Chugach Electric Association 8-K/A Municipality of Anchorage, Alaska Electric Utility Fund

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

A Major Enterprise Fund of the Municipality of Anchorage

Financial Statements,

Required Supplementary Information

and

Other Information

December 31, 2019 and 2018

(With Independent Auditor’s Report Thereon)

MUNICIPALITY OF ANCHORAGE, ALASKA

ELECTRIC UTILITY FUND

Table of Contents

Financial Section	1-3
Independent Auditor’s Report	4-6
Management’s Discussion and Analysis	18-19
Statements of Net Position	20
Statements of Revenues, Expenses and Changes in Net Position	22-23
Statements of Cash Flows	22-23
Notes to Financial Statements	25-97
Required Supplementary Information:
Public Employees’ Retirement System – Defined Benefit Pension Plan: Schedule of the Utility’s Proportionate Share of the Net Pension Liability	100
Schedule of Utility Contribution	101
Public Employees’ Retirement System -
Other Postemployment Benefit Plans (OPEB):
Schedule of the Utility’s Proportionate Share of the Net OPEB Liability	102
Schedule of Utility Contributions	103
International Brotherhood of Electrical Workers (IBEW) – Defined Benefit Pension Plan – Schedule of Utility Contributions	104
Notes to Required Supplementary Information	105-106
Statistical Section:
Net Position by Components	108
Change in Net Position	109
Capital Assets	110
Comparative Operating Revenue Relationships	111
Top Ten Customers by Revenue	112-115
Rate Summary	116-117
Typical Monthly Bill Comparison	118
Rate Comparison	119
Bond Debt	120
Schedule of Revenue Bond Coverage	121
Statement of Net Position Ratios	122
Base Ratings by Generation Units	123
Generated and Purchased Power	124
Energy Loads and Resources	125
Monthly Peak (Megawatt Hours)	126-127
Miscellaneous Statistical Information	128
Independent Auditor’s Report on Internal Control Over Financial Reporting and on Compliance and Other Matters Based on an Audit of Financial Statements Performed in Accordance with Government Auditing Standards	129-130

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II

Independent Auditor’s Report

Honorable Mayor and Members of the Assembly

Municipality of Anchorage, Alaska

Report on the Financial Statements

We have audited the accompanying financial statements of the Electric Utility Fund, an enterprise fund of the Municipality of Anchorage, Alaska, as of and for the years ended December 31, 2019 and 2018, and the related notes to the financial statements, which collectively comprise the Electric Utility Fund’s Alaska’s basic financial statements as listed in the table of contents.

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.

Auditor’s 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 and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States. 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 judgement, 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 entity’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 entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of the accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of 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 the Electric Utility Fund as of December 31, 2019 and 2018, and the changes in financial position and its cash flows for the year then ended in accordance with accounting principles generally accepted in the United State of America.

BDO USA, LLP, a Delaware limited liability partnership, is the U.S. member of BDO International Limited, a UK company limited by guarantee, and forms part of the international BDO network of independent member firms.

BDO is the brand name for the BDO network and for each of the BDO Member Firms.

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Emphasis on Matters

As discussed in Note 1, the financial statements present only the Electric Utility Fund, and do not purport to, and do not present fairly the financial position of the Municipality of Anchorage, Alaska as of December 31, 2019 and 2018, the changes in its financial position, or where applicable, its cash flows for the years ended in accordance with accounting principles generally accepted in the United States. Our opinion s not modified with respect to this matter.

As discussed in Note 13 to the financial statements, the Electric utility fund is currently in the process of being sold to a third party. Our opinion is not modified with respect to this matter.

Other Matters

Required Supplementary Information

Accounting principles generally accepted in the United States of America require that Management’s Discussion and Analysis on pages 4 through 16 and the schedules of the Utility’s proportionate share of the net pension and net other postemployment benefit liability and Utility contributions to the pension and other postemployment benefit plans on pages 100 through 106 be presented to supplement the basis financial statements. Such information, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

Other Information

Our audit was conducted for the purpose of forming an opinion on the financial statements that collectively comprise the Electric Utility Fund’s basic financial statements. The statistical section is presented for purposes of additional analysis and is not a required part of the basic financial statements. The statistical section has not been subjected to the auditing procedures applied in the audit of the basic financial statements, and accordingly, we do not express an opinion or provide any assurance on it.

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Other Reporting Required by Government Auditing Standards

In accordance with Government Auditing Standards, we have also issued our report dated June 30, 2020 on our consideration of the Electric Utility Fund’s internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations, contracts and grant agreements and other matters. The purpose of that report is to describe the scope of our testing of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on the internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with the Government Auditing Standards in considering the Electric Utility Fund’s internal control over financial reporting and compliance.

/s/ BDO USA, LLP

Anchorage, Alaska

June 30,2020

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Management’s Discussion and Analysis

December 31, 2019 and 2018

The Electric Utility Fund (Utility) is a public utility of the Municipality of Anchorage (Municipality or Anchorage). The following is a discussion and analysis of the Utility’s financial performance, providing an overview of the financial activities for the years ended December 31, 2019 and 2018. This discussion and analysis is designed to assist the reader in focusing on the significant financial issues, provide an overview of the Utility’s financial activities and identify changes in the Utility’s financial position. We encourage readers to consider the information presented here in conjunction with the Utility’s financial statements and accompanying notes, taken as a whole.

Financial Highlights

· The Utility’s total plant increased $0.2 million or 0.03% in 2019 while decreasing $12.7 million or 1.4% in 2018. The increase in 2019 was due to depreciation and retirements keeping pace with additions to plant. The decrease in 2018 was due to depreciation and plant retirement exceeding additions to plant.

· Total assets and deferred outflows of resources exceeded total liabilities and deferred inflows of resources by $299.3 million at December 31, 2019 and by $285.2 million at December 31, 2018. Of these amounts, $69.7 million in 2019 and $69.7 million in 2018 were unrestricted and available to meet the Utility’s ongoing obligations to customers and creditors.

· The Utility’s total net position increased $14.1 million or 4.9% in 2019, compared to an increase of $15.8 million or 5.86% in 2018. The increase in net position in 2019 was primarily due to lower production costs, primarily fuel, higher investment income, and lower administrative costs. The restriction on paying dividends to the MOA also has contributed to the increase in net position since 2016.The increase in net position in 2018 was primarily due to lower fuel costs and a lower gas transfer price for internally produced gas. Depreciation also decreased significantly in 2018. Beginning net position was reduced by $2.5 million due to adoption of a new accounting standard in 2018.

Overview of the Financial Statements

The Utility is a business type activity of the Municipality that provides electrical services to a specific area of the Municipality. The Utility’s activities are recorded in an enterprise fund of the Municipality.

Required Financial Statements

The Utility’s financial statements offer short and long-term information about the activities of the Utility and collectively provide an indication of the Utility’s financial health. The basic financial statements are prepared using the economic resources measurement focus and accrual basis of accounting.

The basic financial statements, presented on a comparative basis for the years ended December 31, 2019 and 2018, include Statements of Net Position, Statements of Revenues, Expenses, and Changes in Net Position and Statements of Cash Flows.

The Statements of Net Position present information on all of the Utility’s assets, liabilities, deferred outflows of resources and deferred inflows of resources, with the difference reported as net position, and provides information about the nature and amounts of investments in resources and obligations to creditors.

The Statements of Revenues, Expenses, and Changes in Net Position report operating and non-operating revenues and expenses, and the change in net position of the Utility for the years presented.

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municipality of anchorage, alaska
electric utility fund

Management’s Discussion and Analysis

December 31, 2019 and 2018

The Statements of Cash Flows, using the direct method of presentation, provide information about the Utility’s cash receipts and cash payments during the years presented. These statements report cash and cash‑equivalent activities for each fiscal year resulting from operating activities, noncapital financing activities, capital and related financing activities, and investing activities. These statements also provide answers to such questions as, where did cash come from, what was cash used for, and what was the change in cash balance during the reporting periods.

The Notes to Financial Statements provide the reader with additional information that is essential to a full understanding of the data provided in the basic financial statements.

The Required Supplementary Information presents certain information concerning the progress in funding the Utility’s obligation to provide pension and other postemployment benefits.

Financial Analysis of the Utility

One of the most important questions asked about the Utility’s finances is whether the Utility, as a whole, is better or worse off as a result of the year’s activities.  The Statements of Net Position and the Statements of Revenues, Expenses, and Changes in Net Position report information about the Utility’s activities in ways that will help answer this question. These two statements report the net position of the Utility and changes in net position for each of the years presented. You can think of the Utility’s net position, the difference between assets, deferred outflows of resources, liabilities, and deferred inflows of resources as one way to, over time, provide a measure of the Utility’s financial health or financial position. Over time, increases or decreases in the Utility’s net position can indicate whether its financial health is improving or deteriorating. However, you will need to also consider other non-financial factors such as changes in economic conditions and customer growth, as well as legislative and regulatory mandates.

The Utility’s total net position increased $14.1 million from beginning net position, during 2019 compared to an increase in net position of $18.3 million from beginning net position, as restated, during 2018. The following analysis focuses on the Utility’s net position and changes in net position during the year.

A portion of the Utility’s net position (71.8% and 70.2% as of December 31, 2019 and 2018, respectively) reflects its net investment in capital assets, such as gas and electric production, transmission and distribution facilities, less any related outstanding debt used to acquire those assets. Those capital assets are used to provide services to customers; consequently those assets are not available for future spending or to be used to liquidate any outstanding debt. The changes in net investment in capital assets reflects changes in plant assets over the year as well as changes in the related debt. The slight increase in 2019 was due to depreciation and retirements keeping pace with additions to plant. The decrease in 2018 was due to depreciation and plant retirement exceeding additions to plant.  For an electric utility with aging distribution assets, the construction of new assets is often done to replace older assets, so the increase in plant from new construction is offset by the retirement of older assets. The Utility did not issue any new debt during either 2019 or 2018 and the redemption of debt kept pace with the reduction in plant assets, resulting in little change in the percentage of net position invested in capital assets.

An additional portion of the Utility’s net position (4.9% and 5.3% as of December 31, 2019 and 2018 respectively) represent resources that are subject to external restriction for debt repayment and future operations. The Utility has two categories of restricted net position, restricted for debt service and restricted for operations. These restrictions are imposed by the trust agreement as debt covenants for the Utility’s revenue bonds.

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municipality of anchorage, alaska
electric utility fund

Management’s Discussion and Analysis

December 31, 2019 and 2018

Net position restricted for debt service includes the restricted debt service investment, accrued bond interest and the revenue bond reserve investment offset by the portion of debt used to fund the reserve. The primary difference between the net amounts for 2019 and 2018 is due to market value adjustments to the reserve investments. Those adjustments were negative in 2018 and positive in 2019. Net position restricted for operations is required by bond covenants to be equal to 1/8 of current cash operating expenses. Cash operating expenses were lower in 2019 than 2018.

The unrestricted portion of the Utility’s net position (23.3% and 24.4% as of December 31, 2019 and 2018, respectively) are available to be used to meet the Utility’s obligations to creditors and customers. The changes in unrestricted net position in both 2019 and 2018 are due to an overall positive change in net position, as well as the changes in net position invested in capital assets and restricted net position. The Utility has maintained over $60 million in unrestricted cash, which makes up a large portion of unrestricted net position in both years.

Net Position

Notable components of changes in assets, liabilities, and deferred inflows and outflows of resources are discussed below.

Plant increased $0.2 million during 2019 compared to a decrease of $12.7 million during 2018. The primary reasons for those changes are as follows.  

During 2019, the Utility pursued a vigorous construction schedule, building two new substations and replacing old power poles and continuing to upgrade electric meters to “smart” meters. Additions to construction work in progress (CWIP) during the year were $30.1 million, while $15.1 million in CWIP projects were placed in service. This resulted in net additions to plant assets of $35.9 million, offset by $29.2 million in depreciation and $6.1 million in plant retirements.

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municipality of anchorage, alaska
electric utility fund

Management’s Discussion and Analysis

December 31, 2019 and 2018

During 2018, the construction program resulted in $23.2 million in additions to CWIP, while $31.2 million in CWIP was placed in service. Net additions to plant were $23.5 million, offset by plant retirements of $7.4 million, and depreciation of $28.9 million.

Restricted assets increased $6.0 million during 2019 compared to a decrease $38.9 million during 2018.

During 2019, the primary reasons for the increase was activity in the restricted funds for the gas field. Those funds earned $2.6 million in interest revenue, were increased by $0.7 million in ARO surcharge revenue deposits, $1.9 million in gas sales and $1.8 million in interfund loan principal and interest payments. They were decreased by $0.6 million in rate stabilization payments, and $0.3 million in royalty and tax payments.

During 2018, the Regulatory Commission of Alaska (RCA) allowed the Utility to remove the restriction on $40.6 million in cash collected due to the rate increase and the Utility repaid $9.1 million in tax credits received in prior years from the State of Alaska. These reductions were offset by interest earnings, loan repayments, gas sales and surcharge revenue collections.

Current and other assets increased $5.3 million during 2019 compared to an increase of $27.6 million during 2018.

During 2019, the primary reason for the increase is the increase in the Utility’s equity in general cash pool, or unrestricted cash. This increase continues an upward trend from 2016, due to rate increases; reduction in operating expenses, primarily the cost of fuel for the generators; and the restriction by the RCA on the Utility paying a dividend to the Municipality.

During 2018, the Utility’s equity in general cash pool increased by $29.3 million primarily due to lifting of the restriction of funds collected from customers pursuant to the refundable rate increase granted by the RCA. Other receivables decreased by $1.7 million due to timing of payment of receivables. Prepaid items decreased $2.2 million due to accelerated payments in 2017 for purchased power.

Deferred outflows of resources decreased $0.4 million during 2019 and increased $0.6 million during 2018 as a result of changes in pension related items and accounting for other postemployment benefits.

During 2019, deferred outflows of resources related the pensions decreased significantly and deferred outflows of resources related to other post-retirement benefits decreased slightly due to changes in expectations and assumptions from the prior year.

During 2018, deferred outflows related to other post-retirement benefits were recorded for the first time due to implementation of GASB Statement No. 75.

Current and other liabilities increased $1.5 million during 2019 compared to a decrease of $13.2 million during 2018.

During 2019, accounts payable from current assets increased $1.3 million primarily due to increase in over-recovery of cost of power expenses from customers.

During 2018, accounts payable from current assets decreased $12.5 million primarily due to repaying prior year over-recovery of cost of power expenses from customers, and $0.5 million in pollution remediation liabilities were written off.

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municipality of anchorage, alaska
electric utility fund

Management’s Discussion and Analysis

December 31, 2019 and 2018

Long-term liabilities decreased $1.3 million during 2019 compared to a decrease of $7.2 million in 2018.

During 2019, the ARO was increased by $7.8 million, as a result of a cost of remediation assessment and a reserve study for the gas field. This is offset by a $1.3 million reduction in the pension liability, a reduction of $2.0 million in other postemployment benefits (OPEB) liability, and $7.7 million redemption of bonds.

During 2018, the primary driver of the change was a $0.9 million reduction in the pension liability, the addition of $2.3 million in OPEB liability due to adoption of new accounting standards, and $7.9 million redemption of bonds.

Deferred inflows of resources decreased $3.1 million in 2019 compared to a decrease of $18.9 million in 2018.

During 2019, contributions in aid of construction decreased by $5.3 million due to amortization in 2019 exceeding additions. Future BRU construction or natural gas purchases account increased by $2.0 million primarily $1.8 million in gas sales and $0.5 million in investment earnings.

During 2018, contributions in aid of construction decreased by $2.8 million due to amortization in 2018 exceeding additions. Deferred inflows of resources related to pensions decreased $0.7 million while deferred inflows of resources related to other postemployment benefits of $0.8 million were recorded due to the adoption of a new accounting standard. The future natural gas purchases account increased by $0.7 million in investment earnings and redemption of intercompany debt. Future BRU construction or natural gas purchases account decreased by $16.9 million primarily due to refunding tax credits offset by $2.2 million in gas sales and $0.1 million in investment earnings (see Note 9 (c)).

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municipality of anchorage, alaska
electric utility fund

Management’s Discussion and Analysis

December 31, 2019 and 2018

Revenues, Expenses, and Changes in Net Position

Changes in the Utility’s net position can be determined by reviewing the following condensed schedule of revenues, expenses, and changes in net position for the years ended December 2019, 2018, and 2017:

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municipality of anchorage, alaska
electric utility fund

Management’s Discussion and Analysis

December 31, 2019 and 2018

Revenues by Source:

During 2019total operating revenues were $166.8 million, a decrease of $10.9 million from 2018, compared to $177.7 million and a decrease of $7.7 million during 2018. Total kilowatt hours (kWh) sold decreased by 253.7 million in 2019 compared to an increase of 54.8 million in 2018.  Components of the changes in revenues were:

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municipality of anchorage, alaska
electric utility fund

Management’s Discussion and Analysis

December 31, 2019 and 2018

Residential sales increased by $2.7 million and commercial and industrial sales increased by $10.2 million. and military sales revenue increased by $3.3 million. Sales for resale decreased by $17.5 million during the year. Warmer weather during the year contributed to lower kWh sold to retail customers. Overall, 8.9 million less kWh were sold to retail customers in 2019 than in 2018. Increases in dollar revenues were primarily due to higher Cost of Power Adjustment (COPA) revenues as a result of slightly increased fuel costs for the year. Military sales revenue increased by $3.3 million and kWh sales increased by 871,000. Sales for resale decreased by $17.5 million during the year. Sales for resale is wholesale power sold to other utilities and is dependent on a number of factors such as the cost of buying versus the cost to produce, the availability of power from other sources and price competition among sellers. In 2019, our primary customers purchased from other sources.

Other operating revenues decreased by $9.7 million due to over-recovery of COPA. Non-operating revenues increased by $5.6 million due to an increase in market conditions resulting in higher investment income for the year.

