~~Moody's Investors Service, Inc.~~
MW	~~Megawatt~~
~~OCI~~	~~Other comprehensive income~~
~~power pool~~	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
~~PPA~~	~~Power purchase agreement~~
~~PSC~~	~~Public Service Commission~~
~~ROE~~	~~Return on equity~~
~~S&P~~	~~S&P Global Ratings, a division of S&P Global Inc.~~
~~scrubber~~	~~Flue gas desulfurization system~~
~~SCS~~	~~Southern Company Services, Inc. (the Southern Company system service company)~~
~~SEC~~	~~U.S. Securities and Exchange Commission~~
~~Southern Company~~	~~The Southern Company~~
~~Southern Company Gas~~	~~Southern Company Gas (formerly known as AGL Resources Inc.) and its subsidiaries~~
~~Southern Company system~~	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), Southern Electric Generating Company, Southern Nuclear, SCS, Southern LINC, PowerSecure, Inc. (as of May 9, 2016), and other subsidiaries
~~Southern LINC~~	~~Southern Communications Services, Inc.~~
~~Southern Nuclear~~	~~Southern Nuclear Operating Company, Inc.~~
~~Southern Power~~	~~Southern Power Company and its subsidiaries~~
~~traditional electric operating companies~~	~~Alabama Power, Georgia Power, Gulf Power Company, and Mississippi Power~~

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Gulf Power Company 2016 Annual Report~~

~~OVERVIEW~~

~~Business Activities~~

Gulf Power Company (the Company) operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located in northwest Florida and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of the Company's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, restoration following major storms, fuel, and capital expenditures. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future. Through 2015, long-term non-affiliate capacity sales from the Company's ownership of Plant Scherer Unit 3 (205 MWs) provided the majority of the Company's wholesale earnings. Contract expirations at the end of 2015 and the end of May 2016 related to Plant Scherer Unit 3 wholesale sales had a material negative impact on the Company's earnings in 2016. Remaining contract sales from Plant Scherer Unit 3 cover approximately 24% of the Company's ownership of the unit through 2019.

In 2013, the Florida PSC approved the settlement agreement (2013 Rate Case Settlement Agreement) among the Company and all of the intervenors to the Company's retail base rate case. Under the terms of the 2013 Rate Case Settlement Agreement, the Company (1) increased base rates approximately $35 million and $20 million annually effective January 2014 and 2015, respectively; (2) continued its authorized retail ROE midpoint (10.25%) and range (9.25% – 11.25%); (3) may reduce depreciation expense and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million between January 2014 and June 2017, of which $28.5 million had been recorded as of December 31, 2016; and (4) accrued a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 through January 1, 2017.

On October 12, 2016, the Company filed a petition (2016 Rate Case) with the Florida PSC requesting an annual increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. The requested increase includes recovery of the portion of Plant Scherer Unit 3 that has been rededicated to serving retail customers following the contract expirations discussed above. If retail recovery of Plant Scherer Unit 3 is not approved by the Florida PSC in the 2016 Rate Case, the Company may consider an asset sale. The current book value of the Company's ownership of Plant Scherer Unit 3 could exceed market value which could result in a material loss. The Florida PSC is expected to make a decision on the 2016 Rate Case in the second quarter 2017. The Company has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017.

On November 2, 2016, the Florida PSC approved the Company's 2017 annual cost recovery clause factors. The fuel and environmental factors include certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" herein for additional information.

The Company continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. The Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate the Company's results and generally targets the top quartile of these surveys in measuring performance.

~~See RESULTS OF OPERATIONS herein for information on the Company's financial performance.~~

~~Earnings~~

The Company's 2016 net income after dividends on preference stock was $131 million, representing a $17 million, or 11.5%, decrease over the previous year. The decrease was primarily due to lower wholesale revenues and higher depreciation, partially offset by higher retail revenues and lower operations and maintenance expenses as compared to the corresponding period in 2015.

In 2015, the net income after dividends on preference stock was $148 million, representing an $8 million, or 5.7%, increase over the previous year. The increase was primarily due to an increase in retail base revenues effective January 1, 2015 and a reduction in depreciation, both as authorized in the 2013 Rate Case Settlement Agreement, partially offset by higher operations and maintenance expenses as compared to the corresponding period in 2014.

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~RESULTS OF OPERATIONS~~

~~A condensed statement of income follows:~~

Amount
Increase (Decrease)
from Prior Year
2016 2016 2015
(in millions)
Operating revenues $ 1,485
$ 2
$ (107 )
Fuel 432
(13 ) (160 )
Purchased power 142
7
28
Other operations and maintenance 336
(18 ) 13
Depreciation and amortization 172
31
(4 )
Taxes other than income taxes 120
2
7
Total operating expenses 1,202
9
(116 )
Operating income 283
(7 ) 9
Total other income and (expense) (52 ) (11 ) 3
Income taxes 91
(1 ) 4
Net income 140
(17 ) 8
Dividends on preference stock 9
—
—
Net income after dividends on preference stock $ 131
$ (17 ) $ 8

~~Operating Revenues~~

~~Operating revenues for 2016 were $1.49 billion, reflecting an increase of $2 million from 2015. Details of operating revenues were as follows:~~

Amount
2016 2015
(in millions)
Retail — prior year $ 1,249
$ 1,267
Estimated change resulting from –
Rates and pricing 30
22
Sales growth —
—
Weather 1
3
Fuel and other cost recovery 1
(43 )
Retail — current year 1,281
1,249
Wholesale revenues –
Non-affiliates 61
107
Affiliates 75
58
Total wholesale revenues 136
165
Other operating revenues 68
69
Total operating revenues $ 1,485
$ 1,483
Percent change N/M
(6.7 )%

~~N/M - Not meaningful~~

In 2016, retail revenues increased $32 million, or 2.6%, when compared to 2015 primarily as a result of an increase in the Company's environmental cost recovery clause revenues, partially offset by a decrease in the energy conservation clause revenues. In 2015, retail revenues decreased $18 million, or 1.4%, when compared to 2014 primarily as a result of lower fuel cost recovery revenues partially offset by higher revenues associated with purchased power capacity costs and higher revenues resulting from an increase in retail base rates, as authorized in the 2013 Rate Case Settlement Agreement, as well as an increase in

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

the environmental and energy conservation cost recovery clause rates, both effective in January 2015. See "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales growth and weather.

In 2016, revenues associated with changes in rates and pricing increased primarily due to an increase in the environmental cost recovery clause as a result of additional rate base investment related to environmental compliance equipment placed in service at the end of 2015 as well as portions of the Company's ownership in Plant Scherer Unit 3 that were rededicated to retail service in 2016. In 2015, revenues associated with changes in rates and pricing included higher revenues due to increases in retail base rates and the Company's environmental and energy conservation cost recovery clauses. Annually, the Company petitions the Florida PSC for recovery of projected environmental and energy conservation costs, including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions include related expenses and a return on average net investment.

Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. Annually, the Company petitions the Florida PSC for recovery of projected fuel and purchased power costs, including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions generally equal the related expenses and have no material effect on earnings.

See Note 1 to the financial statements under "Revenues" and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information regarding the Company's retail base rate case and cost recovery clauses, including the Company's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.

~~Wholesale revenues from power sales to non-affiliated utilities were as follows:~~

2016 2015 2014
(in millions)
Capacity and other $ 30
$ 67
$ 65
Energy 31
40
64
Total non-affiliated $ 61
$ 107
$ 129

Wholesale revenues from sales to non-affiliates consist of long-term sales agreements to other utilities in Florida and Georgia and short-term opportunity sales. Capacity revenues from long-term sales agreements represent the greatest contribution to net income. The energy is generally sold at variable cost. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Company's variable cost of energy. Wholesale energy revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of the Company's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. See FUTURE EARNINGS POTENTIAL – "General" for additional information regarding the expiration of long-term sales agreements for Plant Scherer Unit 3, which will materially impact future wholesale earnings.

In 2016, wholesale revenues from sales to non-affiliates decreased $46 million, or 43.0%, as compared to the prior year primarily due to a 55.3% decrease in capacity revenues resulting from the expiration of Plant Scherer Unit 3 long-term sales agreements at the end of 2015 and the end of May 2016. In 2015, wholesale revenues from sales to non-affiliates decreased $22 million, or 17.1%, as compared to the prior year primarily due to a 37.7% decrease in KWH sales resulting from lower sales under the Plant Scherer Unit 3 long-term sales agreements due to a planned outage and lower natural gas prices that led to increased self-generation from customer-owned units.

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. These transactions do not have a significant impact on earnings since the revenue related to these energy sales generally offsets the cost of energy sold. In 2016, wholesale revenues from sales to affiliates increased $17 million, or 29.3%, as compared to the prior year primarily due to a 46.1% increase in KWH sales to affiliates due to lower planned unit outages for the Company's generation resources and a 7.9% increase in the price of energy sold to affiliates due to more sales during peak load hours. In 2015, wholesale revenues from sales to affiliates decreased $72 million, or 55.4%, as compared to the prior year primarily due to a 23.5% decrease in the price of energy sold to affiliates due to lower power pool interchange rates resulting from lower natural gas prices and a 42.0% decrease in KWH sales that resulted from the availability of lower-cost generation alternatives.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

In 2016, other operating revenues decreased by an immaterial amount compared to 2015. In 2015, other operating revenues increased $5 million, or 7.8%, as compared to the prior year primarily due to a $2 million increase in franchise fees and a $2 million increase in revenues from other energy services. Franchise fees have no impact on net income. Revenues from other energy services did not have a material effect on net income since they were generally offset by associated expenses.

~~Energy Sales~~

~~Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2016 and the percent change from the prior year were as follows:~~

Total
KWHs

Total KWH
Percent Change

Weather-Adjusted
Percent Change
2016 2016 2015 2016 2015
(in millions)

Residential 5,358
(0.1 )% — % (0.2 )% (1.0 )%
Commercial 3,869
(0.7 ) 1.6
(1.5 ) 0.3
Industrial 1,830
1.8
(2.8 ) 1.8
(2.8 )
Other 25
(0.8 ) (0.1 ) (0.8 ) (0.1 )
Total retail 11,082
—
0.1
(0.3 )% (0.8 )%
Wholesale
Non-affiliates 751
(27.8 ) (37.7 )
Affiliates 2,784
46.1
(42.0 )
Total wholesale 3,535
20.0
(40.5 )
Total energy sales 14,617
4.2 % (12.5 )%

~~Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers.~~

Residential KWH sales decreased in 2016 compared to 2015 due to declining use per customer primarily resulting from energy efficiency improvements, partially offset by customer growth and warmer weather during the third quarter. Residential KWH sales increased minimally in 2015 compared to 2014 due to customer growth and warmer weather in the second and third quarters of 2015, mostly offset by a decline in use per customer, primarily resulting from efficiency improvements.

Commercial KWH sales decreased in 2016 compared to 2015 due to declining use per customer, primarily resulting from energy efficiency improvements, partially offset by customer growth and warmer weather during the third quarter. Commercial KWH sales increased in 2015 compared to 2014 due to customer growth and warmer weather in the second and third quarters of 2015, partially offset by a decline in use per customer, primarily resulting from efficiency improvements.

Industrial KWH sales increased in 2016 compared to 2015 primarily due to decreased customer co-generation, partially offset by changes in customers' operations. Industrial KWH sales decreased in 2015 compared to 2014 primarily due to increased customer co-generation as a result of lower natural gas prices, partially offset by increases due to changes in customers' operations.

~~See "Operating Revenues" above for a discussion of significant changes in wholesale sales to non-affiliates and affiliated companies.~~

~~Fuel and Purchased Power Expenses~~

Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Details of the Company's generation and purchased power were as follows:~~

2016 2015 2014
Total generation (in millions of KWHs)
8,259
8,629
11,109
Total purchased power (in millions of KWHs)
6,973
5,976
5,547
Sources of generation (percent) –

Coal 57
57
67
Gas 43
43
33
Cost of fuel, generated (in cents per net KWH) –

Coal 3.68
3.88
4.03
Gas 4.17
4.22
3.93
Average cost of fuel, generated (in cents per net KWH)
3.89
4.03
3.99
Average cost of purchased power (in cents per net KWH)^(*)
3.63
3.89
4.83

~~(*)Average cost of purchased power includes fuel purchased by the Company for tolling agreements where power is generated by the provider.~~

In 2016, total fuel and purchased power expenses were $574 million, a decrease of $6 million, or 1.0%, from the prior year costs. The decrease was primarily the result of a $30 million decrease due to a lower average cost of fuel and purchased power, largely offset by a $24 million increase due to a higher volume of KWHs generated and purchased.

In 2015, total fuel and purchased power expenses were $580 million, a decrease of $132 million, or 18.5%, from the prior year costs. The decrease was primarily the result of a $79 million decrease due to a lower volume of KWHs generated and purchased and a $53 million decrease due to a lower average cost of fuel and purchased power.

Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through the Company's fuel and purchased power capacity cost recovery clauses and long-term wholesale contracts. See Note 3 to the financial statements under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" for additional information.

~~Fuel~~

Fuel expense was $432 million in 2016, a decrease of $13 million, or 2.9%, from the prior year costs. The decrease was primarily due to a 3.5% decrease in the average cost of fuel due to lower coal and natural gas prices and a 4.3% lower volume of KWHs generated due to an increase in KWHs purchased from lower-cost gas-fired PPA resources. In 2015, fuel expense was $445 million, a decrease of $160 million, or 26.4%, from the prior year costs. The decrease was primarily due to a 22.3% lower volume of KWHs generated due to the availability of lower-cost generation alternatives, partially offset by a 1.0% increase in the average cost of fuel due to higher natural gas prices per KWH generated.

~~Purchased Power~~ – ~~Non-Affiliates~~

Purchased power expense from non-affiliates was $126 million in 2016, an increase of $26 million, or 26.0%, from the prior year. The increase was primarily due to a 41.2% increase in the volume of KWHs purchased due to an increase in energy purchased from gas-fired PPA resources, partially offset by a 14.9% decrease in the average cost per KWH purchased, both due to lower energy costs from gas-fired resources. In 2015, purchased power expense from non-affiliates was $100 million, an increase of $18 million, or 22.0%, from the prior year. The increase was primarily due to a $26 million increase in capacity costs associated with a scheduled price increase for an existing PPA, partially offset by the expiration of another PPA, an 11.9% decrease in the average cost per KWH purchased due to lower market prices for fuel, and a 7.8% decrease in the volume of KWHs purchased due to the availability of lower-cost generation alternatives.

Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.

~~Purchased Power – Affiliates~~

Purchased power expense from affiliates was $16 million in 2016, a decrease of $19 million, or 54.3%, from the prior year. The decrease was primarily due to a 53.9% decrease in the volume of KWHs purchased primarily due to increased supply from the Company's fossil and wind resources, partially offset by a 0.4% increase in the average cost per KWH purchased from power pool resources. In 2015, purchased power expense from affiliates was $35 million, an increase of $10 million, or 40.0%, from the prior

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

year. The increase was primarily due to a 108.9% increase in the volume of KWHs purchased primarily due to the availability of lower-cost generation alternatives available from the power pool, partially offset by a 34.2% decrease in the average cost per KWH purchased due to lower power pool interchange rates.

Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.

~~Other Operations and Maintenance Expenses~~

In 2016, other operations and maintenance expenses decreased $18 million, or 5.1%, compared to the prior year primarily due to decreases of $7 million in marketing incentive programs and $6 million in routine and planned maintenance expenses at generation facilities. Also contributing to the decrease was $4 million in rate case expense amortization recorded in 2015 and a $3 million reduction in employee compensation and benefits expenses including pension costs. In 2015, other operations and maintenance expenses increased $13 million, or 3.8%, compared to the prior year primarily due to increases of $6 million in employee compensation and benefits expenses including pension costs, $3 million in rate case expense amortization, and $2 million in energy service contracts.

Expenses from marketing incentive programs and energy services did not have a significant impact on earnings since they were generally offset by associated revenues. Rate case expenses were amortized as authorized in the 2013 Rate Case Settlement Agreement. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" herein and Note 210 to the financial statements for additional ~~information related~~information.

Federal Tax Reform Legislation

~~Depreciation~~existing renewable energy incentives, and ~~Amortization~~

~~Depreciation and amortization increased $31 million, or 22.0%, in 2016 compared~~repealed the corporate alternative minimum tax. In addition, under the Tax Reform Legislation, NOLs generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the ~~prior~~subsequent tax year. The ~~increase was primarily due to a~~projected reduction ~~in depreciation~~ of ~~$20.1 million recorded in 2015, as authorized in~~Southern Company's consolidated income tax liability resulting from the ~~2013 Rate Case Settlement Agreement,~~tax rate reduction also delays the expected utilization of existing tax credit carryforwards. See "Consolidated Income Taxes" herein and an increase of $9 million primarily attributable to property additions to utility plant. In 2015, depreciation and amortization decreased $4 million, or 2.8%, compared to the prior year. As authorized in the 2013 Rate Case Settlement Agreement, the Company recorded $11.7 million more of a reduction in depreciation in 2015 than in 2014. This decrease was partially offset by an increase of $8 million primarily attributable to property additions at transmission and distribution facilities. See Note 310 to the financial statements ~~under "Retail Regulatory Matters – Retail Base Rate Cases"~~ for ~~additional information.~~

~~Taxes Other Than Income Taxes~~

~~Taxes other than~~information on Southern Company's joint consolidated income taxes increased $2 million, or 1.7%, in 2016 compared to the prior year primarily due to increases of $2 million in property taxes. In 2015, taxes other than income taxes increased $7 million, or 6.3%, compared to the prior year primarily due to increases of $3 million in property taxes, $2 million in franchise fees, and $2 million in gross receipts taxes. Gross receipts taxes and franchise fees are based on billed revenues and have no impact on net income. These taxes are collected from customers and remitted to governmental agencies.

~~Total Other Income and (Expense)~~

In 2016, total other income and (expense) decreased $11 million, or 26.8%, compared to the prior year primarily due to a decrease of $13 million in AFUDC equity related to environmental control projects at generating facilities and transmission projects placed in service in 2015, partially offset by a $2 million decrease in interest expense, net of amounts capitalized, primarily due to the redemption of debt. In 2015, total other income and (expense) increased $3 million, or 6.8%, primarily due to $6 million in deferred returns on transmission projects, which reduced interest expense and were recorded as a regulatory asset, as authorized in the 2013 Rate Case Settlement Agreement. This decrease was partially offset by a $2 million net increase in interest expense related to long-term debt resulting from the issuance of senior notes in 2014. See Note 1 to the financial statements under "Allowance for Funds Used During Construction" for additional information.

~~Effects of Inflation~~

The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years.tax allocation agreement.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

~~Gulf Power~~Southern Company ~~2016~~and Subsidiary Companies 2019 Annual Report

~~FUTURE EARNINGS POTENTIAL~~

~~General~~

The Company operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located in northwest Florida and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Florida PSC under cost-based regulatory principles. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Utility Regulation" herein and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information about regulatory matters.

The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's business of selling electricity. These factors include the Company's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years, and the outcome of the 2016 Rate Case. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies due to changes in the minimum allowable equipment efficiencies along with the continuation of changes in customer behavior. Earnings are subject to a variety of other factors. These factors include weather, competition, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on the Company's financial statements.

Through 2015, long-term non-affiliate capacity sales from the Company's ownership of Plant Scherer Unit 3 provided the majority of the Company's wholesale earnings. Contract expirations at the end of 2015 and the end of May 2016 related to Plant Scherer Unit 3 wholesale sales had a material negative impact on the Company's earnings in 2016. Remaining contract sales from Plant Scherer Unit 3 cover approximately 24% of the Company's ownership of the unit through 2019. The Company has requested recovery through retail rates for the portion of Plant Scherer Unit 3 that has been rededicated to serving retail customers. Therefore, the retail recoverability of these costs will be decided in the 2016 Rate Case. If retail recovery of Plant Scherer Unit 3 is not approved by the Florida PSC in the 2016 Rate Case, the Company may consider an asset sale. The current book value of the Company's ownership of Plant Scherer Unit 3 could exceed market value which could result in a material loss. See Note 3 to the financial statements under "Retail Regulatory Matters – Retail Base Rate Cases" for additional information.

~~Environmental Matters~~

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in retail rates or through long-term wholesale agreements on a timely basis or through market-based contracts. The State of Florida has statutory provisions that allow a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. The Company's current long-term wholesale agreements contain provisions that permit charging the customer with costs incurred as a result of changes in environmental laws and regulations. The full impact of any such legislative or regulatory changes cannot be determined at this time. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates or long-term wholesale agreements could contribute to reduced demand for electricity as well as impact the cost competitiveness of wholesale capacity, which could negatively affect results of operations, cash flows, and financial condition. See "Other Matters" herein and Note 3 to the financial statements under "Environmental Matters" and "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" for additional information, including a discussion on the State of Florida's statutory provisions on environmental cost recovery.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Environmental Statutes and Regulations~~

~~General~~

The Company's operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; the Migratory Bird Treaty Act; the Bald and Golden Eagle Protection Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2016, the Company had invested approximately $1.9 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of approximately $28 million, $116 million, and $227 million for 2016, 2015, and 2014, respectively. The Company expects that capital expenditures to comply with environmental statutes and regulations will total approximately $245 million from 2017 through 2021, with annual totals of approximately $33 million, $52 million, $57 million, $55 million, and $48 million for 2017, 2018, 2019, 2020, and 2021, respectively. These estimated expenditures do not include any potential capital expenditures that may arise from the EPA's final rules and guidelines or future state plans that would limit CO₂ emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. The Company also anticipates costs associated with ash pond closure and ground water monitoring under the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) and the closure of an ash pond at Plant Scholz, which are reflected in the Company's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Cost of Removal" for additional information.

The Company's ultimate environmental compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations, including the environmental regulations described below; the time periods over which compliance with regulations is required; individual state implementation of regulations, as applicable; the outcome of any legal challenges to the environmental rules; any additional rulemaking activities in response to legal challenges and court decisions; the cost, availability, and existing inventory of emissions allowances; the impact of future changes in generation and emissions-related technology; the Company's fuel mix; and environmental remediation requirements. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time.

~~Air Quality~~

~~Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company.~~

The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone National Ambient Air Quality Standard (NAAQS). In 2008, the EPA adopted a revised eight-hour ozone NAAQS and published its final area designations in 2012. All areas within the Company's service territory have achieved attainment of the 2008 standard. In October 2015, the EPA published a more stringent eight-hour ozone NAAQS. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. States were required to recommend area designations by October 2016, and no areas within the Company's service territory were proposed for designation as nonattainment.

The EPA regulates fine particulate matter concentrations through an annual and 24-hour average NAAQS, based on standards promulgated in 1997, 2006, and 2012. All areas in which the Company's generating units are located have been determined by the EPA to be in attainment with those standards.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~On July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR is an emissions trading program that limits SO~~₂ ~~and nitrogen oxide (NO~~_x~~) emissions from power plants in two phases – Phase 1 in 2015 and Phase 2 in 2017. On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone-season NO~~_x program, beginning in 2017, and establishes more stringent ozone-season emissions budgets in Mississippi and removes Florida from the program. The State of Georgia's emission budget was not affected by the revisions, but interstate emissions trading is restricted unless the state decides to voluntarily adopt a significantly reduced budget. Georgia is also in the CSAPR annual SO₂ ~~and NO~~_x ~~programs.~~

The EPA finalized regional haze regulations in 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of best available retrofit technology to certain sources, including fossil fuel-fired generating facilities, built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter. On December 14, 2016, the EPA finalized revisions to the regional haze regulations. These regulations establish a deadline of July 31, 2021 for states to submit revised State Implementation Plans (SIP) to the EPA demonstrating reasonable progress toward the statutory goal of achieving natural background conditions by 2064. State implementation of the reasonable progress requirements defined in this final rule could require further reductions in SO₂ ~~or NO~~_x ~~emissions.~~

In June 2015, the EPA published a final rule requiring certain states (including Florida, Georgia, and Mississippi) to revise or remove the provisions of their SIPs relating to the regulation of excess emissions at industrial facilities, including fossil fuel-fired generating facilities, during periods of startup, shut-down, or malfunction (SSM), and proposed SIP revisions have been submitted by the affected states where the Company's generating units are located.

The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the current and proposed environmental requirements discussed above. These regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through PPAs. The ultimate impact of the eight-hour ozone and SO₂ NAAQS, CSAPR, regional haze regulations, and SSM rule will depend on various factors, such as implementation, adoption, or other action at the state level, and the outcome of pending and/or future legal challenges, and cannot be determined at this time.

~~Water Quality~~

In November 2015, the EPA published a final effluent guidelines rule which imposes stringent technology-based requirements for certain wastestreams from steam electric power plants. The revised technology-based limits and compliance dates will be incorporated into future renewals of NPDES permits at affected units and may require the installation and operation of multiple technologies sufficient to ensure compliance with applicable new numeric wastewater compliance limits. Compliance deadlines between November 1, 2018 and December 31, 2023 will be established in permits based on information provided for each applicable wastestream.

In 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs. The final rule significantly expands the scope of federal jurisdiction under the CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. The rule became effective in August 2015 but, in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The case is held in abeyance pending review by the U.S. Supreme Court of challenges to the U.S. Court of Appeals for the Sixth Circuit's jurisdiction in the case.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

In addition, numeric nutrient water quality standards promulgated by the State of Florida to limit the amount of nitrogen and phosphorous allowed in state waters are in effect for the State's streams and estuaries. The impact of these standards will depend on further regulatory action in connection with their site-specific implementation through the State of Florida's National Pollutant Discharge Elimination System permitting program and Total Maximum Daily Load restoration program and cannot be determined at this time.

~~Coal Combustion Residuals~~

The Company currently manages CCR at onsite storage units consisting of landfills and surface impoundments (CCR Units) at three electric generating plants in Florida and is a co-owner of units at generating plants located in Mississippi and Georgia operated by Mississippi Power and Georgia Power, respectively. In addition to on-site storage, the Company sells a portion of its CCR to third parties for beneficial reuse. Individual states regulate CCR and the States of Florida, Mississippi, and Georgia each have their own regulatory requirements. The Company has an inspection program in place to assist in maintaining the integrity of its coal ash surface impoundments.

Based on current cost estimates for closure and monitoring of ash ponds pursuant to the CCR Rule, and the closure of an ash pond at Plant Scholz, the Company has recorded AROs. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing with respect to compliance activities, the Company expects to continue to periodically update these estimates. The Company has posted closure and post-closure care plans to its public website as required by the CCR Rule; however, the ultimate impact of the CCR Rule will depend on the results of initial and ongoing minimum criteria assessments and the implementation of state or federal permit programs. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The estimated costs associated with closure of the ash ponds at Plant Scholz and Plant Smith for 2017 have been approved for recovery through the environmental cost recovery clause. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information regarding the Company's AROs as of December 31, 2016.

~~Environmental Remediation~~

The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up affected sites. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known affected sites. Included in this amount are costs associated with remediation of the Company's substation sites. These projects have been approved by the Florida PSC for recovery through the environmental cost recovery clause; therefore, these liabilities have no impact to the Company's net income. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under "Environmental Matters – Environmental Remediation" for additional information.

~~Global Climate Issues~~

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

either does not submit a state plan or its plan is not approved by the EPA. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for review with the courts. The stay will remain in effect through the resolution of the litigation, including any review by the U.S. Supreme Court.

These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions and decisions on infrastructure expansion and improvements. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs. However, the ultimate financial and operational impact of the final rules on the Company cannot be determined at this time and will depend upon numerous factors, including the outcome of pending legal challenges, including legal challenges filed by the traditional electric operating companies, and any individual state implementation of the EPA's final guidelines in the event the rule is upheld and implemented.

In December 2015, parties to the United Nations Framework Convention on Climate Change – including the United States – adopted the Paris Agreement, which establishes a non-binding universal framework for addressing greenhouse gas emissions based on nationally determined contributions. It also sets in place a process for tracking progress toward the goals every five years. The ultimate impact of this agreement depends on its implementation by participating countries and cannot be determined at this time.

~~The EPA's greenhouse gas reporting rule requires annual reporting of greenhouse gas emissions expressed in terms of metric tons of CO~~₂ equivalent emissions for a company's operational control of facilities. Based on ownership or financial control of facilities, the Company's 2015 greenhouse gas emissions were approximately 9 million metric tons of CO₂ ~~equivalent. The preliminary estimate of the Company's 2016 greenhouse gas emissions on the same basis is approximately 8 million metric tons of CO~~₂ ~~equivalent. The level of greenhouse gas emissions from year to year will depend on the level of generation, the mix of fuel sources, and other factors.~~

~~FERC Matters~~

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Retail Regulatory Matters~~

The Company's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. The Company's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through the Company's base rates. See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Retail Base Rate Cases~~

In 2013, the Florida PSC approved the 2013 Rate Case Settlement Agreement among the Company and all of the intervenors to the Company's retail base rate case. Under the terms of the 2013 Rate Case Settlement Agreement, the Company (1) increased base rates approximately $35 million and $20 million annually effective January 2014 and 2015, respectively; (2) continued its authorized retail ROE midpoint (10.25%) and range (9.25% – 11.25%); (3) may reduce depreciation expense and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million between January 2014 and June 2017, of which $28.5 million had been recorded as of December 31, 2016; and (4) accrued a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 through January 1, 2017.

The 2013 Rate Case Settlement Agreement also provides that the Company may reduce depreciation and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction may not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in the Company's 2016 Rate Case. For 2014 and 2015, the Company recognized reductions in depreciation expense of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016.

On October 12, 2016, the Company filed the 2016 Rate Case with the Florida PSC requesting an annual increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. The requested increase includes recovery of the portion of Plant Scherer Unit 3 that has been rededicated to serving retail customers following the contract expirations discussed previously. If retail recovery of Plant Scherer Unit 3 is not approved by the Florida PSC in the 2016 Rate Case, the Company may consider an asset sale. The current book value of the Company's ownership of Plant Scherer Unit 3 could exceed market value which could result in a material loss. The Florida PSC is expected to make a decision on the 2016 Rate Case in the second quarter 2017. The Company has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017. The ultimate outcome of this matter cannot be determined at this time.

~~See Note 3 to the financial statements under "Retail Regulatory Matters – Retail Base Rate Cases" for additional information.~~

~~Cost Recovery Clauses~~

On November 2, 2016, the Florida PSC approved the Company's 2017 annual cost recovery clause rates for its fuel, purchased power capacity, environmental, and energy conservation cost recovery clauses. The net effect of the approved changes is a decrease of approximately $41 million in annual revenues effective in January 2017. In general, the decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses. However, certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 were included in the environmental cost recovery clause rate, which increased annual revenues by approximately $12 million in 2016 and is expected to increase revenues by an incremental $2 million for a total of approximately $14 million in 2017. The final disposition of these costs, and the related impact on rates, is subject to the Florida PSC's ultimate ruling on whether costs associated with Plant Scherer Unit 3 are recoverable from retail customers, which is expected to be decided in the 2016 Rate Case as discussed previously. The ultimate outcome of this matter cannot be determined at this time. See Note 3 to the financial statements under "Retail Regulatory Matters – Retail Base Rate Cases" for additional information.

Revenues for all cost recovery clauses, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor for fuel and purchased power will have no significant effect on the Company's revenues or net income, but will affect annual cash flow. The recovery provisions for environmental compliance and energy conservation include related expenses and a return on net average investment. See Note 1 to the financial statements under "Revenues" for additional information.

~~Renewables~~

In April 2015, the Florida PSC approved three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. Purchases under these solar agreements are expected to begin by the summer of 2017.

The Florida PSC issued a final approval order on the Company's Community Solar Pilot Program on April 15, 2016. The program will offer the Company's customers an opportunity to voluntarily contribute to the construction and operation of a solar photovoltaic facility with electric generating capacity of up to 1 MW through annual subscriptions. The energy generated from the solar facility is expected to provide power to all of the Company's customers.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

On November 29, 2016, the Florida PSC approved an energy purchase agreement for up to 94 MWs of additional wind generation in central Oklahoma. Purchases under this agreement will be for energy only and will be recovered through the Company's fuel cost recovery clause.

~~Income Tax Matters~~

Bonus Depreciation

~~In December 2015,~~Under the ~~Protecting Americans from~~ Tax ~~Hikes (PATH) Act was signed into law. Bonus depreciation was extended for qualified property~~Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service ~~through 2020. The PATH Act allows~~after September 27, 2017 remain eligible for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. ~~The extension of~~Based on provisional estimates, bonus depreciation ~~included in the PATH Act~~ is expected to result in ~~approximately $20 million of~~ positive cash flows for the ~~2016 tax year and approximately $26 million for the 2017 tax year.~~ Registrants as follows:



	2019 Tax Year		2020 Tax Year
	(in millions)
Southern Company	$	989	$	382
Alabama Power	180		68
Georgia Power	314		56
Mississippi Power	7		2
Southern Power^(*)	87		95
Southern Company Gas	190		58


(*)	Cash flows resulting from bonus depreciation for Southern Power would also be impacted by Southern Power's use of tax equity partnerships.

See Note 510 to the financial statements under "Current and Deferred Income Taxes" for additional information.

~~Other Matters~~

As a result of the cost to comply with environmental regulations imposed by the EPA, the Company retired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) on March 31, 2016. The Company filed a petition with the Florida PSC requesting permission to recover the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date. On August 29, 2016, the Florida PSC approved the Company's request to reclassify these costs, totaling approximately $63 million, to a regulatory asset for recovery over a period to be decided in the 2016 Rate Case. The ultimate outcome of this matter cannot be determined at this time.

Tax Credits

The Tax Reform Legislation retained solar energy incentives of 30% ITC for projects that commenced construction by December 31, 2019; 26% ITC for projects that commence construction in 2020; 22% ITC for projects that commence construction in 2021; and a permanent 10% ITC for projects that commence construction on or after January 1, 2022. In addition, the Tax Reform Legislation retained wind energy incentives of 100% PTC for projects that commenced construction in 2016; 80% PTC for projects that commenced construction in 2017; 60% PTC for projects that commenced construction in 2018; and 40% PTC for projects that commenced construction in 2019. As a result of a tax extenders bill passed in December 2019, projects that begin construction in 2020 will be entitled to 60% PTC. Projects commencing construction after 2020 will not be entitled to any PTCs. Southern Company ishas received ITCs and PTCs in connection with investments in solar, wind, and biomass facilities primarily at Southern Power and Georgia Power.

General Litigation Matters

The Registrants are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂~~and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.~~ The ultimate outcome of such pending or potential litigation or regulatory matters against ~~the Company~~each Registrant and any subsidiaries cannot be ~~predicted~~determined at this time; however, for current proceedings not specifically reported herein or in ~~Note~~Notes 2 and 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on ~~the Company's~~such Registrant's financial statements. See ~~Note~~Notes 2 and 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.

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Southern Company and Subsidiary Companies 2019 Annual Report

Southern Company

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In April 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action.

In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. In May 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. On August 5, 2019, the court granted a motion filed by the plaintiff on July 17, 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.

Georgia Power

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Southern Company and Subsidiary Companies 2019 Annual Report

Mississippi Power

See Note 2 to the financial statements under "Kemper County Energy Facility" for additional information.

Other Matters

Southern Company

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Southern Company and Subsidiary Companies 2019 Annual Report

Mississippi Power

Southern Company Gas

The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on the financial statements of Southern Company and Southern Company Gas.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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Southern Company and Subsidiary Companies 2019 Annual Report

Utility Regulation (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

The ~~Company is~~traditional electric operating companies and the natural gas distribution utilities are subject to retail regulation by their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by the ~~Florida PSC. The Florida PSC sets~~FERC. These regulatory agencies set the rates the ~~Company is~~traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable ~~costs. The Company is also subject to cost-based regulation by the FERC with respect to wholesale transmission rates.~~costs, including a reasonable ROE. As a result, the ~~Company applies~~traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards ~~has a further effect on the Company's~~for rate regulated entities also impacts their financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the ~~Company;~~traditional electric operating companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the ~~Company's~~ results of operations and financial condition of the applicable Registrants than they would on a non-regulated company.

~~Table~~Revenues related to regulated utility operations as a percentage of ~~ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf~~total operating revenues in 2019 for the applicable Registrants were as follows: 87% for Southern Company, 99% for Alabama Power, 97% for Georgia Power, 100% for Mississippi Power, and 80% for Southern Company ~~2016 Annual Report~~

Gas.

Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4

(Southern Company and Georgia Power)

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Southern Company and Subsidiary Companies 2019 Annual Report

proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.

Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4.

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Southern Company and Subsidiary Companies 2019 Annual Report

Accounting for Income Taxes (Southern Company, Mississippi Power, Southern Power, and Southern Company Gas)

Asset Retirement Obligations (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

The ~~liability~~ARO liabilities for ~~AROs~~the traditional electric operating companies primarily ~~relates~~relate to ~~the Company's~~ facilities that are subject to the CCR Rule and to the ~~closure of an~~related state rules, principally ash ~~pond at Plant Scholz.~~ponds. In addition, ~~the Company has~~Alabama Power and Georgia Power have retirement obligations related to ~~combustion turbines at its Pea Ridge facility,~~the decommissioning of nuclear facilities (Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2). The traditional electric operating companies also have AROs related to various landfill sites, ~~a barge unloading dock,~~ asbestos removal, and underground storage tanks, as well as, for Alabama Power, disposal of polychlorinated biphenyls in certain ~~transformers.~~ transformers and sulfur hexafluoride gas in certain substation breakers, for Georgia Power, gypsum cells and restoration of land at the end of long-term land leases for solar facilities, and for Mississippi Power, mine reclamation and water wells.

The traditional electric operating companies and Southern Company Gas also ~~has~~have identified other retirement obligations, such as obligations related to certain electric transmission and distribution facilities, certain asbestos-containing material within long-term assets not subject to ongoing repair and maintenance activities, certain wireless communication towers, the disposal of polychlorinated biphenyls in certain transformers, leasehold improvements, equipment on customer property, and ~~certain structures authorized by~~property associated with the ~~U.S. Army Corps of Engineers.~~Southern Company system's rail lines and natural gas pipelines. However, liabilities for the removal of these

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

The ~~Company recorded new~~cost estimates for AROs ~~in 2015 for facilities that are subject~~related to the ~~CCR Rule as discussed above and for the closure~~disposal of ~~an ash pond at Plant Scholz. The cost estimates~~CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule ~~requirements for closure for those facilities impacted by~~and the ~~CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the~~related state rules. The traditional electric operating companies expect to update their ARO cost estimates ~~such~~periodically as additional information related to these assumptions becomes available. See Note 6 to the ~~quantities of CCR at each site, and the determination of timing with respect~~financial statements for additional information, including increases to ~~compliance activities, including the potential for closing~~AROs related to ash ponds prior to the end of their currently anticipated useful life, the Company expects to continue to periodically update these estimates. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals" herein for additional information.recorded during 2019 by certain Registrants.

Given the significant judgment involved in estimating AROs, the ~~Company considers~~applicable Registrants consider the liabilities for AROs to be critical accounting estimates.

~~See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.~~

Pension and Other Postretirement Benefits (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

For 2019, the LRR assumption for qualified pension plan assets was reduced from 7.95% to 7.75% for purposes of determining net periodic pension expense ~~using~~as a result of changes in the ~~same single-point discount rate. For 2016,~~economic outlook used in estimating the expected returns as of December 31, 2018. As a result of the decrease in the LRR, the non-service costs component of net periodic pension expense increased by $24 million for the Southern Company ~~adopted~~system in 2019. See the table below for the impact on each Registrant.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

~~Gulf Power~~Southern Company ~~2016~~and Subsidiary Companies 2019 Annual Report

For 2020, net periodic pension expense will be impacted by two factors: a ~~full yield curve~~change in the approach ~~for calculating~~used to determine the ~~interest cost component whereby the discount rate for each year is applied~~LRR assumption and cash contributions totaling $1.1 billion to the ~~liability~~qualified pension plan made in December 2019. Historically, Southern Company has set the LRR assumption using asset return modeling based on geometric returns that reflect the compound average returns for ~~that specific~~dependent annual periods. Beginning in 2020, Southern Company will set the LRR assumption using an arithmetic mean which represents the expected simple average return to be earned by the pension plan assets over any one year. AsSouthern Company believes the use of the arithmetic mean is more compatible with the LRR's function of estimating a ~~result,~~single year's investment return. Excluding the ~~interest cost~~additional pension contribution in December 2019, the change in the LRR assumption will reduce the non-service costs component of net periodic pension expense by $78 million for the Southern Company system in 2020. See the table below for the impact on each Registrant. The contributions in 2019 will further reduce expense by $88 million for the Southern Company system in 2020.



	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions)
Increase (decrease) in pension expense:
2019	$	24		$	5		$	8		$	1		$	2
2020	(78		)	(18		)	(25		)	(4		)	(7		)

The following table illustrates the sensitivity to changes in the applicable Registrants' long-term assumptions with respect to the discount rate, salary increases, and ~~other postretirement benefit plan expense decreased by approximately $4 million in 2016.~~

~~A 25 basis point change in any significant assumption (discount~~the long-term rate ~~salaries, or long-term~~of return on plan ~~assets) would result in a $2 million or less change in total annual benefit expense and a $21 million or less change in projected obligations.~~assets:



	Increase/(Decrease) in
25 Basis Point Change in:	Total Benefit Expense for 2020	Projected Obligation for Pension Plan at December 31, 2019	Projected Obligation for Other Postretirement Benefit Plans at December 31, 2019
	(in millions)
Discount rate:
Southern Company	$41/$(39)	$549/$(518)	$57/$(54)
Alabama Power	$10/$(10)	$131/$(123)	$14/$(13)
Georgia Power	$12/$(11)	$166/$(156)	$21/$(20)
Mississippi Power	$2/$(2)	$25/$(23)	$2/$(2)
Southern Company Gas	$1/$(1)	$38/$(36)	$6/$(6)
Salaries:
Southern Company	$23/$(22)	$118/$(113)	$–/$–
Alabama Power	$6/$(6)	$33/$(32)	$–/$–
Georgia Power	$6/$(6)	$34/$(33)	$–/$–
Mississippi Power	$1/$(1)	$5/$(5)	$–/$–
Southern Company Gas	$1/$(1)	$3/$(3)	$–/$–
Long-term return on plan assets:
Southern Company	$35/$(35)	N/A	N/A
Alabama Power	$9/$(9)	N/A	N/A
Georgia Power	$11/$(11)	N/A	N/A
Mississippi Power	$2/$(2)	N/A	N/A
Southern Company Gas	$3/$(3)	N/A	N/A

See Note 211 to the financial statements for additional information regarding pension and other postretirement benefits.

~~Contingent Obligations~~

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Southern Company and Subsidiary Companies 2019 Annual Report

Asset Impairment (Southern Company, Southern Power, and Southern Company Gas)

Goodwill (Southern Company and Southern Company Gas)

See Note 1 to the financial statements under "Goodwill and Other Intangible Assets and Liabilities" for additional information regarding the applicable Registrants' goodwill.

Long-Lived Assets (Southern Company, Southern Power, and Southern Company Gas)

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Southern Company and Subsidiary Companies 2019 Annual Report

See Note 3 to the financial statements under "Other Matters" and Note 15 to the financial statements for information on certain assets recently evaluated for impairment.

Derivatives and Hedging Activities (Southern Company and Southern Company Gas)

the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);

events specific to a given counterparty; and

the impact of nonperformance risk on liabilities.

A significant change in the underlying market prices or pricing assumptions used in pricing derivative assets or liabilities may result in a significant financial statement impact.

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Southern Company and Subsidiary Companies 2019 Annual Report

Revenue Recognition (Southern Power)

Lease Transactions

Southern Power considers the following factors to determine whether the sales contract is a lease:

Assessing whether specific property is explicitly or implicitly identified in the agreement;

Determining whether the fulfillment of the arrangement is dependent on the use of the identified property; and

Assessing whether the arrangement conveys to the counterparty substantially all of the economic benefits and the right to direct the use of the asset.

Non-Derivative and Normal Sale Derivative Transactions

If the power sales contract is not classified as a lease, Southern Power further considers the following factors to determine proper classification:

Assessing whether the contract meets the definition of a derivative;

Assessing whether the contract meets the definition of a capacity contract;

Assessing the probability at inception and throughout the term of the individual contract that the contract will result in physical delivery; and

Ensuring that the contract quantities do not exceed available generating capacity (including purchased capacity).

Cash Flow Hedge Transactions

Southern Power further considers the following in designating other derivative contracts for the sale of electricity as cash flow hedges of anticipated sale transactions:

Identifying the hedging instrument, the forecasted hedged transaction, and the nature of the risk being hedged; and

Assessing hedge effectiveness at inception and throughout the contract term.

These contracts are accounted for on a fair value basis and are recorded in AOCI over the life of the contract. Realized gains and losses are then recognized in operating revenues as incurred.

Derivative (Non-Hedge) Transactions

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Acquisition Accounting (Southern Power)

Variable Interest Entities (Southern Power)

Contingent Obligations (All Registrants)

Recently Issued Accounting Standards

The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on the Company's financial statements.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

~~Gulf Power~~Southern Company ~~2016~~and Subsidiary Companies 2019 Annual Report

rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5, 8, and 11 to the financial statements for disclosures impacted by ASU 2016-09.

