South Jersey Industries (SJIIU) 8-K Index to the Notes to Financial Statements

Exhibit 99.1

Elizabethtown Gas

(A division of Pivotal Utility Holdings, Inc., a wholly-owned subsidiary

of Southern Company Gas)

Financial Statements as of December 31, 2017 and 2016

and for the Years Then Ended, and Independent Auditor’s Report

Index to the Notes to Financial Statements

		Page
Independent Auditor’s Report		3
Financial Statements
	Statements of Income	4
	Statements of Comprehensive Income	5
	Statements of Cash Flows	6
	Balance Sheets	8
	Statements of Equity	9
Notes to Financial Statements
	1.  Summary of Significant Accounting Policies	10
	2.  Retirement Benefits	16
	3.  Contingencies and Regulatory Matters	25
	4.  Income Taxes	26
	5.  Financing	28
	6.  Commitments	30
	7.  Fair Value Measurements	31
	8.  Derivatives	31
	9.  Disposition	34
	10. Affiliate Transactions	34
	11. Subsequent Events	34

2

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Stockholder of

Elizabethtown Gas

We have audited the accompanying financial statements of Elizabethtown Gas (the “Company”), which comprise the balance sheets as of December 31, 2017 and 2016 and the related statements of income, comprehensive income, cash flows, and equity for the years then ended, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design 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. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Elizabethtown Gas as of December 31, 2017 and 2016, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

March 13, 2018

3

STATEMENTS OF INCOME

Elizabethtown Gas

For the Years Ended December 31, 2017 and 2016

	2017			2016
	(in thousands)
Operating Revenues	$	304,747		$	292,699
Operating Expenses:
Cost of natural gas		135,850			132,122
Other operations and maintenance		66,574			82,599
Depreciation and amortization		27,163			25,439
Taxes other than income taxes		4,917			2,572
Total operating expenses		234,504			242,732
Operating Income		70,243			49,967
Other Income and (Expense):
Interest expense, net of amounts capitalized		(15,960	)		(14,932	)
Other income (expense), net		1,460			1,610
Total other income and (expense)		(14,500	)		(13,322	)
Earnings Before Income Taxes		55,743			36,645
Income taxes		21,926			14,751
Net Income	$	33,817		$	21,894

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

4

STATEMENTS OF COMPREHENSIVE INCOME

Elizabethtown Gas

For the Years Ended December 31, 2017 and 2016

	2017		2016
	(in thousands)
Net Income	$	33,817	$	21,894
Other comprehensive income (loss):
Pension and other postretirement benefit plans:
Benefit plan net loss, net of tax of $- and $(6,314), respectively		—		(9,142	)
Reclassification adjustment for amounts included in net income, net of tax of $- and $454, respectively
Total Other Comprehensive Loss		—		(8,485	)
Comprehensive Income	$	33,817	$	13,409

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

5

STATEMENTS OF CASH FLOWS

Elizabethtown Gas

For the Years Ended December 31, 2017 and 2016

	2017			2016
	(in thousands)
Operating Activities:
Net income	$	33,817		$	21,894
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		27,163			25,439
Deferred income taxes		33,355			7,819
Pension, postretirement, and other employee benefits		1,448			(13,083	)
Mark-to-market adjustments		10,391			(22,243	)
Other, net		(18,083	)		(17,315	)
Changes in certain current assets and liabilities —
—Receivables		(21,798	)		(16,458	)
—Inventories		(476	)		3,029
—Other current assets		(161	)		3,672
—Accrued taxes		(13,451	)		7,381
—Accounts payable		27,765			2,611
—Accrued compensation		1,604			(997	)
—Other current liabilities		(31,572	)		21,099
Net cash provided from operating activities		50,002			22,848
Investing Activities:
Property additions		(155,148	)		(117,221	)
Cost of removal, net of salvage		(2,520	)		(6,612	)
Change in construction payables, net		(2,584	)		5,542
Other investing activities		243			—
Net cash used for investing activities		(160,009	)		(118,291	)
Financing Activities:
Net borrowings from parent		100,878			51,698
Dividends to parent		(25,229	)		(23,494	)
Capital contributions from parent company		34,358			67,239
Net cash provided from financing activities		110,007			95,443
Net Change in Cash and Cash Equivalents		—			—
Cash and Cash Equivalents at Beginning of Period		—			—
Cash and Cash Equivalents at End of Period	$	—		$	—
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest, net of amounts capitalized	$	15,872		$	12,324
Income taxes		1,062			3,216
Noncash transactions — Accrued property additions at end of period		7,469			10,053

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

6

BALANCE SHEETS

Elizabethtown Gas

At December 31, 2017 and 2016

Assets	2017			2016
	(in thousands)
Receivables —
Customer accounts receivable	$	29,078		$	22,979
Unbilled revenues		35,209			24,948
Other accounts and notes receivable		6,659			1,221
Accumulated provision for uncollectible accounts		(4,904	)		(4,054	)
Materials and supplies		307			304
Natural gas for sale		20,913			20,437
Prepaid taxes		21,544			3,682
Assets from risk management activities, net of collateral		—			7,473
Regulatory assets, current		7,922			10,186
Other current assets		141			218
Total current assets		116,869			87,394
Property, Plant, and Equipment:
In service		1,290,302			1,140,213
Less: Accumulated depreciation		267,019			274,679
Plant in service, net of depreciation		1,023,283			865,534
Construction work in progress		32,052			54,994
Total property, plant, and equipment		1,055,335			920,528
Other Property and Investments:
Goodwill		126,020			126,020
Deferred Charges and Other Assets:
Regulatory assets, deferred		131,590			114,680
Other deferred charges and assets		40			919
Total deferred charges and other assets		131,630			115,599
Total Assets	$	1,429,854		$	1,249,541

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

7

BALANCE SHEETS

Elizabethtown Gas

At December 31, 2017 and 2016

Liabilities and Stockholder’s Equity	2017		2016
	(in thousands)
Current Liabilities:
Due to affiliates	$	81,903	$	55,186
Accounts payable		12,751		14,287
Customer deposits		7,299		9,686
Other accrued taxes		140		2,720
Accrued compensation		3,445		1,781
Liabilities from risk management activities, net of collateral		1,694		—
Regulatory liabilities, current		10,197		16,276
Accrued environmental remediation, current		9,700		29,000
Other current liabilities		1,506		1,530
Total current liabilities		128,635		130,466
Long-term Debt (See notes)		447,825		346,879
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		130,889		210,826
Deferred credits related to income tax		121,041		673
Other cost of removal obligations		57,819		55,873
Accrued environmental remediation, deferred		75,437		77,054
Other regulatory liabilities, deferred		456		1,583
Employee benefit obligations		18,909		20,700
Other deferred credits and liabilities		1,438		1,028
Total deferred credits and other liabilities		405,989		367,737
Total Liabilities		982,449		845,082
Stockholder’s Equity
Common stock, no par value; 12,807,111 shares authorized, issued, and outstanding		—		—
Paid-in capital		166,377		132,019
Retained earnings		281,028		272,440
Total Stockholder’s Equity		447,405		404,459
Total Liabilities and Stockholder’s Equity	$	1,429,854	$	1,249,541
Commitments and Contingent Matters (See Notes)

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

8

STATEMENTS OF EQUITY

Elizabethtown Gas

For the Years Ended December 31, 2017 and 2016

	Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Loss			Total
	(in thousands)
Balance at December 31, 2015	$	64,858	$	274,040		$	(19,961	)	$	318,937
Net income		—		21,894			—			21,894
Other comprehensive loss		—		—			(8,485	)		(8,485	)
Reclassification of accumulated other comprehensive loss to regulatory assets		—		—			28,446			28,446
Dividends to parent		—		(23,494	)		—			(23,494	)
Capital contributions from parent company		67,161		—			—			67,161
Balance at December 31, 2016	$	132,019	$	272,440		$	—		$	404,459
Net income		—		33,817			—			33,817
Dividends to parent		—		(25,229	)		—			(25,229	)
Capital contributions from parent company		34,358		—			—			34,358
Balance at December 31, 2017	$	166,377	$	281,028		$	—		$	447,405

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

9

Elizabethtown Gas

Notes to Financial Statements

December 31, 2017 and 2016

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Elizabethtown Gas (the Company) engages in the sale and distribution of natural gas to approximately 292 thousand customers in New Jersey. Elizabethtown Gas is a division of Pivotal Utility Holdings, Inc. (Pivotal Utility), which is a wholly-owned subsidiary of Southern Company Gas. On July 1, 2016, Southern Company Gas completed its previously announced merger (Merger) with The Southern Company (Southern Company) and became a wholly-owned, direct subsidiary of Southern Company.

The Company is subject to regulation by the New Jersey Board of Public Utilities (New Jersey BPU). As such, the Company’s financial statements reflect the effects of rate regulation in accordance with accounting principles generally accepted in the United States of America (GAAP) and comply with the accounting policies and practices prescribed by the New Jersey BPU. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates.

The impact of the acquisition method of accounting was not pushed down to Elizabethtown Gas and is not reflected in the financial statements included herein.

Certain prior year data presented in the financial statements has been reclassified to conform to the current year presentation used by Southern Company Gas.

Recently Issued Accounting Standards

Revenue

In 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers (ASC 606), 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 new standard 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.

Most of the Company’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term.

The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company’s financial statements. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.

The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. The adoption of ASC 606 did not result in a cumulative-effect adjustment.

Leases

In February 2016, the FASB issued Accounting Standards Update (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 and the Company will adopt the new standard effective January 1, 2019.

10

The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to fleet vehicles and real estate and where the Company is the lessee and there are no material leases where the Company is the lessor. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is not expected to have a significant impact on the Company’s balance sheet.

Other

On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit’s carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after December 15, 2019, with early adoption permitted. The Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements.

On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under Federal Energy Regulatory Commission (FERC) regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will not result in a material impact on the Company’s operating income or other income for 2016 and 2017. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.

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.

11

Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:

	2017			2016
	(in thousands)
Environmental remediation	$	87,792		$	72,482
Retiree benefit plans		32,188			35,283
Under recovered regulatory clause revenues		12,426			10,186
Other regulatory assets		7,106			6,915
Deferred credits related to income tax(*)		(121,041	)		(673	)
Other cost of removal obligations		(57,819	)		(55,873	)
Over recovered regulatory clause revenues		(10,223	)		(7,425	)
Other regulatory liabilities		(430	)		(10,434	)
Total regulatory assets (liabilities), net	$	(50,001	)	$	50,461

(*)   Includes excess deferred income tax assets/liabilities resulting from the Tax Cuts and Jobs Act that was signed into law on December 22, 2017 and became effective January 1, 2018 (Tax Reform Legislation), the recovery and amortization of which will be determined by the New Jersey BPU. See Note 3 under “Regulatory Matters” and Note 4 for additional details.

In the event that the Company’s operations are no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income 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 “Regulatory Matters” for additional information.

Revenues

The Company records revenues when goods or services are provided to customers. Those revenues are based on rates approved by the New Jersey BPU. The Company has a rate structure that includes a volumetric rate design that allows the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of natural gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers, revenues are based on actual deliveries to the end of the period.

The tariffs for the Company include weather normalization adjustments, which reduce customer bills when winter weather is colder than normal and increase customer bills when weather is warmer than normal and are included in the tariffs. These provisions, referred to as alternative revenue programs, allow for the recognition of certain revenues prior to the time such revenues are billed to customers, so long as the amounts recognized will be collected from customers within 24 months of recognition.

Concentration of Revenue

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 2% of revenues.

Cost of Natural Gas

The Company charges its customers for natural gas consumed using a natural gas cost recovery mechanism set by the New Jersey BPU, under which all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. The Company defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively.

12

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 investment tax credits (ITCs) utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented on the balance sheet.

The Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 4 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 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:

	2017		2016
	(in thousands)
Utility plant in service	$	1,170,020	$	1,056,686
Information technology equipment and software		46,885		37,124
Storage facilities		27,888		7,193
Other		45,509		39,210
Total other plant in service		120,282		83,527
Total plant in service	$	1,290,302	$	1,140,213

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.

Depreciation

Depreciation of the original cost of utility plant in service is provided using composite straight-line rates, which approximated 2.6% and 2.3% in 2017 and 2016, respectively. Depreciation studies are conducted periodically to update the composite rate that is approved by the New Jersey BPU. When property subject to composite 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. As such, gains or losses are not recognized, they are ultimately refunded to, or recovered from, customers through future rate adjustments. Minor items of property included in the original cost of the asset are retired when the related property unit is retired.