During 2018total operating revenues were $177.7 million, a decrease of $6.7 million from 2017.Military sales revenue decreased by $2.4 million. Commercial and industrial sales decreased by $19.5 million while sales for resale increased by $4.9 million during the year. Retail sales decreases were primarily due to lower COPA. revenues as a result of lower fuel costs for the year and more efficient generation assets. Other operating revenues increased by $12.3 million due to under-recovery of COPA. Non-operating revenues decreased by just under $1 million due to lower investment income as a result of fewer assets invested.

Expenses by Category

Total expenses by category decreased $1.1 million during 2019 compared to a decrease of $11.4 million during 2018. Components of the changes were:

During 2019 operating expenses decreased $1.0 million from 2018 due to a $3.4 million decrease in production expenses (primarily fuel),and a $6.4 million increase in regulatory credits due to repayment of over-collection of COPA from customers. These two numbers are related to each other. Fuel costs are down primarily because of a decrease in fuel costs related to sales for resale. COPA is calculated based on projections of costs in providing that fuel for production. There will always be a variance between projected costs collected from customers and actual costs. Over and under recovery of actual costs are factored into future COPA calculations. Distribution expenses increased by $1 million. Administrative and general expenses decreased $3.4 million due to a loss of personnel, higher than expected recovery of administrative costs through overheads and the negative $2.4 million in OPEB expenses recorded as an adjustment of the OPEB liability in 2019. Non-operating expenses decreased $2.2 million because the Utility did not have a large loss on disposal of property as there was in 2018.

MUSA, which represents payments to the municipal government in lieu of property taxes, remained consistent with 2018, increasing just $80,000 due to an increase in mill rates. 

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municipality of anchorage, alaska
electric utility fund

Management’s Discussion and Analysis

December 31, 2019 and 2018

During 2018 operating expenses decreased $11.7 million from 2017 due to a $4.4 million decrease in production expenses (primarily fuel),and  a $4 million increase in regulatory credits due to repayment of over-collection of COPA from customers. Distribution expenses increased by $1.9 million, administrative and general expenses decreased $1.1 million; depreciation expenses decreased $3.6 million primarily due to retirement of assets. Non-operating expenses increased just $0.4 million primarily due to increased short-term borrowing costs offset by decreases in other miscellaneous and interest expense and loss on disposal of property.

MUSA remained consistent with 2017, increasing just $0.2 million due to a decrease in plant assets and an increase in mill rates.

* Expenses by category excluding regulatory debits (credits)

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municipality of anchorage, alaska
electric utility fund

Management’s Discussion and Analysis

December 31, 2019 and 2018

*Expenses by type excluding regulatory debits (credits)

**Fuel expense includes purchased natural gas, transportation costs, diesel fuel used, and CINGSA.

***Employee expense includes general liability and workers compensation insurance.

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municipality of anchorage, alaska
electric utility fund

Management’s Discussion and Analysis

December 31, 2019 and 2018

Capital Assets – Plant

The Utility’s investment in capital assets as of December 31, 2019 and 2018 was $877.3 million and $877.1 million, respectively (net of accumulated depreciation and depletion.) This included investments in gas and electric production, transmission and distribution related facilities, as well as general items such as buildings and vehicles. Plant increased 0.03% in 2019 and decreased 1.4 % in 2018.

The Utility’s capital assets as of December 31, 2019, 2018, and 2017 were as follows:

During 2019, the Utility completed some upgrades to its older generating units and replaced overhead line systems and continued undergrounding projects. Construction projects still in progress at year end included the rebuild of substation 8, several large cable undergrounding projects, generating Unit 7 cooling water skid and the major overhaul of Eklutna hydroelectric generator Unit 2.

During 2018, the Utility performed a major overhaul of one of its two hydroelectric generators at Eklutna and continued to upgrade its distribution lines, both overhead and underground. Construction projects still in progress at year end included generating Unit 7 cooling water skid, SCADA system upgrade and undergrounding projects.

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municipality of anchorage, alaska
electric utility fund

Management’s Discussion and Analysis

December 31, 2019 and 2018

Long Term Debt – Revenue Bonds and Notes Payable

As of December 31, 2019 and 2018, the Utility had outstanding long-term debt of $515.5 million and $524.4 million, respectively.

The Utility’s long-term debt as of December 31, 2019, 2018, and 2017, were as follows:

The Utility has not issued new revenue bonds since 2014. It is the intention of the Municipality to redeem or defease all long term debt pursuant to the sale of the Utility in 2020.

Bond Rating

At December 31, 2019, the Utility maintains the following underlying credit ratings:

Standard & Poor’s	A+
Fitch	A+

In February 2020, Standard & Poor’s reaffirmed the A+ rating of the Utility’s Senior Debt. In January 2020, Fitch opted to do an internal review in light of the pending sale of the Utility and did not change its rating at that time.

Currently Known Facts, Decisions and Conditions

Sale of the Utility

On April 3, 2018, Anchorage voters approved an amendment to the Anchorage Municipal Charter authorizing the Municipality to sell the Utility to Chugach Electric Association (CEA) by Municipal ordinance. An asset purchase and sale agreement has been approved by the Anchorage Municipal Assembly and CEA’s board of directors.

On May 28, 2020, the RCA issued an order addressing the acquisition dockets and approving the sale if the parties agree to modify the proposed transaction as required in the final order. (See Note 9(i)). At this time, CEA, the Municipality, and all the other parties in the docket have yet to decide whether they accept the conditions as ordered by the RCA. If they do accept the conditions and the acquisition goes forward, the expected closing date will be in the fall of 2020.

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municipality of anchorage, alaska
electric utility fund

Management’s Discussion and Analysis

December 31, 2019 and 2018

A successful acquisition of most of the assets of the Utility by CEA would have a significant effect on the financial position and results of operations of the Utility. The agreement, as approved with conditions by the RCA, requires that the Utility retain only the generation assets of Eklutna Hydroelectric Project and sell power to Chugach Electric Association (CEA) and Matanuska Electric Association (MEA) from those assets. (See Note 13).

Global Pandemic

In late January 2020 the World Health Organization (“WHO”) announced a global health emergency regarding a new strain of virus called coronavirus (COVID-19). This virus originated from within China, and spread globally, including Alaska.  Further, in March 2020, the WHO classified the coronavirus as a pandemic. On March 12, 2020, the mayor of Anchorage declared a state of emergency to protect and preserve public health and safety, and subsequently closed all civic, cultural and recreational facilities in the Municipality. The governor of Alaska declared a public health disaster as did the President of the United States. The governor instituted a number of public health measures that affected intrastate and interstate travel and the movement of goods and services.

Management is actively monitoring the global situation and assessing its effect on the Utility’s financial condition, liquidity, operations, supply chain, and workforce. Given the daily evolution of the COVID-19 outbreak and the global responses to curb its spread, the Utility is not able to estimate the effects of the COVID-19 outbreak on its results of operations, financial condition, or cash flows for fiscal year 2020, however, the Utility expects a longer receivables cycle and potential reduction in commercial sales during the economic slowdown that appears to be resulting from the health emergency.

The state legislature has passed legislation that could enable the Utility or its successor to recover in future rates some of the impact of unpaid utility bills and extraordinary expenses related to responding to the emergency. The legislation also provides for deferred payment agreements with customers affected by the pandemic and needing to defer payment of their electric bills to future periods. Management anticipates a negative impact on its short-term cash flows as a result of these arrangements.

Cares Act Funding

On March 27, 2020 the President signed into law the “Coronavirus Aid, Relief and Economic Security (CARES) Act.” The CARES Act, among other things, appropriated funds for the Coronavirus Relief Fund to be used to make payments for specified uses to states and certain local governments. There is no assurance the Utility is eligible for these funds or will be able to obtain them. The Utility continues to examine the impact that the CARES Act may have. Currently, the Utility is unable to determine the impact that the CARES Act will have on the Utility’s financial condition, results of operations or liquidity.

Contacting the Utility’s Financial Management

This financial report is designed to provide our customers, citizens, and creditors with a general overview of the Utility’s finances and to demonstrate the Utility’s accountability for the money it receives. If you have any questions about this report or need additional financial information, contact the Utility’s Acting Chief Financial Officer, Mollie C. Morrison, at (907) 263‑5205.

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statements of Net Position

December 31, 2019 and 2018

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statements of Net Position, continued

December 31, 2019 and 2018

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Statements of Revenues, Expenses and Changes in Net Position

For the Years Ended

December 31, 2019 and 2018

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Statements of Cash Flows

For the Years Ended

December 31, 2019 and 2018

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Statements of Cash Flows, continued

For the Years Ended

December 31, 2019 and 2018

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

(1)Description of Business and Summary of Significant Accounting Policies

The first electric system serving Anchorage was installed in 1916 by the Alaska Engineering Commission, the agency of the United States Department of the Interior which constructed the Alaska Railroad.  A small steam plant and several diesel power generators supplied Anchorage with electricity until 1929 when the private Anchorage Power and Light Company began supplying the community with electricity from a hydroelectric power plant on the Eklutna River located 15 miles northeast of downtown Anchorage. The Alaska Engineering Commission distribution system was purchased by Anchorage in 1932. Anchorage then acquired the Eklutna plant from the Anchorage Power and Light Company in 1943. This is what is now Anchorage Municipal Light and Power or the Electric Utility Fund, a public utility of the Municipality of Anchorage.  The Utility now has six turbine generating units fired by natural gas and one heat recovery steam turbine generating unit. The Utility also has a thirty percent ownership in Southcentral Power Project and fifty-three and one-third percent ownership interest in the Eklutna Hydroelectric Project and is entitled to twenty-five and nine-tenths percent of the output of the Bradley Lake Hydroelectric Project. The Utility meets the majority of its natural gas requirements from its ownership interest in the Beluga River Gas Field (BRU), including the initial one-third interest acquired in December 1996. The Utility’s goal in acquiring the  working interest in the BRU was to lock in a critical resource for the long-term and provide a hedge against anticipated future increases in natural gas prices.  During 2016 the Utility acquired 70% of a one-third working interest in the field from ConocoPhillips Alaska, Inc.(CPAI), increasing its working interest to 56.67%.

The accompanying financial statements include the activities of the Utility.  The Utility is a major enterprise fund of the Municipality and not the Municipality as a whole. The Utility is subject to the regulatory authority of the RCA.

The Utility applies all applicable provisions of the Governmental Accounting Standards Board (GASB) which has authority for setting accounting standards for governmental entities.The accounting records of the Utility conform to the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC).

Accounting and reporting treatment applied to the Utility is accounted for on a flow of economic resources measurement focus using the accrual basis of accounting. Revenues are recognized when they are earned and expenses are recognized at the time liabilities are incurred. Operating revenues and expenses generally result from providing services and producing and delivering goods in connection with the Utility’s principal ongoing operations. All other revenues and expenses are reported as non-operating.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Description of Business and Summary of Significant Accounting Policies, continued

(a)    Regulated Operations

The Utility meets the criteria, and accordingly follows the accounting and reporting requirements applicable to regulated operations. The Utility’s rates are regulated by the RCA and as a result, revenues intended to recover certain costs are provided either before or after the costs are incurred, resulting in regulatory assets or liabilities. The following regulatory assets and liabilities are reflected in the accompanying financial statements:

· The Utility receives contributions in aid of construction, which it records as contributed plant in service and a deferred inflow of resources.  The Utility amortizes contributed plant and the deferred inflow of resources over the useful life of the utility plant.

· The Utility accepted a monetary settlement in 2015 from its BRU partners for its 2014 underlift.  The Utility used these funds to reduce its Gas Transfer Price (GTP) from July 1, 2016 through June 30, 2017.  See Note 9(a).

· The Utility has a regulatory asset or liability account to capture the difference in the cost of power and revenue received through the Cost of Power Adjustment (COPA).  See Note 9(b).

· The Utility has a regulatory asset or liability account to capture the difference in the amount of the Gas Fund revenue requirement and the actual amount of revenue collected from the Electric Fund. See Note 9(b).

· The Utility records proceeds from the sales of gas, net of royalties, taxes and an Asset Retirement Obligation (ARO) surcharge, as a regulatory liability, reported as deferred inflows of resources on the statements of net position. See Note 9(c).

· The Utility funds ARO expenses associated with future abandonment of the BRU through a surcharge to the Utility’s GTP, which is deposited into a sinking fund. See Note 9(c) and (d).

Management believes that the recorded amounts of all regulatory assets are fully recoverable from ratepayers in the future.

(b)    Management Estimates

In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and deferred outflows of resources, liabilities and deferred inflows of resources and the reporting of contingent assets and liabilities as of the date of the statement of net position and revenues and expenses for the period. Actual results could differ from those estimates. The more significant accounting and reporting policies and estimates applied in the preparation of the accompanying financial statements are discussed below.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Description of Business and Summary of Significant Accounting Policies, continued

(c)   Cash Pools and Investments

The Municipality uses a central treasury to account for all cash and investments to maximize interest. Interest income on cash pool investments is distributed based on the average daily balance in the general cash pool.  The Utility’s investments are reported at fair value in the financial statements.

(d) Statements of Cash Flows

For purposes of the statements of cash flows, the Utility has defined cash as the demand deposits and all investments maintained in the general cash pool, regardless of maturity period, since the Utility uses the cash pools essentially as demand deposit accounts. Restricted assets in the general cash pool, except for customer deposits, have not been included in the definition of cash.

(e)   Restricted Assets

Certain proceeds of the Utility’s revenue bonds, as well as resources set aside for their repayment, are classified as restricted assets on the statements of net position because their use is limited by applicable bond covenants. The revenue bond reserve investment account is used to report resources set aside to augment potential deficiencies from Utility operations that could adversely affect debt service payments. The debt service investment account is used to segregate resources accumulated for debt service payments over the next twelve months. The revenue bond operations and maintenance investment account represents funds set aside to comply with bond covenants requiring a reserve equal to one‑eighth of the preceding year’s operating expenses (as defined in the bond covenants).

The restricted equity in general cash pool-customer deposits account represents deposits provided by electric service customers as security for bill payment. Future natural gas purchases or BRU construction and ARO sinking fund investments are funds for which the RCA has specified the use.

(f)    Inventories

Inventories are valued at weighted average cost. The cost of inventories are recorded as expenses when consumed rather than when purchased. Inventories consist of parts and materials used to maintain or build new transmission, distribution, and generation facilities. Scrap and nonusable materials in inventory are carried at net estimated realizable value until sold or otherwise disposed of.

The Utility also stores natural gas in a depleted field on the Kenai Peninsula. Cook Inlet Natural Gas Storage Alaska (CINGSA) started in 2012 and as of December 31, 2019 the Utility has stored 9.58 billion cubic feet of gas.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Description of Business and Summary of Significant Accounting Policies, continued

(g)    Property, Plant and Equipment

Electric

Capital assets are stated at cost. Depreciation is computed by use of the straight‑line method over the estimated economic life of the asset. Additions to electric plant in service are at original cost of items such as contracted services, direct labor and materials, indirect overhead charges and allowance for funds used during construction. The Utility capitalizes general plant assets valued at more than $25,000 that have an expected life in excess of one year. Contributed assets are recorded at the cost incurred by the Utility for the addition of such assets. Donated assets are recorded at acquisition value. Acquisition value is the price that would be paid to acquire an asset with equivalent service potential in an orderly market transaction at the acquisition date. For property replaced or retired, the cost of the property unit, plus removal costs less salvage, is charged to accumulated depreciation. Gain or loss is not recognized unless the Utility determines that such costs could not be recovered in rates. Costs for maintenance and repairs are expensed as incurred, except for major maintenance on generation assets, for which costs are collected into a regulatory asset and amortized over the period of utility, generally three to five years.

The Utility capitalizes Allowance for Funds Used During Construction (AFUDC) as a means to capture the cost of using both debt and equity funds to finance utility plant additions during the construction period in accordance with regulatory requirements. AFUDC of $595,493 and $638,303 were capitalized for the years ending December 31, 2019 and 2018, respectively.

Estimated lives of major plant and equipment categories follow:

Gas

The acquisition of assets purchased with designated underlift settlement funds and Utility equity funds  are being amortized using the units of production method, based upon proven reserves in accordance with the amortization method used for regulatory purposes.  The acquisition of assets purchased with gas sale proceeds, and assets acquired from CPAI in the 2016 purchase, are being recorded as contributed plant and are being amortized using the units of production method, based on proven reserves in accordance with the amortization method used for regulatory purposes. No AFUDC is capitalized for gas field assets.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Description of Business and Summary of Significant Accounting Policies, continued

(h)    Unbilled Revenues and Accounts Receivable

Electric revenues are based on cycle billings rendered to customers monthly. As a result of this cycle billing method, the Utility does not accrue revenue at the end of any fiscal period for services sold but not billed at such date. The unbilled revenues for the Utility are immaterial. An allowance for doubtful accounts is provided for receivables where there is a question of collectability. Utility receivables are presented in the statements of net position net of estimated uncollectible amounts.

Other receivables are primarily related to sales of electricity outside of the usual retail billing processes. The largest components of these receivables are related to sales of electricity to the military bases and wholesale sales for resale to other electric utilities.

Gas sales are calculated based upon volumes delivered and recorded as a regulatory liability, which is reported as deferred inflows of resources on the statements of net position (see Note 9(c)).

(i)    Gas Balancing

The Utility has elected to account for underlifted gas from its ownership interest in the BRU according to the sales method. Therefore, the financial statements do not include a receivable or revenue for underlifted volumes for which the Utility did not elect to receive cash settlement. As of December 31, 2019 and 2018, the (overlift)/underlift balance was (521) and 23,106 Mcf, respectively. The Utility also has the option per the Gas Balancing Agreement to take cash settlements for any underlifted gas. 