~~On October 24, 2016, the FASB issued ASU No. 2016-16,~~ ~~Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory~~ (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements and has not yet determined its ultimate impact.

FINANCIAL CONDITION AND LIQUIDITY

Overview

The ~~Company's~~ financial condition of each Registrant remained stable at December 31, ~~2016.~~2019. The ~~Company's~~Registrants' cash requirements primarily consist of funding ongoing operations, including unconsolidated subsidiaries, as well as common stock dividends, capital expenditures, and debt maturities. Southern Power's cash requirements also include distributions to noncontrolling interests. Capital expenditures and other investing activities for the traditional electric operating companies include investments to meet projected long-term demand requirements, including to build new generation facilities, to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units and closures of ash ponds, to expand and improve transmission and distribution facilities, and for restoration following major storms. Southern Power's capital expenditures and other investing activities may include acquisitions or new construction associated with its overall growth strategy and to maintain its existing generation fleet's performance. Southern Company Gas' capital expenditures and other investing activities include investments to meet projected long-term demand requirements, to maintain existing ~~facilities,~~natural gas distribution systems as well as to update and expand these systems, and to comply with environmental regulations including adding environmental modifications to certain existing generating units, to expand and improve transmission and distribution facilities, and for restoration following major storms. regulations.

Operating cash flows provide a substantial portion of the ~~Company's~~Registrants' cash needs. During 2019, Southern Power utilized tax credits, which provided $734 million in operating cash flows. For the three-year period from ~~2017~~2020 through ~~2019, the Company's~~2022, each Registrant's projected ~~common~~ stock dividends, capital expenditures, and debt maturities, as well as distributions to noncontrolling interests for Southern Power, are expected to exceed its operating cash flows. ~~The~~Southern Company plans to finance future cash needs in excess of its operating cash flows primarily ~~through~~by accessing borrowings from financial institutions and issuing debt ~~issuances~~and hybrid securities in the capital ~~markets,~~markets. Each Subsidiary Registrant plans to finance its future cash needs in excess of its operating cash flows primarily through external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Georgia Power plans to utilize borrowings through the FFB and Southern Power plans to utilize tax equity partnership contributions. The ~~Company intends~~Registrants plan to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs and continue to monitor ~~its~~their access to short-term and long-term capital markets as well as their bank credit ~~agreements~~arrangements to meet future capital and liquidity needs. See ~~"Sources~~"Sources of Capital," ~~"Financing~~"Financing Activities," "Capital Requirements," and ~~"Capital Requirements and~~ "Contractual ~~Obligations"~~Obligations" herein for additional information.

The ~~Company's~~Registrants' investments in ~~the~~their qualified pension ~~plan~~plans and Alabama Power's and Georgia Power's investments in their nuclear decommissioning trust funds increased in value ~~as of~~at December 31, ~~2016~~2019 as compared to December 31, ~~2015. On~~2018. In December ~~19, 2016,~~2019, the ~~Company~~Registrants voluntarily contributed ~~$48 million~~the following amounts to the qualified pension ~~plan.~~ plan:



	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Contributions to qualified pension plan	$	1,136	$	362	$	200	$	54	$	24	$	145

No mandatory contributions to the qualified pension ~~plan~~plans are anticipated during ~~2017.~~2020. See ~~Note 2~~"Contractual Obligations" herein and Notes 6 and 11 to the financial statements under ~~"Pension Plans"~~"Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Analysis of Cash Flows

Net cash flows provided from (used for) operating, investing, and financing activities ~~totaled $379 million~~ in ~~2016, a decrease of $81 million from 2015, primarily due to decreases~~2019 and 2018 are presented in the following table:



Net cash provided from (used for):	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
2019
Operating activities	$	5,781		$	1,779		$	2,907		$	339		$	1,385		$	1,067
Investing activities	(3,392		)	(1,963		)	(3,885		)	(263		)	(167		)	(1,386		)
Financing activities	(1,930		)	765			918			(83		)	(1,120		)	298

2018
Operating activities	$	6,945		$	1,881		$	2,769		$	804		$	631		$	764
Investing activities	(5,760		)	(2,289		)	(3,109		)	(232		)	(227		)	998
Financing activities	(1,813		)	177			(400		)	(527		)	(363		)	(1,770		)

Fluctuations in cash flows related to clause recovery and a voluntary contribution to the qualified pension plan, partially offset by the timing of fossil fuel stock purchases. Net cash provided from operating activities totaled $460 million in 2015, an increase of $116 million from 2014, primarily due to increases in cash flows related to clause recovery and bonus depreciation. This increase was partially offset by decreases related to the timing of fossil fuel stock purchases and vendor payments.

Net cash used for investing activities totaled $180 million, $281 million, and $358 million for 2016, 2015, and 2014, respectively. The changes in cash used for investing activities were primarily related to gross property additions for environmental, distribution, steam generation, and transmission assets. Funds for the Company's property additions were provided by operating activities, capital contributions, and other financing activities.

Net cash used for financing activities totaled $217 million in 2016 primarily due to the redemptions of long-term debt and the payment of common stock dividends, partially offset by an increase in notes payable. Net cash used for financing activities totaled $144 million in 2015 primarily due to the payment of common stock dividends and redemptions of long-term debt, partially offset by an increase in notes payable and proceeds from the issuance of common stock to Southern Company. Net cash provided from financing activities totaled $31 million in 2014 primarily due to the issuance of long-term debt and common stock to Southern Company, partially offset by the payment of common stock dividends, the redemption of long-term debt, and a decrease to notes payable. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Southern Company

Alabama Power

The net cash used for investing activities in 2019 and 2018 was primarily due to gross property additions.

Georgia Power

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Mississippi Power

The net cash used for investing activities in 2019 and 2018 was primarily due to gross property additions.

Southern Power

Southern Company Gas

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Significant Balance Sheet Changes

Southern Company

Significant balance sheet changes in ~~2016 included~~ 2019 for Southern Company included:

an increase of $2.3 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' construction of electric generation, transmission, and distribution facilities, including installation of equipment to comply with environmental standards, net of $1.2 billion and $1.0 billion reclassified to other regulatory assets and regulatory assets associated with AROs, respectively, as a result of generating unit retirements at Alabama Power and Georgia Power;

increases in operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.8 billion, recorded upon the adoption of ASC 842;

a decrease of ~~$206~~$0.9 billion in notes payable related to net repayments of short-term bank debt and commercial paper.

See Notes 2, 5, 6, 8, 9, 10, 11, and 15 to the financial statements for additional information.

Alabama Power

Significant balance sheet changes in 2019 for Alabama Power included:

an increase of $1.5 billion in total common stockholder's equity primarily due to a $1.2 billion capital contribution from Southern Company;

an increase of $0.6 billion in cash and cash equivalents; and

an increase of $0.3 billion in AROs, deferred primarily due to an increase in the ARO estimate related to ash pond facilities.

See Notes 2 and 6 to the financial statements for additional information.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Georgia Power

Significant balance sheet changes in 2019 for Georgia Power included:

increases in operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.4 billion, recorded upon the adoption of ASC 842;

an increase of $742 million in total common stockholder's equity primarily due to capital contributions from Southern Company.

See Notes 2, 8, 9, and 11 to the financial statements for additional information.

Mississippi Power

Significant balance sheet changes in 2019 for Mississippi Power included:

a decrease of $231 million in long-term debt, primarily due to the ~~early retirement and redemption at maturity of $235 million in senior notes and the~~ reclassification of ~~$85~~$249 million inof senior notes to securities due within one year and the redemption of $25 million of senior notes, partially offset by $43 million in pollution control revenue bonds reoffered to the public;

an increase of ~~$126 million in notes payable, and an increase of $85~~$107 million in other property and investments primarily due to a new tolling arrangement accounted for as a sales-type lease;

increases of $67 million in regulatory assets associated with AROs and $31 million in AROs, deferred

~~Table of ContentsIndex~~ primarily due to ~~Financial Statements~~ARO revisions; and


•	a net change of $57 million in accumulated deferred income tax assets and liabilities primarily due to the recognition of a tax loss on the CO₂ pipeline transfer and the alternative minimum tax carryforward from prior years.

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~primarily related to the retirement of Plant Smith Units 1~~See Notes 2, 6, 8, 9, and ~~2 and CCR compliance costs. See Note 3 to the financial statements for additional information related to the retirement of Plant Smith Units 1 and 2.~~

~~The Company's ratio of common equity to total capitalization plus short-term debt, was 48.3% and 46.0% at December 31, 2016 and 2015, respectively. See Note 6~~10 to the financial statements for additional information.

Southern Power

Significant balance sheet changes in 2019for Southern Power included:

a $662 million decrease in stockholders' equity due to returns of capital to Southern Company;

a $635 million decrease in accumulated deferred income tax assets primarily related to the utilization of tax credits for the 2019 tax year;

a $619 million decrease in long-term debt (including securities due within one year) related to the maturity of $600 million in senior notes;

a $449 million increase in notes payable due to net issuances of commercial paper; and

increases in operating lease right-of-use assets, net of amortization and operating lease obligations totaling $369 million and $376 million, respectively, recorded upon the adoption of ASC 842.

See Notes 8, 9, and 10 to the financial statements for additional information.

Southern Company Gas

Significant balance sheet changes in 2019 for Southern Company Gas included:

additional paid-in-capital of $841 million primarily related to capital contributions from Southern Company;

decreases of $373 million and $414 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and volumes of natural gas sold;

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

a $203 million increase in accumulated deferred income taxes primarily due to accelerated tax depreciation and other timing differences;

reclassification of $171 million in total assets held for sale associated with Pivotal LNG and Atlantic Coast Pipeline;

increases of $93 million in operating right-of-use assets and $92 million in operating lease obligations, respectively, related to the adoption of ASC 842.

See Notes 3, 7, 8, 9, 10, and 15 to the financial statements for additional information.

Sources of Capital

The ~~Company plans~~Subsidiary Registrants plan to obtain the funds ~~required~~ to meet ~~its~~their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, ~~short-term debt,~~ external ~~security~~securities issuances, ~~term loans,~~borrowings from financial institutions, and equity contributions from Southern Company. ~~However,~~In addition, Georgia Power plans to utilize borrowings from the FFB, as discussed further in Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings," Southern Power plans to utilize tax equity partnership contributions, as discussed further herein, and Southern Company Gas plans to utilize proceeds from the pending sale of its interests in Pivotal LNG and Atlantic Coast Pipeline, as discussed further in Note 15 to the financial statements under "Southern Company Gas – Proposed Sale of Pivotal LNG and Atlantic Coast Pipeline."

The amount, type, and timing of any ~~future~~ financings ~~if needed,~~in 2020, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon ~~regulatory approval,~~ prevailing market conditions, regulatory approvals (for the Subsidiary Registrants), and other factors. See "Capital Requirements" herein for additional information.

~~Security issuances~~

Southern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. During 2019, Southern Power obtained tax equity funding for the Wildhorse Mountain wind project and received proceeds of $97 million. See Notes 1 and 15 to the financial statements under "General" and "Southern Power," respectively, for additional information.

The issuance of securities by the traditional electric operating companies and Nicor Gas is generally subject to ~~annual~~the approval of the applicable state PSC or other applicable state regulatory agency. The issuance of all securities by Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by the ~~Florida PSC pursuant to its rules and regulations.~~FERC. Additionally, with respect to the public offering of securities, Southern Company, the traditional electric operating companies, and Southern Power (excluding its subsidiaries), Southern Company ~~files~~Gas Capital, and Southern Company Gas (excluding its other subsidiaries) file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the ~~Florida PSC,~~appropriate regulatory authorities, as well as the ~~amounts~~securities registered under the 1933 Act, are ~~continuously~~closely monitored and appropriate filings are made to ensure flexibility in the capital markets.

The ~~Company's~~traditional electric operating companies and SEGCO may utilize a Southern Company subsidiary organized to issue and sell commercial paper at their request and for their benefit. Proceeds from such issuances for the benefit of an individual company are loaned directly to that company. The obligations of each traditional electric operating company and SEGCO under these arrangements are several and there is no cross-affiliate credit support. Alabama Power also maintains its own separate commercial paper program.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At December 31, 2019, the amount of subsidiary retained earnings restricted to dividend totaled $951 million. This restriction did not impact Southern Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.

The Registrants' current liabilities frequently exceed their current assets because of long-term debt maturities and the ~~continued~~periodic use of short-term debt as a funding source, ~~to meet scheduled maturities of long-term debt,~~ as well as significant seasonal fluctuations in cash needs. ~~The Company has substantial cash flow from operating activities and access~~See Note 8 to the financial statements for additional information. Also see "Financing Activities" herein for information on issuances of long-term debt subsequent to December 31, 2019. At December 31, 2019, the following Registrants' current liabilities exceeded their current assets, primarily as a result of securities due within one year and notes payable, as shown in the table below:



At December 31, 2019	Southern Company^(*)		Georgia Power		Mississippi Power		Southern Power
	(in millions)
Current liabilities in excess of current assets	$	2,729	$	1,902	$	125	$	945
Securities due within one year	2,989		1,025		281		824
Notes payable	2,055		365		—		549


(*)	Includes $600 million and $465 million of securities due within one year and notes payable, respectively, at the parent company.

The Registrants believe the need for working capital ~~markets and financial institutions to meet short-term liquidity needs, including its~~can be adequately met by utilizing operating cash flows, as well as commercial paper, ~~program which is supported by~~lines of credit, and short-term bank ~~credit facilities.~~notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company.

Bank Credit Arrangements

At December 31, ~~2016,~~2019, the ~~Company had approximately $56 million of cash and cash equivalents. Committed~~Registrants' unused committed credit arrangements with banks ~~at December 31, 2016~~ were as follows:

Expires
Executable
Term Loans
Expires Within One Year
2017 2018 Total Unused
One
Year

Two
Years
Term Out No Term Out
(in millions) (in millions) (in millions) (in millions)
$85 $195 $280 $280 $45 $— $25 $60



At December 31, 2019	Southern Company parent		Alabama Power		Georgia Power		Mississippi Power		Southern Power^(a)		Southern Company Gas^(b)		SEGCO		Southern Company
	(in millions)
Unused committed credit	$	1,999	$	1,328	$	1,733	$	150	$	591	$	1,745	$	30	$	7,576

(a)


(b)	Includes $1.245 billion and $500 million at Southern Company Gas Capital and Nicor Gas, respectively.

~~See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.~~

Most of these bank credit arrangements contain covenants that limit debt levels and contain cross acceleration provisions to other indebtedness (including guarantee obligations) of the Company. Such cross acceleration provisions to other indebtedness would trigger an event of default if the Company defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2016, the Company was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

Subject to applicable market conditions, the ~~Company expects~~Registrants, Nicor Gas, and SEGCO expect to renew or replace ~~its~~their bank credit arrangements as needed, prior to expiration. In connection therewith, the ~~Company~~Registrants, Nicor Gas, and SEGCO may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

~~Most~~ A portion of the unused credit ~~arrangements~~ with banks ~~are~~is allocated to provide liquidity support to the ~~Company's pollution control~~ revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.

Short-term Borrowings

The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2016 was approximately $82 million. In addition, at December 31, 2016, the Company had $86 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.

~~The Company may also meet~~Commercial paper and short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional electric operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowingsbank term loans are included in notes payable in the balance sheets.

~~Table~~ Details of ~~ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Details of~~the Registrants' short-term borrowings were as follows:

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Short-term Debt at the End of the Period
Short-term Debt During the Period ^(*)
Amount Outstanding Weighted Average Interest Rate Average Amount Outstanding Weighted Average Interest Rate Maximum Amount Outstanding
(in millions) (in millions) (in millions)
December 31, 2016
Commercial paper $ 168
1.1 % $ 53
0.9 % $ 168
Short-term bank debt 100
1.5 % 64
1.3 % 100
Total $ 268
1.2 % $ 117
1.1 %
December 31, 2015
Commercial paper $ 142
0.7 % $ 101
0.4 % $ 175
Short-term bank debt —
— % 10
0.7 % 40
Total $ 142
0.7 % $ 111
0.4 %
December 31, 2014
Commercial paper $ 110
0.3 % $ 85
0.2 % $ 145



	Short-term Debt at the End of the Period
	Amount Outstanding						Weighted Average Interest Rate
	December 31,						December 31,
	2019		2018		2017		2019		2018		2017
	(in millions)
Southern Company	$	2,055	$	2,915	$	2,439	2.1	%	3.1	%	1.9	%
Alabama Power	—		—		3		—		—		3.7
Georgia Power	365		294		150		2.2		3.1		2.2
Mississippi Power	—		—		4		—		—		3.8
Southern Power	549		100		105		2.2		3.1		2.0
Southern Company Gas:
Southern Company Gas Capital	$	372	$	403	$	1,243	2.1	%	3.1	%	1.7	%
Nicor Gas	278		247		275		1.8		3.0		1.8
Southern Company Gas Total	$	650	$	650	$	1,518	2.0	%	3.0	%	1.8	%



	Short-term Debt During the Period^(*)
	Average Amount Outstanding						Weighted Average Interest Rate						Maximum Amount Outstanding
	2019		2018		2017		2019		2018		2017		2019		2018		2017
	(in millions)												(in millions)
Southern Company	$	1,240	$	3,377	$	2,672	2.6	%	2.6	%	1.5	%	$	2,914	$	5,447	$	3,668
Alabama Power	17		27		25		2.6		2.3		1.3		190		258		223
Georgia Power	371		139		427		2.7		2.5		1.8		935		710		1,460
Mississippi Power	—		68		18		—		2.0		3.0		—		300		36
Southern Power	76		188		232		2.7		2.5		1.4		578		385		419
Southern Company Gas:
Southern Company Gas Capital	$	302	$	520	$	723	2.6	%	2.3	%	1.4	%	$	490	$	1,361	$	1,243
Nicor Gas	91		123		176		2.3		2.2		1.1		278		275		525
Southern Company Gas Total	$	393	$	643	$	899	2.5	%	2.3	%	1.4	%


(*)	Average and maximum amounts are based upon daily balances during the ~~year.~~12-month periods ended December 31, 2019, 2018, and 2017.

~~The~~

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company ~~believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank term loans,~~ and ~~operating cash flows.~~Subsidiary Companies 2019 Annual Report

Financing Activities

~~In May 2016,~~The following table outlines the ~~Company redeemed $125 million aggregate principal amount of its Series 2011A 5.75% Senior Notes due June 1, 2051.~~Registrants' long-term debt financing activities for the year ended December 31, 2019:

~~Also in May 2016,~~



Company	Senior Note Issuances		Senior Note Maturities, Redemptions, and Repurchases		Revenue Bond Issuances and Reofferings of Purchased Bonds		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities^(a)
	(in millions)
Southern Company parent	$	—	$	2,400	$	—	$	—	$	1,725	$	—
Alabama Power	600		200		—		—		—		1
Georgia Power	750		500		584		223		1,218		13
Mississippi Power	—		25		43		—		—		—
Southern Power	—		600		—		—		—		—
Southern Company Gas	—		300		—		—		300		50
Other	—		—		—		25		—		17
Elimination^(b)	—		—		—		—		—		(7		)
Southern Company	$	1,350	$	4,025	$	627	$	248	$	3,243	$	74


(a)	Includes reductions in finance lease obligations resulting from cash payments under finance leases.


(b)	Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements.

Except as otherwise described herein, the ~~Company entered into an 11-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and~~Registrants used the proceeds ~~were used~~of debt issuances for their redemptions and maturities shown in the table above, to repay ~~existing~~short-term indebtedness, and ~~for working capital and other general corporate purposes.~~

~~In December 2016, the Company repaid at maturity $110 million aggregate principal amount of its Series M 5.30% Senior Notes due December 1, 2016.~~

~~Subsequent to December 31, 2016, the Company issued 1,750,000 shares of common stock to Southern Company and realized proceeds of $175 million. The proceeds were used~~ for general corporate purposes, including working capital. The Subsidiary Registrants also used the ~~Company's continuous~~proceeds for their construction ~~program.~~programs.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, ~~and storm recovery,~~ the ~~Company plans~~Registrants plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Southern Company

During 2019, Southern Company issued approximately 19.5 million shares of common stock through employee equity compensation plans and received proceeds of approximately $844 million.

In January 2019, Southern Company repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.

In 2019, Southern Company, through repurchases and redemptions, retired all $1.0 billion aggregate principal amount of its 1.85% Senior Notes due July 1, 2019, $350 million aggregate principal amount of its Series 2014B 2.15% Senior Notes due September 1, 2019, $750 million aggregate principal amount of its Series 2018A Floating Rate Notes due February 14, 2020, and $300 million aggregate principal amount of its Series 2017A Floating Rate Senior Notes due September 30, 2020.

Subsequent to December 31, 2019, Southern Company issued $1.0 billion aggregate principal amount of Series 2020A 4.95% Junior Subordinated Notes due January 30, 2080.

Alabama Power

In February 2019, Alabama Power repaid at maturity $200 million aggregate principal amount of Series Z 5.125% Senior Notes due February 15, 2019.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

In September 2019, Alabama Power issued $600 million aggregate principal amount of Series 2019A 3.45% Senior Notes due October 1, 2049.

Subsequent to December 31, 2019, Alabama Power received a capital contribution totaling $610 million from Southern Company.

Georgia Power

In June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.

During 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and were held by Georgia Power at December 31, 2018:

$173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009;

$65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008;

$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994; and

During 2019, Georgia Power purchased, held, and subsequently reoffered to the public an additional $115 million of pollution control revenue bonds.

In December 2019, Georgia Power repaid at maturity $500 million aggregate principal amount of its Series 2009B 4.25% Senior Notes.

Mississippi Power

In December 2019, Mississippi Power redeemed $25 million aggregate principal amount of its Series 2018A Floating Rate Senior Notes due March 27, 2020.

Southern Power

In May 2019, Southern Power repaid at maturity a $100 million short-term floating rate bank loan.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

In December 2019, Southern Power repaid at maturity $600 million aggregate principal amount of its Series 2016D 1.95% Senior Notes.

Southern Company Gas

In July 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of its 4.7% first mortgage bonds.

In August 2019, Southern Company Gas Capital repaid at maturity $300 million aggregate principal amount of its 5.25% Senior Notes.

In August and October 2019, Nicor Gas issued $200 million and $100 million, respectively, aggregate principal amount of first mortgage bonds in a private placement.

Credit Rating Risk

At December 31, ~~2016,~~2019, the ~~Company~~Registrants did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain Registrants to ~~BBB-~~BBB and/or ~~Baa3~~Baa2 or below. These contracts are primarily for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, ~~transmission, and~~ energy price risk ~~management.~~management, transmission, interest rate management, and, for Georgia Power, construction of new generation at Plant Vogtle Units 3 and 4.

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

The maximum potential collateral requirements under these contracts at December 31, ~~2016~~2019 were as follows:


Credit Ratings	Maximum Potential Collateral Requirements		Southern Company^(*)		Alabama Power		Georgia Power		Mississippi Power		Southern Power^(*)		Southern Company Gas
	(in millions)		(in millions)
At BBB and/or Baa2			$	36	$	1	$	—	$	—	$	35	$	—
At BBB- and/or Baa3	$	192	472		1		86		—		385		—
Below BBB- and/or Baa3	$	628
At BB+ and/or Ba1 or below			2,040		322		1,020		267		1,174		18

(*)

Excludes amounts related to Plant Mankato, which was sold on January 17, 2020. Southern Power has PPAs that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPAs require credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade. Southern Power had $104 million of cash collateral posted related to PPA requirements at December 31, 2019.

~~Included~~The potential collateral requirement amounts in ~~these amounts are~~the previous table for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that either Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the ~~Company~~Registrants to access capital markets and would be likely to impact the cost at which ~~it does~~they do so.

Mississippi Power and its largest retail customer, Chevron, have agreements under which Mississippi Power continues to provide retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a security interest in the co-generation assets located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.

On ~~January 10, 2017,~~August 1, 2019, Moody's upgraded Mississippi Power's senior unsecured long-term debt rating to Baa2 from Baa3 and maintained the positive rating outlook.

On September 12, 2019, S&P ~~revised its consolidated credit~~upgraded the senior unsecured long-term debt rating ~~outlook for~~ of Alabama Power to A from A-, the long-term issuer rating of Nicor Gas to A from A-, and the senior secured debt rating of Nicor Gas to A+ from A. The ratings outlooks remained negative.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company ~~(including the Company) from negative to stable.~~and Subsidiary Companies 2019 Annual Report

Market Price Risk

~~Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure~~The Registrants are exposed to market ~~volatility in~~risks, including commodity price risk, interest ~~rates, commodity fuel prices,~~rate risk, weather risk, and ~~prices of electricity.~~occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, the ~~Company~~applicable company nets the exposures, where possible, to take advantage of natural offsets and ~~may enter~~enters into various derivative transactions for the remaining exposures pursuant to the ~~Company's~~applicable company's policies in areas such as counterparty exposure and risk management practices. ~~The Company's~~Southern Company Gas' wholesale gas operations uses various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.

~~To mitigate future~~Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities that sell natural gas directly to end-use customers continue to have limited exposure to ~~changes~~market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. The traditional electric operating companies and certain of the ~~Company may enter into derivatives which are designated as hedges. The weighted average interest rate on $82 million~~natural gas distribution utilities manage fuel-hedging programs implemented per the guidelines of ~~outstanding variable rate~~their respective state PSCs or other applicable state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. Mississippi Power also manages wholesale fuel-hedging programs under agreements with its wholesale customers. Because energy from Southern Power's facilities is primarily sold under long-term ~~debt that has not been hedged at January 1, 2017 was 0.79%. If~~PPAs with tolling agreements and provisions shifting substantially all of the ~~Company sustained a 100 basis point change in interest rates~~responsibility for ~~all variable rate long-term debt, the change would not materially affect annualized interest expense at January 1, 2017. See Note 1~~fuel cost to the ~~financial statements under "Financial Instruments"~~counterparties, Southern Power's exposure to market volatility in commodity fuel prices and ~~Note 10~~prices of electricity is generally limited. However, Southern Power has been and may continue to ~~the financial statements for additional information.~~

be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. To mitigate residual risks relative to movements in ~~fuel and~~ electricity prices, the ~~Company enters~~traditional electric operating companies and Southern Power may enter into ~~financial hedge contracts for natural gas purchases and~~ physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

Certain of Southern Company Gas' non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Southern Company Gas' gas marketing services and wholesale gas services businesses also actively manage storage positions through a variety of hedging transactions for the purpose of managing exposures arising from changing natural gas prices. These hedging instruments are used to substantially protect economic margins (as spreads between wholesale and retail natural gas prices widen between periods) and thereby minimize exposure to declining operating margins. Some of these economic hedge activities may not qualify, or may not be designated, for hedge accounting treatment.

The Company continues to manage a fuel-hedging program implemented per the guidelines of the Florida PSC and the actual cost of fuel is recovered through the retail fuel clause. The Florida PSC approved a stipulation and agreement that prospectively imposed a moratorium on the Company's fuel-hedging program in October 2016 through December 31, 2017. The CompanyRegistrants had no material change in market risk exposure for the year ended December 31, ~~2016~~2019 when compared to the year ended December 31, ~~2015.~~2018. See Note 1 to the financial statements under "Financial Instruments" and Note 14 to the financial statements for additional information.

The Registrants may enter into interest rate derivatives designated as hedges, which are intended to mitigate interest rate volatility related to forecasted debt financings and existing fixed and floating rate obligations. Outstanding interest rate derivatives at December 31, 2019 are as follows:



At December 31, 2019	Southern Company^(*)		Georgia Power		Southern Company Gas
	(in millions)
Hedges of forecasted debt	$	700	$	500	$	200
Hedges of existing debt	1,800		—		—
Total	$	2,500	$	500	$	200


(*)	Includes $1.8 billion of hedges of existing debt at the Southern Company parent.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

The following table provides information related to variable interest rate exposure on long-term debt (including amounts due within one year) at December 31, 2019 for the applicable Registrants:



At December 31, 2019	Southern Company^(*)			Alabama Power			Georgia Power			Mississippi Power			Southern Power
	(in millions, except percentages)
Long-term variable interest rate exposure	$	4,063		$	1,079		$	550		$	308		$	525
Weighted average interest rate on long-term variable interest rate exposure	2.38		%	2.35		%	1.74		%	2.51		%	2.46		%
Impact on annualized interest expense of 100 basis point change in interest rates	$	41		$	11		$	6		$	3		$	5


(*)	Includes $1.5 billion of long-term variable interest rate exposure at the Southern Company parent entity.

Southern Power Company had foreign currency denominated debt of €1.1 billion at December 31, 2019. Southern Power Company has mitigated its exposure to foreign currency exchange rate risk through the use of foreign currency swaps converting all interest and principal payments to fixed-rate U.S. dollars.

The changes in fair value of energy-related derivative contracts for Southern Company and Southern Company Gas for the years ended December 31, 2019 and 2018 are provided in the table below. The fair value of energy-related derivative contracts was not material for the other Registrants.



	Southern Company^(a)			Southern Company Gas^(a)
	(in millions)
Contracts outstanding at December 31, 2017, assets (liabilities), net	$	(163	)	$	(106	)
Contracts realized or settled	93			66
Current period changes^(b)	(131		)	(127		)
Contracts outstanding at December 31, 2018, assets (liabilities), net	$	(201	)	$	(167	)
Contracts realized or settled	69			26
Current period changes^(b)	105			213
Disposition	6			—
Contracts outstanding at December 31, 2019, assets (liabilities), net	$	(21	)	$	72


(a)	Excludes cash collateral held on deposit in broker margin accounts of $99 million, $277 million, and $193 million at December 31, 2019, 2018, and 2017, respectively, and premium and intrinsic value associated with weather derivatives of $4 million, $8 million, and $11 million at December 31, 2019, 2018, and 2017, respectively.

(b)

The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. ~~For the years ended December 31, the changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, were as follows:~~

2016
Changes

2015
Changes
Fair Value
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net $ (100 ) $ (72 )
Contracts realized or settled 49
47
Current period changes^(*)
27
(75 )
Contracts outstanding at the end of the period, assets (liabilities), net $ (24 ) $ (100 )


~~(*)~~	Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

The net hedge volumes of energy-related derivative contracts ~~were 51 million mmBtu and 82 million mmBtu as of~~for natural gas purchased (sold) at December 31, ~~2016~~2019 and ~~December 31, 2015, respectively.~~2018 for Southern Company and Southern Company Gas were as follows:



	Southern Company	Southern Company Gas
	mmBtu Volume (in millions)
At December 31, 2019:
Commodity – Natural gas swaps	327	—
Commodity – Natural gas options	262	218
Total hedge volume	589	218

At December 31, 2018:
Commodity – Natural gas swaps	287	—
Commodity – Natural gas options	144	120
Total hedge volume	431	120

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

~~Gulf Power~~Southern Company ~~2016~~and Subsidiary Companies 2019 Annual Report

Southern Company Gas' derivative contracts are comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. The volumes presented above for Southern Company Gas represent the net of long natural gas positions of 4.10 billion mmBtu and short natural gas positions of 3.88 billion mmBtu at December 31, 2019 and the net of long natural gas positions of 4.16 billion mmBtu and short natural gas positions of 4.04 billion mmBtu at December 31, 2018.

For the Southern Company system, the weighted average swap contract cost above market prices was approximately ~~$0.48~~$0.28 and $0.12 per mmBtu ~~as of~~at December 31, ~~2016~~2019 and ~~$1.17 per mmBtu as~~2018, respectively. The change in option fair value is primarily attributable to the volatility of ~~December 31, 2015. Natural~~the market and the underlying change in the natural gas ~~settlements~~price. Substantially all of the traditional electric operating companies' natural gas hedge gains and losses are recovered through ~~the Company's~~their respective fuel cost recovery ~~clause.~~clauses.

At December 31, ~~2016~~2019 and ~~2015~~,2018, substantially all of the ~~Company's~~traditional electric operating companies' and certain of the natural gas distribution utilities' energy-related derivative contracts were designated as regulatory hedges and were related to the ~~Company's~~applicable company's fuel-hedging program. ~~Therefore, gains~~Gains and losses associated with regulatory hedges are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel ~~expense~~expense/cost of natural gas as they are recovered through ~~the fuel~~their respective cost recovery clause. Gains and losses on energy-related derivatives designated as cash flow hedges, which are used to hedge anticipated purchases and sales, are initially deferred in AOCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as ~~incurred~~incurred. See Note 14 to the financial statements for additional information.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and ~~were not material for~~this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any ~~year presented~~cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual ~~cost~~price of ~~fuel is recovered through~~ the ~~retail fuel clause. The moratorium imposed by the Florida PSC does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program.~~underlying goods being delivered.

The ~~Company uses~~Registrants use over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. In addition, Southern Company Gas uses exchange-traded market-observable contracts, which are categorized as Level 1, and contracts that include a combination of observable and unobservable components, which are categorized as Level 3. See Note 913 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts ~~which are all Level 2 of the fair value hierarchy,~~for Southern Company and Southern Company Gas at December 31, ~~2016~~2019 were as follows:

Fair Value Measurements
December 31, 2016
Total Maturity
Fair Value Year 1 Years 2&3 Years 4&5
(in millions)
Level 1 $ —
$ —
$ —
$ —
Level 2 (24 ) (8 ) (16 ) —
Level 3 —
—
—
—
Fair value of contracts outstanding at end of period $ (24 ) $ (8 ) $ (16 ) $ —



	Fair Value Measurements of Contracts at
	December 31, 2019
	Total Fair Value			Maturity
	Total Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Southern Company
Level 1^(a)	$	(53	)	$	(19	)	$	(37	)	$	3
Level 2^(b)	18			42			(25		)	1
Level 3	14			10			1			3
Southern Company total^(c)	$	(21	)	$	33		$	(61	)	$	7

Southern Company Gas
Level 1^(a)	$	(53	)	$	(19	)	$	(37	)	$	3
Level 2^(b)	111			98			11			2
Level 3	14			10			1			3
Southern Company Gas total^(c)	$	72		$	89		$	(25	)	$	8


(a)	Valued using NYMEX futures prices.


(b)	Level 2 amounts for Southern Company Gas are valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.


(c)	Excludes cash collateral of $99 million as well as premium and associated intrinsic value associated with weather derivatives of $4 million at December 31, 2019.

The ~~Company is~~Registrants are exposed to ~~market price~~ risk in the event of nonperformance by counterparties to ~~the~~ energy-related and interest rate derivative ~~contracts.~~contracts, as applicable. The ~~Company~~Registrants only ~~enters~~enter into agreements and material transactions with counterparties that have

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

investment grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the ~~Company does~~Registrants do not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under ~~"Financial Instruments"~~"Financial Instruments" and Note 1014 to the financial statements.

~~Through 2015, long-term non-affiliate capacity sales from~~Southern Company performs periodic reviews of its leveraged lease transactions, both domestic and international, and the ~~Company's ownership of Plant Scherer Unit 3 provided the majority~~creditworthiness of the ~~Company's wholesale earnings. Contract expirations at the end of 2015 and the end of May 2016 related to Plant Scherer Unit 3 wholesale sales had~~lessees, including a ~~material negative impact on the Company's earnings in 2016. Remaining contract sales from Plant Scherer Unit 3 cover approximately 24%~~review of the Company's ownership of the unit through 2019. The Company has requested recovery through retail rates for the portion of Plant Scherer Unit 3 that has been rededicated to serving retail customers. Therefore, the retail recoverability of these costs will be decided in the 2016 Rate Case. If retail recovery of Plant Scherer Unit 3 is not approved by the Florida PSC in the 2016 Rate Case, the Company may consider an asset sale. The current book value of the underlying leased assets and the credit ratings of the lessees. Southern Company's ~~ownership~~domestic lease transactions generally do not have any credit enhancement mechanisms; however, the lessees in its international lease transactions have pledged various deposits as additional security to secure the obligations. The lessees in Southern Company's international lease transactions are also required to provide additional collateral in the event of ~~Plant Scherer Unit 3 could exceed market value which could result in~~ a ~~material loss.~~credit downgrade below a certain level. See ~~Note~~Notes 1 and 3 to the financial statements under ~~"Retail Regulatory~~"Leveraged Leases" and "Other Matters – ~~Retail Base Rate Cases"~~Southern Company," respectively, for additional information.

Southern Company Gas Value at Risk (VaR)

VaR is the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. Southern Company Gas' VaR may not be comparable to that of other companies due to differences in the factors used to calculate VaR. Southern Company Gas' VaR is determined on a 95% confidence interval and a one-day holding period, which means that 95% of the time, the risk of loss in a day from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated. The open exposure of Southern Company Gas is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management. Because Southern Company Gas generally manages physical gas assets and economically protects its positions by hedging in the futures markets, Southern Company Gas' open exposure is generally mitigated. Southern Company Gas employs daily risk testing, using both VaR and stress testing, to evaluate the risk of its positions.

Southern Company Gas actively monitors open commodity positions and the resulting VaR and maintains a relatively small risk exposure as total buy volume is close to sell volume, with minimal open natural gas price risk. Based on a 95% confidence interval and employing a one-day holding period, SouthStar's portfolio of positions for all periods presented was immaterial.

Southern Company Gas' wholesale gas services segment had the following VaRs at December 31:



	2019		2018		2017
	(in millions)
Period end^(*)	$	2.6	$	6.4	$	4.8
Average	3.4		3.7		2.0
High^(*)	7.0		11.7		4.8
Low	2.1		1.2		1.0


(*)	The increase in VaR at December 31, 2018 reflects significant natural gas price increases in Sequent's key markets driven by an industry-wide lower-than-normal natural gas storage inventory position and colder-than-normal weather in the middle of fourth quarter 2018. As weather and natural gas prices moderated subsequent to December 31, 2018, VaR reduced.

Credit Risk

Southern Company (except as discussed herein), the traditional electric operating companies, and Southern Power are not exposed to any concentrations of credit risk. Southern Company Gas' exposure to concentrations of credit risk is discussed herein.

Southern Company Gas

Gas Distribution Operations

Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 16 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The provisions of Atlanta Gas Light's tariff allow Atlanta Gas Light to obtain credit security support in an amount equal to a minimum of two times a Marketer's highest month's estimated bill from Atlanta Gas Light. For 2019, the four largest Marketers based on customer count, which includes SouthStar, accounted for 21% of Southern Company Gas' adjusted operating margin and 27% of adjusted operating margin for Southern Company Gas' gas distribution operations segment.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Several factors are designed to mitigate Southern Company Gas' risks from the increased concentration of credit that has resulted from deregulation. In addition to the security support described above, Atlanta Gas Light bills intrastate delivery service to Marketers in advance rather than in arrears. Atlanta Gas Light accepts credit support in the form of cash deposits, letters of credit/surety bonds from acceptable issuers, and corporate guarantees from investment-grade entities. Southern Company Gas reviews the adequacy of credit support coverage, credit rating profiles of credit support providers, and payment status of each Marketer. Southern Company Gas believes that adequate policies and procedures are in place to properly quantify, manage, and report on Atlanta Gas Light's credit risk exposure to Marketers.

Atlanta Gas Light also faces potential credit risk in connection with assignments of interstate pipeline transportation and storage capacity to Marketers. Although Atlanta Gas Light assigns this capacity to Marketers, in the event that a Marketer fails to pay the interstate pipelines for the capacity, the interstate pipelines would likely seek repayment from Atlanta Gas Light.

Wholesale Gas Services

Southern Company Gas has established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. Southern Company Gas also utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions.

Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary. Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for a counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.

Certain of Southern Company Gas' derivative instruments contain credit-risk-related or other contingent features that could increase the payments for collateral it posts in the normal course of business when its financial instruments are in net liability positions. At December 31, 2019, for agreements with such features, Southern Company Gas' derivative instruments with liability fair values were immaterial and Southern Company Gas had no collateral posted with derivatives counterparties to satisfy these arrangements.

Southern Company Gas has a concentration of credit risk as measured by its 30-day receivable exposure plus forward exposure. At December 31, 2019, the top 20 counterparties of Southern Company Gas' wholesale gas services segment represented approximately 59%, or $218 million, of its total counterparty exposure and had a weighted average S&P equivalent credit rating of A-, all of which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody's ratings to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody's, respectively, and 1 being D / Default by S&P and Moody's, respectively. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios of that counterparty. To arrive at the weighted average credit rating, each counterparty is assigned an internal ratio, which is multiplied by their credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties' exposures, and this numeric value is then converted to a S&P equivalent.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

The following table provides credit risk information related to Southern Company Gas' third-party natural gas contracts receivable and payable positions at December 31:



	Gross Receivables				Gross Payables
	2019		2018		2019		2018
	(in millions)				(in millions)
Netting agreements in place:
Counterparty is investment grade	$	238	$	461	$	127	$	255
Counterparty is non-investment grade	1		5		43		95
Counterparty has no external rating	175		314		272		505
No netting agreements in place:
Counterparty is investment grade	14		19		—		1
Counterparty has no external rating	—		2		—		—
Amount recorded in balance sheets	$	428	$	801	$	442	$	856

Gas Marketing Services

Southern Company Gas obtains credit scores for its firm residential and small commercial customers using a national credit reporting agency, enrolling only those customers that meet or exceed Southern Company Gas' credit threshold. Southern Company Gas considers potential interruptible and large commercial customers based on reviews of publicly available financial statements and commercially available credit reports. Prior to entering into a physical transaction, Southern Company Gas also assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements.

Capital Requirements

Total estimated capital expenditures for the Registrants through 2024 based on their current construction programs are as follows:



	2020		2021		2022		2023		2024
	(in billions)
Southern Company^(a)(b)(c)(d)	$	8.7	$	7.3	$	6.8	$	6.8	$	6.2
Alabama Power^(b)	2.1		1.8		1.8		1.8		1.6
Georgia Power^(c)	4.1		3.4		3.0		2.8		2.7
Mississippi Power	0.3		0.2		0.2		0.3		0.2
Southern Power^(d)	0.3		0.2		0.1		0.1		0.1
Southern Company Gas	1.8		1.6		1.6		1.7		1.6


(a)	Includes the Subsidiary Registrants, as well the other subsidiaries.


(b)	Includes amounts contingent upon approval by the Alabama PSC related to Alabama Power's September 6, 2019 CCN filing totaling $0.5 billion for 2020, $0.2 billion for 2021, $0.3 billion for 2022, and $0.1 billion for 2023. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power – Petition for Certificate of Convenience and Necessity" herein for additional information.


(c)	These amounts include expenditures of approximately $1.6 billion, $0.9 billion, and $0.3 billion for the construction of Plant Vogtle Units 3 and 4 in 2020, 2021, and 2022, respectively.


(d)	These amounts do not include approximately $0.5 billion per year for 2020 through 2024 for Southern Power's planned expenditures for plant acquisitions and placeholder growth, which may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy.

These amounts include estimated capital expenditures to comply with environmental laws and ~~Contractual Obligations~~

~~The construction program~~regulations, but do not include any potential compliance costs associated with pending regulation of ~~the Company is currently estimated to total $227 million~~CO₂ emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters" herein for ~~2017, $218 million for 2018, $219 million for 2019, $265 million for 2020, and $225 million for 2021.~~additional information. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel (for Southern Company, Alabama Power, and Georgia Power) and capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental statutes and regulations included in these amounts are $33 million, $52 million, $57 million, $55 million, and $48 million for 2017, 2018, 2019, 2020, and 2021, respectively. These estimated expenditures do not include any potential compliance costs that may arise from the EPA's final rules and guidelines or future state plans that would limit CO₂ emissions from new, existing, modified, or reconstructed fossil-fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" and "– Global Climate Issues" herein for additional information.LTSAs.

The ~~Company~~traditional electric operating companies also ~~anticipates~~anticipate costs associated with closure and monitoring of ash ponds ~~at Plant Scholz~~ and landfills in accordance with the CCR Rule and the related state rules, which are reflected in the ~~Company's~~applicable Registrants' ARO liabilities. ~~These costs, which could change as the Company continues to refine its assumptions underlying the~~Alabama Power's cost estimates ~~and evaluate the method and timing~~are based on closure-in-place for all of ~~compliance activities, are estimated~~its ash ponds. The cost estimates for Georgia

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

~~Gulf Power~~Southern Company ~~2016~~and Subsidiary Companies 2019 Annual Report

Power and Mississippi Power are based on a combination of closure-in-place for some ash ponds and closure by removal for others. These anticipated costs are likely to ~~be $16 million, $17 million, $6 million, $26 million,~~change, and ~~$8 million for the years 2017, 2018, 2019, 2020,~~could change materially, as assumptions and ~~2021, respectively.~~details pertaining to closure are refined and compliance activities continue. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 16 to the financial statements ~~under "Asset Retirement Obligations and Other Costs of Removal"~~ for additional information. The current estimates of these costs through 2024 are as follows:



	2020		2021		2022		2023		2024
	(in millions)
Southern Company	$	498	$	551	$	742	$	916	$	967
Alabama Power	200		217		284		363		386
Georgia Power	265		289		391		475		530
Mississippi Power	23		29		24		23		20

The construction ~~program is~~programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; ~~storm impacts;~~ changes in environmental ~~statutes~~laws and regulations; the outcome of any legal challenges to ~~the~~ environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; ~~changes in FERC rules and regulations; Florida PSC approvals;~~ changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, Southern Power's planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 15 to the financial statements under "Southern Power" for additional information regarding Southern Power's plant acquisitions and construction projects.