Allowance for Funds Used During Construction (AFUDC)

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 asset through a higher rate base and higher depreciation. All current construction costs are included in rates. The Company’s AFUDC composite rate was 1.56% and 1.68% for the years ended 2017 and 2016, respectively. The Company recorded $0.4 million and $0.3 million of AFUDC for the years ended December 31, 2017 and 2016, respectively.

Goodwill

Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. In assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine that it is more likely than not that fair value of its reporting unit exceeds its carrying value (commonly referred to as Step 0). If the Company chooses not to perform a qualitative assessment, or the result of Step 0 indicates a probable decrease in fair value of its reporting unit below its carrying value, a quantitative two-step test is performed (commonly referred to as Step 1 and Step 2). Step 1 compares the fair value of the reporting unit to its carrying value including goodwill. If the carrying value exceeds the fair value, Step 2 is performed to allocate the fair value of the reporting unit to its assets and liabilities in order to determine the implied fair value of goodwill, which is compared to the carrying value of goodwill to calculate an impairment loss, if any.

For the 2017 annual impairment test, the Company performed Step 1 of the two-step impairment test, which resulted in its fair value exceeding its carrying value. For the 2016 annual impairment test, the Company performed the qualitative Step 0 assessment and determined that it was more likely than not that its fair value exceeded its carrying value and therefore no quantitative assessment was required.

13

Cash Management Money Pool

The Company participates in Southern Company Gas’ utility money pool, under which short-term borrowings are made from the money pool and surplus funds are contributed to the money pool. Borrowings from the money pool are recorded as due to affiliates in the balance sheets and intercompany interest expense is recorded in the statements of income for these borrowings. See Note 10 for additional information.

Receivables and Provision for Uncollectible Accounts

The Company’s receivables consist primarily of natural gas sales and transportation services billed to residential, commercial, industrial, and other customers. Customers are billed monthly and payment is due within 30 days. For the majority of receivables, a provision for uncollectible accounts is established based on historical collection experience and other factors. For the remaining receivables, if the Company is aware of a specific customer’s inability to pay, a provision for uncollectible accounts is recorded to reduce the receivable balance to the amount the Company reasonably expects to collect. If circumstances change, the estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect this estimate include, but are not limited to, customer credit issues, customer deposits, and general economic conditions. Customers’ accounts are written off once they are deemed to be uncollectible.

Materials and Supplies

Generally, materials and supplies include propane gas inventory, fleet fuel, and other materials and supplies. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.

Natural Gas for Sale

The Company’s natural gas inventories are carried at cost on a weighted average cost of gas basis.

Fair Value Measurements

The Company has financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include derivative instruments. The carrying values of receivables, accounts payable, due to affiliates, other current assets and liabilities, accrued interest, and long-term debt approximate their respective fair value. The nonfinancial assets and liabilities include pension and other postretirement benefits. See Notes 2 and 7 for additional fair value disclosures.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements to utilize the best available information. Accordingly, the Company uses valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Fair value balances are classified based on the observance of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows:

Level 1

Quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company’s Level 1 items consist of exchange-traded derivatives, money market funds, and certain retirement plan assets.

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Level 2

Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Market price data is obtained from multiple sources in order to value certain Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Level 2 instruments include non-exchange-traded derivatives such as over-the-counter forwards and options and certain retirement plan assets.

Level 3

Pricing inputs include significant unobservable inputs that may be used with internally developed methodologies to determine management’s best estimate of fair value from the perspective of market participants. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. Level 3 assets, liabilities, and any applicable transfers are primarily related to the Company’s pension and other postretirement benefit plan assets as described in Note 2. Transfers into and out of Level 3 are determined using values at the end of the interim period in which the transfer occurred.

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in natural gas prices. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (shown separately as “Risk Management Activities”) and are measured at fair value. See Note 7 for additional information regarding fair value. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the respective state regulatory agency approved fuel-hedging programs result in the deferral of related gains and losses in other comprehensive income (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. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 8 for additional information regarding derivatives.

The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. The Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017.

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. In 2017, comprehensive income was equal to net income. In 2016, comprehensive income consisted of net income, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income.

Dividend Distributions

The Company paid dividends of $25.2 million and $23.5 million to Southern Company Gas during 2017 and 2016, respectively. The Company is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to Southern Company Gas to the extent of 70% of its quarterly net income.

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2. RETIREMENT BENEFITS

The Company participates in the Southern Company Gas qualified defined benefit, trusteed, pension plan covering most eligible employees, which was closed in 2012 to new employees and reopened to all non-union employees on January 1, 2018. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of the Company’s management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. The Company also participates in the Southern Company Gas postretirement benefit plan, which provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan.

In connection with the Merger, Southern Company Gas performed updated valuations of its pension and other postretirement benefit plan assets and obligations to reflect actual census data at the new measurement date of July 1, 2016. The Company also recorded a related regulatory asset of $47.5 million as of July 1, 2016 related to unrecognized prior service cost and actuarial gain/loss, as it is probable that this amount will be recovered through future rates for the Company.

The following discussions reflect the Company’s balances and activity under the multiple-employer method of accounting.

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 all periods presented and the benefit obligations as of the measurement date are presented below.

Assumptions used to determine net periodic costs:	Year Ended December 31, 2017			July 1, 2016 through December 31, 2016			January 1, 2016 through June 30, 2016
Pension plans
Discount rate - interest costs		3.76	%		3.21	%		4.00	%
Discount rate - service costs		4.64			4.07			4.80
Expected long-term return on plan assets		7.60			7.75			7.80
Annual salary increase		3.50			3.50			3.70
Other postretirement benefit plans
Discount rate - interest costs		3.40	%		2.84	%		3.60	%
Discount rate - service costs		4.55			3.96			4.70
Expected long-term return on plan assets		6.03			5.93			6.60
Annual salary increase		3.50			3.50			3.70

Assumptions used to determine benefit obligations:	December 31, 2017			December 31, 2016
Pension plans
Discount rate		3.74	%		4.39	%
Annual salary increase		2.88			3.50
Other postretirement benefit plans
Discount rate		3.62	%		4.15	%
Annual salary increase		2.56			3.50

The Company estimates the expected return on pension plan and other postretirement benefit plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing, and historical performance. The Company also considers guidance from its investment advisors in making a final determination of its expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater or less than the assumed rate, it does not affect that year’s annual pension or other postretirement benefit plan cost; rather, this gain or loss reduces or increases future pension or other postretirement benefit plan costs.

16

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, 2017 were as follows:

	Initial Cost TrendRate			Ultimate CostTrend Rate			Year ThatUltimate Rate isReached
Pre-65		6.40	%		4.50	%		2038
Post-65 medical		7.80			4.50			2038
Post-65 prescription		7.80			4.50			2038

An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO; however, the impact on the service and interest cost components would be immaterial.

Pension Plans

The total accumulated benefit obligation for the pension plans was $95.4 million at December 31, 2017 and $85.7 million at December 31, 2016. Changes in the projected benefit obligations and the fair value of plan assets for the Company’s qualified pension plans for all periods presented were as follows:

	Year EndedDecember 31, 2017			July 1, 2016 throughDecember 31, 2016			January 1, 2016through June 30, 2016
	(in thousands)
Change in benefit obligation
Benefit obligation at beginning of period	$	94,963		$	105,458		$	90,910
Service cost		1,393			990			861
Interest cost		4,383			2,044			2,238
Benefits paid		(10,407	)		(3,592	)		(3,338	)
Actuarial (gain) loss		15,175			(9,937	)		14,787
Balance at end of period		105,507			94,963			105,458
Change in plan assets
Fair value of plan assets at beginning of period		74,849			60,687			61,044
Actual return on plan assets		20,986			3,706			2,981
Employer contributions		—			14,048			—
Benefits paid		(10,407	)		(3,592	)		(3,338	)
Fair value of plan assets at end of period		85,428			74,849			60,687
Accrued liability	$	20,079		$	20,114		$	44,771

At December 31, 2017, the projected benefit obligations for the qualified and non-qualified pension plans were $105.5 million and $1.1 million, respectively. All pension plan assets are related to the qualified pension plan.

Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company’s pension plans consist of the following:

	2017			2016
	(in thousands)
Other regulatory assets, deferred	$	28,176		$	30,484
Employee benefit obligations		(20,079	)		(20,114	)

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Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2017 and 2016 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 2018.

	Amount Subject toRegulatory Amortization		Prior ServiceCosts			Net (Gain)Loss
	(in thousands)
Balance at December 31, 2017:
Regulatory assets (liabilities)	$	38,584	$	(89	)	$	(10,319	)
Balance at December 31, 2016:
Regulatory assets (liabilities)	$	—	$	(2,000	)	$	32,484
Estimated amortization in net periodic cost in 2018:
Regulatory assets	$	2,691	$	10		$	—

The components of OCI, and the changes in the balance of regulatory assets (liabilities), related to the defined benefit pension plans for all years presented were as follows:

	Accumulated OCI			Regulatory Assets
	(in thousands)
Balance at December 31, 2015:	$	27,789		$	—
Net (gain) loss		15,216			(9,816	)
Reclassification adjustments:
Amortization of prior service costs		434			434
Amortization of net loss		(1,396	)		(2,177	)
Reclassification from accumulated OCI to regulatory assets		(42,043	)		42,043
Total reclassification adjustments		(43,005	)		40,300
Total change		(27,789	)		30,484
Balance at December 31, 2016:	$	—		$	30,484
Net (gain) loss		—			(149	)
Reclassification adjustments:
Amortization of prior service costs		—			424
Amortization of net loss		—			(1,427	)
Amortization of regulatory assets		—			(1,156	)
Total reclassification adjustments		—			(2,159	)
Total change		—			(2,308	)
Balance at December 31, 2017:	$	—		$	28,176

The Company’s pro rata components of Southern Company Gas’ net periodic pension costs for the years ended December 31, 2017 and 2016 were as follows:

	2017			2016
	(in thousands)
Service cost	$	1,393		$	1,851
Interest cost		4,383			4,282
Expected return on plan assets		(6,534	)		(6,249	)
Amortization of regulatory assets		1,156			—
Amortization:
Prior service costs		(424	)		(868	)
Net loss		1,427			3,573
Net periodic pension cost	$	1,401		$	2,589

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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.

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, 2017, estimated benefit payments were as follows:

	Benefit Payments
	(in thousands)
2018	$	7,244
2019		7,006
2020		7,382
2021		7,041
2022		6,890
2023 to 2027		32,623

Other Postretirement Benefits

Changes in the APBO and the fair value of plan assets for all periods presented were as follows:

	Year EndedDecember 31, 2017			July 1, 2016 throughDecember 31, 2016			January 1, 2016through June 30, 2016
	(in thousands)
Change in benefit obligation
Benefit obligation at beginning of period	$	12,317		$	13,174		$	13,512
Service cost		100			55			47
Interest cost		416			187			218
Benefits paid		(843	)		(293	)		(438	)
Actuarial (gain) loss		1,424			(806	)		(165	)
Benefit obligation at end of period		13,414			12,317			13,174
Change in plan assets
Fair value of plan assets at beginning of period		13,177			12,829			12,737
Actual return on plan assets		2,489			348			92
Employer contributions		843			293			438
Benefits paid		(843	)		(293	)		(438	)
Fair value of plan assets at end of period		15,666			13,177			12,829
(Prepaid asset) accrued liability	$	(2,252	)	$	(860	)	$	345

Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company’s other postretirement benefit plans consist of the following:

	2017		2016
	(in thousands)
Other regulatory assets, deferred	$	4,012	$	4,361
Employee benefit obligations		2,252		860

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Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2017 and 2016 related to 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 2018 is immaterial.

	Amount Subject toRegulatory Amortization		Prior Service Costs		Net (Gain) Loss
	(in thousands)
Balance at December 31, 2017:
Regulatory assets (liabilities)	$	5,285	$	395	$	(1,668	)
Balance at December 31, 2016:
Regulatory assets	$	—	$	—	$	4,361

The components of OCI, along with the changes in the balance of regulatory assets (liabilities), related to the other postretirement benefit plans for all years presented were as follows:

	Accumulated OCI			Regulatory Assets
	(in thousands)
Balance at December 31, 2015:	$	5,548		$	—
Net (gain) loss		90			(933	)
Reclassification adjustments:
Amortization of prior service costs		(1	)		(1	)
Amortization of net loss		(137	)		(205	)
Reclassification from accumulated OCI to regulatory assets		(5,500	)		5,500
Total reclassification adjustments		(5,638	)		5,294
Total change		(5,548	)		4,361
Balance at December 31, 2016:	$	—		$	4,361
Net (gain) loss		—			53
Reclassification adjustments:
Amortization of net loss		—			(149	)
Amortization of regulatory assets		—			(253	)
Total reclassification adjustments		—			(402	)
Total change		—			(349	)
Balance at December 31, 2017:	$	—		$	4,012

The Company’s pro rata components of Southern Company Gas’ other postretirement benefit plans’ net periodic cost for the years ended December 31, 2017 and 2016 were as follows:

	2017			2016
	(in thousands)
Service cost	$	100		$	102
Interest cost		416			405
Expected return on plan assets		(655	)		(673	)
Amortization of regulatory assets		253			—
Amortization:
Prior service costs		—			2
Net loss		149			342
Net periodic pension cost	$	263		$	178

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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. At December 31, 2017, estimated benefit payments were as follows:

	Benefit Payments
	(in thousands)
2018	$	748
2019		797
2020		829
2021		864
2022		890
2023 to 2027		4,295

Benefit Plan Assets

Southern Company Gas’ 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 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. Southern Company Gas minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.