(j)    Asset Retirement Obligation (ARO)

The Utility accounts for its ARO for its interest in the BRU in accordance with Accounting Standards Codification (ASC) Topic 980-410-20, formerly Statement of Financial Accounting Standards No 143, “Accounting for Asset Retirement Obligations” (SFAS No 143) and 18 CFR 101 General Instruction No 25, Accounting for Asset Retirement Obligations (Regulations of the Federal Energy Regulatory Commission, Department of Energy, or FERC). ASC 980-410-20 and FERC General Instruction No 25 applies to the fair value of a liability for an ARO that is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Obligations associated with the retirement of these assets require recognition of: (1) the present value of a liability and offsetting asset for an ARO, (2) the subsequent accretion of that liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount rates.

In 2012 the Utility made its initial recording of the ARO asset and ARO liability with a beginning balance of $1,461,335 representing the fair value of the obligation at 1996 – the period when the obligation was incurred. The Utility recorded in 2012 $4,185,549 to the ARO liability representing total accretion expense that would have been incurred if the liability was accreted from the time the obligation was incurred through December 31, 2012. During 2013, the Utility commissioned a study of the costs associated with abandoning the BRU field and as a result of the findings of that study, adjusted the ARO liability and accretion as of December 2013.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Description of Business and Summary of Significant Accounting Policies, continued

Asset Retirement Obligation (ARO), continued

On April 22, 2016, the Utility purchased 70% of CPAI’s one-third interest in the BRU. At that time a revised estimate was made of the life of the gas field. The Utility’s obligation for an ARO was adjusted for the increased liability and changes in estimated life and discount rate.

During 2019, the Utility commissioned a study of the costs associated with abandoning the BRU field and also a study of remaining gas reserves, and, as a result of the findings of both studies, the Utility adjusted the ARO liability and accretion, for regulatory purposes as of January 1, 2019.

As of December 31, 2016, the Utility entered into an agreement with the State of Alaska Department of Natural Resources (DNR) to establish an ARO investment fund to meet its obligations for dismantling, removing and restoring the land and property to a condition acceptable to the commissioner of the DNR in accordance with the terms and conditions of assigned leases and applicable statutes and regulations. The balance of the ARO investment fund was $16,342,806 and $13,915,853 at December 31, 2019 and 2018, respectively.

A schedule of changes in the ARO balance for the years ending December 31, 2019 and 2018 is as follows:

(k)    Discount or Premium on Revenue Bonds Payable

The discount or premium on revenue bonds payable is amortized over the life of the related bond issues using the effective interest method.

(l)    Compensated Absences

The Utility records employee leave, which includes sick leave, when earned.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Description of Business and Summary of Significant Accounting Policies, continued

(m)Deferred Outflows and Inflows of Resources

The Utility enters into transactions that result in the consumption or acquisition of resources in one period that are applicable to future periods. These consumptions and acquisitions of resources are reported in the statements of net position as deferred outflows and inflows of resources, respectively. The Utility records deferred outflows of resources related to pensions, other postemployment benefits and deferred loss on refunding of bonds, and deferred inflows of resources related to pensions and other postemployment benefits, contributions in aid of construction and certain items related to the operation of the BRU.

(n)    Net Position

The Utility’s net position is categorized as net investment in capital assets, restricted or unrestricted. The Utility’s restricted net position represents assets restricted for payment of debt service, or restricted for operations, in accordance with covenants of the related revenue bond indentures. It is the Utility’s policy to evaluate whether to use restricted or unrestricted resources to make certain payments, on a case by case basis, when both restricted and unrestricted assets are available for the same purposes.

(o)    Intragovernmental Charges

Certain functions of the Municipality of a general and administrative nature are centralized and the related costs are allocated to the various funds of the Municipality, including the Utility. Such costs allocated to the Utility totaled $4,765,388 and $4,214,954 for the years ended December 31, 2019 and 2018, respectively, including general liability and workers compensation of $537,311 for 2019 and $660,414 for 2018.

(p)   Utility Revenue Distribution/Municipal Service Assessment (MUSA)

Prior to 2006, the RCA restricted the Utility from making a revenue distribution or paying the gross receipts portion of the MUSA.  That restriction was removed in December 2005.  The Utility made an annual revenue distribution to the Municipality for the years 2006 - 2015, which by Ordinance, was up to a maximum of 5% of the Utility’s gross revenues, excluding restricted revenues. During those years the Utility also included the gross receipts portion, considered supplemental MUSA, at 1.25% times the actual gross operating revenues in its payment of MUSA. During 2017, the Municipality eliminated the gross receipts portion of the MUSA and revised the methodology for calculating the Utility Revenue Distribution.

Beginning January 1, 2016, the Utility is restricted by the RCA from making revenue distributions to the Municipality, with the exception of MUSA. The Utility’s distribution for MUSA in 2019 and 2018 was $9,645,938 and $9,565,771, respectively.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Description of Business and Summary of Significant Accounting Policies, continued

(q)    Environmental

The Utility has adopted an aggressive policy designed to identify and mitigate the potential effects of past, present, and future operational activities that may result in environmental impact. It is the Utility’s accounting policy to record a liability when the likelihood of responsibility for an environmental impact is probable and the cost of mitigating the impact is estimable within reasonable limits. Such costs are capitalized if they result in an extension of the assets’ life, increase the capacity, or improve the safety or efficiency of property owned by the Utility; or mitigate or prevent environmental contamination that has yet to occur and that otherwise may result from future operations or activities. There were no environmental issues that met the Utility’s accounting policy and accordingly, no provision has been made in the accompanying financial statements for any potential liability.

(r)    Net Pension Liability

For purposes of measuring net pension liability, deferred outflows and inflows of resources related to pensions and pension expenses, information about the fiduciary net position of the Public Employees’ Retirement System (PERS) and additions to/from PERS’ fiduciary net position have been determined on the same basis as they are reported by PERS. For this purpose, benefit payments (including refunds of employee contributions) are recognized when due and payable in accordance with the benefit terms. Investments are reported at fair value. Details regarding the net pension liability are discussed in Note 7.

(s)    Net Other Postemployment Benefits (OPEB) Liability

For purposes of measuring net OPEB liability, deferred outflows and inflows of resources related to OPEB and OPEB expenses, information about the fiduciary net position of PERS and additions to/from PERS’ fiduciary net position have been determined on the same basis as they are reported by PERS. For this purpose, benefit payments (including refunds of employee contributions) are recognized when due and payable in accordance with the benefit terms. Investments are reported at fair value. Details regarding the net OPEB liability are discussed in Note 7.

(t)    Reclassifications

Certain amounts previously reported may have been reclassified to conform to current presentations. The reclassifications had no effect on the previously reported change in net position.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

(2)    Change in Accounting Principle

As discussed in Note 7 to the financial statements, the Utility participates in the PERS plans. In 2018, the Utility adopted the provisions of GASB Statement No. 75 Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions, which, among other accounting and reporting criteria, requires the Utility to recognize its proportional share of the net OPEB liability (and related deferred inflows and outflows of resources), as of the beginning of the Utility’s fiscal year. As a result of the implementation of this statement, the Utility recorded an opening balance adjustment in 2018 to reflect opening balance OPEB liabilities and related accounts and to decrease opening net position as follows:

(3)    Cash and Investments

At December 31, 2019 and 2018, the Utility had cash and investments in the Municipality’s general cash pool (Central Treasury). The Utility also carries certain balances in a separate account for Asset Retirement Obligations. At December 31, 2019 and 2018, the Utility had the following cash and investments, with fixed income maturities as noted:

December 31, 2019:

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Cash and Investments, continued

December 31, 2019, continued

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Cash and Investments, continued

December 31, 2018:

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Cash and Investments, continued

(a)   Municipal Central Treasury

The Municipality manages its Central Treasury in four portfolios; one internally managed portfolio and three externally managed duration portfolios based on liability duration and cash needs: working capital, contingency reserve and strategic reserve.

The Municipality maintains a comprehensive policy over cash and investments that is designed to mitigate risks while maximizing investment return and providing for operating liquidity. Pursuant to Anchorage Municipal Code (AMC) 6.50.030, the Municipality requires investments to meet specific rating and issuer requirements. 

Both externally and internally managed investments are subject to the primary investment objectives outlined in AMC 6.50.030, in priority order as follows: safety of principal, liquidity, return on investment and duration matching. Consistent with these objectives, AMC 6.50.030 authorizes investments that meet the following rating and issuer requirements:

· Obligations issued or guaranteed by the U.S. government, U.S. agencies or U.S. government sponsored corporations and agencies.

· Corporate debt securities that are guaranteed by the U.S. government or the Federal Deposit Insurance Corporation (FDIC) as to principal and interest.

· Taxable and tax-exempt municipal securities having a long-term rating of at least A- by a nationally recognized rating agency or taxable or tax-exempt municipal securities having a short-term rating of at least A-1 by Standard & Poor’s, P-1 by Moody’s, or F-1 by Fitch.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Cash and Investments, continued

Municipal Central Treasury, continued

· Debt securities issued and guaranteed by the International Bank for Reconstruction and Development (IBRD) and rated AAA by a nationally recognized rating agency.

· Commercial paper, excluding asset-backed commercial paper, rated at least A-1 by Standard & Poor’s, P-1 by Moody’s, or F-1 by Fitch.

· Bank debt obligations, including unsecured certificates of deposit, notes, time deposits, and bankers’ acceptances (with maturities of not more than 365 days), and deposits with any bank, the short-term obligations of which are rated at least A-1 by Standard & Poor’s, P-1 by Moody’s, or F-1 by Fitch and which is either:

a) Incorporated under the laws of the United States of America, or any state thereof, and subject to supervision and examination by federal or state banking authorities; or

b) Issued through a foreign bank with a branch or agency licensed under the laws of the United States of America, or any state thereof, or under the laws of a country with a Standard & Poor’s sovereign rating of AAA, or a Moody’s sovereign rating for bank deposits of Aaa, or a Fitch national rating of AAA, and subject to supervision and examination by federal or state banking authorities.

· Repurchase agreements secured by obligations of the U.S. government, U.S. agencies, or U.S. government-sponsored corporations and agencies.

· Dollar denominated corporate debt instruments rated BBB- or better (investment grade) by Standard & Poor’s or the equivalent by another nationally recognized rating agency.

· Dollar denominated corporate debt instruments rated lower than BBB- (non-investment grade) by Standard & Poor’s or the equivalent by another nationally recognized rating agency, including emerging markets.

· Dollar denominated debt instruments of foreign governments rated BBB- or better (investment grade) by Standard & Poor’s or the equivalent by another nationally recognized rating agency.

· Asset Backed Securities (ABS), excluding commercial paper, collateralized by: credit cards, automobile loans, leases and other receivables which must have a credit rating of AA- or above by Standard & Poor’s or the equivalent by another nationally recognized rating agency.

· Mortgage Backed Securities, including generic mortgage-backed pass-through securities issued by Ginnie Mae, Freddie Mac, and Fannie Mae, as well as non-agency mortgage-backed securities, Collateralized Mortgage Obligations (CMOs), or Commercial Mortgage-Backed Securities (CMBS), which must have a credit rating of AA- or better by Standard & Poor’s or the equivalent by another nationally recognized rating agency.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Cash and Investments, continued

Municipal Central Treasury, continued

· Debt issued by the Tennessee Valley Authority

· Money Market Mutual Funds rated Am or better by Standard & Poor’s, or the equivalent by another nationally recognized rating agency, as long as they consist of allowable securities as outlined above.

· The Alaska Municipal League Investment Pool (AMLIP), except that the Working Capital portfolio may not be invested in AMLIP.

· Mutual Funds consisting of allowable securities as outlined above.

· Interfund Loans from a Municipal Cash Pool to a Municipal Fund.

In addition to providing a list of authorized investments, AMC 06.50.030 specifically prohibits investment in the following:

· Structured Investment Vehicles.

· Asset Backed Commercial Paper.

· Short Sales.

· Securities not denominated in U.S. Dollars.

· Commodities.

· Real Estate Investments.

Derivatives, except “to be announced” forward mortgage-backed securities (TBAs) and derivatives for which payment is guaranteed by the U.S. government or an agency thereof.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

The Investment Management Agreement (IMA) for each external manager and the policy and procedures (P&P) applicable to the internally managed investments provide additional guidelines for each portfolio’s investment mandate. The IMA limits the concentration of investments for the Working Capital portfolio at the time new investments are purchased as follows, with year-end concentrations listed for 2019 and 2018:

The P&P limits the concentration of investments for the internally managed portfolio at the time new investments are purchased as follows, with year-end concentrations listed for 2019 and 2018:

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

(b)   Beluga River Asset Retirement Obligation Fund

Funds set aside to pay for dismantling, removing, and restoring assets of the Beluga River Unit gas field were transferred from the MOA Central Treasury to a separate investment portfolio in 2017, per assembly ordinance. 

The Beluga River Asset Retirement Obligation Fund is managed to maximize capital appreciation with a long-term rate of return. The Fund is authorized to invest in the following assets:

· Domestic equities and International equities, including real estate investment trusts.

· Investment grade dollar-denominated fixed income securities.

· Cash and money market instruments.

The Beluga River Asset Retirement Obligation Fund limits the concentration of its investments as follows:

(c)   Interest Rate Risk

Interest rate risk is the risk that changes in interest rates will adversely affect the fair value of an investment. The externally managed portfolios of the Municipal Central Treasury utilize the duration method to measure exposure to interest rate risk.

Duration is a measure of an investment’s sensitivity to interest rate changes, and represents the sensitivity of an investment’s market price to a one percent change in interest rates. The effective duration of an investment is determined by its expected future cash flows, factoring in uncertainties introduced through options, prepayments, and variable rates. The effective duration of a pool is the average fair value weighted effective duration of each security in the pool.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Cash and Investments, continued

Interest Rate Risk, continued

AMC 6.50.030 requires the Working Capital Portfolio have a duration of zero to 270 days.  At December 31, 2019, the Working Capital Portfolio had a duration of 0.09 years, or approximately 33 days, and was within the targeted duration. At December 31, 2018, the Working Capital Portfolio had a duration of 1.37 years, or approximately 500 days, and was not within the targeted duration. AMC 6.50.030 also requires that the Contingency Reserve Portfolio have an average duration within half a year of its benchmark. At December 31, 2019, the Contingency Reserve Portfolio had a duration of 1.83 years as compared to its benchmark, Barclays 1-3 Year Government Index, which had a duration of 1.87 years. At December 31, 2018, the Contingency Reserve Portfolio had a duration of 1.83 years as compared to its benchmark, Barclays 1-3 Year Government Index, which had a duration of 1.90 years. AMC 6.50.030 requires the Strategic Reserve Portfolio have a maximum duration no greater than one year in excess of its benchmark.

At December 31, 2019, the Strategic Reserve Portfolio had a duration of 3.21 years as compared to its benchmark, Barclays Intermediate Government/Corporate Index, which had a duration of 3.62 years. At December 31, 2018, the Strategic Reserve Portfolio had a duration of 3.12 years as compared to its benchmark, Barclays Intermediate Government/Corporate Index, which had a duration of 2.91 years.

The effective duration of the externally managed portfolio of the Municipal Central Treasury working capital portfolio at December 31, 2019, was 0.09 years, which is within the targeted duration of +/-.25 years of the Merrill Lynch 90-day Treasury Bill Index, as required per Alaska Permanent Capital Management Investment Manager Agreement. The effective duration of the contingency reserve and strategic reserve portfolios at December 31, 2019, were 1.83 years, and 3.21 years, respectively, which are within the required durations per the policy.

The effective duration of the externally managed portfolio of the Municipal Central Treasury working capital portfolio at December 31, 2018, was 1.37 years, which is not within the targeted duration of +/-.25 years of the Merrill Lynch 90-day Treasury Bill Index, as required per Alaska Permanent Capital Management Investment Manager Agreement. The effective duration of the contingency reserve and strategic reserve portfolios at December 31, 2018, were 1.83 years, and 3.12 years, respectively, which are within the required durations per the policy.

The Beluga River Asset Retirement Obligation Fund does not have Investment Policies addressing interest rate risk.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Cash and Investments, continued

(d)   Credit Risk

Credit risk is the risk that an issuer or other counterparty to an investment will not fulfill its obligations. For fixed income securities, this risk is generally expressed as a credit rating.

At December 31, 2019, the Municipal Central Treasury’s investment in marketable debt securities, excluding U.S. Treasuries, totaled $248,214,420. The distribution of ratings on these securities was as follows:

At December 31, 2018, the Municipal Central Treasury’s investment in marketable debt securities, excluding U.S. Treasuries and Agencies, totaled $185,136,594. The distribution of ratings on these securities was as follows:

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Cash and Investments, continued

Credit Risk, continued

At December 31, 2019 and 2018, the Beluga River Asset Retirement Obligation Fund investment in fixed income securities, excluding U.S. Treasuries, totaled $4,900,063 and $5,015,367, respectively. The distribution of Moody’s ratings on these securities was as follows:

(e)   Concentration of Credit Risk

Concentration of credit risk is the risk of loss attributed to the magnitude of an entity’s investment in a single issuer. GASB Statement No. 40 requires disclosure when the amount invested in a single issuer exceeds 5 percent or more of total investments. Investments issued or explicitly guaranteed by the U.S. Government, as well as mutual funds and other pooled investments, are exempted from this requirement. At December 31, 2019, the Municipal Cash Pool held investments in the Federal Farm Credit Bank that were 6.57 percent of the Municipal Cash Pool’s investments.

The Beluga River Asset Retirement Obligation Fund has no policy regarding concentration of holdings with a single issuer. 