~~In addition, as discussed~~The construction program of Georgia Power also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. See Note 2 to the financial statements ~~the Company provides postretirement benefits to substantially all employees~~under "Georgia Power – Nuclear Construction" for information regarding Plant Vogtle Units 3 and ~~funds trusts to the extent required by the FERC~~4 and ~~the Florida PSC.~~additional factors that may impact construction expenditures.

~~Other~~See FUTURE EARNINGS POTENTIAL – "Construction Programs" herein for additional information. Also see "Contractual Obligations" herein for information regarding other future funding requirements ~~related to obligations associated with scheduled maturities~~ of ~~long-term debt, as well as~~ the related interest, derivative obligations, preference stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 10 to the financial statements for additional information.Registrants.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

~~Gulf Power~~Southern Company ~~2016~~and Subsidiary Companies 2019 Annual Report

Contractual Obligations

~~Contractual~~The following tables present the Registrants' contractual obligations at December 31, ~~2016 were as follows:~~2019. Additional information about these funding requirements is provided herein.

2017
2018-
2019

2020-
2021

After
2021
Total
(in millions)
Long-term debt^(a) –

Principal $ 87
$ —
$ 175
$ 824
$ 1,086
Interest 42
73
65
515
695
Financial derivative obligations^(b)
12
17
—
—
29
Preference stock dividends^(c)
9
18
18
—
45
Operating leases^(d)
8
7
—
1
16
Purchase commitments –
Capital^(e)
227
437
462
—
1,126
Fuel^(f)
261
290
162
70
783
Purchased power^(g)
126
261
271
1,044
1,702
Other^(h)
8
24
34
136
202
Pension and other postretirement benefit plans⁽ⁱ⁾
5
11
—
—
16
Total $ 785
$ 1,138
$ 1,187
$ 2,590
$ 5,700



Southern Company	2020		2021-2022		2023-2024		After 2024		Total
	(in millions)
Long-term debt –
Principal	$	2,971	$	5,189	$	2,890	$	33,489	$	44,539
Interest	1,677		3,109		2,809		25,986		33,581
Financial derivative obligations	450		204		65		—		719
Operating leases	294		543		386		1,609		2,832
Finance leases	31		47		33		246		357
Pipeline charges, storage capacity, and gas supply	725		1,085		784		1,677		4,271
Purchase commitments –
Capital	7,758		12,981		11,989				32,728
Fuel	2,787		3,491		1,527		4,546		12,351
Purchased power	150		270		237		1,725		2,382
Other	406		618		530		2,174		3,728
ARO settlements	498		1,293		1,883				3,674
Other^(*)	163		310		38		65		576
Southern Company system total	$	17,910	$	29,140	$	23,171	$	71,517	$	141,738


~~(a)~~(*)	Includes funding requirements related to pension and other postretirement benefit plans, nuclear decommissioning trusts of Georgia Power, and preferred stock dividends of Alabama Power.



Alabama Power	2020		2021-2022		2023-2024		After 2024		Total
	(in millions)
Long-term debt –
Principal	$	250	$	1,060	$	321	$	6,956	$	8,587
Interest	338		649		578		4,985		6,550
Preferred stock dividends	15		29		29		—		73
Financial derivative obligations	14		10		—		—		24
Operating leases	54		105		5		1		165
Finance leases	1		2		1		—		4
Purchase commitments –
Capital	1,502		2,891		2,927				7,320
Fuel	959		1,226		465		808		3,458
Purchased power	35		75		77		446		633
Other	39		81		62		243		425
ARO settlements	200		501		749				1,450
Pension and other postretirement benefit plans	14		28						42
Alabama Power total	$	3,421	$	6,657	$	5,214	$	13,439	$	28,731

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report



Georgia Power	2020		2021-2022		2023-2024		After 2024		Total
	(in millions)
Long-term debt –
Principal	$	1,014	$	906	$	628	$	9,236	$	11,784
Interest	384		715		668		5,070		6,837
Financial derivative obligations	49		21		—		—		70
Operating leases	205		395		359		831		1,790
Finance leases	28		49		50		134		261
Purchase commitments –
Capital	3,805		6,080		4,966				14,851
Fuel	1,091		1,401		629		3,610		6,731
Purchased power	56		117		123		862		1,158
Other	117		121		133		205		576
ARO settlements	265		680		1,006				1,951
Nuclear decommissioning trust	5		9		9		65		88
Pension and other postretirement benefit plans	50		93						143
Georgia Power total	$	7,069	$	10,587	$	8,571	$	20,013	$	46,240



Mississippi Power	2020		2021-2022		2023-2024		After 2024		Total
	(in millions)
Long-term debt –
Principal	$	282	$	270	$	—	$	1,026	$	1,578
Interest	68		102		83		542		795
Financial derivative obligations	15		11		1		—		27
Operating leases	2		2		1		2		7
Purchase commitments –
Capital	255		397		402				1,054
Fuel	313		312		169		108		902
Purchased power	17		36		37		417		507
Other	28		58		69		230		385
ARO settlements	23		53		44				120
Pension and other postretirement benefits plans	7		14						21
Mississippi Power total	$	1,010	$	1,255	$	806	$	2,325	$	5,396



Southern Power	2020		2021-2022		2023-2024		After 2024		Total
	(in millions)
Long-term debt –
Principal	$	825	$	977	$	290	$	2,339	$	4,431
Interest	163		278		222		1,302		1,965
Financial derivative obligations	3		—		—		—		3
Operating leases	29		50		52		888		1,019
Purchase commitments –
Capital	251		306		294				851
Fuel	424		552		265		20		1,261
Purchased power	42		42		—		—		84
Other	159		296		239		1,481		2,175
Southern Power total	$	1,896	$	2,501	$	1,362	$	6,030	$	11,789

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report



Southern Company Gas	2020		2021-2022		2023-2024		After 2024		Total
	(in millions)
Long-term debt –
Principal	$	—	$	376	$	400	$	4,659	$	5,435
Interest	235		458		425		3,213		4,331
Financial derivative obligations	369		161		66		—		596
Operating leases	18		31		21		44		114
Pipeline charges, storage capacity, and gas supply	725		1,085		784		1,677		4,271
Purchase commitments –
Capital	1,775		3,191		3,335				8,301
Other	31		14		1		—		46
Pension and other postretirement benefit plans	16		29						45
Southern Company Gas total	$	3,169	$	5,345	$	5,032	$	9,593	$	23,139

Additional information about these funding requirements is provided below:

•

Long-term debt – Represents scheduled maturities of long-term debt, as well as the related interest. All amounts are reflected based on final maturity ~~dates.~~dates except for amounts related to Georgia Power's FFB borrowings. The final maturity date for Georgia Power's FFB borrowings is February 20, 2044; however, principal amortization is reflected beginning in February 2020. The interest amounts also include the effects of interest rate derivatives employed to manage interest rate risk and effects of foreign currency swaps employed to manage foreign currency exchange rate risk, as applicable. For Southern Company ~~plans~~and Southern Power, debt principal includes a $5 million loss related to Southern Power's foreign currency hedge of €1.1 billion. The Registrants plan to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates ~~as of January 1, 2017,~~at December 31, 2019, as reflected in the statements of ~~capitalization. Fixed rates include, where applicable,~~capitalization for each Registrant. Long-term debt excludes finance lease amounts, which are shown separately. See Note 8 to the ~~effects of interest rate derivatives employed to manage interest rate risk.~~financial statements for additional information.


~~(b)~~•	~~Includes~~ Financial derivative ~~liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 10~~obligations – See Note 14 to the financial ~~statements.~~statements for additional information.

~~(c)~~•

~~Preference stock does not mature; therefore,~~

Operating and finance leases – See Note 9 to the financial statements for additional information. Operating lease commitments may include certain land leases for facilities that may be subject to annual price escalation based on indices. Estimated lease payments for Southern Company and Alabama Power exclude amounts ~~are provided~~contingent upon approval by the Alabama PSC related to Alabama Power's September 6, 2019 CCN filing totaling $1 million for 2021, $2 million for 2022, $3 million for 2023, $4 million for 2024, and $85 million for after 2024. See Note 2 to the ~~next five years only.~~financial statements under "Alabama Power – Petition for Certificate of Convenience and Necessity" for additional information.


~~(d)~~•	~~Excludes a PPA accounted for as a lease, which is included in "Purchased power."~~

~~(e)~~

~~The Company provides estimated~~

Purchase commitments – Capital – Estimated capital expenditures are provided for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel, capital expenditures covered under ~~long-term service agreements,~~LTSAs, and estimated capital expenditures for AROs, which are reflected in ~~"Other.~~the "fuel," "other," and "ARO settlements" categories, respectively, where applicable. Estimated capital expenditures for Southern Company and Alabama Power exclude amounts contingent upon approval by the Alabama PSC related to Alabama Power's September 6, 2019 CCN filing totaling $0.5 billion for 2020, $0.2 billion for 2021, $0.3 billion for 2022, and $0.1 billion for 2023. See Note 2 to the financial statements under "Alabama Power – Petition for Certificate of Convenience and Necessity" for additional information. Estimated capital expenditures for Southern Company and Southern Power exclude approximately $0.5 billion per year for 2020 through 2024 for Southern Power's planned expenditures for plant acquisitions and placeholder growth. At December 31, ~~2016,~~2019, significant purchase commitments were outstanding in connection with the Registrants' construction ~~program.~~programs. See FUTURE EARNINGS POTENTIAL ~~– "Environmental~~�� "Environmental Matters ~~– Environmental Statutes~~" and ~~Regulations"~~"Construction Programs" herein and "Capital Requirements" herein for additional information.

~~(f)~~•

~~Includes~~

Purchase commitments – Fuel – Primarily includes commitments to purchase coal ~~and~~(for the traditional electric operating companies), natural gas (for the traditional electric operating companies and Southern Power), and nuclear fuel (for Alabama Power and Georgia Power), as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the ~~New York Mercantile Exchange~~NYMEX future prices at December 31, ~~2016.~~2019.

~~(g)~~•

~~The~~

Purchase commitments – Purchased power – Represents estimated minimum obligations for various PPAs for the purchase of capacity and ~~transmission~~energy, as well as, for Georgia Power, capacity payments related ~~costs associated with~~to Plant Vogtle Units 1 and 2. Amounts exclude PPAs accounted for as leases, which are ~~recovered through~~reflected in the ~~purchased power capacity clause. Energy costs associated with PPAs are recovered through the fuel clause. See Notes 3~~"operating leases" and ~~7 to the financial statements for additional information.~~"finance leases" categories, where applicable.

Table of ContentsIndex to Financial Statements

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2019 Annual Report

Estimated capacity payments for Southern Company and Alabama Power exclude amounts contingent upon approval by the Alabama PSC related to Alabama Power's September 6, 2019 CCN filing totaling $4 million for 2020, $7 million for 2021, $7 million for 2022, $8 million for 2023, $8 million for 2024, and $107 million for after 2024. See Note 2 to the financial statements under "Alabama Power – Petition for Certificate of Convenience and Necessity" for additional information. Mississippi Power's long-term PPAs are associated with solar facilities and only include an energy component. Southern Power's purchased power commitments will be resold under a third-party agreement at cost. See Note 3 to the financial statements under "Guarantees" for additional information.

~~(h)~~•

Purchase commitments – Other – Includes ~~long-term service agreements and~~LTSAs (for all Registrants), contracts for the procurement of ~~limestone. Long-term service~~limestone (for Alabama Power and Georgia Power), contractual environmental remediation liabilities (for Southern Company Gas), operation and maintenance agreements (for Southern Power), and transmission agreements (for Southern Power). LTSAs include price escalation based on inflation indices. ~~Limestone costs~~Southern Power's transmission commitments are ~~recovered through~~based on the ~~environmental cost recovery clause. See Note 3 to the financial statements~~Southern Company system's current tariff rate for ~~additional information.~~point-to-point transmission.

~~(i)~~•

Pension and other postretirement benefit plans – The Southern Company ~~forecasts~~system provides postretirement benefits to the majority of its employees and funds trusts to the extent required by PSCs, other applicable state regulatory agencies, or the FERC. The Registrants forecast contributions to ~~the~~their pension and other postretirement benefit plans over a three-year period. The ~~Company anticipates~~Registrants anticipate no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from corporate assets of the ~~Company's corporate assets.~~applicable subsidiaries. See Note 211 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from corporate assets of the ~~Company's corporate assets.~~applicable subsidiaries.

•

ARO settlements – Represents estimated costs for a five-year period associated with closing and monitoring ash ponds at the traditional electric operating companies in accordance with the CCR Rule and the related state rules, which are reflected in the applicable Registrants' ARO liabilities. Material expenditures in future years for ARO settlements also will be required for ash ponds, nuclear decommissioning (for Alabama Power and Georgia Power), and other liabilities reflected in the applicable Registrants' AROs. See Note 6 to the financial statements for additional information.


•	Preferred stock dividends – Represents preferred stock of Alabama Power. Preferred stock does not mature; therefore, amounts are provided for the next five years only.

•

Nuclear decommissioning trusts – As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs. Based on its most recent site study completed in 2018, Alabama Power currently has no additional funding requirements. Alabama Power's next site study is expected to be conducted by 2023. Georgia Power's projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2019 ARP. See Note 6 to the financial statements under "Nuclear Decommissioning" for additional information.

•

Pipeline charges, storage capacity, and gas supply – Includes charges at Southern Company Gas recoverable through a natural gas cost recovery mechanism, or alternatively billed to Marketers selling retail natural gas, and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 45 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2019 and valued at $84 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries, including SouthStar, in support of payment obligations.

Table of ContentsIndex to Financial Statements


Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO 2019 FINANCIAL STATEMENTS



	Page
The Southern Company and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm	II-124
Consolidated Statements of Income for the Years Ended December 31, 2019, 2018, and 2017	II-128
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2019, 2018, and 2017	II-129
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018, and 2017	II-130
Consolidated Balance Sheets at December 31, 2019 and 2018	II-131
Consolidated Statements of Capitalization at December 31, 2019 and 2018	II-133
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2019, 2018, and 2017	II-135

Alabama Power:
Report of Independent Registered Public Accounting Firm	II-136
Statements of Income for the Years Ended December 31, 2019, 2018, and 2017	II-137
Statements of Comprehensive Income for the Years Ended December 31, 2019, 2018, and 2017	II-138
Statements of Cash Flows for the Years Ended December 31, 2019, 2018, and 2017	II-139
Balance Sheets at December 31, 2019 and 2018	II-140
Statements of Capitalization at December 31, 2019 and 2018	II-142
Statements of Common Stockholder's Equity for the Years Ended December 31, 2019, 2018, and 2017	II-143

Georgia Power:
Report of Independent Registered Public Accounting Firm	II-144
Statements of Income for the Years Ended December 31, 2019, 2018, and 2017	II-145
Statements of Comprehensive Income for the Years Ended December 31, 2019, 2018, and 2017	II-146
Statements of Cash Flows for the Years Ended December 31, 2019, 2018, and 2017	II-147
Balance Sheets at December 31, 2019 and 2018	II-148
Statements of Capitalization at December 31, 2019 and 2018	II-150
Statements of Common Stockholder's Equity for the Years Ended December 31, 2019, 2018, and 2017	II-151

Mississippi Power:
Report of Independent Registered Public Accounting Firm	II-152
Statements of Operations for the Years Ended December 31, 2019, 2018, and 2017	II-153
Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2019, 2018, and 2017	II-154
Statements of Cash Flows for the Years Ended December 31, 2019, 2018, and 2017	II-155
Balance Sheets at December 31, 2019 and 2018	II-156
Statements of Capitalization at December 31, 2019 and 2018	II-158
Statements of Common Stockholder's Equity for the Years Ended December 31, 2019, 2018, and 2017	II-159

Table of ContentsIndex to Financial Statements



	Page
Southern Power and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm	II-160
Consolidated Statements of Income for the Years Ended December 31, 2019, 2018, and 2017	II-161
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2019, 2018, and 2017	II-162
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018, and 2017	II-163
Consolidated Balance Sheets at December 31, 2019 and 2018	II-164
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2019, 2018, and 2017	II-166

Southern Company Gas and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm	II-167
Consolidated Statements of Income for the Years Ended December 31, 2019, 2018, and 2017	II-168
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2019, 2018, and 2017	II-169
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018, and 2017	II-170
Consolidated Balance Sheets at December 31, 2019 and 2018	II-171
Consolidated Statements of Capitalization at December 31, 2019 and 2018	II-173
Consolidated Statements of Common Stockholder's Equity for the Years Ended December 31, 2019, 2018, and 2017	II-174

Combined Notes to Financial Statements	II-175

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~Table of ContentsIndex to Financial Statements

~~Cautionary Statement Regarding Forward-Looking~~

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of The Southern Company and Subsidiary Companies

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of The ~~Company's 2016 Annual Report contains forward-looking statements. Forward-looking~~Southern Company and subsidiary companies (Southern Company) as of December 31, 2019 and 2018, the related consolidated statements ~~include, among other things, statements concerning retail rates, customer~~of income, comprehensive income, stockholders' equity, and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projectionscash flows for the qualified pension plan and postretirement benefit plans contributions, financing activities, start and completion of construction projects, filings with state and federal regulatory authorities, impacteach of the ~~PATH Act, federal income tax benefits, estimated sales~~three years in the period ended December 31, 2019, and ~~purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such~~the related notes (collectively referred to as ~~"may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or~~ the ~~negative~~"financial statements"). We also have audited Southern Company's internal control over financial reporting as of ~~these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested~~December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the ~~forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:~~

~~the impact~~Committee of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which the Company is subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;

~~current and future litigation, regulatory investigations, proceedings, or inquiries;~~

~~the effects, extent, and timing~~Sponsoring Organizations of the ~~entry~~Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of ~~additional competition~~Southern Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the ~~markets~~period ended December 31, 2019, in ~~which~~conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, Southern Company ~~operates;~~maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

~~variations~~Basis for Opinions

Southern Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in ~~demand for electricity, including those relating~~the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to ~~weather,~~express an opinion on these financial statements and an opinion on Southern Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the ~~general economy~~Public Company Accounting Oversight Board (United States) (PCAOB) and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

~~available sources and costs of fuels;~~

~~effects of inflation;~~

~~the ability~~are required to ~~control costs and avoid cost overruns during the development and construction of facilities,~~be independent with respect to ~~construct facilities~~Southern Company in accordance with the ~~requirements of permits~~U.S. federal securities laws and ~~licenses,~~the applicable rules and ~~to satisfy any environmental performance standards;~~

~~investment performance~~regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Table of ContentsIndex to Financial Statements

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the Audit Committee of Southern Company's ~~employee~~Board of Directors and ~~retiree benefit plans;~~that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

~~advances~~Impact of Rate Regulation on the Financial Statements – Refer to Note 1 (Summary of Significant Accounting Policies – Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters) to the financial statements

Critical Audit Matter Description

Southern Company's traditional electric operating companies and natural gas distribution utilities (the "regulated utility subsidiaries"), which represent approximately 87% of Southern Company's consolidated operating revenues for the year ended December 31, 2019 and 84% of its consolidated total assets at December 31, 2019, are subject to rate regulation by their respective state Public Service Commissions or other applicable state regulatory agencies and wholesale regulation by the Federal Energy Regulatory Commission (the "Commissions"). Management has determined that the regulated utility subsidiaries meet the requirements under accounting principles generally accepted in ~~technology;~~the United States of America to utilize specialized rules to account for the effects of rate regulation in the preparation of its financial statements. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, including, but not limited to, property, plant, and equipment; other regulatory assets; other regulatory liabilities; other cost of removal obligations; deferred charges and credits related to income taxes; under and over recovered regulatory clause revenues; operating revenues; operations and maintenance expenses; and depreciation.

~~state~~The Commissions set the rates the regulated utility subsidiaries are permitted to charge customers based on allowable costs, including a reasonable return on equity. Rates are determined and ~~federal~~approved in regulatory proceedings based on an analysis of the applicable regulated subsidiary's costs to provide utility service and a return on, and recovery of, its investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate ~~regulations~~of return earned on investments, and the timing and amount of assets to be recovered by rates. The Commissions' regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. While Southern Company's regulated utility subsidiaries expect to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.

We identified the impact of ~~pending~~rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures (e.g., asset retirement costs, property damage reserves, and net book value of retired assets) and the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and/or (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate ~~cases~~regulation and ~~negotiations, including~~the rate ~~actions relating~~setting process due to ~~fuel~~its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

We read relevant regulatory orders issued by the Commissions for the regulated utility subsidiaries, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other ~~cost~~publicly available information to assess the likelihood of recovery ~~mechanisms;~~

~~the ability to successfully operate generating, transmission, and distribution facilities and the successful performance~~in future rates or of ~~necessary corporate functions;~~

~~internal restructuring or other restructuring options that may be pursued;~~

~~potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;~~

~~the ability of counterparties~~a future reduction in rates based on precedence of the ~~Company~~Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared it to ~~make payments as~~management's recorded regulatory asset and ~~when due and to perform as required;~~

~~the ability to obtain new short- and long-term contracts with wholesale customers;~~

~~the direct or indirect effect on the Company's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;~~

~~interest rate fluctuations and financial market conditions and the results of financing efforts;~~

~~changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;~~

~~the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;~~

~~catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;~~liability balances for completeness.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Gulf Power Company 2016 Annual Report~~

For regulatory matters in process, we inspected filings with the ~~direct~~Commissions by both Southern Company's regulated utility subsidiaries and other interested parties that may impact the regulated utility subsidiaries' future rates for any evidence that might contradict management's assertions.

We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. We tested selected costs included in the capitalized project costs for completeness and accuracy.

We obtained representation from management regarding probability of recovery for regulatory assets or ~~indirect effects on~~refund or future reduction in rates for regulatory liabilities to assess management's assertion that amounts are probable of recovery, refund, or a future reduction in rates.

We evaluated Southern Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

Disclosure of Uncertainties – Plant Vogtle Units 3 and 4 Construction – Refer to Note 2 (Regulatory Matters – Georgia Power – Nuclear Construction) to the financial statements

Critical Audit Matter Description

As discussed in Note 2 to the financial statements, the ultimate recovery of Georgia Power Company's ~~business resulting from incidents affecting~~(Georgia Power) investment in the ~~U.S. electric grid or operation~~construction of ~~generating resources;~~

Plant Vogtle Units 3 and 4 is subject to multiple uncertainties. Such uncertainties include the ~~effect~~potential impact of ~~accounting pronouncements issued periodically~~future decisions by ~~standard-setting bodies; and~~

~~other factors discussed elsewhere herein and in other reports (including~~Georgia Power's regulators (particularly the ~~Form 10-K) filed~~Georgia Public Service Commission), actions by the co-owners of the Vogtle project, and litigation or other legal proceedings involving the project. In addition, Georgia Power's ability to meet its cost and schedule forecasts could impact its capacity to fully recover its investment in the project. While the project is not subject to a cost cap, Georgia Power's cost and schedule forecasts are subject to numerous uncertainties which could impact cost recovery, including challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related craft labor productivity, particularly in the installation of electrical and mechanical commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues that could arise and change the projected schedule and estimated cost. The ultimate recovery of Georgia Power's investment in Plant Vogtle Units 3 and 4 is subject to the outcome of future assessments by management as well as Georgia Public Service Commission decisions in future regulatory proceedings.

Management has disclosed the status, risks, and uncertainties associated with Plant Vogtle Units 3 and 4, including (1) the status of construction; (2) challenges to the achievement of Georgia Power's cost and schedule forecasts; (3) the status of regulatory proceedings; (4) the status of legal actions or issues involving the co-owners of the project; and (5) other matters which could impact the ultimate recoverability of Georgia Power's investment in the project. We identified as a critical audit matter the evaluation of these disclosures which involved significant audit effort requiring specialized industry and construction expertise, extensive knowledge of rate regulation, and difficult and subjective judgments.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the disclosure of the status, risks, and uncertainties of the nuclear construction at Plant Vogtle Units 3 and 4 included the following, among others:

We tested the effectiveness of internal controls over the on-going evaluation and monitoring of the construction schedule and capital cost forecast and over the disclosure of matters related to the construction and ultimate cost recovery of Plant Vogtle Units 3 and 4.

We involved construction specialists to assist in our evaluation of Georgia Power's processes for on-going evaluation and monitoring of the construction schedule and cost forecast and to assess the disclosures of challenges to the achievement of such forecasts.

We attended meetings with Georgia Power and Southern Company ~~from time~~officials, project managers (including contractors), independent regulatory monitors, and co-owners of the project to ~~time with~~evaluate and monitor construction status and identify cost and schedule challenges.

We read reports of external independent monitors employed by the ~~SEC.~~Georgia Public Service Commission to monitor the status of construction at Plant Vogtle Units 3 and 4 to evaluate the completeness of Georgia Power's disclosure of challenges to the achievement of cost and schedule forecasts.

~~The Company expressly disclaims any obligation to update any forward-looking statements.~~

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We inquired of Georgia Power and Southern Company officials and project managers regarding the status of construction, the construction schedule, and cost forecasts to assess the financial statement disclosures with respect to project status and potential risks and uncertainties to the achievement of such forecasts.

We inspected regulatory filings and transcripts of Georgia Public Service Commission hearings regarding the construction of Plant Vogtle Units 3 and 4 to identify potential challenges to the recovery of Georgia Power's construction costs and to evaluate the disclosures with respect to such uncertainties.

We inquired of Georgia Power and Southern Company management and internal and external legal counsel regarding any potential legal actions or issues arising from project construction or issues involving the co-owners of the project.

We compared the financial statement disclosures relating to this matter to the information gathered through the conduct of all our procedures to evaluate whether there were omissions relating to significant facts or uncertainties regarding the status of construction or other factors which could impact the ultimate cost recovery of Plant Vogtle Units 3 and 4.

We obtained representation from management regarding disclosure of all matters related to the cost and/or status, including matters related to a co-owner or regulatory development, that could result in a potential disallowance of costs related to the construction of Plant Vogtle Units 3 and 4.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 19, 2020

We have served as Southern Company's auditor since 2002.

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CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, ~~2016~~2019, ~~2015~~2018, and ~~2014~~2017

~~Gulf Power~~Southern Company ~~2016~~and Subsidiary Companies 2019 Annual Report


	2016			2015			2014			2019			2018			2017
	(in millions)									(in millions)
Operating Revenues:
Retail revenues	$	1,281		$	1,249		$	1,267
Wholesale revenues, non-affiliates	61			107			129
Wholesale revenues, affiliates	75			58			130
Retail electric revenues										$	14,084		$	15,222		$	15,330
Wholesale electric revenues										2,152			2,516			2,426
Other electric revenues										636			664			681
Natural gas revenues										3,792			3,854			3,791
Other revenues	68			69			64			755			1,239			803
Total operating revenues	1,485			1,483			1,590			21,419			23,495			23,031
Operating Expenses:
Fuel	432			445			605			3,622			4,637			4,400
Purchased power, non-affiliates	126			100			82
Purchased power, affiliates	16			35			25
Purchased power										816			971			863
Cost of natural gas										1,319			1,539			1,601
Cost of other sales										435			806			513
Other operations and maintenance	336			354			341			5,600			5,889			5,739
Depreciation and amortization	172			141			145			3,038			3,131			3,010
Taxes other than income taxes	120			118			111			1,230			1,315			1,250
Estimated loss on plants under construction										24			1,097			3,362
Impairment charges										168			210			—
(Gain) loss on dispositions, net										(2,569		)	(291		)	(40		)
Total operating expenses	1,202			1,193			1,309			13,683			19,304			20,698
Operating Income	283			290			281			7,736			4,191			2,333
Other Income and (Expense):
Allowance for equity funds used during construction										128			138			160
Earnings from equity method investments										162			148			106
Interest expense, net of amounts capitalized	(47		)	(49		)	(53		)	(1,736		)	(1,842		)	(1,694		)
Other income (expense), net	(5		)	8			9			252			114			163
Total other income and (expense)	(52		)	(41		)	(44		)	(1,194		)	(1,442		)	(1,265		)
Earnings Before Income Taxes	231			249			237			6,542			2,749			1,068
Income taxes	91			92			88			1,798			449			142
Net Income	140			157			149
Dividends on Preference Stock	9			9			9
Net Income After Dividends on Preference Stock	$	131		$	148		$	140
Consolidated Net Income										4,744			2,300			926
Dividends on preferred and preference stock of subsidiaries										15			16			38
Net income (loss) attributable to noncontrolling interests										(10		)	58			46
Consolidated Net Income Attributable to Southern Company										$	4,739		$	2,226		$	842
Common Stock Data:
Earnings per share —
Basic										$	4.53		$	2.18		$	0.84
Diluted										4.50			2.17			0.84
Average number of shares of common stock outstanding — (in millions)
Basic										1,046			1,020			1,000
Diluted										1,054			1,025			1,008

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, ~~2016~~2019, ~~2015~~2018, and ~~2014~~2017

~~Gulf Power~~Southern Company ~~2016~~and Subsidiary Companies 2019 Annual Report


	2016		2015		2014		2019			2018			2017
	(in millions)						(in millions)
Net Income	$	140	$	157	$	149
Consolidated Net Income							$	4,744		$	2,300		$	926
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, and $-, respectively	1		1		—
Changes in fair value, net of tax of $(39), $(16), and $34, respectively							(115		)	(47		)	57
Reclassification adjustment for amounts included in net income, net of tax of $19, $24, and $(37), respectively							57			72			(60		)
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax of $(31), $(2), and $6, respectively							(64		)	(5		)	17
Reclassification adjustment for amounts included in net income, net of tax of $1, $5, and $(6), respectively							4			6			(23		)
Total other comprehensive income (loss)	1		1		—		(118		)	26			(9		)
Comprehensive Income	$	141	$	158	$	149
Dividends on preferred and preference stock of subsidiaries							15			16			38
Comprehensive income (loss) attributable to noncontrolling interests							(10		)	58			46
Consolidated Comprehensive Income Attributable to Southern Company							$	4,621		$	2,252		$	833

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2019, 2018, and 2017

Southern Company and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Activities:
Consolidated net income	$	4,744		$	2,300		$	926
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	3,331			3,549			3,457
Deferred income taxes	611			89			166
Utilization of federal investment tax credits	757			5			—
Allowance for equity funds used during construction	(128		)	(138		)	(160		)
Pension, postretirement, and other employee benefits	(204		)	(103		)	(84		)
Pension and postretirement funding	(1,136		)	(4		)	(2		)
Settlement of asset retirement obligations	(328		)	(244		)	(177		)
Storm damage reserve accruals	168			74			38
Stock based compensation expense	107			125			109
Estimated loss on plants under construction	15			1,093			3,179
Impairment charges	168			210			—
(Gain) loss on dispositions, net	(2,588		)	(301		)	(42		)
Other, net	102			14			(63		)
Changes in certain current assets and liabilities —
-Receivables	630			(426		)	(202		)
-Fossil fuel for generation	(120		)	123			36
-Natural gas for sale	44			49			36
-Other current assets	70			(127		)	(143		)
-Accounts payable	(693		)	291			(280		)
-Accrued taxes	117			267			(142		)
-Accrued compensation	(9		)	33			(8		)
-Retail fuel cost over recovery	62			36			(212		)
-Other current liabilities	61			30			(38		)
Net cash provided from operating activities	5,781			6,945			6,394
Investing Activities:
Business acquisitions, net of cash acquired	(50		)	(65		)	(1,054		)
Property additions	(7,555		)	(8,001		)	(7,423		)
Proceeds pursuant to the Toshiba Guarantee, net of joint owner portion	—			—			1,682
Nuclear decommissioning trust fund purchases	(888		)	(1,117		)	(811		)
Nuclear decommissioning trust fund sales	882			1,111			805
Proceeds from dispositions and asset sales	5,122			2,956			97
Cost of removal, net of salvage	(393		)	(388		)	(313		)
Change in construction payables, net	(169		)	50			259
Investments in unconsolidated subsidiaries	(148		)	(114		)	(152		)
Payments pursuant to LTSAs	(234		)	(186		)	(227		)
Other investing activities	41			(6		)	(53		)
Net cash used for investing activities	(3,392		)	(5,760		)	(7,190		)
Financing Activities:
Increase (decrease) in notes payable, net	640			(774		)	(401		)
Proceeds —
Long-term debt	5,220			2,478			5,858
Common stock	844			1,090			793
Preferred stock	—			—			250
Short-term borrowings	350			3,150			1,259
Redemptions and repurchases —
Long-term debt	(4,347		)	(5,533		)	(2,930		)
Preferred and preference stock	—			(33		)	(658		)
Short-term borrowings	(1,850		)	(1,900		)	(659		)
Distributions to noncontrolling interests	(256		)	(153		)	(119		)
Capital contributions from noncontrolling interests	196			2,551			80
Payment of common stock dividends	(2,570		)	(2,425		)	(2,300		)
Other financing activities	(157		)	(264		)	(222		)
Net cash provided from (used for) financing activities	(1,930		)	(1,813		)	951
Net Change in Cash, Cash Equivalents, and Restricted Cash	459			(628		)	155
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	1,519			2,147			1,992
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	1,978		$	1,519		$	2,147
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $74, $72, and $89 capitalized, respectively)	$	1,651		$	1,794		$	1,676
Income taxes (net of refunds)	276			172			(410		)
Noncash transactions — Accrued property additions at year-end	932			1,103			985

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and 2018

Southern Company and Subsidiary Companies 2019 Annual Report



Assets	2019			2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,975		$	1,396
Receivables —
Customer accounts receivable	1,614			1,726
Energy marketing receivable	428			801
Unbilled revenues	599			654
Under recovered fuel clause revenues	—			115
Other accounts and notes receivable	817			813
Accumulated provision for uncollectible accounts	(49		)	(50		)
Materials and supplies	1,388			1,465
Fossil fuel for generation	521			405
Natural gas for sale	479			524
Prepaid expenses	314			432
Assets from risk management activities, net of collateral	183			222
Regulatory assets – asset retirement obligations	287			—
Other regulatory assets	885			525
Assets held for sale	188			393
Other current assets	188			162
Total current assets	9,817			9,583
Property, Plant, and Equipment:
In service	105,114			103,706
Less: Accumulated depreciation	30,765			31,038
Plant in service, net of depreciation	74,349			72,668
Nuclear fuel, at amortized cost	851			875
Construction work in progress	7,880			7,254
Total property, plant, and equipment	83,080			80,797
Other Property and Investments:
Goodwill	5,280			5,315
Equity investments in unconsolidated subsidiaries	1,303			1,580
Other intangible assets, net of amortization of $280 and $235 at December 31, 2019 and December 31, 2018, respectively	536			613
Nuclear decommissioning trusts, at fair value	2,036			1,721
Leveraged leases	788			798
Miscellaneous property and investments	391			269
Total other property and investments	10,334			10,296
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,800			—
Deferred charges related to income taxes	798			794
Unamortized loss on reacquired debt	300			323
Regulatory assets – asset retirement obligations, deferred	4,094			2,933
Other regulatory assets, deferred	6,805			5,375
Assets held for sale, deferred	601			5,350
Other deferred charges and assets	1,071			1,463
Total deferred charges and other assets	15,469			16,238
Total Assets	$	118,700		$	116,914

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and 2018

Southern Company and Subsidiary Companies 2019 Annual Report



Liabilities and Stockholders' Equity	2019		2018
	(in millions)
Current Liabilities:
Securities due within one year	$	2,989	$	3,198
Notes payable	2,055		2,915
Energy marketing trade payables	442		856
Accounts payable	2,115		2,580
Customer deposits	496		522
Accrued taxes —
Accrued income taxes	—		21
Other accrued taxes	659		635
Accrued interest	474		472
Accrued compensation	992		1,030
Asset retirement obligations	504		404
Other regulatory liabilities	756		376
Liabilities held for sale	5		425
Operating lease obligations	229		—
Other current liabilities	830		852
Total current liabilities	12,546		14,286
Long-Term Debt (See accompanying statements)	41,798		40,736
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	7,888		6,558
Deferred credits related to income taxes	6,078		6,460
Accumulated deferred ITCs	2,291		2,372
Employee benefit obligations	1,814		2,147
Operating lease obligations, deferred	1,615		—
Asset retirement obligations, deferred	9,282		8,990
Accrued environmental remediation	234		268
Other cost of removal obligations	2,239		2,297
Other regulatory liabilities, deferred	256		169
Liabilities held for sale, deferred	—		2,836
Other deferred credits and liabilities	609		465
Total deferred credits and other liabilities	32,306		32,562
Total Liabilities	86,650		87,584
Redeemable Preferred Stock of Subsidiaries (See accompanying statements)	291		291
Total Stockholders' Equity (See accompanying statements)	31,759		29,039
Total Liabilities and Stockholders' Equity	$	118,700	$	116,914
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CAPITALIZATION

At December 31, 2019 and 2018

Southern Company and Subsidiary Companies 2019 Annual Report



	Weighted Average Interest Rate at December 31, 2019	2019			2018			2019		2018
		(in millions)						(percent of total)
Long-Term Debt:
Long-term debt payable to affiliated trusts —
Variable rate due 2042	5.20%	$	206		$	206
Long-term senior notes and debt —
Maturity
2019	—	—			2,948
2020	2.43%	2,100			2,271
2021	2.70%	2,672			2,638
2022	2.53%	1,870			1,983
2023	3.05%	2,290			2,290
2024	2.20%	400			—
2025 through 2049	4.27%	20,120			19,895
Variable rate due 2020	2.50%	800			1,875
Variable rate due 2021	2.42%	125			125
Total long-term senior notes and debt		30,377			34,025
Other long-term debt —
Pollution control revenue bonds —
Maturity
2019	—	—			25
2022	2.35%	53			90
2023	—	—			33
2025 through 2053	2.40%	1,466			1,112
Variable rate due 2020	1.80%	7			148
Variable rate due 2021	1.75%	65			65
Variable rate due 2022	—	—			4
Variable rate due 2024	1.72%	21			21
Variable rate due 2025 to 2052	1.69%	1,351			1,396
Plant Daniel revenue bonds due 2021	7.13%	270			270
FFB loans —
Maturity
2020	3.20%	64			44
2021	3.20%	64			44
2022	3.20%	64			44
2023	3.20%	64			44
2024	3.20%	64			44
2025 to 2044	3.20%	3,523			2,405
First mortgage bonds —
Maturity
2019	—	—			50
2023	5.80%	50			50
2026 to 2059	3.94%	1,525			1,225
Junior subordinated notes due 2024	2.70%	863			—
Junior subordinated notes due 2027 to 2077	5.00%	4,433			3,570
Total other long-term debt		13,947			10,684
Unamortized fair value adjustment of long-term debt		430			474
Finance lease obligations		226			197
Unamortized debt premium (discount), net		(152		)	(158		)
Unamortized debt issuance expense		(247		)	(208		)
Total long-term debt		44,787			45,220
Less:
Amount due within one year		2,989			3,198
Amount held for sale		—			1,286
Long-term debt excluding amounts due within one year and held for sale		41,798			40,736			56.6	%	58.1	%

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 2019 and 2018 Southern Company and Subsidiary Companies 2019 Annual Report
	2019			2018			2019		2018
	(in millions)						(percent of total)
Redeemable Preferred Stock of Subsidiaries:
Cumulative preferred stock
$100 par or stated value — 4.20% to 4.92%
Authorized — 10 million shares
Outstanding — 475,115 shares	48			48
$1 par value — 5.00%
Authorized — 28 million shares
Outstanding — 10 million shares	243			243
Total redeemable preferred stock of subsidiaries
(annual dividend requirement — $15 million)	291			291			0.4		0.4
Common Stockholders' Equity:
Common stock, par value $5 per share —	5,257			5,164
Authorized — 1.5 billion shares
Issued — 2019: 1.1 billion shares
— 2018: 1.0 billion shares
Treasury — 2019: 1.0 million shares
— 2018: 1.0 million shares
Paid-in capital	11,734			11,094
Treasury, at cost	(42		)	(38		)
Retained earnings	10,877			8,706
Accumulated other comprehensive loss	(321		)	(203		)
Total common stockholders' equity	27,505			24,723			37.2		35.3
Noncontrolling interests	4,254			4,316			5.8		6.2
Total stockholders' equity	31,759			29,039
Total Capitalization	$	73,848		$	70,066		100.0	%	100.0	%

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

For the Years Ended December 31, 2019, 2018, and 2017

Southern Company and Subsidiary Companies 2019 Annual Report



	Southern Company Common Stockholders' Equity
	Number of Common Shares			Common Stock											Accumulated Other Comprehensive Income (Loss)			Preferred and Preference Stock of Subsidiaries			Noncontrolling Interests^(a)
	Issued	Treasury		Par Value		Paid-In Capital			Treasury			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Preferred and Preference Stock of Subsidiaries			Noncontrolling Interests^(a)			Total
	(in millions)
Balance at December 31, 2016	991	(1	)	$	4,952	$	9,661		$	(31	)	$	10,356		$	(180	)	$	609		$	1,245		$	26,612
Consolidated net income attributable to Southern Company	—	—		—		—			—			842			—			—			—			842
Other comprehensive income (loss)	—	—		—		—			—			—			(9		)	—			—			(9		)
Stock issued	18	—		86		707			—			—			—			—			—			793
Stock-based compensation	—	—		—		105			—			—			—			—			—			105
Cash dividends of $2.3000 per share	—	—		—		—			—			(2,300		)	—			—			—			(2,300		)
Preferred and preference stock redemptions	—	—		—		—			—			—			—			(609		)	—			(609		)
Contributions from noncontrolling interests	—	—		—		—			—			—			—			—			79			79
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(122		)	(122		)
Net income attributable to noncontrolling interests	—	—		—		—			—			—			—			—			44			44
Reclassification from redeemable noncontrolling interests	—	—		—		—			—			—			—			—			114			114
Other	—	—		—		(4		)	(5		)	(13		)	—			—			1			(21		)
Balance at December 31, 2017	1,009	(1	)	5,038		10,469			(36		)	8,885			(189		)	—			1,361			25,528
Consolidated net income attributable to Southern Company	—	—		—		—			—			2,226			—			—			—			2,226
Other comprehensive income	—	—		—		—			—			—			26			—			—			26
Stock issued	26	—		126		964			—			—			—			—			—			1,090
Stock-based compensation	—	—		—		84			—			—			—			—			—			84
Cash dividends of $2.3800 per share	—	—		—		—			—			(2,425		)	—			—			—			(2,425		)
Contributions from noncontrolling interests	—	—		—		—			—			—			—			—			1,372			1,372
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(164		)	(164		)
Net income attributable to noncontrolling interests	—	—		—		—			—			—			—			—			58			58
Sale of noncontrolling interests	—	—		—		(417		)	—			—			—			—			1,690			1,273
Other	—	—		—		(6		)	(2		)	20			(40		)	—			(1		)	(29		)
Balance at December 31, 2018	1,035	(1	)	5,164		11,094			(38		)	8,706			(203		)	—			4,316			29,039
Consolidated net income attributable to Southern Company	—	—		—		—			—			4,739			—			—			—			4,739
Other comprehensive income (loss)	—	—		—		—			—			—			(118		)	—			—			(118		)
Issuance of equity units^(b)	—	—		—		(198		)	—			—			—			—			—			(198		)
Stock issued	19	—		93		751			—			—			—			—			—			844
Stock-based compensation	—	—		—		66			—			—			—			—			—			66
Cash dividends of $2.4600 per share	—	—		—		—			—			(2,570		)	—			—			—			(2,570		)
Contributions from noncontrolling interests	—	—		—		—			—			—			—			—			276			276
Distributions to noncontrolling interests	—	—		—		—			—			—			—			—			(327		)	(327		)
Net income (loss) attributable to noncontrolling interests	—	—		—		—			—			—			—			—			(10		)	(10		)
Other	—	—		—		21			(4		)	2			—			—			(1		)	18
Balance at December 31, 2019	1,054	(1	)	$	5,257	$	11,734		$	(42	)	$	10,877		$	(321	)	$	—		$	4,254		$	31,759


(a)	Excludes redeemable noncontrolling interests. See Note 7 to the financial statements under "Southern Power – Redeemable Noncontrolling Interests" for additional information.


(b)	See Note 8 under "Equity Units" for additional information.

The accompanying notes are an integral part of these consolidated financial statements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of Alabama Power Company

Opinion on the Financial Statements

We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (Alabama Power) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2019 and 2018, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Alabama Power as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of Alabama Power's management. Our responsibility is to express an opinion on Alabama Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Alabama Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Alabama Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Alabama Power's internal control over financial reporting. Accordingly, we express no such opinion.

/s/ Deloitte & Touche LLP

Birmingham, Alabama

February 19, 2020

We have served as Alabama Power's auditor since 2002.