The composition of Southern Company Gas’ pension plan and other postretirement benefit plan assets as of December 31, 2017 and 2016, along with the targets for each plan, is presented below:

	Target			2017			2016
Pension plan assets:
Equity		53	%		65	%		69	%
Fixed Income		15			19			20
Cash		2			6			1
Other		30			10			10
Total		100	%		100	%		100	%
Other postretirement benefit plan assets:
Equity		72	%		76	%		74	%
Fixed Income		24			20			23
Cash		1			2			1
Other		3			2			2
Total		100	%		100	%		100	%

The investment strategy for plan assets related to Southern Company Gas’ 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, Southern Company Gas employs a formal rebalancing program for its pension plan assets. To manage the actual asset class exposures relative to the target asset allocation, Southern Company Gas employs a formal rebalancing program for its pension plan assets. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.

21

Investment Strategies

Detailed below is a description of the investment strategies for each major asset category for the Southern Company Gas 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.

• 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.

The investment strategies prior to July 1, 2016 followed a policy to preserve the plans’ capital and maximize investment earnings in excess of inflation within acceptable levels of capital market volatility. To accomplish this goal, the plans’ assets were managed to optimize long-term return while maintaining a high standard of portfolio quality and diversification. In developing the allocation policy for the assets of the pension and other postretirement benefit plans, Southern Company Gas examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, the risk and return trade-offs of alternative asset classes and asset mixes were evaluated given long-term historical relationships as well as prospective capital market returns. Southern Company Gas also conducted asset-liability studies to match projected asset growth with projected liability growth to determine whether there is sufficient liquidity for projected benefit payments. Asset mix guidelines were developed by incorporating the results of these analyses with an assessment of Southern Company Gas’ risk posture, and taking into account industry practices. Southern Company Gas periodically evaluated its investment strategy to ensure that plan assets were sufficient to meet the benefit obligations of the plans. As part of the ongoing evaluation, the Company made changes to its targeted asset allocations and investment strategy.

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, 2017 and 2016. 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. Management believes the portfolio is well-diversified with no significant concentrations of risk.

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.

• Real estate investments and private equity. 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.

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The Company’s pro rata portion of fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Absolute return investment assets are presented in the tables below based on the nature of the investment.

	Fair Value Measurements Using
	Quoted Pricesin Active Marketsfor IdenticalAssets		Significant OtherObservableInputs		Net Asset Valueas a PracticalExpedient
As of December 31, 2017	(Level 1)		(Level 2)		(NAV)		Total
	(in thousands)
Assets:
Domestic equity(*)	$	13,978	$	29,196	$	—	$	43,174
International equity(*)		—		14,988		—		14,988
Fixed income:
U.S. Treasury, government, and agency bonds		—		7,710		—		7,710
Corporate bonds		—		3,554		—		3,554
Cash equivalents and other		7,574		2,251		4,379		14,204
Real estate investments		288		—		1,399		1,687
Private equity		—		—		111		111
Total	$	21,840	$	57,699	$	5,889	$	85,428

(*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

	Fair Value Measurements Using
	Quoted Pricesin Active Marketsfor IdenticalAssets		Significant Other ObservableInputs		Net Asset Valueas a PracticalExpedient
As of December 31, 2016	(Level 1)		(Level 2)		(NAV)		Total
	(in thousands)
Assets:
Domestic equity(*)	$	10,800	$	26,103	$	—	$	36,903
International equity(*)		—		14,117		—		14,117
Fixed income:
U.S. Treasury, government, and agency bonds		—		6,482		—		6,482
Corporate bonds		—		3,099		—		3,099
Pooled funds		—		5,039		—		5,039
Cash equivalents and other		931		375		6,328		7,634
Real estate investments		275		—		1,110		1,385
Private equity		—		—		190		190
Total	$	12,006	$	55,215	$	7,628	$	74,849

(*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

23

The Company’s pro rata portion of fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.

	Fair Value Measurements Using
	Quoted Pricesin Active Marketsfor IdenticalAssets		Significant OtherObservableInputs		Net Asset Valueas a PracticalExpedient
As of December 31, 2017	(Level 1)		(Level 2)		(NAV)		Total
	(in thousands)
Assets:
Domestic equity(*)	$	370	$	8,811	$	—	$	9,181
International equity(*)		—		2,858		—		2,858
Fixed income:
U.S. Treasury, government, and agency bonds		—		70		—		70
Corporate bonds		—		29		—		29
Pooled funds		—		3,053		—		3,053
Cash equivalents and other		289		—		133		422
Real estate investments		8		—		42		50
Private equity		—		—		3		3
Total	$	667	$	14,821	$	178	$	15,666

(*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

	Fair Value Measurements Using
	Quoted Pricesin Active Marketsfor IdenticalAssets		Significant OtherObservableInputs		Net Asset Valueas a PracticalExpedient
As of December 31, 2016	(Level 1)		(Level 2)		(NAV)		Total
	(in thousands)
Assets:
Domestic equity(*)	$	315	$	7,264	$	—	$	7,579
International equity(*)		—		2,206		—		2,206
Fixed income:
U.S. Treasury, government, and agency bonds		—		63		—		63
Corporate bonds		—		28		—		28
Pooled funds		—		2,942		—		2,942
Cash equivalents and other		99		—		209		308
Real estate investments		8		—		37		45
Private equity		—		—		6		6
Total	$	422	$	12,503	$	252	$	13,177

(*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.

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Employee Savings Plan

Southern Company Services, Inc. sponsors 401(k) defined contribution plans covering certain eligible employees. Through December 31, 2017, the 401(k) plans provided matching contributions of either 65% on up to 8% of an employee’s eligible compensation, or a 100% matching contribution on up to 3% of an employee’s eligible compensation, followed by a 75% matching contribution on up to the next 3% of an employee’s eligible compensation. Total matching contributions made to the 401(k) plans for each of the years ended December 31, 2017 and 2016 were $1.2 million.

For employees not accruing a benefit under the pension plan, additional contributions made to the 401(k) plans for the years ended December 31, 2017 and 2016 were immaterial.

Effective January 1, 2018, the 401(k) plans were merged into the Southern Company Employee Savings Plan, which is a defined contribution plan covering substantially all employees of the Company. Under this plan, Southern Company Gas matches a portion of the first 6% of employee base salary contributions. The maximum Company match is 5.1% of an employee’s base salary.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is assessing its alleged involvement in an incident that occurred in its service territory that resulted in several deaths, injuries, and property damage. The Company has been named as one of the defendants in several lawsuits related to this incident. At December 31, 2017, the Company has reserved for all of its potential exposure from this case. 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. The ultimate outcome of these matters and such pending or potential litigation against the Company cannot be determined 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.

Environmental Matters

The Company’s operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Company maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations impact future results of operations, cash flows, and financial condition. Compliance costs may result from the installation of additional environmental controls. Compliance with these environmental requirements involves significant capital and operating costs to clean up affected sites. The Company conducts studies to determine the extent of any required clean up and has recognized in its financial statements the costs to clean up known impacted sites. The Company has received authority from the New Jersey BPU to recover approved environmental compliance costs through regulatory mechanisms.

The Company is subject to environmental remediation liabilities associated with six former manufactured gas plant sites in New Jersey. Accrued environmental remediation costs of $85.1 million and $106.1 million have been recorded in the balance sheets as of December 31, 2017 and December 31, 2016, respectively. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the New Jersey BPU.

The Company’s ultimate environmental compliance strategy and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations and the outcome of any legal challenges to the environmental rules. The ultimate outcome of these matters cannot be determined at this time.

Regulatory Matters

The Merger was approved by the New Jersey BPU on June 29, 2016. In connection with the Merger approval order, the Company was required to:

• provide rate credits of $17.5 million to its customers; and

• file a rate case no later than September 1, 2016, with another rate case no later than three years after the 2016 rate case.

25

The rate credits to customers were paid during the third quarter of 2016 and the Company filed a general base rate case with the New Jersey BPU on September 1, 2016. See “Customer Refunds” and “Base Rate Case” herein for additional information.

Regulatory Infrastructure Program

The Company’s 2013 extension of the Aging Infrastructure Replacement (AIR) enhanced infrastructure program allowed for infrastructure investment of $115 million over four years and was focused on the replacement of aging cast iron in its pipeline system. Carrying charges on the additional capital spend are being accrued and deferred for regulatory purposes at a weighted average cost of capital of 6.65%. Effective July 1, 2017, investments under this program, which ended September 30, 2017, are being recovered through base rate revenues. See “Base Rate Case” herein for additional information.

In 2015, the Company filed the Safety, Modernization and Reliability Tariff plan with the New Jersey BPU seeking approval to invest more than $1.1 billion to replace 630 miles of vintage cast iron, steel, and copper pipeline, as well as 240 regulator stations. During the first quarter 2018, the Company withdrew this filing in response to a proposed rule by the New Jersey BPU to incentivize utilities to accelerate investment in infrastructure replacement programs that enhance reliability, resiliency, and/or safety of the distribution system. The ultimate outcome of this matter cannot be determined at this time.

Base Rate Case

On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See Note 9 for information on the proposed sale of the Company.

Other

The New Jersey BPU issued an order effective January 1, 2018 that requires the Company to track as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes. The Company made the required filing on March 2, 2018 seeking to reduce annual rates by $10.9 million with an April 1, 2018 interim effective date and final rates that are anticipated to take effect July 1, 2018. Credits will be issued to customers for the impact of the Tax Reform Legislation from January 2018 through March 2018.

Unrecognized Ratemaking Amounts

The following table illustrates the Company’s 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 the Company’s AIR program. These amounts will be recognized as revenues in the Company’s financial statements in the periods they are billable to customers. See Note 9 for information on the proposed sale of the Company.

	(in thousands)
December 31, 2017	$	7,229
December 31, 2016		5,535

Customer Refunds

In the third quarter 2016, the Company provided direct per-customer rate credits totaling $17.5 million to its customers in accordance with the Merger approval from the New Jersey BPU. These rate credits were allocated among the Company’s customer classes based on the base rate revenues reflected in the rates that resulted from its most recent base rate proceeding.

4. INCOME TAXES

Subsequent to the Merger, Southern Company files a consolidated federal income tax return and various combined and separate state income tax returns on behalf of the Company and Southern Company Gas. 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 Internal Revenue Service (IRS) regulations, the Company is jointly and severally liable for the federal tax liability. Prior to the Merger, the Company was a part of Southern Company Gas’ U.S. federal consolidated income tax return and various state income tax returns.

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Federal Tax Reform Legislation

Following the enactment of the Tax Reform Legislation, the Securities and Exchange Commission staff issued Staff Accounting Bulletin 118 - “Income Tax Accounting Implications of the Tax Cuts and Jobs Act” (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be “provisional” as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time.

Current and Deferred Income Taxes

Details of income tax provisions are as follows:

	2017			2016
	(in thousands)
Federal —
Current	$	(10,363	)	$	5,630
Deferred		29,339			6,661
		18,976			12,291
State —
Current		(1,066	)		1,302
Deferred		4,102			1,277
		3,036			2,579
Amortization of investment tax credits		(86	)		(119	)
Total	$	21,926		$	14,751

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:

	2017		2016
	(in thousands)
Deferred tax liabilities —
Accelerated depreciation	$	163,965	$	208,605
Property basis differences		16,961		23,262
Regulatory assets associated with employee benefit obligations		9,656		15,525
Other		5,816		7,558
Total		196,398		254,950
Deferred tax assets —
Federal net operating loss		5,829		8,275
Federal effect of state deferred taxes		8,296		12,426
Employee benefit obligations		10,275		15,566
Regulatory liability associated with the Tax Reform Legislation		34,858		—
Bad debt and insurance reserves		1,555		1,936
Other		4,696		5,921
Total		65,509		44,124
Accumulated deferred income taxes, net	$	130,889	$	210,826

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The implementation of the Tax Reform Legislation significantly reduced accumulated deferred income taxes, partially offset by bonus depreciation provisions in the Protecting Americans from Tax Hikes Act. The Tax Reform Legislation also significantly increased tax-related regulatory liabilities.

