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EX-32.2 - EX-32.2 - CHUGACH ELECTRIC ASSOCIATION INCc004-20171231xex32_2.htm
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EX-31.2 - EX-31.2 - CHUGACH ELECTRIC ASSOCIATION INCc004-20171231xex31_2.htm
EX-31.1 - EX-31.1 - CHUGACH ELECTRIC ASSOCIATION INCc004-20171231xex31_1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



FORM 10-K



     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended   December 31, 2017

or

   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from  ____________ to ____________

Commission file number   33-42125

Picture 1

Chugach Electric Association, Inc.

(Exact name of registrant as specified in its charter)



 

 

Alaska

 

92-0014224

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification No.)



 

 

5601 Electron Dr., Anchorage, Alaska

 

99518

(Address of principal executive offices)

 

(Zip Code)



 

 

Registrant’s telephone number, including area code

 

(907) 563-7494



 

 

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

 

Name of each exchange on which registered

N/A

 

N/A



 

 

Securities registered pursuant to Section 12(g) of the Act:

N/A

(Title of class)



Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes No

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes No

(Note:  The registrant is a voluntary filer and not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934.  Although not subject to these filing requirements, the registrant has filed all reports that would have been required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months had the registrant been subject to such requirements.)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Registration S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



 

 

Large accelerated filer

 

Accelerated filer

Non-accelerated filer

 

Smaller reporting company



 

 

Emerging growth company



 

 

 

 



 

 

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes No

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter.   N/A

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the last practicable date.    NONE

 


 

CHUGACH ELECTRIC ASSOCIATION, INC.



2017 Form 10-K Annual Report



Table of Contents



 

 

 

PART I

Page



Item 1.

Business



Item 1A.

Risk Factors



Item 1B.

Unresolved Staff Comments

13 



Item 2.

Properties

14 



Item 3.

Legal Proceedings

22 



Item 4.

Mine Safety Disclosures

22 

PART II

 



Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matter and Issuer Purchases of Equity Securities

23 



Item 6.

Selected Financial Data

23 



Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

24 



Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

40 



Item 8.

Financial Statements and Supplementary Data

41 



Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

83 



Item 9A.

Controls and Procedures

83 



Item 9B.

Other Information

84 

PART III

 



Item 10.

Directors, Executive Officers and Corporate Governance

84 



Item 11.

Executive Compensation

88 



Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

96 



Item 13.

Certain Relationships and Related Transactions, and Director Independence

96 



Item 14.

Principal Accounting Fees and Services

96 

PART IV

 



Item 15.

Exhibits, Financial Statement Schedules

97 



 

SIGNATURES

110 



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CAUTION REGARDING FORWARD-LOOKING STATEMENTS

Statements in this report that do not relate to historical facts, including statements relating to future plans, events or performance, are forward-looking statements that involve risks and uncertainties. Actual results, events or performance may differ materially. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date of this report and the accuracy of which is subject to inherent uncertainty. Chugach Electric Association, Inc. (Chugach) undertakes no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances that may occur after the date of this report or the effect of those events or circumstances on any of the forward-looking statements contained in this report, except as required by law.

PART I

Item 1 Business

General

Chugach was organized as an Alaska electric cooperative in 1948. Cooperatives are business organizations that are owned by their members. As not-for-profit organizations (Internal Revenue Code 501(c)(12)), cooperatives are structured to provide services to their members at cost, in part by eliminating the need to produce profits or a return on equity other than for reasonable reserves and margins. Today, cooperatives in general operate throughout the United States in such diverse areas as utilities, agriculture, irrigation, insurance and credit. All cooperatives are based upon similar principles and legal foundations. Because members’ equity is not considered an investment, a cooperative’s objectives and policies are oriented to serving member interests, rather than maximizing return on investment.

Chugach makes its current and periodic reports available, free of charge, on its website at www.chugachelectric.com as soon as practicable after filing with the Securities and Exchange Commission (SEC). The information on Chugach’s website is not a part of this Annual Report on Form 10-K. Chugach’s website also provides a link to the SEC’s website at http://www.sec.gov.

Chugach is one of the largest electric utilities in Alaska. We are engaged in the generation, transmission and distribution of electricity in the Anchorage and upper Kenai Peninsula areas. Chugach is on an interconnected regional electrical system referred to as the Alaska Railbelt, a 400-mile-long area stretching from the coastline of the southern Kenai Peninsula to the interior of the state, including Alaska’s largest cities, Anchorage and Fairbanks. Neither Chugach nor any other electric utility in Alaska’s Railbelt has any connection to the electric grid of the continental United States or Canada. Our principal executive offices are located at 5601 Electron Drive, Anchorage, Alaska 99518. Our telephone number is (907) 563-7494.

Chugach is an electric cooperative that is exempt from federal income taxation as an organization described in Section 501(c)(12) of the Internal Revenue Code (Code). Chugach’s hydroelectric project is licensed by the Federal Energy Regulatory Commission (FERC). As such, Chugach is subject to FERC reporting requirements and our accounting records conform to the Uniform System of Accounts as prescribed by FERC. In lieu of state and local ad valorem, income and excise taxes, Alaska electric cooperatives must pay a gross revenue tax to the State of Alaska at the rate of $0.0005 per kilowatt-hour (kWh) of electricity sold in the retail market during the preceding year. This tax is collected monthly and remitted annually. In addition, we currently collect a regulatory cost charge (RCC) of $0.000899 per kWh of retail electricity sold. The RCC is assessed to fund the

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operations of the Regulatory Commission of Alaska (RCA) and is collected monthly and remitted to the State of Alaska quarterly. We also collect sales tax on retail electricity sold to consumers in Whittier, seasonally (April through September), and in the Kenai Peninsula Borough, monthly. This tax is remitted to the City of Whittier monthly and to the Kenai Peninsula Borough quarterly. These taxes are a direct pass-through to consumer bills and therefore do not impact our margins.

We had 291 employees as of March 12, 2018. Approximately 70% of our employees are members of the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW. We also have a CBA with the Hotel Employees and Restaurant Employees (HERE). All of the CBA’s have been renewed through June 30, 2021. The three IBEW CBAs provide for wage and pension contribution increases in all years and include health and welfare premium cost sharing provisions. The HERE CBA provides for wage, pension contribution, and health and welfare contribution increases in all years. We believe our relationship with our employees is good.

Our members are the consumers of the electricity sold by us. As of December 31, 2017, we had one wholesale customer, 67,992 retail members, and 84,106 service locations, including idle services. No individual retail customer accounts for more than ten percent of our revenue. Our customers’ requirements for capacity and energy generally peak in fall and winter as home heating and lighting needs rise and then decline in the spring and summer as the weather becomes milder and daylight hours increase.

We supply power to the City of Seward (Seward) as a wholesale customer, and provided most of the power requirements of Matanuska Electric Association, Inc. (MEA) through the expiration of their contract on April 30, 2015.  Periodically, we sell available generation, in excess of our own needs, to Matanuska Electric Association, Inc. (MEA), Homer Electric Association, Inc. (HEA), Golden Valley Electric Association, Inc. (GVEA) and Anchorage Municipal Light & Power (ML&P). 

Our customers are billed on a monthly basis per a tariffed rate for electrical power consumed during the preceding period. Billing rates are approved by the RCA, see “Item 1 – Business – Rate Regulation and Rates.” Base rates (derived on the basis of historic cost of service including margins) are established to generate revenues in excess of current period costs in any year and such excess is designated on our Consolidated Statements of Operations, Changes in Equities and Margins, and Cash Flows as “assignable margins.” Retained assignable margins are designated on our balance sheet as “patronage capital” that is assigned to each member on the basis of patronage. Patronage capital is held for the account of the members without interest and returned when the Chugach Board of Directors deems it appropriate to do so.

In 2017, we had 531.2 megawatts (MW) of installed generating capacity (rated capacity) provided by 16 generating units at our five owned power plants: Beluga Power Plant, International Station Power Plant (historically known as “IGT”), Cooper Lake Hydroelectric Project, Southcentral Power Project (SPP), in which we own a 70% interest, and Eklutna Hydroelectric Project, in which we own a 30% interest. Of the 531.2 MW of installed generating capacity, approximately 87% was fueled by natural gas. The rest of our owned generating resources were hydroelectric facilities. In 2017,  81% of Chugach’s power, including purchased power, was generated from gas. Of that gas-fired generation, 81% took place at SPP and 14% took place at Beluga. SPP furnishes up to 200.2 MW of capacity; Chugach owns 70% of this plant’s output and Anchorage Municipal Light & Power (ML&P) owns the remaining 30%. The Bradley Lake Hydroelectric Project, which is not owned by Chugach, provides up to 27.4 MW, as currently operated, for our retail customers and up

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to 0.9 MW for our remaining wholesale customer. For more information concerning Bradley Lake, see “Item 2 – Properties – Other Property – Bradley Lake.” In addition, we purchase up to 17.6 MW from Fire Island Wind, LLC (FIW), annually. We operate 1,724 miles of distribution line and 434 miles of transmission line, which includes Chugach’s share of the Eklutna transmission line. For the year ended December 31, 2017, we sold 1.2 billion kWh of electrical power.

Customer Revenue from Sales



 

 

Picture 3

 

Picture 4

Economy energy/other includes sales to GVEA, MEA, HEA and ML&P.







Retail Service Territory

Our retail service area covers most of Anchorage, excluding downtown Anchorage, as well as remote mountain areas and villages. The service area ranges from the northern Kenai Peninsula westward to Tyonek, including Fire Island, and eastward to Whittier.

Retail Customers

As of December 31, 2017,  we had 67,992 members receiving power from 84,106 services, including idle services (some members are served by more than one service). Our customers are a mix of urban and suburban. The urban nature of our customer base means that we have a relatively high customer density per line mile. Higher customer density means that fixed costs can be spread over a greater number of customers. As a result of lower average costs attributable to each customer, we benefit from a greater stability in revenue, as compared to a less dense distribution system in which each individual customer would have a more significant impact on operating results. For the past five years no retail customer accounted for more than ten percent of our revenues. The revenue contributed by retail customers for the years ended December 31, 2017, 2016 and 2015 is discussed in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Year ended December 31, 2017, compared to the year ended December 31, 2016, and the year ended December 31, 2016, compared to the year ended December 31, 2015 – Revenues.

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Wholesale Customers

We are the principal supplier of power to Seward under a wholesale power contract. We were the principal supplier of power to MEA through April 30, 2015. Our wholesale power contracts, including the fuel and purchased power components, contributed $5.9 million, $4.9 million, and $30.9 million in revenues for the years ended December 31, 2017, 2016 and 2015, respectively.