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STATEMENTS OF INCOME

For the Years Ended December 31, 2019, 2018, and 2017

Alabama Power Company 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Revenues:
Retail revenues	$	5,501		$	5,367		$	5,458
Wholesale revenues, non-affiliates	258			279			276
Wholesale revenues, affiliates	81			119			97
Other revenues	285			267			208
Total operating revenues	6,125			6,032			6,039
Operating Expenses:
Fuel	1,112			1,301			1,225
Purchased power, non-affiliates	203			216			170
Purchased power, affiliates	200			216			158
Other operations and maintenance	1,821			1,669			1,709
Depreciation and amortization	793			764			736
Taxes other than income taxes	403			389			384
Total operating expenses	4,532			4,555			4,382
Operating Income	1,593			1,477			1,657
Other Income and (Expense):
Allowance for equity funds used during construction	52			62			39
Interest expense, net of amounts capitalized	(336		)	(323		)	(305		)
Other income (expense), net	46			20			43
Total other income and (expense)	(238		)	(241		)	(223		)
Earnings Before Income Taxes	1,355			1,236			1,434
Income taxes	270			291			568
Net Income	1,085			945			866
Dividends on Preferred and Preference Stock	15			15			18
Net Income After Dividends on Preferred and Preference Stock	$	1,070		$	930		$	848

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF ~~CASH FLOWS~~COMPREHENSIVE INCOME

For the Years Ended December 31, ~~2016~~2019, ~~2015~~2018, and ~~2014~~2017

~~Gulf~~Alabama Power Company ~~2016 Annual Report~~

2016
2015
2014
(in millions)
Operating Activities:
Net income $ 140
$ 157
$ 149
Adjustments to reconcile net income
to net cash provided from operating activities —
Depreciation and amortization, total 179
152
153
Deferred income taxes 57
90
65
Pension and postretirement funding (48 ) —
(30 )
Other, net (3 ) 4
(4 )
Changes in certain current assets and liabilities —
-Receivables 15
33
(17 )
-Fossil fuel stock 37
(6 ) 34
-Prepaid income taxes (11 ) 32
(19 )
-Other current assets (1 ) (2 ) (2 )
-Accounts payable 5
(22 ) 8
-Over recovered regulatory clause revenues 1
22
—
-Other current liabilities 8
—
7
Net cash provided from operating activities 379
460
344
Investing Activities:
Property additions (178 ) (235 ) (348 )
Cost of removal net of salvage (9 ) (10 ) (13 )
Change in construction payables 13
(28 ) 12
Payments pursuant to long-term service agreements (5 ) (8 ) (8 )
Other investing activities (1 ) —
(1 )
Net cash used for investing activities (180 ) (281 ) (358 )
Financing Activities:
Increase (decrease) in notes payable, net 126
32
(26 )
Proceeds —
Common stock issued to parent —
20
50
Capital contributions from parent company 20
4
4
Pollution control revenue bonds —
13
42
Senior notes —
—
200
Redemptions and repurchases —
Senior notes (235 ) (60 ) (75 )
Pollution control revenue bonds —
(13 ) (29 )
Payment of common stock dividends (120 ) (130 ) (123 )
Other financing activities (8 ) (10 ) (12 )
Net cash provided from (used for) financing activities (217 ) (144 ) 31
Net Change in Cash and Cash Equivalents (18 ) 35
17
Cash and Cash Equivalents at Beginning of Year 74
39
22
Cash and Cash Equivalents at End of Year $ 56
$ 74
$ 39
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $-, $6, and $5 capitalized, respectively) $ 53
$ 52
$ 48
Income taxes (net of refunds) 21
(7 ) 44
Noncash transactions — accrued property additions at year-end 33
20
42

~~The accompanying notes are an integral part of these financial statements.~~

~~Table of ContentsIndex to Financial Statements~~

~~BALANCE SHEETS~~

At ~~December 31, 2016~~ ~~and~~ ~~2015~~

~~Gulf Power Company 2016~~2019 Annual Report

Assets 2016
2015
(in millions)
Current Assets:
Cash and cash equivalents $ 56
$ 74
Receivables —
Customer accounts receivable 72
76
Unbilled revenues 55
54
Under recovered regulatory clause revenues 17
20
Income taxes receivable, current —
27
Other accounts and notes receivable 6
9
Affiliated 17
1
Accumulated provision for uncollectible accounts (1 ) (1 )
Fossil fuel stock 71
108
Materials and supplies 55
56
Prepaid expenses 18
8
Other regulatory assets, current 44
90
Other current assets 12
14
Total current assets 422
536
Property, Plant, and Equipment:
In service 5,140
5,045
Less accumulated provision for depreciation 1,382
1,296
Plant in service, net of depreciation 3,758
3,749
Other utility plant, net —
62
Construction work in progress 51
48
Total property, plant, and equipment 3,809
3,859
Deferred Charges and Other Assets:
Deferred charges related to income taxes 58
61
Other regulatory assets, deferred 512
427
Other deferred charges and assets 21
37
Total deferred charges and other assets 591
525
Total Assets $ 4,822
$ 4,920



	2019		2018		2017
	(in millions)
Net Income	$	1,085	$	945	$	866
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, and $(1), respectively	—		—		1
Reclassification adjustment for amounts included in net income, net of tax of $2, $2, and $2, respectively	4		4		3
Total other comprehensive income (loss)	4		4		4
Comprehensive Income	$	1,089	$	949	$	870

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CASH FLOWS

~~BALANCE SHEETS~~

At For the Years Ended December 31, ~~2016~~2019, 2018, and ~~2015~~2017

~~Gulf~~Alabama Power Company ~~2016~~2019 Annual Report

Liabilities and Stockholder's Equity 2016
2015
(in millions)
Current Liabilities:
Securities due within one year $ 87
$ 110
Notes payable 268
142
Accounts payable —
Affiliated 59
55
Other 54
44
Customer deposits 35
36
Accrued taxes —
Accrued income taxes 1
4
Other accrued taxes 19
9
Accrued interest 8
9
Accrued compensation 40
36
Deferred capacity expense, current 22
22
Other regulatory liabilities, current 16
22
Liabilities from risk management activities 9
49
Other current liabilities 31
29
Total current liabilities 649
567
Long-Term Debt (See accompanying statements)
987
1,193
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 948
893
Employee benefit obligations 96
129
Deferred capacity expense 119
141
Asset retirement obligations 120
113
Other cost of removal obligations 249
233
Other regulatory liabilities, deferred 47
47
Other deferred credits and liabilities 71
102
Total deferred credits and other liabilities 1,650
1,658
Total Liabilities 3,286
3,418
Preference Stock (See accompanying statements)
147
147
Common Stockholder's Equity (See accompanying statements)
1,389
1,355
Total Liabilities and Stockholder's Equity $ 4,822
$ 4,920
Commitments and Contingent Matters (See notes)



	2019			2018			2017
	(in millions)
Operating Activities:
Net income	$	1,085		$	945		$	866
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	951			917			888
Deferred income taxes	197			174			409
Allowance for equity funds used during construction	(52		)	(62		)	(39		)
Pension and postretirement funding	(362		)	(4		)	(2		)
Settlement of asset retirement obligations	(127		)	(55		)	(26		)
Natural disaster reserve accruals	138			16			4
Other deferred charges – affiliated	(42		)	—			—
Other, net	(90		)	(17		)	9
Changes in certain current assets and liabilities —
-Receivables	9			(149		)	(168		)
-Prepayments	(4		)	(2		)	(2		)
-Materials and supplies	23			(82		)	(34		)
-Other current assets	(85		)	30			20
-Accounts payable	(41		)	24			71
-Accrued taxes	49			10			(84		)
-Accrued compensation	(14		)	8			(2		)
-Retail fuel cost over recovery	47			—			(76		)
-Other current liabilities	97			128			3
Net cash provided from operating activities	1,779			1,881			1,837
Investing Activities:
Property additions	(1,757		)	(2,158		)	(1,882		)
Nuclear decommissioning trust fund purchases	(261		)	(279		)	(237		)
Nuclear decommissioning trust fund sales	260			278			237
Cost of removal net of salvage	(103		)	(130		)	(112		)
Change in construction payables	(71		)	26			161
Other investing activities	(31		)	(26		)	(43		)
Net cash used for investing activities	(1,963		)	(2,289		)	(1,876		)
Financing Activities:
Proceeds —
Senior notes	600			500			1,100
Preferred stock	—			—			250
Pollution control revenue bonds	—			120			—
Capital contributions from parent company	1,240			511			361
Redemptions and repurchases —
Senior notes	(200		)	—			(525		)
Preferred and preference stock	—			—			(238		)
Pollution control revenue bonds	—			(120		)	(36		)
Payment of common stock dividends	(844		)	(801		)	(714		)
Other financing activities	(31		)	(33		)	(35		)
Net cash provided from financing activities	765			177			163
Net Change in Cash, Cash Equivalents, and Restricted Cash	581			(231		)	124
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	313			544			420
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	894		$	313		$	544
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $19, $22, and $15 capitalized, respectively)	$	311		$	284		$	285
Income taxes (net of refunds)	26			106			236
Noncash transactions — Accrued property additions at year-end	200			272			245

The accompanying notes are an integral part of these financial statements.

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~~STATEMENTS OF CAPITALIZATION~~BALANCE SHEETS

At December 31, ~~2016~~2019 and ~~2015~~2018

~~Gulf~~Alabama Power Company ~~2016~~2019 Annual Report

2016
2015
2016
2015
(in millions) (percent of total)
Long-Term Debt:
Long-term notes payable —
5.30% due 2016 $ —
$ 110

2.93 to 5.90% due 2017 87
85

4.75% due 2020 175
175

3.10% to 5.75% due 2022-2051 515
640

Total long-term notes payable 777
1,010

Other long-term debt —
Pollution control revenue bonds —
1.15% to 4.45% due 2022-2049 227
227

Variable rates (0.75% to 0.84% at 1/1/17) due 2022-2042 82
82

Total other long-term debt 309
309

Unamortized debt discount (5 ) (8 )
Unamortized debt issuance expense (7 ) (8 )
Total long-term debt (annual interest requirement — $42 million) 1,074
1,303

Less amount due within one year 87
110

Long-term debt excluding amount due within one year 987
1,193
39.1 % 44.3 %
Preferred and Preference Stock:
Authorized — 20,000,000 shares — preferred stock
— 10,000,000 shares — preference stock
Outstanding — $100 par or stated value
— 6% preference stock — 550,000 shares (non-cumulative) 54
54

— 6.45% preference stock — 450,000 shares (non-cumulative) 44
44

— 5.60% preference stock — 500,000 shares (non-cumulative) 49
49

Total preference stock (annual dividend requirement — $9 million) 147
147
5.8
5.4
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 5,642,717 shares 503
503

Paid-in capital 589
567

Retained earnings 296
285

Accumulated other comprehensive loss 1
—

Total common stockholder's equity 1,389
1,355
55.1
50.3
Total Capitalization $ 2,523
$ 2,695
100.0 % 100.0 %

~~The accompanying notes are an integral part of these financial statements.~~

~~Table of ContentsIndex to Financial Statements~~

~~STATEMENTS OF COMMON STOCKHOLDER'S EQUITY~~

~~For the Years Ended~~ ~~December 31, 2016~~, ~~2015, and~~ ~~2014~~

~~Gulf Power Company 2016 Annual Report~~

Number of Common Shares Issued Common Stock Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Total
(in millions)
Balance at December 31, 2013 5
$ 433
$ 553
$ 250
$ (1 ) $ 1,235
Net income after dividends on
preference stock
—
—
—
140
—
140
Issuance of common stock —
50
—
—
—
50
Capital contributions from parent company —
—
7
—
—
7
Cash dividends on common stock —
—
—
(123 ) —
(123 )
Balance at December 31, 2014 5
483
560
267
(1 ) 1,309
Net income after dividends on
preference stock
—
—
—
148
—
148
Issuance of common stock 1
20
—
—
—
20
Capital contributions from parent company —
—
7
—
—
7
Other comprehensive income (loss) —
—
—
—
1
1
Cash dividends on common stock —
—
—
(130 ) —
(130 )
Balance at December 31, 2015 6
503
567
285
—
1,355
Net income after dividends on
preference stock
—
—
—
131
—
131
Capital contributions from parent company —
—
22
—
—
22
Other comprehensive income (loss) —
—
—
—
1
1
Cash dividends on common stock —
—
—
(120 ) —
(120 )
Balance at December 31, 2016 6
$ 503
$ 589
$ 296
$ 1
$ 1,389



Assets	2019			2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	894		$	313
Receivables —
Customer accounts receivable	425			403
Unbilled revenues	134			150
Affiliated	37			94
Other accounts and notes receivable	72			51
Accumulated provision for uncollectible accounts	(22		)	(10		)
Fossil fuel stock	212			141
Materials and supplies	512			546
Prepaid expenses	50			66
Other regulatory assets	242			137
Other current assets	30			18
Total current assets	2,586			1,909
Property, Plant, and Equipment:
In service	30,023			30,402
Less: Accumulated provision for depreciation	9,540			9,988
Plant in service, net of depreciation	20,483			20,414
Nuclear fuel, at amortized cost	296			324
Construction work in progress	890			1,113
Total property, plant, and equipment	21,669			21,851
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	66			65
Nuclear decommissioning trusts, at fair value	1,023			847
Miscellaneous property and investments	128			127
Total other property and investments	1,217			1,039
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	132			—
Deferred charges related to income taxes	244			240
Deferred under recovered regulatory clause revenues	40			116
Regulatory assets – asset retirement obligations	1,019			147
Other regulatory assets, deferred	1,976			1,240
Other deferred charges and assets	269			188
Total deferred charges and other assets	3,680			1,931
Total Assets	$	29,152		$	26,730

The accompanying notes are an integral part of these financial statements.

Table of ContentsIndex to Financial Statements

~~NOTES TO FINANCIAL STATEMENTS~~BALANCE SHEETS

~~Gulf~~At December 31, 2019 and 2018

Alabama Power Company ~~2016~~2019 Annual Report



Liabilities and Stockholder's Equity	2019		2018
	(in millions)
Current Liabilities:
Securities due within one year	$	251	$	201
Accounts payable —
Affiliated	316		364
Other	514		614
Customer deposits	100		96
Accrued taxes	78		44
Accrued interest	92		89
Accrued compensation	216		227
Asset retirement obligations	195		163
Other regulatory liabilities	193		116
Other current liabilities	105		45
Total current liabilities	2,060		1,959
Long-Term Debt (See accompanying statements)	8,270		7,923
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,260		2,962
Deferred credits related to income taxes	1,960		2,027
Accumulated deferred ITCs	100		106
Employee benefit obligations	206		314
Operating lease obligations	107		—
Asset retirement obligations, deferred	3,345		3,047
Other cost of removal obligations	412		497
Other regulatory liabilities, deferred	146		69
Other deferred credits and liabilities	40		58
Total deferred credits and other liabilities	9,576		9,080
Total Liabilities	19,906		18,962
Redeemable Preferred Stock (See accompanying statements)	291		291
Common Stockholder's Equity (See accompanying statements)	8,955		7,477
Total Liabilities and Stockholder's Equity	$	29,152	$	26,730
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these financial statements.

~~Index to the Notes to Financial Statements~~

Table of ContentsIndex to Financial Statements

~~NOTES (continued)~~

~~Gulf~~STATEMENTS OF CAPITALIZATION

At December 31, 2019 and 2018

Alabama Power Company ~~2016~~2019 Annual Report

~~1. SUMMARY~~



	Weighted Average Interest Rate at December 31, 2019	2019			2018			2019		2018
		(in millions)						(percent of total)
Long-Term Debt:
Long-term debt payable to affiliated trusts —
Variable rate due 2042	5.20%	$	206		$	206
Long-term notes payable —
Maturity
2019	—	—			200
2020	3.38%	250			250
2021	3.81%	220			220
2022	3.36%	750			750
2023	3.55%	300			300
2025-2049	4.41%	5,775			5,175
Variable rate due 2021	2.90%	25			25
Total long-term notes payable		7,320			6,920
Other long-term debt —
Pollution control revenue bonds —
Due 2034	2.46%	207			207
Variable rate due 2021	1.75%	65			65
Variable rate due 2024	1.72%	21			21
Variable rate due 2028-2038	1.65%	767			767
Total other long-term debt		1,060			1,060
Finance lease obligations		4			4
Unamortized debt premium (discount), net		(14		)	(12		)
Unamortized debt issuance expense		(55		)	(54		)
Total long-term debt		8,521			8,124
Less amount due within one year		251			201
Long-term debt excluding amount due within one year		8,270			7,923			47.2	%	50.4	%
Redeemable Preferred Stock:
Cumulative redeemable preferred stock
$100 par or stated value — 4.20% to 4.92%
Authorized — 3,850,000 shares
Outstanding — 475,115 shares		48			48
$1 par value — 5.00%
Authorized — 27,500,000 shares
Outstanding — 10,000,000 shares: $25 stated value		243			243
Total redeemable preferred stock (annual dividend requirement — $15 million)		291			291			1.7		1.9
Common Stockholder's Equity:
Common stock, par value $40 per share —
Authorized — 40,000,000 shares
Outstanding — 30,537,500 shares		1,222			1,222
Paid-in capital		4,755			3,508
Retained earnings		3,001			2,775
Accumulated other comprehensive loss		(23		)	(28		)
Total common stockholder's equity		8,955			7,477			51.1		47.7
Total Capitalization		$	17,516		$	15,691		100.0	%	100.0	%

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF ~~SIGNIFICANT ACCOUNTING POLICIES~~COMMON STOCKHOLDER'S EQUITY

~~General~~For the Years Ended December 31, 2019, 2018, and 2017

~~Gulf~~Alabama Power Company ~~(the Company) is a~~2019 Annual Report



	Number of Common Shares Issued	Common Stock		Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2016	31	$	1,222	$	2,613	$	2,518		$	(30	)	$	6,323
Net income after dividends on preferred and preference stock	—	—		—		848			—			848
Capital contributions from parent company	—	—		373		—			—			373
Other comprehensive income	—	—		—		—			4			4
Cash dividends on common stock	—	—		—		(714		)	—			(714		)
Other	—	—		—		(5		)	—			(5		)
Balance at December 31, 2017	31	1,222		2,986		2,647			(26		)	6,829
Net income after dividends on preferred and preference stock	—	—		—		930			—			930
Capital contributions from parent company	—	—		522		—			—			522
Other comprehensive income	—	—		—		—			4			4
Cash dividends on common stock	—	—		—		(801		)	—			(801		)
Other	—	—		—		(1		)	(6		)	(7		)
Balance at December 31, 2018	31	1,222		3,508		2,775			(28		)	7,477
Net income after dividends on preferred and preference stock	—	—		—		1,070			—			1,070
Capital contributions from parent company	—	—		1,247		—			—			1,247
Other comprehensive income	—	—		—		—			4			4
Cash dividends on common stock	—	—		—		(844		)	—			(844		)
Other	—	—		—		—			1			1
Balance at December 31, 2019	31	$	1,222	$	4,755	$	3,001		$	(23	)	$	8,955

The accompanying notes are an integral part of these financial statements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Georgia Power Company

Opinion on the Financial Statements

We have audited the accompanying balance sheets and statements of capitalization of Georgia Power Company (Georgia Power) (a wholly-owned subsidiary of The Southern ~~Company, which is~~Company) as of December 31, 2019 and 2018, the ~~parent company~~related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Georgia Power as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of Georgia Power's management. Our responsibility is to express an opinion on Georgia Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and ~~three other traditional electric operating companies,~~are required to be independent with respect to Georgia Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Georgia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Georgia Power's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as ~~Southern Power, Southern Company Gas (as~~evaluating the overall presentation of ~~July 1, 2016)~~the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 19, 2020

We have served as Georgia Power's auditor since 2002.

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STATEMENTS OF INCOME

For the Years Ended December 31, 2019, ~~SCS, Southern LINC, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), Inc. (PowerSecure)~~2018, and ~~other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Alabama Power,~~ 2017

Georgia Power Company 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Revenues:
Retail revenues	$	7,707		$	7,752		$	7,738
Wholesale revenues, non-affiliates	129			163			163
Wholesale revenues, affiliates	11			24			26
Other revenues	561			481			383
Total operating revenues	8,408			8,420			8,310
Operating Expenses:
Fuel	1,444			1,698			1,671
Purchased power, non-affiliates	521			430			416
Purchased power, affiliates	575			723			622
Other operations and maintenance	1,972			1,860			1,724
Depreciation and amortization	981			923			895
Taxes other than income taxes	454			437			409
Estimated loss on Plant Vogtle Units 3 and 4	—			1,060			—
Total operating expenses	5,947			7,131			5,737
Operating Income	2,461			1,289			2,573
Other Income and (Expense):
Interest expense, net of amounts capitalized	(409		)	(397		)	(419		)
Other income (expense), net	140			115			104
Total other income and (expense)	(269		)	(282		)	(315		)
Earnings Before Income Taxes	2,192			1,007			2,258
Income taxes	472			214			830
Net Income	1,720			793			1,428
Dividends on Preferred and Preference Stock	—			—			14
Net Income After Dividends on Preferred and Preference Stock	$	1,720		$	793		$	1,414

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2019, 2018, and2017

Georgia Power Company 2019 Annual Report



	2019			2018		2017
	(in millions)
Net Income	$	1,720		$	793	$	1,428
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(15), $-, and $-, respectively	(44		)	—		—
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, and $1, respectively	2			3		3
Total other comprehensive income (loss)	(42		)	3		3
Comprehensive Income	$	1,678		$	796	$	1,431

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2019, 2018, and 2017

Georgia Power Company 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Activities:
Net income	$	1,720		$	793		$	1,428
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	1,193			1,142			1,100
Deferred income taxes	179			(260		)	458
Pension, postretirement, and other employee benefits	(146		)	(75		)	(68		)
Pension and postretirement funding	(200		)	—			—
Settlement of asset retirement obligations	(151		)	(116		)	(120		)
Retail fuel cost over recovery – long-term	73			—			—
Other deferred charges – affiliated	(108		)	—			—
Estimated loss on Plant Vogtle Units 3 and 4	—			1,060			—
Other, net	12			(21		)	(83		)
Changes in certain current assets and liabilities —
-Receivables	177			8			(256		)
-Fossil fuel stock	(41		)	83			(16		)
-Prepaid income taxes	102			152			(168		)
-Other current assets	(19		)	(43		)	(28		)
-Accounts payable	(92		)	95			(219		)
-Accrued taxes	58			58			1
-Retail fuel cost over recovery	—			—			(84		)
-Other current liabilities	150			(107		)	(33		)
Net cash provided from operating activities	2,907			2,769			1,912
Investing Activities:
Property additions	(3,510		)	(3,116		)	(2,704		)
Proceeds pursuant to the Toshiba Guarantee, net of joint owner portion	—			—			1,682
Nuclear decommissioning trust fund purchases	(628		)	(839		)	(574		)
Nuclear decommissioning trust fund sales	622			833			568
Cost of removal, net of salvage	(186		)	(107		)	(100		)
Change in construction payables, net of joint owner portion	(122		)	68			223
Payments pursuant to LTSAs	(81		)	(54		)	(64		)
Proceeds from dispositions and asset sales	14			138			96
Other investing activities	6			(32		)	(39		)
Net cash used for investing activities	(3,885		)	(3,109		)	(912		)
Financing Activities:
Increase (decrease) in notes payable, net	(179		)	294			(391		)
Proceeds —
FFB loan	1,218			—			—
Senior notes	750			—			1,350
Pollution control revenue bonds issuances and remarketings	584			108			65
Capital contributions from parent company	634			2,985			431
Short-term borrowings	250			—			700
Other long-term debt	—			—			370
Redemptions and repurchases —
Senior notes	(500		)	(1,500		)	(450		)
Pollution control revenue bonds	(223		)	(469		)	(65		)
Short-term borrowings	—			(150		)	(550		)
Preferred and preference stock	—			—			(270		)
Other long-term debt	—			(100		)	—
Payment of common stock dividends	(1,576		)	(1,396		)	(1,281		)
Premiums on redemption and repurchases of senior notes	—			(152		)	—
Other financing activities	(40		)	(20		)	(60		)
Net cash provided from (used for) financing activities	918			(400		)	(151		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(60		)	(740		)	849
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	112			852			3
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	52		$	112		$	852
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $35, $26, and $23 capitalized, respectively)	$	373		$	408		$	386
Income taxes (net of refunds)	110			300			496
Noncash transactions — Accrued property additions at year-end	560			683			550

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS

At December 31, 2019 and 2018

Georgia Power Company 2019 Annual Report



Assets	2019			2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	52		$	4
Restricted cash and cash equivalents	—			108
Receivables —
Customer accounts receivable	533			591
Unbilled revenues	203			208
Under recovered fuel clause revenues	—			115
Joint owner accounts receivable	136			170
Affiliated	21			39
Other accounts and notes receivable	209			80
Accumulated provision for uncollectible accounts	(2		)	(2		)
Fossil fuel stock	272			231
Materials and supplies	501			519
Prepaid expenses	63			142
Regulatory assets – storm damage reserves	213			30
Regulatory assets – asset retirement obligations	254			—
Other regulatory assets	263			169
Other current assets	77			70
Total current assets	2,795			2,474
Property, Plant, and Equipment:
In service	38,137			37,675
Less: Accumulated provision for depreciation	11,753			12,096
Plant in service, net of depreciation	26,384			25,579
Nuclear fuel, at amortized cost	555			550
Construction work in progress	5,650			4,833
Total property, plant, and equipment	32,589			30,962
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	52			51
Nuclear decommissioning trusts, at fair value	1,013			873
Miscellaneous property and investments	64			72
Total other property and investments	1,129			996
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,428			—
Deferred charges related to income taxes	519			517
Regulatory assets – asset retirement obligations, deferred	2,865			2,644
Other regulatory assets, deferred	2,716			2,258
Other deferred charges and assets	500			514
Total deferred charges and other assets	8,028			5,933
Total Assets	$	44,541		$	40,365

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS

At December 31, 2019 and 2018

Georgia Power Company 2019 Annual Report



Liabilities and Stockholder's Equity	2019			2018
	(in millions)
Current Liabilities:
Securities due within one year	$	1,025		$	617
Notes payable	365			294
Accounts payable —
Affiliated	512			575
Other	711			890
Customer deposits	283			276
Accrued taxes	407			377
Accrued interest	118			105
Accrued compensation	233			221
Operating lease obligations	144			—
Asset retirement obligations	265		��	202
Other regulatory liabilities	447			169
Other current liabilities	187			183
Total current liabilities	4,697			3,909
Long-Term Debt (See accompanying statements)	10,791			9,364
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,257			3,062
Deferred credits related to income taxes	2,862			3,080
Accumulated deferred ITCs	255			262
Employee benefit obligations	540			599
Operating lease obligations, deferred	1,282			—
Asset retirement obligations, deferred	5,519			5,627
Other deferred credits and liabilities	273			139
Total deferred credits and other liabilities	13,988			12,769
Total Liabilities	29,476			26,042
Common Stockholder's Equity (See accompanying statements)	15,065			14,323
Total Liabilities and Stockholder's Equity	$	44,541		$	40,365
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CAPITALIZATION

At December 31, 2019 and 2018

Georgia Power Company 2019 Annual Report



	Weighted Average Interest Rate at December 31, 2019	2019			2018			2019		2018
		(in millions)						(percent of total)
Long-Term Debt:
Long-term notes payable —
Maturity
2019	—	$	—		$	498
2020	2.00%	950			950
2021	2.40%	325			325
2022	2.85%	400			400
2023	5.75%	100			100
2024	2.20%	400			—
2026-2043	4.21%	3,675			3,325
Total long-term notes payable		5,850			5,598
Other long-term debt —
Pollution control revenue bonds —
Due 2022	2.35%	53			53
Due 2025-2053	2.37%	1,217			748
Variable rate due 2019	—	—			108
Variable rate due 2026-2052	1.74%	551			551
FFB loans —
Maturity
2020	3.20%	64			44
2021	3.20%	64			44
2022	3.20%	64			44
2023	3.20%	64			44
2024	3.20%	64			44
2025-2044	3.20%	3,523			2,405
Junior subordinated notes due 2077	5.00%	270			270
Total other long-term debt		5,934			4,355
Finance lease obligations		156			142
Unamortized debt premium (discount), net		(7		)	(6		)
Unamortized debt issuance expense		(117		)	(108		)
Total long-term debt		11,816			9,981
Less amount due within one year		1,025			617
Long-term debt excluding amount due within one year		10,791			9,364			41.7	%	39.5	%
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 9,261,500 shares		398			398
Paid-in capital		10,962			10,322
Retained earnings		3,756			3,612
Accumulated other comprehensive loss		(51		)	(9		)
Total common stockholder's equity		15,065			14,323			58.3		60.5
Total Capitalization		$	25,856		$	23,687		100.0	%	100.0	%

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

For the Years Ended December 31, 2019, 2018, and 2017

Georgia Power Company 2019 Annual Report



	Number of Common Shares Issued	Common Stock		Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2016	9	$	398	$	6,885	$	4,086		$	(13	)	$	11,356
Net income after dividends on preferred and preference stock	—	—		—		1,414			—			1,414
Capital contributions from parent company	—	—		443		—			—			443
Other comprehensive income	—	—		—		—			3			3
Cash dividends on common stock	—	—		—		(1,281		)	—			(1,281		)
Other	—	—		—		(4		)	—			(4		)
Balance at December 31, 2017	9	398		7,328		4,215			(10		)	11,931
Net income after dividends on preferred and preference stock	—	—		—		793			—			793
Capital contributions from parent company	—	—		2,994		—			—			2,994
Other comprehensive income	—	—		—		—			3			3
Cash dividends on common stock	—	—		—		(1,396		)	—			(1,396		)
Other	—	—		—		—			(2		)	(2		)
Balance at December 31, 2018	9	398		10,322		3,612			(9		)	14,323
Net income after dividends on preferred and preference stock	—	—		—		1,720			—			1,720
Capital contributions from parent company	—	—		640		—			—			640
Other comprehensive income (loss)	—	—		—		—			(42		)	(42		)
Cash dividends on common stock	—	—		—		(1,576		)	—			(1,576		)
Balance at December 31, 2019	9	$	398	$	10,962	$	3,756		$	(51	)	$	15,065

The accompanying notes are an integral part of these financial statements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Mississippi Power ~~– are vertically integrated utilities providing electric service in four Southeastern states.~~Company

Opinion on the Financial Statements

We have audited the accompanying balance sheets and statements of capitalization of Mississippi Power Company (Mississippi Power) (a wholly-owned subsidiary of The ~~Company provides electric service to retail customers in northwest Florida~~Southern Company) as of December 31, 2019 and ~~to wholesale customers~~2018, the related statements of operations, comprehensive income (loss), common stockholder's equity, and cash flows for each of the three years in the ~~Southeast. Southern~~period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Mississippi Power ~~constructs, acquires, owns,~~as of December 31, 2019 and ~~manages generation assets, including renewable energy projects,~~2018, and ~~sells electricity at market-based rates~~the results of its operations and its cash flows for each of the three years in the ~~wholesale market. Southern Company Gas distributes natural gas through utilities~~period ended December 31, 2019, in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. PowerSecure is a provider of products and servicesconformity with accounting principles generally accepted in the ~~areas~~United States of ~~distributed generation, energy efficiency, and utility infrastructure.~~America.

~~The equity method is used~~Basis for ~~entities in which the Company has significant influence but does not control.~~Opinion

~~The Company is subject to regulation by the FERC and the Florida PSC. As such, the Company's~~These financial statements ~~reflect~~are the ~~effects~~responsibility of ~~rate regulation~~Mississippi Power's management. Our responsibility is to express an opinion on Mississippi Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Mississippi Power in accordance with ~~GAAP~~the U.S. federal securities laws and ~~comply~~the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the ~~accounting policies~~standards of the PCAOB. Those standards require that we plan and ~~practices prescribed by its regulatory commissions. The preparation of~~perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Mississippi Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Mississippi Power's internal control over financial reporting. Accordingly, we express no such opinion.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 19, 2020

We have served as Mississippi Power's auditor since 2002.

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STATEMENTS OF OPERATIONS

For the Years Ended December 31, 2019, 2018, and 2017

Mississippi Power Company 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Revenues:
Retail revenues	$	877		$	889		$	854
Wholesale revenues, non-affiliates	237			263			259
Wholesale revenues, affiliates	132			91			56
Other revenues	18			22			18
Total operating revenues	1,264			1,265			1,187
Operating Expenses:
Fuel	407			405			395
Purchased power	20			41			25
Other operations and maintenance	283			313			291
Depreciation and amortization	192			169			161
Taxes other than income taxes	113			107			104
Estimated loss on Kemper IGCC	24			37			3,362
Total operating expenses	1,039			1,072			4,338
Operating Income (Loss)	225			193			(3,151		)
Other Income and (Expense):
Allowance for equity funds used during construction	1			—			72
Interest expense, net of amounts capitalized	(69		)	(76		)	(42		)
Other income (expense), net	12			17			1
Total other income and (expense)	(56		)	(59		)	31
Earnings (Loss) Before Income Taxes	169			134			(3,120		)
Income taxes (benefit)	30			(102		)	(532		)
Net Income (Loss)	139			236			(2,588		)
Dividends on Preferred Stock	—			1			2
Net Income (Loss) After Dividends on Preferred Stock	$	139		$	235		$	(2,590	)

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2019, 2018, and 2017

Mississippi Power Company 2019 Annual Report



	2019		2018			2017
	(in millions)
Net Income (Loss)	$	139	$	236		$	(2,588	)
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(1), and $(1), respectively	—		(1		)	(1		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, and $1, respectively	1		1			1
Total other comprehensive income (loss)	1		—			—
Comprehensive Income (Loss)	$	140	$	236		$	(2,588	)

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2019, 2018, and 2017

Mississippi Power Company 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Activities:
Net income (loss)	$	139		$	236		$	(2,588	)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	197			177			198
Deferred income taxes	37			475			(727		)
Allowance for equity funds used during construction	(1		)	—			(72		)
Pension and postretirement funding	(54		)	—			—
Settlement of asset retirement obligations	(35		)	(35		)	(23		)
Estimated loss on Kemper IGCC	15			33			3,179
Other, net	21			18			(8		)
Changes in certain current assets and liabilities —
-Receivables	6			(19		)	540
-Fossil fuel stock	(6		)	(3		)	24
-Prepaid income taxes	12			(12		)	—
-Other current assets	(2		)	(7		)	(13		)
-Accounts payable	3			15			(3		)
-Accrued interest	—			(1		)	(29		)
-Accrued taxes	11			(46		)	80
-Over recovered regulatory clause revenues	16			14			(51		)
-Other current liabilities	(20		)	(41		)	(4		)
Net cash provided from operating activities	339			804			503
Investing Activities:
Property additions	(202		)	(188		)	(429		)
Construction payables	(1		)	4			(47		)
Payments pursuant to LTSAs	(23		)	(29		)	(10		)
Other investing activities	(37		)	(19		)	(18		)
Net cash used for investing activities	(263		)	(232		)	(504		)
Financing Activities:
Decrease in notes payable, net	—			(4		)	(18		)
Proceeds —
Capital contributions from parent company	51			15			1,002
Senior notes	—			600			—
Long-term debt issuance to parent company	—			—			40
Short-term borrowings	—			300			109
Pollution control revenue bonds	43			—			—
Redemptions —
Preferred stock	—			(33		)	—
Pollution control revenue bonds	—			(43		)	—
Short-term borrowings	—			(300		)	(109		)
Long-term debt to parent company	—			—			(591		)
Capital leases	—			—			(71		)
Senior notes	(25		)	(155		)	(35		)
Other long-term debt	—			(900		)	(300		)
Return of capital to parent company	(150		)	—			—
Other financing activities	(2		)	(7		)	(2		)
Net cash provided from (used for) financing activities	(83		)	(527		)	25
Net Change in Cash, Cash Equivalents, and Restricted Cash	(7		)	45			24
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	293			248			224
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	286		$	293		$	248
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $(1), $-, and $29 capitalized, respectively)	$	71		$	80		$	65
Income taxes (net of refunds)	(27		)	(525		)	(424		)
Noncash transactions — Accrued property additions at year-end	35			35			32

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS

At December 31, 2019 and 2018

Mississippi Power Company 2019 Annual Report



Assets	2019		2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	286	$	293
Receivables —
Customer accounts receivable	35		34
Unbilled revenues	39		41
Affiliated	27		21
Other accounts and notes receivable	26		31
Fossil fuel stock	26		20
Materials and supplies	61		53
Other regulatory assets	99		116
Prepaid income taxes	—		12
Other current assets	10		7
Total current assets	609		628
Property, Plant, and Equipment:
In service	4,857		4,900
Less: Accumulated provision for depreciation	1,463		1,429
Plant in service, net of depreciation	3,394		3,471
Construction work in progress	126		103
Total property, plant, and equipment	3,520		3,574
Other Property and Investments	131		24
Deferred Charges and Other Assets:
Deferred charges related to income taxes	32		33
Regulatory assets – asset retirement obligations	210		143
Other regulatory assets, deferred	360		331
Accumulated deferred income taxes	139		150
Other deferred charges and assets	34		3
Total deferred charges and other assets	775		660
Total Assets	$	5,035	$	4,886

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS

At December 31, 2019 and 2018

Mississippi Power Company 2019 Annual Report



Liabilities and Stockholder's Equity	2019		2018
	(in millions)
Current Liabilities:
Securities due within one year	$	281	$	40
Accounts payable —
Affiliated	76		60
Other	75		90
Accrued taxes	105		95
Accrued interest	15		15
Accrued compensation	35		38
Accrued plant closure costs	15		29
Asset retirement obligations	33		34
Other regulatory liabilities	21		12
Over recovered regulatory clause liabilities	29		14
Other current liabilities	49		28
Total current liabilities	734		455
Long-Term Debt (See accompanying statements)	1,308		1,539
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	424		378
Deferred credits related to income taxes	352		382
Employee benefit obligations	99		115
Asset retirement obligations, deferred	157		126
Other cost of removal obligations	189		185
Other regulatory liabilities, deferred	76		81
Other deferred credits and liabilities	44		16
Total deferred credits and other liabilities	1,341		1,283
Total Liabilities	3,383		3,277
Common Stockholder's Equity (See accompanying statements)	1,652		1,609
Total Liabilities and Stockholder's Equity	$	5,035	$	4,886
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CAPITALIZATION

At December 31, 2019 and 2018

Mississippi Power Company 2019 Annual Report



	Weighted Average Interest Rate at December 31, 2019	2019			2018			2019		2018
		(in millions)						(percent of total)
Long-Term Debt:
Long-term notes payable —
Due 2028-2042	4.16%	$	950		$	950
Adjustable rate due 2020	2.59%	275			300
Total long-term notes payable		1,225			1,250
Other long-term debt —
Pollution control revenue bonds —
Due 2028	3.20%	43			—
Variable rate due 2020	1.80%	7			40
Variable rate due 2025-2028	1.80%	33			—
Plant Daniel revenue bonds due 2021	7.13%	270			270
Total other long-term debt		353			310
Unamortized debt premium (discount), net		19			27
Unamortized debt issuance expense		(8		)	(8		)
Total long-term debt		1,589			1,579
Less amount due within one year		281			40
Long-term debt excluding amount due within one year		1,308			1,539			44.2	%	48.9	%
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 1,130,000 shares
Outstanding — 1,121,000 shares		38			38
Paid-in capital		4,449			4,546
Accumulated deficit		(2,832		)	(2,971		)
Accumulated other comprehensive loss		(3		)	(4		)
Total common stockholder's equity		1,652			1,609			55.8		51.1
Total Capitalization		$	2,960		$	3,148		100.0	%	100.0	%

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

For the Years Ended December 31, 2019, 2018, and 2017

Mississippi Power Company 2019 Annual Report



	Number of Common Shares Issued	Common Stock		Paid-In Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2016	1	$	38	$	3,525		$	(616	)	$	(4	)	$	2,943
Net loss after dividends on preferred stock	—	—		—			(2,590		)	—			(2,590		)
Capital contributions from parent company	—	—		1,004			—			—			1,004
Other	—	—		—			1			—			1
Balance at December 31, 2017	1	38		4,529			(3,205		)	(4		)	1,358
Net income after dividends on preferred stock	—	—		—			235			—			235
Capital contributions from parent company	—	—		17			—			—			17
Other	—	—		—			(1		)	—			(1		)
Balance at December 31, 2018	1	38		4,546			(2,971		)	(4		)	1,609
Net income after dividends on preferred stock	—	—		—			139			—			139
Return of capital to parent company	—	—		(150		)	—			—			(150		)
Capital contributions from parent company	—	—		53			—			—			53
Other comprehensive income	—	—		—			—			1			1
Balance at December 31, 2019	1	$	38	$	4,449		$	(2,832	)	$	(3	)	$	1,652

The accompanying notes are an integral part of these financial statements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Southern Power Company and Subsidiary Companies

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Southern Power Company and subsidiary companies (Southern Power) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Southern Power as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with ~~GAAP requires~~accounting principles generally accepted in the ~~use~~United States of ~~estimates,~~America.

Basis for Opinion

These financial statements are the responsibility of Southern Power's management. Our responsibility is to express an opinion on Southern Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Southern Power in accordance with the U.S. federal securities laws and the ~~actual results may differ from~~applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those ~~estimates. Certain prior years' data presented~~risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial ~~statements have been reclassified to conform to~~statements. Our audits also included evaluating the ~~current year presentation.~~

~~Recently Issued Accounting Standards~~

~~In 2014,~~accounting principles used and significant estimates made by management, as well as evaluating the ~~FASB issued ASC 606,~~ ~~Revenue from Contracts with Customers,~~ replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principleoverall presentation of the guidance is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.

The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accountedWe believe that our audits provide a reasonable basis for ~~under ASC 606 and offsetting regulatory treatment is not permitted, it could~~our opinion.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 19, 2020

We have ~~a material impact on the Company's financial statements.~~served as Southern Power's auditor since 2002.

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~~NOTES (continued)~~

~~Gulf~~CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2019, 2018, and 2017

Southern Power Company ~~2016~~and Subsidiary Companies 2019 Annual Report

effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.

~~On March 30, 2016, the FASB issued ASU No. 2016-09,~~ ~~Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting~~ (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5, 8, and 11 for disclosures impacted by ASU 2016-09.

~~Affiliate Transactions~~



	2019			2018			2017
	(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	1,528		$	1,757		$	1,671
Wholesale revenues, affiliates	398			435			392
Other revenues	12			13			12
Total operating revenues	1,938			2,205			2,075
Operating Expenses:
Fuel	577			699			621
Purchased power	108			176			149
Other operations and maintenance	359			395			386
Depreciation and amortization	479			493			503
Taxes other than income taxes	40			46			48
Asset impairment	3			156			—
Gain on dispositions, net	(23		)	(2		)	—
Total operating expenses	1,543			1,963			1,707
Operating Income	395			242			368
Other Income and (Expense):
Interest expense, net of amounts capitalized	(169		)	(183		)	(191		)
Other income (expense), net	47			23			1
Total other income and (expense)	(122		)	(160		)	(190		)
Earnings Before Income Taxes	273			82			178
Income taxes (benefit)	(56		)	(164		)	(939		)
Net Income	329			246			1,117
Net income (loss) attributable to noncontrolling interests	(10		)	59			46
Net Income Attributable to Southern Power	$	339		$	187		$	1,071

The ~~Company has~~accompanying notes are an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs forintegral part of these services amounted to $80 million, $81 million, and $80 million during 2016, 2015, and 2014, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.consolidated financial statements.

The Company has operating agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel, respectively. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $8 million, $12 million, and $9 million and Mississippi Power $26 million, $27 million, and $31 million in 2016, 2015, and 2014, respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under "Operating Leases" for additional information.

The Company has an agreement with Alabama Power under which Alabama Power made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Alabama. Payments by the Company to Alabama Power for the improvements were $12 million, $14 million, and $12 million in 2016, 2015, and 2014, respectively, and are expected to be approximately $10 million annually for 2017 through 2023, when the PPA expires. These costs have been approved for recovery by the Florida PSC through the Company's purchased power capacity cost recovery clause and by the FERC in the transmission facilities cost allocation tariff.

~~In 2016, the Company purchased a turbine rotor assembly from Southern Power for $6.8 million.~~

The traditional electric operating companies, including the Company and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.