At December 31, 2017, the tax-related regulatory liabilities to be credited to customers were $121.0 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs.

Deferred federal and state 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 amounted to $0.1 million for each of the years ended December 31, 2017 and 2016. At December 31, 2017, 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:

	Years Ended December 31,
	2017			2016
Federal statutory rate		35.0	%		35.0	%
State income tax, net of federal deduction		5.9			5.9
Other		(1.6	)		(0.6	)
Effective income tax rate		39.3	%		40.3	%

Unrecognized Tax Benefits

The Company has no unrecognized tax benefits for any year presented.

The Company classifies interest on tax uncertainties as interest expense; however, the Company had no 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. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

Southern Company is a participant in the Compliance Assurance Process of the IRS. The IRS has finalized its audits of  Southern Company’s consolidated federal tax returns through 2016. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. The audits for Southern Company Gas by any state have either concluded, or the statute of limitations has expired with respect to income tax examinations, for years prior to 2011.

5. FINANCING

The following table provides maturity dates, year-to-date weighted average interest rates, and amounts outstanding for various debt securities and facilities that are included in the balance sheets.

			December 31, 2017						December 31, 2016
(Dollars in thousands)	Year(s) due		Weightedaverage interestrate			Outstanding			Weighted averageinterest rate			Outstanding
Gas facility revenue bonds		2022-2033		1.7	%	$	180,100			1.3	%	$	180,100
Affiliate promissory note		2034		4.5	%		268,406			7.2	%		167,528
Total principal long-term debt				3.4	%	$	448,506			4.1	%	$	347,628
Unamortized debt issuance costs				n/a		$	(681	)		n/a		$	(749	)
Total debt				n/a		$	447,825			n/a			346,879

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Gas Facility Revenue Bonds

The Company is party to a series of loan agreements with the New Jersey Economic Development Authority under which, a series of gas facility revenue bonds have been issued. These revenue bonds are issued by state agencies to investors, and proceeds from each issuance then are loaned to the Company. Southern Company Gas fully and unconditionally guarantees all of the Company’s gas facility revenue bonds.

The Company’s asset sale agreement requires that the gas facility revenue bonds, which are currently eligible for redemption at par, be redeemed on or prior to consummation of the sale. The ultimate outcome of this matter cannot be determined at this time. See Note 9 for information on the proposed sale of the Company.

Affiliate Promissory Note

Pivotal Utility entered into a promissory note with Southern Company Gas (Affiliate Promissory Note) for the purpose of refinancing its short-term debt and recapitalizing the capital structure of Pivotal Utility and those of its utility operating divisions including the Company’s, in accordance with the target capitalization of 47% and with authorization of the New Jersey BPU. The Affiliate Promissory Note is adjusted periodically to maintain the appropriate targeted capitalization percentages and, during 2017, $100.9 million was converted to the Affiliate Promissory Note and $34.4 million was converted to equity. The Affiliate Promissory Note is due December 31, 2034 and had an initial interest rate at December 31, 2004 of 6.3%, which adjusts on a periodic basis based upon weighted average costs and expenses of borrowing the then-outstanding long-term debt of both Southern Company Gas and Southern Company Gas Capital Corporation, a 100%-owned financing subsidiary of Southern Company Gas. As of December 31, 2017, the effective interest rate on this note was 4.5% which consists of two components. The first is incurred equal to the weighted average costs that is applied to the principal amount of the Affiliate Promissory Note. The second component is an adjustment to increase the effective interest incurred on long-term debt other than the Affiliate Promissory Note to the weighted average cost applicable to the Affiliate Promissory Note.

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6. COMMITMENTS

Pipeline Charges, Storage Capacity, and Gas Supply

Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to marketers of natural gas as well as demand charges associated with Sequent Energy Management, L.P. (Sequent), a wholly-owned subsidiary of Southern Company Gas that engages in wholesale marketing of natural gas supply services.

Contractual Obligations

Contractual obligations at December 31, 2017 were as follows:

	2018			2019-2020		2021-2022	After 2022		Total
	(in thousands)
Long-term debt(a) _
Principal	$	—	$	—	$	46,500	$	401,325		447,825
Interest		3,082		6,165		6,165		19,538		34,950
Pipeline charges, storage capacity, and gas supply(b)		57,278		112,079		78,698		264,754		512,809
Operating leases(c)		4,046		8,181		5,660		—		17,887
Asset management agreements(d)		4,250		2,125		—		—		6,375
Financial derivative obligations(e)		1,694		312		—		—		2,006
Other purchase commitments(f)		7,000		—		—		—		7,000
Total	$	77,350	$	128,862	$	137,023	$	685,617	$	1,028,852

(a) Amounts are reflected based on final maturity dates. 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 at December 31, 2017 and do not include interest on the affiliated promissory note.

(b) Includes charges recoverable through a natural gas cost recovery mechanism, subject to review by the New Jersey BPU.

(c) Certain operating leases have provisions for step rent or escalation payments and certain lease concessions are accounted for by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms. However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein. In terms of rental charges and duration of contracts, the Company’s most significant operating leases relate to real estate and fleet vehicles.

(d) Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements.

(e) See Notes 1 and 9 for additional information.

(f) Includes contractual environmental remediation liabilities that are generally recoverable through base rates or rate rider mechanisms.

Indemnities

In certain instances, the Company has undertaken to indemnify current property owners and others against costs associated with the effects and/or remediation of contaminated sites for which it may be responsible under applicable federal or state environmental laws, generally with no limitation as to the amount. These indemnifications relate primarily to ongoing coal tar cleanup. See Note 3 under “Environmental Matters” for additional information. The Company believes that the likelihood of payment under its other environmental indemnifications is remote. No liability has been recorded for such indemnifications as the fair value was inconsequential at inception.

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7. 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. See Note 1 under “Fair Value Measurements” for additional information on the fair value hierarchy.

As of December 31, 2017, liabilities measured at fair value on a recurring basis during the year, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using
	Quoted Pricesin ActiveMarkets forIdentical Assets(Level 1)		SignificantOtherObservableInputs(Level 2)		SignificantUnobservableInputs(Level 3)		Net Asset Valueas a PracticalExpedient(NAV)		Total
	(in thousands)
Liabilities:
Energy-related derivatives	$	—	$	2,006	$	—	$	—	$	2,006

As of December 31, 2016, assets measured at fair value on a recurring basis during the year, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using
	Quoted Pricesin ActiveMarkets forIdentical Assets(Level 1)		SignificantOtherObservableInputs(Level 2)		SignificantUnobservableInputs(Level 3)		Net Asset Valueas a PracticalExpedient(NAV)		Total
Assets:
Energy-related derivatives	$	—	$	8,385	$	—	$	—	$	8,385

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and non-exchange-traded derivatives such as over-the-counter forwards and options. 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 and implied volatility. See Note 8 for additional information on how these derivatives are used.

8. DERIVATIVES

The Company is exposed to market risks, primarily commodity price risk, interest rate risk, and weather 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 7 for additional information. In the statements of cash flows, the cash impacts of settled energy-related are recorded as operating activities.

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Energy-Related Derivatives

The Company enters into energy-related derivatives to hedge exposures to natural 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 prices of natural gas. The Company manages fuel-hedging programs, implemented per the guidelines of the New Jersey BPU, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility.

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 the cost of natural gas as the underlying natural gas is used in operations and ultimately recovered through cost recovery clauses.

• 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 in the period of change.

At December 31, 2017, the net volume of energy-related derivative contracts for natural gas positions totaled 18 billion cubic feet for the Company, together with the longest hedge date of 2019 over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions.

Derivative Financial Statement Presentation and Amounts

The derivative contracts of the Company are subject to master netting arrangements or similar agreements and are reported net in the financial statements. Some of these energy-related derivative contracts 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, 2017 and 2016, the fair value of energy-related derivatives was reflected in the balance sheets as follows:

		Asset Derivatives					Liability Derivatives
DerivativeCategory	Balance SheetLocation	2017		2016		Balance SheetLocation	2017		2016
		(in thousands)					(in thousands)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities – current		$	—	$	7,473	Liabilities from risk management activities – current	$	1,694	$	—
Other deferred charges and assets			—		912	Other deferred credits and liabilities		312		—
Total derivatives designated as hedging instruments for regulatory purposes		$	—	$	8,385		$	2,006	$	—
Gross amounts of recognized		$	—	$	8,385		$	2,006	$	—
Gross amounts offset		$	—	$	—		$	—	$	—
Net amounts recognized in the Balance Sheets		$	—	$	8,385		$	2,006	$	—

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At December 31, 2017 and 2016, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

		Unrealized Losses						Unrealized Gains
DerivativeCategory	Balance SheetLocation	2017			2016		Balance SheetLocation	2017		2016
		(in thousands)						(in thousands)
Energy-related derivatives:
Other regulatory assets, current		$	(1,694	)	$	—	Other regulatory liabilities, current	$	—	$	7,473
Other regulatory assets, deferred			(312	)		—	Other regulatory liabilities, deferred		—		912
Total energy-related derivative gains (losses)		$	(2,006	)	$	—		$	—	$	8,385

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 a credit rating change below BBB- and/or Baa3. At December 31, 2017, the Company had no collateral posted with derivative counterparties to satisfy these arrangements.

At December 31, 2017, the fair value of derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features were immaterial.

Generally, collateral may be provided by a 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 Investors Service Inc. and S&P Global Ratings 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 its exposure to counterparty credit risk.

The Company also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When the Company is engaged in more than one outstanding derivative transaction with the same counterparty and it 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 the Company’s credit risk. The Company also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable the Company to net certain assets and liabilities by counterparty. The Company also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. The Company may require counterparties to pledge additional collateral when deemed necessary. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

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9. DISPOSITION

On October 15, 2017, Pivotal Utility entered into an agreement for the sale of the Company’s assets to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. The completion of the asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, and the New Jersey BPU. Pivotal Utility and South Jersey Industries, Inc. made a joint filing on December 22, 2017 with the New Jersey BPU requesting regulatory approval. The asset sale is expected to be completed by the end of the third quarter 2018.

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

10. AFFILIATE TRANSACTIONS

The Company has agreements with Sequent for transportation and storage capacity to meet natural gas demands. The following table provides additional information on the Company’s asset management agreements with Sequent.

				Profit sharing / fees payments
Expiration date	Type of fee structure	Annual fee		2017		2016
				(in thousands)
March 2019	Tiered		(*)	$	11,195	$	15,043

(*) In March 2014, the New Jersey BPU authorized the renewal of the asset management agreement between Elizabethtown Gas and Sequent for five years. This renewed agreement began on April 1, 2014 and requires Sequent to pay minimum annual fees of $4.25 million to Elizabethtown Gas and includes tiered margin sharing levels between Elizabethtown Gas and Sequent.

Upon consummation of the asset sale of Elizabethtown Gas, South Jersey Industries, Inc. will assume the asset management agreements of Elizabethtown Gas. See Note 9 for information on the proposed sale of the Company.

Amounts Due to Affiliates

The Company had $81.9 million and $55.2 million in payable at December 31, 2017 and 2016, respectively, which was due to Southern Company Gas, primarily related to the participation in the Southern Company Gas money pool. The Company also had $268.4 million and $167.5 million outstanding at December 31, 2017 and 2016, respectively, related to a promissory note with Southern Company Gas. See Note 5 for additional information on the Affiliate Promissory Note.

The Company is covered by Southern Company Gas’ agreement with Southern Company Services, Inc. under which various services are currently being rendered to the Company as direct or allocated cost. Additionally, the Company engages in transactions with Southern Company Gas’ affiliates consistent with its services and tax allocation agreements.

11. SUBSEQUENT EVENTS

Management evaluated subsequent events for potential recognition and disclosure through March 13, 2018, the date these financial statements were available to be issued, and determined that, except for the Company’s withdrawal of its Safety, Modernization and Reliability Tariff filing as discussed in Note 3 under “Regulatory Infrastructure Programs” and the Company’s filing with the New Jersey BPU for reduced annual rate base in response to the Tax Reform Legislation as discussed in Note 3 under “Other,” no significant events have occurred subsequent to period end.