At December 31, 2019, more than 5 percent of the Beluga River Asset Retirement Obligation Fund’s investments were held with the Federal Home Loan Mortgage Corporation and Federal National Mortgage Association.  These investments are 7.06 percent and 9.01 percent, respectively, of the Beluga River Asset Retirement Obligation Fund’s total investments. At December 31, 2018, more than 5 percent of the Beluga River Asset Retirement Obligation Fund’s investments were held with the Federal Home Loan Mortgage Corporation and Federal National Mortgage Association.  These investments are 8.18 percent and 9.32 percent, respectively, of the Beluga River Asset Retirement Obligation Fund’s total investments.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Cash and Investments, continued

(f)   Custodial Credit Risk

Custodial credit risk is the risk, in event of the failure of a depository institution, that an entity will not be able to recover deposits or collateral securities in the possession of an outside party. For investments, custodial credit risk is the risk, in event of the failure of the counterparty to a transaction, that an entity will not be able to recover the value of the investment or collateral securities in the possession of an outside party. All collateral consists of obligations issued, or fully insured or guaranteed as to payment of principal and interest, by the United States of America, an agency thereof or a United States government sponsored corporation, with market value not less than the collateralized deposit balances. 

AMC 6.50.030 requires that repurchase agreements be secured by obligations of the U.S. government, U.S. agencies, or U.S. government-sponsored corporations and agencies. As of December 31, 2019 and 2018 cash deposits and investments were not exposed to custodial credit risk.

 (g)  Foreign Currency Risk

Foreign currency risk is the risk that changes in exchange rates will adversely impact the fair value of an investment. The Municipality has no specific policy addressing foreign currency risk; however foreign currency risk is managed through the requirements of AMC 6.50.030 and the asset allocation policies of each portfolio.

The Municipal Central Treasury is not exposed to foreign currency risk because AMC 6.50.030 explicitly prohibits the purchase of securities not denominated in U.S. Dollars. At December 31, 2019 and 2018, all debt obligations held in the Municipal Central Treasury were payable in U.S. Dollars.

The Asset Retirement Obligation Fund invests in dollar denominated exchange traded international equity funds which are broadly diversified across currencies, effectively limiting foreign currency risk.

44

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Cash and Investments, continued

(h)  Fair Value Measurements

At December 31, 2019 and 2018, the Municipality had investments valued as follows:

· Asset-backed securities are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings.

· Short-term collective investments such as money market funds are valued at amortized cost.

· Commercial paper is valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings.

· Corporate bonds are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings.

· Domestic equity funds are valued at the closing price reported on the active market on which the individual funds traded.

· International equity funds are valued at the closing price reported on the active market on which the individual funds traded.

· Municipal bonds are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings.

· Real estate funds are valued at the closing price reported on the active market on which the individual funds traded.

· Repurchase agreements are valued at amortized cost.

· U.S Treasuries are valued at the closing price reported on the active market on which the individual securities traded.

· U.S Agencies are valued using pricing models maximizing the use of observable inputs for similar securities.

· U.S TIPs are valued at the closing price reported on the active market on which the individual securities traded.

45

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Cash and Investments, continued

Fair Value Measurements, continued

The Municipality utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Municipality determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principle or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:

•Level 1 Inputs: quoted prices for identical assets or liabilities in active markets

•Level 2 Inputs: quoted prices for similar assets or liabilities in active or inactive markets; or inputs other than quoted prices that are observable

•Level 3 Inputs: significant unobservable inputs for assets or liabilities

The Municipality categorizes its fair value measurements within the fair value hierarchy established by generally accepted accounting principles. The Municipality as a whole has the following recurring fair value measurements as of December 31, 2019 and 2018:

December 31, 2019:

46

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Cash and Investments, continued

Fair Value Measurements, continued

December 31, 2019, continued:

47

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Cash and Investments, continued

Fair Value Measurements, continued

December 31, 2018:

48

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

(4)Capital Assets

A summary of capital assets at December 31, 2019 follows:

49

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Capital Assets, continued

A summary of capital assets at December 31, 2018 follows:

(5)Long‑Term Liabilities

(a)   Revenue Bonds Payable

A summary of revenue bonds payable consist of the following at December 31:

50

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Long‑Term Liabilities, continued

Revenue Bonds Payable, continued

Debt service requirements to maturity at December 31, 2019 are as follows:

The Utility’s revenue bonds bear interest at effective rates of 3.75% to 6.5% and require the establishment of reserves over a five‑year period at least equal to the maximum annual debt service on all outstanding senior lien bonds. The senior lien revenue bond covenants further stipulate that net revenue before depreciation and amortization for each year will be equal to at least 1.35 times the debt service requirements for that year. At December 31, 2019 and 2018, the Utility had satisfied the reserve requirements and debt service covenants. The Utility has pledged future customer revenues, net of specified operating expenses, to repay revenue bonds. Proceeds from the bonds provided financing for construction and other capital improvements. The bonds are payable solely from customer net revenues and are payable through 2044. The total principal remaining and interest to be paid on the bonds for the years ended December 31, 2019 and 2018 was $537,069,783 and $561,750,529, respectively. Principal and interest paid for the years ended December 31, 2019 and 2018 were $24,680,747 and $25,178,098, respectively. Total customer net revenues for the years ended December 31, 2019 and 2018 were $62,569,791 and $62,308,872, respectively.

As a condition of the sale of the Utility, (See Note 13) the Municipality is obligated, under its Charter, to retire all debt of the Utility.  Therefore, on the closing date of the sale, the Municipality i) will retire all outstanding 2005 Revenue Bonds, ii) will retire all outstanding 2009 Revenue Bonds, iii) will defease all outstanding 2014 Revenue Bonds to their maturity date or the first call date of December 1, 2024, whichever occurs first.

(b)   Notes from Direct Borrowings

In February 2012, the Assembly authorized the issuance of commercial paper in one or more series in the aggregate principal amount not to exceed three hundred million dollars ($300,000,000).In April 2015, the Utility redeemed all outstanding commercial paper and entered into a short-term borrowing agreement with Wells Fargo Municipal Capital Strategies, LLC, herein referred to as the Direct Drawdown Purchase Program (DDPP).

51

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Long‑Term Liabilities, continued

Notes from Direct Borrowings, continued

This borrowing program continued to fulfill the purpose of the Commercial Paper program, but at a lower aggregate fee and interest cost to the Utility over the life of the program. The DDPP was used by the Utility to complete construction of Generation Plant 2A. At December 31, 2019 and 2018 the outstanding balance of DDPP notes payable was $191,900,000. On November 1, 2019 the loan term was extended to September 30, 2020. No further drawdowns are anticipated. The Utility intends to extend the loan term until December 31, 2020. Pursuant to the sale of the Utility, the Municipality will retire the amount outstanding on the date of the sale.

The maturity date of the loan is September 30, 2020. The Utility agrees to pay the outstanding principal and the accrued and unpaid interest on the earlier of the Termination date or the Maturity date. The interest rate is the LIBOR index rate as defined by the loan agreement. The average interest rate for 2019 was 2.77%. 

In the event of default by the Utility, the Lender may terminate the Loan commitment and declare all amounts owed to be immediately due and payable. There are no unused lines of credit or assets pledged as collateral for this debt.

The following is a summary of long-term liability activity as of December 31, 2019 and 2018:

52

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Long‑Term Liabilities, continued

(6)   Net Position

Net position is composed of the following at December 31:

53

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

(7)Retirement and OPEB Plans

Substantially all regular employees of the Utility are covered by one or more of the following plans:

(a)IBEW Plans

Defined Benefit Plan

The Utility’s IBEW members participate in a cost‑sharing defined benefit plan, the Alaska Electrical Pension Plan of the Alaska Electrical Pension Fund (IBEW Plan). The Alaska Electrical Trust Funds (AETF) Board of Trustees administers the IBEW Plan and has the authority to establish and amend benefit terms and approve changes in employer required contributions.  Each year, AETF issues annual financial reports that can be obtained by writing the plan administrator, Alaska Electrical Pension Trust, 2600 Denali Street, Suite 200, Anchorage, Alaska, 99503. The Utility had 168 and 166 employees covered by the Plan as of December 31, 2019 and 2018, respectively.

The IBEW Plan provides several levels of retirement benefits, including early retirement, normal retirement, late retirement, and disability retirement and includes several options for spouse participation and death benefits. The Utility contributes to the IBEW Plan for its covered employees according to the terms of its Agreement Covering Terms and Conditions of Employment (Agreement) with the IBEW Local 1547. The Agreement in effect during 2018 and 2019 was effective until December 31, 2019. On February 27, 2020, the Agreement was extended to December 31, 2020 and amended effective the first full pay period in 2020.

Employer contributions are determined from hours of work reported by participating employers and the contractual employer contribution rate in effect. The Utility’s required contribution to the IBEW Plan for each hour for which compensation is paid to the employee for January 1, 2019 to December 31, 2019 was $8.00 per hour, and from January 1, 2018 to December 31, 2018 was $7.95 per hour. The Utility’s total employer contributions to the IBEW Plan for 2019 and 2018 were $3,249,636 and $3,382,920, respectively. The Utility had $355,339 and $119,769 in required contributions to the IBEW Plan payable to AETF at December 31, 2019 and 2018, respectively. These amounts are paid during the normal course of business in the month following each year end. The Utility is not subject to withdrawal penalties, nor are there any future minimum payments to the IBEW Plan required other than the contribution per hour compensated as required by the Agreement.

Defined Contribution Plan - Money Purchase Plan

The Agreement requires employer contributions to be made in an amount of 1.9% of each employee’s gross wages to the Alaska Electrical Workers Money Purchase Plan (Money Purchase Plan). The Utility’s employer and employee contributions to the Money Purchase Plan during 2019 were $412,735 and $106,142, respectively. The Utility’s employer and employee contributions to the Money Purchase Plan during 2018 were $437,345 and $89,841, respectively. One hundred percent (100%) of the Utility’s required contributions to the IBEW plans have been made through these contributions to the AETF.

54

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

(b)  State of Alaska Public Employees’ Retirement System Defined Benefit Plan (PERS I-III)

General Information About the Plan

The Municipality participates in the Alaska Public Employees’ Retirement System (PERS I-III or the Plan). PERS I-III is a cost-sharing multiple employer plan which covers eligible State and local government employees, other than teachers. The Plan was established and is administered by the State of Alaska Department of Administration. Benefit and contribution provisions are established by State law and may be amended only by the State Legislature. 

The Plan provides for retirement, death and disability, and post-employment health care benefits. There are three tiers of employees, based on entry date. For all tiers within the Defined Benefit (DB) plan, full retirement benefits are generally calculated using a formula comprised of a multiplier times the average monthly salary (AMS) times the number of years of service. The multiplier is increased at longevity milestone markers for most employees.

The tiers within the Plan establish differing criteria regarding normal retirement age, early retirement age, and the criteria for calculation of AMS, COLA adjustments, and Other Post-Employment Benefits (OPEB) benefits.

A complete benefit comparison chart is available at the website noted below.

The Plan is included in a comprehensive annual financial report that includes financial statements and other required supplemental information. That report is available via the internet at http://doa.alaska.gov/drb/pers. Actuarial valuation reports, audited financial statements, and other detailed plan information are also available on this website. They may be obtained by writing to the State of Alaska, Department of Administration, Division of Retirement and Benefits, P.O. Box 110203, Juneau, Alaska, 99811‑0203 or by phoning (907) 465‑4460.

The PERS I-III DB Plan was closed to new entrants effective July 1, 2006. New employees hired after that date participate in the PERS IV Defined Contribution (DC) Plan described later in this note.

Historical Context and Special Funding Situation

In April 2008, the Alaska Legislature passed legislation converting the previously existing PERS plan from an agent-multiple employer plan to a defined benefit cost-sharing plan with an effective date of July 1, 2008. In connection with this conversion, the State of Alaska passed additional legislation which statutorily capped the employer contribution rate, established a state funded “on-behalf” contribution (subject to funding availability), and required that employer contributions be calculated against allPERS eligible wages, including wages paid to participants of the PERS Tier IV defined contribution plan described later in this note. 

Alaska Statutes require the State of Alaska to contribute to the Plan an amount such that, when combined with the employer contribution, is sufficient to pay the Plan’s past service liability contribution rate as adopted by the Alaska Retirement Management Board.

55

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System Defined Benefit Plan (PERS I-III), continued

Although current statutes call for the State of Alaska to contribute to the Plan, the Alaska Department of Law determined that the statute does not create a legal obligation to assume the liabilities of the Plan; rather it establishes a contribution mechanism to provide employer relief against the rising contribution rates. This relief payment is subject to funding availability, and therefore not legally mandated. As a result, the State initially determined that the Plan is not in a special funding situation. Following much discussion with various stakeholders, participant communities, attorneys, auditors, and the GASB itself, the State has subsequently reversed its position on this matter, and as of June 30, 2015, the State did record the liability presuming that the current statute does constitute a special funding situation as the legislation is currently written. It is important to note that the Alaska Legislature has the power and authority to change the aforementioned statute through the legislative process, and it is likely that the State will pursue efforts to do so in a future legislative session.

For the current year financial statements, management has treated AS 39.35.255 and AS 39.35.280 as constituting a special funding situation under GASB Statement No. 68 rules and has recorded all pension related liabilities, deferred inflows and outflows of resources, and disclosures on this basis.

Employee Contribution Rates

Regular employees are required to contribute 6.75 percent of their annual covered salary.

Employer and Other Contribution Rates

There are several contribution rates associated with the pension and healthcare contributions and related liabilities. These amounts are calculated on an annual basis.

Employer Effective Rate

This is the contractual employer pay-in rate. Under current legislation, this rate is statutorily capped at 22 percent of eligible wages, subject to a wage floor, and other termination events. This 22 percent rate is calculated on all PERS participating wages, including those wages attributable to employees in the defined contribution plan. Contributions derived from the defined contribution employees are referred to as the Defined Benefit Unfunded Liability (DBUL) contribution.

Alaska Retirement Management (ARM) Board  Adopted Rate

This is the rate formally adopted by the ARM Board. This rate is actuarially determined and used to calculate annual Plan funding requirements, without regard to the statutory rate cap or the GASB accounting rate. Prior to July 1, 2015, there were no constraints or restrictions on the actuarial cost method or other assumptions used in the ARM Board valuation. Effective July 1, 2015, the Legislature requires the ARM Board to adopt employer contribution rates for past service liabilities using a level percent of pay method over a closed 25 year term which ends in 2039.

56

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System Defined Benefit Plan (PERS I-III), continued

On-behalf Contribution Rate

This is the rate paid in by the State as an on-behalf payment under the current statute.  The statute requires the State to contribute, based on funding availability, an on-behalf amount equal to the difference between the ARM Board Rate and the Employer Effective Rate. In the Utility’s financial statements, the on-behalf amounts reflect revenue and expense only during the measurement period July 1, 2018 to June 30, 2019, in which the Plan recognizes the payments, resulting in a significant timing difference between the cash transfers and revenue and expense recognition. Total on-behalf amounts recognized as of the measurement period are actuarially calculated.

Contribution rates for the years ended June 30, 2018 and June 30, 2019 were determined in the June 30, 2017 and June 30, 2018 actuarial valuations, respectively. Municipality contribution rates for the 2019 and 2018 calendar year were as follows:

57

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System Defined Benefit Plan (PERS I-III), continued

In 2019 and 2018, the Utility’s proportionate share of the Municipality’s share was 2.85 and 3.14 percent, respectively and was credited with the following contributions into the pension plan. 

In addition, employee contributions to the Plan totaled $264,652 and $226,127 during the Utility’s calendar years 2019 and 2018, respectively.

Pension Liabilities, Pension Expense, Deferred Outflows of Resources and Deferred Inflows of Resources Related to Pensions 

The Utility’s portion of the Municipality’s liabilities, pension expense, deferred outflows and inflows of resources related to pensions are based on its share of the Municipality’s contributions to the plan in the current year. Those proportions are 2.85% and 3.14% at December 31, 2019 and 2018, respectively.

At December 31, 2019 and 2018, the Municipality reported a liability for its proportionate share of the net pension liability (NPL) that reflected a reduction for State pension support provided to the Municipality. The amount recognized by the Municipality and the Utility for their proportional share, the related State proportion, and the total were as follows:

The total pension liability for the June 30, 2019 measurement date was determined by an actuarial valuation as of June 30, 2018 rolled forward to June 30, 2019 to calculate the net pension liability as of that date. The total pension liability for the June 30, 2018 measurement date was determined by an actuarial valuation as of June 30, 2017 rolled forward to June 30, 2018 to calculate the net pension liability as of that date.

58

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System Defined Benefit Plan (PERS I-III), continued

The Municipality’s proportion of the net pension liability was based on a projection of the Municipality’s long-term share of contributions to the pension plan relative to the projected contributions of all participating entities, including the State, actuarially determined. At the June 30, 2019 measurement date, the Utility’s proportion was 0.1844 percent, which was a decrease of 0.0442 percent from the prior year. At the June 30, 2018 measurement date, the Utility’s proportion was 0.2286 percent, which was an increase of 0.0087 percent from its proportion measured as of June 30, 2017.

The Utility recognized pension expense of $1,582,003 and $626,449 for the year ended December 31, 2019 and December 31, 2018, respectively, of which $544,512 and $154,073 were recorded as on-behalf revenue and expense for additional contributions paid by the State.

At December 31, 2019 and 2018, the Utility reported deferred outflows of resources and deferred inflows of resources related to pensions from the following sources:

At December 31, 2019, the $427,894 reported as deferred outflows of resources related to pensions resulting from contributions subsequent to the measurement date will be recognized as a reduction in the net pension liability in the year ended December 31, 2020. Other amounts reported as deferred outflows of resources and deferred inflows of resources related to pensions will be recognized in pension expense as follows:

59

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System Defined Benefit Plan (PERS I-III), continued

Actuarial Assumptions

The total pension liability for the measurement period ended June 30, 2019 was determined by an actuarial valuation as of June 30, 2018, using the following actuarial assumptions, applied to all periods included in the measurement, and rolled forward to the measurement date of June 30, 2019. The actuarial assumptions used in the June 30, 2018 (latest available) actuarial valuation were based on the results of an actuarial experience study for the period from July 1, 2013 to June 30, 2017, resulting in changes in actuarial assumptions adopted by the ARM Board to better reflect expected future experience.

The total pension liability for the measurement period ended June 30, 2018 was determined by an actuarial valuation as of June 30, 2017, using the following actuarial assumptions, applied to all periods included in the measurement, and rolled forward to the measurement date of June 30, 2018. The actuarial assumptions used in the June 30, 2017 actuarial valuation were based on the results of an actuarial experience study for the period from July 1, 2009 to June 30, 2013, resulting in changes in actuarial assumptions adopted by the Alaska Retirement Management Board to better reflect expected future experience.

60

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System Defined Benefit Plan (PERS I-III), continued

Long-Term Expected Rate of Return

The long-term expected rate of return on pension plan investments was determined using a building-block method in which best-estimate ranges of expected future real rates of return (expected returns, net of pension plan investment expense and inflation) are developed for each major asset class.

These ranges are combined to produce the long-term expected rate of return by weighting the expected future real rates of return by the target asset allocation percentage and by adding expected inflation. The best estimates of arithmetic real rates of return for each major asset class included in the pension plan’s target asset allocation as of the measurement period June 30, 2019 and 2018 are summarized in the following table (note that the rates shown below exclude the inflation component):

61

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System Defined Benefit Plan (PERS I-III), continued

Discount Rate

The discount rate used to measure the total pension liability was 7.38 percent and 8 percent in 2019 and 2018, respectively. The projection of cash flows used to determine the discount rate assumed that Employer and State contributions will continue to follow the current funding policy which meets State statutes. Based on those assumptions, the pension plan's fiduciary net position was projected to be available to make all projected future benefit payments of current plan members. Therefore, the long-term expected rate of return on pension plan investments was applied to all periods of projected benefit payments to determine the total pension liability.

Discount Rate Sensitivity

The following presents the Utility’s proportionate share of the net pension liability calculated using the current discount rate of 7.38 percent and 8 percent for 2019 and 2018 respectively, as well as what the Utility’s proportionate share of the net pension liability would be if it were calculated using a discount rate that is 1-percentage-point lower or 1-percentage-point higher than the current rate:

June 30, 2019

June 30, 2018

62

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System Defined Benefit Plan (PERS I-III), continued

Pension Plan Fiduciary Net Position

Detailed information about the pension plan’s fiduciary net position is available in the     separately issued PERS financial report.

(c) State of Alaska Public Employees’ Retirement System Defined Contribution Plan (PERS IV)

Plan Information

The Utility participates in the Alaska Public Employees’ Retirement System (PERS IV or (Plan). PERS IV is a Defined Contribution (DC) plan which covers eligible State and local government employees, other than teachers. The Plan was established and is administered by the State of Alaska Department of Administration. Benefit and contribution provisions are established by State law and may be amended only by the State Legislature. 

The Plan is included in a comprehensive annual financial report that includes financial statements and other required supplemental information. That report is available via the internet at http://doa.alaska.gov/drb/pers. Actuarial valuation reports, audited financial statements, and other detailed plan information are also available on this website. They may be obtained by writing to the State of Alaska, Department of Administration, Division of Retirement and Benefits, P.O. Box 110203, Juneau, Alaska, 99811-0203 or by phoning (907) 465-4460.

Plan Participation and Benefit Terms

The Plan is governed by Section 401(a) of the Internal Revenue Code. A portion of employee wages and a matching employer contributions are made to the Plan before tax. These contributions plus any change in value (interest, gains and losses), and minus any Plan administrative fees or other charges, are payable to the employee or the employee’s beneficiary at a future date. The Plan is a participant-directed plan with investment options offered by providers that are selected by the ARM Board.

Participating employees are immediately and fully vested in that employee’s contributions and related earnings (losses). An employee shall be full vested in the employer contributions made on that employee’s behalf, and related earnings (losses), after five years of service. An employee is partially vested in the employer contributions, made on that employee’s behalf, and the related earnings, in the ratio of (a) 25 percent with two years of service; (b) 50 percent with three years of service; (c) 75 percent with four years of service; and (d) 100 percent with five years of service. Employer contributions, and related earnings, that are contributed for employees that are not fully vested before leaving employment are considered forfeit and returned to the employer.

Employees first enrolling into PERS after July 1, 2006 participate in PERS IV. PERS IV is a defined   contribution retirement plan that includes a component of defined benefit post-employment health care.

63

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System Defined Contribution Plan (PERS IV), continued

Plan Contribution Requirement

The Plan requires both employer and employee contributions. Employees may make additional contributions into the Plan, subject to limitations. Contribution rates for 2019 and 2018 are as follows:

The Utility contributed $159,421 and $159,988 to PERS IV on behalf of its employees for the years ended December 31, 2019 and 2018, respectively. Employee contributions to the Plan totaled $254,649 and 256,006 for 2019 and 2018, respectively. Defined Contribution forfeitures for the Utility in 2019 were $49,654.

(d)   State of Alaska Public Employees’ Retirement System OPEB Plans

General Information About the Plans

As part of its participation in the PERS Defined Benefit Plan (Tiers I, II, III), which is a cost-sharing multiple employer plan, the Utility participates in the Alaska Retiree Healthcare Trust (ARHCT), Retiree Medical Plan (RMP) and Occupational Death and Disability Plan (ODD). The ARHCT is self-funded and provides major medical coverage to retirees of the Defined Benefit Plan. Benefits vary by Tier level. The ARHCT was closed to all new members effective July 1, 2006. The RMP provides major medical coverage to retirees of the PERS Defined Contribution Plan (Tier IV). The RMP is self-insured. Members are not eligible to use this plan until they have at least 10 years of service and are Medicare eligible. The ODD provides death benefits for beneficiaries of plan participants and long-term disability benefits to all active members within PERS. The Plans are administered by the State of Alaska, Department of Administration. They may be obtained by writing to the State of Alaska, Department of Administration, Division of Retirement and Benefits, P.O. Box 110203, Juneau, Alaska, 99811-0203 or by phoning (907) 465-4460.

The Utility is required to contribute the following percentages of covered payroll into the OPEB plans; for January 1 through June 30, 2019, ARHCT 5.83 percent, ODD .26 percent, and RMP .94 percent, for July 1 through December 31, 2019, ARHCT 6.28 percent, ODD .26 percent, and RMP 1.32 percent. Employees do not contribute.

64

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System OPEB Plans, continued

In 2019, the Utility was credited with the following contributions to the OPEB plan

The Utility is required to contribute the following percentages of covered payroll into the OPEB plans, January 1 through June 30, 2018 ARHCT, 4.88%, ODD, 0.43%, and RMP, 1.03%, for July 1 through December 31, 2018, ARHCT 5.83 percent, ODD .26 percent, and RMP .94 percent Employees do not contribute.

In 2018, the Utility was credited with the following contributions to the OPEB plans:

OPEB Liabilities, OPEB Expense, and Deferred Outflows of Resources and Deferred Inflows of Resources Related to OPEB Plans

At December 31, 2019 and 2018, the Utility reported a liability for its proportionate share of the net OPEB liabilities (NOL) that reflected a reduction for State OPEB support provided to the Utility. The Utility reported a net OPEB asset (NOA) for ODD. The amount recognized by the Utility for its proportional share, the related State proportion, and the total were as follows:

65

MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System OPEB Plans, continued

The total OPEB liabilities for the June 30, 2019 measurement date was determined by an actuarial valuation as of June 30, 2018 rolled forward to June 30, 2019 to calculate the net OPEB liabilities as of that date. The Utility’s proportion of the net OPEB liabilities were based on a projection of the Utility’s long-term share of contributions to the OPEB plans relative to the projected contributions of all participating entities, actuarially determined. The Utility’s proportionate share at the June 30, 2019 measurement date changed from the proportionate share as of the June 30, 2018, as shown below.

The total OPEB liabilities for the June 30, 2018 measurement date was determined by an actuarial valuation as of June 30, 2017 rolled forward to June 30, 2018 to calculate the net OPEB liabilities as of that date. The Utility’s proportion of the net OPEB liabilities were based on a projection of the Utility’s long-term share of contributions to the OPEB plans relative to the projected contributions of all participating entities, actuarially determined. The Utility’s proportionate share at the June 30, 2018 measurement date increased over the proportionate share as of the June 30, 2017, as shown below.

As a result of its requirement to contribute to the Plans and changes in the actuarially calculated net OPEB asset and liability, the Utility recognized net OPEB expense of ($2,543,341) and $371,147 for 2019 and 2018, respectively, which includes ($703,104) and $89,409 of on-behalf expense. On-behalf revenue was recognized for ($703,104) and $89,409 for 2019 and 2018, respectively, for actuarially calculated support provided by the State for the ARHCT plan.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System OPEB Plans, continued

At December 31, 2019 and 2018, the Utility reported deferred outflows of resources and deferred inflows of resources related to all OPEB plans from the following sources:

Deferred outflows of resources and deferred inflows of resources from each Plan for 2019 are reported from the following sources:

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System OPEB Plans, continued

The $200,086 reported in 2019 as deferred outflows of resources related to OPEB resulting from contributions made subsequent to the measurement date will be recognized as a reduction in the net OPEB liability in the following year. Other amounts reported as deferred outflows of resources and deferred inflows of resources related to OPEB will be recognized in OPEB expense as follows:

Excluding contributions made subsequent to the measurement date, other amounts reported as deferred outflows of resources and deferred inflows of resources related to each OPEB plan will be recognized in OPEB expense as follows:

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System OPEB Plans, continued

Actuarial Assumptions

The total OPEB liability for the measurement period ended June 30, 2019 was determined by an actuarial valuation as of June 30, 2018, using the following actuarial assumptions, applied to all periods included in the measurement, and rolled forward to the measurement date of June 30, 2019. The actuarial assumptions used in the June 30, 2018 actuarial valuation were based on the results of an actuarial experience study for the period from July 1, 2013 to June 30, 2017, resulting in changes in actuarial assumptions adopted by the ARM Board to better reflect expected future experience.

In addition to the changes in assumptions resulting from the experience study, the following changes have been made since the prior valuation:

· An Employee Group Waiver Plan (EGWP) was implemented effective January 1, 2019. This arrangement replaced the Retiree Drug Subsidy (RDS) under Medicare Part D and resulted in larger projected subsidies to offset the cost of prescription drug coverage.

· Based on recent experience, the healthcare cost trend assumptions were updated.

· Per capita claims costs were updated to reflect recent experience.

· Healthcare cost trends were updated to reflect a Cadillac Tax load.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System OPEB Plans, continued

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System OPEB Plans, continued

The total OPEB liability for the measurement period ended June 30, 2018 was determined by an actuarial valuation as of June 30, 2017, using the following actuarial assumptions, applied to all periods included in the measurement, and rolled forward to the measurement date of June 30, 2018. The actuarial assumptions used in the June 30, 2017 actuarial valuation were based on the results of an actuarial experience study for the period from July 1, 2009 to June 30, 2013, resulting in changes in actuarial assumptions adopted by the ARM Board to better reflect expected future experience.

Long-Term Expected Rate of Return

The long-term expected rate of return on OPEB plan investments was determined using a building-block method in which best-estimate ranges of expected future real rates of return (expected returns, net of postretirement healthcare plan investment expense and inflation) are developed for each major asset class. These ranges are combined to produce the long-term expected rate of return by weighting the expected future real rates of return by the target asset allocation percentage and by adding expected inflation. The best estimates of arithmetic real rates of return for each major asset class are summarized in the following tables (note that the rates shown below exclude the inflation component):

June 30, 2019

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System OPEB Plans, continued

June 30, 2018

Discount Rate

The discount rate used to measure the total OPEB liability in 2019 and 2018 was 7.38 percent  and 8.00 percent, respectively for each plan. The projection of cash flows used to determine the discount rate assumed that employer and State contributions will continue to follow the current funding policy which meets State statutes. Based on those assumptions, the OPEB plan's fiduciary net position was projected to be available to make all projected future benefit payments of current plan members. Therefore, the long-term expected rate of return on OPEB plan investments was applied to all periods of projected benefit payments to determine the total OPEB liability for each plan.

Discount Rate Sensitivity

The following presents the Utility’s proportionate share of the net OPEB liabilities calculated using the current discount rate for both years presented, as well as what the Utility’s proportionate share of the net OPEB liabilities would be if they were calculated using a discount rate that is 1-percentage-point lower or 1-percentage-point higher than the current rate:

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System OPEB Plans, continued

Healthcare Cost Trend Rate Sensitivity

The following presents the Utility’s proportionate share of the net OPEB liabilities as of June 30, 2019 and 2018, calculated using the healthcare cost trend rates as summarized in the 2019 and 2018 actuarial valuation report, respectively, as well as what the respective Plan’s net OPEB liability would be if it were calculated using trend rates that are one-percentage-point lower or one-percentage-point higher than the current healthcare cost trend rates (in thousands):

OPEB Plan Fiduciary Net Position

Detailed information about the OPEB plan’s fiduciary net position is available in the separately issued PERS financial report.

(e)   State of Alaska Public Employees’ Retirement System Defined Contribution OPEB Plans

General Information About the Plans

Defined Contribution Pension Plan participants (PERS Tier IV) participate in the ODD Plan, and the RMP. Information on these plans is included in the comprehensive annual financial report for the PERS Plans noted above. These plans provide for death, disability, and postemployment healthcare benefits.

Employer Contribution Rates

Employees do not contribute to the Defined Contribution OPEB plans. Employer contribution rates for the years ended December 31, 2019 and 2018 were as follows:

2019

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Retirement and OPEB Plans, continued

State of Alaska Public Employees’ Retirement System Defined Contribution OPEB Plans, continued

2018

Healthcare Reimbursement Arrangement

In addition, PERS defined contribution members also participate in the Health Reimbursement Arrangement. AS 39.30.370 establishes the employer contribution amount as  “three percent of the employer’s average annual employee compensation of all employees of all employers in the plan”.

Prior to July 1, 2018 a flat rate of approximately $2,084 per year for full time employees and $1.34 per part time hour worked was paid. For pay periods ending after July 1, 2018, a flat rate of approximately $2,103 per year for full time employees and $1.35 per part time hour worked were paid. For pay periods ending after July 1, 2019, a flat rate of approximately $2,122 per year for full time employees and $1.36 per part time hour worked were paid.

Annual Postemployment Healthcare Cost

The Utility contributed $128,167 and $122,740 in Defined Contribution OPEB costs for the years ended December 31, 2019 and 2018, respectively.

(8)Commitments and Contingencies

The Utility, in the normal course of its activities, is involved in various claims and pending litigation. In the opinion of management and the Municipality’s legal department, the disposition of these matters is not expected to have a material adverse effect on the Utility’s financial statements.

(a)Environmental

Fuel/Polychlorinated Biphenyl (PCB) Contaminated Sites at Hank Nikkels Power Plant 1 and Operations/Dispatch Center

During the 1964 earthquake, approximately 250,000‑400,000 gallons of diesel fuel spilled on the ground. Based on numerous environmental investigations, the spill impacted soil and groundwater at the Hank Nikkels Power Plant 1 and properties west/northwest of the plant. During the 2006-2007 subsurface investigation, in addition to diesel contamination known from the 1964 spill, PCBs were detected in the soil. All soil disturbing activities at the site are governed by the Risk-Based Disposal Plan (RBDP) administered by the Alaska Department of Environmental Conservation (ADEC) and the Environmental Protection Agency (EPA).

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MUNICIPALITY OF ANCHORAGE, ALASKA
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Notes to Financial Statements

December 31, 2019 and 2018

Commitments and Contingencies, continued

Environmental, continued

In May 2017, the Utility conducted PCB cleanup activities at the plant and paved the surface of the cleanup area in accordance with the 2008 RBDP approved by EPA and ADEC. All cleanup activities were considered to be performed during 2018.

In 2009, PCB contaminated soil was discovered near the Operations/Dispatch building during excavation to install water lines for a fire suppression system. In 2010 and 2015 additional site investigations were conducted to determine a horizontal and vertical extent of PCB contamination.  Following the soil investigations the Utility performed monitoring of groundwater at the site and in the vicinity during 2015 and 2016. Analytical results indicated no off-site migration of PCBs. The Utility is waiting on EPA’s review of the site data and further decisions. The cost associated with any further actions cannot be determined at this time.

Petroleum Contaminated Sites and Spill Cleanup

In 2018, based on an ADEC request, the Utility conducted a vapor intrusion assessment associated with the old petroleum contamination in the subsurface near and under the Transformer Shop.  The assessment concluded that there were no petroleum vapors entering the Transformer Shop from the subsurface. In response to the assessment, ADEC requested to continue biennial groundwater monitoring at this site and include additional volatile organic compounds into the monitoring program. The Utility’s environmental consultant will prepare a work plan and conduct groundwater sampling during the summer of 2020. The Utility does not anticipate any material environmental liability associated with this contaminated site.

Compliance with Air Quality Permits

The Utility owns three turbines that are subject to hourly and annual emissions limits emission controls for criteria pollutants, NOx and CO.  In addition to maintaining continuous emission monitoring systems (CEMS) on each turbine, the two newly installed turbines requires operation with post-combustion emission controls. EPA regulations require annual third party emissions testing to assure accuracy of the CEMS. Newly installed turbines have significant emissions reductions compared to the existing turbines, however maintaining emissions control equipment and performing all testing required by the EPA will remain a significant part of the overall environmental compliance cost. The Utility will oversee environmental compliance and contract qualified third-party experts to perform necessary services. Environmental permitting and compliance will continue to require a consultant’s expertise. The cost of compliance cannot be determined at this time.

(b)   Petroleum Production Tax (PPT)

For tax year 2019, the Utility estimated that its PPT liability under AS 43.55.011(e) for non-royalty gas is zero and its liability under AS 43.44.011(i) for private royalty gas is $3,429. Monthly installment payments from February 2019 through January 2020 totaled $86,268.

For tax year 2018, the Utility estimated that its PPT liability under AS 43.55.011(e) for non-royalty gas is zero and its liability under AS 43.44.011(i) for private royalty gas is $4,370. Monthly installment payments from February 2018 through January 2019 totaled $104,554.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Commitments and Contingencies , continued

(c)   Petroleum Production Credits

Pursuant to AS 43.55.023, the Utility applies for Alaska oil and gas tax credits from the State of Alaska Department of Revenue (DOR). The Utility records the receipt of cash from tax credits as a restricted investment and as a deferred inflow of resources for the benefit of customers. During 2019 and 2018, the Utility did not apply for tax credits. The amounts received by the Utility are subject to final resolution of DOR audits, and are not recorded until cash is received.

(d)   Contractual Commitments

The Utility has purchase commitments to contractors and suppliers at December 31, 2019 of approximately $10 million. Those commitments are for contracts, materials and services related to construction and maintenance of the Utility’s generation and distribution system assets, regulatory filings contracted billing services, and janitorial and security services. Construction of plant assets is financed with contributions in aid of construction and Utility equity, and operating commitments are financed with Utility revenues.

(9)Regulatory Matters

(a)Beluga River Unit Underlift Settlements

Until April 2016, the Utility owned a one-third interest in annual production of the BRU.  Its field partners at that time – CPAI and Hilcorp Alaska, LLC - each also owned a one-third interest in BRU production.  Every BRU owner has a right to take a portion of annually produced gas proportionate to its interest.  

In 2005, the Utility underlifted (i.e. took less than its interest in BRU’s annual output) and accepted a monetary settlement from its field partners.  These funds were deposited in a Future Natural Gas Purchases Account (FGP), and the Utility recorded deferred inflows of resources for future natural gas purchases.  The balances of the Future Natural Gas Purchases Account, as of December 31, 2019 and 2018 were $18,230,036 and $17,934,651, respectively.

In 2015, the Utility petitioned the RCA for authorization to apply 2014 underlift settlement proceeds to reduce its GTP in effect from July 1, 2016 through June 30, 2017.  The RCA approved the Utility’s unopposed proposal in Order U-15-116(2), dated March 10, 2016.

In April 2016, the Utility purchased 70% of CPAI’s one-third interest in the BRU.  The RCA approved the Utility’s request in Order U-16-012(14), dated April 21, 2016, to utilize a closing underlift settlement from CPAI of $13,177,726 towards financing this acquisition.  See Note 9(f).

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Regulatory Matters, continued

(b)Regulatory Debits/Credits

The Utility files a COPA rate quarterly with the RCA to recover cost of power expenses not recovered in base rates.    The COPA calculation is based on the projected cost of fuel and purchased power for the applicable quarter, the projected kilowatt hour sales for the applicable quarter, and the over- or under- recovered balance in the cost of power clearing account. The Utility records in the cost of power clearing account an asset with an offsetting credit to a contra revenue account for under recovered costs or a liability and an offsetting debit to a contra revenue account for over recovered costs. The Utility over-recovered as of December 31, 2019in the amount of $1,562,679 and under-recovered as of December 31, 2018 in the amount of $1,904,402. 

Prior to October 24, 2017, the Utility annually set the GTP with its third quarter COPA filings.  (See Note 9 (g) for the new schedule in filing the GTP.)  Through the GTP, the Utility recovers the Gas Fund’s annual revenue requirement associated with the Utility’s ownership interest in the BRU and any over or under recovery from the prior year.  The Utility records in the cost of Gas Transfer Price Clearing Account an asset and a credit to an expense account for under-recovered costs or a liability and debit to an expense account for over-recovered costs. The Utility under-recovered as of December 31, 2019 and 2018 in the amount of $4,793 and $1,647,342, respectively.

c)Deferred Regulatory Liability for Gas Sales

Revenue from third party sales of natural gas produced at the BRU is excluded from the GTP calculation.  These funds, net of royalties and the ARO surcharge, are recorded in the Utility’s Future BRU Construction or Natural Gas Purchases account, reported on the statement of net position as deferred inflows of resources, and referred to for regulatory purposes as the Deferred Regulatory Liability from Gas Sales (DRLGS) Account. These funds are to be used for future BRU construction or natural gas purchases. The balances of the DRLGS account, as of December 31, 2019 and 2018, were $10,106,438 and $8,077,741, respectively.

(d)Asset Retirement Obligation Sinking Fund

ARO expenses associated with future abandonment of the BRU are funded through a surcharge to the Utility’s GTP. This surcharge is deposited into a sinking fund investment account. As of December 31, 2019and 2018, the sinking fund account balances were $16,342,806 and $13,915,853, respectively.

On page 24 of its revised petition in Docket U-14-009, dated January 29, 2014, the Utility stated that it would “each year, as part of [its] third quarter COPA filing, update the projected interest earnings rate for the ARO surcharge calculation.” In accordance with that requirement, in TA375-121, the Utility updated its future interest earnings estimate to 4.7%. This estimate is based on the targeted earnings rates established by the ARO Board Investment Guidelines of CPI-U plus 200 basis points. CPI-U for Anchorage was at 2.7% in 2019. The actual average earnings over the most recent 12-month period was 5.87% and the actual average earnings over the most recent 6-month period was 7.66%. The Utility will continue to review the projected interest earnings as part of its semiannual ARO surcharge filing.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Regulatory Matters, continued

In accordance with U-14-009(2) the Utility is required to update its field abandonment cost estimate for the ARO surcharge every 5 years. With the filing of TA375-121, the Utility submitted its updated cost estimate. The updated cost estimate for the field was $56.9 million, comprised of $28.5 million for above ground assets and $28.4 million for below ground assets. The updated estimate is higher than the prior field estimate of $33.5 million produced in the 2013 study.

Significant factors contributing to the increase include new facilities and increased regulatory requirements for remediation. The above ground cost increased approximately $5.6 million for the removal of a site compressor and water gathering system. Also included in the updated study are the cost estimates to remediate contaminated sites in the field. The below ground estimate for plugging and abandonment of the 25 existing wells increased approximately $18 million due to new regulatory requirements that require additional cement barriers to complete well abandonment downhole. Labor, material and equipment costs to construct the cement barriers are the primary factors leading to the increase in the below ground well abandonment cost.

Also in accordance with U-14-009(2) the Utility is required to update its BRU production projections for the ARO surcharge every 3 years. With the filing of TA375-121, the Utility submitted its updated production projections. Based on the updated 2019 report completed by Ryder Scott, the Utility’s share of the remaining gas reserves, net of fuel gas, is 82 billion cubic feet. The end of the life of the field is estimated to occur in 2038.

(e)Revenue Requirement Studies

On December 30, 2016 the Utility filed a petition with the RCA, based on a 2015 test year revenue requirement study, for interim and permanent across-the-board rate increases in energy and demand charges in order to recover costs associated with its construction of Plant 2A. The Utility requested a 29.49% interim and refundable rate increase, based on RCA approval of the Utility’s proposed rate stabilization plan (RSP).  On February 13, 2017 the RCA granted the Utility an interim and refundable rate increase of 37.30%, denied approval of the Utility’s proposed RSP, and suspended the Utility’s request into Docket U-17-008 for further investigation. A public hearing was held on this matter that began on November 16, 2017, and continued through December 21, 2017.  The RCA issued a final order on March 23, 2018 [U-17-008(13)] approving a 37.32% increase in the revenue requirement.

In two separate submittals at the Superior Court, Providence Health and Services (PHS) appealed the decision by the RCA on (1) Order 10 – refund order and (2) Order 13 - final order.  The Superior Court rendered an Order on Order 13 (final order) on May 20, 2019 – reversing and remanding the RCA Order 13 for further proceedings consistent with the Superior Court’s Order and the reasons that supported the Order. The RCA was ordered to “make findings and conclusions on whether the Utility met its burden to demonstrate that the decision to construct Plant 2A was prudent, reopening the evidentiary record if necessary.”  The RCA also has to provide the process by which it arrived at the final ROE of 10.7%.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Regulatory Matters, continued

On May 28, 2020, as part of the acquisition dockets (U-19-020/U-19-021/U-18-102), the RCA accepted the Amended Remand Stipulation, reaffirmed the Utility’s current rates as permanent, and closed the Utility’s rate case docket (U-17-008). This stipulation was signed by the Utility, Providence Health and Services, the Federal Executive Agency, and Attorney General for the State of Alaska.  It resolved the remanded issues by agreeing to the permanent rates as set in the rate case. ( See Note 9 (i))

(f)Acquisition of CPAI’s Interest in the BRU

In Order U-16-012(14), dated April 21, 2016, the RCA granted a joint petition filed by the Utility and CEA requesting approval of a purchase and sale agreement for the acquisition of CPAI’s one-third interest in the BRU.  The total purchase price was $152 million, with the Utility acquiring 70% of that interest for $106.4 million and CEA the remaining 30% for $45.6 million.  The Utility funded its share of the acquisition with DRLGS and Future Natural Gas Purchases Account funds, cumulative and underlift proceeds owed to it by CPAI. With this purchase the Utility has a  56.67% interest in the BRU.

(g)    BRU Ratemaking and Accounting Treatment – Aggregate BRU Interest

On June 20, 2016, the Utility filed for approval from the RCA for some changes in the ratemaking and accounting treatment applicable to the Aggregate BRU Interest. Ruling under Docket U-16-060(12), the RCA granted in part the request on October 24, 2017.  The use of rate base/rate of return (RB/ROR) methodology to calculate the gas fund revenue requirement beginning in 2019 was approved.    The use of a system-wide weighted average cost of capital (WACC) for calculating the gas fund revenue requirement was approved.  The RCA also approved the inclusion of depletion expense using the units of production methodology for calculating the gas fund revenue requirement.

Because the GTP is one component of the COPA and Small Facility Power Purchase Rate (SFPPR), several 2017 tariff advice filings were suspended and were filed under Docket U-16-073. On October 24, 2017, these were approved and made permanent.

In its own motion the RCA opened Docket U-18-102 to specifically investigate the Utility’s BRU gas management procedures, including use of its share of BRU gas for economy energy sales and the appropriate pricing of BRU gas that is used for economy energy sales. The RCA also opened Docket U-18-102 to investigate the adequacy of the ARO surcharge. An order in Docket U-18-102 revising the ARO surcharge used in the Utility’s GTP calculation will directly affect both the COPA and the SFPPR proposed in COPA filings by the Utility. An order in Docket U-18-102 affecting the pricing of economy energy sales by the Utility would also affect the COPA proposed in COPA filings.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Regulatory Matters, continued

One COPA filing in 2019, TA373-121, was directly affected by the matters under investigation in Docket U-18-102. Accordingly, the RCA suspended TA373-121 for further investigation. The rates shown on the tariff sheets are approved on an interim and refundable basis effective October 1, 2019.  In addition, the gas transfer price of $2.15705 per thousand cubic feet was approved on an interim and refundable basis, effective October 1, 2019. 

On May 28, 2020, as part of the acquisition Dockets (U-19-020/U-19-021), the RCA ruled the use of market value proxy mechanism in pricing economy energy sales using the Utility’s BRU interest gas. The methodology is set out in Section 2.05 of the Restated BRU Agreement, which is one of the agreement documents of the acquisition dockets. This requirement was effective May 28, 2020.

The Utility’s tax credit appeal at the Office of Administrative Hearings (OAH), 17-0379-TAX, is still ongoing. The Department of Revenue and the Utility are currently working on analyzing discovery requests and responses from both sides.

(h)Bradley Lake Transmission

Homer Electric Association, Inc. (HEA) filed a rate case on November 15, 2013 requesting RCA’s approval of postage stamp rates for Bradley Lake energy wheeled over HEA’s system.  The Utility intervened, arguing in part that the Bradley Lake Agreements govern the obligations of Bradley Lake participants and that the RCA was statutorily precluded, under AS 42.05.431(c), from reviewing these wheeling rates.  On June 30, 2014, the RCA issued an order establishing interim rates for wheeling Bradley Lake energy from the Soldotna to Quartz Creek Substations.  The parties appealed to the state superior court, which ruled May 27, 2015 that the RCA lacks jurisdiction over Bradley Lake wheeling rates.  All parties appealed this decision to the Alaska Supreme Court.  The parties engaged in lengthy mediation, and filed reply briefs with the Alaska Supreme Court.  Oral arguments before the Alaska Supreme Court were heard May 31, 2018. On February 22, 2019, the Supreme Court issued an opinion affirming the Superior Court’s decision reversing the RCA’s order.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Financial Statements

December 31, 2019 and 2018

Regulatory Matters, continued

(i)Acquisition of the Utility by CEA

On April 1, 2019, CEA filed a petition at the RCA requesting necessary approvals for acquiring the Utility from the Municipality and requesting an amendment of Certificate of Public Convenience and Necessity (CPCN) No. 8 to reflect the acquired service territory. This filing was assigned Docket U-19-020. CEA has agreed to acquire most of the assets of the Utility from the Municipality. CEA and the Municipality have agreed to a transaction in which CEA will purchase most of the Utility’s assets and the generation output of the Utility’s share of the Eklutna Hydroelectric Project for a term of 35 years.

On April 5, 2019, the Municipality applied for approval from the RCA to amend its CPCN No. 121 to consist solely of wholesale bulk power sales at the Eklutna generation plant. The Municipality also applied to terminate the restriction on payment of dividends to the Municipality initially imposed by Order No. U-13-184(22). This filing was assigned Docket U-19-021.

On May 8, 2019, the RCA ordered the consolidation of U-19-020 and U-19-021. Hearings occurred from August 27, 2019 to November 8, 2019. Two stipulations agreed upon by most parties in the dockets were presented to the RCA – Acquisition stipulation and Remand stipulation. The remand stipulation revolves around the appeal by PHS on the prudency of the Utility’s Plant 2A (see Note 9(e)). On February 21, 2020, the RCA closed Docket U-17-008, which addressed the remand stipulation. The RCA was then left with reviewing the acquisition stipulation.

On May 28, 2020, the RCA issued a ruling addressing the acquisition Dockets, U-19-020(39) and U-19-021(39), and part of the BRU Management Practices, U-18-102(44). The RCA did not approve the sale as proposed, but did approve the sale if parties agree to modify the transaction as required in the final order. The approval of the transaction is subject to the following conditions: (1)Unified COPA surcharges and rejection of the BRU Fuel Agreement cost and benefit allocations as unreasonably discriminatory; (2)Unified base rates to be filed in Chugach’s first rate case. The PILT Agreement’s proposed recovery of payments only from former ratepayers of the Utility through 2033 must be rejected; (3) CEA and MEA forming a tight power dispatch pool.

If the transaction closes under these dockets, the RCA will terminate the dividend restriction imposed on the Utility by Order U-13-184(22). This will allow disbursement of the Utility’s assets as contemplated by the transaction.

At this time, CEA, the Municipality, and all the other parties in the docket have yet to provide their response whether they accept the conditions as ruled by the RCA.

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MUNICIPALITY OF ANCHORAGE, ALASKA
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Notes to Financial Statements

December 31, 2019 and 2018

Regulatory Matters, continued

(j)   Petition to Adjust Depreciation Rates

On December 31, 2018, the Utility filed a petition at the RCA for approval of revised depreciation rates (Docket U-18-121).  The study was based on the Utility’s electric plant balances and continuing property records as of December 31, 2017. The Utility requested that the depreciation rates be approved for implementation as of the next accounting month following final approval by the RCA. On June 18, 2019, Order 2 was issued. The RCA denied the petition citing the results of the recently concluded rate case in Docket U-17-008 and that they did not find the $2.5 million revenue requirement reduction recommended in the 2018 Depreciation Study to be so materially substantial that the RCA should require the Utility to incur the cost of filing a new rate case.  The RCA further explains that the lack of synchronization between the requested depreciation rates and the current rates charged for electric public utility service. The denial will allow the depreciation rates previously found to be adequate but not excessive to remain in effect, and will result in depreciation expense collected from customers matching depreciation being recorded. The Utility was ordered to file another depreciation study in 2024, or when it files its next rate case.

(k)   Senate Bill 241

A bill introduced in the Senate of the Alaska Legislature was signed by Governor Dunleavy on April 10, 2020. This Act extended the Governor’s declaration of public health disaster emergency mandate in response to the novel coronavirus (COVID-19) that was issued on March 10, 2020. It provides for a financial plan and made temporary changes to state law in response to the COVID-19 outbreak in response to several areas. One of these areas is on regulatory assets for unpaid utility bills and extraordinary expenses. A utility certified under AS 42.05 may record regulatory assets, to be recovered through future rates, for uncollectible residential utility bills and extraordinary expenses that result from the novel coronavirus disease public health disaster declared by the Governor. The determination as to whether an extraordinary expense resulted from the COVID-19 public health disaster emergency, and the amortization periods for the regulatory assets are subject to approval by the RCA before recovery occurs through future rates. In this section, an "uncollectable residential utility bill" does not include a debt paid under a deferred payment agreement.

The Utility has suspended utility shut offs as of March 17, 2020. Customers are encouraged to pay on time, as they are able.  Each unpaid utility bill will continue to accrue. Customers who are not able to pay are encouraged to contact Customer Service to work out a payment plan. Under SB241, the Utility is prohibited from disconnecting service or imposing late fees for the duration of the emergency. In order to avoid disconnection for non-payment and late fees, a residential customer must provide a statement of financial hardship, and negotiate a deferred payment agreement with the Utility. This was offered by the Utility to its customers.

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Notes to Financial Statements

December 31, 2019 and 2018

  Regulatory Matters, continued

On May 1, 2020, the RCA issued Order U-20-015, Order Permitting Deviation from Tariff Under AS 42.05.711(d). This order addresses deviations by utilities from their approved tariffs as they avoid disconnections to their customers.  Instead of formally requesting approval to deviate, the RCA requires a certificated public utility to promptly make informational filing in U-20-015 describing how it is deviating from its tariff.  The Utility’s tariff language pertaining to disconnections is not violated, therefore no information filing is needed for the Utility.

(10)     Risk Management and Self Insurance

The Municipality is exposed to various risks of loss related to torts; theft of, damage to and destruction of assets; errors and omissions; illness of and injuries to employees; unemployment; and natural disasters. The Municipality utilizes three risk management funds to account for and finance its uninsured risks of loss.

The Municipality provides coverage up to the maximum of $3,000,000 per occurrence for automobile and general liability claims and for each workers’ compensation claim. No settled claim exceeded this commercial coverage in 2019, 2018 or 2017.

Unemployment compensation expense is based on actual claims paid by the State of Alaska and reimbursed by the Municipality.

The Utility participates in the Municipality’s risk management program and makes payments to the Municipality through inter-governmental charges based on actuarial estimates of the amounts needed to pay prior and current year claims (See Note 1(o).) The Utility does not include any portion of the Municipality’s claims payable among its liabilities on the Statements of Net Position.

(11)     Other GAAP Disclosures

The Municipality has entered into an agreement to sell certain assets and discharge certain liabilities of the Utility to CEA as outlined in Note 13. CEA is a non-governmental entity and, as such, follows the Financial Accounting Standards Board (FASB) accounting framework to prepare its financial statements. The Utility's financial statements are prepared according to the GASB framework, and therefore the accounting for certain items could differ from the accounting treatment by CEA. The table beginning on the following page presents relevant authoritative accounting pronouncements under the respective GASB and FASB frameworks to provide clarification to the users of these statements.

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Notes to Financial Statements

December 31, 2019 and 2018

Other GAAP Disclosures, continued

Reported in the Utility's Financial Statements	GASB Authoritative Guidance	FASB Authoritative Guidance
Net Pension Liabilities	GASBS 68 Paragraph 59 -  A liability should be recognized for the employer’s proportionate share of the collective net pension liability, measured as of a date (measurement date) no earlier than the end of the employer’s prior fiscal year, consistently applied from period to period. The employer’s proportionate share of the collective net pension liability should be measured by: a.    Determining the employer’s proportion—a measure of the proportionate relationship of (1) the employer (and, to the extent associated with the employer, nonemployer contributing entities, if any, that provide support for the employer but that are not in a special funding situation) to (2) all employers and all nonemployer contributing entities. b.    Multiplying the collective net pension liability by the employer’s proportion calculated in (a).	FASB ASC Topic 715-30-25 Paragraph 1 - If the projected benefit obligation exceeds the fair value of plan assets, the employer shall recognize in its statement of financial position a liability that equals the unfunded projected benefit obligation. If the fair value of plan assets exceeds the projected benefit obligation, the employer shall recognize in its statement of financial position an asset that equals the overfunded projected benefit obligation.

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Notes to Financial Statements

December 31, 2019 and 2018

Other GAAP Disclosures, continued

Reported in the Utility's Financial Statements	GASB Authoritative Guidance	FASB Authoritative Guidance
Deferred Inflows of Resources and Deferred Outflows of Resources Related to Pensions	GASBS 68 Paragraph 71 - Changes in the collective net pension liability should be included in collective pension expense in the current measurement period except as indicated below:  a. Each of the following should be included in collective pension expense, beginning in the current measurement period, using a systematic and rational method over a closed period equal to the average of the expected remaining service lives of all employees that are provided with pensions through the pension plan (active employees and inactive employees) determined as of the beginning of the measurement period: (1) Differences between expected and actual experience with regard to economic and demographic factors (differences between expected and actual experience) in the measurement of the total pension liability (2) Changes of assumptions about future economic or demographic factors or of other inputs (changes of assumptions or other inputs). The portion of (1) and (2) not included in collective pension expense should be included in collective deferred outflows of resources or deferred inflows of resources related to pensions. b. The difference between projected and actual earnings on pension plan investments should be included in collective pension expense using a systematic and rational method over a closed five-year period,	ASC Topic 715-30-35 Paragraph 18 - As established in the definition of the term, a gain or loss results from a change in the value of either the projected benefit obligation or the plan assets resulting from experience different from that assumed or from a change in an actuarial assumption.  Paragraph 19 - Because gains and losses may reflect refinements in estimates as well as real changes in economic values and because some gains in one period may be offset by losses in another or vice versa, this Subtopic does not require recognition of gains and losses as components of net pension cost of the period in which they arise. Paragraph 22 - Asset gains and losses are differences between the actual return on plan assets during a period and the expected return on plan assets for that period. Asset gains and losses include both changes reflected in the market-related value of plan assets and changes not yet reflected  in the market-related value (that is, the difference between the fair value of assets and the market-related value). Gains or losses on transferable securities issued by the employer and included in plan assets are also included in asset gains and losses. Paragraph 23 - In other words, the expected return on plan assets generally will be different from the actual return on plan assets for the year. This Subtopic provides for recognition of that difference (a net gain or loss) in other comprehensive income in the period it arises. The amount recognized in other

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Notes to Financial Statements

December 31, 2019 and 2018

Other GAAP Disclosures, continued

Reported in the Utility's Financial Statements	GASB Authoritative Guidance	FASB Authoritative Guidance
Deferred Inflows of Resources and Deferred Outflows of Resources Related to Pensions, continued	beginning in the current measurement period. The amount not included in collective pension expense should be included in collective deferred outflows of resources or deferred inflows of resources related to pensions. Collective deferred outflows of resources and deferred inflows of resources arising from differences between projected and actual pension plan investment earnings in different measurement periods should be aggregated and included as a net collective deferred outflow of resources related to pensions or a net collective deferred inflow of resources related to pensions.	comprehensive income is also a component of net periodic pension cost for the current period. Thus, the amount recognized in other comprehensive income and the actual return on plan assets, when aggregated, equal the expected return on plan assets. The amount recognized in accumulated other comprehensive income affects future net periodic pension cost through subsequent amortization, if any, of the net gain or loss.
Net Other Post Employment Benefits  Liabilities	GASBS 75 Paragraph 109 - A liability should be recognized for the employer’s proportionate share of the collective net OPEB liability determined in conformity with paragraphs 59-61. (Paragraph 59 - The employer’s proportionate share of the collective net OPEB liability should be measured by: (a) Determining the employer’s proportion – a measure of the proportionate relationship of (1) the employer.. to (2) all employers and all nonemployer contributing entities… (b) Multiplying the collective net OPEB liability (determined in conformity with paragraphs 70-85) by employer’s proportion calculated in (a). Paragraph 70 – The collective net OPEB liability should be measured as the total OPEB liability net of the	FASB ASC Topic 715-60-25 Paragraph 1 - An employer that sponsors one or more single-employer defined benefit postretirement plans other than pensions shall recognize in its statement of financial position the funded statuses of those plans. The employer shall aggregate the statuses of all overfunded plans and recognize that amount as an asset in its statement of financial position. It also shall aggregate the statuses of all underfunded plans and recognize that amount as a liability in its statement of financial position.  Paragraph 2 - As indicated in paragraphs 715-60-35-125 through 35-126 remeasurement of both plan assets and the accumulated postretirement benefit obligation may be necessary. Upon remeasurement, a business entity shall adjust its statement of financial position in a

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Notes to Financial Statements

December 31, 2019 and 2018

Reported in the Utility's Financial Statements	GASB Authoritative Guidance	FASB Authoritative Guidance
Net Other Post Employment Benefits  Liabilities, continued	OPEB plan’s fiduciary net position.  Paragraph 71 - The total OPEB liability should be determined by (a) an actuarial valuation as of the measurement date or (b) the use of update procedures to roll forward to the measurement date amounts from an actuarial valuation as of a date no more than 30 months and 1 day earlier than the employer’s most recent fiscal year end.. If update procedures are used and significant changes occur between the actuarial valuation date and the measurement date, professional judgment should be used to determine the extent of procedures needed to roll forward the measurement from the actuarial valuation to the measurement date, and consideration should be given to whether a new actuarial valuation is needed. For purposes of this determination, the effects of changes in the discount rate resulting from changes in the OPEB plan’s fiduciary net position or from changes in the municipal bond rate, if applicable, should be among the factors evaluated. For accounting and financial reporting purposes, an actuarial valuation of the total OPEB liability should be performed at least biennially. More frequent actuarial valuations are encouraged.	subsequent interim period to reflect the overfunded or underfunded status of the plan consistent with that measurement date.

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Notes to Financial Statements

December 31, 2019 and 2018

Other GAAP Disclosures, continued

Reported in the Utility's Financial Statements	GASB Authoritative Guidance	FASB Authoritative Guidance
Deferred Inflows of Resources and Deferred Outflows of Resources Related to OPEB	GASBS 75 Paragraph 86 -  Changes in the collective net OPEB liability should be included in collective OPEB expense in the current measurement period except as indicated below:  (a) If the alternative measurement method is not used to measure the total OPEB liability, each of the following should be recognized in collective OPEB expense, beginning in the current measurement period, using a systematic and rational method over a closed period equal to the average of the expected remaining service lives of all employees that are provided with OPEB through the OPEB plan  determined as of the beginning of the measurement period: (1)    Differences between expected and actual experience with regard to economic or demographic factors (differences between expected and actual experience) in the measurement of the total OPEB liability. (2)    Changes of assumptions about future economic or demographic factors or of other inputs (changes of assumptions or other inputs). The portion of (1) and (2) not recognized in collective OPEB expense should be reported as collective deferred outflows of resources or deferred inflows of resources related to OPEB. (b)  The difference between projected and actual earnings on OPEB plan investments should be included in collective OPEB expense using a	ASC Topic 715-60-35 Paragraph 7 - As with other forms of deferred compensation, the cost of providing postretirement benefits shall be attributed to the periods of employee service rendered in exchange for those future benefits pursuant to the terms of the plan. That cost notionally represents the change in the unfunded accumulated postretirement benefit obligation for the period, ignoring employer contributions to the plan, plan settlements, and payments made by the employer directly to retirees. However, changes in that unfunded obligation that arise from experience gains and losses and the effects of changes in assumptions may be recognized as a component of net periodic postretirement benefit cost on a delayed basis. Paragraph 8 - Thus any change in the accumulated postretirement benefit obligation or the plan assets (other than contributions and benefit payments) either is initially recognized in other comprehensive income or is included in net periodic postretirement benefit cost. Paragraph 24 - Because gains and losses may reflect refinements in estimates as well as real changes in economic values and because some gains in one period may be offset by losses in another or vice versa, this Subtopic does not require recognition of gains and losses as components of net postretirement benefit cost of the period in which they arise.

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Notes to Financial Statements

December 31, 2019 and 2018

Other GAAP Disclosures, continued

Reported in the Utility's Financial Statements	GASB Authoritative Guidance	FASB Authoritative Guidance
Deferred Inflows of Resources and Deferred Outflows of Resources Related to OPEB, continued	systematic and rational method over a closed five-year period, beginning in the current measurement period. The amount not included in collective OPEB expense should be included in collective deferred outflows of resources or deferred inflows of resources related to OPEB. Collective deferred outflows of resources and deferred inflows of resources arising from differences between projected and actual OPEB plan investment earnings in different measurement periods should be aggregated and included as a net collective deferred outflow of resources related to OPEB or a net collective deferred inflow of resources related to OPEB. (c) Contributions to the OPEB plan from employers or nonemployer contributing entities should not be included in collective OPEB expenses.	Paragraph 25 - Gains and losses that are not recognized immediately as a component of net periodic postretirement benefit cost shall be recognized as increases or decreases in other comprehensive income as they arise. Paragraph 27 - Plan asset gains and losses are differences between the actual return on plan assets during a period and the expected return on plan assets for that period. Asset gains and losses include both of the following: a. Changes reflected in the market-related value of plan assets b.  Changes not yet reflected in the market-related value of plan assets (that is, the difference between the fair value and the market-related value of plan assets).

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Notes to Financial Statements

December 31, 2019 and 2018

Other GAAP Disclosures, continued

Reported in the Utility's Financial Statements	GASB Authoritative Guidance	FASB Authoritative Guidance
Contributions in Aid of Construction	GASBCS4 Paragraph 34.    A deferred inflow of resources is an acquisition of net position by the government that is applicable to a future reporting period.	FASB ASC 210-10-S99 Paragraph 13(b) Tangible and intangible utility plant of a public utility company shall be segregated so as to show separately the original cost, plant acquisition adjustments, and plant adjustments, as required by the system of accounts prescribed by the applicable regulatory authorities.
Restricted Assets	GASBS 34 Paragraph 99 -  Restricted assets should be reported when restrictions  on asset use change the nature or normal understanding of the availability of the asset. For example, cash and investments normally are classified as current assets, and a normal understanding of these assets presumes that restrictions do not limit the government's ability to use the resources to pay current liabilities. But cash and investments held in a separate account that can be used to pay debt principal and interest only (as required by the debt covenant) and that cannot be used to pay other current liabilities should be reported as restricted assets. Because restricted assets may include temporarily invested debt proceeds or other resources that are not generated through operations (such as customer deposits), the amount reported as restricted assets will not necessarily equal restricted net position.	FASB ASC 210-10-S99-1 Paragraph 1 - Cash and cash items. Separate disclosure shall be made of the cash and cash items which are restricted as to withdrawal or usage. The provisions of any restrictions shall be described in a note to the financial statements. Restrictions may include legally restricted deposits held as compensating balances against short-term borrowing arrangements, contracts entered into with others, or company statements of intention with regard to particular deposits.

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Notes to Financial Statements

December 31, 2019 and 2018

Other GAAP Disclosures, continued

Reported in the Utility's Financial Statements	GASB Authoritative Guidance	FASB Authoritative Guidance
Transfers to Other Funds	GASBS 34 Paragraph 112b -  Nonreciprocal interfund activity is the internal counterpart to nonexchange transactions. It includes: Interfund transfers—flows of assets (such as cash or goods) without equivalent flows of assets in return and without a requirement for repayment. This category includes payments in lieu of taxes that are not payments for, and are not reasonably equivalent in value to, services provided.	Not addressed in FASB reporting framework
Non-Operating Revenues and Expenses	GASBS 34 Paragraph 102 - Governments should establish a policy that defines operating revenues and expenses that is appropriate to the nature of the activity being reported, disclose it in the summary of significant accounting policies, and use it consistently from period to period. A consideration for defining a proprietary fund's operating revenues and expenses is how individual transactions would be categorized for purposes of preparing a statement of cash flows. Transactions for which cash flows are reported as capital and related financing activities, noncapital financing activities, or investing activities normally would not be reported as components of operating income.	FASB ASC Topic 360-10-45-5 - A gain or loss recognized on the sale of a long-lived asset that is not a discontinued operation shall be included in income from continuing operations before income taxes.

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Notes to Financial Statements

December 31, 2019 and 2018

Other GAAP Disclosures, continued

Reported in the Utility's Financial Statements	GASB Authoritative Guidance	FASB Authoritative Guidance
Asset Retirement Obligations	The Utility uses the Guidance from FASB ASC Topic 980 (Formerly FASBS 143) to record asset retirement obligations. The implementation date for GASBS 83 Certain Asset Retirement Obligations has been postponed until fiscal year 2020.	FASB ASC Topic 980-410-25-2 - Many rate-regulated entities currently provide for costs related to the retirement of certain long-lived assets in their financial statements and recover those amounts in rates charged to their customers. Some of those costs result from asset retirement obligations within the scope of subtopic 410-20; others result from costs that are not within the scope of the subtopic. The amounts charged to customers for the costs related to the retirement of long-lived assets may differ from the period costs for financial reporting and rate-making purposes. An additional recognition timing difference may exist when the costs related to the retirement of long-lived assets are included in amounts charged to customers but liabilities are not recognized in the financial statements. If the requirements of this topic are met, a regulated entity shall also recognize a regulatory asset or liability for differences in the timing of recognition of the period costs associated with asset retirement obligations for financial reporting pursuant to that Subtopic and rate-making purposes.

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Notes to Financial Statements

December 31, 2019 and 2018

(12)   Other Matters

(a)Eklutna Hydroelectric Project

On October 2, 1997, the ownership of the Eklutna Hydroelectric Project was formally transferred from the Alaska Power Administration, a unit of the United States Department of Energy, to the three participating utilities: the Utility, CEA and Matanuska Electric Association (MEA). The project is jointly owned and operated by the participating utilities and each contributes their proportionate share for operation, maintenance, and capital improvement costs, as well as maintenance of the transmission line between Anchorage and the hydroelectric plant. The Utility has a 53.33% ownership interest in the project and recorded operating and maintenance costs of $542,438 and $409,562 in 2019 and 2018, respectively. Capital costs for 2019 and 2018 were $965,640 and $373,142, respectively. In addition, the Utility paid transmission costs for hydroelectric power of $42,688 and $26,132 in 2019 and 2018, respectively. The operations and maintenance costs are part of production expenses in the Statements of Revenue, Expenses and Changes in Net Position and the capital costs are part of plant assets reported in the Statements of Net Position.

(b)Bradley Lake Hydroelectric Project

The Utility agreed to acquire a portion of the output of the Bradley Lake Hydroelectric Project (Project) pursuant to a Power Sales Agreement (Agreement). The Agreement specifies the Utility acquire 25.9% of the output of the Project.

The Project went on line September 1, 1991.  The Utility made payments to the Alaska Energy Authority (AEA) of $4,997,622 in 2019 for its portion of costs, and received 66,345 megawatt hours of power from the Project. In 2018 the Utility paid $5,028,039 and received 102,307 megawatt hours. The Utility received a budget surplus refund in the amount of $226,448 for 2019. During the late summer and fall of 2019, the Swan Lake fire resulted in the transmission line from Bradley Lake to be de-energized for several months. The Utility as well as its other partners in the Project were unable to receive delivery of power from the Project until the fire was extinguished and the line was assessed and repaired. The line was fully operational by the end of November 2019.  The Utility’s estimated cost of power from the Project for 2020 is $2,536,188.

AEA issued the Power Revenue Bonds, First and Second Series in September 1989 and August 1990, respectively, for the long term financing of the construction costs of the Project.  On July 1, 2010, AEA issued $28,800,000 principal amount of Power Revenue Bonds, Sixth Series.  The Sixth Series Bonds were issued for the purpose of refunding the Power Revenue Bonds, Fifth Series Bonds to take advantage of lower interest rates.  The total amount of debt outstanding as of December 31, 2019 is $22,445,000. The pro rata share of the debt service costs of the Project for which the Utility is responsible, given its 25.9% share of the Project, is $6,276,098.  In the event of payment defaults by other power purchasers, the Utility’s share could be increased by up to 25%, which would then cause the Utility’s pro rata share of Project debt service to be a total of $7,845,122. The Utility does not now know of or anticipate any such defaults.

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Notes to Financial Statements

December 31, 2019 and 2018

Other Matters, continued

(c)    Southcentral Power Project (SPP)

The Utility entered into a participation agreement with CEA on August 28, 2008, to proceed with the joint development, construction and operation of SPP.  SPP went into service on January 31, 2013.  It has a capacity of 200.3 MW, of which the Utility’s proportionate share is 60.1 MW, or 30%.  The Utility has recorded costs of $15,097,247 and $14,895,085 in 2019 and 2018, respectively for its share of the operation of the plant. These costs include plant operation and maintenance costs and fuel expenses reported as production expenses in the Statements of Revenues, Expenses and Changes in Net Position and purchases of inventory and prepaid insurance, reported in the Statements of Net Position.

(13)  Subsequent Events

(a)    Sale of the Utility

On April 3, 2018, Anchorage voters approved an amendment to the Anchorage Municipal Charter authorizing the Municipality to sell the Utility to CEA by Municipal ordinance, to be approved no later than December 31, 2018. The Anchorage Assembly approved the sale on December 4, 2018. In April 2019, both the Municipality and CEA filed applications to the RCA to amend their CPCNs and to approve the sale.

On May 28, 2020, the RCA issued an order addressing the acquisition dockets and approving the sale if the parties agree to modify the transaction as required in the final order. (See Note 9(i)). At this time, CEA, the Municipality, and all the other parties in the docket have yet to decide whether they accept the conditions as ruled by the RCA. If they do accept the conditions and the acquisition goes forward, the expected closing date will be in the fall of 2020

The Utility, the Municipality and CEA are currently engaged in integration activities and transition planning. The Utility continues to operate as usual and the proposed sale has had no material effect on ongoing operations of the Utility. It is expected that the Municipality will continue to operate the Utility until the acquisition date, at which time CEA will take over operation of the Utility. Of course, the successful acquisition of most of the assets of the Utility by CEA would have a significant effect on the financial position and results of operations of the Utility. The agreement, as approved with conditions by the RCA, requires that the Utility retain only the generation assets of Eklutna Hydroelectric Project and sell power to CEA and MEA from those assets.

(b)    COVID-19 Pandemic

In late January 2020, the World Health Organization (“WHO”) announced a global health emergency regarding a new strain of virus called coronavirus (COVID-19). This virus originated from within China, and spread globally, including Alaska. The WHO declared this new strain creates extreme health risks as it spreads globally. Further, in March 2020, the WHO classified the coronavirus as a pandemic. March 12, 2020, the mayor of Anchorage declared a state of emergency to protect and preserve public health and safety, and subsequently closed all civic, cultural and recreational facilities in the Municipality.

Subsequent Events, continued

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Notes to Financial Statements

December 31, 2019 and 2018

The governor of Alaska declared a public health disaster as did the President of the United States. The governor instituted a number of public health measures that affected intrastate and interstate travel and the movement of goods and services. The Municipality and the Utility instituted strong social distancing measures for all employees and for several weeks, many of the Utility’s employees worked remotely, part-time, or were on administrative leave until safety and health procedures could be implemented to ensure that they could continue to do their jobs safely.

Management is actively monitoring the global situation and assessing its effect on the Utility’s financial condition, liquidity, operations, supply chain, and workforce. Given the daily evolution of the COVID-19 outbreak and the global responses to curb its spread, the Utility is not able to estimate the effects of the COVID-19 outbreak on its results of operations, financial condition, or cash flows for fiscal year 2020.

The Utility expects a longer receivables cycle and potential reduction in commercial sales during the economic slowdown that appears to be resulting from the health emergency. The state legislature has passed legislation that could enable the Utility or its successor to recover in future rates some of the impact of unpaid utility bills and extraordinary expenses related to responding to the emergency. The legislation also provides for deferred payment agreements with customers affected by the pandemic and needing to defer payment of their electric bills to future periods. Management anticipates a negative impact on its short-term cash flows as a result of these arrangements It is possible that the pandemic will adversely impact the value of the Utility’s investments held in marketable securities.

(b)    CARES Act Funding

On March 27, 2020 the President signed into law the “Coronavirus Aid, Relief and Economic Security (CARES) Act.” The CARES Act, among other things, appropriated funds for the Coronavirus Relief Fund to be used to make payments for specified uses to States and certain local governments. There is no assurance the Utility is eligible for these funds or will be able to obtain them. The Utility continues to examine the impact that the CARES Act may have. Currently, the Utility is unable to determine the impact that the CARES Act will have on the Utility’s financial condition, results of operations or liquidity.

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Notes to Financial Statements

December 31, 2019 and 2018

(14) New Accounting Pronouncements

GASB has passed several new accounting standards with upcoming implementation dates. The following new accounting standards were implemented by the Utility for 2019 reporting:

· GASB 84 – Fiduciary Activities.No changes were required under this Statement.

· GASB 88 – Certain Disclosures Related to Debt, including Direct Borrowings and Direct Placements. This Statement requires additional disclosures for debt that fall under the definition of a direct placement and/or a direct borrowing. A direct borrowing is defined as “a government entering into a loan agreement with a lender”. A direct placement is defined as “a government issuing a debt security directly to an investor”. The Utility does not have any debt that is defined as a direct placement debt but has several notes and contracts that meet the definition of a direct borrowing. Additional disclosures related to debt that is defined as a direct borrowing are to be found in Note 5.

· GASB 90 – Majority Equity Interests - an Amendment of GASB Statements No. 14 and No. 61. The provisions of this statement were considered not applicable at this time.

· GASB 95 -Postponement of the Effective Dates of Certain Authoritative Guidance. Due to the COVID-19 Pandemic -the GASB Board issued GASB Statement No. 95, which postponed the effective dates of several statements which were due to be implemented during the 2020 and 2021 reporting periods. The Municipality made the decision to early implement the aforementioned GASB Statements Nos. 84, 88, and 90, as the implementation of these Statements were already completed or were not applicable at the time of the issuance of GASB 95. The remainder of the Statements affected by GASB 95 will be implemented in accordance with their new effective dates as listed below

The following standards are required to be implemented in future financial reporting periods:

· GASB 83 – Certain Asset Retirement Obligations. The provisions of this Statement are required to be implemented for the 2020 financial reporting period.

· GASB 87 – Leases. The provisions of this Statements are required to be implemented for the 2022 financial reporting period.

· GASB 89 – Accounting for Interest Costs Incurred before the End of a Construction Period. The provisions of this statement are required to be implemented in the 2021 reporting period.

· GASB 91 – Conduit Debt Obligations – The provisions of this statement are required to be implemented in the 2022 reporting period.

GASB 92 – Omnibus 2020. The provisions of this statement are required to be implemented in the 2022 reporting period.

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Notes to Financial Statements

December 31, 2019 and 2018

New Accounting Pronouncements, continued

· GASB 93 – Replacement of Interbank Offered Rates. The provisions of this statement are required to be implemented in the 2022 reporting period.

· GASB 94 – Public-private and Public-public Partnerships and Availability Payment Arrangements. The provisions of this statement are required to be implemented in the 2023 reporting period.

· GASB 96 – Subscription-based Information Technology Arrangements. The provisions of this statement are required to be implemented in the 2023 reporting period.

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REQUIRED SUPPLEMENTARY INFORMATION

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Required Supplementary Information

Public Employees’ Retirement System – Defined Benefit Pension Plan

Schedule of Utility’s Proportionate Share of Net Pension Liability

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Required Supplementary Information

Public Employees’ Retirement System – Defined Benefit Pension Plan

Schedule of Utility Contributions

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Required Supplementary Information

Public Employees’ Retirement System – Other Postemployment Benefit Plan (OPEB)

Schedule of Utility’s Proportionate Share of Net OPEB Liability (Asset)

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Required Supplementary Information

Public Employees’ Retirement System – Other Postemployment Benefit Plan (OPEB)

Schedule of Utility Contributions -

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International Brotherhood of Electrical Workers (IBEW) – Defined Benefit Pension Plan

Schedule of Utility Contributions

Last 10 Fiscal Years

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Required Supplementary Information

December 31, 2019

(1)Public Employees’ Retirement System – Defined Benefit Pension Plan

In accordance with GASB Statement No. 82, “Covered Payroll” is defined as payroll on which contributions to the pension plan are based. Because a portion of the Utility’s contributions to the Plan (the DBUL) are based on Defined Contribution Wages, covered payroll reported here includes all PERS participating wages (both Defined Benefit and Defined Contribution).

Both pension tables are intended to present 10 years of information. Additional years’ information will be added to the schedules as it becomes available.

Schedule of Utility’s Proportionate Share of the Net Pension Liability

· This table is presented based on the Plan measurement date. For December 31, 2019, the Plan measurement date is June 30, 2019.

· There were no changes in benefit terms from the prior measurement period.

· There were no changes in assumptions from the prior measurement period, except for a decrease in the Discount Rate from 8 percent in 2018 to 7.38 percent in 2019.

· There were no changes in valuation method from the prior measurement period.

· There were no changes in the allocation methodology from the prior measurement period. The measurement period ended June 30, 2019 allocated the net pension liability based on the present value of contributions for fiscal year 2020 through 2039, as determined by projections based on the June 30, 2018 actuarial valuation. This is the same allocation method used for the measurement periods ended June 30, 2018 and June 30, 2017.

The actuarial assumptions used in the June 30, 2019 actuarial valuation (latest available) were based on the results of an actuarial experience study for the period from July 1, 2013 to June 30, 2017. As a result of this experience study, the ARM Board adopted updated actuarial assumptions for the June 30, 2019 actuarial valuation to better reflect expected future experience.

Schedule of Utility Contributions

· This table is based on the Utility’s contributions for each year presented. A portion of these contributions are included in the plan measurement results, while a portion of the contributions are reported as a deferred outflow of resources on the December 31, 2019 statement of net position.

(2)Public Employees’ Retirement System - Defined Benefit OPEB Plans

· In accordance with GASB Statement No. 85, “Covered Payroll” is defined as payroll on which contributions to the OPEB plan are based. Because a portion of the Utility’s contributions to the Plan (the DBUL) are based on Defined Contribution Wages, covered payroll reported here includes all PERS participating wages (both Defined Benefit and Defined Contribution).

· Both OPEB tables are presented for each of the three PERS OPEB plans; Alaska Retiree Healthcare Trust Plan (ARHCT), Retiree Medical Plan (RMP), and Occupational Death and Disability Plan (ODD).

· The OPEB tables are intended to present 10 years of information. Additional year’s information will be added to the schedules as it becomes available.

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Notes to Required Supplementary Information

December 31, 2019

Schedule of Utility’s Proportionate Share of the Net OPEB Liability

· This table is presented based on the Plan measurement date. For December 31, 2019, the Plan measurement date is June 30, 2019.

· There were no changes in benefit terms from the prior measurement period.

· As part of the experience study, the actuarial cost method for the retiree healthcare plan was changed from the Entry Age Level Dollar method to the Entry Age Level Percent of Pay method. The Discount Rate was reduced from 8 percent in 2018 to 7.38 in 2019.

· In addition to the changes in assumptions resulting from the experience study, the following changes have been made since the prior valuation:

o An Employee Group Waiver Plan (EGWP) was implemented effective January 1, 2019. This arrangement replaced the Retiree Drug Subsidy (RDS) under Medicare Part D and resulted in larger projected subsidies to offset the cost of prescription drug coverage.

o Based on recent experience, the healthcare cost trend assumptions were updated.

o Per capita claims costs were updated to reflect recent experience.

o Healthcare cost trends were updated to reflect a Cadillac Tax load.

· There were no changes in valuation method from the prior measurement period.

· There were no changes in the allocation methodology from the prior measurement period. The measurement period ended June 30, 2019 allocated the net OPEB liability based on the present value of contributions for fiscal year 2020 through 2039, as determined by projections based on the June 30, 2018 actuarial valuation.

The actuarial assumptions used in the June 30, 2019 actuarial valuation (latest available) were based on the results of an actuarial experience study for the period from July 1, 2013 to June 30, 2017. As a result of this experience study, the ARM Board adopted updated actuarial assumptions for the June 30, 2019 actuarial valuation to better reflect expected future experience

Schedule of Utility’s Contributions

· This table is based on the Utility’s contributions for each year presented. A portion of these contributions are included in the plan measurement results, while a portion of the contributions are reported as a deferred outflow of resources on the December 31, 2019 statement of net position.

· All tables are intended to present 10 years’ information. Additional years’ information will be added to the schedule as it becomes available.

(3)International Brotherhood of Electrical Workers (IBEW) Defined Benefit Pension Plan

Schedule of Utility Contributions

· This table presents the Utility contributions for each of the last ten years based on fiscal year contributions.

In accordance with GASB Statement No. 78, “Covered Payroll” is defined as payroll on which contributions to the pension plan are based.

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STATISTICAL SECTION

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Net Position by Components

Last Ten Fiscal Years

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Change in Net Position

Last Ten Fiscal Years

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Capital Assets

Last Ten Fiscal Years

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Comparative Operating Revenue Relationships

Last Ten Fiscal Years

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Top Ten Customers By Revenue

Last Ten Fiscal Years

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Top Ten Customers By Revenue

Last Ten Fiscal Years

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Top Ten Customers By Revenue

Last Ten Fiscal Years

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Top Ten Customers By Revenue

Last Ten Fiscal Years

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Rate Summary

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Rate Summary

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Rate Summary

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Rate Comparison

Last Ten Fiscal Years

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MUNICIPALITY OF ANCHORAGE,  ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Schedule of Revenue Bond Coverage

Last Ten Fiscal Years

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Statement of Net Position Ratios

Last Ten Fiscal Years

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Base Ratings by Generation Units

As of December 31, 2019

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Generated and Purchased Power (Kilowatt Hours)

Last Ten Fiscal Years

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Energy Loads and Resources

Last Ten Fiscal Years

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MUNICIPALITY OF ANCHORAGE, ALASKA
ELECTRIC UTILITY FUND

Statistical Section (Unaudited)

Monthly Peak (Megawatt Hours)

Last Ten Fiscal Years

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municipality of anchorage, alaska
electric utility fund

Statistical Section (Unaudited)

Monthly Peak (Megawatt Hours)

Last Ten Fiscal Years

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municipality of anchorage, alaska
electric utility fund

Statistical Section (Unaudited)

Miscellaneous Statistical Information

Last Ten Fiscal Years

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Independent Auditor’s Report on Internal Control Over Financial Reporting and on Compliance and Other Matters Based on an Audit of Financial Statements Performed in Accordance With Government Auditing Standards

Honorable Mayor and Members of the Assembly

Municipality of Anchorage, Alaska

We have audited, in accordance with the auditing standards generally accepted in the United States of America and the standards applicable to financial audits contained in Government Auditing Standards issued by the Comptroller General of the United States, the financial statements of the Electric Utility Fund, an enterprise fund of the Municipality of Anchorage, Alaska, as of and for the year ended December 31, 2019, and the related notes to the financial statements, which collectively comprise the Electric Utility Fund’s basic financial statements, and have issued our report thereon dated June 30, 2020.

Internal Control Over Financial Reporting

In planning and performing our audit of the financial statements, we considered the Electric Utility Fund’s internal control over financial reporting (internal controls) to determine the audit procedures that are appropriate in the circumstances for the purpose of expressing our opinion on the financial statements, but not for the purpose of expressing an opinion on the effectiveness of the Electric Utility Fund’s internal control. Accordingly, we do not express an opinion on the effectiveness of the Electric Utility Fund’s internal control.

A  deficiency in internal control exists when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent, or detect and correct, misstatements on a timely basis. A material weakness is a deficiency, or a combination of deficiencies, in internal control, such that there is a reasonable possibility that a material misstatement of the entity’s financial statements will not be prevented, or detected and corrected on a timely basis. A significant deficiency is a deficiency, or a combination of deficiencies, in internal control that is less severe than a material weakness, yet important enough to merit attention by those charged with governance.

Our consideration of internal control was for the limited purpose described in the first paragraph of this section and was not designed to identify all deficiencies in internal control that might be material weaknesses or significant deficiencies. Given these limitations, during our audit we did not identify any deficiencies in internal control that we consider to be material weaknesses. However, material weaknesses may exist that have not been identified.

Compliance and Other Matters

As part of obtaining reasonable assurance about whether the Electric Utility Fund’s financial statements are free from material misstatement, we performed tests of its compliance with certain provisions of laws, regulations, contracts, and grant agreements, noncompliance with which could have a direct and material effect on the determination of financial statement amounts. However,

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providing an opinion on compliance with those provisions was not an objective of our audit, and accordingly, we do not express such an opinion. The results of our tests disclosed no instances of noncompliance or other matters that are required to be reported under Government Auditing Standards

Purpose of this Report

The purpose of this report is solely to describe the scope of our testing of internal control and compliance and the results of that testing, and not to provide an opinion on the effectiveness of the entity’s internal control or on compliance. This report is an integral part of an audit performed in accordance with Government Auditing Standards in considering the Electric Utility Fund’s internal control and compliance. Accordingly, this communication is not suitable for any other purpose.

/s/ BDO USA, LLP

Anchorage, Alaska

June 30, 2020

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