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~~NOTES (continued)~~

~~Gulf~~CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2019, 2018, and 2017

Southern Power Company ~~2016~~and Subsidiary Companies 2019 Annual Report

~~Regulatory Assets and Liabilities~~

The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

~~Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:~~

2016
2015
Note
(in millions)
Retiree benefit plans, net $ 160
$ 147
(a,b)
PPA charges 141
163
(b,c)
Closure of ash ponds 75
29
(b,d)
Remaining book value of retired assets 66
4
(e)
Deferred income tax charges 56
59
(f)
Environmental remediation 44
46
(b,d)
Regulatory asset, offset to other cost of removal 29
29
(g)
Deferred return on transmission upgrades 25
10
(g)
Fuel-hedging assets, net 24
104
(b,h)
Other regulatory assets, net 18
16
(i)
Loss on reacquired debt 18
15
(j)
Asset retirement obligations, net 7
(1 ) (b,f)
Other cost of removal obligations (278 ) (262 ) (f)
Property damage reserve (40 ) (38 ) (e)
Over recovered regulatory clause revenues (23 ) (22 ) (k)
Deferred income tax credits (2 ) (3 ) (f)
Total regulatory assets (liabilities), net $ 320
$ 296



	2019			2018			2017
	(in millions)
Net Income	$	329		$	246		$	1,117
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(22), $(17), and $39, respectively	(66		)	(51		)	63
Reclassification adjustment for amounts included in net income, net of tax of $14, $19, and $(46), respectively	41			58			(73		)
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax of $(6), $2, and $-, respectively	(17		)	5			—
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, and $-, respectively	—			2			—
Total other comprehensive income (loss)	(42		)	14			(10		)
Comprehensive income (loss) attributable to noncontrolling interests	(10		)	59			46
Comprehensive Income Attributable to Southern Power	$	297		$	201		$	1,061

~~Note:~~ The ~~recovery~~accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2019, 2018, and ~~amortization periods for~~2017

Southern Power Company and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Activities:
Net income	$	329		$	246		$	1,117
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	505			524			536
Deferred income taxes	(74		)	(244		)	(263		)
Utilization of federal investment tax credits	734			5			—
Amortization of investment tax credits	(151		)	(58		)	(57		)
Accrued income taxes, non-current	—			(14		)	14
Income taxes receivable, non-current	25			42			(61		)
Pension and postretirement funding	(24		)	—			—
Asset impairment	3			156			—
Other, net	(33		)	7			(13		)
Changes in certain current assets and liabilities —
-Receivables	72			(20		)	(60		)
-Prepaid income taxes	39			25			24
-Other current assets	(8		)	(26		)	(28		)
-Accrued taxes	6			7			(55		)
-Other current liabilities	(38		)	(19		)	1
Net cash provided from operating activities	1,385			631			1,155
Investing Activities:
Business acquisitions. net of cash acquired	(50		)	(65		)	(1,016		)
Property additions	(489		)	(315		)	(268		)
Change in construction payables	7			(6		)	(153		)
Investment in unconsolidated subsidiaries	(116		)	—			—
Proceeds from dispositions and asset sales	572			203			—
Payments pursuant to LTSAs and for equipment not yet received	(104		)	(75		)	(203		)
Other investing activities	13			31			15
Net cash used for investing activities	(167		)	(227		)	(1,625		)
Financing Activities:
Increase (decrease) in notes payable, net	449			(105		)	(104		)
Proceeds —
Short-term borrowings	100			200			—
Capital contributions from parent company	64			2			—
Senior notes	—			—			525
Other long-term debt	—			—			43
Redemptions —
Senior notes	(600		)	(350		)	(500		)
Other long-term debt	—			(420		)	(18		)
Short-term borrowings	(100		)	(100		)	—
Return of capital to parent company	(755		)	(1,650		)	—
Distributions to noncontrolling interests	(256		)	(153		)	(119		)
Capital contributions from noncontrolling interests	196			2,551			80
Purchase of membership interests from noncontrolling interests	—			—			(59		)
Payment of common stock dividends	(206		)	(312		)	(317		)
Other financing activities	(12		)	(26		)	(33		)
Net cash used for financing activities	(1,120		)	(363		)	(502		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	98			41			(972		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	181			140			1,112
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	279		$	181		$	140
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $15, $17, and $11 capitalized, respectively)	$	167		$	173		$	189
Income taxes (net of refunds and investment tax credits)	(664		)	79			(487		)
Noncash transactions — Accrued property additions at year-end	57			31			32

The accompanying notes are an integral part of these ~~regulatory assets~~consolidated financial statements.

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CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and ~~(liabilities)~~2018

Southern Power Company and Subsidiary Companies 2019 Annual Report



Assets	2019		2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	279	$	181
Receivables —
Customer accounts receivable	107		111
Affiliated	30		55
Other	73		116
Materials and supplies	191		220
Prepaid income taxes	36		25
Other current assets	43		37
Total current assets	759		745
Property, Plant, and Equipment:
In service	13,270		13,271
Less: Accumulated provision for depreciation	2,464		2,171
Plant in service, net of depreciation	10,806		11,100
Construction work in progress	515		430
Total property, plant, and equipment	11,321		11,530
Other Property and Investments:
Intangible assets, net of amortization of $69 and $61 at December 31, 2019 and December 31, 2018, respectively	322		345
Equity investments in unconsolidated subsidiaries	28		—
Total other property and investments	350		345
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	369		—
Prepaid LTSAs	128		98
Accumulated deferred income taxes	551		1,186
Income taxes receivable, non-current	5		30
Assets held for sale	601		576
Other deferred charges and assets	216		373
Total deferred charges and other assets	1,870		2,263
Total Assets	$	14,300	$	14,883

The accompanying notes are ~~as follows:~~an integral part of these consolidated financial statements.

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CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and 2018

Southern Power Company and Subsidiary Companies 2019 Annual Report



Liabilities and Stockholders' Equity	2019			2018
	(in millions)
Current Liabilities:
Securities due within one year	$	824		$	599
Notes payable	549			100
Accounts payable —
Affiliated	56			92
Other	85			77
Accrued taxes	26			6
Accrued interest	32			36
Other current liabilities	132			121
Total current liabilities	1,704			1,031
Long-Term Debt:
Senior notes —
2.375% due 2020	—			300
2.50% due 2021	300			300
1.00% due 2022	674			687
2.75% due 2023	290			290
Weighted average interest rate 4.12% at 12/31/19 due 2025-2046	2,337			2,348
Other long-term debt —
Variable rate (3.34% at 12/31/18) due 2020	—			525
Unamortized debt premium (discount), net	(8		)	(9		)
Unamortized debt issuance expense	(19		)	(23		)
Total long-term debt	3,574			4,418
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	115			105
Accumulated deferred ITCs	1,731			1,832
Operating lease obligations	376			—
Other deferred credits and liabilities	178			213
Total deferred credits and other liabilities	2,400			2,150
Total Liabilities	7,678			7,599
Common Stockholder's Equity:
Common stock, par value $0.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares	—			—
Paid-in capital	909			1,600
Retained earnings	1,485			1,352
Accumulated other comprehensive income (loss)	(26		)	16
Total common stockholder's equity	2,368			2,968
Noncontrolling Interests	4,254			4,316
Total Stockholders' Equity	6,622			7,284
Total Liabilities and Stockholders' Equity	$	14,300		$	14,883
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

For the Years Ended December 31, 2019, 2018, and 2017

Southern Power Company and Subsidiary Companies 2019 Annual Report



	Number of Common Shares Issued	Common Stock		Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income			Total Common Stockholder's Equity			Noncontrolling Interests^(a)			Total
	(in millions)
Balance at December 31, 2016	—	$	—	$	3,671		$	724		$	35		$	4,430		$	1,245		$	5,675
Net income attributable to Southern Power	—	—		—			1,071			—			1,071			—			1,071
Capital contributions to parent company, net	—	—		(2		)	—			—			(2		)	—			(2		)
Other comprehensive income (loss)	—	—		—			—			(10		)	(10		)	—			(10		)
Cash dividends on common stock	—	—		—			(317		)	—			(317		)	—			(317		)
Other comprehensive income transfer from SCS^(b)	—	—		—			—			(27		)	(27		)	—			(27		)
Capital contributions from noncontrolling interests	—	—		—			—			—			—			79			79
Distributions to noncontrolling interests	—	—		—			—			—			—			(122		)	(122		)
Net income attributable to noncontrolling interests	—	—		—			—			—			—			44			44
Reclassification from redeemable noncontrolling interests	—	—		—			—			—			—			114			114
Other	—	—		(7		)	—			—			(7		)	—			(7		)
Balance at December 31, 2017	—	—		3,662			1,478			(2		)	5,138			1,360			6,498
Net income attributable to Southern Power	—	—		—			187			—			187			—			187
Return of capital to parent company	—	—		(1,650		)	—			—			(1,650		)	—			(1,650		)
Capital contributions from parent company	—	—		2			—			—			2			—			2
Other comprehensive income	—	—		—			—			14			14			—			14
Cash dividends on common stock	—	—		—			(312		)	—			(312		)	—			(312		)
Capital contributions from noncontrolling interests	—	—		—			—			—			—			1,372			1,372
Distributions to noncontrolling interests	—	—		—			—			—			—			(164		)	(164		)
Net income attributable to noncontrolling interests	—	—		—			—			—			—			59			59
Sale of noncontrolling interests^(c)	—	—		(417		)	—			—			(417		)	1,690			1,273
Other	—	—		3			(1		)	4			6			(1		)	5
Balance at December 31, 2018	—	—		1,600			1,352			16			2,968			4,316			7,284
Net income attributable to Southern Power	—	—		—			339			—			339			—			339
Return of capital to parent company	—	—		(755		)	—			—			(755		)	—			(755		)
Capital contributions from parent company	—	—		64			—			—			64			—			64
Other comprehensive income (loss)	—	—		—			—			(42		)	(42		)	—			(42		)
Cash dividends on common stock	—	—		—			(206		)	—			(206		)	—			(206		)
Capital contributions from noncontrolling interests	—	—		—			—			—			—			276			276
Distributions to noncontrolling interests	—	—		—			—			—			—			(327		)	(327		)
Net income (loss) attributable to noncontrolling interests	—	—		—			—			—			—			(10		)	(10		)
Other	—	—		—			—			—			—			(1		)	(1		)
Balance at December 31, 2019	—	$	—	$	909		$	1,485		$	(26	)	$	2,368		$	4,254		$	6,622


(a)	~~Recovered and amortized over the average remaining service period which may range up to 14 years.~~Excludes redeemable noncontrolling interests. See Note 27 to the financial statements under "Noncontrolling Interests" for additional information.


(b)	~~Not earning~~In connection with Southern Power becoming a ~~return as offset in rate base by a corresponding asset or liability.~~participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of other comprehensive income, net of tax of $9 million, was transferred from SCS.


(c)	~~Recovered over the life of the PPA for periods up to seven years.~~


~~(d)~~	~~Recovered through the environmental cost recovery clause when the remediation or the work is performed.~~


~~(e)~~	~~Recorded and recovered or amortized as approved by the Florida PSC.~~


~~(f)~~	Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.


~~(g)~~	~~Recorded as authorized by the Florida PSC in a settlement agreement approved in December 2013 (2013 Rate Case Settlement Agreement).~~ See Note 315 under "Southern Power - Sales of Renewable Facility Interests" for additional information.


~~(h)~~	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause.


~~(i)~~	Comprised primarily of vacation pay. Other regulatory assets costs, with the exception of vacation pay, are recorded and recovered or amortized as approved by the Florida PSC. Vacation pay, including banked holiday pay, does not earn a return as offset in rate base by a corresponding liability; it is recorded as earned by employees and recovered as paid, generally within one year.


~~(j)~~	~~Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years.~~


~~(k)~~	~~Recorded and recovered or amortized as approved by the Florida PSC, generally within one year.~~

~~In the event that a portion~~The accompanying notes are an integral part of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information.these consolidated financial statements.

Table of ContentsIndex to Financial Statements

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Revenues~~

Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. The Company is required to notify the Florida PSC if the projected fuel cost over or under recovery is expected to exceed 10% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. The Company has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Annually, the Company petitions for recovery of projected costs including any true-up amounts from prior periods, and approved rates are implemented each January. See Note 3 under "Retail Regulatory Matters" for additional information.

~~Fuel Costs~~

Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC.

~~Income and Other Taxes~~

The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property and state ITCs are recognized in the period in which the credit is claimed on the state income tax return. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

~~Property, Plant, and Equipment~~

Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.

~~The Company's property, plant, and equipment in service consisted of the following at December 31:~~

2016 2015
(in millions)
Generation $ 3,001
$ 2,974
Transmission 706
691
Distribution 1,241
1,196
General 191
182
Plant acquisition adjustment 1
2
Total plant in service $ 5,140
$ 5,045

~~Depreciation and Amortization~~

Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.5% in both 2016 and 2015 and 3.6% in 2014. Depreciation studies are conducted periodically to update the composite rates. These studies are approved by the Florida PSC and the FERC. When property subject to depreciation is retired or

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. As authorized by the Florida PSC in the 2013 Rate Case Settlement Agreement, the Company is allowed to reduce depreciation and record a regulatory asset in an aggregate amount up to $62.5 million between January 2014 and June 2017. See Note 3 herein under "Retail Regulatory Matters – Retail Base Rate Cases" for additional information.

~~Asset Retirement Obligations and Other Costs of Removal~~

AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received an order from the Florida PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.

The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in April 2015 (CCR Rule), principally ash ponds, and to the closure of an ash pond at Plant Scholz. In addition, the Company has retirement obligations related to combustion turbines at its Pea Ridge facility, various landfill sites, a barge unloading dock, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Florida PSC, and are reflected in the balance sheets.

~~Details of the AROs included in the balance sheets are as follows:~~

2016 2015
(in millions)
Balance at beginning of year $ 130
$ 17
Liabilities incurred 1
105
Liabilities settled (1 ) (1 )
Accretion 4
2
Cash flow revisions 2
7
Balance at end of year $ 136
$ 130

The increase in liabilities incurred in 2015 is primarily related to AROs associated with the portion of the Company's steam generation facilities impacted by the CCR Rule and the closure of an ash pond at Plant Scholz. In connection with permitting activity related to the coal ash pond at the retired Plant Scholz facility, the Company recorded additional AROs of $29 million in 2015.

The cost estimates for AROs related to CCR are based on information as of December 31, 2016 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure for those facilities impacted by the CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing with respect to compliance activities, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the Company expects to continue to periodically update these estimates.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Allowance for Funds Used During Construction~~

~~Impairment of Long-Lived Assets and Intangibles~~

The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

~~Property Damage Reserve~~

The Company accrues for the cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property. The costs of such damage are charged to the reserve. The Florida PSC approved annual accrual to the property damage reserve is $3.5 million, with a target level for the reserve between $48 million and $55 million. The Florida PSC also authorized the Company to make additional accruals above $3.5 million at the Company's discretion. The Company accrued total expenses of $3.5 million in each of 2016, 2015, and 2014. As of December 31, 2016 and 2015, the balance in the Company's property damage reserve totaled approximately $40 million and ~~$38 million, respectively, which is included in deferred liabilities in the balance sheets.~~

When the property damage reserve is inadequate to cover the cost of major storms, the Florida PSC can authorize a storm cost recovery surcharge to be applied to customer bills. As authorized in the 2013 Rate Case Settlement Agreement, the Company may recover costs associated with any tropical systems named by the National Hurricane Center through the initiation of a storm surcharge. The storm surcharge will begin, on an interim basis, 60 ~~days following the filing of a cost recovery petition. The storm surcharge generally may not exceed~~ ~~$4.00~~/~~1,000~~ KWHs on monthly residential bills in aggregate for a calendar year. This limitation does not apply if the Company incurs in excess of $100 million in storm recovery costs that qualify for recovery in a given calendar year. This threshold amount is inclusive of the amount necessary to replenish the storm reserve to the level that existed as of December 31, 2013. See Note 3 under "Retail Regulatory Matters – Retail Base Rate Cases" for additional details of the 2013 Rate Case Settlement Agreement.

~~Injuries and Damages Reserve~~

The Company is subject to claims and lawsuits arising in the ordinary course of business. As permitted by the Florida PSC, the Company accrues for the uninsured costs of injuries and damages by charges to income amounting to $1.6 million annually. The Florida PSC has also given the Company the flexibility to increase its annual accrual above $1.6 million to the extent the balance in the reserve does not exceed $2 million and to defer expense recognition of liabilities greater than the balance in the reserve. The cost of settling claims is charged to the reserve. The injuries and damages reserve had a balance of $1.4 million at December 31, 2016, which is included in current liabilities in the balance sheets. The balance was zero at December 31, 2015. There were no liabilities in excess of the reserve balance at December 31, 2016. The Company recorded a liability with a corresponding regulatory asset of $1.7 million for estimated liabilities related to outstanding claims and suits in excess of the reserve balance at December 31, 2015, of which $1.6 million and $0.1 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively.

~~Cash and Cash Equivalents~~

~~For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of~~ ~~90 days~~ ~~or less.~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Materials and Supplies~~

~~Fuel Inventory~~

Fuel inventory includes the average cost of oil, natural gas, coal, transportation, and emissions allowances. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.

~~Financial Instruments~~

The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Florida PSC approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. The Florida PSC approved a stipulation and agreement that prospectively imposed a moratorium on the Company's fuel-hedging program in October 2016 through December 31, 2017. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. See Note 10 for additional information regarding derivatives.

Beginning in 2016, the Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2016.

~~Comprehensive Income~~

~~2. RETIREMENT BENEFITS~~

The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). On December 19, 2016, the Company voluntarily contributed $48 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2017. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the FERC. For the year ending December 31, 2017, no other postretirement trust contributions are expected.

~~Actuarial Assumptions~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

Assumptions used to determine net periodic costs: 2016 2015 2014
Pension plans
Discount rate – benefit obligations 4.71 % 4.18 % 5.02 %
Discount rate – interest costs 3.97
4.18
5.02
Discount rate – service costs 5.04
4.48
5.02
Expected long-term return on plan assets 8.20
8.20
8.20
Annual salary increase 4.46
3.59
3.59
Other postretirement benefit plans
Discount rate – benefit obligations 4.51 % 4.04 % 4.86 %
Discount rate – interest costs 3.68
4.04
4.86
Discount rate – service costs 4.88
4.38
4.86
Expected long-term return on plan assets 8.05
8.07
8.08
Annual salary increase 4.46
3.59
3.59

Assumptions used to determine benefit obligations: 2016
2015
Pension plans

Discount rate 4.46 %
4.71 %
Annual salary increase 4.46

4.46
Other postretirement benefit plans

Discount rate 4.25 %
4.51 %
Annual salary increase 4.46

4.46

Initial Cost Trend Rate Ultimate Cost Trend Rate Year That Ultimate Rate is Reached
Pre-65 6.50 % 4.50 % 2025
Post-65 medical 5.00
4.50
2025
Post-65 prescription 10.00
4.50
2025

~~An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at~~ ~~December 31, 2016~~ ~~as follows:~~

1 Percent
Increase

1 Percent
Decrease
(in millions)
Benefit obligation $ 4
$ 3
Service and interest costs —
—

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Pension Plans~~

~~The total accumulated benefit obligation for the pension plans was $460 million at~~ ~~December 31, 2016~~ ~~and~~ ~~$424 million~~ at ~~December 31, 2015. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~were as follows:~~

2016 2015
(in millions)
Change in benefit obligation
Benefit obligation at beginning of year $ 480
$ 491
Service cost 12
12
Interest cost 19
20
Benefits paid (17 ) (20 )
Actuarial (gain) loss 23
(23 )
Balance at end of year 517
480
Change in plan assets
Fair value of plan assets at beginning of year 420
435
Actual return (loss) on plan assets 39
4
Employer contributions 49
1
Benefits paid (17 ) (20 )
Fair value of plan assets at end of year 491
420
Accrued liability $ (26 ) $ (60 )

At ~~December 31, 2016~~, the projected benefit obligations for the qualified and non-qualified pension plans were $494 million and $23 million, respectively. All pension plan assets are related to the qualified pension plan.

~~Amounts recognized in the balance sheets at~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~related to the Company's pension plans consist of the following:~~

2016 2015
(in millions)
Other regulatory assets, deferred $ 153
$ 142
Other current liabilities (1 ) (1 )
Employee benefit obligations (25 ) (59 )

2016 2015 Estimated Amortization in 2017
(in millions)
Prior service cost $ 3
$ 2
$ 1
Net (gain) loss 150
140
7
Regulatory assets $ 153
$ 142

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~are presented in the following table:~~

2016 2015

(in millions)
Regulatory assets:

Beginning balance $ 142
$ 146
Net (gain) loss 16
6
Change in prior service costs 2
—
Reclassification adjustments:

Amortization of prior service costs (1 ) (1 )
Amortization of net gain (loss) (6 ) (9 )
Total reclassification adjustments (7 ) (10 )
Total change 11
(4 )
Ending balance $ 153
$ 142

~~Components of net periodic pension cost were as follows:~~

2016 2015 2014
(in millions)
Service cost $ 12
$ 12
$ 10
Interest cost 19
20
19
Expected return on plan assets (34 ) (32 ) (28 )
Recognized net (gain) loss 6
9
5
Net amortization 1
1
1
Net periodic pension cost $ 4
$ 10
$ 7

Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.

Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2016, estimated benefit payments were as follows:

Benefit
Payments
(in millions)
2017 $ 20
2018 22
2019 23
2020 24
2021 26
2022 to 2026 149

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Other Postretirement Benefits~~

~~Changes in the APBO and in the fair value of plan assets during the plan years ended~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~were as follows:~~

2016 2015
(in millions)
Change in benefit obligation
Benefit obligation at beginning of year $ 81
$ 78
Service cost 1
1
Interest cost 3
3
Benefits paid (4 ) (4 )
Actuarial (gain) loss 2
(1 )
Plan amendment —
4
Balance at end of year 83
81
Change in plan assets
Fair value of plan assets at beginning of year 17
18
Actual return (loss) on plan assets 2
—
Employer contributions 3
3
Benefits paid (4 ) (4 )
Fair value of plan assets at end of year 18
17
Accrued liability $ (65 ) $ (64 )

~~Amounts recognized in the balance sheets at~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~related to the Company's other postretirement benefit plans consist of the following:~~

2016 2015
(in millions)
Other regulatory assets, deferred $ 11
$ 10
Other current liabilities (1 ) (1 )
Other regulatory liabilities, deferred (4 ) (5 )
Employee benefit obligations (64 ) (63 )

~~Approximately $7 million and $5 million was included in net regulatory assets at~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~, respectively, related to the net loss for the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2017 is immaterial.

~~The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended~~ ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~are presented in the following table:~~

2016 2015

(in millions)
Net regulatory assets (liabilities):

Beginning balance $ 5
$ 2
Net (gain) loss 2
1
Change in prior service costs —
2
Total change 2
3
Ending balance $ 7
$ 5

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Components of the other postretirement benefit plans' net periodic cost were as follows:~~

2016 2015 2014
(in millions)
Service cost $ 1
$ 1
$ 1
Interest cost 3
3
3
Expected return on plan assets (1 ) (1 ) (1 )
Net periodic postretirement benefit cost $ 3
$ 3
$ 3

Benefit
Payments

Subsidy
Receipts
Total
(in millions)
2017 $ 5
$ —
$ 5
2018 5
—
5
2019 6
(1 ) 5
2020 6
(1 ) 5
2021 6
(1 ) 5
2022 to 2026 30
(3 ) 27

~~Benefit Plan Assets~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

Target 2016 2015
Pension plan assets:
Domestic equity 26 % 29 % 30 %
International equity 25
22
23
Fixed income 23
29
23
Special situations 3
2
2
Real estate investments 14
13
16
Private equity 9
5
6
Total 100 % 100 % 100 %
Other postretirement benefit plan assets:
Domestic equity 25 % 28 % 29 %
International equity 24
21
22
Domestic fixed income 25
31
25
Special situations 3
2
2
Real estate investments 14
13
16
Private equity 9
5
6
Total 100 % 100 % 100 %

~~Investment Strategies~~

~~Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above:~~

~~International equity.~~ ~~A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.~~

~~Fixed income.~~ ~~A mix of domestic and international bonds.~~

~~Benefit Plan Asset Fair Values~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.~~

~~Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:~~

Fair Value Measurements Using
Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient
As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Assets:
Domestic equity^(*)
$ 93
$ 43
$ —
$ —
$ 136
International equity^(*)
57
52
—
—
109
Fixed income:
U.S. Treasury, government, and agency bonds —
27
—
—
27
Mortgage- and asset-backed securities —
1
—
—
1
Corporate bonds —
47
—
—
47
Pooled funds —
24
—
—
24
Cash equivalents and other 46
—
—
—
46
Real estate investments 14
—
—
53
67
Special situations —
—
—
8
8
Private equity —
—
—
25
25
Total $ 210
$ 194
$ —
$ 86
$ 490


~~(*)~~	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

Fair Value Measurements Using
Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient
As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Assets:
Domestic equity^(*)
$ 73
$ 31
$ —
$ —
$ 104
International equity^(*)
54
45
—
—
99
Fixed income:
U.S. Treasury, government, and agency bonds —
21
—
—
21
Mortgage- and asset-backed securities —
9
—
—
9
Corporate bonds —
51
—
—
51
Pooled funds —
23
—
—
23
Cash equivalents and other —
7
—
—
7
Real estate investments 14
—
—
55
69
Private equity —
—
—
29
29
Total $ 141
$ 187
$ —
$ 84
$ 412


~~(*)~~	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

Fair Value Measurements Using
Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient
As of December 31, 2016: (Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Assets:
Domestic equity^(*)
$ 3
$ 2
$ —
$ —
$ 5
International equity^(*)
2
2
—
—
4
Fixed income:
U.S. Treasury, government, and agency bonds —
1
—
—
1
Corporate bonds —
2
—
—
2
Pooled funds —
1
—
—
1
Cash equivalents and other 2
—
—
—
2
Real estate investments 1
—
—
2
3
Private equity —
—
—
1
1
Total $ 8
$ 8
$ —
$ 3
$ 19


~~(*)~~	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

Fair Value Measurements Using
Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Net Asset Value as a Practical Expedient
As of December 31, 2015: (Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Assets:
Domestic equity^(*)
$ 3
$ 1
$ —
$ —
$ 4
International equity^(*)
2
2
—
—
4
Fixed income:
U.S. Treasury, government, and agency bonds —
1
—
—
1
Corporate bonds —
2
—
—
2
Pooled funds —
1
—
—
1
Cash equivalents and other 1
—
—
—
1
Real estate investments 1
—
—
2
3
Private equity —
—
—
1
1
Total $ 7
$ 7
$ —
$ 3
$ 17


~~(*)~~	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

~~Employee Savings Plan~~

The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2016, 2015, and 2014 were $5 million, $4 million, and $4 million, respectively.

~~3. CONTINGENCIES AND REGULATORY MATTERS~~

~~General Litigation Matters~~

~~Environmental Matters~~

~~Environmental Remediation~~

The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up affected sites. The Company received authority from the Florida PSC to recover approved environmental compliance costs through the environmental cost recovery clause. The Florida PSC reviews costs and adjusts rates up or down annually.

~~The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable. At~~ ~~December 31, 2016~~, the Company's environmental remediation liability included estimated costs of environmental remediation projects of approximately $44 million, of which approximately $4 million is included in under recovered regulatory clause revenues and other current liabilities and approximately $40 million is included in other regulatory assets, deferred and other deferred credits and

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

liabilities. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at the Company's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through the Company's environmental cost recovery clause; therefore, these liabilities have no impact on net income.

The ultimate outcome of these matters cannot be determined at this time; however, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, the Company does not believe that additional liabilities, if any, at these sites would be material to the Company's financial statements.

~~FERC Matters~~

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Retail Regulatory Matters~~

~~Retail Base Rate Cases~~

The 2013 Rate Case Settlement Agreement also provides that the Company may reduce depreciation and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction may not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in the 2016 Rate Case, as defined below. For 2014 and 2015, the Company recognized reductions in depreciation expense of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

11% compared to the current retail ROE of 10.25%. The requested increase includes recovery of the portion of Plant Scherer Unit 3 that has been rededicated to serving retail customers following the contract expirations at the end of 2015 and May 2016. If retail recovery of Plant Scherer Unit 3 is not approved by the Florida PSC in the 2016 Rate Case, the Company may consider an asset sale. The current book value of the Company's ownership of Plant Scherer Unit 3 could exceed market value which could result in a material loss. The Florida PSC is expected to make a decision on the 2016 Rate Case in the second quarter 2017. The Company has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017. The ultimate outcome of this matter cannot be determined at this time.

~~Cost Recovery Clauses~~

~~Retail Fuel Cost Recovery~~

~~The Company has established fuel cost recovery rates as approved by the Florida PSC. If, at any time during the year, the projected year-end fuel cost over or under recovery balance exceeds~~ ~~10%~~ ~~of the projected fuel revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested.~~

At December 31, 2016 and 2015, the over recovered fuel balance was approximately $15 million and $18 million, respectively, which is included in other regulatory liabilities, current in the balance sheets.

~~Purchased Power Capacity Recovery~~

~~The Company has established purchased power capacity recovery cost rates as approved by the Florida PSC. If the projected year-end purchased power capacity cost over or under recovery balance exceeds~~ ~~10%~~ of the projected purchased power capacity revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the purchased power capacity cost recovery factor is being requested.

At ~~December 31, 2016~~ ~~and 2015, the under recovered purchased power capacity balance was immaterial.~~

~~Environmental Cost Recovery~~

The Florida Legislature adopted legislation for an environmental cost recovery clause, which allows an electric utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Such environmental costs include operations and maintenance expenses, emissions allowance expense, depreciation, and a return on net average investment. This legislation also allows recovery of costs incurred as a result of an agreement between the Company and the FDEP for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA.

~~Annually, the Company seeks recovery of projected costs including any true-up amounts from prior periods. At~~ ~~December 31, 2016~~, the over recovered environmental balance of approximately $8 million, along with the current portion of projected environmental expenditures, was included in under recovered regulatory clause revenues in the balance sheet. At December 31, 2015, the over recovered environmental balance was immaterial.

In 2012, the Mississippi PSC approved Mississippi Power's request for a certificate of public convenience and necessity to construct scrubbers on Plant Daniel Units 1 and 2, which were placed in service in November 2015. These units are jointly owned by Mississippi Power and the Company, with 50% ownership each. The total cost of the project was approximately $653 million, with the Company's portion being approximately $316 million, excluding AFUDC. The Company's portion of the cost is being recovered through the environmental cost recovery clause.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Energy Conservation Cost Recovery~~

~~Every five years, the Florida PSC establishes new numeric conservation goals covering a~~ 10-year period for utilities to reduce annual energy and seasonal peak demand using demand-side management (DSM) programs. After the goals are established, utilities develop plans and programs to meet the approved goals. The costs for these programs are recovered through rates established annually in the energy conservation cost recovery (ECCR) clause.

At ~~December 31, 2016~~, the under recovered ECCR balance was approximately $4 million, which is included in under recovered regulatory clause revenues in the balance sheet. At December 31, 2015, the over recovered ECCR balance was approximately $4 million, which is included in other regulatory liabilities, current in the balance sheet.

~~Other Matters~~

As a result of the cost to comply with environmental regulations imposed by the EPA, the Company retired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) on March 31, 2016. The Company filed a petition with the Florida PSC requesting permission to recover the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date. On August 29, 2016, the Florida PSC approved the Company's request to reclassify these costs, totaling $63 million, to a regulatory asset for recovery over a period to be decided in the 2016 Rate Case. The ultimate outcome of this matter cannot be determined at this time.

~~4. JOINT OWNERSHIP AGREEMENTS~~

The Company and Mississippi Power jointly own Plant Daniel Units 1 and 2, which together represent capacity of 1,000 MWs. Plant Daniel is a generating plant located in Jackson County, Mississippi. In accordance with the operating agreement, Mississippi Power acts as the Company's agent with respect to the construction, operation, and maintenance of these units.

The Company and Georgia Power jointly own the 818-MW capacity Plant Scherer Unit 3. Plant Scherer is a generating plant located near Forsyth, Georgia. In accordance with the operating agreement, Georgia Power acts as the Company's agent with respect to the construction, operation, and maintenance of the unit.

At ~~December 31, 2016, the Company's percentage ownership and investment in these jointly-owned facilities were as follows:~~

Plant Scherer
Unit 3 (coal)
Plant Daniel Units 1 & 2 (coal)
(in millions)
Plant in service $ 398
$ 680
Accumulated depreciation 143
202
Construction work in progress 7
7
Company ownership 25 % 50 %

The Company's proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income and the Company is responsible for providing its own financing.

~~5. INCOME TAXES~~

On behalf of the Company, Southern Company files a consolidated federal income tax return and various combined and separate state income tax returns. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Current and Deferred Income Taxes~~

~~Details of income tax provisions are as follows:~~

2016 2015 2014
(in millions)
Federal -
Current $ 34
$ (3 ) $ 23
Deferred 45
80
52
79
77
75
State -
Current —
5
—
Deferred 12
10
13
12
15
13
Total $ 91
$ 92
$ 88

2016 2015
(in millions)
Deferred tax liabilities-
Accelerated depreciation $ 834
$ 812
Property basis differences 123
133
Pension and other employee benefits 58
39
Regulatory assets 45
16
Regulatory assets associated with employee benefit obligations 65
59
Regulatory assets associated with asset retirement obligations 55
40
Other 12
10
Total 1,192
1,109
Deferred tax assets-
Federal effect of state deferred taxes 37
33
Postretirement benefits 26
26
Pension and other employee benefits 72
65
Property reserve 17
15
Asset retirement obligations 55
40
Alternative minimum tax carryforward 18
18
Other 19
19
Total 244
216
Accumulated deferred income taxes $ 948
$ 893

~~The application of bonus depreciation provisions in current tax law significantly increased deferred tax liabilities related to accelerated depreciation in 2016 and 2015.~~

At December 31, 2016, tax-related regulatory assets to be recovered from customers were $58 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest.

At December 31, 2016, the tax-related regulatory liabilities to be credited to customers were $2 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and unamortized ITCs.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

In accordance with regulatory requirements, deferred federal ITCs are amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner are not material for the periods presented. At December 31, 2016, all ITCs available to reduce federal income taxes payable had been utilized.

~~Effective Tax Rate~~

~~A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:~~

2016 2015 2014
Federal statutory rate 35.0% 35.0% 35.0%
State income tax, net of federal deduction 3.4 3.9 3.5
Non-deductible book depreciation 0.6 0.5 0.4
Differences in prior years' deferred and current tax rates (0.1) (0.1) (0.1)
AFUDC equity — (1.8) (1.8)
Other, net 0.6 (0.6) 0.1
Effective income tax rate 39.5% 36.9% 37.1%

~~The increase in the Company's 2016 effective tax rate is primarily the result of the decrease in nontaxable AFUDC equity.~~

~~Unrecognized Tax Benefits~~

The Company has no material unrecognized tax benefits for the periods presented. The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial and the Company did not accrue any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances, but an estimate of the range of reasonably possible outcomes cannot be determined at this time.

The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013, 2014, and 2015 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.

~~6. FINANCING~~

~~Securities Due Within One Year~~

~~At December 31, 2016 and 2015, the Company had $87 million and $110 million of long-term debt due within one year, respectively.~~

~~Maturities through 2021 applicable to total long-term debt include $87 million in 2017 and $175 million in 2020. There are no scheduled maturities in 2018, 2019, or 2021.~~

~~Bank Term Loans~~

In May 2016, the Company entered into an 11-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes.

This bank loan has a covenant that limits debt levels to 65% of total capitalization, as defined in the agreement. For purposes of this definition, debt excludes certain hybrid securities. At December 31, 2016, the Company was in compliance with its debt limit.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Senior Notes~~

At ~~December 31, 2016~~ ~~and~~ ~~2015~~, the Company had a total of $777 million and $1.01 billion of senior notes outstanding, respectively. These senior notes are effectively subordinate to all secured debt of the Company, which totaled approximately $41 million at both ~~December 31, 2016~~ ~~and 2015.~~

~~In May 2016, the Company redeemed $125 million aggregate principal amount of its Series 2011A 5.75% Senior Notes due June 1, 2051.~~

~~Pollution Control Revenue Bonds~~

Pollution control revenue bond obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bond obligations outstanding at ~~December 31, 2016~~ ~~and~~ ~~2015~~ ~~was $309 million.~~

~~Outstanding Classes of Capital Stock~~

The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company's preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company's preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. No shares of preferred stock or Class A preferred stock were outstanding at December 31, 2016. The Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the preference stock are subject to redemption at the option of the Company on or after a specified date (typically ~~five~~ ~~or 10 years after the date of issuance) at a redemption price equal to~~ ~~100%~~ ~~of the liquidation amount of the preference stock. In addition, certain series of the preference stock may be redeemed earlier at a redemption price equal to~~ ~~100%~~ ~~of the liquidation amount plus a make-whole premium based on the present value of the liquidation amount and future dividends.~~

In January 2015, the Company issued 200,000 shares of common stock to Southern Company and realized proceeds of $20 million. The proceeds were used to repay a portion of the Company's short-term debt and for other general corporate purposes, including the Company's continuous construction program.

Subsequent to December 31, 2016, the Company issued 1,750,000 shares of common stock to Southern Company and realized proceeds of $175 million. The proceeds were used for general corporate purposes, including the Company's continuous construction program.

~~Dividend Restrictions~~

~~The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.~~

~~Assets Subject to Lien~~

The Company has granted a lien on its property at Plant Daniel in connection with the issuance of two series of pollution control revenue bonds with an aggregate outstanding principal amount of $41 million as of December 31, 2016. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its subsidiaries.

~~Bank Credit Arrangements~~

At ~~December 31, 2016, committed credit arrangements with banks were as follows:~~

~~Most of the bank credit arrangements require payment of commitment fees based on the unused portion of the commitments. Commitment fees average less than~~ ¹/₄ ~~of 1% for the Company.~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

Subject to applicable market conditions, the Company expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, the Company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

Most of these bank credit arrangements contain covenants that limit the Company's debt level to 65% of total capitalization, as defined in the arrangements. For purposes of these definitions, debt excludes certain hybrid securities. At December 31, 2016, the Company was in compliance with these covenants.

Most of the $280 million of unused credit arrangements with banks provide liquidity support to the Company's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2016 was approximately $82 million. In addition, at December 31, 2016, the Company had $86 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.

For short-term cash needs, the Company borrows primarily through a commercial paper program that has the liquidity support of the Company's committed bank credit arrangements described above. The Company may also borrow through various other arrangements with banks. Commercial paper and short-term bank loans are included in notes payable in the balance sheets.

~~Details of short-term borrowings were as follows:~~

Short-term Debt at the
End of the Period
Amount Outstanding Weighted Average Interest Rate
(in millions)
December 31, 2016:
  Commercial paper $ 168
1.1%
  Short-term bank debt 100
1.5%
Total $ 268
1.2%
December 31, 2015:
  Commercial paper $ 142
0.7%

~~7. COMMITMENTS~~

~~Fuel and Purchased Power Agreements~~

To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil fuel which are not recognized on the balance sheets. In 2016, 2015, and 2014, the Company incurred fuel expense of $432 million, $445 million, and $605 million, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments.

In addition, the Company has entered into various long-term commitments for the purchase of capacity, energy, and transmission, some of which are accounted for as operating leases. The energy-related costs associated with PPAs are recovered through the fuel cost recovery clause. The capacity and transmission-related costs associated with PPAs are recovered through the purchased power capacity cost recovery clause. Capacity expense under a PPA accounted for as an operating lease was $75 million for both 2016 and 2015 and ~~$50 million~~ ~~for 2014.~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~Estimated total minimum long-term commitments at December 31, 2016 were as follows:~~

Operating Lease PPA
(in millions)
2017 $ 79
2018 79
2019 79
2020 79
2021 79
2022 and thereafter 112
Total $ 507

~~Operating Leases~~

~~In addition to the operating lease PPA discussed above, the Company has other operating lease agreements with various terms and expiration dates. Total rent expense was $9 million, $14 million, and~~ ~~$15 million~~ ~~for~~ ~~2016~~, ~~2015, and~~ ~~2014, respectively.~~

~~Estimated total minimum lease payments under these operating leases at December 31, 2016 were as follows:~~

Minimum Lease Payments

Barges &
Railcars
Other Total
(in millions)
2017 $ 7
$ 1
$ 8
2018 5
1
6
2019 —
1
1
2020 —
—
—
2021 —
—
—
2022 and thereafter —
1
1
Total $ 12
$ 4
$ 16

The Company and Mississippi Power jointly entered into an operating lease agreement for aluminum railcars for the transportation of coal to Plant Daniel. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value or to renew the leases at the end of the lease term. The Company and Mississippi Power also have separate lease agreements for other railcars that do not include purchase options. The Company's 50% share of the lease costs, charged to fuel inventory and recovered through the retail fuel cost recovery clause, was $2 million in both 2016 and 2015 and $3 million in 2014. The Company's total annual railcar lease payments for 2017 are $2 million and are immaterial for 2018 through 2020.

In addition to railcar leases, the Company has operating lease agreements for barges and towboats for the transport of coal to Plant Crist. The Company has the option to renew the leases at the end of the lease term. The Company's lease costs, charged to fuel inventory and recovered through the retail fuel cost recovery clause, were $5 million in 2016 and $10 million in both 2015 and 2014. The Company's annual barge and towboat payments for 2017 and 2018 are expected to be approximately $5 million each year.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~8. STOCK COMPENSATION~~

~~Stock-Based Compensation~~

Stock-based compensation primarily in the form of Southern Company performance share units may be granted through the Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. As of December 31, 2016, there were 184 current and former employees participating in the stock option and performance share unit programs.

~~Stock Options~~

Through 2009, stock-based compensation granted to employees consisted exclusively of non-qualified stock options. The exercise price for stock options granted equaled the stock price of Southern Company common stock on the date of grant. Stock options vest on a pro rata basis over a maximum period of three years from the date of grant or immediately upon the retirement or death of the employee. Options expire no later than 10 years after the grant date. All unvested stock options vest immediately upon a change in control where Southern Company is not the surviving corporation. Compensation expense is generally recognized on a straight-line basis over the three-year vesting period with the exception of employees that are retirement eligible at the grant date and employees that will become retirement eligible during the vesting period. Compensation expense in those instances is recognized at the grant date for employees that are retirement eligible and through the date of retirement eligibility for those employees that become retirement eligible during the vesting period. In 2015, Southern Company discontinued the granting of stock options.

~~The weighted average grant-date fair value of stock options granted during 2014 derived using the Black-Scholes stock option pricing model was $2.20.~~

The total intrinsic value of options exercised during the years ended December 31, 2016, 2015, and 2014 was $3 million, $2 million, and $5 million, respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $1 million for the years ended December 31, 2016 and 2015 and $2 million for 2014. Prior to the adoption of ASU 2016-09, the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2016, the aggregate intrinsic value for the options outstanding and options exercisable was $6 million and $5 million, respectively.

~~Performance Share Units~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

(EPS) over the performance period and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period. The EPS-based and ROE-based awards each represent 25% of total target grant date fair value of the performance share unit awards granted. The remaining 50% of the target grant date fair value consists of TSR-based awards. In contrast to the Monte Carlo simulation model used to determine the fair value of the TSR-based awards, the fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three-year performance period initially assuming a 100% payout at the end of the performance period. The TSR-based performance share units, along with the EPS-based and ROE-based awards, vest immediately upon the retirement of the employee. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period.

For the years ended December 31, 2016, 2015, and 2014, employees of the Company were granted performance share units of 57,333, 48,962, and 37,829, respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2016, 2015, and 2014, determined using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period, was $45.18, $46.38, and $37.54, respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2016 and 2015 was $48.83 and $47.75, respectively.

For the years ended December 31, 2016, 2015, and 2014, total compensation cost for performance share units recognized in income was $3 million, $2 million, and $1 million, respectively. The related tax benefit also recognized in income was $1 million in 2016 and 2015 and immaterial in 2014. The compensation cost related to the grant of Southern Company performance share units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2016, $2 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 22 months.

~~9. FAIR VALUE MEASUREMENTS~~

~~Level 1 consists of observable market data in an active market for identical assets or liabilities.~~

~~Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~As of~~ ~~December 31, 2015, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:~~

~~Valuation Methodologies~~

The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflect the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 10 for additional information on how these derivatives are used.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~As of~~ ~~December 31, 2016~~ ~~and~~ ~~2015, other financial instruments for which the carrying amount did not equal fair value were as follows:~~

Carrying
Amount

Fair
Value
(in millions)
Long-term debt:
2016 $ 1,074
$ 1,097
2015 $ 1,303
$ 1,339

~~The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Company.~~

~~10. DERIVATIVES~~

The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and may enter into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 9 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.

~~Energy-Related Derivatives~~

The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in energy-related commodity prices. The Company manages fuel-hedging programs, implemented per the guidelines of the Florida PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The Florida PSC approved a stipulation and agreement that prospectively imposed a moratorium on the Company's fuel-hedging program in October 2016 through December 31, 2017. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program.

~~Energy-related derivative contracts are accounted for under one of three methods:~~

~~Regulatory Hedges~~ — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery clause.

~~Cash Flow Hedges~~ — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

~~Not Designated~~ ~~— Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.~~

At ~~December 31, 2016~~, the net volume of energy-related derivative contracts for natural gas positions totaled 51 million mmBtu for the Company, with the longest hedge date of 2020 over which it is hedging its exposure to the variability in future cash flows for forecasted transactions.

~~Interest Rate Derivatives~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings.