34

Elizabethtown Gas

(A division of Pivotal Utility Holdings, Inc., a wholly-owned

subsidiary of Southern Company Gas)

Financial Statements as of December 31, 2016 and 2015

and for the years then ended, and Independent Auditors’ Report

Index to the Notes to Financial Statements

		Page
Independent Auditor’s Report		4
Financial Statements
	Statements of Income	5
	Statements of Comprehensive Income	5
	Statements of Cash Flows	6
	Balance Sheets	7
	Statements of Equity	9
Notes to Financial Statements
	1.  Summary of Significant Accounting Policies	10
	2.  Retirement Benefits	16
	3.  Contingencies and Regulatory Matters	26
	4.  Income Taxes	27
	5.  Financing	29
	6.  Commitments	29
	7.  Fair Value Measurements	30
	8.  Derivatives	31
	9.  Affiliate Transactions	33
	10. Subsequent Events	33

2

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3

Report of Independent Auditors

To the Management of Elizabethtown Gas:

We have audited the accompanying financial statements of Elizabethtown Gas (a division of Pivotal Utility Holdings, Inc., a wholly owned subsidiary of Southern Company Gas, the “Company”), which comprise the balance sheet as of December 31, 2015, and the related statements of income, comprehensive income, equity, and cash flows for the year then ended.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on the financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design 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. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Elizabethtown Gas as of December 31, 2015, and the results of its operations and its cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ PricewaterhouseCoopers LLP

Atlanta, Georgia

February 11, 2016

4

STATEMENTS OF INCOME

Elizabethtown Gas

For the Years Ended December 31, 2016 and 2015

	2016		2015
	(in thousands)
Operating Revenues	$	292,699	$	307,162
Operating Expenses:
Cost of natural gas		132,122		148,876
Other operations and maintenance		82,599		65,403
Depreciation and amortization		25,439		24,154
Taxes other than income taxes		2,572		2,850
Total operating expenses		242,732		241,283
Operating Income		49,967		65,879
Other income, net		1,610		367
Interest expense, net of amounts capitalized		14,932		14,664
Earnings Before Income Taxes		36,645		51,582
Income taxes		14,751		20,230
Net Income	$	21,894	$	31,352

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

STATEMENTS OF COMPREHENSIVE INCOME

Elizabethtown Gas

For the Years Ended December 31, 2016 and 2015

	2016			2015
	(in thousands)
Net Income	$	21,894		$	31,352
Other comprehensive income (loss):
Pension and other postretirement benefit plans:
Benefit plan net loss, net of tax of $(6,314) and $(742), respectively		(9,142	)		(1,075	)
Reclassification adjustment for amounts included in net income, net of tax of $454 and $1,143, respectively		657			1,654
Total Other Comprehensive Income (Loss)		(8,485	)		579
Comprehensive Income	$	13,409		$	31,931

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

5

STATEMENTS OF CASH FLOWS

Elizabethtown Gas

For the Years Ended December 31, 2016 and 2015

	2016			2015
	(in thousands)
Operating Activities:
Net income	$	21,894		$	31,352
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total		25,439			24,154
Deferred income taxes		7,819			20,113
Pension, postretirement, and other employee benefits		(13,083	)		1,490
Mark-to-market adjustments		(22,243	)		(2,455	)
Other, net		(17,315	)		(9,279	)
Changes in certain current assets and liabilities —
—Receivables		(16,458	)		31,467
—Proceeds from insurance settlement		—			32,000
—Inventories		3,029			6,635
—Other current assets		3,672			67
—Accrued taxes		7,381			(13,574	)
—Accounts payable		2,611			(6,932	)
—Accrued compensation		(997	)		(354	)
—Other current liabilities		21,099			(7,492	)
Net cash provided from operating activities		22,848			107,192
Investing Activities:
Property additions		(117,221	)		(89,525	)
Cost of removal, net of salvage		(6,612	)		(5,016	)
Change in construction payables, net		5,542			1,146
Net cash used for investing activities		(118,291	)		(93,395	)
Financing Activities:
Net borrowings from parent		51,698			3,000
Dividends to parent		(23,494	)		(24,001	)
Capital contributions from parent company		67,239			7,204
Net cash provided from (used for) financing activities		95,443			(13,797	)
Net Change in Cash and Cash Equivalents		—			—
Cash and Cash Equivalents at Beginning of Period		—			—
Cash and Cash Equivalents at End of Period	$	—		$	—
Supplemental Cash Flow Information:
Interest, net of amounts capitalized	$	12,324		$	14,465
Income taxes		3,216			13,799
Accrued property additions at end of period		10,053			4,511

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

6

BALANCE SHEETS

Elizabethtown Gas

At December 31, 2016 and 2015

Assets	2016			2015
	(in thousands)
Receivables —
Customer accounts receivable	$	22,979		$	16,295
Unbilled revenues		24,948			14,745
Other accounts and notes receivable		1,221			1,650
Accumulated provision for uncollectible accounts		(4,054	)		(4,897	)
Materials and supplies		304			322
Natural gas for sale		20,437			23,466
Prepaid taxes		3,682			14,205
Assets from risk management activities, net of collateral		7,473			—
Regulatory assets		10,186			5,663
Other current assets		218			3,207
Total current assets		87,394			74,656
Property, Plant, and Equipment:
In service		1,140,213			1,047,564
Less accumulated depreciation		274,679			268,063
Plant in service, net of depreciation		865,534			779,501
Construction work in progress		54,994			44,883
Total property, plant, and equipment		920,528			824,384
Other Property and Investments:
Goodwill		126,020			126,020
Deferred Charges and Other Assets:
Assets from risk management activities, net of collateral		912			—
Regulatory assets		114,680			92,465
Other deferred charges and assets		7			26
Total deferred charges and other assets		115,599			92,491
Total Assets	$	1,249,541		$	1,117,551

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

7

BALANCE SHEETS

Elizabethtown Gas

At December 31, 2016 and 2015

Liabilities and Stockholder’s Equity	2016		2015
	(in thousands)
Current Liabilities:
Due to affiliates	$	55,186	$	50,031
Accounts payable		14,287		11,289
Customer deposits		9,686		10,684
Other accrued taxes		2,720		5,215
Accrued interest		167		166
Accrued compensation		1,781		2,765
Liabilities from risk management activities, net of collateral		—		12,291
Regulatory liabilities		16,276		5,106
Accrued environmental remediation		29,000		18,300
Other current liabilities		1,363		3,242
Total current liabilities		130,466		119,089
Long-Term Debt (see notes)		346,879		295,114
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		210,826		187,880
Accrued pension and retiree welfare benefits		20,700		32,234
Other cost of removal  obligations		55,873		56,413
Accrued environmental remediation		77,054		104,072
Other regulatory liabilities		2,256		1,355
Liabilities from risk management activities, net of collateral		—		1,567
Other deferred credits and liabilities		1,028		890
Total deferred credits and other liabilities		367,737		384,411
Total Liabilities		845,082		798,614
Stockholder’s Equity
Paid-in capital		132,019		64,858
Retained earnings		272,440		274,040
Accumulated other comprehensive loss		—		(19,961	)
Total Stockholder’s Equity		404,459		318,937
Total Liabilities and Stockholder’s Equity	$	1,249,541	$	1,117,551
Commitments and Contingent Matters (see notes)

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

8

STATEMENTS OF EQUITY

Elizabethtown Gas

For the Years Ended December 31, 2016 and 2015

	Paid-in Capital			RetainedEarnings			Accumulated OtherComprehensive Loss			Total
	(in thousands)
Balance at December 31, 2014	$	57,654		$	266,689		$	(20,540	)	$	303,803
Net income		—			31,352			—			31,352
Other comprehensive income		—			—			579			579
Dividends to parent		—			(24,001	)		—			(24,001	)
Capital contributions from parent company		7,204			—			—			7,204
Balance at December 31, 2015	$	64,858		$	274,040		$	(19,961	)	$	318,937
Net income		—			21,894			—			21,894
Other comprehensive loss		—			—			(8,485	)		(8,485	)
Reclassification of accumulated other comprehensive loss to regulatory assets		—			—			28,446			28,446
Dividends to parent		—			(23,494	)		—			(23,494	)
Capital contributions from parent company		67,239			—			—			67,239
Stock-based compensation		(78	)		—			—			(78	)
Balance at December 31, 2016	$	132,019		$	272,440		$	—		$	404,459

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

9

Elizabethtown Gas

Notes to Financial Statements

December 31, 2016 and 2015

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Elizabethtown Gas (the Company) engages in the sale and distribution of natural gas to approximately 287 thousand customers in New Jersey. Elizabethtown Gas is a division of Pivotal Utility Holdings, Inc. (Pivotal Utility), which is a wholly-owned subsidiary of Southern Company Gas (formerly known as AGL Resources Inc.). On July 1, 2016, Southern Company Gas completed its previously announced merger (Merger) with The Southern Company (Southern Company) and became a wholly-owned, direct subsidiary of Southern Company.

The Company is subject to regulation by the New Jersey Board of Public Utilities (New Jersey BPU). As such, the Company’s financial statements reflect the effects of rate regulation in accordance with accounting principles generally accepted in the United States of America (GAAP) and comply with the accounting policies and practices prescribed by the New Jersey BPU. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates.

The impact of the acquisition method of accounting was not pushed down to Elizabethtown Gas and is not reflected in the financial statements included herein.

Certain prior year data in the financial statements has been modified or reclassified to conform to the presentation used by Southern Company Gas. Changes to the statements of cash flows include revised financial statement line item descriptions to align with the new balance sheet descriptions and expanded line items within each type of cash flow activity. Changes to the balance sheets include changing certain captions to conform to the presentation of Southern Company Gas.

Recently Issued Accounting Standards

In 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (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 an amount an entity expects to collect. The new standard also requires enhanced quantitative and qualitative 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 within 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 natural gas 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 natural gas supplied and billed in that period (including unbilled revenues) and 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. Some revenue arrangements, such as certain 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.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the Company has not elected its transition method.

On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance in 2016. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The adoption of ASU 2015-17 did not have an impact on the results of operations, financial position, or cash flows.

10

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 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.

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
	(in thousands)
Regulatory Assets
Recoverable weather normalization adjustment	$	10,186	$	—
Deferred natural gas costs		—		5,663
Regulatory assets – current		10,186		5,663
Recoverable environmental remediation costs		72,481		85,922
Recoverable pension and retiree welfare benefit costs		35,283		—
Unamortized losses on reacquired debt		4,425		4,867
Other		2,491		1,676
Regulatory assets – long-term		114,680		92,465
Total Regulatory Assets	$	124,866	$	98,128
Regulatory Liabilities
Accrued natural gas costs	$	14,898	$	—
Other		1,378		5,106
Regulatory liabilities – current		16,276		5,106
Other cost of removal obligations		55,873		56,413
Regulatory income tax liability		673		907
Other		1,583		448
Regulatory liabilities – long-term		58,129		57,768
Total Regulatory Liabilities	$	74,405	$	62,874

11

In the event that the Company’s operations are no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income 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 “Regulatory Matters” for additional information.

Revenues

The Company records revenues when goods or services are provided to customers. Those revenues are based on rates approved by the New Jersey BPU. The Company has a rate structure that includes a volumetric rate design that allows the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of natural gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers, revenues are based on actual deliveries to the end of the period.

The tariffs for the Company contain weather normalization adjustments that partially mitigate the impact of unusually cold or warm weather on customer billings and natural gas revenues. The weather normalization adjustments have the effect of reducing customer bills when winter weather is colder than normal and increasing customer bills when weather is warmer than normal. The weather normalization adjustments are alternative revenue programs, which allow recognition of revenue prior to billing as long as the amounts will be collected within 24 months of recognition.

Concentration of Revenue

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 2% of revenues.

Cost of Natural Gas

The Company charges its customers for natural gas consumed using a natural gas cost recovery mechanism set by the New Jersey BPU, under which all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. The Company defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively

Income and Other Taxes

The Company does not file its own federal or state income tax returns. Instead, the Company is included in Southern Company’s consolidated federal income tax return and Southern Company Gas’ various state income tax returns. Prior to the Merger, the Company was included in the consolidated tax returns of Southern Company Gas.

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 investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented on the balance sheets.

The Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 4 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 interest capitalized and cost of equity funds used during construction.

12

The Company’s property, plant, and equipment in service consisted of the following at December 31:

	2016		2015
	(in thousands)
Distribution and transmission	$	1,056,686	$	964,796
Information technology equipment and software		37,124		35,515
Storage facilities		7,193		7,112
Other		39,210		40,141
Total plant in service	$	1,140,213	$	1,047,564

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.

Depreciation

Depreciation of the original cost of plant in service is provided using composite straight-line rates, which approximated 2.3% and 2.4% in 2016 and 2015, respectively. Depreciation studies are conducted periodically to update the composite rate that is approved by the New Jersey BPU. When property subject to composite 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. As such, gains or losses are not recognized, instead they are ultimately refunded to, or recovered from, customers through future rate adjustments. Minor items of property included in the original cost of the asset are retired when the related property unit is retired.