Seward

We currently provide nearly all the power needs of the City of Seward. Sales to Seward represented approximately 5%, 5%, and 4% of Chugach’s total energy sales for the years ended December 31, 2017, 2016, and 2015, respectively. We entered into the 2006 Agreement for the Sale and Purchase of Electric Power and Energy between Chugach Electric Association, Inc. and the City of Seward (2006 Agreement), effective June 1, 2006. The 2006 Agreement contains an evergreen clause providing for automatic five-year extensions unless written notice is provided at least one year prior to the expiration date. Neither Chugach nor Seward provided written notice to terminate as both utilities desired to extend the term of the agreement.

On June 2, 2016, Chugach submitted an updated listing of its special contracts to reflect the extension of the expiration date of the 2006 Agreement from December 31, 2016, to December 31, 2021. On July 18, 2016, the RCA approved the filing.

The 2006 Agreement is an interruptible, all-requirements/no generation capacity reserves contract. It has many of the attributes of firm service, especially in the requirement that so long as Chugach has sufficient power available, it must meet Seward’s needs for power. However, service is interruptible because Chugach is under no obligation to supply or plan for generation capacity reserves to supply Seward and there is no limit on the number of times or hours per year that the supply can be interrupted. Counterbalancing this is the requirement that Chugach must provide power to Seward if Chugach has the power available after first meeting its obligations to its retail customers for whom Chugach has an obligation to provide reserves. The price under the 2006 Agreement reflects the reduced level of service because no costs of generation in excess of that needed to meet the system peak is assigned to Seward.

Economy Customers

Periodically, Chugach sells available generation, in excess of its own needs, to other electric utilities. Sales are made under the terms and conditions of Chugach’s economy energy sales tariff. The price includes the cost of fuel, variable operations and maintenance expense, wheeling charges and a margin.

We made non-firm, economy energy sales to GVEA, HEA, MEA, and ML&P on an as needed basis. Total non-firm sales were 48,526 MWh, 25,000 MWh, and 105,815 MWh for 2017, 2016, and 2015, respectively.

5


 

Rate Regulation and Rates

The RCA regulates our rates. We seek changes in our base rates by submitting Simplified Rate Filings (SRF) or through general rate cases filed with the RCA on an as-needed basis. Chugach’s base rates, whether set under a general rate case or a SRF, are established to allow the continued recovery of our specific costs of providing electric service. In each rate filing, rates are set at levels to recover all of our specific allowable costs and those rates are then collected from our retail and wholesale customers.

Alaska Statute 42.05.175 requires the RCA to issue a final order no later than 15 months after a complete tariff filing is made for a tariff filing that changes a utility’s revenue requirement or rate design. It is within the RCA’s authority to authorize, after a notice period, rate changes on an interim, refundable basis. In addition, the RCA has been willing to open limited reviews of matters to resolve specific issues from which expeditious decisions can often be rendered.

The RCA has exclusive regulatory control of Chugach’s retail and wholesale rates, subject to appeal to the Alaska courts. The regulatory environment in Alaska requires cooperatives to use a debt service coverage approach to ratemaking. Times Interest Earned Ratio (TIER) is designed to ensure Chugach maintains a coverage ratio that allows Chugach to remain in compliance with its debt covenants. Under Alaska law, financial covenants of an Alaskan electric cooperative contained in a debt instrument will be valid and enforceable, and rates set by the RCA must be adequate to meet those covenants. Under Alaska law, a cooperative utility that is negotiating to enter into a mortgage or other debt instrument that provides for a TIER greater than the ratio the RCA most recently approved for that cooperative must submit the mortgage or debt instrument to the RCA before the instrument takes effect. The rate covenants contained in the instruments governing our outstanding long-term indebtedness do not impose any greater TIER requirement than those previously approved by the RCA.

Chugach expects to continue to recover changes in its fuel and purchased power expenses through routine quarterly filings with the RCA, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations – Overview – Rate Regulation and Rates – Fuel and Purchased Power Recovery.”

The Second Amended and Restated Indenture of Trust (the Indenture), which became effective January 20, 2011, governs all of our outstanding bonds and requires us to set rates expected to yield margins for interest equal to at least 1.10 times total interest expense. The Second Amended and Restated Master Loan Agreement with CoBank, ACB (CoBank) which became effective June 30, 2016, also requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense. The Credit Agreement with National Rural Utilities Cooperative Finance Corporation (NRUCFC), KeyBank National Association, Bank of America, N.A., and CoBank, which governs the unsecured credit facility Chugach may use to meet its obligations under its commercial paper program, also requires Chugach to maintain minimum margins for interest of at least 1.10 times interest charges for each fiscal year.

For the years ended December 31, 2017, 2016 and 2015, our Margins for Interest/Interest (MFI/I) was 1.27, 1.27, and 1.29, respectively. For the same periods, our TIER was 1.28, 1.27, and 1.30, respectively.

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Our Service Areas and Local Economy

Our service areas and the service area of our wholesale customer reside within the Alaska Railbelt region of Alaska which is linked by the Alaska Railroad.

Anchorage is located in the Southcentral region of Alaska and is the trade, service, medical and financial center for most of Alaska and serves as a major center for many state governmental functions. Other significant contributing factors to the Anchorage economy include a large federal government and military presence, tourism, medical, financial and educational facilities, air and rail transportation facilities and headquarters support for the petroleum, mining and other basic industries located elsewhere in the state.

Seward is a city located at the head of Resurrection Bay on the Kenai Peninsula. Seward, which is approximately 127 miles south of Anchorage, is a major fisheries port and also serves as the ocean terminus of the Alaska Railroad. Seward’s other major industry is tourism.

Sales Forecasts

The following table sets forth our projected sales forecasts for the next five years:





 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

Sales (MWh)

 

2018

 

2019

 

2020

 

2021

 

2022

Retail

 

1,081,499 

 

1,070,110 

 

1,058,950 

 

1,061,598 

 

1,064,252 

Wholesale

 

57,676 

 

57,099 

 

56,529 

 

56,670 

 

56,811 

Total

 

1,139,175 

 

1,127,209 

 

1,115,479 

 

1,118,268 

 

1,121,063 

Energy sales are expected to slightly decline due to slow economic growth and progress in energy efficiency and conservation from 2018 to 2020, and then slightly rebound in 2021 and 2022. These projections are based on assumptions that management believes to be reasonable as of the date the projections were made. The occurrence of a significant change in any of the assumptions could affect a change in the projected sales forecast.

Item 1A – Risk Factors

Chugach’s consolidated financial results will be impacted by weather, the economy of our service territory, fuel availability and prices, and the decisions of regulatory agencies. Our creditworthiness will be affected by national and international monetary trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that, in the view of management, may significantly affect our consolidated financial condition, results of operations, and cash flows. This discussion is not exhaustive. You may view risks differently than we do, or there may be other risks and uncertainties which you consider important which are not discussed. These risks, whether discussed below or those unknown, could negatively affect our business operations and financial condition.  The statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.

Financing



On March 17, 2017, Chugach issued $40,000,000 of First Mortgage Bonds, 2017 Series A, due March 15, 2037. The bonds were issued for general corporate purposes. The 2017 Series A Bonds will mature on March 15, 2037, and bear interest at 3.43%. Interest will be paid each

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March 15 and September 15, commencing on September 15, 2017. The 2017 Series A Bonds require principal payments in equal installments on an annual basis beginning March 15, 2018, resulting in an average life of approximately 10.0 years. The bonds are secured, ranking equally with all other long-term obligations, by a first lien on substantially all of Chugach’s assets, pursuant to the Sixth Supplemental Indenture to the Second Amended and Restated Indenture of Trust, which initially became effective on January 20, 2011, as previously amended and supplemented.

Chugach is expected to continue to issue commercial paper in 2018, as needed.  For additional information concerning our Commercial Paper Program, see  “Item 8 – Financial Statements and Supplementary Data – Note 11 – Debt – Commercial Paper.” No assurance can be given that Chugach will be able to continue to access the commercial paper market. If Chugach were unable to access that market, the Credit Agreement would effectively replace Chugach’s commercial paper program. The cost of raising money in the debt capital markets could increase while the availability of funds from those markets could diminish as a result of volatile global financial markets and economic conditions.

Credit Ratings

Changes in our credit ratings could affect our ability to access capital. We maintain a rating from Standard & Poor's Rating Services (S&P) and Fitch Ratings (Fitch) of "A" (Stable) and "A" (Watch Evolving), respectively. Fitch’s Watch Evolving is driven by Chugach’s planned purchase, subject to voter and regulatory approval, of ML&P, see Item 7 – Management's Discussion and Analysis of Financial Condition and Results of OperationsPotential ML&P Acquisition.” S&P and Moody's currently rate our commercial paper at "A-1" and "P-2", respectively. If these agencies were to downgrade our ratings, particularly below investment grade, our commercial paper rates could increase immediately and we may be required to pay higher interest rates on financings which we need to undertake in the future. Additionally our potential pool of investors and funding sources could decrease.

War, acts and threats of terrorism, sabotage, cyber security breach, natural disaster, and other significant events could adversely affect our operations

We cannot predict the impact that any future terrorist attacks, sabotage, or natural disaster may have on the energy industry in general, or on our business in particular. Any such event may affect our operations in unpredictable ways, such as changes in insurance markets. Furthermore, electric generation, transmission and distribution facilities could be direct targets of, or indirect casualties of, an act of terror, sabotage, or cyber security breach. Chugach has not experienced any disruptions or significant costs associated with intentional attacks or unauthorized access to any of our systems. While Chugach has numerous programs in place to safeguard our operating systems and the personal information of our customers and employees,  a physical or cyber security compromise of our facilities could adversely affect our ability to manage our facilities effectively.

Pension Plans

We participate in the Alaska Electrical Pension Fund (AEPF). The AEPF is a multi-employer pension plan to which we make fixed, per employee contributions through our collective bargaining agreement with the IBEW, which covers our IBEW-represented workforce. We do not have control over the AEPF. Chugach receives information concerning its funding status annually. There is no

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contingent liability at this time. If a funding shortfall in the AEPF exists, we may incur a contingent withdrawal liability.