~~At December 31, 2016, the following interest rate derivative was outstanding:~~

Notional
Amount Interest
Rate
Received Weighted Average Interest
Rate Paid Hedge
Maturity
Date Fair Value
Gain (Loss)
December 31,
2016
(in millions) (in millions)
Cash Flow Hedges of Forecasted Debt
$ 80
3-month LIBOR 2.32% December 2026 $ —

~~The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the 12-month period ending~~ ~~December 31, 2017~~ ~~are immaterial. The Company has deferred gains and losses that are expected to be amortized into earnings through 2026.~~

~~Derivative Financial Statement Presentation and Amounts~~

The Company enters into energy-related and interest rate derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. At December 31, 2016, fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties. At December 31, 2015, the fair value amounts of derivative instruments were presented gross on the balance sheets.

At ~~December 31, 2016~~ ~~and 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:~~

2016 2015
Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities
(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Liabilities from risk management activities $ 4
$ 12
$ —
$ 49
Other deferred charges and assets/Other deferred credits and liabilities 1
17
—
51
Total derivatives designated as hedging instruments for regulatory purposes $ 5
$ 29
$ —
$ 100
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Liabilities from risk management activities —
—
1
—
Gross amounts recognized $ 5
$ 29
$ 1
$ 100
Gross amounts offset $ (4 ) $ (4 ) $ —
$ —
Net amounts recognized in the Balance Sheets^(*)
$ 1
$ 25
$ 1
$ 100


~~(*)~~	~~At December 31, 2015, the fair value amounts for derivative contracts subject to netting arrangements were presented gross on the balance sheet.~~

~~Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2016 and 2015.~~

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

Unrealized Losses Unrealized Gains
Derivative Category
Balance Sheet
Location
2016 2015
Balance Sheet
Location
2016 2015
(in millions) (in millions)
Energy-related derivatives:^(*)
Other regulatory assets, current $ (9 ) $ (49 ) Other regulatory liabilities, current $ 1
$ —
Other regulatory assets, deferred (16 ) (51 ) Other regulatory liabilities, deferred —
—
Total energy-related derivative gains (losses) $ (25 ) $ (100 ) $ 1
$ —


~~(*)~~	At December 31, 2016, the unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheet. At December 31, 2015, the unrealized gains and losses for derivative contracts were presented gross on the balance sheet.

~~For the years ended~~ ~~December 31, 2016~~, ~~2015, and~~ ~~2014, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:~~

Derivatives in Cash
Flow Hedging Relationships
Gain (Loss) Recognized in
OCI on Derivative

Gain (Loss) Reclassified from Accumulated
OCI into Income (Effective Portion)
(Effective Portion) Amount
Derivative Category 2016 2015 2014 Statements of Income Location 2016 2015 2014
(in millions) (in millions)
Interest rate derivatives $ —
$ 1
$ —
Interest expense, net of amounts capitalized $ (1 ) $ (1 ) $ (1 )

~~There was no material ineffectiveness recorded in earnings for any period presented.~~

~~For the years ended December 31, 2016, 2015, and 2014, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were not material.~~

~~Contingent Features~~

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2016, the Company's collateral posted with its derivative counterparties was not material.

At December 31, 2016, the fair value of derivative liabilities with contingent features, including certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade because of joint and several liability features underlying these derivatives, was immaterial.

~~Table of ContentsIndex to Financial Statements~~

~~NOTES (continued)~~

~~Gulf Power Company 2016 Annual Report~~

~~11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)~~

~~Summarized quarterly financial information for~~ ~~2016~~ ~~and~~ ~~2015~~ ~~is as follows:~~

Quarter Ended
Operating
Revenues

Operating
Income
Net Income After Dividends on Preference Stock
(in millions)
March 2016 $ 335
$ 65
$ 29
June 2016 365
74
34
September 2016 436
90
45
December 2016 349
54
23

March 2015 $ 357
$ 72
$ 37
June 2015 384
69
35
September 2015 429
91
48
December 2015 313
58
28

In accordance with the adoption of ASU 2016-09 (see Note 1 under "Recently Issued Accounting Standards"), previously reported amounts for income tax expense were reduced by an immaterial amount for the first, second, and third quarters of 2016.

~~The Company's business is influenced by seasonal weather conditions.~~

~~Table of ContentsIndex to Financial Statements~~

~~SELECTED FINANCIAL AND OPERATING DATA 2012-2016~~

~~Gulf Power Company 2016 Annual Report~~

2016
2015
2014
2013
2012
Operating Revenues (in millions) $ 1,485
$ 1,483
$ 1,590
$ 1,440
$ 1,440
Net Income After Dividends
on Preference Stock (in millions)
$ 131
$ 148
$ 140
$ 124
$ 126
Cash Dividends
on Common Stock (in millions)
$ 120
$ 130
$ 123
$ 115
$ 116
Return on Average Common Equity (percent) 9.52
11.11
11.02
10.30
10.92
Total Assets (in millions)^(a)(b)
$ 4,822
$ 4,920
$ 4,697
$ 4,321
$ 4,167
Gross Property Additions (in millions) $ 179
$ 247
$ 361
$ 305
$ 325
Capitalization (in millions):
Common stock equity $ 1,389
$ 1,355
$ 1,309
$ 1,235
$ 1,181
Preference stock 147
147
147
147
98
Long-term debt^(a)
987
1,193
1,362
1,150
1,178
Total (excluding amounts due within one year) $ 2,523
$ 2,695
$ 2,818
$ 2,532
$ 2,457
Capitalization Ratios (percent):
Common stock equity 55.1
50.3
46.5
48.8
48.1
Preference stock 5.8
5.4
5.2
5.8
4.0
Long-term debt^(a)
39.1
44.3
48.3
45.4
47.9
Total (excluding amounts due within one year) 100.0
100.0
100.0
100.0
100.0
Customers (year-end):
Residential 398,501
393,149
388,292
383,980
379,922
Commercial 56,091
55,460
54,892
54,567
53,808
Industrial 254
248
260
260
264
Other 569
614
603
582
577
Total 455,415
449,471
444,047
439,389
434,571
Employees (year-end) 1,352
1,391
1,384
1,410
1,416



~~(a)~~	A reclassification of debt issuance costs from Total Assets to Long-term debt of $8 million, $8 million, and $8 million is reflected for years 2014, 2013, and 2012, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively.
~~(b)~~	A reclassification of deferred tax assets from Total Assets of $3 million, $8 million, and $2 million is reflected for years 2014, 2013, and 2012, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively.

~~Table of ContentsIndex to Financial Statements~~

~~SELECTED FINANCIAL AND OPERATING DATA 2012-2016 (continued)~~

~~Gulf Power Company 2016 Annual Report~~

2016
2015
2014
2013
2012
Operating Revenues (in millions):
Residential $ 714
$ 698
$ 700
$ 632
$ 609
Commercial 410
403
408
395
390
Industrial 152
144
153
139
140
Other 5
4
6
4
5
Total retail 1,281
1,249
1,267
1,170
1,144
Wholesale — non-affiliates 61
107
129
109
107
Wholesale — affiliates 75
58
130
100
124
Total revenues from sales of electricity 1,417
1,414
1,526
1,379
1,375
Other revenues 68
69
64
61
65
Total $ 1,485
$ 1,483
$ 1,590
$ 1,440
$ 1,440
Kilowatt-Hour Sales (in millions):
Residential 5,358
5,365
5,362
5,089
5,054
Commercial 3,869
3,898
3,838
3,810
3,859
Industrial 1,830
1,798
1,849
1,700
1,725
Other 25
25
26
21
25
Total retail 11,082
11,086
11,075
10,620
10,663
Wholesale — non-affiliates 751
1,040
1,670
1,163
977
Wholesale — affiliates 2,784
1,906
3,284
3,127
4,370
Total 14,617
14,032
16,029
14,910
16,010
Average Revenue Per Kilowatt-Hour (cents):
Residential 13.33
13.01
13.06
12.43
12.06
Commercial 10.60
10.34
10.64
10.37
10.11
Industrial 8.31
8.01
8.28
8.15
8.14
Total retail 11.56
11.27
11.44
11.02
10.73
Wholesale 3.85
5.60
5.23
4.87
4.31
Total sales 9.69
10.08
9.52
9.25
8.59
Residential Average Annual
Kilowatt-Hour Use Per Customer 13,515
13,705
13,865
13,301
13,303
Residential Average Annual
Revenue Per Customer $ 1,801
$ 1,783
$ 1,811
$ 1,653
$ 1,604
Plant Nameplate Capacity
Ratings (year-end) (megawatts) 2,278
2,583
2,663
2,663
2,663
Maximum Peak-Hour Demand (megawatts):
Winter 2,033
2,488
2,684
1,729
2,130
Summer 2,503
2,491
2,424
2,356
2,344
Annual Load Factor (percent) 54.7
54.9
51.1
55.9
56.3
Plant Availability Fossil-Steam (percent) 81.0
88.3
89.4
92.8
82.5
Source of Energy Supply (percent):
Coal 31.0
33.5
44.5
36.4
34.6
Gas 23.2
25.6
22.2
23.0
23.5
Purchased power —
From non-affiliates 41.1
30.4
28.9
37.0
40.2
From affiliates 4.7
10.5
4.4
3.6
1.7
Total 100.0
100.0
100.0
100.0
100.0

~~Table of ContentsIndex to Financial Statements~~

~~MISSISSIPPI POWER COMPANY~~

~~FINANCIAL SECTION~~

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING~~

~~Mississippi Power Company 2016 Annual Report~~

The management of Mississippi Power Company (the Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

~~/s/ Anthony L. Wilson~~

~~Anthony L. Wilson~~

~~Chairman, President, and Chief Executive Officer~~

~~/s/ Moses H. Feagin~~

~~Moses H. Feagin~~

~~Vice President, Chief Financial Officer, and Treasurer~~

~~February 21, 2017~~

~~Table of ContentsIndex to Financial Statements~~

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Southern Company Gas and Subsidiary Companies

Opinion on the Financial Statements

Basis for Opinion

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Southern Company Gas is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Southern Company Gas' internal control over financial reporting. Accordingly, we express no such opinion.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 19, 2020

We have served as Southern Company Gas' auditor since 2016.

Table of ContentsIndex to Financial Statements

CONSOLIDATED STATEMENTS OF INCOME

Southern Company Gas and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of $117, $114, and $100 for the periods presented, respectively)	$	3,793		$	3,874		$	3,787
Alternative revenue programs	(1		)	(20		)	4
Other revenues	—			55			129
Total operating revenues	3,792			3,909			3,920
Operating Expenses:
Cost of natural gas	1,319			1,539			1,601
Cost of other sales	—			12			29
Other operations and maintenance	888			981			945
Depreciation and amortization	487			500			501
Taxes other than income taxes	213			211			184
Impairment charges	115			42			—
(Gain) loss on dispositions, net	—			(291		)	—
Total operating expenses	3,022			2,994			3,260
Operating Income	770			915			660
Other Income and (Expense):
Earnings from equity method investments	157			148			106
Interest expense, net of amounts capitalized	(232		)	(228		)	(200		)
Other income (expense), net	20			1			44
Total other income and (expense)	(55		)	(79		)	(50		)
Earnings Before Income Taxes	715			836			610
Income taxes	130			464			367
Net Income	$	585		$	372		$	243

The accompanying notes are an integral part of these consolidated financial statements.

Table of ContentsIndex to Financial Statements

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Southern Company Gas and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Net Income	$	585		$	372		$	243
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(2), $2, and $(3), respectively	(5		)	5			(5		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $(1), and $-, respectively	2			(1		)	1
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax of $(14), $-, and $-, respectively	(16		)	—			(1		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $3, and $-, respectively	—			(2		)	—
Total other comprehensive income (loss)	(19		)	2			(5		)
Comprehensive Income	$	566		$	374		$	238

The accompanying notes are an integral part of these consolidated financial statements.

Table of ContentsIndex to Financial Statements

CONSOLIDATED STATEMENTS OF CASH FLOWS

Southern Company Gas and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Activities:
Net income	$	585		$	372		$	243
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	487			500			501
Deferred income taxes	213			(1		)	236
Pension and postretirement funding	(145		)	—			—
Impairment charges	115			42			—
(Gain) loss on dispositions, net	—			(291		)	—
Mark-to-market adjustments	(56		)	(19		)	(24		)
Other, net	(55		)	(24		)	(51		)
Changes in certain current assets and liabilities —
-Receivables	467			(218		)	(94		)
-Natural gas for sale	44			49			36
-Prepaid income taxes	40			(42		)	(39		)
-Other current assets	31			4			(24		)
-Accounts payable	(520		)	372			(20		)
-Accrued taxes	(69		)	10			110
-Accrued compensation	1			32			15
-Other current liabilities	(71		)	(22		)	(8		)
Net cash provided from operating activities	1,067			764			881
Investing Activities:
Property additions	(1,408		)	(1,388		)	(1,514		)
Cost of removal, net of salvage	(82		)	(96		)	(66		)
Change in construction payables, net	24			(37		)	72
Investments in unconsolidated subsidiaries	(31		)	(110		)	(145		)
Returned investment in unconsolidated subsidiaries	67			20			80
Proceeds from dispositions and asset sales	32			2,609			—
Other investing activities	12			—			5
Net cash provided from (used for) investing activities	(1,386		)	998			(1,568		)
Financing Activities:
Increase (decrease) in notes payable, net	—			(868		)	262
Proceeds —
First mortgage bonds	300			300			400
Capital contributions from parent company	821			24			103
Senior notes	—			—			450
Redemptions and repurchases —
Gas facility revenue bonds	—			(200		)	—
Medium-term notes	—			—			(22		)
First mortgage bonds	(50		)	—			—
Senior notes	(300		)	(155		)	—
Return of capital to parent company	—			(400		)	—
Payment of common stock dividends	(471		)	(468		)	(443		)
Other financing activities	(2		)	(3		)	(9		)
Net cash provided from (used for) financing activities	298			(1,770		)	741
Net Change in Cash, Cash Equivalents, and Restricted Cash	(21		)	(8		)	54
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	70			78			24
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	49		$	70		$	78
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $6, $7, and $11 capitalized, respectively)	$	251		$	249		$	223
Income taxes (net of refunds)	(41		)	524			72
Noncash transactions — Accrued property additions at year-end	122			97			135

The accompanying notes are an integral part of these consolidated financial statements.

Table of ContentsIndex to Financial Statements

CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and 2018

Southern Company Gas and Subsidiary Companies 2019 Annual Report



Assets	2019			2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	46		$	64
Receivables —
Energy marketing receivable	428			801
Customer accounts receivable	323			370
Unbilled revenues	183			213
Affiliated	5			11
Other accounts and notes receivable	114			142
Accumulated provision for uncollectible accounts	(18		)	(30		)
Natural gas for sale	479			524
Prepaid expenses	65			118
Assets from risk management activities, net of collateral	177			219
Other regulatory assets	92			73
Assets held for sale	171			—
Other current assets	41			50
Total current assets	2,106			2,555
Property, Plant, and Equipment:
In service	16,344			15,177
Less: Accumulated depreciation	4,650			4,400
Plant in service, net of depreciation	11,694			10,777
Construction work in progress	613			580
Total property, plant, and equipment	12,307			11,357
Other Property and Investments:
Goodwill	5,015			5,015
Equity investments in unconsolidated subsidiaries	1,251			1,538
Other intangible assets, net of amortization of $176 and $145 at December 31, 2019 and December 31, 2018, respectively	70			101
Miscellaneous property and investments	20			20
Total other property and investments	6,356			6,674
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	93			—
Other regulatory assets, deferred	618			669
Other deferred charges and assets	207			193
Total deferred charges and other assets	918			862
Total Assets	$	21,687		$	21,448

The accompanying notes are an integral part of these consolidated financial statements.

Table of ContentsIndex to Financial Statements

CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and 2018

Southern Company Gas and Subsidiary Companies 2019 Annual Report



Liabilities and Stockholder's Equity	2019		2018
	(in millions)
Current Liabilities:
Securities due within one year	$	—	$	357
Notes payable	650		650
Energy marketing trade payables	442		856
Accounts payable —
Affiliated	41		45
Other	315		402
Customer deposits	96		133
Accrued taxes —
Accrued income taxes	—		66
Other accrued taxes	71		75
Accrued interest	52		55
Accrued compensation	100		100
Liabilities from risk management activities, net of collateral	21		76
Other regulatory liabilities	94		79
Other current liabilities	128		130
Total current liabilities	2,010		3,024
Long-term Debt (See accompanying statements)	5,845		5,583
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,219		1,016
Deferred credits related to income taxes	874		940
Employee benefit obligations	265		357
Operating lease obligations	78		—
Other cost of removal obligations	1,606		1,585
Accrued environmental remediation	233		268
Other deferred credits and liabilities	51		105
Total deferred credits and other liabilities	4,326		4,271
Total Liabilities	12,181		12,878
Common Stockholder's Equity (See accompanying statements)	9,506		8,570
Total Liabilities and Stockholder's Equity	$	21,687	$	21,448
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these consolidated financial statements.

Table of ContentsIndex to Financial Statements

CONSOLIDATED STATEMENTS OF CAPITALIZATION

At December 31, 2019 and 2018

Southern Company Gas and Subsidiary Companies 2019 Annual Report



	Weighted Average Interest Rate at December 31, 2019	2019			2018			2019		2018
		(in millions)						(percent of total)
Long-Term Debt:
Long-term notes payable —
Maturity
2019	—	$	—		$	300
2021	4.01%	330			330
2022	8.63%	46			46
2023	2.45%	350			350
2025-2047	4.68%	3,134			3,134
Total long-term notes payable		3,860			4,160
Other long-term debt —
First mortgage bonds —
Maturity
2019	—	—			50
2023	5.80%	50			50
2026-2059	3.94%	1,525			1,225
Total other long-term debt		1,575			1,325
Unamortized fair value adjustment of long-term debt		430			474
Unamortized debt discount		(20		)	(19		)
Total long-term debt		5,845			5,940
Less amount due within one year		—			357
Long-term debt excluding amount due within one year		5,845			5,583			38.1	%	39.4	%
Common Stockholder's Equity:
Common stock — par value $0.01 per share
Authorized — 100 million shares
Outstanding — 100 shares
Paid-in capital		9,697			8,856
Accumulated deficit		(198		)	(312		)
Accumulated other comprehensive income		7			26
Total common stockholder's equity		9,506			8,570			61.9		60.6
Total Capitalization		$	15,351		$	14,153		100.0	%	100.0	%

The accompanying notes are an integral part of these financial statements.

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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

Southern Company Gas and Subsidiary Companies 2019 Annual Report



	Number of Common Shares Issued	Common Stock		Paid-In Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2016	—	$	—	$	9,095		$	(12	)	$	26		$	9,109
Net income	—	—		—			243			—			243
Capital contributions from parent company	—	—		117			—			—			117
Other comprehensive income (loss)	—	—		—			—			(5		)	(5		)
Cash dividends on common stock	—	—		—			(443		)	—			(443		)
Other	—	—		2			—			(1		)	1
Balance at December 31, 2017	—	—		9,214			(212		)	20			9,022
Net income	—	—		—			372			—			372
Return of capital to parent company	—	—		(400		)	—			—			(400		)
Capital contributions from parent company	—	—		42			—			—			42
Other comprehensive income	—	—		—			—			2			2
Cash dividends on common stock	—	—		—			(468		)	—			(468		)
Other	—	—		—			(4		)	4			—
Balance at December 31, 2018	—	—		8,856			(312		)	26			8,570
Net income	—	—		—			585			—			585
Capital contributions from parent company	—	—		841			—			—			841
Other comprehensive income (loss)	—	—		—			—			(19		)	(19		)
Cash dividends on common stock	—	—		—			(471		)	—			(471		)
Balance at December 31, 2019	—	$	—	$	9,697		$	(198	)	$	7		$	9,506

The accompanying notes are an integral part of these consolidated financial statements.

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COMBINED NOTES TO FINANCIAL STATEMENTS

Southern Company and Subsidiary Companies 2019 Annual Report

Notes to the Financial Statements

for

The Southern Company and Subsidiary Companies

Alabama Power Company

Georgia Power Company

STATEMENTS OF OPERATIONS

For the Years Ended December 31, 2019, 2018, and 2017

Mississippi Power Company 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Revenues:
Retail revenues	$	877		$	889		$	854
Wholesale revenues, non-affiliates	237			263			259
Wholesale revenues, affiliates	132			91			56
Other revenues	18			22			18
Total operating revenues	1,264			1,265			1,187
Operating Expenses:
Fuel	407			405			395
Purchased power	20			41			25
Other operations and maintenance	283			313			291
Depreciation and amortization	192			169			161
Taxes other than income taxes	113			107			104
Estimated loss on Kemper IGCC	24			37			3,362
Total operating expenses	1,039			1,072			4,338
Operating Income (Loss)	225			193			(3,151		)
Other Income and (Expense):
Allowance for equity funds used during construction	1			—			72
Interest expense, net of amounts capitalized	(69		)	(76		)	(42		)
Other income (expense), net	12			17			1
Total other income and (expense)	(56		)	(59		)	31
Earnings (Loss) Before Income Taxes	169			134			(3,120		)
Income taxes (benefit)	30			(102		)	(532		)
Net Income (Loss)	139			236			(2,588		)
Dividends on Preferred Stock	—			1			2
Net Income (Loss) After Dividends on Preferred Stock	$	139		$	235		$	(2,590	)

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2019, 2018, and 2017

Mississippi Power Company 2019 Annual Report



	2019		2018			2017
	(in millions)
Net Income (Loss)	$	139	$	236		$	(2,588	)
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(1), and $(1), respectively	—		(1		)	(1		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, and $1, respectively	1		1			1
Total other comprehensive income (loss)	1		—			—
Comprehensive Income (Loss)	$	140	$	236		$	(2,588	)

The accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2019, 2018, and 2017

Mississippi Power Company 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Activities:
Net income (loss)	$	139		$	236		$	(2,588	)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	197			177			198
Deferred income taxes	37			475			(727		)
Allowance for equity funds used during construction	(1		)	—			(72		)
Pension and postretirement funding	(54		)	—			—
Settlement of asset retirement obligations	(35		)	(35		)	(23		)
Estimated loss on Kemper IGCC	15			33			3,179
Other, net	21			18			(8		)
Changes in certain current assets and liabilities —
-Receivables	6			(19		)	540
-Fossil fuel stock	(6		)	(3		)	24
-Prepaid income taxes	12			(12		)	—
-Other current assets	(2		)	(7		)	(13		)
-Accounts payable	3			15			(3		)
-Accrued interest	—			(1		)	(29		)
-Accrued taxes	11			(46		)	80
-Over recovered regulatory clause revenues	16			14			(51		)
-Other current liabilities	(20		)	(41		)	(4		)
Net cash provided from operating activities	339			804			503
Investing Activities:
Property additions	(202		)	(188		)	(429		)
Construction payables	(1		)	4			(47		)
Payments pursuant to LTSAs	(23		)	(29		)	(10		)
Other investing activities	(37		)	(19		)	(18		)
Net cash used for investing activities	(263		)	(232		)	(504		)
Financing Activities:
Decrease in notes payable, net	—			(4		)	(18		)
Proceeds —
Capital contributions from parent company	51			15			1,002
Senior notes	—			600			—
Long-term debt issuance to parent company	—			—			40
Short-term borrowings	—			300			109
Pollution control revenue bonds	43			—			—
Redemptions —
Preferred stock	—			(33		)	—
Pollution control revenue bonds	—			(43		)	—
Short-term borrowings	—			(300		)	(109		)
Long-term debt to parent company	—			—			(591		)
Capital leases	—			—			(71		)
Senior notes	(25		)	(155		)	(35		)
Other long-term debt	—			(900		)	(300		)
Return of capital to parent company	(150		)	—			—
Other financing activities	(2		)	(7		)	(2		)
Net cash provided from (used for) financing activities	(83		)	(527		)	25
Net Change in Cash, Cash Equivalents, and Restricted Cash	(7		)	45			24
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	293			248			224
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	286		$	293		$	248
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $(1), $-, and $29 capitalized, respectively)	$	71		$	80		$	65
Income taxes (net of refunds)	(27		)	(525		)	(424		)
Noncash transactions — Accrued property additions at year-end	35			35			32

The accompanying notes are an integral part of these financial statements.

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BALANCE SHEETS

At December 31, 2019 and 2018

Mississippi Power Company 2019 Annual Report



Assets	2019		2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	286	$	293
Receivables —
Customer accounts receivable	35		34
Unbilled revenues	39		41
Affiliated	27		21
Other accounts and notes receivable	26		31
Fossil fuel stock	26		20
Materials and supplies	61		53
Other regulatory assets	99		116
Prepaid income taxes	—		12
Other current assets	10		7
Total current assets	609		628
Property, Plant, and Equipment:
In service	4,857		4,900
Less: Accumulated provision for depreciation	1,463		1,429
Plant in service, net of depreciation	3,394		3,471
Construction work in progress	126		103
Total property, plant, and equipment	3,520		3,574
Other Property and Investments	131		24
Deferred Charges and Other Assets:
Deferred charges related to income taxes	32		33
Regulatory assets – asset retirement obligations	210		143
Other regulatory assets, deferred	360		331
Accumulated deferred income taxes	139		150
Other deferred charges and assets	34		3
Total deferred charges and other assets	775		660
Total Assets	$	5,035	$	4,886

The accompanying notes are an integral part of these financial statements.

Table of ContentsIndex to Financial Statements

BALANCE SHEETS

At December 31, 2019 and 2018

Mississippi Power Company 2019 Annual Report



Liabilities and Stockholder's Equity	2019		2018
	(in millions)
Current Liabilities:
Securities due within one year	$	281	$	40
Accounts payable —
Affiliated	76		60
Other	75		90
Accrued taxes	105		95
Accrued interest	15		15
Accrued compensation	35		38
Accrued plant closure costs	15		29
Asset retirement obligations	33		34
Other regulatory liabilities	21		12
Over recovered regulatory clause liabilities	29		14
Other current liabilities	49		28
Total current liabilities	734		455
Long-Term Debt (See accompanying statements)	1,308		1,539
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	424		378
Deferred credits related to income taxes	352		382
Employee benefit obligations	99		115
Asset retirement obligations, deferred	157		126
Other cost of removal obligations	189		185
Other regulatory liabilities, deferred	76		81
Other deferred credits and liabilities	44		16
Total deferred credits and other liabilities	1,341		1,283
Total Liabilities	3,383		3,277
Common Stockholder's Equity (See accompanying statements)	1,652		1,609
Total Liabilities and Stockholder's Equity	$	5,035	$	4,886
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these financial statements.

Table of ContentsIndex to Financial Statements

STATEMENTS OF CAPITALIZATION

At December 31, 2019 and 2018

Mississippi Power Company 2019 Annual Report



	Weighted Average Interest Rate at December 31, 2019	2019			2018			2019		2018
		(in millions)						(percent of total)
Long-Term Debt:
Long-term notes payable —
Due 2028-2042	4.16%	$	950		$	950
Adjustable rate due 2020	2.59%	275			300
Total long-term notes payable		1,225			1,250
Other long-term debt —
Pollution control revenue bonds —
Due 2028	3.20%	43			—
Variable rate due 2020	1.80%	7			40
Variable rate due 2025-2028	1.80%	33			—
Plant Daniel revenue bonds due 2021	7.13%	270			270
Total other long-term debt		353			310
Unamortized debt premium (discount), net		19			27
Unamortized debt issuance expense		(8		)	(8		)
Total long-term debt		1,589			1,579
Less amount due within one year		281			40
Long-term debt excluding amount due within one year		1,308			1,539			44.2	%	48.9	%
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 1,130,000 shares
Outstanding — 1,121,000 shares		38			38
Paid-in capital		4,449			4,546
Accumulated deficit		(2,832		)	(2,971		)
Accumulated other comprehensive loss		(3		)	(4		)
Total common stockholder's equity		1,652			1,609			55.8		51.1
Total Capitalization		$	2,960		$	3,148		100.0	%	100.0	%

The accompanying notes are an integral part of these financial statements.

Table of ContentsIndex to Financial Statements

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

For the Years Ended December 31, 2019, 2018, and 2017

Mississippi Power Company 2019 Annual Report



	Number of Common Shares Issued	Common Stock		Paid-In Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2016	1	$	38	$	3,525		$	(616	)	$	(4	)	$	2,943
Net loss after dividends on preferred stock	—	—		—			(2,590		)	—			(2,590		)
Capital contributions from parent company	—	—		1,004			—			—			1,004
Other	—	—		—			1			—			1
Balance at December 31, 2017	1	38		4,529			(3,205		)	(4		)	1,358
Net income after dividends on preferred stock	—	—		—			235			—			235
Capital contributions from parent company	—	—		17			—			—			17
Other	—	—		—			(1		)	—			(1		)
Balance at December 31, 2018	1	38		4,546			(2,971		)	(4		)	1,609
Net income after dividends on preferred stock	—	—		—			139			—			139
Return of capital to parent company	—	—		(150		)	—			—			(150		)
Capital contributions from parent company	—	—		53			—			—			53
Other comprehensive income	—	—		—			—			1			1
Balance at December 31, 2019	1	$	38	$	4,449		$	(2,832	)	$	(3	)	$	1,652

The accompanying notes are an integral part of these financial statements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Southern Power Company and Subsidiary Companies

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets ~~and statements~~ of ~~capitalization of Mississippi~~Southern Power Company ~~(the Company)~~and subsidiary companies (Southern Power) (a ~~wholly owned~~wholly-owned subsidiary of The Southern Company) as of December 31, ~~2016~~2019 and ~~2015, and~~2018, the related consolidated statements of ~~operations,~~income, comprehensive income, ~~(loss), common stockholder's~~stockholders' equity, and cash flows for each of the three years in the period ended December 31, ~~2016.~~ 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Southern Power as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of ~~the Company's~~Southern Power's management. Our responsibility is to express an opinion on ~~these~~Southern Power's financial statements based on our audits.

We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Southern Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the ~~Public Company Accounting Oversight Board (United States).~~PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material ~~misstatement. The Company~~misstatement, whether due to error or fraud. Southern Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. ~~Our~~As part of our audits, ~~included consideration~~we are required to obtain an understanding of internal control over financial reporting ~~as a basis for designing audit procedures that are appropriate in the circumstances,~~ but not for the purpose of expressing an opinion on the effectiveness of ~~the Company's~~Southern Power's internal control over financial reporting. Accordingly, we express no such opinion. ~~An audit also includes~~

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence ~~supporting~~regarding the amounts and disclosures in the financial ~~statements, assessing~~statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial ~~statement presentation.~~statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 19, 2020

We have served as Southern Power's auditor since 2002.

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CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2019, 2018, and 2017

Southern Power Company and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	1,528		$	1,757		$	1,671
Wholesale revenues, affiliates	398			435			392
Other revenues	12			13			12
Total operating revenues	1,938			2,205			2,075
Operating Expenses:
Fuel	577			699			621
Purchased power	108			176			149
Other operations and maintenance	359			395			386
Depreciation and amortization	479			493			503
Taxes other than income taxes	40			46			48
Asset impairment	3			156			—
Gain on dispositions, net	(23		)	(2		)	—
Total operating expenses	1,543			1,963			1,707
Operating Income	395			242			368
Other Income and (Expense):
Interest expense, net of amounts capitalized	(169		)	(183		)	(191		)
Other income (expense), net	47			23			1
Total other income and (expense)	(122		)	(160		)	(190		)
Earnings Before Income Taxes	273			82			178
Income taxes (benefit)	(56		)	(164		)	(939		)
Net Income	329			246			1,117
Net income (loss) attributable to noncontrolling interests	(10		)	59			46
Net Income Attributable to Southern Power	$	339		$	187		$	1,071

The accompanying notes are an integral part of these consolidated financial statements.

Table of ContentsIndex to Financial Statements

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2019, 2018, and 2017

Southern Power Company and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Net Income	$	329		$	246		$	1,117
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(22), $(17), and $39, respectively	(66		)	(51		)	63
Reclassification adjustment for amounts included in net income, net of tax of $14, $19, and $(46), respectively	41			58			(73		)
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax of $(6), $2, and $-, respectively	(17		)	5			—
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, and $-, respectively	—			2			—
Total other comprehensive income (loss)	(42		)	14			(10		)
Comprehensive income (loss) attributable to noncontrolling interests	(10		)	59			46
Comprehensive Income Attributable to Southern Power	$	297		$	201		$	1,061

The accompanying notes are an integral part of these consolidated financial statements.

Table of ContentsIndex to Financial Statements

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2019, 2018, and 2017

Southern Power Company and Subsidiary Companies 2019 Annual Report



	2019			2018			2017
	(in millions)
Operating Activities:
Net income	$	329		$	246		$	1,117
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	505			524			536
Deferred income taxes	(74		)	(244		)	(263		)
Utilization of federal investment tax credits	734			5			—
Amortization of investment tax credits	(151		)	(58		)	(57		)
Accrued income taxes, non-current	—			(14		)	14
Income taxes receivable, non-current	25			42			(61		)
Pension and postretirement funding	(24		)	—			—
Asset impairment	3			156			—
Other, net	(33		)	7			(13		)
Changes in certain current assets and liabilities —
-Receivables	72			(20		)	(60		)
-Prepaid income taxes	39			25			24
-Other current assets	(8		)	(26		)	(28		)
-Accrued taxes	6			7			(55		)
-Other current liabilities	(38		)	(19		)	1
Net cash provided from operating activities	1,385			631			1,155
Investing Activities:
Business acquisitions. net of cash acquired	(50		)	(65		)	(1,016		)
Property additions	(489		)	(315		)	(268		)
Change in construction payables	7			(6		)	(153		)
Investment in unconsolidated subsidiaries	(116		)	—			—
Proceeds from dispositions and asset sales	572			203			—
Payments pursuant to LTSAs and for equipment not yet received	(104		)	(75		)	(203		)
Other investing activities	13			31			15
Net cash used for investing activities	(167		)	(227		)	(1,625		)
Financing Activities:
Increase (decrease) in notes payable, net	449			(105		)	(104		)
Proceeds —
Short-term borrowings	100			200			—
Capital contributions from parent company	64			2			—
Senior notes	—			—			525
Other long-term debt	—			—			43
Redemptions —
Senior notes	(600		)	(350		)	(500		)
Other long-term debt	—			(420		)	(18		)
Short-term borrowings	(100		)	(100		)	—
Return of capital to parent company	(755		)	(1,650		)	—
Distributions to noncontrolling interests	(256		)	(153		)	(119		)
Capital contributions from noncontrolling interests	196			2,551			80
Purchase of membership interests from noncontrolling interests	—			—			(59		)
Payment of common stock dividends	(206		)	(312		)	(317		)
Other financing activities	(12		)	(26		)	(33		)
Net cash used for financing activities	(1,120		)	(363		)	(502		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	98			41			(972		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	181			140			1,112
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	279		$	181		$	140
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $15, $17, and $11 capitalized, respectively)	$	167		$	173		$	189
Income taxes (net of refunds and investment tax credits)	(664		)	79			(487		)
Noncash transactions — Accrued property additions at year-end	57			31			32

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and 2018

Southern Power Company and Subsidiary Companies 2019 Annual Report



Assets	2019		2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	279	$	181
Receivables —
Customer accounts receivable	107		111
Affiliated	30		55
Other	73		116
Materials and supplies	191		220
Prepaid income taxes	36		25
Other current assets	43		37
Total current assets	759		745
Property, Plant, and Equipment:
In service	13,270		13,271
Less: Accumulated provision for depreciation	2,464		2,171
Plant in service, net of depreciation	10,806		11,100
Construction work in progress	515		430
Total property, plant, and equipment	11,321		11,530
Other Property and Investments:
Intangible assets, net of amortization of $69 and $61 at December 31, 2019 and December 31, 2018, respectively	322		345
Equity investments in unconsolidated subsidiaries	28		—
Total other property and investments	350		345
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	369		—
Prepaid LTSAs	128		98
Accumulated deferred income taxes	551		1,186
Income taxes receivable, non-current	5		30
Assets held for sale	601		576
Other deferred charges and assets	216		373
Total deferred charges and other assets	1,870		2,263
Total Assets	$	14,300	$	14,883

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and 2018

Southern Power Company and Subsidiary Companies 2019 Annual Report



Liabilities and Stockholders' Equity	2019			2018
	(in millions)
Current Liabilities:
Securities due within one year	$	824		$	599
Notes payable	549			100
Accounts payable —
Affiliated	56			92
Other	85			77
Accrued taxes	26			6
Accrued interest	32			36
Other current liabilities	132			121
Total current liabilities	1,704			1,031
Long-Term Debt:
Senior notes —
2.375% due 2020	—			300
2.50% due 2021	300			300
1.00% due 2022	674			687
2.75% due 2023	290			290
Weighted average interest rate 4.12% at 12/31/19 due 2025-2046	2,337			2,348
Other long-term debt —
Variable rate (3.34% at 12/31/18) due 2020	—			525
Unamortized debt premium (discount), net	(8		)	(9		)
Unamortized debt issuance expense	(19		)	(23		)
Total long-term debt	3,574			4,418
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	115			105
Accumulated deferred ITCs	1,731			1,832
Operating lease obligations	376			—
Other deferred credits and liabilities	178			213
Total deferred credits and other liabilities	2,400			2,150
Total Liabilities	7,678			7,599
Common Stockholder's Equity:
Common stock, par value $0.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares	—			—
Paid-in capital	909			1,600
Retained earnings	1,485			1,352
Accumulated other comprehensive income (loss)	(26		)	16
Total common stockholder's equity	2,368			2,968
Noncontrolling Interests	4,254			4,316
Total Stockholders' Equity	6,622			7,284
Total Liabilities and Stockholders' Equity	$	14,300		$	14,883
Commitments and Contingent Matters (See notes)

The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

For the Years Ended December 31, 2019, 2018, and 2017

Southern Power Company and Subsidiary Companies 2019 Annual Report



	Number of Common Shares Issued	Common Stock		Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income			Total Common Stockholder's Equity			Noncontrolling Interests^(a)			Total
	(in millions)
Balance at December 31, 2016	—	$	—	$	3,671		$	724		$	35		$	4,430		$	1,245		$	5,675
Net income attributable to Southern Power	—	—		—			1,071			—			1,071			—			1,071
Capital contributions to parent company, net	—	—		(2		)	—			—			(2		)	—			(2		)
Other comprehensive income (loss)	—	—		—			—			(10		)	(10		)	—			(10		)
Cash dividends on common stock	—	—		—			(317		)	—			(317		)	—			(317		)
Other comprehensive income transfer from SCS^(b)	—	—		—			—			(27		)	(27		)	—			(27		)
Capital contributions from noncontrolling interests	—	—		—			—			—			—			79			79
Distributions to noncontrolling interests	—	—		—			—			—			—			(122		)	(122		)
Net income attributable to noncontrolling interests	—	—		—			—			—			—			44			44
Reclassification from redeemable noncontrolling interests	—	—		—			—			—			—			114			114
Other	—	—		(7		)	—			—			(7		)	—			(7		)
Balance at December 31, 2017	—	—		3,662			1,478			(2		)	5,138			1,360			6,498
Net income attributable to Southern Power	—	—		—			187			—			187			—			187
Return of capital to parent company	—	—		(1,650		)	—			—			(1,650		)	—			(1,650		)
Capital contributions from parent company	—	—		2			—			—			2			—			2
Other comprehensive income	—	—		—			—			14			14			—			14
Cash dividends on common stock	—	—		—			(312		)	—			(312		)	—			(312		)
Capital contributions from noncontrolling interests	—	—		—			—			—			—			1,372			1,372
Distributions to noncontrolling interests	—	—		—			—			—			—			(164		)	(164		)
Net income attributable to noncontrolling interests	—	—		—			—			—			—			59			59
Sale of noncontrolling interests^(c)	—	—		(417		)	—			—			(417		)	1,690			1,273
Other	—	—		3			(1		)	4			6			(1		)	5
Balance at December 31, 2018	—	—		1,600			1,352			16			2,968			4,316			7,284
Net income attributable to Southern Power	—	—		—			339			—			339			—			339
Return of capital to parent company	—	—		(755		)	—			—			(755		)	—			(755		)
Capital contributions from parent company	—	—		64			—			—			64			—			64
Other comprehensive income (loss)	—	—		—			—			(42		)	(42		)	—			(42		)
Cash dividends on common stock	—	—		—			(206		)	—			(206		)	—			(206		)
Capital contributions from noncontrolling interests	—	—		—			—			—			—			276			276
Distributions to noncontrolling interests	—	—		—			—			—			—			(327		)	(327		)
Net income (loss) attributable to noncontrolling interests	—	—		—			—			—			—			(10		)	(10		)
Other	—	—		—			—			—			—			(1		)	(1		)
Balance at December 31, 2019	—	$	—	$	909		$	1,485		$	(26	)	$	2,368		$	4,254		$	6,622


(a)	Excludes redeemable noncontrolling interests. See Note 7 to the financial statements under "Noncontrolling Interests" for additional information.


(b)	In connection with Southern Power becoming a participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of other comprehensive income, net of tax of $9 million, was transferred from SCS.


(c)	See Note 15 under "Southern Power - Sales of Renewable Facility Interests" for additional information.

The accompanying notes are an integral part of these consolidated financial statements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Southern Company Gas and Subsidiary Companies

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southern Company Gas and subsidiary companies (Southern Company Gas) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, ~~such~~the financial statements ~~(pages II-427 to II-475)~~ present fairly, in all material respects, the financial position of ~~Mississippi Power~~Southern Company Gas as of December 31, ~~2016~~2019 and ~~2015,~~2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2016,~~2019, in conformity with accounting principles generally accepted in the United States of America.

~~As discussed in Note 3 to~~We did not audit the financial statements of Southern Natural Gas Company, L.L.C. (SNG), Southern Company Gas' investment which is accounted for by the ~~Mississippi Public Service Commission rate recovery process associated~~use of the equity method. The accompanying consolidated financial statements of Southern Company Gas include its equity investment in SNG of $1,137 million and $1,261 million as of December 31, 2019 and December 31, 2018, respectively, and its earnings from its equity method investment in SNG of $141 million, $131 million, and $88 million for the years ended December 31, 2019, 2018, and 2017, respectively. Those statements were audited by other auditors whose reports (which express unqualified opinions on SNG's financial statements and contain an emphasis of matter paragraph calling attention to SNG's significant transactions with related parties) have been furnished to us, and our opinion, insofar as it relates to the amounts included for SNG, is based solely on the reports of the other auditors.

Basis for Opinion

These financial statements are the responsibility of Southern Company Gas' management. Our responsibility is to express an opinion on Southern Company Gas' financial statements based on our audits. We are a public accounting firm registered with the ~~Kemper Integrated Coal Gasification Combined Cycle Project may~~Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Southern Company Gas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Southern Company Gas is not required to have, ~~a material impact~~nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the ~~Company's~~effectiveness of Southern Company Gas' internal control over financial reporting. Accordingly, we express no such opinion.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February ~~21, 2017~~19, 2020

We have served as Southern Company Gas' auditor since 2016.

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~~DEFINITIONS~~CONSOLIDATED STATEMENTS OF INCOME

Southern Company Gas and Subsidiary Companies 2019 Annual Report



~~Term~~	~~Meaning~~
~~2012 MPSC CPCN Order~~	A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing acquisition, construction, and operation of the Kemper IGCC
~~AFUDC~~	~~Allowance for funds used during construction~~
~~Alabama Power~~	~~Alabama Power Company~~
~~ARO~~	~~Asset retirement obligation~~
~~ASC~~	~~Accounting Standards Codification~~
~~ASU~~	~~Accounting Standards Update~~
~~Baseload Act~~	~~State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi~~
~~CCR~~	~~Coal combustion residuals~~
~~Clean Air Act~~	~~Clean Air Act Amendments of 1990~~
CO₂	~~Carbon dioxide~~
~~CPCN~~	~~Certificate of public convenience and necessity~~
~~CWIP~~	~~Construction work in progress~~
~~DOE~~	~~U.S. Department of Energy~~
~~ECM~~	~~Energy cost management clause~~
~~ECO~~	~~Environmental compliance overview~~
~~EPA~~	~~U.S. Environmental Protection Agency~~
~~FASB~~	~~Financial Accounting Standards Board~~
~~FERC~~	~~Federal Energy Regulatory Commission~~
~~GAAP~~	~~U.S. generally accepted accounting principles~~
~~Georgia Power~~	~~Georgia Power Company~~
~~Gulf Power~~	~~Gulf Power Company~~
~~IGCC~~	~~Integrated coal gasification combined cycle~~
~~IRS~~	~~Internal Revenue Service~~
~~ITC~~	~~Investment tax credit~~
~~Kemper IGCC~~	~~IGCC facility under construction in Kemper County, Mississippi~~
~~KWH~~	~~Kilowatt-hour~~
~~LIBOR~~	~~London Interbank Offered Rate~~
~~Mirror CWIP~~	~~A regulatory liability used by Mississippi Power to record customer refunds resulting from a 2015 Mississippi PSC order~~
~~mmBtu~~	~~Million British thermal units~~
~~Moody's~~	~~Moody's Investors Service, Inc.~~
~~MPUS~~	~~Mississippi Public Utilities Staff~~
~~MRA~~	~~Municipal and Rural Associations~~
MW	~~Megawatt~~
~~OCI~~	~~Other comprehensive income~~
~~PEP~~	~~Performance evaluation plan~~
~~Plant Daniel Units 3 and 4~~	~~Combined cycle Units 3 and 4 at Plant Daniel~~
~~power pool~~	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
~~PPA~~	~~Power purchase agreement~~
~~PSC~~	~~Public Service Commission~~



	2019			2018			2017
	(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of $117, $114, and $100 for the periods presented, respectively)	$	3,793		$	3,874		$	3,787
Alternative revenue programs	(1		)	(20		)	4
Other revenues	—			55			129
Total operating revenues	3,792			3,909			3,920
Operating Expenses:
Cost of natural gas	1,319			1,539			1,601
Cost of other sales	—			12			29
Other operations and maintenance	888			981			945
Depreciation and amortization	487			500			501
Taxes other than income taxes	213			211			184
Impairment charges	115			42			—
(Gain) loss on dispositions, net	—			(291		)	—
Total operating expenses	3,022			2,994			3,260
Operating Income	770			915			660
Other Income and (Expense):
Earnings from equity method investments	157			148			106
Interest expense, net of amounts capitalized	(232		)	(228		)	(200		)
Other income (expense), net	20			1			44
Total other income and (expense)	(55		)	(79		)	(50		)
Earnings Before Income Taxes	715			836			610
Income taxes	130			464			367
Net Income	$	585		$	372		$	243

The accompanying notes are an integral part of these consolidated financial statements.