Allowance for Funds Used During Construction (AFUDC)

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 asset through a higher rate base and higher depreciation. The AFUDC composite rate was 1.68% and 1.69% for the years ended 2016 and 2015, respectively. The Company recorded $343 thousand and $392 thousand of AFUDC for the years ended December 31, 2016 and 2015, respectively.

Goodwill

Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. In assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine that it is more likely than not that fair value of its reporting unit exceeds its carrying value (commonly referred to as Step 0). If the Company chooses not to perform a qualitative assessment, or the result of Step 0 indicates a probable decrease in fair value of its reporting unit below its carrying value, a quantitative two-step test is performed (commonly referred to as Step 1 and Step 2). Step 1 compares the fair value of the reporting unit to its carrying value including goodwill. If the carrying value exceeds the fair value, Step 2 is performed to allocate the fair value of the reporting unit to its assets and liabilities in order to determine the implied fair value of goodwill, which is compared to the carrying value of goodwill to calculate an impairment loss, if any.

For the 2016 and 2015 annual goodwill impairment tests, the Step 0 assessment was performed focusing on the following qualitative factors: macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events, and events specific to each reporting unit. This Step 0 analysis concluded that it is more likely than not that the fair value of the Company’s reporting units that have goodwill exceeds their carrying amounts and a quantitative assessment was not required.

Cash Management Money Pool

The Company participates in Southern Company Gas’ utility money pool, under which short-term borrowings are made from the money pool and surplus funds are contributed to the money pool. Borrowings from the money pool are recorded as due to affiliates in the balance sheets and intercompany interest expense is recorded in the statements of income for these borrowings. See Note 9 for additional information.

Receivables and Allowance for Uncollectible Accounts

The Company’s receivables consist primarily of natural gas sales and transportation services billed to residential, commercial, industrial, and other customers. Customers are billed monthly and payment is due within 30 days. For the majority of receivables, an allowance for doubtful accounts is established based on historical collection experience and other factors. For the remaining receivables, if the Company is aware of a specific customer’s inability to pay, an allowance for doubtful accounts is recorded to reduce the receivable balance to the amount the Company reasonably expects to collect. If circumstances change, the estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect this estimate include, but are not limited to, customer credit issues, customer deposits, and general economic conditions. Customers’ accounts are written off once they are deemed to be uncollectible.

13

Materials and Supplies

Generally, materials and supplies include propane, fleet fuel, and other materials and supplies. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.

Natural Gas for Sale

The Company’s natural gas inventories are carried at cost on a weighted average cost of gas basis.

Fair Value Measurements

The Company has financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include derivative assets and liabilities. The carrying values of receivables, accounts payable, due to affiliates, other current assets and liabilities, accrued interest, and long-term debt approximate their respective fair value. The Company’s nonfinancial assets and liabilities include pension and other retirement benefits. See Notes 2 and 7 for additional fair value disclosures.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements to utilize the best available information. Accordingly, the Company uses valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Fair value balances are classified based on the observance of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows:

Level 1

Quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company’s Level 1 items consist of exchange-traded derivatives, money market funds, and certain retirement plan assets.

Level 2

Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Market price data is obtained from multiple sources in order to value certain Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Level 2 instruments include non-exchange-traded derivatives such as over-the-counter forwards and options and certain retirement plan assets.

Level 3

Pricing inputs include significant unobservable inputs that may be used with internally developed methodologies to determine management’s best estimate of fair value from the perspective of market participants. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. Level 3 assets, liabilities, and any applicable transfers are primarily related to the Company’s pension and welfare benefit plan assets as described in Note 2. Transfers into and out of Level 3 are determined using values at the end of the interim period in which the transfer occurred.

14

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in natural gas prices, interest rates, and commodity prices. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (shown separately as “Risk Management Activities”) and are measured at fair value. See Note 7 for additional information regarding fair value. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the respective state regulatory agency approved fuel-hedging programs result in the deferral of related gains and losses in other comprehensive income (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. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 8 for additional information regarding derivatives.

The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. The Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2016.

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income.

Dividend Distributions

The Company paid dividends of $23.5 million and $24.0 million to Southern Company Gas during 2016 and 2015, respectively. The Company is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to Southern Company Gas to the extent of 70% of its quarterly net income.

15

2. RETIREMENT BENEFITS

Effective July 1, 2016, in connection with the Merger, Southern Company Services, Inc., a subsidiary of Southern Company, became the sponsor of Southern Company Gas’ pension and other postretirement benefit plans. The Company participates in the Southern Company Gas qualified defined benefit, trusteed, pension plan - AGL Resources Inc. Retirement Plan (AGL Plan) - that covers certain eligible employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974 (ERISA), as amended. Southern Company Gas provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of the Company’s management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. The Company also participates in the Southern Company Gas postretirement benefit plan - AGL Welfare Plan - which provides medical care and life insurance benefits for eligible retired employees.

In connection with the Merger, Southern Company Gas performed updated valuations of its pension and other postretirement benefit plan assets and obligations to reflect actual census data at the new measurement date of July 1, 2016. The Company recorded a regulatory asset of $35 million as of December 31, 2016 related to unrecognized prior service cost and actuarial gain/loss, as it is probable that this amount will be recovered through future rates.

The following disclosures reflect the Company’s balances and activity in the AGL Plan and the AGL Welfare Plan under the multiple-employer method of accounting.

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 periods presented and the benefit obligations as of the measurement date are presented below.

Assumptions used to determine net periodic costs:	July 1, 2016 through December 31, 2016			January 1, 2016 through June 30, 2016			Year Ended Ended December 31, 2015
Pension plans
Discount rate - interest costs (*)		3.21	%		4.00	%		4.20	%
Discount rate - service costs (*)		4.07			4.80			4.20
Expected long-term return on plan assets		7.75			7.80			7.80
Annual salary increase		3.50			3.70			3.70
Other postretirement benefit plans
Discount rate - interest costs (*)		2.84	%		3.60	%		4.00	%
Discount rate - service costs (*)		3.96			4.70			4.00
Expected long-term return on plan assets		5.93			6.60			7.80
Annual salary increase		3.50			3.70			3.70

(*)   Effective January 1, 2016, the Company uses a spot rate approach to estimate the service cost and interest cost components. Previously, the Company estimated these components using a single weighted average discount rate.

Assumptions used to determine benefit obligations:	December 31, 2016			December 31, 2015
Pension plans
Discount rate		4.39	%		4.60	%
Annual salary increase		3.50			3.70
Other postretirement benefit plans
Discount rate		4.15	%		4.40	%
Annual salary increase		3.50			3.70

The Company estimates the expected return on plans assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing, and historical performance. The Company also considers guidance from its investment advisors in making a final determination of its expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater or less than the assumed rate, it does not affect that year’s annual pension or welfare plan cost; rather, this gain or loss reduces or increases future pension or welfare plan costs.

16

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 TrendRate			Ultimate CostTrend Rate			Year That UltimateRate is Reached
Pre-65		6.60	%		4.50	%		2038
Post-65 medical		8.40			4.50			2038
Post-65 prescription		8.40			4.50			2038

An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO; however, the impact on the service and interest cost components would be immaterial.

Pension Plans

The total accumulated benefit obligation for the pension plans was $86 million at December 31, 2016 and $80 million at December 31, 2015. Changes in the projected benefit obligation and the fair value of plan assets for the Company’s qualified pension plans for the periods ended December 31, 2016, June 30, 2016, and December 31, 2015 were as follows:

	July 1, 2016 throughDecember 31, 2016			January 1, 2016through June 30, 2016			Year Ended EndedDecember 31, 2015
	(in thousands)
Change in benefit obligation
Benefit obligation at beginning of period	$	105,458		$	90,910		$	93,042
Service cost		990			861			1,713
Interest cost		2,044			2,238			4,788
Benefits paid		(3,592	)		(3,338	)		(6,812	)
Actuarial loss (gain)		(9,937	)		14,787			(1,821	)
Benefit obligation at end of period		94,963			105,458			90,910
Change in plan assets
Fair value of plan assets at beginning of period		60,687			61,044			63,830
Actual return on plan assets		3,706			2,981			4,026
Employer contributions		14,048			—			—
Benefits paid		(3,592	)		(3,338	)		(6,812	)
Fair value of plan assets at end of period		74,849			60,687			61,044
Accrued liability	$	20,114		$	44,771		$	29,866

At December 31, 2016, the projected benefit obligations for the qualified and non-qualified pension plans were $95 million and $1 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 qualified pension plans consist of the following:

	2016			2015
	(in thousands)
Other regulatory assets, deferred	$	30,484		$	—
Employee benefit obligations		(20,114	)		(29,866	)

17

Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2016 and 2015 related to the qualified 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.

	Prior Service Cost			Net (Gain) Loss
	(in thousands)
Balance at December 31, 2016:
Regulatory assets (liabilities)	$	(2,000	)	$	32,484
Balance at December 31, 2015:
Accumulated OCI		(2,848	)		30,637
Estimated amortization in net periodic cost in 2017:
Regulatory assets (liabilities)		847			(2,903	)

The components of OCI and the changes in the balance of regulatory assets related to the qualified defined benefit pension plans for the periods ended December 31, 2016, June 30, 2016, and December 31, 2015 are presented in the following table:

	Accumulated OCI			Regulatory Assets
	(in thousands)
Balance at December 31, 2014:	$	29,172		$	—
Net (gain) loss		997			—
Reclassification adjustments:
Amortization of prior service costs		907			—
Amortization of net loss		(3,287	)		—
Total reclassification adjustments		(2,380	)		—
Total change		(1,383	)		—
Balance at December 31, 2015:	$	27,789		$	—
Net (gain) loss		15,216			(9,816	)
Reclassification adjustments:
Amortization of prior service costs		434			434
Amortization of net loss		(1,396	)		(2,177	)
Reclassification from accumulated OCI to regulatory assets		(42,043	)		42,043
Total reclassification adjustments		(43,005	)		40,300
Total change		(27,789	)		30,484
Balance at December 31, 2016:	$	—		$	30,484

The Company’s pro rata components of Southern Company Gas’ net periodic pension costs for the periods presented were as follows:

	Years Ended December 31,
	2016			2015
	(in thousands)
Service cost	$	1,851		$	1,713
Interest cost		4,282			4,788
Expected return on plan assets		(6,249	)		(5,733	)
Amortization:
Prior service costs		(868	)		(907	)
Net loss		3,573			3,287
Net periodic pension cost	$	2,589		$	3,148

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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.

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, the Company’s estimated benefit payments were as follows:

	Benefit Payments
	(in thousands)
2017	$	8,286
2018		8,086
2019		8,107
2020		8,344
2021		8,195
2022 to 2026		40,610

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Other Postretirement Benefits

Changes in the APBO and the fair value of plan assets for the periods ended December 31, 2016, June 30, 2016, and December 31, 2015 were as follows:

	July 1, 2016 throughDecember 31, 2016			January 1, 2016through June 30, 2016			Year Ended December31, 2015
	(in thousands)
Change in benefit obligation
Benefit obligation at beginning of period	$	13,174		$	13,512		$	14,314
Service cost		55			47			114
Interest cost		187			218			553
Benefits paid		(293	)		(438	)		(636	)
Actuarial gain		(806	)		(165	)		(833	)
Benefit obligation at end of period		12,317			13,174			13,512
Change in plan assets
Fair value of plan assets at beginning of period		12,829			12,737			13,600
Actual return (loss) on plan assets		348			92			(863	)
Employer contributions		293			438			636
Benefits paid		(293	)		(438	)		(636	)
Fair value of plan assets at end of period		13,177			12,829			12,737
(Prepaid asset) accrued liability	$	(860	)	$	345		$	775

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 thousands)
Other regulatory assets, deferred	$	4,361	$	—
Employee benefit asset (obligation)		860		(775	)

Presented below are the amounts included in accumulated OCI and 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. The estimated amortization of such amounts for 2017 is immaterial.

	Prior Service Cost		Net (Gain) Loss
	(in thousands)
Balance at December 31, 2016:
Regulatory assets	$	—	$	4,361
Balance at December 31, 2015:
Accumulated OCI	$	2	$	5,546

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The components of OCI, along with the changes in the balance of regulatory assets (liabilities), related to the other postretirement benefit plans for the periods ended December 31, 2016, June 30, 2016, and December 31, 2015 are presented in the following table:

	Accumulated OCI			Regulatory Assets
	(in thousands)
Balance at December 31, 2014:	$	5,058		$	—
Net (gain) loss		891			—
Reclassification adjustments:
Amortization of prior service costs		(44	)		—
Amortization of net loss		(357	)		—
Total reclassification adjustments		(401	)		—
Total change		490			—
Balance at December 31, 2015:	$	5,548		$	—
Net (gain) loss		90			(933	)
Reclassification adjustments:
Amortization of prior service costs		(1	)		(1	)
Amortization of net loss		(137	)		(205	)
Reclassification from accumulated OCI to regulatory assets		(5,500	)		5,500
Total reclassification adjustments		(5,638	)		5,294
Total change		(5,548	)		4,361
Balance at December 31, 2016:	$	—		$	4,361

The Company’s pro rata components of Southern Company Gas’ other postretirement benefit plans’ net periodic cost for the periods presented were as follows:

	Years Ended December 31,
	2016			2015
	(in thousands)
Service cost	$	102		$	114
Interest cost		405			553
Expected return on plan assets		(673	)		(1,015	)
Amortization:
Prior service costs		2			44
Net loss		342			357
Net periodic postretirement benefit cost	$	178		$	53

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. At December 31, 2016, estimated benefit payments were as follows:

	Benefit Payments
	(in thousands)
2017	$	693
2018		745
2019		790
2020		826
2021		861
2022 to 2026		4,277

Benefit Plan Assets

Southern Company Gas’ 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 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. Southern Company Gas minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.

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The assets of the AGL Plan were allocated 69% equity, 20% fixed income, 1% cash, and 10% other at December 31, 2016 compared to the Company’s targets of 53% equity, 15% fixed income, 2% cash, and 30% other. The plan’s investment policy provides for variation around the target asset allocation in the form of ranges. The Company’s pro rata share of the AGL Plan assets was 7.62% and 7.21% for December 31, 2016 and 2015, respectively.

The assets of the AGL Welfare Plan were allocated 74% equity, 23% fixed income, 1% cash, and 2% other at December 31, 2016 compared to the Company’s targets of 72% equity, 24% fixed income, 1% cash, and 3% other. The investment policy provides for variation around the target asset allocation in the form of ranges. The Company’s pro rata share of the AGL Welfare Plan assets was 12.56% and 12.82% for December 31, 2016 and 2015, respectively.

The assets of the AGL Plan and the AGL Welfare Plan were allocated 72% equity and 28% fixed income at December 31, 2015 compared to the Company’s targets of 70% to 95% equity, 5% to 20% fixed income, and up to 10% cash. The investment policies provided for some variation in these targets in the form of ranges around the target.

The investment strategy for plan assets related to the Southern Company Gas’ 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 Southern Company Gas employs a formal rebalancing program for its pension plan assets. 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 Southern Company Gas pension 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.

• 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 (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 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 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.

22

• 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.

• 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.

The Company’s pro rata portion of 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. Absolute return investment assets are presented in the tables below based on the nature of the investment.

	Fair Value Measurements Using
As of December 31, 2016	Quoted Pricesin Active Marketsfor Identical Assets(Level 1)		Significant OtherObservable Inputs(Level 2)		Net Asset Valueas a PracticalExpedient(NAV)		Total
	(in thousands)
Assets:
Domestic equity(*)	$	10,800	$	26,103	$	—	$	36,903
International equity(*)		—		14,117		—		14,117
Fixed income:
U.S. Treasury, government, and agency bonds		—		6,482		—		6,482
Corporate bonds		—		3,099		—		3,099
Pooled funds		—		5,039		—		5,039
Cash equivalents and other		931		375		6,328		7,634
Real estate investments		275		—		1,110		1,385
Private equity		—		—		190		190
Total	$	12,006	$	55,215	$	7,628	$	74,849

(*) 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.

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	Pension plans
As of December 31, 2015	Level 1			Level 2			Level 3			Total			% of total
	(in thousands)
Cash	$	300		$	21		$	—		$	321			1	%
Equity securities:
U.S. large cap(a)	$	5,363		$	14,371		$	—		$	19,734			32	%
U.S. small cap(a)		4,115			1,740			—			5,855			9
International companies(b)		—			9,017			—			9,017			15
Emerging markets(c)		—			1,992			—			1,992			3
Total equity securities	$	9,478		$	27,120		$	—		$	36,598			59	%
Fixed income securities:
Corporate bonds(d)	$	—		$	6,528		$	—		$	6,528			10	%
Other (or gov’t/muni bonds)		—			10,881			—			10,881			18
Total fixed income securities	$	—		$	17,409		$	—		$	17,409			28	%
Other types of investments:
Global hedged equity(e)	$	—		$	—		$	2,900		$	2,900			5	%
Absolute return(f)		—			—			3,075			3,075			5
Private capital(g)		—			—			1,419			1,419			2
Total other investments	$	—		$	—		$	7,394		$	7,394			12	%
Total assets at fair value	$	9,778		$	44,550		$	7,394		$	61,722			100	%
% of fair value hierarchy		16	%		72	%		12	%		100	%

(a) Includes funds that invest primarily in U.S. common stocks.

(b) Includes funds that invest primarily in foreign equity and equity-related securities.

(c) Includes funds that invest primarily in common stocks of emerging markets.

(d) Includes funds that invest primarily in investment grade debt and fixed income securities.

(e) Includes funds that invest in limited/general partnerships, managed accounts, and other investment entities issued by non-traditional firms or “hedge funds.”

(f) Includes funds that invest primarily in investment vehicles and commodity pools as a “fund of funds.”

(g) Includes funds that invest in private equity and small buyout funds, partnership investments, direct investments, secondary investments, directly/indirectly in real estate and may invest in equity securities of real estate related companies, real estate mortgage loans, and real estate mezzanine loans.

The following is a reconciliation of the Company’s pension plan assets in Level 3 of the fair value hierarchy at December 31, 2015:

	Global HedgedEquity			Absolute Return		Private Capital			Total
	(in thousands)
Balance at December 31, 2014	$	2,043		$	2,959	$	1,409		$	6,411
Actual return on plan assets		(82	)		116		(71	)		(37	)
Purchases		975			—		—			975
Sales		(36	)		—		81			45
Balance at December 31, 2015	$	2,900		$	3,075	$	1,419		$	7,394

There were no transfers out of Level 3 or between Level 1 and Level 2 in 2015. During 2016, the Level 3 assets were accounted for at net asset value as a practical expedient.

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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 2016, special situations (absolute return and hedge funds) investment assets are presented in the table below based on the nature of the investment.

	Fair Value Measurements Using
	Quoted Pricesin Active Marketsfor Identical Assets		Significant OtherObservableInputs		Net Asset Valueas a PracticalExpedient
As of December 31, 2016	(Level 1)		(Level 2)		(NAV)		Total
	(in thousands)
Assets:
Domestic equity(*)	$	315	$	7,264	$	—	$	7,579
International equity(*)		—		2,206		—		2,206
Fixed income:
U.S. Treasury, government, and agency bonds		—		63		—		63
Corporate bonds		—		28		—		28
Pooled funds		—		2,942		—		2,942
Cash equivalents and other		99		—		209		308
Real estate investments		8		—		37		45
Private equity		—		—		6		6
Total	$	422	$	12,503	$	252	$	13,177

(*)  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.

	Other postretirement plans
As of December 31, 2015	Level 1			Level 2			Level 3			Total			% of total
	(in thousands)
Cash	$	122		$	—		$	—		$	122			1	%
Equity securities:
U.S. large cap(a)	$	—		$	6,621		$	—		$	6,621			58	%
International companies(b)		—			1,995			—			1,995			17
Total equity securities	$	—		$	8,616		$	—		$	8,616			75	%
Fixed income securities:
Corporate bonds(c)	$	—		$	2,794		$	—		$	2,794			24	%
Total fixed income securities	$	—		$	2,794		$	—		$	2,794			24	%
Total assets at fair value	$	122		$	11,410		$	—		$	11,532			100	%
% of fair value hierarchy		1	%		99	%		—	%		100	%

(a) Includes funds that invest primarily in U.S. common stocks.

(b) Includes funds that invest primarily in foreign equity and equity-related securities.

(c) Includes funds that invest primarily in common stocks of emerging markets.

Employee Savings Plan

Southern Company Services, Inc. sponsors 401(k) defined contribution plans covering certain eligible employees. The AGL Resources Inc. 401(k) plans provide matching contributions of either 65% on up to 8% of an employee’s eligible compensation, or a 100% matching contribution on up to 3% of an employee’s eligible compensation, followed by a 75% matching contribution on up to the next 3% of an employee’s eligible compensation. Total matching contributions made to the AGL Resources Inc. 401(k) plans for each of the periods ended December 31, 2016 and 2015 were $1 million.

For employees not accruing a benefit under the AGL Plan, additional contributions made to the 401(k) plans for the period ended December 31, 2016 and 2015 were immaterial.

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3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is assessing its alleged involvement in an incident that occurred in its service territory that resulted in several deaths, injuries, and property damage. The Company has been named as one of the defendants in several lawsuits related to this incident. At December 31, 2016, the Company recorded reserves for its potential exposure from this case. 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. The ultimate outcome of these matters and 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.

Environmental Matters

The Company’s operations are subject to extensive regulation by the state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including the handling and disposal of waste and releases of hazardous substances. Compliance with these environmental requirements involves significant capital and operating costs to clean up affected sites. The Company conducts studies to determine the extent of any required clean up and has recognized in its financial statements the costs to clean up known impacted sites.

The Company is subject to environmental remediation liabilities associated with six former manufactured gas plant sites in New Jersey. Accrued environmental remediation costs of $106 million have been recorded in the balance sheets as of December 31, 2016, $29 million of which is expected to be incurred over the next 12 months. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the New Jersey BPU.

The Company’s ultimate environmental compliance strategy and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations and the outcome of any legal challenges to the environmental rules. The ultimate outcome of these matters cannot be determined at this time.

In 2014, the Company reached a settlement with an insurance company for environmental claims relating to potential contamination at several manufactured gas plant sites. The terms of the settlement required the insurance company to pay the Company a total of $77 million in two installments. The Company received a $45 million installment in 2014 and the remaining $32 million in July 2015. The New Jersey BPU approved the use of the insurance proceeds to reduce the regulatory assets associated with environmental remediation costs that otherwise would have been recovered from Elizabethtown Gas customers.

Regulatory Matters

The Merger was approved by the New Jersey BPU on June 29, 2016. In connection with the Merger approval order, the Company was required to:

• provide rate credits of $17.5 million to its customers; and

• file a rate case no later than September 1, 2016, with another rate case no later than three years after the 2016 rate case.

See “Customer Refunds” and “Base Rate Case” below for additional information.

Regulatory Infrastructure Program

The Company has the following infrastructure improvement programs:

Elizabethtown Gas’ extension of the Aging Infrastructure Replacement (AIR) enhanced infrastructure program effective in 2013 allowed for infrastructure investment of $115 million over four years, and is focused on the replacement of aging cast iron in its pipeline system. Carrying charges on the additional capital spend are being accrued and deferred for regulatory purposes at a WACC of 6.65%. In conjunction with the general base rate case filed with the New Jersey BPU on September 1, 2016, the Company requested recovery of the AIR program. See “Base Rate Case” herein for additional information.

In 2014, the New Jersey BPU approved Natural Gas Distribution Utility Reinforcement Effort, a program that improved the Company’s distribution system’s resiliency against coastal storms and floods. Under the plan, Elizabethtown Gas invested $15 million in infrastructure and related facilities and communication planning over a one-year period from August 2014 through September 2015. Effective November 2015, the Company increased its base rates for investments made under the program.

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In September 2015, the Company filed the Safety, Modernization and Reliability Tariff plan with the New Jersey BPU seeking approval to invest more than $1.1 billion to replace 630 miles of vintage cast iron, steel, and copper pipeline, as well as 240 regulator stations. If approved, the program is expected to be completed by 2027. As currently proposed, costs incurred under the program would be recovered through a rider surcharge over a period of 10 years.

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

Customer Refunds

In the third quarter 2016, the Company provided direct per-customer rate credits totaling $17.5 million to its customers in accordance with the Merger approval from the New Jersey BPU. These rate credits were allocated among the Company’s customer classes based on the base rate revenues reflected in the rates that resulted from its most recent base rate proceeding.

Base Rate Case

On September 1, 2016, the Company filed a general base rate case with the New Jersey BPU as required under its AIR program and in accordance with the Merger approval, requesting an increase in annual revenues of $19 million, based on an allowed return on equity of 10.25%. The Company expects the New Jersey BPU to issue an order on the filing in the third quarter 2017. The ultimate outcome of this matter cannot be determined at this time.

Unrecognized Ratemaking Amounts

The following table illustrates the Company’s 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 the Company’s AIR program. These amounts will be recognized as revenues in the Company’s financial statements in the periods they are billable to customers.

	(in thousands)
December 31, 2016	$	5,535
December 31, 2015		3,844

4. INCOME TAXES

On behalf of the Company, Southern Company will file a consolidated federal income tax return and Southern Company Gas will file various 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 the Internal Revenue Service (IRS) regulations, the Company is jointly and severally liable for the federal tax liability. Prior to the Merger, the Company was a part of Southern Company Gas’ federal consolidated income tax return and various state income tax returns.

Current and Deferred Income Taxes

Details of income tax provisions for the years ended December 31, 2016 and 2015 are as follows:

	2016			2015
	(in thousands)
Federal —
Current	$	5,630		$	(852	)
Deferred		6,661			17,430
		12,291			16,578
State —
Current		1,302			969
Deferred		1,277			2,835
		2,579			3,804
Amortization of investment tax credits		(119	)		(152	)
Total	$	14,751		$	20,230

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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 thousands)
Deferred tax liabilities —
Accelerated depreciation	$	208,605	$	185,274
Property basis differences		23,262		25,767
Regulatory assets associated with employee benefit obligations		15,525		—
Other		7,558		11,825
Total		254,950		222,866
Deferred tax assets —
Federal net operating loss		8,275		—
Federal effect of state deferred taxes		12,426		10,609
Employee benefit obligations		15,566		18,243
Bad debt and insurance reserves		1,936		2,307
Other		5,921		6,817
Total		44,124		37,976
Accumulated deferred income taxes, net	$	210,826	$	184,890

In November 2015, the FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes. See Note 1 under “Recently Issued Accounting Standards” for additional information.

At December 31, 2016, the tax-related regulatory liabilities to be credited to customers were $673 thousand. These liabilities are primarily attributable to unamortized ITCs.

Deferred federal and state 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 amounted to $119 thousand and $152 thousand for the years ended December 31, 2016 and 2015, respectively. 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:

	Years Ended December 31,
	2016			2015
Federal statutory rate		35.0	%		35.0	%
State income tax, net of federal deduction		5.9			5.9
Other		(0.6	)		(1.7	)
Effective income tax rate		40.3	%		39.2	%

Unrecognized Tax Benefits

The Company has no unrecognized tax benefits for any period presented. The Company classifies interest on tax uncertainties as interest expense; however, the Company had no accrued interest or penalties for unrecognized tax benefits for any period 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. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits by the IRS or any state have either concluded, or the statute of limitations has expired with respect to income tax examinations, for periods prior to 2012.

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5. FINANCING

The following table provides maturity dates, year-to-date weighted average interest rates, and amounts outstanding for various debt securities and facilities that are included in the balance sheets.

			December 31, 2016						December 31, 2015
Dollars in thousands	Year(s) due		Weighted averageinterest rate			Outstanding			Weighted averageinterest rate			Outstanding
Gas facility revenue bonds		2022-2033		1.3	%	$	180,100			0.9	%	$	180,100
Affiliate promissory note		2034		7.2			167,528			10.0			115,830
Total principal long-term debt				4.1	%	$	347,628		$	4.5	%		295,930
Unamortized debt issuance costs				n/a		$	(749	)	$	n/a			(816	)
Total debt				n/a		$	346,879		$	n/a			295,114

Gas Facility Revenue Bonds

The Company is party to a series of loan agreements with the New Jersey Economic Development Authority under which, a series of gas facility revenue bonds have been issued. These revenue bonds are issued by state agencies to investors, and proceeds from each issuance then are loaned to the Company. Southern Company Gas fully and unconditionally guarantees all of the Company’s gas facility revenue bonds.

Affiliate Promissory Note

Pivotal Utility entered into a promissory note with Southern Company Gas (Affiliate Promissory Note) for the purpose of refinancing its short-term debt and recapitalizing the capital structure of Pivotal Utility and those of its utility operating divisions including the Company’s, in accordance with the target capitalization of 45% and with authorization of the New Jersey BPU. The Affiliate Promissory Note is adjusted periodically to maintain the appropriate targeted capitalization percentages. During 2016, $67.2 million was converted from the Affiliate Promissory Note to equity in order to maintain the target capitalization ratio. The Affiliate Promissory Note is due December 31, 2034 and had an initial interest rate at December 31, 2004 of 6.3%, which adjusts on a periodic basis based upon weighted average costs and expenses of borrowing the then-outstanding long-term debt of both Southern Company Gas and Southern Company Gas Capital Corporation, a 100%-owned financing subsidiary of Southern Company Gas. As of December 31, 2016, the effective interest rate on this note was 7.2% which consists of two components. The first is incurred equal to the weighted average costs that is applied to the principal amount of the Affiliate Promissory Note. The second component is an adjustment to increase the effective interest incurred on long-term debt other than the Affiliate Promissory Note to the weighted average cost applicable to the Affiliate Promissory Note.

6. COMMITMENTS

Pipeline Charges, Storage Capacity, and Gas Supply

Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to marketers of natural gas as well as demand charges associated with Sequent Energy Management, L.P. (Sequent), a wholly-owned subsidiary of Southern Company Gas that engages in wholesale marketing of natural gas supply services.

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Contractual Obligations

Contractual obligations at December 31, 2016 were as follows:

	2017			2018-2019		2020-2021	After 2021		Total
	(in thousands)
Long-term debt(a) _
Principal	$	—	$	—	$	—	$	346,879		346,879
Interest		2,313		4,625		4,625		16,969		28,532
Pipeline charges, storage capacity, and gas supply(b)		50,341		86,810		71,549		256,587		465,287
Operating leases(c)		4,082		7,946		8,269		1,394		21,691
Asset management agreements(d)		4,250		6,375		—		—		10,625
Standby letters of credit and performance/surety bonds(e)		576		116		—		—		692
Other purchase commitments(f)		28,875		1,000		—		—		29,875
Total	$	90,437	$	106,872	$	84,443	$	621,829	$	903,581

(a) Amounts are reflected based on final maturity dates. 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 at January 1, 2017 and do not include interest on the affiliated promissory note.

(b) Includes charges recoverable through a natural gas cost recovery mechanism, subject to review by the New Jersey BPU.

(c) Certain operating leases have provisions for step rent or escalation payments and certain lease concessions are accounted for by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms. However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein. The Company’s operating leases are primarily related to equipment purchases and real estate licenses.

(d) Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements.

(e) Guarantees are provided to certain municipalities and other agencies in support of payment obligations.

(f) Primarily consists of contractual environmental remediation liabilities that are generally recoverable through base rates or rate rider mechanisms.

Indemnities

In certain instances, the Company has undertaken to indemnify current property owners and others against costs associated with the effects and/or remediation of contaminated sites for which it may be responsible under applicable federal or state environmental laws, generally with no limitation as to the amount. These indemnifications relate primarily to ongoing coal tar cleanup. See Note 3 under “Environmental Matters” for additional information. The Company believes that the likelihood of payment under its other environmental indemnifications is remote. No liability has been recorded for such indemnifications as the fair value was inconsequential at inception.

7. 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. See Note 1 for additional information.

As of December 31, 2016, assets 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 Pricesin ActiveMarkets forIdentical Assets(Level 1)		SignificantOtherObservableInputs(Level 2)		SignificantUnobservableInputs(Level 3)		Net AssetValue as aPracticalExpedient(NAV)		Total
	(in thousands)
Assets:
Energy-related derivatives	$	—	$	8,385	$	—	$	—	$	8,385

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As of December 31, 2015, 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 Pricesin ActiveMarkets forIdentical Assets(Level 1)		SignificantOtherObservableInputs(Level 2)		SignificantUnobservableInputs(Level 3)		Net AssetValue as aPracticalExpedient(NAV)		Total
	(in thousands)
Liabilities:
Energy-related derivatives	$	—	$	13,858	$	—	$	—	$	13,858

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and non-exchange-traded derivatives such as over-the-counter forwards and options. 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 and implied volatility. See Note 8 for additional information on how these derivatives are used.

8. DERIVATIVES

The Company is exposed to market risks, primarily commodity price risk, interest rate risk, and weather 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 7 for additional information. In the statements of cash flows, the cash impacts of settled energy-related are recorded as operating activities.

Energy-Related Derivatives

The Company enters into energy-related derivatives to hedge exposures to natural 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 prices of natural gas. The Company manages fuel-hedging programs, implemented per the guidelines of the New Jersey BPU, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility.

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 the cost of natural gas as the underlying natural gas is used in operations and ultimately recovered through cost recovery clauses.

• 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 in the period of change.

At December 31, 2016, the net volume of energy-related derivative contracts for natural gas positions totaled 18 billion cubic feet for the Company, together with the longest hedge date of 2018 over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions.

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Derivative Financial Statement Presentation and Amounts

The Company’s derivative contracts are subject to master netting arrangements or similar agreements and are reported net on its financial statements. Some of these energy-related derivative contracts 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 and 2015, the fair value of energy-related derivatives was reflected in the balance sheets as follows:

		Asset Derivatives					Liability Derivatives
DerivativeCategory	Balance Sheet Location	December 31, 2016		December 31, 2015		Balance Sheet Location	December 31, 2016		December 31, 2015
		(in thousands)					(in thousands)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities – current		$	7,473	$	—	Liabilities from risk management activities – current	$	—	$	12,291
Assets from risk management activities – deferred			912		—	Liabilities from risk management activities – deferred		—		1,567
Total derivatives designated as hedging instruments for regulatory purposes		$	8,385	$	—		$	—	$	13,858
Gross amounts of recognized assets and liabilities(a)		$	8,385	$	—		$	—	$	13,858
Gross amounts offset in the balance sheet		$	—	$	—		$	—	$	—
Net amounts of derivatives assets and liabilities, presented in the balance sheet(b)		$	8,385	$	—		$	—	$	13,858

(a) The gross amounts of recognized assets and liabilities are netted on the balance sheets to the extent that there were netting arrangements with the counterparties.

(b) As of December 31, 2016 and 2015, letters of credit from counterparties offset an immaterial portion of these assets under master netting arrangements.

At December 31, 2016 and 2015, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

		Unrealized Losses						Unrealized Gains
Derivative Category	Balance Sheet Location	December 31, 2016		December 31, 2015			Balance Sheet Location	December 31, 2016		December 31, 2015
		(in thousands)						(in thousands)
Energy-related derivatives:
Other regulatory assets, current		$	—	$	(12,291	)	Other regulatory liabilities, current	$	7,473	$	—
Other regulatory assets, deferred			—		(1,567	)	Other regulatory liabilities, deferred		912		—
Total energy-related derivative gains (losses)		$	—	$	(13,858	)		$	8,385	$	—

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 a credit rating change below BBB- and/or Baa3. At December 31, 2016, the Company had no collateral posted with derivative counterparties to satisfy these arrangements.

At December 31, 2016, the fair value of derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features were immaterial.

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Generally, collateral may be provided by a 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 Investors Service Inc. and S&P Global Ratings 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 its exposure to counterparty credit risk.

The Company also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When the Company is engaged in more than one outstanding derivative transaction with the same counterparty and it 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 the Company’s credit risk. The Company also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable the Company to net certain assets and liabilities by counterparty. The Company also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. The Company may require counterparties to pledge additional collateral when deemed necessary. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

9. AFFILIATE TRANSACTIONS

The Company has agreements with Sequent for transportation and storage capacity to meet natural gas demands. The following table provides additional information on the Company’s asset management agreements with Sequent.

				Profit sharing / fees payments
Expiration date	Type of fee structure	Annual fee		2016		2015
				(in thousands)
March 2019	Tiered		(*)	$	15,043	$	28,617

(*) In March 2014, the New Jersey BPU authorized the renewal of the asset management agreement between Elizabethtown Gas and Sequent for five years. This renewed agreement began on April 1, 2014 and requires Sequent to pay minimum annual fees of $4.25 million to Elizabethtown Gas and includes tiered margin sharing levels between Elizabethtown Gas and Sequent.

Amounts Due to Affiliates

The Company had $55.2 million and $50.0 million in payable at December 31, 2016 and 2015, respectively, which was due to Southern Company Gas, primarily related to the participation in the Southern Company Gas money pool. The Company also had $167.5 million and $115.8 million outstanding at December 31, 2016 and 2015, respectively, related to a promissory note with Southern Company Gas. See Note 5 for additional information on the Affiliate Promissory Note.

The Company also engages in transactions with Southern Company Gas’ affiliates consistent with its services and tax allocation agreements.

10. SUBSEQUENT EVENTS

Management evaluated subsequent events for potential recognition and disclosure through March 31, 2017, the date these financial statements were available to be issued, and determined that no significant events have occurred subsequent to period end.

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