We also participate in the National Rural Electric Cooperative Association (NRECA) Retirement Security Plan (RS Plan), a multi-employer defined benefit master pension plan maintained and administered by NRECA for the benefit of its members and their employees. All employees not covered by a union agreement become participants in the RS Plan. We do not have control over the RS Plan. The RS Plan updates contribution rates on an annual basis to maintain the health of the plan under the plans rules allowed by the Employee Retirement Income Security Act (ERISA). The RS Plan’s funding status is governed by plan rules as provided by ERISA. Chugach receives information concerning its funding status biannually. The RS Plan is not subject to the Pension Protection Act of 2006 under a permanent exemption from Congress as of December 16, 2014.

On December 14, 2016 the Chugach Board of Directors approved a prepayment of $7.9 million to the NRECA Retirement Security plan. Using the low interest rate environment, this prepayment will mitigate the impact of future contribution increases and will lower annual budgetary impacts of current contributions over an 11 year term.

Equipment Failures and Other External Factors

The generation and transmission of electricity requires the use of expensive and complex equipment. While we have maintenance programs for existing equipment, along with a contractual service plan in place for SPP, generating plants are subject to unplanned outages because of equipment failure or environmental disasters. In the event of unplanned outages, we must acquire power, which is not otherwise available from the fleet of Chugach generators, from other sources at unpredictable costs in order to supply our customers and comply with our contractual agreements. The fuel and purchased power rate adjustment process allows Chugach to recover current purchased power costs and to recover under-recoveries or refund over-recoveries with a three-month lag. If Chugach were to materially under-recover purchased power costs due to an unplanned outage, we would normally seek an increase in the rate adjustment to recover those costs at the time of the next quarterly fuel and purchased power rate adjustment filing. As a result, cash flows may be impacted due to the lag in payments for purchased power costs and the corresponding collection of those costs from customers. To the extent the regulatory process does not provide for the timely recovery of purchased power costs, Chugach could experience a material negative impact on its cash flows. Chugach has line of credit and commercial paper borrowing capacity to mitigate this risk.

Fuel Supply

In 2017, 81% of our power was generated from natural gas. Our primary sources of natural gas in 2017 were Hilcorp, Chugach’s 10% share of the Beluga River Unit, and Furie Operating Alaska, LLC. Chugach currently has gas contracts in place to fill up to 100% of Chugach’s needs through March 31, 2023. Chugach also has agreements with Cook Inlet Energy (CIE) and AIX Energy, LLC, which provide a structure to purchase supplemental gas, adding diversity in Chugach’s sources of natural gas to meet system load requirements.

On May 1, 2017, the RCA approved the Furie Agreement.   The Furie Agreement provides Chugach with both firm and non-firm gas supplies over a 16-year period, with firm purchases beginning on April 1, 2023, and ending March 31, 2033, and interruptible gas purchases available to Chugach immediately and ending on March 31, 2033.  With respect to firm purchases beginning on April 1, 2023, and ending on March 31, 2033, the Furie Agreement 

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provides an Annual Gas Commitment by Furie to sell and Chugach to purchase approximately 1.8 Bcf of gas each year, which represents approximately 20% to 25% of Chugach’s projected gas requirements during this period.  The Furie Agreement also provides Chugach with additional purchase options, on a firm and interruptible basis.  The initial price for firm gas is $7.16 per thousand cubic feet (Mcf) beginning April 1, 2023 and escalates annually rising to $7.98 per Mcf on April 1, 2032, the last year of the contract.

On April 21, 2016, the RCA approved the acquisition of the Beluga River Unit effective January 1, 2016, as discussed in “Item 8 - Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Beluga River Unit and Note 15 – Beluga River Unit.” The acquisition complements existing gas supplies and is expected to provide greater fuel diversity at an effective annual cost that is $2 million to $3 million less than alternative sources of gas in the Cook Inlet region.

The acquisition is expected to provide gas to meet Chugach’s on-going generation requirements over an approximate 18-year period beginning in 2016. Gas associated with the acquisition is expected to provide about 15% of Chugach’s gas requirements through 2033, although actual gas quantities produced are expected to vary on a year-by-year basis.

The State of Alaska’s Department of Natural Resources (DNR) published a study in September of 2015, “Updated Engineering Evaluation of Remaining Cook Inlet Gas Reserves,” to provide an estimate of Cook Inlet’s gas supply. The study estimated there are 1,183 Bcf of proved and probable reserves remaining in Cook Inlet’s legacy fields. This is higher than the 2009 DNR study estimate of 1,142 Bcf.  Effectively, Cook Inlet gas supply has slightly increased from 2009. The 2015 DNR estimate does not include reserves from a large gas field developed and in production by Furie and another considered for development by BlueCrest Energy, Inc. Furie has constructed an offshore gas production platform and has achieved commercial production. The platform and other production facilities are designed for up to 200 million cubic feet (MMcf) per day. Other gas producers are actively developing gas supplies in the Cook Inlet. Chugach is encouraged with these developments but continues to explore other alternatives to diversify its portfolio.

The Alaska Gasline Development Corporation (AGDC) is investigating a project to deliver North Slope gas to Southcentral Alaska for export. AGDC expects to complete the FERC license application and assess gas markets by mid-2018. The gas pipeline is expected to include off-take points to allow for the opportunity for future in-state deliveries of natural gas. If the project moves forward, the pipeline is expected to be completed in the mid 2020’s.

Cook Inlet Natural Gas Storage Alaska (CINGSA) began service April 1, 2012. The facility ensures local utilities, including Chugach, have gas available to meet deliverability requirements during peak periods and store gas during low demand periods. The RCA approved inception rates and a tariff for the CINGSA facility on January 31, 2011, and a Firm Storage Service (FSS) Agreement between the seller and Chugach in July of 2011. Injections into the facility began in 2012. Chugach's share of the capacity was 1.6 Bcf in 2017. Chugach is entitled to withdraw gas at a rate of up to 31 million cubic feet (MMcf) per day.

Recovery of Fuel and Purchased Power Costs

The RCA approved inclusion of all fuel and transportation costs related to our current contracts in the calculation of Chugach’s fuel and purchased power adjustment process which will ensure, in

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advance, that costs incurred under the contracts can be recovered from Chugach’s customers. The fuel and purchased power adjustment process collects under-recoveries and refunds over-recoveries from prior periods with minimal regulatory lag. Chugach's fuel and purchased power adjustment process includes quarterly filings with the RCA, which set the rates on projected costs, sales and system operations for the quarter. Any under- or over-recovery of costs is incorporated into the following quarterly filing. Chugach under-recovered $4.9 million at December 31, 2017, and had over-recovered $3.8 million at December 31, 2016. To the extent the regulated fuel and purchased power adjustment process does not provide for the timely recovery of costs, Chugach could experience a material negative impact on its cash flows. Chugach has line of credit and commercial paper borrowing capacity to mitigate this risk.

Regulatory

Chugach’s billing rates are approved by the RCA. Chugach is a participant in the Simplified Rate Filing (SRF) process for adjustments to base demand and energy rates for Chugach retail customers and wholesale customer, Seward. SRF is an expedited base rate adjustment process available to electric cooperatives in the State of Alaska, with filings made either on a quarterly or semi-annual basis. Chugach is a participant on a quarterly filing schedule basis. See “Item 8 - Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Simplified Rate Filings.”

To the extent the RCA does not allow for the recovery of our costs associated with our current or anticipated rate cases, Chugach could experience a material negative impact on its results of operations, financial position and cash flows.

Accounting Standards or Practices

We cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or our operations specifically. New accounting standards could be issued that could change the way we record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect our reported earnings or could increase reported liabilities.

Green House Gas Regulations, Carbon Emission and Climate Change

Uncertainty remains regarding the impacts of potential regulations regarding greenhouse gases (GHG), carbon emissions, and climate change on Chugach’s operations. The United States Environmental Protection Agency (EPA) is moving forward with regulations that seek to limit carbon emissions in the United States. Power plants are the single largest source of carbon emissions in the United States. On August 3, 2015, the EPA released the final 111(d) regulation aimed at reducing emissions of carbon dioxide (CO2) from existing power plants. Alaska is not bound by the 111(d) regulation, however Alaska may be required to comply at some future date. On February 9, 2016 the U.S. Supreme Court issued a stay on the proposed EPA 111(d) regulations until the DC Circuit decides the case, or until the disposition of a petition to the Supreme Court on the issue. On September 27, 2016, the US Court of Appeals for the District of Columbia Circuit heard oral arguments challenging the legality of the Clean Power Plan. While awaiting the court decision, an Executive Order promoting energy independence and economic growth was issued on March 28, 2017, by the President instructing the EPA to review the Clean Power Plan. The EPA is directed to review the Clean Power Plan rule and either revise or withdraw the proposed rule. On October 10, 2017, the EPA initiated a Proposed Repeal of the

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Clean Power Plan.  EPA 111(d) regulation, in its current form, is not expected to have a material effect on Chugach’s financial condition, results of operations, or cash flows.

Additional costs related to a GHG tax or cap and trade program, if enacted by Congress, or other regulatory action, could affect the relative cost of the energy Chugach produces. While Chugach cannot predict the implementation of any additional new law or regulation, or the limitations thereof, it is possible that new laws or regulations could increase capital and operating costs. Chugach has obtained or applied for all Clean Air Act permits currently required for the operation of generating facilities.

Other Environmental Regulations

Since January 1, 2007, transformer manufacturers have been required to meet the United States Department of Energy (DOE) efficiency levels as defined by the Energy Act of 2005 (Energy Act) for all “Distribution Transformers.” As of January 1, 2016, the specific efficiency levels increased from the original “TP1” levels to the new “DOE-2016” levels. All new transformers are DOE-2016 compliant. At this time a small increase in capital costs is anticipated along with a reduction in energy losses.

Chugach is currently required to comply with numerous federal, state and local laws and regulations relating to the protection of the environment. While we believe Chugach has obtained all material environmental-related approvals currently required to own and operate our facilities, Chugach may incur significant additional costs because of compliance with these requirements in addition to costs related to any costs of compliance with laws or regulations relating to GHG or carbon emissions. Failure to comply with environmental laws and regulations could have a material effect on Chugach, including potential civil or criminal liability and the imposition of fines or expenditures of funds to bring our facilities into compliance. Delay in obtaining, or failure to obtain and maintain in effect any environmental approvals, or the delay or failure to satisfy any applicable environmental regulatory requirements related to the operation of our existing facilities could result in significant additional costs to Chugach and a material adverse impact to Chugach’s results of operations, financial condition, and cash flows.

Aging Plant

Many of our facilities were constructed over 30 years ago and, as a result, may require significant capital expenditures to maintain efficiency and reliability. As plant equipment ages, the potential for operational issues such as unscheduled outages increases which could negatively impact our cost of electric service. With the addition of the SPP generating facility which began operation in 2013, we are able to significantly reduce the reliance on some of the older facilities. The older units are used for peaking, and, in the future, may be primarily used as a reserve. Mitigating the aging risk is Chugach’s experienced work force, extensive maintenance program, and predictive maintenance measures. Also mitigating the risk of significant unanticipated capital expenditures associated with generation maintenance is a long-term service agreement smoothing major maintenance costs for our largest power producer, SPP. Additionally, we are working to establish the Power Pooling and Joint Dispatch Agreement which will allow us to buy power from other utilities if it is more efficient and economical than generating power on our own.

Distributed Generation

Distributed generation technologies, such as combined heat and power, solar cells, micro turbines, fuel cells, batteries, and wind turbines currently exist or are in development. Significant

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technological advancements or positive perceptions regarding the environmentally friendly benefits of self-generation and distributed energy technologies could lead to the adoption of these technologies by our members. Increased adoption of these technologies could reduce demand for electricity and the pool of customers from whom we recover fixed costs. This could have a negative impact on our business, financial condition, or cost of electric service.

Constraints on Transmission

We currently experience occasional constraints on our transmission system and those of other utilities used to transmit energy from our remote generators to loads due to periodic maintenance activities, equipment failures and other system conditions. We manage these constraints using alternative generation dispatch and energy purchasing patterns. The long-term solution for reducing transmission constraints include purchasing additional wheeling service from other utilities, or construction of additional transmission lines which would require significant capital expenditures.

Construction of new transmission lines presents numerous challenges. Environmental and state and local permitting processes can result in significant inefficiencies and delays in construction. These issues are unavoidable and are addressed through long-term planning. We typically begin planning new transmission at least 10 years in advance of the need and foster and participate in regional and interregional transmission planning and cost allocation discussions with neighboring transmission providers. In the event that we are unable to complete construction of planned transmission expansion, we must rely on purchases of electric power, which could put increased pressure on electric rates.

Counterparties

We rely on other entities in the production of power and supply of fuel and therefore, we are exposed to the risk that these counterparties may default in performance of their obligations to us. As a 70% owner in SPP, a 30% owner in the Eklutna Hydroelectric Project, and a 10% owner in the Beluga River Unit (BRU), we rely upon the other owners to fulfill their contractual and financial obligations. Additionally we rely on numerous other entities with whom we have purchased power agreements. Failure of our counterparties to perform their obligations could increase the cost of electric service we provide to our members as we, for example, may be forced to enter into alternative contractual arrangements or purchase energy or natural gas at prices that may exceed the prices previously agreed upon with the defaulting counterparty.

Legal Proceedings

Chugach has certain litigation matters and pending claims that arise in the ordinary course of business as discussed under “Item 3 – Legal Proceedings.” We cannot predict the outcome of any current or future legal proceedings. Our business, financial condition, and results of operations could be materially adversely affected by unfavorable resolution or adverse results of legal matters.

These factors, as well as weather, interest rates and economic conditions are largely beyond our control, but may have a material adverse effect on our earnings, cash flows and financial position.

Item 1B – Unresolved Staff Comments

None

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Item 2 Properties

General

As of December 31, 2017, we had 531.2 MW of installed capacity consisting of 16 generating units at five power plants. These included 332.0 MW of operating capacity at the Beluga facility on the west side of Cook Inlet; 140.1 MW at SPP in Anchorage, which we jointly own with ML&P; 28.2 MW at IGT in Anchorage; and 19.2 MW at the Cooper Lake facility, which is on the Kenai Peninsula. We also own rights to 11.7 MW of capacity from the two Eklutna Hydroelectric Project generating units that we jointly own with MEA and ML&P.

In addition to our own generation, we purchased power from the 120 MW Bradley Lake Hydroelectric Project, which is owned by the Alaska Energy Authority (AEA), operated by Homer Electric Association, Inc. (HEA) and dispatched by Chugach, and MEA’s newly constructed 171 MW Eklutna Generation Station (EGS). We also purchased power from FIW.

The Beluga, IGT and SPP facilities are fueled by natural gas. We own our offices and headquarters, located adjacent to IGT and SPP in Anchorage. We also lease warehouse space for some generation, transmission and distribution inventory (including a small amount of office space).

Generation Assets

We own the land and improvements comprising our generating facilities at Beluga, IGT and SPPOur principal generation assets are in two plants, Beluga and SPP. With SPP in operation, the Beluga units are used for peaking, and in the future, may be primarily used as reserve. While the Beluga turbine-generators have been in service for many years, they have been maintained in good working order with scheduled inspections and periodic upgrades. All Beluga units are inspected annually with combustion and hot gas path parts replaced according to their condition or as recommended by the manufacturer. Units 3 and 5 are most often run for peak demand and are being considered for major parts replacements and generator inspections over the next three years.



On February 1, 2013, SPP began commercial operation, contributing 200.2 MW of capacity provided by 4 generating units. Chugach owns 70% of this plant and ML&P owns the remaining 30%. Each owner takes a proportionate share of power from SPP. Our principal generation units at SPP are Units 10, 11, 12, and 13. Since the units have been in commercial operation, SPP units have received preventative maintenance inspections consistent with original equipment manufacturer (OEM) recommendations through 2017. The gas turbine generators of Units 11, 12, and 13 receive two internal combustion system inspections each and one full package inspection annually. In 2017, Unit 13 gas turbine was replaced with a spare gas turbine. The removed gas turbine was prepared for another full cycle of operation by the OEM and Chugach technicians under our Contractual Service Agreement and later installed in Unit 11 when it began to show evidence of bearing failure, per the OEM recommendation.  Unit 10 steam turbine received a scheduled inspection consistent with OEM specifications. All three steam-generating boilers were internally inspected as well as hydrotested in accordance with OEM recommendations.

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The Cooper Lake Hydroelectric Project is partially located on federal lands. Chugach owns, operates and maintains the Cooper Lake project subject to a 50-year license granted to us by FERC in August of 2007. As part of the relicensing process, a Relicensing Settlement Agreement (RSA) was entered into in August of 2005. A requirement of the RSA required Chugach to establish a flow regime in Cooper Creek below the Cooper Lake Dam; designed to replace colder water flowing into the Cooper Creek drainage from Stetson Creek with warmer Cooper Lake water. This project included a Stetson Creek Diversion (Dam), Pipeline (Conveyance System) and Cooper Lake Outlet Works. Project construction was completed in July 2015.

The two generating units at Cooper Lake, Units 1 and 2, have a combined capacity of 19.2 MW. Both units were taken out of service for annual maintenance in August of 2016 and 2017.

The Eklutna Hydroelectric Project is located on federal land subject to a United States Bureau of Land Management right-of-way grant issued in October of 1997. The facility is jointly owned, operated and maintained by Chugach, MEA, and ML&P with ownership shares of 30%, 17%, and 53%, respectively. Chugach owns rights to 11.7 MW of capacity from the two Eklutna Hydroelectric Project generating units. 

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The following matrix depicts nomenclature, run hours for 2017, percentages of contribution and other historical information for all Chugach generation units.





 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

Facility

 

Commercial Operation Date

 

Nomenclature

 

Rating
(MW)(1)

 

Run
Hours
(2017)

 

Percent of Total Run Hours

 

Percent of Time Available

Beluga Power Plant (2)

1

 

1968

 

GE Frame 5

 

19.6 

 

231.8 

 

0.53 

 

86.2 

2

 

1968

 

GE Frame 5

 

19.6 

 

256.6 

 

0.59 

 

89.3 

3

 

1973

 

GE Frame 7

 

64.8 

 

594.0 

 

1.36 

 

73.6 

5

 

1975

 

GE Frame 7

 

68.7 

 

3,337.5 

 

7.66 

 

94.3 

6

 

1976

 

GE 11DM-EV

 

79.2 

 

855.7 

 

1.96 

 

91.3 

7

 

1978

 

GE 11DM-EV

 

80.1 

 

1,348.2 

 

3.09 

 

91.6 



 

 

 

 

 

332.0 

 

 

 

 

 

 

Cooper Lake Hydroelectric Project

1

 

1960

 

BBC MV 230/10

 

9.6 

 

875.0 

 

2.01 

 

96.7 

2

 

1960

 

BBC MV 230/10

 

9.6 

 

2,854.0 

 

6.55 

 

96.7 



 

 

 

 

 

19.2 

 

 

 

 

 

 

IGT Power Plant (7)

1

 

1964

 

GE Frame 5

 

14.1 

 

9.5 

 

0.02 

 

91.5 

2

 

1965

 

GE Frame 5

 

14.1 

 

8.7 

 

0.02 

 

100.0 



 

 

 

 

 

28.2 

 

 

 

 

 

 

Southcentral Power Project

10

 

2013

 

Mitsubishi SC1F-29.5 (6)

 

40.2 

(5)

8,144.5 

 

18.69 

 

93.0 

11

 

2013

 

GE LM6000 PF

 

33.3 

(5)

8,359.9 

 

19.19 

 

96.4 

12

 

2013

 

GE LM6000 PF

 

33.3 

(5)

8,310.2 

 

19.07 

 

94.9 

13

 

2013

 

GE LM6000 PF

 

33.3 

(5)

8,387.5 

 

19.26 

 

95.7 



 

 

 

 

 

140.1 

 

 

 

 

 

 

Eklutna Hydroelectric Project

1

 

1955

 

Newport News

 

5.8 

(3)

N/A

(4)

 

 

42.6 

2

 

1955

 

Oerlikon custom

 

5.9 

(3)

N/A

(4)

 

 

94.7 



 

 

 

 

 

11.7 

 

 

 

 

 

 

System Total

 

 

 

531.2 

 

43,573.1 

 

100.00 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

(1) Capacity rating in MW at 30 degrees Fahrenheit.

(2) Beluga Unit 4 was retired during 1994.  Beluga Unit 8 was retired in April of 2015.

(3) The Eklutna Hydroelectric Project is jointly owned by Chugach, MEA and ML&P. The capacity shown is our 30% share of the plant's output under normal operating conditions. The actual nameplate rating on each unit is 23.5 MW.

(4) Run hours are not recorded by Chugach for the Eklutna Hydroelectric Project as it is maintained by a committee of three owners.

(5) The Southcentral Power Project is jointly owned by Chugach and ML&P. The capacity shown is our 70% share of the plant's output under normal operating conditions. The actual nameplate rating for the project is 200.2 MW.

(6) Steam-turbine powered generator with heat provided by exhaust from natural gas fueled Units 11, 12 and 13 and additional heat from supplemental duct firing in the once through steam generators associated with the respective gas turbines (combined-cycle).

(7) IGT Unit 3 was retired in August of 2015.

Note: GE = General Electric, BBC = Brown Boveri Corporation

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Transmission and Distribution Assets

As of December 31, 2017, our transmission and distribution assets included 43 substations and 434 miles of transmission lines, which included Chugach’s share of the Eklutna transmission line, 896 miles of overhead distribution lines and 828 miles of underground distribution line. We own the land on which 25 of our substations are located and a portion of the right-of-way connecting our Beluga plant to Anchorage. As part of our 1997 acquisition of 30% of the Eklutna Hydroelectric Project, we also acquired a partial interest in two substations and additional transmission facilities.

Most of Chugach’s generation sites and many of its substation sites are on Chugach-owned lands. The rights for the sites not on Chugach-owned lands are as follows: the Postmark and Point Woronzof Substations, and the East Terminal Site (North - South Runway) are authorized by the State Department of Transportation and Public Facilities, Ted Stevens Anchorage International Airport; the East Terminal Site (Six Mile) is under rights from Joint Base Elmendorf-Richardson; the West Terminal Site is authorized by the Matanuska-Susitna Borough; the University Substation is on State land under rights from the Federal Bureau of Land Management; the Hope and Daves Creek Substations are authorized by the State; the Portage Substation has a permit from the Alaska Railroad Corporation (ARRC); the Summit Lake Substation is on land recently conveyed to the Kenai Peninsula Borough (permit pending) and a permit from the United States Forest Service; the Dowling and Raspberry Substations are on Municipality of Anchorage land under rights from the State; and, the Indian Substation is authorized by FERC License, until a permit is issued by Chugach State Park. The Cooper Lake Power Plant, Quartz Creek Substation, and the 69kV transmission line between them are operated under the FERC License. Most of Chugach’s transmission, sub-transmission and distribution lines are either on public lands under rights from federal, state, municipal, borough agencies, ARRC, or on private lands via easements.

Title

On January 20, 2011, Chugach and the indenture trustee entered into the Indenture, granting a lien on substantially all of Chugach’s assets to secure Chugach’s long-term debt. Assets that are generally not subject to the lien of the Indenture include cash (other than cash deposited with the indenture trustee); instruments and securities; patents, trademarks, licenses and other intellectual property; vehicles and other movable equipment; inventory and consumable materials and supplies; office furniture, equipment and supplies; computer equipment and software; office leases; other leasehold interests for an original term of less than five years; contracts (other than power sales agreements with members having an original term exceeding three years, certain contracts specifically identified in the Indenture, and other contracts relating to the ownership, operation or maintenance of generation, transmission or distribution facilities); non-assignable permits, licenses and other contract rights; timber and minerals separated from land; electricity, gas, steam, water and other products generated, produced or purchased; other property in which a security interest cannot legally be perfected by the filing of a Uniform Commercial Code financing statement, and certain parcels of real property specifically excepted from the lien of the Indenture. The lien of the Indenture may be subject to various permitted encumbrances that include matters existing on the date of the Indenture or the date on which property is later acquired; reservations in United States patents; non-delinquent or contested taxes, assessments and contractors’ liens; and various leases, rights-of-way, easements, covenants, conditions, restrictions, reservations, licenses and permits that do not materially impair Chugach’s use of the mortgaged property in the conduct of Chugach’s business.

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Many of Chugach’s properties are burdened by easements, plat restrictions, mineral reservation, water rights and similar title exceptions common to the area or customarily reserved in conveyances from federal or state governmental entities, and by additional minor title encumbrances and defects. We do not believe that any of these title defects will materially impair the use of our properties in the operation of our business.

Under the Alaska Electric and Telephone Cooperative Act, we possess the power of eminent domain for the purpose and in the manner provided by Alaska condemnation laws for acquiring private property for public use.

Other Property

Bradley Lake

We are a participant in the Bradley Lake Hydroelectric Project, which is a 120 MW rated capacity hydroelectric facility near Homer on the southern end of the Kenai Peninsula that was placed into service in September 1991. The project is nominally scheduled below 90 MW to minimize losses and ensure system stability. We have a 30.4% (27.4 MW as currently operated) share in the Bradley Lake project’s output, and currently take Seward’s share which we net bill to them, for a total of 31.4% of the project’s capacity. We are obligated to pay 30.4% of the annual project costs regardless of project output.

The project was financed and built by AEA through grants from the State of Alaska and the issuance of $166.0 million principal amount of revenue bonds supported by power sales agreements with six electric utilities that share the output from the facility (ML&P, HEA and MEA (through Alaska Electric Generation & Transmission Cooperative, Inc. (AEG&T) and Alaska Electric and Energy Cooperative, Inc. (AEEC)), GVEA, Seward and us). The participating utilities have entered into take-or-pay power sales agreements under which AEA has sold percentage shares of the project capacity and the utilities have agreed to pay a like-percentage of annual costs of the project (including ownership, operation and maintenance costs, debt-service costs and amounts required to maintain established reserves). By contract, we also provide transmission and related services to all of the participants in the Bradley Lake project.

The term of our Bradley Lake power sales agreement is 50 years from the date of commercial operation of the facility (September 1991) or when the revenue bond principal is repaid, whichever is longer. The agreement may be renewed for successive 40-year periods or for the useful life of the project, whichever is shorter. We believe that so long as this project produces power taken by us for our use that this expense will be recoverable through the fuel and purchased power adjustment process. The share of Bradley Lake indebtedness for which we are responsible is approximately $16.3 million. Upon the default of a participant, and subject to certain other conditions, AEA is entitled to increase each participant’s share of costs and output pro rata, to the extent necessary to compensate for the failure of the defaulting participant to pay its share, provided that no participant’s percentage share is increased by more than 25%. Upon default, Chugach could be faced with annual expenditures of approximately $6.0 million as a result of Chugach’s Bradley Lake take-or-pay obligations.

The Battle Creek Diversion Project (Project) is a project to increase water available for generation by constructing a diversion on the West Fork of Upper Battle Creek to divert flows to Bradley Lake, increasing annual energy output by an estimated 37,000 MWh. The Bradley Lake Project Management Committee (BPMC) approved the project October 13, 2017, as amended December 1,

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2017, and December 6, 2017.  The Project cost is estimated at $47.0 million and the BMPC approved financing in this amount on December 6, 2017.  The project is estimated to begin in the Spring of 2018 with an estimated completion date of 2020.  Not all Bradley Lake purchasers are participating in the development and resulting benefits of the Project at this time, although they have preserved their ability to participate in the Project at a later date.  Chugach would be entitled to 39.38% of the additional energy produced if no additional participants elect to join.    

Eklutna

Along with two other utilities, Chugach purchased the Eklutna Hydroelectric Project from the Federal Government in 1997. Ownership was transferred from the DOE’s Alaska Power Administration jointly to Chugach (30%), MEA (17%) and ML&P (53%). Through April 30, 2015, the power MEA purchased from the Eklutna Hydroelectric Project was pooled with Chugach’s purchases and sold back to MEA to be used to meet MEA’s overall power requirements.

Beluga River Unit (BRU)

On April 22, 2016, Chugach commenced receiving gas from the BRU as a Working Interest Owner (WIO) of the gas production field. Chugach acquired a 10% working interest in the BRU by jointly purchasing, in partnership with ML&P, ConocoPhillips’ 1/3 Working Interest Ownership of the BRU.  In 2017 Chugach received 1.4 Bcf from the BRU field at the field’s delivery meter as a WIO. Of that gas volume received Chugach allocated gas deliveries of 875 MMcf to the ConocoPhillips-ENSTAR contract (average price of $7.57 per Mcf) and retained 506 MMcf for Chugach native use in thermal generation, which had a weighted average transfer price of $4.64 per Mcf.

Fuel Supply

In 2017, 81% of our power was generated from natural gas. Total gas purchased and produced in 2017 was approximately 9.3 Bcf. All of the production came from Cook Inlet, Alaska. The contract with Hilcorp provided 89%, Furie provided 5%, Chugach’s 10% share of the Beluga River Unit gas field provided 5%, and the balance from minor purchases from AIX and CIE. Of the 9.3 Bcf of gas purchased and produced, 0.9 Bcf was sold to ENSTAR as part of an existing ConocoPhillips-ENSTAR gas contract that was assumed with Chugach’s share of the BRU acquisition. The current gas contract with Hilcorp began providing gas in 2011 and will expire March 31, 2023. The BRU and Hilcorp, together, fill 100% of Chugach’s firm needs through March 31, 2023. The gas contract with Furie currently provides Chugach with additional purchase options, on a firm and interruptible basis, and will provide both firm and non-firm gas supplies beginning on April 1, 2023 and ending March 31, 2033. 

Hilcorp

Chugach entered into a contract with Hilcorp to provide gas beginning January 1, 2015, and through multiple amendments, now extends through March 31, 2023. The total amount of gas under contract is currently estimated to be 60 Bcf. Pricing for the 2017 term of the Hilcorp contract was set at $7.73 per Mcf.

Furie Agreement

On March 16, 2017, Chugach submitted a request to the RCA for approval of the agreement entitled, “Firm and Interruptible Gas Sale and Purchase Agreement between Furie Operating Alaska, LLC and Chugach Electric Association, Inc.” (Furie Agreement) dated March 3, 2017. As

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part of the filing, Chugach requested RCA approval to recover both firm and interruptible purchases under the agreement and all attendant transportation and storage costs through its quarterly fuel and purchased power cost adjustment process.

The Furie Agreement provides Chugach with both firm and non-firm gas supplies over a 16-year period, with firm purchases beginning on April 1, 2023, and ending March 31, 2033, and interruptible gas purchases available to Chugach immediately and ending on March 31, 2033. With respect to firm purchases beginning on April 1, 2023, and ending on March 31, 2033, the Furie Agreement provides an annual gas commitment by Furie to sell and Chugach to purchase approximately 1.8 Bcf of gas each year, which represents approximately 20% to 25% of Chugach’s projected gas requirements during this period. The Furie Agreement also provides Chugach with additional purchase options, on a firm and interruptible basis. The initial price for firm gas is $7.16 per Mcf beginning April 1, 2023 and escalates annually rising to $7.98 per Mcf on April 1, 2032, the last year of the Furie Agreement.

On May 1, 2017, the RCA approved the Furie Agreement. The RCA also approved recovery of costs associated with the Furie Agreement through its fuel and purchased power cost adjustment process.

Cook Inlet Energy, LLC

Chugach entered into a Gas Sale and Purchase Agreement (GSPA) with CIE in 2013, to supply gas from April 1, 2014, through March 31, 2018, with an option to extend for an additional five years by mutual agreement during the term of the GSPA. In an extension letter agreement dated February 17, 2017, both parties agreed to extend the term of the agreement until March 31, 2023. The GSPA with CIE provides Chugach with an opportunity to diversify its gas supply portfolio, and minimize its current dependence on the gas agreements in place with two vendors. The gas that may be purchased under the GSPA with CIE is not required, however it introduces a new pricing mechanism.

The GSPA identifies and defines two types of gas purchases. Base Gas is defined by the volume of gas purchased on a firm or interruptible basis at an agreed delivery rate. Pricing for base gas purchases ranges from $6.12 to $7.31 per Mcf. Swing Gas is gas sold to Chugach at a delivery rate in excess of the applicable Base Gas agreed delivery rate. Pricing for swing gas purchases ranges from $7.65 to $9.14 per Mcf.

AIX Energy, LLC

Chugach entered into a contract with AIX Energy, LLC (AIX) in 2014, to supply gas from March 1, 2015, through February 29, 2016. This agreement caps the price of gas at $6.24 per Mcf and the total volume at 300,000 Mcf. In anticipation of this agreement’s expiration, Chugach entered into another gas sale and purchase agreement with AIX in November of 2015, to provide gas beginning April 1, 2016, through March 31, 2023, with the option to extend to March 31, 2029. The AIX agreements provide flexibility in both the purchase price and volumes and allow Chugach to further diversify its gas supply portfolio, with no minimum purchase requirements.

20


 

Municipality of Anchorage, dba Municipal Light and Power

Chugach entered into a contract with Municipality of Anchorage, DBA Municipal Light and Power (ML&P) in 2016, to supply gas beginning June 6, 2016, and expiring March 31, 2017. This agreement capped the price of gas at $5.75 per Mcf and the total volume at 500,000 Mcf. The ML&P agreement provided Chugach the ability to further diversify its gas supply portfolio, with no minimum purchase requirements.

Natural Gas Transportation Contracts

The terms of the ML&P and Hilcorp agreements require Chugach to transport gas. Chugach took over the transportation obligation for natural gas shipments for gas supplied under its contracts on October 1, 2010. The following information summarizes the transportation obligations for Chugach:

ENSTAR (Alaska Pipeline Company)

ENSTAR Natural Gas Company (ENSTAR) has a tariff to transport our gas purchased from gas suppliers on a firm basis to our IGT Power Plant and SPP.

Chugach and ENSTAR entered into a Firm Transportation Service Agreement on May 21, 2012, to provide for the transportation of gas to SPP. The agreement commenced on August 1, 2012, and remains in effect until canceled upon a 12-month written notice by either party. The agreement sets a contracted peak demand of 36,300 Mcf per day.

Harvest Alaska, LLC Pipeline System

Hilcorp now operates four major gas pipelines through Harvest Alaska, LLC, in the Cook Inlet basin, including the Kenai-Nikiski Pipeline (KNPL), the Beluga Pipeline (BPL), the Cook Inlet Gas Gathering System (CIGGS) and the Kenai-Kachemak Pipeline (KKPL).

On November 1, 2014, the RCA approved consolidation of these four pipelines into a single pipeline, the KBPL. Chugach has entered into tariff agreements to ship gas on the KBPL.

Environmental Matters

Chugach’s operations are subject to certain federal, state and local environmental laws and regulations, which seek to limit air, water and other pollution and regulate hazardous or toxic waste disposal. While we monitor these laws and regulations to ensure compliance, they frequently change and often become more restrictive. When this occurs, the costs of our compliance generally increase.

We include costs associated with environmental compliance in both our operating and capital budgets. We accrue for costs associated with environmental remediation obligations when those costs are probable and reasonably estimable. We do not anticipate that environmental related expenditures will have a material effect on our results of operations or financial condition. We cannot, however, predict the nature, extent or cost of new laws or regulations relating to environmental matters.

Since January 1, 2007, transformer manufacturers have been required to meet the DOE efficiency levels as defined by the Energy Act for all “Distribution Transformers.” As of January 1, 2016, the specific efficiency levels increased from the original “TP1” levels to the new “DOE-2016” levels.

21


 

All new transformers are DOE-2016 compliant. A small increase in capital costs is anticipated along with a reduction in energy losses.

The Clean Air Act and Environmental Protection Agency (EPA) regulations under the Clean Air Act establish ambient air quality standards and limit the emission of many air pollutants. New Clean Air Act regulations impacting electric utilities may result from future events or new regulatory programs. On August 3, 2015, the EPA released the final 111(d) regulation language aimed at reducing emissions of carbon dioxide (CO2) from existing power plants that provide electricity for utility customers. In the final rule, the EPA took the approach of making individual states responsible for the development and implementation of plans to reduce the rate of CO2 emissions from the power sector. The EPA initially applied the final rule to 47 of the contiguous states. At this time, Alaska, Hawaii, Vermont, Washington District of Columbia (D.C.) and two U.S. territories are not bound by the regulation. Alaska may be required to comply at some future date. On February 9, 2016 the U.S. Supreme Court issued a stay on the proposed EPA 111(d) regulations until the D.C. Circuit decides the case, or until the disposition of a petition to the Supreme Court on the issue. On September 27, 2016, the U.S. Court of Appeals for the D.C. Circuit heard oral arguments challenging the legality of the Clean Power Plan. While awaiting the court decision, an Executive Order promoting energy independence and economic growth was issued March 28, 2017, by the President instructing the EPA to review the Clean Power Plan. The EPA is directed to review the Clean Power Plan rule and either revise or withdraw the proposed rule. On October 10, 2017, the EPA initiated a Proposed Repeal of the Clean Power Plan. The EPA 111(d) regulation, in its current form, is not expected to have a material effect on Chugach’s financial condition, results of operations, or cash flows. While Chugach cannot predict the implementation of any additional new law or regulation, or the limitations thereof, it is possible that new laws or regulations could increase capital and operating costs. Chugach has obtained or applied for all Clean Air Act permits currently required for the operation of generating facilities.

Chugach is subject to numerous other environmental statutes including the Clean Water Act, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Endangered Species Act, and the Comprehensive Environmental Response, Compensation and Liability Act and to the regulations implementing these statutes. Chugach does not believe that compliance with these statutes and regulations to date has had a material impact on its financial condition, results of operation or cash flows. However, the implementation of any additional new law or regulation, or the limitations thereof, or changes in or new interpretations of laws or regulations could result in significant additional capital or operating expenses. Chugach monitors proposed new regulations and existing regulation changes through industry associations and professional organizations.

Item 3 Legal Proceedings

Chugach has certain litigation matters and pending claims that arise in the ordinary course of Chugach’s business. In the opinion of management, none of these other matters, individually, or in the aggregate, is or are likely to have a material adverse effect on Chugach’s results of operations, financial condition or cash flows.

Item 4 – Mine Safety Disclosures

Not Applicable

22


 

PART II

Item 5 Market for Registrant's Common Equity, Related Stockholder Matters

and Issuer Purchases of Equity Securities

Not Applicable

Item 6 Selected Financial Data



The following table presents selected historical information relating to financial condition and results of operations for the years ended December 31:





 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Data

2017

 

2016

 

2015

 

2014

 

2013

Electric plant, net:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

In service

$

689,595,912 

 

$

696,415,738 

 

$

659,275,066 

 

$

657,899,592 

 

$

670,476,634 

Construction work in progress

 

17,952,573 

 

 

18,455,940 

 

 

15,601,374 

 

 

21,567,341 

 

 

28,674,163 

Electric plant, net

 

707,548,485 

 

 

714,871,678 

 

 

674,876,440 

 

 

679,466,933 

 

 

699,150,797 

Other assets

 

129,970,259 

 

 

121,284,452 

 

 

110,437,674 

 

 

126,244,688 

 

 

139,033,241 

Total assets

$

837,518,744 

 

$

836,156,130 

 

$

785,314,114 

 

$

805,711,621 

 

$

838,184,038 

Capitalization:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

456,327,846 

 

 

442,890,253 

 

 

446,227,620 

 

 

473,024,497 

 

 

496,914,274 

Equities and margins

 

189,301,294 

 

 

185,515,525 

 

 

181,637,381 

 

 

176,925,299 

 

 

175,795,865 

Total capitalization

$

645,629,140 

 

$

628,405,778 

 

$

627,865,001 

 

$

649,949,796 

 

$

672,710,139 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Ratio1

 

29.3% 

 

 

29.5% 

 

 

28.9% 

 

 

27.2% 

 

 

26.1% 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operations Data

 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

$

224,688,669 

 

$

197,747,579 

 

$

216,421,152 

 

$

281,318,513 

 

$

305,308,427 

Operating expenses

 

197,217,684 

 

 

171,140,389 

 

 

188,791,558 

 

 

252,972,879 

 

 

278,738,497 

Interest expense

 

22,366,034 

 

 

21,856,095 

 

 

22,194,290 

 

 

23,264,041 

 

 

24,691,582 

Capitalized interest

 

(164,898)

 

 

(454,798)

 

 

(379,845)

 

 

(463,335)

 

 

(1,310,110)

Net operating margins

 

5,269,849 

 

 

5,205,893 

 

 

5,815,149 

 

 

5,544,928 

 

 

3,188,458 

Nonoperating margins

 

778,875 

 

 

607,963 

 

 

687,703 

 

 

970,617 

 

 

7,355,585 

Assignable margins

$

6,048,724 

 

$

5,813,856 

 

$

6,502,852 

 

$

6,515,545 

 

$

10,544,043 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

Margins for Interest Ratio2

1.27 

 

 

1.27 

 

 

1.29 

 

 

1.28 

 

 

1.43 

1 Equity ratio equals equities and margins divided by the sum of our long-term debt and equities and margins.

2 Margins for interest ratio equals the sum of long and short-term interest expense and assignable margins divided by the sum of long and short-term interest expense, excluding amounts capitalized.

 

23


 

Item 7 – Management's Discussion and Analysis

of Financial Condition and Results of Operations

Caution Regarding Forward Looking Statements

Statements in this report that do not relate to historical facts, including statements relating to future plans, events or performance, are forward-looking statements that involve risks and uncertainties. Actual results, events or performance may differ materially. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date of this report and the accuracy of which is subject to inherent uncertainty. We undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances that may occur after the date of this report or the effect of those events or circumstances on any of the forward-looking statements contained herein, except as required by law.

Results of Operations

Overview

MarginsWe operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to pay operating and maintenance costs, the cost of fuel and purchased power, capital expenditures, depreciation and principal and interest on our indebtedness and to provide for reserves. These amounts are referred to as “margins.” Patronage capital, the retained margins of our members, constitutes our principal equity.

Times Interest Earned Ratio (TIER).  Alaska electric cooperatives generally set their rates on the basis of TIER, which is a debt service coverage approach to ratemaking. TIER is determined by dividing the sum of assignable margins plus long-term interest expense (excluding capitalized interest) by long-term interest expense (excluding capitalized interest). Chugach’s long-term interest expense for the years ended December 31, 2017, 2016 and 2015 was $21,424,095, $21,168,967 and $21,811,573, respectively. Chugach’s authorized TIER for ratemaking purposes on a system basis was 1.30 through July 4, 2016, which was established by the RCA in order U-01-08(26) on January 31, 2003. Pursuant to RCA order U-15-081(8), Chugach’s authorized TIER for ratemaking purposes on a system basis was increased to 1.35 effective July 5, 2016. The increase in the 2013 achieved TIER was caused by the recognition of the gain on the sale of the Bernice Lake Power Plant.

Chugach’s achieved TIER includes nonoperating margins that are not generated by electric rates. We manage our business with a view towards achieving our authorized TIER (currently established at 1.35) averaged over a 5-year period. For further discussion on factors that contribute to TIER results, see “Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Year ended December 31, 2017, compared to the year ended December 31, 2016, and the year ended December 31, 2016 compared to the year ended December 31, 2015 – Expenses.”  We achieved TIERs for the past five years as follows:

1

24

Year

TIER

2017

1.28

2016

1.27

2015

1.30

2014

1.29

2013

1.43

24


 

Rate Regulation and RatesOur electric rates are made up of two primary components: “base rates” and “fuel and purchased power rates.” Base rates provide recovery of fixed and variable costs (excluding fuel and purchased power) related to providing electric service. Fuel and purchased power rates provide recovery of fuel and purchased power costs.

The RCA approves both base rates and fuel and purchased power recovery rates paid by our retail and wholesale customers.

Base RatesChugach’s base rates, whether set under a general rate case or an SRF, are established to allow the continued recovery of our specific costs of providing electric service. In each rate filing, rates are set at levels to recover all of our specific allowable costs, other than fuel and purchased power, and those rates are then collected from our retail and wholesale customers. Under SRF, base rate increases are limited to 8% over a 12-month period and 20% over a 36-month period. Chugach is still permitted to submit general rate case filings while participating in the SRF process. In general, during these periods, rate adjustments under SRF would temporarily cease. The RCA may authorize, after a notice period, rate changes on an interim and refundable basis.

In 2017, Chugach submitted quarterly SRF filings which resulted in a 3.0% decrease to system demand and energy rates effective July 1, 2017, and an increase of 1.9% for rates effective November 1, 2017.

On August 15, 2016, base demand and energy rates increased approximately 4.2% to Chugach’s retail customers and wholesale customer, Seward. These changes were the result of Chugach’s SRF.

On May 1, 2015, base demand and energy rates increased approximately 22.0% to Chugach’s retail customers. Effective June 1, 2015, base demand and energy rates increased 16.9% to Chugach’s wholesale customer, Seward. These changes were the result of Chugach’s June 2014 Test Year General Rate Case.

Fuel and Purchased Power Rates.    Chugach recovers fuel and purchased power costs directly from retail and wholesale customers through the fuel and purchased power rate adjustment process. Changes in fuel and purchased power costs are primarily due to fixed price or fuel price adjustment processes in gas-supply contracts. Other factors, including generation unit availability also impact fuel and purchased power recovery rate levels. The fuel and purchased power adjustment is approved on a quarterly basis by the RCA. There are no limitations on the number or amount of fuel and purchased power recovery rate changes. Increases in fuel and purchased power costs result in increased revenues while decreases in these costs result in lower revenues. Therefore, revenue from the fuel and purchased power adjustment process does not impact margins. Chugach recognizes differences between projected recoverable fuel and purchased power costs and amounts actually recovered through rates. The fuel cost under/over recovery on the balance sheet represents the net accumulation of any under- or over-collection of fuel and purchased power costs. A fuel cost under-recovery will appear as an asset on our balance sheet and will be collected from our members in subsequent periods. Conversely, a fuel cost over-recovery will appear as a liability on the balance sheet and will be refunded to members in subsequent periods.

25


 

Electric Utility Regulation

Chugach is subject to regulation by the RCA. The RCA sets the rates Chugach is permitted to charge customers based on our specific allowable costs. As a result, Chugach applies FASB ASC 980, “Topic 980 – Regulated Operations.” Through the ratemaking process, our regulator may require the recognition of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of regulatory liabilities. The application of FASB ASC 980 has a further effect on Chugach's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by Chugach; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and post-retirement benefits have less of a direct impact on Chugach's results of operations than they would on a non-regulated company. As reflected in the financial statements, see “Item 8 -Financial Statements and Supplementary Data – Note 2o – Deferred Charges and Liabilities,” significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines. However, adverse legislation and judicial or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact Chugach’s financial statements.

Year ended December 31, 2017, compared to the year ended December 31, 2016, and the year ended December 31, 2016, compared to the year ended December 31, 2015

Margins

Our margins for the years ended December 31, were as follows:





 

 

 

 

 

 

 

 



2017

 

2016

 

2015

Net Operating Margins

$

5,269,849 

 

$

5,205,893 

 

$

5,815,149 

Nonoperating Margins

$

778,875 

 

$

607,963 

 

$

687,703 

Assignable Margins

$

6,048,724 

 

$

5,813,856 

 

$

6,502,852 

Net operating margins did not materially change in 2017 from 2016. The decrease in net operating margins in 2016 from 2015 of $0.6 million, or 10.5%, was primarily due to lower operating revenue, which was somewhat offset by decreases in production, transmission, and administrative, general and other expense.

Nonoperating margins include interest income, Allowance for Funds Used During Construction (AFUDC), capital credits and patronage capital allocations and other. The increase in nonoperating margins in 2017 from 2016 was primarily due to increased interest and dividends associated with marketable securities. The decrease in nonoperating margins in 2016 from 2015 was primarily due to the unrealized loss on marketable securities during 2016 following Chugach’s return to this investment portfolio in September.

26


 

Revenues

Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2017, operating revenues were $27.0 million, or 13.7% higher than 2016. The increase was primarily due to higher fuel and purchased power expense recovered in revenue and higher economy energy sales and wheeling.

In 2016, operating revenues were $18.7 million or 8.6% lower than 2015.  The decrease was primarily due to lower wholesale revenue as a result of the expiration of MEA’s wholesale contract.

Retail revenue increased $17.3 million, or 9.6%, in 2017 from 2016 primarily due to increased fuel and purchased power costs recovered in revenue.  Retail revenue increased $10.7 million, or 6.3%, in 2016 from 2015. Base revenue increased due to an increase in rates charged to retail customers as a result of Chugach’s June 2014 Test Year General Rate Case and SRFs, which was somewhat offset by lower retail energy sales.

Wholesale revenue increased $0.9 million, or 18.0% in 2017 from 2016, due to increased fuel and purchased power costs recovered in revenue.  Wholesale revenue decreased $26.0 million, or 84.1%, in 2016 from 2015, primarily due to the expiration of MEA’s wholesale contract on April 30, 2015.

Economy revenue increased $3.0 million due to increased sales to GVEA, MEA, and HEA.  Economy revenue decreased $6.9 million, or 84.1%, in 2016 from 2015 due primarily to the expiration of GVEA’s contract at the end of the first quarter of 2015.

Miscellaneous revenue increased $5.8 million or 54.7% in 2017 from 2016 and $3.5 million, or 48.6%, in 2016 from 2015 primarily due to sales of natural gas to ENSTAR as a result of Chugach’s investment in the BRU in April 2016. Additional wheeling revenue from GVEA, in 2017 and 2016, and from MEA, in 2017, also contributed to the increase.

Based on the results of fixed and variable cost recovery established in Chugach’s rate filings, wholesale sales to Seward contributed approximately $1.4 million for the year ended December 31, 2017 and $1.3 million for the years ended December 31, 2016 and 2015. Wholesale sales to MEA contributed approximately $26.2 million, for the year ended December 31, 2015.

27


 

The following table shows base rate sales revenue and fuel and purchased power revenue by customer class included in revenue for the years ended December 31, 2017, and 2016.





 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



Base Rate Sales Revenue

Fuel and Purchased Power Revenue

Total Revenue



 

2017

 

2016

 

% Variance

 

2017

 

2016

 

% Variance

 

2017

 

2016

 

% Variance

Retail

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

$

66.0 

 

$

64.8 

 

1.9 

%

 

$

34.6 

 

$

26.7 

 

29.6 

%

 

$

100.6 

 

$

91.5 

 

9.9 

%

Small Commercial

 

$

11.5 

 

$

11.6 

 

(0.9 

%)

 

$

8.1 

 

$

6.4 

 

26.6 

%

 

$

19.6 

 

$

18.0 

 

8.9 

%

Large Commercial

 

$

43.4 

 

$

43.7 

 

(0.7 

%)

 

$

32.7 

 

$

25.8 

 

26.7 

%

 

$

76.1 

 

$

69.5 

 

9.5 

%

Lighting

 

$

1.6 

 

$

1.6 

 

0.0 

%

 

$

0.2 

 

$

0.2 

 

0.0 

%

 

$

1.8 

 

$

1.8 

 

0.0 

%

Total Retail

 

$

122.5 

 

$

121.7 

 

0.7 

%

 

$

75.6 

 

$

59.1 

 

27.9 

%

 

$

198.1 

 

$

180.8 

 

9.6 

%



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Wholesale

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SES

 

$

2.1 

 

$

2.2 

 

(4.5 

%)

 

$

3.8 

 

$

2.8 

 

35.7 

%

 

$

5.9 

 

$

5.0 

 

18.0 

%

Total Wholesale

 

$

2.1 

 

$

2.2 

 

(4.5 

%)

 

$

3.8 

 

$

2.8 

 

35.7 

%

 

$

5.9 

 

$

5.0 

 

18.0 

%



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Economy

 

$

0.7 

 

$

0.5 

 

40.0 

%

 

$

3.6 

 

$

0.8 

 

350.0 

%

 

$

4.3 

 

$

1.3 

 

230.8 

%

Miscellaneous

 

$

2.1 

 

$

2.2 

 

(4.5 

%)

 

$

14.3 

 

$

8.4 

 

70.2 

%

 

$

16.4 

 

$

10.6 

 

54.7 

%



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Revenue

 

$

127.4 

 

$

126.6 

 

0.6 

%

 

$

97.3 

 

$

71.1 

 

36.8 

%

 

$

224.7 

 

$

197.7 

 

13.7 

%

The following table shows the base rate sales revenue and fuel and purchased power revenue by customer class that is included in revenue for the years ended December 31, 2016, and 2015.





 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



Base Rate Sales Revenue

Fuel and Purchased Power Revenue

Total Revenue



 

2016

 

2015

 

% Variance

 

2016

 

2105

 

% Variance

 

2016

 

2015

 

% Variance

Retail

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

$

64.8 

 

$

61.1 

 

6.1 

%

 

$

26.7 

 

$

24.8 

 

7.7 

%

 

$

91.5 

 

$

85.9 

 

6.5 

%

Small Commercial

 

$

11.6 

 

$

10.9 

 

6.4 

%

 

$

6.4 

 

$

5.9 

 

8.5 

%

 

$

18.0 

 

$

16.8 

 

7.1 

%

Large Commercial

 

$

43.7 

 

$

41.7 

 

4.8 

%

 

$

25.8 

 

$

24.0 

 

7.5 

%

 

$

69.5 

 

$

65.7 

 

5.8 

%

Lighting

 

$

1.6 

 

$

1.5 

 

6.7 

%

 

$

0.2 

 

$

0.2 

 

0.0 

%

 

$

1.8 

 

$

1.7 

 

5.9 

%

Total Retail

 

$

121.7 

 

$

115.2 

 

5.6 

%

 

$

59.1 

 

$

54.9 

 

7.7 

%

 

$

180.8 

 

$

170.1 

 

6.3 

%



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Wholesale

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

MEA

 

$

0.0 

 

$

12.8 

 

(100.0 

%)

 

$

0.0 

 

$

13.4 

 

(100.0 

%)

 

$

0.0 

 

$

26.2 

 

(100.0 

%)

SES

 

$

2.2 

 

$

2.0 

 

10.0 

%

 

$

2.8 

 

$

2.7 

 

3.7 

%

 

$

5.0 

 

$

4.7 

 

6.4 

%

Total Wholesale

 

$

2.2 

 

$

14.8 

 

(85.1 

%)

 

$

2.8 

 

$

16.1 

 

(82.6 

%)

 

$

5.0 

 

$

30.9 

 

(83.8 

%)



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Economy

 

$

0.5 

 

$

0.9 

 

(44.4 

%)

 

$

0.8 

 

$

7.3 

 

(89.0 

%)

 

$

1.3 

 

$

8.2 

 

(84.1 

%)

Miscellaneous

 

$

2.2 

 

$

2.2 

 

0.0 

%

 

$

8.4 

 

$

5.0 

 

68.0 

%

 

$

10.6 

 

$

7.2 

 

47.2 

%



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Revenue

 

$

126.6 

 

$

133.1 

 

(4.9 

%)

 

$

71.1 

 

$

83.3 

 

(14.6 

%)

 

$

197.7 

 

$

216.4 

 

(8.6 

%)



28


 

The major components of our operating revenue for the years ending December 31 were as follows:





 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 



2017

 

2017

 

2016

 

2016

 

2015

 

2015



Sales (MWh)

 

Revenue

 

Sales (MWh)

 

Revenue

 

Sales (MWh)

 

Revenue

Retail

1,105,173 

 

$

198,079,331 

 

1,113,020 

 

$

180,838,811 

 

1,133,427 

 

$

170,147,462 

Wholesale:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

MEA

 

 

 

 

 

 

275,362 

 

 

26,177,627 

Seward

59,803 

 

 

5,883,121 

 

59,063 

 

 

4,938,175 

 

61,347 

 

 

4,770,129 

Total Wholesale

59,803 

 

 

5,883,121 

 

59,063 

 

 

4,938,175 

 

336,709 

 

 

30,947,756 

Economy energy

48,526 

 

 

4,351,050 

 

25,000 

 

 

1,340,750 

 

105,815 

 

 

8,150,983 

Other

N/A

 

 

16,375,167 

 

N/A

 

 

10,629,843 

 

N/A

 

 

7,174,951 

Total

1,213,502 

 

$

224,688,669 

 

1,197,083 

 

$

197,747,579 

 

1,575,951 

 

$

216,421,152 

Chugach provided economy energy sales to GVEA through March of 2015 under contract, and continues to provide economy energy on an as needed basis to GVEA, HEA, MEA, and ML&P. Sales are made under the terms and conditions of Chugach’s economy energy sales tariff approved by the RCA. The price includes the cost of fuel, variable operations and maintenance expense, wheeling charges and a margin.

In 2017, 2016, and 2015, economy sales constituted approximately 2%, 1%, and 4%, respectively, of our sales revenues. Economy energy revenue decreased in 2016 from 2015 due to the expiration of the contract with GVEA at the end of the first quarter of 2015.

Expenses

The major components of our operating expenses for the years ended December 31 were as follows:



 

 

 

 

 

 

 

 



2017

 

2016

 

2015

Fuel

$

78,552,672 

 

$

54,778,582 

 

$

66,534,877 

Power production

 

18,006,490 

 

 

15,809,168 

 

 

16,886,257 

Purchased power

 

17,301,067 

 

 

15,774,733 

 

 

19,599,994 

Transmission

 

6,129,871 

 

 

5,590,737 

 

 

6,287,558 

Distribution

 

13,991,088 

 

 

13,991,997 

 

 

14,089,862 

Consumer accounts

 

5,968,736 

 

 

6,073,710 

 

 

6,117,625 

Administrative, general and other

 

23,256,983 

 

 

22,888,048 

 

 

23,623,299 

Depreciation

 

34,010,777 

 

 

36,233,414 

 

 

35,652,086 

Total operating expenses

$

197,217,684 

 

$

171,140,389 

 

$

188,791,558 

29


 

Fuel

Chugach recognizes actual fuel expense as incurred. Fuel expense increased $23.8 million, or 43.4% in 2017 from 2016.  The increase was primarily due to an increase in the amount of natural gas used as well as an increase in the average effective delivered price.  In 2017, Chugach used 9,042,071 Mcf of fuel at an average effective delivered price of $7.91 per Mcf compared to 8,546,043 Mcf at an average effective price of $5.63 per Mcf in 2016.  Fuel expense decreased $11.8 million, or 17.7%, in 2016 from 2015. The decrease was primarily due to a decrease in the natural gas used, as a result of the expiration of MEA’s wholesale contract and GVEA’s economy energy contract, which was somewhat offset by an increase in the average effective delivered price due in part to higher transportation costs. In 2015, Chugach used 13,058,423 Mcf at an average effective price of $4.69 per Mcf.

Power Production

Power production expense increased $2.2 million, or 13.9%, in 2017 from 2016, primarily due to increased operating and maintenance costs at SPP, as well as increased generation maintenance expense at Beluga Power Plant associated with the amortization of production equipment parts, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Beluga Parts Filing.”    Power production expense decreased $1.1 million, or 6.4%, in 2016 from 2015, primarily due to a decrease in the maintenance for SPP. Additionally, there was a decrease in operating and maintenance costs at Beluga Power Plant as a result of the retirement of Beluga Unit 8 during the second quarter of 2015 and the change in the use of Beluga’s remaining units from base load to peaking units, coinciding with the expiration of MEA’s interim wholesale contract.

Purchased Power

Purchased power expense increased $1.5 million, or 9.7%, in 2017 from 2016, primarily due to an increase in purchases from ML&P and Bradley Lake, which was somewhat offset by a decrease in purchases from Fire Island Wind and a lower average effective price.  In 2017, Chugach purchased 231,749 MWh of energy at an average effective price of 6.16 cents per kWh compared to 182,651 MWh at an average effective price of 7.17 cents per kWh.  Purchased power expense decreased $3.8 million, or 19.5%, in 2016 from 2015, primarily due to a decrease in purchases associated with MEA’s EGS, which was somewhat offset by a higher average effective price. In 2015, Chugach purchased 295,925 MWh of energy at an average effective of 5.68 cents per kWh.  

Transmission

Transmission expense increased $0.5 million or 9.6%, in 2017 from 2016, primarily due to increased labor expense associated with control & communication systems and line maintenance, as well as higher vegetation control expense. Transmission expense decreased $0.7 million, or 11.1%, in 2016 from 2015, primarily due to less labor expense associated with substation and overhead line maintenance.

Other Expenses

Distribution, consumer accounts, administrative, general and other expenses did not materially change in 2017 from 2016 or in 2016 from 2015.

30


 

Depreciation

Depreciation and amortization expense decreased $2.2 million or 6.1%, in 2017 from 2016, primarily due to the implementation of lower depreciation rates effective July 1, 2017. Depreciation and amortization expense did not materially change in 2016 from 2015.

Interest

Interest on long-term debt and other increased $0.5 million, or 2.3%, in 2017 from 2016, primarily due to additional interest expense associated with the issuance of the 2017 Series A Bonds. Interest on long-term debt and other did not materially change in 2016 from 2015.

Interest charged to construction decreased $0.3 million, or 63.7%, primarily due to a lower average CWIP balance. Interest charged to construction did not materially change in 2016 from 2015.

Non-Operating Margins

Non-operating margins increased $0.2 million or 28.1% in 2017 from 2016, primarily due to higher interest and dividends associated with marketable securities. Non-operating margins decreased $0.1 million, or 11.6% in 2016 from 2015 primarily due to lower patronage capital allocations as a result of the payment of the 2011 CoBank note.

Patronage Capital (Equity)

The following table summarizes our patronage capital and total equity position for the years ended December 31:





 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 



 

2017

 

2016

 

2015

Patronage capital at beginning of year

 

$

169,996,436 

 

$

167,447,781 

 

$

164,135,053 

Retirement/net transfer of capital credits

 

 

(3,116,273)

 

 

(3,265,201)

 

 

(3,190,124)

Assignable margins