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~~DEFINITIONS~~CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

~~(continued)~~Southern Company Gas and Subsidiary Companies 2019 Annual Report



~~Term~~	~~Meaning~~
~~ROE~~	~~Return on equity~~
~~S&P~~	~~S&P Global Ratings, a division of S&P Global Inc.~~
~~scrubber~~	~~Flue gas desulfurization system~~
~~SCS~~	~~Southern Company Services, Inc. (the Southern Company system service company)~~
~~SEC~~	~~U.S. Securities and Exchange Commission~~
~~SMEPA~~	~~South Mississippi Electric Power Association (now known as Cooperative Energy)~~
~~Southern Company~~	~~The Southern Company~~
~~Southern Company Gas~~	~~Southern Company Gas (formerly known as AGL Resources Inc.) and its subsidiaries~~
~~Southern Company system~~	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), Southern Electric Generating Company, Southern Nuclear, SCS, Southern LINC, PowerSecure, Inc. (as of May 9, 2016), and other subsidiaries
~~Southern LINC~~	~~Southern Communications Services, Inc.~~
~~Southern Nuclear~~	~~Southern Nuclear Operating Company, Inc.~~
~~Southern Power~~	~~Southern Power Company and its subsidiaries~~
~~SRR~~	~~System Restoration Rider~~
~~traditional electric operating companies~~	~~Alabama Power, Georgia Power, Gulf Power, and Mississippi Power Company~~



	2019			2018			2017
	(in millions)
Net Income	$	585		$	372		$	243
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(2), $2, and $(3), respectively	(5		)	5			(5		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $(1), and $-, respectively	2			(1		)	1
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax of $(14), $-, and $-, respectively	(16		)	—			(1		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $3, and $-, respectively	—			(2		)	—
Total other comprehensive income (loss)	(19		)	2			(5		)
Comprehensive Income	$	566		$	374		$	238

The accompanying notes are an integral part of these consolidated financial statements.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS~~CONSOLIDATED STATEMENTS OF ~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~CASH FLOWS

~~Mississippi Power~~Southern Company ~~2016~~Gas and Subsidiary Companies 2019 Annual Report

~~OVERVIEW~~

~~Business Activities~~



	2019			2018			2017
	(in millions)
Operating Activities:
Net income	$	585		$	372		$	243
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	487			500			501
Deferred income taxes	213			(1		)	236
Pension and postretirement funding	(145		)	—			—
Impairment charges	115			42			—
(Gain) loss on dispositions, net	—			(291		)	—
Mark-to-market adjustments	(56		)	(19		)	(24		)
Other, net	(55		)	(24		)	(51		)
Changes in certain current assets and liabilities —
-Receivables	467			(218		)	(94		)
-Natural gas for sale	44			49			36
-Prepaid income taxes	40			(42		)	(39		)
-Other current assets	31			4			(24		)
-Accounts payable	(520		)	372			(20		)
-Accrued taxes	(69		)	10			110
-Accrued compensation	1			32			15
-Other current liabilities	(71		)	(22		)	(8		)
Net cash provided from operating activities	1,067			764			881
Investing Activities:
Property additions	(1,408		)	(1,388		)	(1,514		)
Cost of removal, net of salvage	(82		)	(96		)	(66		)
Change in construction payables, net	24			(37		)	72
Investments in unconsolidated subsidiaries	(31		)	(110		)	(145		)
Returned investment in unconsolidated subsidiaries	67			20			80
Proceeds from dispositions and asset sales	32			2,609			—
Other investing activities	12			—			5
Net cash provided from (used for) investing activities	(1,386		)	998			(1,568		)
Financing Activities:
Increase (decrease) in notes payable, net	—			(868		)	262
Proceeds —
First mortgage bonds	300			300			400
Capital contributions from parent company	821			24			103
Senior notes	—			—			450
Redemptions and repurchases —
Gas facility revenue bonds	—			(200		)	—
Medium-term notes	—			—			(22		)
First mortgage bonds	(50		)	—			—
Senior notes	(300		)	(155		)	—
Return of capital to parent company	—			(400		)	—
Payment of common stock dividends	(471		)	(468		)	(443		)
Other financing activities	(2		)	(3		)	(9		)
Net cash provided from (used for) financing activities	298			(1,770		)	741
Net Change in Cash, Cash Equivalents, and Restricted Cash	(21		)	(8		)	54
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	70			78			24
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	49		$	70		$	78
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $6, $7, and $11 capitalized, respectively)	$	251		$	249		$	223
Income taxes (net of refunds)	(41		)	524			72
Noncash transactions — Accrued property additions at year-end	122			97			135

~~Mississippi Power Company (the Company) operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State~~The accompanying notes are an integral part of ~~Mississippi and to wholesale customers in the Southeast.~~these consolidated financial statements.

Many factors affect the opportunities, challenges, and risks of the Company's business of providing electric service. These factors include the Company's ability to maintain and grow energy sales and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to the completion and operation of the Kemper IGCC, projected long-term demand growth, reliability, fuel, and stringent environmental standards, as well as ongoing capital expenditures required for maintenance and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future.

The Company continues to progress toward completing the construction and start-up of the Kemper IGCC, which was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when the Company demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). The current cost estimate for the Kemper IGCC in total is approximately $6.99 billion, which includes approximately $5.64 billion of costs subject to the construction cost cap and is net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts to customers. The Company does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Company recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $348 million ($215 million after tax), $365 million ($226 million after tax), and $868 million ($536 million after tax) in 2016, 2015, and 2014, respectively. Since 2012, in the aggregate, the Company has incurred charges of $2.76 billion ($1.71 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through December 31, 2016. The current cost estimate includes costs through March 15, 2017.

In addition to the current construction cost estimate, the Company is identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. As of December 31, 2016, approximately $12 million of related potential costs has been included in the estimated loss on the Kemper IGCC. Other projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap. Any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in the Company's statements of income and these changes could be material.

The expected completion date of the Kemper IGCC at the time of the Mississippi PSC's approval in 2010 was May 2014. The combined cycle and the associated common facilities portion of the Kemper IGCC were placed in service in August 2014. The remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." The Company achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. The Company subsequently completed a brief outage to repair and make modifications to further improve the plant's ability to achieve sustained operations sufficient to support placing the plant in service for customers. Efforts to reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines are in process. The plant has produced and captured CO₂, and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. On February 20, 2017, the Company determined gasifier "B," which has been producing syngas over 60% of the time since early November 2016, requires an outage to remove ash deposits from its ash removal system. Gasifier "A" and combustion turbine "A" are expected to remain in operation, producing electricity from syngas, as well as producing chemical by-products. As a result, the Company currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by mid-March 2017.

Upon placing the remainder of the plant in service, the Company will be primarily focused on completing the regulatory cost recovery process. In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power~~CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and 2018

Southern Company ~~2016~~Gas and Subsidiary Companies 2019 Annual Report

~~(2015 Stipulation) between the Company and the MPUS, authorizing rates that provide for the recovery of approximately $126 million annually related to Kemper IGCC assets previously placed in service.~~



Assets	2019			2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	46		$	64
Receivables —
Energy marketing receivable	428			801
Customer accounts receivable	323			370
Unbilled revenues	183			213
Affiliated	5			11
Other accounts and notes receivable	114			142
Accumulated provision for uncollectible accounts	(18		)	(30		)
Natural gas for sale	479			524
Prepaid expenses	65			118
Assets from risk management activities, net of collateral	177			219
Other regulatory assets	92			73
Assets held for sale	171			—
Other current assets	41			50
Total current assets	2,106			2,555
Property, Plant, and Equipment:
In service	16,344			15,177
Less: Accumulated depreciation	4,650			4,400
Plant in service, net of depreciation	11,694			10,777
Construction work in progress	613			580
Total property, plant, and equipment	12,307			11,357
Other Property and Investments:
Goodwill	5,015			5,015
Equity investments in unconsolidated subsidiaries	1,251			1,538
Other intangible assets, net of amortization of $176 and $145 at December 31, 2019 and December 31, 2018, respectively	70			101
Miscellaneous property and investments	20			20
Total other property and investments	6,356			6,674
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	93			—
Other regulatory assets, deferred	618			669
Other deferred charges and assets	207			193
Total deferred charges and other assets	918			862
Total Assets	$	21,687		$	21,448

On August 17, 2016, the Mississippi PSC established a discovery docket to manage all filings related to Kemper IGCC prudence issues. On October 3, 2016 and November 17, 2016, the Company made filings in this docket including a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC is placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increasedThe accompanying notes are an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate.

~~In the fourth quarter 2016, as a~~integral part of the Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings, on February 21, 2017, the Company filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.

After the remainder of the plant is placed in service, AFUDC equity of approximately $11 million per month will no longer be recorded in income, and the Company expects to incur approximately $25 million per month in depreciation, taxes, operations and maintenance expenses, interest expense, and regulatory costs in excess of current rates. The Company expects to file a request for authority from the Mississippi PSC and the FERC to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. In the event that the Mississippi PSC does not grant the Company's request for an accounting order, these monthly expenses will be charged to income as incurred and will not be recoverable through rates. The ultimate outcome of this matter cannot now be determined but could have a material impact on the Company's result of operations,consolidated financial ~~condition, and liquidity.~~

The Company is required to file a rate case to address Kemper IGCC cost recovery by June 3, 2017 (2017 Rate Case). Costs incurred through December 31, 2016 totaled $6.73 billion, net of the Initial and Additional DOE Grants. Of this total, $2.76 billion of costs has been recognized through income as a result of the $2.88 billion cost cap, $0.83 billion is included in retail and wholesale rates for the assets in service, and the remainder will be the subject of the 2017 Rate Case to be filed with the Mississippi PSC and expected subsequent wholesale MRA rate filing with the FERC. The Company continues to believe that all costs related to the Kemper IGCC have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. The Company also recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein, these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs, net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.

Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, the Company is developing both a traditional rate case requesting full cost recovery of the $3.31 billion (net of $137 million in Additional DOE Grants) not currently in rates and a rate mitigation plan that together represent the Company's probable filing strategy. The Company also expects that timely resolution of the 2017 Rate Case will likely require a negotiated settlement agreement. In the event an agreement acceptable to both the Company and the MPUS (and other parties) can be negotiated and ultimately approved by the Mississippi PSC, it is reasonably possible that full regulatory recovery of all Kemper IGCC costs will not occur. The impact of such an agreement on the Company's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to thestatements.

Table of ContentsIndex to Financial Statements

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power~~CONSOLIDATED BALANCE SHEETS

At December 31, 2019 and 2018

Southern Company ~~2016~~Gas and Subsidiary Companies 2019 Annual Report

~~parties cannot be reached, the Company intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges.~~



Liabilities and Stockholder's Equity	2019		2018
	(in millions)
Current Liabilities:
Securities due within one year	$	—	$	357
Notes payable	650		650
Energy marketing trade payables	442		856
Accounts payable —
Affiliated	41		45
Other	315		402
Customer deposits	96		133
Accrued taxes —
Accrued income taxes	—		66
Other accrued taxes	71		75
Accrued interest	52		55
Accrued compensation	100		100
Liabilities from risk management activities, net of collateral	21		76
Other regulatory liabilities	94		79
Other current liabilities	128		130
Total current liabilities	2,010		3,024
Long-term Debt (See accompanying statements)	5,845		5,583
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,219		1,016
Deferred credits related to income taxes	874		940
Employee benefit obligations	265		357
Operating lease obligations	78		—
Other cost of removal obligations	1,606		1,585
Accrued environmental remediation	233		268
Other deferred credits and liabilities	51		105
Total deferred credits and other liabilities	4,326		4,271
Total Liabilities	12,181		12,878
Common Stockholder's Equity (See accompanying statements)	9,506		8,570
Total Liabilities and Stockholder's Equity	$	21,687	$	21,448
Commitments and Contingent Matters (See notes)

The ~~Company has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and has recognized~~accompanying notes are an additional $80 million charge to income, which is the estimated minimum probable amount of the $3.31 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcomeintegral part of these ~~matters cannot now be determined but could result in further charges that could have a material impact on the Company's results~~consolidated financial statements.

Table of ~~operations,~~ContentsIndex to Financial Statements

CONSOLIDATED STATEMENTS OF CAPITALIZATION

At December 31, 2019 and 2018

Southern Company Gas and Subsidiary Companies 2019 Annual Report



	Weighted Average Interest Rate at December 31, 2019	2019			2018			2019		2018
		(in millions)						(percent of total)
Long-Term Debt:
Long-term notes payable —
Maturity
2019	—	$	—		$	300
2021	4.01%	330			330
2022	8.63%	46			46
2023	2.45%	350			350
2025-2047	4.68%	3,134			3,134
Total long-term notes payable		3,860			4,160
Other long-term debt —
First mortgage bonds —
Maturity
2019	—	—			50
2023	5.80%	50			50
2026-2059	3.94%	1,525			1,225
Total other long-term debt		1,575			1,325
Unamortized fair value adjustment of long-term debt		430			474
Unamortized debt discount		(20		)	(19		)
Total long-term debt		5,845			5,940
Less amount due within one year		—			357
Long-term debt excluding amount due within one year		5,845			5,583			38.1	%	39.4	%
Common Stockholder's Equity:
Common stock — par value $0.01 per share
Authorized — 100 million shares
Outstanding — 100 shares
Paid-in capital		9,697			8,856
Accumulated deficit		(198		)	(312		)
Accumulated other comprehensive income		7			26
Total common stockholder's equity		9,506			8,570			61.9		60.6
Total Capitalization		$	15,351		$	14,153		100.0	%	100.0	%

The accompanying notes are an integral part of these financial ~~condition,~~statements.

Table of ContentsIndex to Financial Statements

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

Southern Company Gas and ~~liquidity.~~Subsidiary Companies 2019 Annual Report



	Number of Common Shares Issued	Common Stock		Paid-In Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2016	—	$	—	$	9,095		$	(12	)	$	26		$	9,109
Net income	—	—		—			243			—			243
Capital contributions from parent company	—	—		117			—			—			117
Other comprehensive income (loss)	—	—		—			—			(5		)	(5		)
Cash dividends on common stock	—	—		—			(443		)	—			(443		)
Other	—	—		2			—			(1		)	1
Balance at December 31, 2017	—	—		9,214			(212		)	20			9,022
Net income	—	—		—			372			—			372
Return of capital to parent company	—	—		(400		)	—			—			(400		)
Capital contributions from parent company	—	—		42			—			—			42
Other comprehensive income	—	—		—			—			2			2
Cash dividends on common stock	—	—		—			(468		)	—			(468		)
Other	—	—		—			(4		)	4			—
Balance at December 31, 2018	—	—		8,856			(312		)	26			8,570
Net income	—	—		—			585			—			585
Capital contributions from parent company	—	—		841			—			—			841
Other comprehensive income (loss)	—	—		—			—			(19		)	(19		)
Cash dividends on common stock	—	—		—			(471		)	—			(471		)
Balance at December 31, 2019	—	$	—	$	9,697		$	(198	)	$	7		$	9,506

The accompanying notes are an integral part of these consolidated financial statements.

Table of ContentsIndex to Financial Statements

COMBINED NOTES TO FINANCIAL STATEMENTS

Southern Company and Subsidiary Companies 2019 Annual Report

Notes to the Company are defendants in various lawsuits that allege improper disclosure about the Kemper IGCC. While the Company believes that these lawsuits are without merit, an adverse outcome could have a material impact on the Company's results of operations, financial condition, and liquidity. In addition, the SEC is conducting a formal investigation ofFinancial Statements

for

The Southern Company and the Company concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and the Company believe the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" herein for additional information.Subsidiary Companies

As of December 31, 2016, the Company's current liabilities exceeded current assets by approximately $371 million primarily due to $551 million in promissory notes to Southern Company which mature in December 2017, $35 million in senior notes which mature in November 2017, and $63 million in short-term debt. The Company expects the funds needed to satisfy the promissory notes to Southern Company will exceed amounts available from operating cash flows, lines of credit, and other external sources. Accordingly, the Company intends to satisfy these obligations through loans and/or equity contributions from Southern Company. Specifically, the Company has been informed by Southern Company that, in the event sufficient funds are not available from external sources, Southern Company intends to (i) extend the maturity of the $551 million in promissory notes and (ii) provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, the Company's financial statement presentation contemplates continuation of the Company as a going concern as a result of Southern Company's anticipated ongoing financial support of the Company, consistent with the requirements of ASU 2014-15 (as defined herein). See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" herein and Notes 1 and 6 to the financial statements for additional information.

~~The Company continues to focus on several key performance indicators, including the construction, start-up, and rate recovery of the Kemper IGCC.~~

In recognition that the Company's long-term financial success is dependent upon how well it satisfies its customers' needs, the Company's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to the Company's allowed return. PEP measures the Company's performance on a 10-point scale as a weighted average of results in three areas: average customer price, as compared to prices of other regional utilities (weighted at 40%); service reliability, measured in percentage of time customers had electric service (40%); and customer satisfaction, measured in a survey of residential customers (20%). See Note 3 to the financial statements under "Retail Regulatory Matters – Performance Evaluation Plan" for more information on PEP.

In addition to the PEP performance indicators, the Company focuses on other performance measures, including broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.

The Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate the Company's results and generally targets the top quartile in measuring performance.

~~See RESULTS OF OPERATIONS herein for information on the Company's financial performance.~~

~~Earnings~~

~~The Company's net loss after dividends on preferred stock was $50 million in 2016 compared to $8 million in 2015. The change in 2016 was~~ ~~primarily the result of higher pre-tax charges of~~ $428 million ($264 million after tax) in 2016 compared to pre-tax charges of $365 million ($226 million after tax) in 2015 for estimated losses on the Kemper IGCC. The decrease in net income was partially offset by an increase in retail revenues due to the implementation of rates in September 2015 for certain Kemper IGCC in-service assets, partially offset by a decrease in wholesale revenues. The increase in revenues was partially offset by an

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi~~Alabama Power Company ~~2016 Annual Report~~

increase in interest expense in 2016 compared to 2015 due to the termination of an asset purchase agreement between the Company and SMEPA in May 2015 and an increase in operations and maintenance expenses.

The Company's net loss after dividends on preferred stock was $8 million in 2015 compared to $329 million in 2014. The change in 2015 was primarily the result of lower pre-tax charges of $365 million ($226 million after tax) in 2015 compared to pre-tax charges of $868 million ($536 million after tax) in 2014 for revisions of estimated costs expected to be incurred on the Company's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The reduction in net loss was also related to an increase in retail base revenues, due to the implementation of rates for certain Kemper IGCC assets placed in service that became effective with the first billing cycle in September (on August 19), and a decrease in interest expense primarily due to the termination of an asset purchase agreement between the Company and SMEPA in May 2015, partially offset by increases in income taxes due to a reduced net loss.

~~See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information regarding the Kemper IGCC.~~

~~RESULTS OF OPERATIONS~~

~~A condensed statement of operations follows:~~

Amount
Increase (Decrease)
from Prior Year
2016 2016 2015
(in millions)
Operating revenues $ 1,163
$ 25
$ (105 )
Fuel 343
(100 ) (131 )
Purchased power 34
22
(31 )
Other operations and maintenance 312
38
3
Depreciation and amortization 132
9
26
Taxes other than income taxes 109
15
15
Estimated loss on Kemper IGCC 428
63
(503 )
Total operating expenses 1,358
47
(621 )
Operating income (195 ) (22 ) 516
Allowance for equity funds used during construction 124
14
(26 )
Interest expense, net of amounts capitalized 74
67
(38 )
Other income (expense), net (7 ) 1
6
Income taxes (benefit) (104 ) (32 ) 213
Net income (loss) (48 ) (42 ) 321
Dividends on preferred stock 2
—
—
Net loss after dividends on preferred stock $ (50 ) $ (42 ) $ 321

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi~~Georgia Power Company ~~2016 Annual Report~~

~~Operating Revenues~~

~~Operating revenues for 2016 were $1.2 billion, reflecting a $25 million increase from 2015. Details of operating revenues were as follows:~~

Amount
2016 2015
(in millions)
Retail — prior year $ 776
$ 795
Estimated change resulting from —
Rates and pricing 96
61
Sales decline (4 ) (3 )
Weather 8
(1 )
Fuel and other cost recovery (17 ) (76 )
Retail — current year 859
776
Wholesale revenues —
Non-affiliates 261
270
Affiliates 26
76
Total wholesale revenues 287
346
Other operating revenues 17
16
Total operating revenues $ 1,163
$ 1,138
Percent change 2.2 % (8.4 )%

Total retail revenues for 2016 increased $83 million, or 10.7%, compared to 2015 primarily due to changes in rates and pricing of $96 million partially offset by a net decrease in fuel and other cost recovery of $17 million. Total retail revenues for 2015 decreased $19 million, or 2.4%, compared to 2014 primarily due to a lower fuel cost recovery. This decrease was partially offset by changes in rates and pricing of $61 million.

Revenues associated with changes in rates and pricing increased $96 million in 2016 and $61 million in 2015, primarily due to the implementation of rates for certain Kemper IGCC in-service assets effective in September 2015 and an annual ECO rate increase of $22 million collected from September through December 2016.

See Note 3 to the financial statements under "Retail Regulatory Matters – Environmental Compliance Overview" and "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" for additional information. See "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales and weather.

Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel and emissions portion of wholesale revenues from energy sold to customers outside the Company's service territory. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.

~~Wholesale revenues from power sales to non-affiliated utilities, including FERC-regulated MRA sales as well as market-based sales, were as follows:~~

2016 2015 2014
(in millions)
Capacity and other $ 157
$ 158
$ 160
Energy 104
112
163
Total non-affiliated $ 261
$ 270
$ 323

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of the Company's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, the Company provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 19.8% of the Company's total operating revenues in 2016 and are largely subject to rolling 10-year cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.

Wholesale revenues from sales to non-affiliates decreased $9 million, or 3.3%, in 2016 compared to 2015 primarily as a result of an $8 million decrease in energy revenues, of which $10 million was associated with lower fuel prices, offset by an increase in KWH sales of $2 million. Wholesale revenues from sales to non-affiliates decreased $53 million, or 16.4%, in 2015 compared to 2014 primarily as a result of a $51 million decrease in energy revenues, of which $13 million was associated with a decrease in KWH sales and $38 million was associated with lower fuel prices.

Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above the Company's variable cost to produce the energy.

Wholesale revenues from sales to affiliates will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.

Wholesale revenues from sales to affiliates decreased $50 million, or 65.8%, in 2016 compared to 2015 primarily due to a $50 million decrease in energy revenues of which $4 million was associated with lower fuel prices and $46 million was associated with a decrease in KWH sales as a result of lower cost generation available in the Southern Company system. Wholesale revenues from sales to affiliates decreased $31 million, or 29.0%, in 2015 compared to 2014 primarily due to a $31 million decrease in energy revenues of which $28 million was associated with lower fuel prices and $3 million was associated with a decrease in KWH sales.

~~Energy Sales~~

~~Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2016 and the percent change from the prior year were as follows:~~

Total
KWHs

Total KWH
Percent Change
Weather-Adjusted Percent Change
2016 2016 2015
2016^(*)

2015^(*)
(in millions)
Residential 2,051
1.3 % (4.8 )% (2.4 )% (0.4 )%
Commercial 2,842
1.3
(1.9 ) (2.2 ) (0.4 )
Industrial 4,906
(1.0 ) 0.3
(1.6 ) 0.8
Other 39
(1.3 ) (2.1 ) (1.3 ) (2.1 )
Total retail 9,838
0.1
(1.4 ) (1.9 )% 0.2 %
Wholesale
Non-affiliated 3,920
1.7
(8.1 )
Affiliated 1,108
(60.5 ) (3.2 )
Total wholesale 5,028
(24.5 ) (6.1 )
Total energy sales 14,866
(9.8 )% (3.4 )%

~~(*)~~

In the first quarter 2015, the Company updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a material impact on net income. The KWH sales variances in the above table reflect an adjustment to the estimated allocation of the Company's unbilled 2014 and first quarter 2015 KWH sales among customer classes that is consistent with the actual allocation in 2015 and 2016, respectively. Without this adjustment, 2016 weather-adjusted residential sales decreased 1.0%, commercial sales decreased 0.6%, and industrial KWH sales decreased 1.0% as compared to the corresponding period in 2015. Without this adjustment, 2015 weather-adjusted residential sales decreased 1.8%, commercial sales decreased 2.1%, and industrial KWH sales increased 0.3% as compared to the corresponding period in 2014.

Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales increased 0.1% in 2016 as compared to the prior year. This increase was primarily the result of warmer weather in the third quarter 2016 as compared to the corresponding period in 2015. Weather-adjusted residential and commercial KWH sales decreased primarily due to decreased customer usage partially offset by customer

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

~~growth. The decrease in industrial KWH energy sales was primarily due to planned and unplanned outages by large industrial customers.~~

Retail energy sales decreased 1.4% in 2015 as compared to the prior year. This decrease was primarily the result of milder weather in the first and fourth quarters of 2015 as compared to the corresponding periods in 2014. Weather-adjusted residential and commercial KWH sales decreased primarily due to decreased customer usage partially offset by customer growth. Household income, one of the primary drivers of residential customer usage, had modest growth in 2015. The increase in industrial KWH energy sales was primarily due to expanded operation by many industrial customers.

Wholesale energy sales to non-affiliates decreased in 2016 compared to 2015 primarily due to lower fuel prices which was partially offset by an increased opportunity sales to the external market based on higher demand. Wholesale energy sales to non-affiliates decreased in 2015 compared to 2014 primarily due to decreased opportunity sales to the external market based on lower demand which was offset by lower fuel prices.

Wholesale energy sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of the Company and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.

Wholesale energy sales to affiliates decreased in 2016 compared to 2015 primarily due to lower fuel cost and reduced sales to affiliate companies. Wholesale energy sales to affiliates decreased in 2015 compared to 2014 primarily due to lower fuel cost and reduced sales to affiliate companies.

~~Fuel and Purchased Power Expenses~~

Fuel costs constitute one of the single largest expenses for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market.

~~Details of the Company's generation and purchased power were as follows:~~

2016 2015 2014
Total generation (in millions of KWHs)
14,514
17,014
16,881
Total purchased power (in millions of KWHs)
1,574
539
886
Sources of generation (percent) –

Coal 9
17
42
Gas 91
83
58
Cost of fuel, generated (in cents per net KWH) –

Coal 3.91
3.71
3.96
Gas 2.41
2.58
3.37
Average cost of fuel, generated (in cents per net KWH)
2.55
2.78
3.64
Average cost of purchased power (in cents per net KWH)
3.07
2.17
4.85

Fuel and purchased power expenses were $377 million in 2016, a decrease of $78 million, or 17.1%, as compared to the prior year. The decrease was primarily due to a $20 million decrease in the cost of natural gas and a decrease of $82 million due to a decrease in the volume of KWH generation, partially offset by a $12 million increase in KWHs purchased and a $12 million increase in the cost of coal. Fuel and purchased power expenses were $455 million in 2015, a decrease of $162 million, or 26.3%, as compared to the prior year. The decrease was primarily due to a $125 million decrease in the cost of fuel and purchased power and a decrease of $183 million in the volume of KWHs generated by coal and purchased, partially offset by a $146 million increase in the volume of KWHs generated by gas.

Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through the Company's fuel cost recovery clauses. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein and Note 1 to the financial statements under "Fuel Costs" for additional information.

~~Fuel~~

Fuel expense decreased $100 million, or 22.6%, in 2016 compared to 2015 due to an 8.2% decrease in the average cost of fuel per KWH generated and a 15.5% decrease in the volume of KWHs generated. Fuel expense decreased $131 million, or 22.8%, in

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

~~2015 compared to 2014. The decrease was the result of a 23.6% decrease in the average cost of fuel per KWH generated, partially offset by a 0.9% increase in the volume of KWHs generated.~~

~~Purchased Power - Non-Affiliates~~

Purchased power expense from non-affiliates was flat in 2016 compared to 2015. Purchased power expense from non-affiliates decreased $13 million, or 72.2%, in 2015 compared to 2014. The decrease was primarily the result of a 72.4% decrease in the average cost per KWH purchased.

Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.

~~Purchased Power - Affiliates~~

Purchased power expense from affiliates increased $22 million, or 314.3%, in 2016 compared to 2015. The increase in 2016 was primarily the result of a 338.4% increase in the volume of KWHs purchased due to the availability of lower cost energy as compared to the cost of self-generation and a slight increase in the average cost per KWH purchased compared to 2015. Purchased power expense from affiliates decreased $18 million, or 72.0%, in 2015 compared to 2014. The decrease in 2015 was primarily the result of a 58.3% decrease in the volume of KWHs purchased and a 36.9% decrease in the average cost per KWH purchased compared to 2014.

Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.

~~Other Operations and Maintenance Expenses~~

Other operations and maintenance expenses increased $38 million, or 13.9%, in 2016 compared to the prior year. The increase was primarily due to a $28 million increase in operations and maintenance expenses related to the combined cycle and the associated common facilities portion of the Kemper IGCC, $10 million in amortization of prior operations and maintenance expense deferrals that the Company began recognizing in connection with rates associated with the Kemper IGCC in-service assets, and a $7 million increase in transmission and distribution expenses primarily related to overhead line maintenance and vegetation management, partially offset by a $9 million decrease in generation outage costs.

Other operations and maintenance expenses increased $3 million, or 1.1%, in 2015 compared to the prior year. The increase was primarily related to a $7 million increase in employee compensation and benefits, including pension costs, and a $6 million increase in generation maintenance expenses related to the combined cycle and the associated common facilities portion of the Kemper IGCC. See Note 2 to the financial statements for additional information on pension costs. Beginning in the third quarter 2015, in connection with the implementation of rates associated with the Kemper IGCC, the Company began expensing certain ongoing project costs associated with Kemper IGCC assets placed in service that previously were deferred as regulatory assets. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" and " – Regulatory Assets and Liabilities" herein for additional information. These increases in 2015 were partially offset by decreases of $4 million in transmission and distribution expenses primarily related to overhead line maintenance and vegetation management, $3 million in generation maintenance expenses primarily due to lower outage costs, and $2 million in overtime labor.

~~Depreciation and Amortization~~

Depreciation and amortization increased $9 million, or 7.3%, in 2016 compared to 2015 primarily due to $32 million of additional regulatory asset amortization related to the In-Service Asset Rate Order, ECO plan, and Mercury and Air Toxics Standards (MATS) rule compliance, $13 million associated with Kemper IGCC deferrals primarily related to depreciation deferrals in 2015, and $9 million of depreciation for additional plant in service assets primarily associated with the Plant Daniel scrubbers. These increases were partially offset by $23 million of amortization of regulatory deferrals related to the In-Service Asset Rate Order and a $22 million deferral associated with the implementation of revised ECO plan rates with the first billing cycle for September 2016.

Depreciation and amortization increased $26 million, or 26.8%, in 2015 compared to 2014 primarily due to an $18 million increase in depreciation related to an increase in assets in service and an increase in the depreciation rates, a $16 million increase due to amortization of regulatory assets associated with the Kemper IGCC, and a $2 million increase resulting from the estimated 2015 cost of capital as agreed in the In-Service Asset Rate Order. These increases were partially offset by decreases of $5 million

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~~Mississippi Power Company 2016 Annual Report~~

in ECO plan amortization, $3 million in Kemper IGCC combined cycle cost deferrals, and $2 million in deferrals associated with the purchase of Plant Daniel Units 3 and 4. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information.

See Note 1 to the financial statements under "Depreciation and Amortization" and Note 3 to the financial statements under "FERC Matters," "Retail Regulatory Matters – Environmental Compliance Overview Plan," and "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" for additional information.

~~Taxes Other Than Income Taxes~~

~~Taxes other than income~~ taxes increased $15 million, or 16.0%, in 2016 compared to 2015 primarily due to increases in ad valorem taxes of $10 million, related to an increase in the assessed value of property, as well as increases in franchise taxes of $5 million, related to increased operating revenue. Taxes other than income taxes increased $15 million, or 19.0%, in 2015 compared to 2014 primarily as a result of a $12 million increase in ad valorem taxes and a $4 million increase in franchise taxes, partially offset by a $1 million decrease in payroll taxes.

~~The retail portion of ad valorem taxes is recoverable under the Company's ad valorem tax cost recovery clause and, therefore, does not affect net income.~~

~~Estimated Loss on Kemper IGCC~~

Estimated probable losses on the Kemper IGCC of $428 million, $365 million, and $868 million were recorded in 2016, 2015, and 2014, respectively, to reflect revisions of estimated costs expected to be incurred on the construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The 2016 loss also reflects $80 million associated with the estimated minimum probable amount of costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017.

~~See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information.~~

~~Allowance for Equity Funds Used During Construction~~

AFUDC equity increased $14 million, or 12.7%, in 2016 as compared to 2015. The increase in 2016 was primarily due to a higher AFUDC rate and an increase in Kemper IGCC CWIP subject to AFUDC, partially offset by placing the Plant Daniel scrubbers in service in November 2015. AFUDC equity decreased $26 million, or 19.1%, in 2015 as compared to 2014. The decrease in 2015 was primarily due to a reduction in the AFUDC rate driven by an increase in short-term borrowings and placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Allowance for Funds Used During Construction" herein and Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information regarding the Kemper IGCC.

~~Interest Expense, Net of Amounts Capitalized~~

Interest expense, net of amounts capitalized increased $67 million in 2016 compared to 2015. The increase was primarily due to an increase of $31 million of interest on deposits resulting from the 2015 reversal of interest associated with the termination of an asset purchase agreement between the Company and SMEPA in May 2015; a $20 million increase due to additional long-term debt and a $30 million decrease in amounts capitalized primarily resulting from $17 million of capitalized interest and the amortization of $13 million in interest deferrals in accordance with the In-Service Asset Rate Order. These net increases were partially offset by a decrease of $16 million in interest accrued on the Mirror CWIP liability prior to refund in 2015.

Interest expense, net of amounts capitalized decreased $38 million, or 84.4%, in 2015 compared to 2014. The decrease was primarily due to a $58 million decrease related to the termination of an asset purchase agreement between the Company and SMEPA in May 2015 which required the return of SMEPA's deposits at a lower rate of interest than accrued, a $5 million decrease associated with amended tax returns, and a $2 million decrease associated with the redemption of long-term debt in 2015. These decreases were partially offset by increases in interest expense of $10 million associated with additional issuances of debt in 2015, $9 million associated with unrecognized tax benefits, and $5 million related to the Mirror CWIP refund, partially offset by a $3 million decrease in AFUDC debt. See Note 5 to the financial statements for additional information.

~~See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" for more information.~~

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~~Mississippi Power Company 2016 Annual Report~~

~~Income Taxes (Benefit)~~

Income tax benefits increased $32 million, or 44.4%, in 2016 compared to 2015 primarily as a result of an increase in the estimated probable losses on the Kemper IGCC and an increase in AFUDC equity, which is non-taxable.

~~Income tax benefits decreased $213 million, or 74.7%, in 2015 compared to 2014 primarily resulting from the reduction in pre-tax losses related to the estimated probable losses on the Kemper IGCC.~~

~~Effects of Inflation~~

~~FUTURE EARNINGS POTENTIAL~~

~~General~~

The Company operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located in southeast Mississippi and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Mississippi PSC under cost-based regulatory principles. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. See "FERC Matters" herein, ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Utility Regulation" herein, and Note 3 to the financial statements for additional information about regulatory matters.

The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's business of selling electricity. These factors include the Company's ability to recover its prudently-incurred costs, including those related to the remainder of the Kemper IGCC costs not included in current rates, in a timely manner during a time of increasing costs, its ability to prevail against legal challenges associated with the Kemper IGCC, and the completion and subsequent operation of the Kemper IGCC in accordance with any operational parameters that may be adopted by the Mississippi PSC. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions. Earnings are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on the Company's financial statements.

The Company provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 19.8% of the Company's total operating revenues in 2016 and are largely subject to rolling 10-year cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.

~~Environmental Matters~~

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through long-term wholesale agreements. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See Note 3 to the financial statements under "Environmental Matters" for additional information.

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~~Mississippi Power Company 2016 Annual Report~~

~~Environmental Statutes and Regulations~~

~~General~~

The Company's operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; the Migratory Bird Treaty Act; the Bald and Golden Eagle Protection Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2016, the Company had invested approximately $634 million in environmental capital retrofit projects to comply with these requirements, with annual totals of approximately $17 million, $94 million, and $118 million for 2016, 2015, and 2014, respectively. The Company expects that capital expenditures to comply with environmental statutes and regulations will total approximately $127 million from 2017 through 2021, with annual totals of approximately $11 million, $5 million, $24 million, $29 million, and $58 million for 2017, 2018, 2019, 2020, and 2021, respectively. These estimated expenditures do not include any potential capital expenditures that may arise from the EPA's final rules and guidelines or future state plans that would limit CO₂ emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. The Company also anticipates costs associated with ash pond closure and ground water monitoring under the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are reflected in the Company's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.

The Company's ultimate environmental compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations, including the environmental regulations described below; the time periods over which compliance with regulations is required; individual state implementation of regulations, as applicable; the outcome of any legal challenges to the environmental rules; any additional rulemaking activities in response to legal challenges and court decisions; the cost, availability, and existing inventory of emissions allowances; the impact of future changes in generation and emissions-related technology; the Company's fuel mix; and environmental remediation requirements. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time. See "Retail Regulatory Matters – Environmental Compliance Overview Plan" herein for additional information.

~~Air Quality~~

~~Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company.~~

In 2012, the EPA finalized the MATS rule, which imposes stringent emissions limits for acid gases, mercury, and particulate matter on coal- and oil-fired electric utility steam generating units. The implementation strategy for the MATS rule included emission controls, retirements, and fuel conversions at affected units. All of the Company's units that are subject to the MATS rule completed the measures necessary to achieve compliance with this rule or were retired prior to or during 2016.

The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone National Ambient Air Quality Standard (NAAQS). In 2008, the EPA adopted a revised eight-hour ozone NAAQS and published its final area designations in 2012. All areas within the Company's service territory have achieved attainment of the 2008 standard. In October 2015, the EPA published a more stringent eight-hour ozone NAAQS. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. States were required to recommend area designations by October 2016, and no areas within the Company's service territory were proposed for designation as nonattainment.

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~~Mississippi Power Company 2016 Annual Report~~

In June 2015, the EPA published a final rule requiring certain states (including Alabama and Mississippi) to revise or remove the provisions of their SIPs relating to the regulation of excess emissions at industrial facilities, including fossil fuel-fired generating facilities, during periods of startup, shut-down, or malfunction (SSM), and many states have submitted proposed SIP revisions in response to the rule.

The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the current and proposed environmental requirements discussed above. These regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through PPAs. The ultimate impact of the eight-hour ozone and SO₂ NAAQS, CSAPR, regional haze regulations, and SSM rule will depend on various factors, such as implementation, adoption, or other action at the state level, and the outcome of pending and/or future legal challenges, and cannot be determined at this time.

~~See Note 3 to the financial statements under "Retail Regulatory Matters – Environmental Compliance Overview Plan" for additional information.~~

~~Water Quality~~

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~~Mississippi Power Company 2016 Annual Report~~

These water quality regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions and decisions on infrastructure expansion and improvements. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. The ultimate impact of these final rules will depend on various factors, such as pending and/or future legal challenges, compliance dates, and implementation of the rules, and cannot be determined at this time.

~~Coal Combustion Residuals~~

The Company currently manages two electric generating plants in Mississippi and is also part owner of a plant located in Alabama, each with onsite CCR storage units consisting of landfills and surface impoundments (CCR Units). In addition to on-site storage, the Company also sells a portion of its CCR to third parties for beneficial reuse. Individual states regulate CCR and the States of Mississippi and Alabama each have their own regulatory requirements. The Company has an inspection program in place to assist in maintaining the integrity of its coal ash surface impoundments.

Based on current cost estimates for closure and monitoring of ash ponds pursuant to the CCR Rule, the Company has recorded AROs related to the CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing with respect to compliance activities, the Company expects to continue to periodically update these estimates. The Company has posted closure and post-closure care plans to its public website as required by the CCR Rule; however, the ultimate impact of the CCR Rule will depend on the results of initial and ongoing minimum criteria assessments and the implementation of state or federal permit programs. On December 15, 2016, the Mississippi PSC granted a CPCN to the Company authorizing certain projects associated with complying with the CCR Rule. Additionally in this order, the Mississippi PSC also authorized the Company to recover any costs associated with the CPCN, including future monitoring costs, through the ECO plan rate. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information regarding the Company's AROs as of December 31, 2016.

~~Environmental Remediation~~

The Company must comply with other environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up affected sites. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known impacted sites. The Company has authority from the Mississippi PSC to recover approved environmental compliance costs through its ECO clause. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under "Environmental Matters – Environmental Remediation" for additional information.

~~Global Climate Issues~~

~~In October 2015, the EPA published two final actions that would limit CO~~₂ ~~emissions from fossil fuel-fired electric generating units. One of the final actions contains specific emission standards governing CO~~₂ ~~emissions from new, modified, and reconstructed units. The other final action, known as the Clean Power Plan, establishes guidelines for states to develop plans to meet EPA-mandated CO~~₂ ~~emission rates or emission reduction goals for existing units. The EPA's final guidelines require state plans to meet interim CO~~₂ performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA published a proposed federal plan and model rule that, when finalized, states can adopt or that would be put in place if a state either does not submit a state plan or its plan is not approved by the EPA. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for review with the courts. The stay will remain in effect through the resolution of the litigation, including any review by the U.S. Supreme Court.

These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions and decisions on infrastructure expansion and improvements. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such

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~~Mississippi Power Company 2016 Annual Report~~

costs are not recovered through regulated rates or through PPAs. However, the ultimate financial and operational impact of the final rules on the Company cannot be determined at this time and will depend upon numerous factors, including the outcome of pending legal challenges, including legal challenges filed by the traditional electric operating companies, and any individual state implementation of the EPA's final guidelines in the event the rule is upheld and implemented.

In December 2015, parties to the United Nations Framework Convention on Climate Change – including the United States – adopted the Paris Agreement, which establishes a non-binding universal framework for addressing greenhouse gas emissions based on nationally determined contributions. It also sets in place a process for tracking progress toward the goals every five years. The ultimate impact of this agreement depends on its implementation by participating countries and cannot be determined at this time.

~~The EPA's greenhouse gas reporting rule requires annual reporting of greenhouse gas emissions expressed in terms of metric tons of CO~~₂ equivalent emissions for a company's operational control of facilities. Based on ownership or financial control of facilities, the Company's 2015 greenhouse gas emissions were approximately 7 million metric tons of CO₂ ~~equivalent. The preliminary estimate of the Company's 2016 greenhouse gas emissions on the same basis is approximately 7 million metric tons of CO~~₂ ~~equivalent. The level of greenhouse gas emissions from year to year will depend on the level of generation, the mix of fuel sources, and other factors.~~

~~FERC Matters~~

~~Municipal and Rural Associations Tariff~~

In 2013, the FERC accepted a settlement agreement entered into by the Company with its wholesale customers which approved, among other things, the same regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking by the Mississippi PSC for certain items. The regulatory treatment includes (i) approval to establish a regulatory asset for the portion of non-capitalizable Kemper IGCC-related costs which have been and will continue to be incurred during the construction period for the Kemper IGCC, (ii) authorization to defer as a regulatory asset, for the 10-year period ending October 2021, the difference between the revenue requirement under the purchase option of Plant Daniel Units 3 and 4 (assuming a remaining 30-year life) and the revenue requirement assuming the continuation of the operating lease regulatory treatment with the accumulated deferred balance at the end of the deferral being amortized into wholesale rates over the remaining life of Plant Daniel Units 3 and 4, and (iii) authority to defer in a regulatory asset costs related to the retirement or partial retirement of generating units as a result of environmental compliance rules.

In 2014, the Company reached, and the FERC accepted, a settlement agreement with its wholesale customers for an estimated annual increase in the MRA cost-based tariff of approximately $10 million, effective May 1, 2014. Included in this settlement agreement was a mechanism allowing the Company to adjust the wholesale revenue requirement in a subsequent rate proceeding in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. Therefore, the Company recorded a regulatory asset as a result of a portion of the Kemper IGCC being placed in service prior to the projected date, which was fully amortized as of December 31, 2015. In May 2015, the FERC accepted a further settlement agreement between the Company and its wholesale customers to forgo a MRA cost-based electric tariff increase by, among other things, increasing the accrual of AFUDC and lowering the portion of CWIP in rate base, effective April 1, 2015, resulting in an estimated annual AFUDC increase of approximately $14 million, of which approximately $11 million is related to the Kemper IGCC.

On March 31, 2016, the Company reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in November 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC is estimated to be approximately $14 million through the Kemper IGCC's projected in-service date of mid-March 2017.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

~~Fuel Cost Recovery~~

The Company has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective with the first billing cycle for September 2016, fuel rates decreased $11 million annually for wholesale MRA customers and $1 million annually for wholesale MB customers. At December 31, 2016 and 2015, the amount of over recovered wholesale MRA fuel costs were approximately $13 million and $24 million, respectively, which is included in over recovered regulatory clause liabilities, current in the balance sheets. Effective January 1, 2017, the wholesale MRA fuel rate increased $10 million annually.

The Company's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on the Company's revenues or net income, but will affect cash flow.

~~Market-Based Rate Authority~~

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Retail Regulatory Matters~~

~~General~~

The Company's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. The Company's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through the Company's base rates. See Note 3 to the financial statements under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" for additional information.

In 2012, the Mississippi PSC issued an order for the purpose of investigating and reviewing, for informational purposes only, the ROE formulas used by the Company and all other regulated electric utilities in Mississippi. In 2013, the MPUS filed with the Mississippi PSC its report on the ROE formulas used by the Company and all other regulated electric utilities in Mississippi. The ultimate outcome of this matter cannot be determined at this time.

~~Renewables~~

In November 2015, the Mississippi PSC issued orders approving three solar facilities for a combined total of approximately 105 MWs. The Company will purchase all of the energy produced by the solar facilities for the 25-year term under each of the three PPAs. The projects are expected to be in service by the second quarter 2017 and the resulting energy purchases are expected to be recovered through the Company's fuel cost recovery mechanism. The Company may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.

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~~Mississippi Power Company 2016 Annual Report~~

~~Performance Evaluation Plan~~

The Company's retail base rates are set under the PEP, a rate plan approved by the Mississippi PSC. Two filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on a projected revenue requirement, and the PEP lookback filing, which is filed after the end of the year and allows for review of the actual revenue requirement compared to the projected filing.

In 2011, the Company submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the Company received a letter from the MPUS disputing certain items in the 2010 PEP lookback filing. In 2012, the Mississippi PSC issued an order canceling the Company's PEP lookback filing for 2011. In 2013, the MPUS contested the Company's PEP lookback filing for 2012, which indicated a refund due to customers of $5 million. Unresolved matters related to the 2010 PEP lookback filing, which remain under review, also impact the 2012 PEP lookback filing.

In 2013, the Mississippi PSC approved the projected PEP filing for 2013, which resulted in a rate increase of 1.9%, or $15 million, annually, effective March 19, 2013. The Company may be entitled to $3 million in additional revenues related to 2013 as a result of the late implementation of the 2013 PEP rate increase.

In 2014, 2015, and 2016, the Company submitted its annual PEP lookback filings for the prior years, which for 2013 and 2014 each indicated no surcharge or refund and for 2015 indicated a $5 million surcharge. On July 12, 2016 and November 15, 2016, the Company submitted its annual projected PEP filings for 2016 and 2017, respectively, which each indicated no change in rates. The Mississippi PSC suspended each of these filings to allow more time for review.

In 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for the Company and other regulated electric utilities in Mississippi.

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Energy Efficiency~~

On May 3, 2016, the Mississippi PSC issued an order approving the Company's Energy Efficiency Cost Rider Compliance filing, which reduced annual retail revenues by approximately $2 million effective with the first billing cycle for June 2016.

On November 30, 2016, the Company submitted its Energy Efficiency Cost Rider Compliance filing, which included an increase of $1 million in annual retail revenues. The ultimate outcome of this matter cannot be determined at this time.

~~See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.~~

~~Environmental Compliance Overview Plan~~

In 2012, the Mississippi PSC approved the Company's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which were placed in service in November 2015. These units are jointly owned by the Company and Gulf Power, with 50% ownership each. In 2014, the Company entered into a settlement agreement with the Sierra Club that, among other things, required the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which also occurred in 2014. In addition, and consistent with the Company's ongoing evaluation of recent environmental rules and regulations, the Company agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018 (and the units were retired in July 2016). The Company also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015 (which occurred in April 2015) and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) no later than April 2016 (which occurred in February and March 2016, respectively) and begin operating those units solely on natural gas (which occurred in June and July 2016, respectively).

In accordance with a 2011 accounting order from the Mississippi PSC, the Company has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. As of December 31, 2016, $17 million of Plant Greene County costs have been reclassified as regulatory assets and are expected to be recovered through the ECO plan and other existing cost recovery mechanisms over a period to be determined by the Mississippi PSC. The Mississippi PSC approved $41 million of costs that were reclassified to a regulatory asset associated with Plant Watson for amortization over a five-year period that began in July 2016. As a result, these decisions are not expected to have a material impact on the Company's financial statements.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

On August 17, 2016, the Mississippi PSC approved the Company's revised ECO plan filing for 2016, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to the Plant Daniel Units 1 and 2 scrubbers being placed in service in November 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2017 filing.

On February 14, 2017, the Company submitted its ECO plan filing for 2017, which requested an increase in annual revenues over 2016, capped at 2% of total retail revenues, of approximately $18 million, primarily related to the Plant Daniel Units 1 and 2 scrubbers placed in service in November 2015. The revenue requirement in excess of the 2%, approximately $27 million plus carrying costs, will be carried forward to the 2018 filing. The ultimate outcome of this matter cannot be determined at this time.

~~Fuel Cost Recovery~~

The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually. The Mississippi PSC approved the 2016 retail fuel cost recovery factor, effective January 5, 2016, which resulted in an annual revenue decrease of approximately $120 million. On August 17, 2016, the Mississippi PSC approved an additional decrease of $51 million annually in fuel cost recovery rates effective with the first billing cycle for September 2016. At December 31, 2016 and 2015, over recovered retail fuel costs were approximately $37 million and $71 million, respectively, which is included in over recovered regulatory clause liabilities, current in the balance sheets. On January 12, 2017, the Mississippi PSC approved the 2017 retail fuel cost recovery factor, effective February 2017 through January 2018, which will result in an annual revenue increase of approximately $55 million.

~~Ad Valorem Tax Adjustment~~

The Company establishes, annually, an ad valorem tax adjustment factor that is approved by the Mississippi PSC to collect the ad valorem taxes paid by the Company. On June 17, 2016, the Mississippi PSC approved the Company's annual ad valorem tax adjustment factor filing for 2016, which included an annual rate decrease of 0.07%, or $1 million in annual retail revenues, primarily due to the prior year over recovery.

~~System Restoration Rider~~

In October 2015, the Mississippi PSC approved the Company's 2015 SRR rate filing, which proposed that the SRR rate remain level at zero and the Company continue to accrue $3 million annually to the property damage reserve.

On February 1, 2016, the Company submitted its 2016 SRR rate filing which proposed no changes to either the SRR rate or the annual property damage reserve accrual. On February 19, 2016, the filing was suspended by the Mississippi PSC for review. The ultimate outcome of this matter cannot be determined at this time.

On February 3, 2017, the Company submitted its 2017 SRR rate filing, which proposed that the rate level remain at zero and the Company be allowed to accrue $4 million annually to the property damage reserve in 2017. The ultimate outcome of this matter cannot be determined at this time.

~~See Note 1 to the financial statements under "Provision for Property Damage" for additional information.~~

~~Storm Damage Cost Recovery~~

In connection with the damage associated with Hurricane Katrina, the Mississippi PSC authorized the issuance of system restoration bonds in 2006. In accordance with a Mississippi PSC order dated January 24, 2017, the Company has adjusted the System Restoration Charge implemented after Hurricane Katrina to zero. Upon completion of the proper defeasance process by the Mississippi State Bond Commission, the Company's obligations in relation to system restoration bonds issued after Hurricane Katrina in 2005 will be completely satisfied.

~~Provision for Property Damage~~

On January 21, 2017, a tornado caused extensive damage to the Company's transmission and distribution infrastructure. Preliminary storm damage repairs have been estimated at $11 million. A portion of these costs may be charged to the retail property damage reserve and addressed in a subsequent SRR rate filing. The ultimate outcome of this matter cannot be determined at this time.

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

~~Integrated Coal Gasification Combined Cycle~~

~~Kemper IGCC Overview~~

The Kemper IGCC utilizes IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC is fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, the Company constructed and plans to operate approximately 61 miles of CO₂ ~~pipeline infrastructure for the transport of captured CO~~₂ ~~for use in enhanced oil recovery.~~

~~Kemper IGCC Schedule and Cost Estimate~~

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service inMay 2014. The Company placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014. The remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." The Company achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. The Company subsequently completed a brief outage to repair and make modifications to further improve the plant's ability to achieve sustained operations sufficient to support placing the plant in service for customers. Efforts to reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines are in process. The plant has produced and captured CO₂, and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. On February 20, 2017, the Company determined gasifier "B," which has been producing syngas over 60% of the time since early November 2016, requires an outage to remove ash deposits from its ash removal system. Gasifier "A" and combustion turbine "A" are expected to remain in operation, producing electricity from syngas, as well as producing chemical by-products. As a result, the Company currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by mid-March 2017.

The Company's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision discussed herein under "Rate Recovery of Kemper IGCC Costs – ~~2013 MPSC Rate Order"), and actual costs incurred as of December 31, 2016, all of which include 100% of the costs for the Kemper IGCC, are as follows:~~

Cost Category
2010 Project Estimate^(a)

Current Cost Estimate^(b)
Actual Costs
(in billions)
Plant Subject to Cost Cap^(c)(e)
$ 2.40
$ 5.64
$ 5.44
Lignite Mine and Equipment 0.21
0.23
0.23
CO₂ Pipeline Facilities
0.14
0.11
0.11
AFUDC^(d)
0.17
0.79
0.75
Combined Cycle and Related Assets Placed in
Service – Incremental^(e)
—
0.04
0.04
General Exceptions 0.05
0.10
0.09
Deferred Costs^(e)
—
0.22
0.21
Additional DOE Grants —
(0.14 ) (0.14 )
Total Kemper IGCC^(f)
$ 2.97
$ 6.99
$ 6.73


~~(a)~~	~~The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO~~₂ ~~pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.~~


~~(b)~~	~~Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap.~~


~~(c)~~	~~The 2012 MPSC CPCN Order approved a construction cost cap of up to~~ ~~$2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.~~ ~~The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated~~

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

~~common facilities placed in service in August 2014 that are subject to the~~ ~~$2.88 billion~~ ~~cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information.~~

~~(d)~~

~~The Company's~~ 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.

~~(e)~~

Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at December 31, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information.

~~(f)~~

The Current Cost Estimate and the Actual Costs include $2.76 billion that will not be recovered for costs above the cost cap, $0.83 billion of investment costs included in current rates for the combined cycle and related assets in service, and $0.08 billion of costs that were previously expensed for the combined cycle and related assets in service. The Current Cost Estimate and the Actual Costs exclude $0.25 billion of costs not included in current rates for post-June 2013 mine operations, the lignite fuel inventory, and the nitrogen plant capital lease, which will be included in the 2017 Rate Case to be filed by June 3, 2017. See Note 1 to the financial statements under "Fuel Inventory," Note 6 to the financial statements under "Capital Leases," and "Rate Recovery of Kemper IGCC Costs – 2017 Rate Case" herein for additional information.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of December 31, 2016, $3.67 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants, the Additional DOE Grants, and estimated probable losses of $2.84 billion), $6 million in other property and investments, $75 million in fossil fuel stock, $47 million in materials and supplies, $29 million in other regulatory assets, current, $172 million in other regulatory assets, deferred, $3 million in other current assets, and $14 million in other deferred charges and assets in the balance sheet.

The Company does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Company recorded pre-taxcharges to income for revisions to the cost estimate of $348 million ($215 million after tax), $365 million ($226 million after tax), and $868 million ($536 million after tax) in 2016, 2015, and 2014, respectively. Since 2012, in the aggregate, the Company has incurred charges of $2.76 billion ($1.71 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through December 31, 2016. The increases to the cost estimate in 2016 primarily reflect $186 million for the extension of the Kemper IGCC's projected in-service date from August 31, 2016 to March 15, 2017 and $162 million for increased efforts related to operational readiness and challenges in start-up and commissioning activities, including the cost of repairs and modifications to both gasifiers, mechanical improvements to coal feed and ash management systems, and outage work, as well as certain post-in-service costs expected to be subject to the cost cap.

Any extension of the in-service date beyond mid-March 2017 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond mid-March 2017 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $16 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $3 million per month. For additional information, see "2015 Rate Case" herein.

Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). Any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in the Company's statements of income and these changes could be material.

~~Rate Recovery of Kemper IGCC Costs~~

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

the resolution of legal challenges, cannot now be determined but could result in further material charges that could have a material impact on the Company's results of operations, financial condition, and liquidity.

As of December 31, 2016, in addition to the $2.76 billion of costs above the Mississippi PSC's $2.88 billion cost cap that have been recognized as a charge to income, the Company had incurred approximately $1.99 billion in costs subject to the cost cap and approximately $1.46 billion in Cost Cap Exceptions related to the construction and start-up of the Kemper IGCC that are not included in current rates. These costs primarily relate to the following:

Cost Category Actual Costs
(in billions)
Gasifiers and Gas Clean-up Facilities $ 1.88
Lignite Mine Facility 0.31
CO₂ Pipeline Facilities
0.11
Combined Cycle and Common Facilities 0.16
AFUDC 0.69
General exceptions 0.07
Plant inventory 0.03
Lignite inventory 0.08
Regulatory and other deferred assets 0.12
Subtotal $ 3.45
Additional DOE Grants (0.14 )
Total $ 3.31

Of these amounts, approximately 29% is related to wholesale and approximately 71% is related to retail, including the 15% portion that was previously contracted to be sold to SMEPA. The Company and its wholesale customers have generally agreed to the similar regulatory treatment for wholesale tariff purposes as approved by the Mississippi PSC for retail for Kemper IGCC-related costs. See "FERC Matters – Municipal and Rural Associations Tariff" and "Termination of Proposed Sale of Undivided Interest" herein for further information.

~~Prudence~~

On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, the Company made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC is placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, the Company submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC is placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period. The Company will not seek recovery of the $68 million in additional estimated costs from customers if incurred.

~~The Company expects the Mississippi PSC to address these matters in connection with the 2017 Rate Case.~~

~~Economic Viability Analysis~~

In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected.

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.

~~The Company expects the Mississippi PSC to address this matter in connection with the 2017 Rate Case.~~

~~2017 Accounting Order Request~~

After the remainder of the plant is placed in service, AFUDC equity of approximately $11 million per month will no longer be recorded in income, and the Company expects to incur approximately $25 million per month in depreciation, taxes, operations and maintenance expenses, interest expense, and regulatory costs in excess of current rates. The Company expects to file a request for authority from the Mississippi PSC and the FERC to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. In the event that the Mississippi PSC does not grant the Company's request, these monthly expenses will be charged to income as incurred and will not be recoverable through rates.

~~2017 Rate Case~~

The Company continues to believe that all costs related to the Kemper IGCC have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. The Company also recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein and under "Prudence," "Lignite Mine and CO₂ Pipeline Facilities," "Termination of Proposed Sale of Undivided Interest," and "Income Tax Matters," these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.

Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. The Company expects to utilize this legislation to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact the Company's ability to utilize alternate financing through securitization or the February 2013 legislation.

Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, the Company is developing both a traditional rate case requesting full cost recovery of the amounts not currently in rates and a rate mitigation plan that together represent the Company's probable filing strategy. The Company also expects that timely resolution of the 2017 Rate Case will likely require a negotiated settlement agreement. In the event an agreement acceptable to both the Company and the MPUS (and other parties) can be negotiated and ultimately approved by the Mississippi PSC, it is reasonably possible that full regulatory recovery of all Kemper IGCC costs will not occur. The impact of such an agreement on the Company's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, the Company intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges.

The Company has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and has recognized an additional $80 million charge to income, which is the estimated minimum probable amount of the $3.31 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017.

~~2015 Rate Case~~

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

pipeline, and water pipeline) and other related costs. The interim rates were designed to collect approximately $159 million annually and became effective in September 2015, subject to refund and certain other conditions.

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between the Company and the MPUS regarding the In-Service Asset Proposal. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on the Company's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA but reserved the Company's right to seek recovery in a future proceeding. See "Termination of Proposed Sale of Undivided Interest" herein for additional information. The Company is required to file the 2017 Rate Case by June 3, 2017.

With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, the Company completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.

~~2013 MPSC Rate Order~~

In January 2013, the Company entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, the Company agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).

On February 12, 2015, the Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described above.

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, the Company continues to record AFUDC on the Kemper IGCC. Through December 31, 2016, AFUDC recorded since the original May 2014 estimated in-service date for the Kemper IGCC has totaled $398 million, which will continue to accrue at approximately $16 million per month until the remainder of the plant is placed in service. The Company has not recorded any AFUDC on Kemper IGCC costs in excess of the $2.88 billion cost cap, except for Cost Cap Exception amounts.

~~2012 MPSC CPCN Order~~

The 2012 MPSC CPCN Order included provisions relating to both the Company's recovery of financing costs during the course of construction of the Kemper IGCC and the Company's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters including availability factor, heat rate, lignite heat content, and chemical revenue based upon assumptions in the Company's petition for the CPCN. The Company expects the Mississippi PSC to apply operational parameters in connection with the 2017 Rate Case and future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or the Company incurs additional costs to satisfy such parameters, there could be a material adverse impact on the Company's financial statements. See "Prudence" herein for additional information.

~~Regulatory Assets and Liabilities~~

Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting the Company the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited

~~Table of ContentsIndex to Financial Statements~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.

In August 2014, the Company requested confirmation by the Mississippi PSC of the Company's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, the Company is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015 and the second quarter 2016, in connection with the implementation of retail and wholesale rates, respectively, the Company began expensing certain ongoing project costs and certain retail debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of December 31, 2016, the balance associated with these regulatory assets was $97 million, of which $29 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $104 million as of December 31, 2016. The amortization period for these assets is expected to be determined by the Mississippi PSC in the 2017 Rate Case. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.

The In-Service Asset Rate Order requires the Company to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. At December 31, 2016, the Company's related regulatory liability included in its balance sheet totaled approximately $7 million. See "2015 Rate Case" herein for additional information.

~~Also see Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information.~~

~~Lignite Mine and CO~~₂ ~~Pipeline Facilities~~

In conjunction with the Kemper IGCC, the Company owns the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.

In 2010, the Company executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and the Company has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, the Company currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" for additional information.

~~In addition, the Company has constructed and will operate the CO~~₂ ~~pipeline for the planned transport of captured CO~~₂ for use in enhanced oil recovery. The Company entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO₂ ~~captured from the Kemper IGCC and Treetop would purchase 30% of the CO~~₂ captured from the Kemper IGCC. On June 3, 2016, the Company cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO₂~~captured from the Kemper IGCC, an initial contract term of 16 years, and termination rights if the Company has not satisfied its contractual obligation to deliver captured CO~~₂ by July 1, 2017, in addition to Denbury's existing termination rights in the event of a change in law, force majeure, or an event of default by the Company. Any termination or material modification of the agreement with Denbury could impact the operations of the Kemper IGCC and result in a material reduction in the Company's revenues to the extent the Company is not able to enter into other similar contractual arrangements or otherwise sequester the CO₂ produced. Additionally, sustained oil price reductions could result in significantly lower revenues than the Company originally forecasted to be available to offset customer rate impacts, which could have a material impact on the Company's financial statements.

~~The ultimate outcome of these matters cannot be determined at this time.~~

~~Termination of Proposed Sale of Undivided Interest~~

In 2010 and as amended in 2012, the Company and SMEPA entered into an agreement whereby SMEPA agreed to purchase a 15% undivided interest in the Kemper IGCC (15% Undivided Interest). On May 20, 2015, SMEPA notified the Company of its termination of the agreement. The Company previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation,

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

returned approximately $301 million to SMEPA. Subsequently, the Company issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which matures on December 1, 2017.

~~Litigation~~

On April 26, 2016, a complaint against the Company was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. On August 12, 2016, Southern Company and the Company removed the case to the U.S. District Court for the Southern District of Mississippi. The plaintiffs filed a request to remand the case back to state court, which was granted on November 17, 2016. The individual plaintiff, John Carlton Dean, alleges that the Company and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that the Company and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched the Company and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing the Company or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On December 7, 2016, Southern Company and the Company filed motions to dismiss.

On June 9, 2016, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against the Company, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO₂ contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of the Company, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, the Company, and SCS have moved to compel arbitration pursuant to the terms of the CO₂ ~~contract.~~

The Company believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact on the Company's results of operations, financial condition, and liquidity. The Company will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time.

~~Baseload Act~~

In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. See "Rate Recovery of Kemper IGCC Costs" herein for additional information.

~~Income Tax Matters~~

~~See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information about the Kemper IGCC.~~

~~Bonus Depreciation~~

In December 2015, the Protecting Americans from Tax Hikes (PATH) Act was signed into law. Bonus depreciation was extended for qualified property placed in service through 2020. The PATH Act allows for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. The extension of bonus depreciation included in the PATH Act is expected to result in approximately $20 million of positive cash flows for the 2016 tax year, which was not all realized in 2016 due to a projected consolidated net operating loss (NOL) for Southern Company. Dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2017, the Company expects approximately $370 million of positive cash flows from bonus depreciation for the 2017 tax year, which may not all be realized in 2017 due to additional NOL projections for the 2017 tax year. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" and Note 5 to the financial statements under "Current and Deferred Income Taxes – ~~Net Operating Loss" for additional information. The ultimate outcome of this matter cannot be determined at this time.~~

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

~~Investment Tax Credits~~

The IRS allocated $133 million (Phase I) and $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to the Company in connection with the Kemper IGCC. These tax credits were dependent upon meeting the IRS certification requirements, including an in-service date no later than May 11, 2014 for the Phase I credits and April 19, 2016 for the Phase II credits. In addition, the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code was also a requirement of the Phase II credits. As a result of schedule extensions for the Kemper IGCC, the Phase I tax credits were recaptured in 2013 and the Phase II tax credits were recaptured in 2015.

~~Section 174 Research and Experimental Deduction~~

Southern Company, on behalf of the Company, has reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and has filed amended federal income tax returns for 2008 through 2013 to also include such deductions. The Kemper IGCC is based on first-of-a-kind technology, and Southern Company believes that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, the Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million as of December 31, 2016. See Note 5 to the financial statements under "Unrecognized Tax Benefits" for additional information. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.

~~Other Matters~~

The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ ~~and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.~~

The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

In 2013, the Company submitted a claim under the Deepwater Horizon Economic and Property Damages Settlement Agreement associated with the oil spill that occurred in 2010 in the Gulf of Mexico. The ultimate outcome of this matter cannot be determined at this time.

The SEC is conducting a formal investigation of Southern Company and the Company concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and the Company believe the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC estimated construction costs and expected in-service date. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the Company's financial statements.

~~ACCOUNTING POLICIES~~

~~Application of Critical Accounting Policies and Estimates~~

The Company prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.

~~Utility Regulation~~

The Company is subject to retail regulation by the Mississippi PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.

~~Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery~~

During 2016, the Company further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Company does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.

As a result of revisions to the cost estimate, the Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC subject to the construction cost cap of $127 million ($78 million after tax) in the fourth quarter 2016, $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2016, $53 million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, $462 million ($285 million after tax) in the first quarter 2013, and $78 million ($48 million after tax) in the fourth quarter 2012. In the aggregate, the Company has incurred charges of $2.76 billion ($1.71 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through December 31, 2016.

The Company's revised cost estimate reflects an expected in-service date of mid-March 2017 and includes certain post-in-service costs which are expected to be subject to the cost cap. The Company has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

In addition to the current construction cost estimate, the Company is also identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. As of December 31, 2016, approximately $12 million of related potential costs has been included in the estimated loss on the Kemper IGCC. Other projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap. In subsequent periods, any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in the statements of income and these changes could be material.

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~~Mississippi Power Company 2016 Annual Report~~

fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond mid-March 2017 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $16 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $3 million per month.

The Company continues to believe that all costs related to the Kemper IGCC have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. The Company also recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further under FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs," " – Prudence," " – Lignite Mine and CO₂ Pipeline Facilities," and " – Termination of Proposed Sale of Undivided Interest" and "Income Tax Matters," these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs, net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.

Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, the Company is developing both a traditional rate case requesting full cost recovery of the amounts not currently in rates and a rate mitigation plan that together represent the Company's probable filing strategy. The Company also expects that timely resolution of the 2017 Rate Case will likely require a negotiated settlement agreement. In the event an agreement acceptable to both the Company and the MPUS (and other parties) can be negotiated and ultimately approved by the Mississippi PSC, it is reasonably possible that full regulatory recovery of all Kemper IGCC costs will not occur. The impact of such an agreement on the Company's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, the Company intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges.

Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on results of operations, the Company considers these items to be critical accounting estimates. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information.

~~Asset Retirement Obligations~~

AROs are computed as the fair value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.

The liability for AROs primarily relates to facilities that are subject to the CCR Rule, principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing with respect to compliance activities, including the potential for closing ash ponds prior to the end of their

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~~Mississippi Power Company 2016 Annual Report~~

currently anticipated useful life, the Company expects to continue to periodically update these estimates. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals" herein for additional information.

~~Given the significant judgment involved in estimating AROs, the Company considers the liabilities for AROs to be critical accounting estimates.~~

~~See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.~~

~~Pension and Other Postretirement Benefits~~

The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.

Key elements in determining the Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, the Company discounts the future related cash flows using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, the Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. For 2016, the Company adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost component of net periodic pension and other postretirement benefit plan expense decreased by approximately $4 million in 2016.

A 25 basis point change in any significant assumption (discount rate, salaries, or long-term return on plan assets) would result in a $2 million or less change in total annual benefit expense and a $19 million or less change in projected obligations.

~~See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.~~

~~Allowance for Funds Used During Construction~~

In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 6.5%, 5.99%, and 6.91% for the years ended December 31, 2016, 2015, and 2014, respectively. The AFUDC rate is applied to CWIP consistent with jurisdictional regulatory treatment. AFUDC equity was $124 million, $110 million, and $136 million in 2016, 2015, and 2014, respectively.

~~Unbilled Revenues~~

Revenues related to the retail sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company's results of operations.

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~~Mississippi Power Company 2016 Annual Report~~

~~Contingent Obligations~~

The Company is subject to a number of federal and state laws and regulations as well as other factors and conditions that subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's results of operations, cash flows, or financial condition.

~~Recently Issued Accounting Standards~~

While the Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.

The Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). If final implementation guidance indicates CIAC will be accounted for under ASC 606 and offsetting regulatory treatment is not permitted, it could have a material impact on the Company's financial statements.

~~On March 30, 2016, the FASB issued ASU No. 2016-09,~~ ~~Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting~~ (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5, 8, and 11 to the financial statements for disclosures impacted by ASU 2016-09.

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~~Mississippi Power Company 2016 Annual Report~~

~~In 2014, the FASB issued ASU No. 2014-15,~~ ~~Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern~~ (ASU 2014-15). ASU 2014-15 defines management's responsibility to evaluate whether there is substantial doubt about an organization's ability to continue as a going concern within one year of the date the financial statements are issued and to provide related footnote disclosures including management's plans that alleviate substantial doubt. ASU 2014-15 became effective for fiscal years ending after December 15, 2016 and the Company has included the disclosures required by ASU 2014-15 in Note 6 to the financial statements under "Going Concern."

~~FINANCIAL CONDITION AND LIQUIDITY~~

~~Overview~~

Earnings for all periods presented were negatively affected by revisions to the cost estimate for the Kemper IGCC. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information.

The Company's capital expenditures and debt maturities are expected to materially exceed operating cash flows through 2021. In addition to the Kemper IGCC, projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental modifications to existing generating units, and to expand and improve transmission and distribution facilities.

As of December 31, 2016, the Company's current liabilities exceeded current assets by approximately $371 million primarily due to $551 million in promissory notes to Southern Company which mature in December 2017, $35 million in senior notes which mature in November 2017, and $63 million in short-term debt. The Company expects the funds needed to satisfy the promissory notes to Southern Company will exceed amounts available from operating cash flows, lines of credit, and other external sources. Accordingly, the Company intends to satisfy these obligations through loans and/or equity contributions from Southern Company. Specifically, the Company has been informed by Southern Company that, in the event sufficient funds are not available from external sources, Southern Company intends to (i) extend the maturity of the $551 million in promissory notes and (ii) provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, the Company's financial statement presentation contemplates continuation of the Company as a going concern as a result of Southern Company's anticipated ongoing financial support of the Company, consistent with the requirements of ASU 2014-15. See Note 1 to the financial statements under "Recently Issued Accounting Standards" for additional information regarding ASU 2014-15.

The Company's investments in the qualified pension plan increased in value as of December 31, 2016 as compared to December 31, 2015. On December 19, 2016, the Company voluntarily contributed $47 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated during 2017.

Net cash provided from operating activities totaled $229 million for 2016, an increase of $56 million as compared to 2015. The increase in cash provided from operating activities in 2016 was primarily due to repayment in 2015 of ITCs relating to the Kemper IGCC, as well as the 2015 mirror CWIP refund, partially offset by lower income tax benefits related to the Kemper IGCC in 2016 and lower fuel rates in 2016. Net cash provided from operating activities totaled $173 million for 2015, a decrease of $562 million as compared to 2014. The decrease in net cash provided from operating activities was primarily due to lower R&E tax deductions and lower incremental benefit of ITCs relating to the Kemper IGCC reducing income tax refunds, as well as a decrease in the Mirror CWIP regulatory liability due to the Mirror CWIP refund, partially offset by increases in over recovered regulatory clause revenues and customer liability associated with the Mirror CWIP refund.

Net cash used for investing activities in 2016, 2015, and 2014 totaled $697 million, $906 million, and $1.3 billion, respectively. The cash used for investing activities in 2016 was primarily due to gross property additions related to the Kemper IGCC, partially offset by the receipt of Additional DOE Grants. The cash used for investing activities in 2015 and 2014 was primarily due to gross property additions related to the Kemper IGCC and the Plant Daniel scrubber project.

Net cash provided from financing activities totaled $594 million in 2016 primarily due to long-term debt financings and capital contributions from Southern Company, partially offset by a decrease in short-term borrowings and redemptions of long-term debt.

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~~Mississippi Power Company 2016 Annual Report~~

Net cash provided from financing activities totaled $698 million in 2015 primarily due to short-term borrowings, capital contributions from Southern Company, and long-term debt financings, partially offset by redemptions of long-term debt. Net cash provided from financing activities totaled $593 million in 2014 primarily due to capital contributions from Southern Company, long-term debt financings, and the receipts of interest bearing refundable deposits previously pending, partially offset by redemptions of long-term debt.

Significant balance sheet changes as of December 31, 2016 compared to 2015 included an increase in long-term debt of $538 million. A portion of this debt was used to repay securities and notes payable resulting in a $99 million decrease in securities due within one year and a $477 million decrease in notes payable. Additionally, CWIP increased $291 million primarily due to the Kemper IGCC and the required refund of Mirror CWIP collections which reduced the related customer liability by $72 million. Other significant changes include a $383 million increase in accrued income taxes offset by unrecognized tax benefits of $368 million reclassified from long-term to current. Total common stockholder's equity increased $584 million primarily due to the receipt of capital contributions from Southern Company.

The Company's ratio of common equity to total capitalization plus short-term debt was 45.2% and 47.1% at December 31, 2016 and 2015, respectively. See Note 6 to the financial statements for additional information.

~~Sources of Capital~~

As discussed above, the Company's financial condition and its ability to obtain funds needed for normal business operations and completion of the construction and start-up of the Kemper IGCC were adversely affected for all periods presented by events relating to the Kemper IGCC. In December 2015, the Mississippi PSC approved the In-Service Asset Rate Order, which among other things, provided for retail rate recovery of an annual revenue requirement of approximately $126 million effective December 17, 2015. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of Kemper IGCC cost recovery. See "Capital Requirements and Contractual Obligations" herein and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" herein for additional information.

As of December 31, 2016, the Company's current liabilities exceeded current assets by approximately $371 million primarily due to $551 million in promissory notes to Southern Company which mature in December 2017, $35 million in senior notes which mature in November 2017, and $63 million in short-term debt. The Company expects the funds needed to satisfy the promissory notes to Southern Company will exceed amounts available from operating cash flows, lines of credit, and other external sources. Accordingly, the Company intends to satisfy these obligations through loans and/or equity contributions from Southern Company. Specifically, the Company has been informed by Southern Company that, in the event sufficient funds are not available from external sources, Southern Company intends to (i) extend the maturity of the $551 million in promissory notes and (ii) provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, the Company's financial statement presentation contemplates continuation of the Company as a going concern as a result of Southern Company's anticipated ongoing financial support of the Company, consistent with the requirements of ASU 2014-15. See Note 1 to the financial statements under "Recently Issued Accounting Standards" for additional information regarding ASU 2014-15.

The Company received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE is expected to be received for commercial operation of the Kemper IGCC. On April 8, 2016, the Company received approximately $137 million in Additional DOE Grants for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers. In addition, see Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

The issuance of securities by the Company is subject to regulatory approval by the FERC. Additionally, public offerings of securities are required to be registered with the SEC under the Securities Act of 1933, as amended. The amounts of securities authorized by the FERC are continuously monitored and appropriate filings are made to ensure flexibility in raising capital. Any future financing through secured debt would also require approval by the Mississippi PSC.

See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company in the Southern Company system.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

~~At December 31, 2016, the Company had approximately $224 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2016 were as follows:~~

Expires
Executable
Term Loans
Expires Within One Year
2017 Total Unused
One
Year

Two
Years
Term Out No Term Out
(in millions) (in millions) (in millions) (in millions)
$ 173
$ 173
$ 150
$ —
$ 13
$ 13
$ 160

~~See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.~~

Most of these bank credit arrangements, as well as the Company's term loan arrangements, contain covenants that limit debt levels and typically contain cross acceleration or cross default provisions to other indebtedness (including guarantee obligations) of the Company. Such cross default provisions to other indebtedness would trigger an event of default if the Company defaulted on indebtedness or guarantee obligations over a specific threshold. Such cross acceleration provisions to other indebtedness would trigger an event of default if the Company defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2016, the Company was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.

A portion of the $150 million unused credit arrangements with banks is allocated to provide liquidity support to the Company's pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2016 was approximately $40 million.

~~Short-term borrowings are included in notes payable in the balance sheets. The Company had no short-term borrowings in 2014. Details of short-term borrowing for 2015 and 2016 were as follows:~~

Short-term Debt at the End of the Period
Short-term Debt During the Period ^(*)
Amount Outstanding Weighted Average Interest Rate Average Outstanding Weighted Average Interest Rate Maximum Amount Outstanding
(in millions) (in millions) (in millions)
December 31, 2016 $ 23
2.6 % $ 112
2.0 % $ 500
December 31, 2015 $ 500
1.4 % $ 372
1.3 % $ 515


~~(*)~~	~~Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31.~~

~~Financing Activities~~

In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm restoration costs, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

~~Bank Term Loan and Senior Notes~~

In March 2016, the Company entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. The Company borrowed $900 million in March 2016 under the term loan agreement and the remaining $300 million in October 2016. The Company used the initial proceeds to repay $900 million in maturing bank loans in March 2016 and the remaining $300 million to repay at maturity the Company's Series 2011A 2.35% Senior Notes due October 15, 2016. This loan matures on April 1, 2018 and bears interest based on one-month LIBOR.

~~This bank loan has covenants that limit debt levels t~~o 65% of total capitalization, as defined in the agreement. For purposes of this definition, debt excludes the long-term debt payable to affiliated trusts, other hybrid securities, and securitized debt relating to the contemplated securitization of certain costs of the Kemper IGCC. At December 31, 2016, the Company was in compliance with its debt limit.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

In addition, this bank loan contains cross acceleration provisions to other debt (including guarantee obligations) that would be triggered if the Company defaulted on debt above a specified threshold, the payment of which was then accelerated. The Company is currently in compliance with all such covenants.

~~Parent Company Loans and Equity Contributions~~

On January 28, 2016, the Company issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During 2016, the Company borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015.

~~Also, on December 14, 2016, the Company received a capital contribution from Southern Company of $400 million, the proceeds of which were used for general corporate purposes.~~

~~Other Obligations~~

~~In June 2016, the Company renewed a $10 million short-term note, which matures on June 30, 2017, bearing interest based on three-month LIBOR.~~

~~In September 2016, the Company entered into interest rate swaps to fix the variable interest rate on $900 million of the term loan entered into in March 2016.~~

~~In December 2016, the Company repaid $2.5 million of a $15 million short-term note, reducing the total short-term notes payable to $22.5 million.~~

~~Credit Rating Risk~~

~~At December 31, 2016, the Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.~~

There are certain contracts that have required or could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At ~~December 31, 2016~~, the maximum amount of potential collateral requirements under these contracts at a rating of BBB and/or Baa2 or BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $243 million.

Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets, and would be likely to impact the cost at which it does so.

~~On May 12, 2016, Fitch Ratings, Inc. (Fitch) downgraded the senior unsecured long-term debt rating of the Company to BBB+ from A- and revised the ratings outlook from negative to stable.~~

~~On January 10, 2017, S&P revised its consolidated credit rating outlook for Southern Company (including the Company) from negative to stable.~~

~~On February 6, 2017, Moody's placed the Company on a ratings review for potential downgrade. The Company's current rating for unsecured debt is Baa3.~~

~~Market Price Risk~~

Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques that include, but are not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

To mitigate future exposure to a change in interest rates, the Company may enter into derivatives that have been designated as hedges. The weighted average interest rate on $891 million of long-term variable interest rate exposure at December 31, 2016 was 2.17%. If the Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $9 million at January 1, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 10 to the financial statements for additional information.

To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. The Company continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. The Company had no material change in market risk exposure for the year ended December 31, 2016 when compared to the year ended December 31, 2015.

The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:

2016
Changes

2015
Changes
Fair Value
(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net $ (47 ) $ (45 )
Contracts realized or settled 29
33
Current period changes^(*)
11
(35 )
Contracts outstanding at the end of the period, assets (liabilities), net $ (7 ) $ (47 )


~~(*)~~	~~Current period changes also include the changes in fair value of new contracts entered into during the period, if any.~~

~~The net hedge volumes of energy-related derivative contracts, all of which are natural gas swaps, for the years ended December 31 were as follows:~~

2016 2015
mmBtu Volume
(in millions)
Total hedge volume 36
32

For natural gas hedges, the weighted average swap contract cost above market prices was approximately $0.19 per mmBtu as of December 31, 2016 and $1.49 per mmBtu as of December 31, 2015. There were no options outstanding as of the reporting periods presented. The costs associated with natural gas hedges are recovered through the Company's ECMs.

At December 31, 2016 and 2015, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the ECM clause.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 9 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at December 31, 2016 were as follows:

Fair Value Measurements
December 31, 2016
Total Maturity
Fair Value Year 1 Years 2&3
(in millions)
Level 1 $ —
$ —
$ —
Level 2 (7 ) (4 ) (3 )
Level 3 —
—
—
Fair value of contracts outstanding at end of period $ (7 ) $ (4 ) $ (3 )

The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 10 to the financial statements.

~~Capital Requirements and Contractual Obligations~~

Approximately $586 million will be required through December 31, 2017 to fund maturities of long-term debt, and $23 million will be required to fund maturities of short-term debt. See "Sources of Capital" herein for additional information.

The construction program of the Company is currently estimated to total $517 million for 2017, $241 million for 2018, $274 million for 2019, $305 million for 2020, and $230 million for 2021, which includes completion of the Kemper IGCC and post-in-service costs. Expenditures related to completion of the Kemper IGCC are currently estimated to be $254 million for 2017. These estimated program amounts also include capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental statutes and regulations included in these program amounts are $11 million, $5 million, $24 million, $29 million, and $58 million for 2017, 2018, 2019, 2020, and 2021, respectively. These estimated environmental expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or future state plans that would limit CO₂ emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" and "– Global Climate Issues" and – "Integrated Coal Gasification Combined Cycle" herein for additional information.

The Company also anticipates costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in the Company's ARO liabilities. These costs, which could change as the Company continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $32 million, $11 million, $6 million, $6 million, and $9 million for the years 2017, 2018, 2019, 2020, and 2021, respectively. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.

In addition, the construction program includes the development and construction of the Kemper IGCC, a first-of-a-kind technology, which may result in revised estimates during construction. The ability to control costs and avoid cost overruns during the development and construction of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, sustaining nitrogen supply, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.

~~In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the FERC.~~

Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred stock dividends, unrecognized tax benefits, pension and other post-retirement benefit plans, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 10 to the financial statements for additional information.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

~~Contractual Obligations~~

~~Contractual obligations at December 31, 2016 were as follows:~~

2017 2018-2019 2020-2021
After
2021
Total
(in millions)
Long-term debt^(a) —

Principal $ 626
$ 1,325
$ 270
$ 723
$ 2,944
Interest 98
141
100
598
937
Preferred stock dividends^(b)
2
3
3
—
8
Financial derivative obligations^(c)
6
4
—
—
10
Unrecognized tax benefits^(d)
465
—
—
—
465
Operating leases ^(e)
2
1
1
—
4
Capital leases^(f)
7
13
13
76
109
Purchase commitments —
Capital^(g)
480
508
506
—
1,494
Fuel^(h)
290
320
184
251
1,045
Long-term service agreements⁽ⁱ⁾
15
75
48
244
382
Pension and other postretirement benefits plans^(j)
7
15
—
—
22
Total $ 1,998
$ 2,405
$ 1,125
$ 1,892
$ 7,420

~~(a)~~

~~All amounts are reflected based on final maturity dates except for amounts related to certain pollution control revenue bonds.~~ Long-term debt principal for 2017 includes $40 million of pollution control revenue bonds that are classified on the balance sheet at December 31, 2016 as short-term since they are variable rate demand obligations that are supported by short-term credit facilities; however, the final maturity date is in 2028. ~~The Company plans to continue, when economically feasible, to retire higher-cost sec~~urities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).


~~(b)~~	~~Preferred stock does not mature; therefore, amounts are provided for the next five years only.~~


~~(c)~~	~~For additional information, see Notes 1 and 10 to the financial statements.~~


~~(d)~~	~~See Note 5 to the financial statements under "Unrecognized Tax Benefits" for additional information.~~


~~(e)~~	~~See Note 7 to the financial statements for additional information.~~


~~(f)~~	~~Capital lease related to a 20-year nitrogen supply agreement for the Kemper IGCC. See Note 6 to the financial statements for additional information.~~

~~(g)~~

The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. At December 31, 2016, significant purchase commitments were outstanding in connection with the construction program. These amounts exclude capital expenditures covered under long-term service agreements, which are reflected separately. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" herein for additional information. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information.

~~(h)~~

Includes commitments to purchase coal and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the ~~time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2016.~~


~~(i)~~	~~Long-term service agreements include price escalation based on inflation indices.~~

~~(j)~~

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)~~

~~Mississippi Power Company 2016 Annual Report~~

~~Cautionary Statement Regarding Forward-Looking Statements~~

The Company's 2016 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail rates, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan and postretirement benefit plans contributions, financing activities, completion of construction projects, filings with state and federal regulatory authorities, impact of the PATH Act, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, storm damage cost recovery and repairs, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

the impact of recent and future federal and state regulatory changes, including environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which the Company is subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;

~~current and future litigation, regulatory investigations, proceedings, or inquiries;~~

~~the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;~~

~~available sources and costs of fuels;~~

~~effects of inflation;~~

the ability to control costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, sustaining nitrogen supply, contractor or supplier delay, non-performance under operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC);

~~investment performance of the Company's employee and retiree benefit plans;~~

~~advances in technology;~~

~~state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;~~

~~the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;~~

actions related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's December 2015 rate order, and related legal or regulatory proceedings, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, actions relating to proposed securitization, satisfaction of requirements to utilize grants, and the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA;