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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, 2014

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

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

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

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.

 

2014 Form 10-K Annual Report

 

Table of Contents

PART I 

Page

 

Item 1.

Business

2

 

Item 1A.

Risk Factors

10

 

Item 1B.

Unresolved Staff Comments

16

 

Item 2.

Properties

16

 

Item 3.

Legal Proceedings

24

 

Item 4.

Mine Safety Disclosures

24

PART II 

 

 

Item 5.

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

24

 

Item 6.

Selected Financial Data

25

 

Item 7.

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

26

 

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

44

 

Item 8.

Financial Statements and Supplementary Data

45

 

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

80

 

Item 9A.

Controls and Procedures

80

 

Item 9B.

Other Information

81

PART III 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

81

 

Item 11.

Executive Compensation

85

 

Item 12.

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

91

 

Item 13.

Certain Relationships and Related Transactions, and Director Independence

91

 

Item 14.

Principal Accounting Fees and Services

92

PART IV 

 

 

Item 15.

Exhibits and Financial Statement Schedule

93

 

 

SIGNATURES

105

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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.  Our website also provides a link to the SEC’s website at http://www.sec.gov.

Chugach is the largest electric utility in Alaska.  We are engaged in the generation, transmission and distribution of electricity in the Anchorage and upper Kenai Peninsula areas.  We also provide service to two wholesale customers.  Through an interconnected regional electrical system, our energy is distributed throughout Alaska’s 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 a rural 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

2

 


 

preceding year.  This tax is accrued monthly and remitted annually.  In addition, we currently collect a regulatory cost charge (RCC) of $0.000754 per kWh of retail electricity sold.  The RCC is assessed to fund the 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 monthly on retail electricity sold to consumers in Whittier and in the Kenai Peninsula Borough.  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 301 employees as of March 5, 2015.  Approximately 70 percent 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 an agreement with the Hotel Employees and Restaurant Employees (HERE). All three IBEW CBA have been renewed through June 30, 2017.  The three CBA provide for wage increases in all years and include health and welfare premium cost sharing provisions.  The HERE contract has been renewed through June 30, 2016.  This contract provides for wage increases in all years.  We believe our relationship with our employees is good.

Through direct service to retail customers and indirectly through wholesale and economy energy sales, we provide some or all of the electricity used by approximately two-thirds of Alaska’s electric customers.  We supply much of the power requirements of two wholesale customers, Matanuska Electric Association (MEA) and the City of Seward (Seward).  We provided most of the power requirements of Homer Electric Association, Inc. (HEA) through their contract expiration date of December 31, 2013.  We sell available generation in excess of our own needs to produce electric energy for sale to Golden Valley Electric Association, Inc. (GVEA).  In addition, on a periodic basis, we provide electricity to Anchorage Municipal Light & Power (ML&P).

Our members are the consumers of the electricity sold by us.  As of December 31, 2014, we had two major wholesale customers, 68,241 retail members, and approximately 83,081 service locations, including idle services.  No individual retail customer receives more than 5 percent of our power. Our customers’ requirements for capacity and energy generally increase in fall and winter as home heating and lighting needs increase and then decline in the spring and summer as the weather becomes milder and hours of daylight increase.

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 Statements of Revenues, Expenses and Patronage Capital 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 Board of Chugach deems it appropriate to do so.

In 2014, we had 602.7 megawatts (MW) of installed generating capacity provided by 18 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 percent interest and Eklutna Hydroelectric Project, in which we own a 30 percent interest.  Effective December 31, 2011, we sold the Bernice Lake Power Plant to Alaska Electric and Energy Cooperative, Inc. (AEEC) and HEA, see “Item 1 – Business – Wholesale Customers – HEA.”  On February 1, 2013, the SPP began commercial operation,

3

 


 

furnishing 200.2 MW of capacity.  Chugach owns approximately 70 percent of this plant’s output and ML&P owns the remaining 30 percent.  In 2014, approximately 79 percent (by rated capacity) of our generating capacity was fueled by natural gas, which we purchased under gas contracts.  The rest of our owned generating resources were hydroelectric facilities.  In 2014,  87 percent of our power was generated from gas.  Of that gas-fired generation, 57 and 43 percent took place at Beluga and SPP, respectively.  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 through the first quarter of 2015,  is expected to provide an additional 13.3 MW for our wholesale customers. In the second quarter of 2015, the project is expected to provide up to 0.9 MW for our remaining wholesale customer.    For more information concerning Bradley Lake, see “Item 2 – Properties – Other Property – Bradley Lake.”  We purchase up to 17.6 MW from Fire Island Wind, LLC (FIW), annuallyWe purchased approximately 40 MW from the Nikiski Power Plant and approximately 67 MW from the Bernice Lake Power Plant on the Kenai Peninsula during the year ended December 31, 2013. We operate 1,699 miles of distribution line and 539 miles of transmission line, which includes 128 miles of leased transmission lines and Chugach’s share of the Eklutna transmission line.  For the year ended December 31, 2014, we sold 2.3 billion kWh of electrical power.

Customer Revenue from Sales

The following table shows the megawatt-hour (MWh) energy sales to and electric revenues from our retail, wholesale, and economy energy customers for the year ended December 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

MWh

 

2014 Revenues

 

Percent of Sales Revenue

Direct retail sales:

 

 

 

 

 

 

 

Residential

513,748 

 

$

81,880,150 

 

30 

%

Commercial

620,779 

 

 

80,454,791 

 

29 

%

Total

1,134,527 

 

 

162,334,941 

 

59 

%

Wholesale sales:

 

 

 

 

 

 

 

MEA

764,025 

 

 

70,694,965 

 

26 

%

Seward

61,499 

 

 

4,833,205 

 

%

Total

825,524 

 

 

75,528,170 

 

28 

%

 

 

 

 

 

 

 

 

Economy energy/other1

358,988 

 

 

36,896,019 

 

13 

%

 

 

 

 

 

 

 

 

Total from sales

2,319,039 

 

 

274,759,130 

 

100 

%

 

 

 

 

 

 

 

 

Miscellaneous energy revenue

 

 

 

6,559,383 

 

 

 

 

 

 

 

 

 

 

 

Total energy revenues

 

 

$

281,318,513 

 

 

 

1Economy energy/other includes sales to GVEA.

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Retail Service Territory

Our retail service area covers much of the populated areas of Anchorage (other than downtown Anchorage) as well as remote mountain areas and villages.  The service area ranges from the northern Kenai Peninsula on the south, to Tyonek on the west, including Fire Island, to Whittier on the east and to the Glenn Highway on the north.

Retail Customers

As of December 31, 2014, we had 68,241 members receiving power from approximately 83,081 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 5 percent of our revenues.  The revenue contributed by retail customers for the years ended December 31, 2014, 2013 and 2012 is discussed in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Year ended December 31, 2014, compared to the year ended December 31, 2013, and the year ended December 31, 2013, compared to the year ended December 31, 2012 – Revenues.

Wholesale Customers

We are the principal supplier of power to MEA and Seward under separate wholesale power contracts.  We were also the principal supplier of power to HEA through December 31, 2013.  Our wholesale power contracts, including the fuel and purchased power components, contributed $75.5 million, $108.0 million, and $105.4 million in revenues for the years ended December 31, 2014, 2013 and 2012, respectively.

MEA

We currently have a power sales contract with Alaska Electric Generation & Transmission Cooperative, Inc., (AEG&T) for firm, all-requirement sales to MEA.  AEG&T is a generation and transmission cooperative that was formed by MEA and HEA in the mid 1980’s.  Under this contract, we sell power to AEG&T for resale to MEA.  Under this contract, MEA is obligated to purchase all of its electric power and energy requirements from us.  This MEA contract was in effect through December 31, 2014.  Under this contract, MEA was  obligated to pay us for power sold to AEG&T even if AEG&T did not pay.    Sales to MEA represented approximately 33 percent, 27 percent, and 30 percent of Chugach’s total energy sales for the years ended December 31, 2014, 2013, and 2012, respectively.

The terms of the Power Sales Agreement with MEA required the parties to meet no later than 10 years prior to the termination date of the agreement to discuss possible renewal, extension or modification of the agreement, as well as the desires and potential circumstances of all parties following the termination date.  In 2004, pursuant to this provision of the contract, MEA communicated to Chugach that MEA did not desire to renew, extend or modify the agreement. 

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After open discussions and proposals regarding power sales possibilities beyond 2014, in February of 2012, Chugach received a response from MEA which indicated it would follow the path its membership most favored and move forward with plans to build its own generation plant and confirmed it would not renew the contract.

On August 12, 2014, MEA notified Chugach that their newly constructed power plant, the Eklutna Generation Station (EGS), would not be completed by January 1, 2015.  On September 30, 2014, Chugach entered into an Interim Power Sales Agreement to provide MEA with all demand and energy requirements on a firm basis based on existing tariff rates for a minimum one quarter period beginning on January 1, 2015, and ending on March 31, 2015.

Pursuant to the agreement, MEA was required to notify Chugach if it planned to exercise an option to extend the agreement an additional quarter.  On January 5, 2015, MEA notified Chugach that it would not be extending the agreement.  On January 30, 2015, MEA notified Chugach that it had four units available to pool with Chugach units to meet the combined system load of Chugach and MEA. These units were subsequently placed into economic dispatch. 

On December 22, 2014, Chugach entered into a dispatch services agreement with MEA to provide electric and natural gas dispatch services for EGS, electric dispatch services for MEA’s share of the Bradley Lake Hydroelectric Project and electric dispatch coordination services for MEA’s share of the Eklutna Hydroelectric Project effective on or about April 1, 2015.  The term of the agreement expires on March 31, 2016, unless extended by MEA through March 31, 2017.  The agreement is currently awaiting RCA approval.

In an agreement reached in May of 2014 with MEA, capital credits retired to MEA are classified as patronage capital payable on Chugach’s Balance Sheet.  MEA’s patronage capital payable was $2.3 million at December 31, 2014.

HEA

We had a power sales contract with Alaska Electric and Energy Cooperative, Inc. (AEEC) for firm, partial- requirement sales to HEA through December 31, 2013Sales to HEA represented approximately 16 percent and 19 percent of Chugach’s total energy sales for the years ended December 31, 2013 and 2012, respectively.

On July 12, 2011, Chugach, AEEC and HEA entered into an Asset Purchase and Sale Agreement whereby Chugach agreed to sell and AEEC agreed to purchase the Bernice Lake Power Plant located in Nikiski, Alaska.  The sale also included associated transmission substation facilities located on the premises.  The Bernice Lake Power Plant facility is located on land that was previously leased to Chugach by HEA. 

Associated with the Asset Purchase and Sale Agreement described above, Chugach also entered into an Agreement for Sale of Electric Capacity with AEEC and HEA (Capacity Agreement).  The agreement was a purchased power agreement that gave Chugach the right to purchase the capacity and related energy from the Bernice Lake Power Plant from the closing date of the sale of the facility (Asset Purchase and Sale Agreement) to AEEC through December 31, 2013.  This agreement allowed Chugach to sell the Bernice Lake Power Plant and simultaneously ensure system retail and wholesale deliverability requirements were met through December 31, 2013.

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Chugach continued to dispatch the power plant until the expiration of its power sales agreement with HEA, therefore, in December of 2013, Chugach recognized the gain associated with this sale which amounted to $6.4 million.

HEA’s resource requirements are now provided by AEEC’s Nikiski cogeneration facility, the Bernice Lake Power Plant and AEEC’s contract rights to receive power from the Bradley Lake Hydroelectric Project for the benefit of HEA.  In 2013, sales to HEA represented approximately 16 percent of Chugach’s total sales of energy (including both retail and wholesale).

We also had a dispatch agreement with AEEC to operate the Nikiski unit as a Chugach system resource, which ended on December 31, 2013.  

In 2007, Chugach entered into an agreement with HEA to return all of its patronage capital within five years after expiration of its power sales agreement, which was related to a settlement agreement associated with the 2005 Test Year General Rate Case (Docket U-06-134).  The agreement was contingent on the RCA accepting the parties’ settlement agreement in Docket U-06-134, which occurred on August 9, 2007.  HEA’s patronage capital payable was $7.9 million at December 31, 2014, and must be returned to HEA by December 31, 2018.

Seward

We currently provide nearly all the power needs of the City of Seward.  Sales to Seward represented approximately 3 percent, 2 percent, and 3 percent of Chugach’s total energy sales for the years ended December 31, 2014, 2013, and 2012, respectively.  We entered into a power sales agreement (2006 Agreement) with the City of Seward, nominally effective June 1, 2006, with a term of five years with two automatic five-year extensions, after RCA review, unless notice of termination is given by either party.  On May 6, 2011, Chugach submitted a request to the RCA to extend the term of the 2006 Agreement to December 31, 2016.   The RCA issued a letter order on May 26, 2011, approving the extension.  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 other customers for whom Chugach has an obligation to provide reserves (MEA and Chugach retail customers).  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

Since 1989, we have sold economy (non-firm) energy to GVEA.  We use available generation in excess of our own needs to produce electric energy for sale to GVEA, which uses that energy to serve its own loads.

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On October 5, 2012, Chugach and GVEA finalized arrangements for Chugach to provide economy energy to GVEA until March of 2015.  Sales will be made under the terms and conditions of Chugach’s economy energy sales tariff.  The price to GVEA will include the cost of fuel, variable operations and maintenance expense, wheeling charges and a margin.  Chugach has also entered into specific gas supply arrangements to make economy energy sales to GVEA.  Non-firm sales to GVEA were 358,988 MWh,  351,390 MWh and 90,765 MWh for 2014, 2013, and 2012, respectively.

Rate Regulation and Rates

The RCA regulates our rates.  We seek changes in our base rates by submitting semi-annual 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 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 and those rates are then collected from our retail and wholesale customers. 

On August 10, 2002, A.S. 42.05.175 imposed timelines for RCA decisions.  Among other provisions, it provided that for all dockets commenced on or after July 1, 2002, the RCA shall issue a final order no later than 15 months after a complete tariff filing is made for a tariff filing that changes the 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 our 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 debt service 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 that govern our outstanding long-term indebtedness do not impose any greater TIER requirement than those previously approved by the RCA.

We expect to continue to recover changes in our 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.”

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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 Amended and Restated Master Loan Agreement with CoBank, ACB (CoBank) which became effective January 19, 2011, 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 Amended Unsecured Credit Agreement with National Rural Utilities Cooperative Finance Corporation (NRUCFC), KeyBank National Association, Bank of America, N.A., Bank of Montreal, CoBank and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch, which governs the unsecured credit facility Chugach may use to meet its obligations under its Commercial Paper program, also requires Chugach to maintain a minimum margins for interest of at least 1.10 times interest charges for each fiscal year.

For the years ended December 31, 2014, 2013 and 2012, our Margins for Interest/Interest (MFI/I) was 1.28, 1.43, and 1.23, respectively.  For the same periods, our TIER was 1.29, 1.43, and 1.24, respectively.  The increase in MFI/I and TIER in 2013 was caused by the recognition of the gain on the sale of the Bernice Lake Power Plant.

Our Service Areas and Local Economy

Our service areas and those of our wholesale and economy energy customers are often described collectively as the Railbelt region of Alaska because the three geographic areas (the Southcentral, the Kenai Peninsula and the Interior) are 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.

The Matanuska-Susitna Borough is immediately north of the Municipality of Anchorage, centered around the communities of Palmer and Wasilla.  Although agriculture, tourism, mining and forestry are factors in the economy of the Matanuska-Susitna Borough, the economic well-being of the area is closely tied to that of Anchorage and many Matanuska-Susitna residents commute to jobs in Anchorage.

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.

Fairbanks is the center of economic activity for the central part of the state, known as the Interior.  Fairbanks, which is approximately 350 miles north of Anchorage, is Alaska’s second largest city.  Economic activities in the Fairbanks region include federal and state government and military operations, coal mining, the University of Alaska, tourism and support of natural resource development in the Interior and northern parts of the state.  Several gold mines, served by GVEA, operate near Fairbanks.  The Trans-Alaska Pipeline System, which transports crude oil, passes near Fairbanks on its route from the North Slope oilfields to Valdez. 

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Sales Forecasts

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales (MWh)

 

2015

 

2016

 

2017

 

2018

 

2019

Retail

 

1,154,546 

 

1,156,000 

 

1,157,000 

 

1,159,000 

 

1,161,000 

Wholesale

 

284,335 

 

64,000 

 

64,000 

 

64,000 

 

64,000 

Economy

 

95,220 

 

 

 

 

Total

 

1,534,101 

 

1,220,000 

 

1,221,000 

 

1,223,000 

 

1,225,000 

Retail energy sales are expected to remain relatively flat due to slow economic growth and progress in energy efficiency and conservation from 2015 to 2019.  At the end of March 2015, MEA’s contract to purchase their full requirements from Chugach expires, resulting in a decrease of approximately 77 percent in wholesale energy sales from 2015 to 2016.  The decrease in economy energy sales is due to the expected expiration of GVEA’s contract at the end of March 2015.  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 may affect our consolidated financial condition, results of operations and cash flows.  The statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.

Financing

On November 17, 2010, Chugach entered into a $300.0 million Unsecured Credit Agreement, which is used to back Chugach’s Commercial Paper program.  Effective May 4, 2012, Chugach reduced the commitment amount to $100.0 million and on June 29, 2012, amended and extended the Credit Agreement to update the pricing and extend the term.  The Amended Unsecured Credit Agreement now expires on November 17, 2016.  Chugach is expected to continue to issue commercial paper in 2015, as needed, however, the requirement for short-term borrowing has decreased.  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 Amended Unsecured Credit Agreement would be utilized to support Chugach’s Commercial Paper program.  Global financial markets and economic conditions have been volatile due to a variety of factors.  As a result, the cost of raising money in the debt capital markets could increase while the availability of funds from those markets could diminish.  If Chugach’s effort to recover the remaining fixed cost contribution as result of the termination of the wholesale power contracts with MEA and HEA is not successful, our ability to obtain future financing or the cost associated with future financing efforts could be negatively impacted.

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Wholesale Contracts

As previously discussed, MEA terminated its wholesale power contract with Chugach effective December 31, 2014, but subsequently entered into an interim wholesale power contract that will run through March 31, 2015MEA’s contract with Chugach, including the fuel component, represented $70.7 million, or 26 percent, of total sales revenue in 2014.    Upon expiration of the Interim Power Sales Agreement on March 31, 2015, MEA intends to leave the Chugach system. This is expected to result in a loss of approximately 33 percent of Chugach’s power sales and approximately 26 percent of the utility’s annual sales revenue.

Chugach’s planning process reflects the expected termination of the MEA wholesale contract.  Consequently, to mitigate this risk, Chugach continues to pursue replacement sources of revenue through potential new power sales and dispatch agreements and transmission wheeling and ancillary services tariff revisions.  On December 22, 2014, Chugach entered into a dispatch services agreement with MEA to provide electric and natural gas dispatch services for EGS, electric dispatch services for MEA’s share of the Bradley Lake Hydroelectric Project and electric dispatch coordination services for MEA’s share of the Eklutna Hydroelectric Project effective on or about April 1, 2015.  The term of the agreement expires on March 31, 2016, unless extended by MEA through March 31, 2017.  The agreement is currently awaiting RCA approval.

The impending loss of MEA, as a wholesale customer, required Chugach to file a general rate case on February 13, 2015, to recover total costs and restructure rates.  Since the general rate case could take up to fifteen months to be completed, Chugach requested an interim and refundable rate increase.  To the extent a general rate case or an interim and refundable rate increase does not provide for the timely recovery of expenses, Chugach could experience a material negative impact on its results of operations, financial condition, and cash flows.  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.

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-" (Positive) and "A" (Stable), respectively.  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, we may be required to pay higher interest rates on financings which we need to undertake in the future, and 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.  The physical or cyber security compromise of our facilities could adversely affect our ability to manage our

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facilities effectively.  Chugach has not experienced any disruptions or significant costs associated with intentional attacks or unauthorized access to any of our systems.  Chugach has numerous programs in place to safeguard our operating systems and the personal information of our customers and employees.

Pension Plans

We participate in the Alaska Electrical Pension Fund (AEPF).  The AEPF is a multiemployer 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 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 multiple employer defined benefit master pension plan maintained and administered by the 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.  Currently, the RS Plan does not require deficit reduction contributions to maintain minimum funding standards.

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 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 from other sources at unpredictable costs in order to supply our customers and comply with our contractual agreements.  The fuel and purchased power recovery process allows Chugach to reflect current purchased power cost and to recover under-recoveries and 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 recovery to recover those costs at the time of the next quarterly fuel recovery filing.  As a result, cash flow 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.

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Fuel Supply

In 2014, 87 percent of our power was generated from natural gas.  Our primary suppliers of natural gas are ConocoPhillips and Hilcorp. Chugach currently has gas contracts in place to fill up to 100 percent of Chugach’s needs through March 31, 2019.  In addition, in September of 2013, Chugach entered into an agreement with Cook Inlet Energy (CIE) which provides a structure to purchase supplemental gas from CIE and provides additional diversity in Chugach’s sources of natural gas to meet system load requirements.

The 2010 Alaska Legislature passed legislation that provides incentives to natural gas producers to enhance Cook Inlet oil and gas production.  These incentives have resulted in significant improvement in gas production from existing fields and exploration for new supplies.  The two major Cook Inlet area gas producers, Hilcorp and ConocoPhillips, have gas supply agreements with local utilities for deliveries into the year 2019.  Furie Operating Alaska, LLC has constructed an offshore gas production platform and procured undersea gas pipe that it expects to install in the summer of 2015.  Other gas producers are actively developing on-shore gas supplies in Cook Inlet.  The State of Alaska received approximately $6.3 million in bids at its Cook Inlet 2014 area-wide oil and gas lease sale.  Chugach is encouraged with these developments but continues to explore other alternatives to diversify its portfolio.

Since 2012, Hilcorp has acquired significant oil and gas assets in the Cook Inlet and reworked those assets to increase production, and several other developers have brought new sources of gas production online.  As a result, local gas production trends have changed and indicate a need for an export option to support ongoing development.  On December 12, 2013, ConocoPhillips announced that it filed an application with the United States Department of Energy (DOE) to resume liquefied natural gas (LNG) exports from Alaska.  The application is for a two-year export authorization to export about 40 Bcf of gas per year as LNG.  On February 28, 2014, the DOE approved the application to ship 40 Bcf of gas as LNG over a two-year period to countries which have free trade agreements with the US.  ConocoPhillips exported approximately 13 Bcf of gas as LNG in 2014.

Hilcorp consolidated the operations and tariff for the four major gas pipelines in the Cook Inlet basin into the Kenai-Beluga Pipeline (KBPL) in 2014.  On November 1, 2014, the RCA approved the consolidation.  Prior to consolidation, gas transportation cost could make development of new gas fields cost prohibitive because the gas transport rates varied with flow and the number of pipelines the gas had to cross to transport gas.  The consolidation provides gas producers a single rate for shipping gas on all of the four pipelines, which makes development of gas fields anywhere on the gas pipeline system more attractive to gas producers.

A project commenced by Alaska Gasline Development Corporation and affiliates of BP, ConocoPhillips, ExxonMobil and TransCanada (together, project participants) to construct a liquefaction facility, gas pipeline, and gas treatment plant is underway through a pre-filing process accepted by FERC.  The mainline gas pipeline is expected to include off-take points to allow for the opportunity for future in-state deliveries of natural gas.  The project participants are targeting to file a formal application with FERC in the fall of 2016.  FERC authorizations for the project and commencement of construction are anticipated in the 2018-2019 timeframe, with operation in the 2024-2025 timeframe.

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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 is 1.9 Bcf.  Chugach is entitled to withdraw gas at a rate of up to 35 million cubic feet (MMcf) per day.

Cooper Lake Hydroelectric Project

In August of 2007, Chugach received 50-year license from FERC for the Cooper Lake Hydroelectric Project.  A condition of that license is a requirement to construct a Stetson Creek diversion structure, a pipeline to Cooper Lake, and a bypass structure to release warmer water from Cooper Lake into Cooper Creek.  If the project is not feasible or if the cost estimate materially exceeds the terms of the license, Chugach has the option to request a license amendment.  At the time the project was being relicensed the estimated cost to complete the project was $12.0 million.  The current total project cost is now estimated at $22.3 million.  As an alternative to requesting a license amendment from FERC, Chugach requested grants from the State of Alaska.  Funding for this project includes $9.9 million in grants awarded.  The Chugach Board authorized expenditures for the project on November 15, 2012.  The diversion project began construction in 2013 and will be completed in 2015Chugach expects to operate the hydroelectric project through the duration of the license.

Other Environmental Regulations

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 greenhouse gas (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 negative impact to Chugach’s results of operations, financial condition, and cash flows.

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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 recovery which will ensure, in advance, that costs incurred under the contracts can be recovered from Chugach’s customers.  The fuel and purchased power recovery process recovers under-recoveries and refunds over-recoveries from prior periods with minimal regulatory lag.  Chugach's fuel and purchased power recovery rates are adjusted through quarterly filings with the RCA, which sets 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 recovery.  At December 31, 2014, Chugach had over-recovered $1.5 million and at December 31, 2013, Chugach had over-recovered $1.6 million, net.  To the extent the regulated fuel and purchased power recovery 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.

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.

Regulatory

Our billing rates are approved by the RCA.  Chugach filed its 2013 General Rate Case on November 19, 2013, to reflect revenue and cost changes resulting from the expiration of HEA’s wholesale contract.  On January 2, 2014, the proposed rates became effective on an interim and refundable basis for retail and wholesale customers in January 2014 and February 2014, respectively.  On November 13, 2014, the RCA accepted the stipulation entered into among the parties in the case.  On February 12, 2015, the RCA issued a final order,  see  “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – 2013 General Rate Case.” 

To reflect revenue and cost changes resulting from the impending expiration of MEA’s wholesale contract, Chugach filed a 2014 Test Year General Rate Case with the RCA on February 13, 2015, with interim and refundable rates effective April 1, 2015.  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.

Green House Gas Regulations, Carbon Emission and Climate Change

Uncertainty remains regarding the impacts of potential regulations regarding 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.  In September of 2013, the EPA announced a proposal to establish the first uniform national limits on carbon pollution from future power plants. These regulations will not apply to existing power plants.  On June 2, 2014, the EPA released a proposed regulation aimed at reducing emissions of carbon dioxide (CO2) from existing power

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plants that provide electricity for utility customers.  In the draft 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.  A final rule is expected in June 2015, with state plans due to the EPA in June 2016.  Chugach is subject to this proposed regulation, however, in its current form, we do not expect the regulation to have a material effect on our results of operations, financial position, and 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.  At the present time, we cannot predict the cost or effect of future legislation or regulation.  Federal law or regulation regarding GHG emissions could have a material adverse effect on our operations, financial position, and cash flows.

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

Item 2 Properties

General

In 2014, we had 602.7 MW of installed capacity consisting of 18 generating units at five power plants.  These included 385.0 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; 46.7 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.  Effective December 31, 2011, we sold the Bernice Lake Power Plant to AEEC and HEA, see “Item 1 – Business – Wholesale Customers – HEA.”  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 HEA and dispatched by Chugach.  In 2014, we also purchased power from Fire Island Wind, LLC (FIW).  The Beluga, IGT and SPP facilities are all 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 SPP.  Effective December 31, 2011, we sold the Bernice Lake Power Plant to AEEC and HEA, see “Item 1 – Business – Wholesale Customers – HEA.”

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Our principal generation assets are in two plants, Beluga and SPP.  Our principal generation units at Beluga are Units 6, 7, and 8.  These units have a combined capacity of 212.3 MW.  All other units at Beluga are used principally 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.  In 2010, Unit 6 received a major inspection in which many of the major components were replaced with new or refurbished parts.  Unit 6 had an annual inspection in 2011, 2012, 2013, and 2014.  During the 2012 annual inspection of Unit 6, combustion components nearing end of life were also replaced.  Beluga Unit 7 had a major inspection in 2012, in which many of the major components were replaced with new or refurbished parts.  Annual inspections were performed on this unit in 2011, 2013 and 2014.  Beluga Unit 8, a steam turbine generator, received a major inspection in 2012.  Annual inspections were performed on Unit 8 in 2011, 2013, and 2014.

On February 1, 2013, SPP began commercial operation, furnishing 200.2 MW of capacity provided by 4 generating units.  Chugach owns and takes approximately 70 percent of this plant’s output and ML&P owns and takes the remaining 30 percent.  Chugach proportionately accounts for its ownership in SPP.  Our principal generation units at SPP are Units 10, 11, 12, and 13.  Throughout 2013 and 2014, SPP units received preventative maintenance inspections consistent with original equipment manufacturer (OEM) recommendations.  Units 11, 12, and 13, which have gas turbine generators, received two internal combustion system inspections each and one full annual inspection of the turbine systems.  All three steam-generating boilers were internally inspected as well as hydrotested in accordance with initial OEM recommendations.

The Cooper Lake Hydroelectric Project is partially located on Federal lands.  Chugach operates and maintains the Cooper Lake project pursuant to a 50-year license granted to us by FERC in August of 2007.  As part of the relicensing process, there was a negotiated Relicensing Settlement Agreement (RSA) entered into in August of 2005.  A requirement of the RSA requires Chugach to establish a flow regime in Cooper Creek below the Cooper Lake Dam.  This is a project that includes a Stetson Creek Diversion (Dam), Pipeline (Conveyance System) and Cooper Lake Outlet Works.  The project is designed to replace colder water flowing into the Cooper Creek drainage and replace it with warmer Cooper Lake water.  Project construction began in 2013 and will be completed in 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 and inspections in October of 2012 and 2013.  In 2014, both units again received annual maintenance in October.  The 2014 annual maintenance included generator testing and inspection by the OEM.

The Eklutna Hydroelectric Project is located on federal land pursuant to a United States Bureau of Land Management right-of-way grant issued in October of 1997.  The facility is jointly owned by Chugach (30 percent), MEA (17 percent) and ML&P (53 percent).  The facility is operated by Chugach and maintained jointly by Chugach and ML&P. 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 2014, percentages of contribution and other historical information for all Chugach generation units.

 

 

 

 

 

 

 

 

 

Facility

Commercial Operation Date

Nomenclature

Rating 
(MW)(1)

 

Run Hours (2014)

 

Percent of Total Run Hours

Percent of
Time
Available

(3)

 

 

 

 

 

 

 

 

1968

GE Frame 5

19.6 

 

431.9 

 

0.66 
97.1 

1968

GE Frame 5

19.6 

 

427.7 

 

0.66 
93.2 

1973

GE Frame 7

64.8 

 

2,484.9 

 

3.81 
94.1 

1975

GE Frame 7

68.7 

 

2,774.3 

 

4.25 
94.1 

1976

AP 11DM-EV

79.2 

 

5,683.5 

 

8.70 
91.0 

1978

AP 11DM-EV

80.1 

 

7,505.2 

 

11.49 
94.6 

1981

BBC DK021150(2)

53.0 

 

8,032.2 

 

12.30 
92.3 

Cooper Lake

Hydroelectric Project

 

 

385.0 

 

 

 

 

 

1960

BBC MV 230/10

9.6 

 

1,681.0 

 

2.57 
95.7 

1960

BBC MV 230/10

9.6 

 

2,995.0 

 

4.59 
95.7 

IGT Power Plant

 

 

19.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1964

GE Frame 5

14.1 

 

100.1 

 

0.15 
69.8 

1965

GE Frame 5

14.1 

 

57.8 

 

0.09 
98.0 

1969

Westinghouse 191G

18.5 

 

23.4 

 

0.04 
98.4 

Southcentral Power Project

 

 

46.7 

 

 

 

 

 

10 

2013

Mitsubishi SC1F-29.5(7)

40.2(6)

 

8,513.8 

 

13.04 
99.9 
11 

2013

GE LM6000 PF

33.3(6)

 

8,125.8 

 

12.45 
96.3 
12 

2013

GE LM6000 PF

33.3(6)

 

8,242.3 

 

12.62 
97.1 
13 

2013

GE LM6000 PF

33.3(6)

 

8,215.4 

 

12.58 
96.1 

Eklutna Hydroelectric Project

 

 

140.1

 

 

 

 

 

1955

Newport News

5.8(4)

 

N/A(5)

 

N/A(5)

96.6 

1955

Oerlikon custom

5.9(4)

 

N/A(5)

 

N/A(5)

92.1 

 

 

 

11.7 

 

 

 

 

 

System Total

 

 

602.7 

 

65,294.3 

 

100.00 

 

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

(2)    Steam-turbine powered generator with heat provided by exhaust from natural gas fueled Units 6 and 7 (combined-cycle).

(3)    Beluga Unit 4 was retired during 1994.

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

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

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

(7)    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).

Note: BBC = Brown Boveri Corporation, AP = Alstom Power

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Transmission and Distribution Assets

As of December 31, 2014, our transmission and distribution assets included 43 substations and 539 miles of transmission lines, which included 128 miles of leased transmission lines and Chugach’s share of the Eklutna transmission line, 901 miles of overhead distribution lines and 798 miles of underground distribution line.  In 2012, Chugach completed a new substation to connect SPP to the Chugach and ML&P systems.  We own the land on which 24 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 percent 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 (N/S runway) are under rights from the State Department of Transportation and Public Facilities/Ted Stevens Anchorage International Airport; the East Terminal Site (6 mile) is under rights from the Matanuska-Susitna Borough; the West Terminal Site is under rights from the Army/Air Force; the University Substation is on State land under rights from the Federal Bureau of Land Management; the Hope and Daves Creek Substations are under rights from the State; the Portage Substation is under rights from the Alaska Railroad Corporation (ARRC); the Summit Lake Substation is on State land under rights 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 will be under rights from the Chugach State Park upon approval.  The Cooper Lake Power Plant,  Quartz Creek Substation, and the 69kV transmission line between them are operated under a federal license.  Most of Chugach’s transmission, sub-transmission and distribution lines are either on public lands under rights from the federal, state, municipal, borough or 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 percent (27.4 MW as currently operated) share in the Bradley Lake project’s output, and currently take Seward’s and MEA’s shares which we net bill to them, for a total of 45.2 percent of the project’s capacity.  We are obligated to pay 30.4 percent 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 AEG&T and 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 of 1991) or when the revenue bond principal is repaid, whichever is the longer.  The agreement may be renewed for successive forty-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 $24.0 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 percent.  Upon default, Chugach could be faced with annual expenditures of approximately $5.5 million as a result of Chugach’s Bradley Lake take-or-pay obligations.

The State of Alaska provided an initial grant for work on a project to divert water from Battle Creek into Bradley Lake.  The project is being managed by the Alaska Energy Authority.  Based on stream flow measurements from 1991 through 1993, diverting a portion of Battle Creek into Bradley Lake has the potential to increase annual energy output up to 40,000 MWh.  Chugach would be entitled to 30.4 percent of the additional energy produced.

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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 percent), MEA (17 percent) and ML&P (53 percent).  In 2014 and through March 31, 2015, the power MEA purchases from the Eklutna Hydroelectric Project is pooled with Chugach’s purchases and sold back to MEA to be used to meet MEA’s overall power requirements.

Fuel Supply

In 2014, 87 percent of our power was generated from natural gas.    Total gas purchased in 2014 was approximately 20 Bcf.  In 2014, our sources of natural gas for firm sales were primarily divided among contracts with two major oil and gas companies.  All of the production came from Cook Inlet, Alaska.  ConocoPhillips under their current contract provided 46 percent of gas supplied for generation, while Hilcorp provided 54 percent.  The current gas contract with ConocoPhillips provided gas beginning in 2010 and will expire December 31, 2016.  The current gas contract with Hilcorp, provided gas beginning in April of 2011, and will expire March 31, 2019.  ConocoPhillips and Hilcorp, together, fill up to 100 percent of Chugach’s firm needs through March 31, 2019.  Gas to provide economy energy sales to GVEA is supplied by a gas supply arrangement with Hilcorp through March of 2015.

ConocoPhillips

We entered into a contract with ConocoPhillips in 2009.  The contract provided gas starting January 1, 2010, and will terminate December 31, 2016.  The total amount of gas under the contract is now estimated to be 60 Bcf.

The gas supplied by ConocoPhillips under the contract is separated into two volume tranches for pricing purposes.  “Firm Fixed Quantity” gas meets a portion of Chugach’s base load requirements, while “Firm Variable Quantity” gas meets peaking needs.  All of the gas purchased under the contract is now firm fixed since firm variable gas was not provided by the contract after December 31, 2013.  The dividing line between firm fixed and firm variable volumes was calculated based on a methodology that involved using a multiplier and the simple average of Chugach’s average daily volumes for the 30 lowest volume days during the last calendar year.  The ConocoPhillips contract during 2014 was a fixed volume delivery of 25,000 thousand cubic feet (Mcf) per day at the Firm Fixed Quantity price.

Pricing for firm fixed gas will be based on the average of five Lower 48 natural gas production areas.  The contract price is calculated on a quarterly basis as the trailing average of the simple daily average of the Platts Gas Daily midpoint prices for each “flow day” in these market areas during the last quarter.

Chugach also has the option to receive a fixed price quote from ConocoPhillips and lock that price of any quantity as long as the quantity does not exceed the “Firm Fixed Quantity” and for any term up to December 31, 2016, for which price is to be locked.

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Marathon Alaska Production/Hilcorp

We entered into a contract with MAP effective May 17, 2010, to provide gas beginning April 1, 2011, through December 31, 2014, which included two contract extension options that were exercised in 2011.  Effective February 1, 2013, the gas purchase agreement was assigned to Hilcorp who purchased MAP’s assets in Cook Inlet.  The total amount of gas under contract is now estimated to be 40 Bcf.  Pricing for the 2014 term of the Hilcorp contract was set at the contract floor price of $6.18 per Mcf. Pricing for the 2015 term is $7.13 per Mcf.

Chevron/UNOCAL/Hilcorp

In May of 2010, Chugach entered into an interruptible gas purchase agreement with UNOCAL to supply gas to Chugach to produce economy energy for GVEA.  The agreement was due to terminate on March 31, 2012.  Effective December 28, 2011, the gas purchase agreement was assigned to Hilcorp who purchased Chevron/UNOCAL’s assets in Cook Inlet.  On January 30, 2012, Hilcorp extended the term of the contract to March 31, 2013.

On October 1, 2012, Chugach entered into a Gas Sales and Purchase Agreement with Hilcorp for the purchase of gas with an effective period of April 1, 2013, through March 31, 2015.  This agreement is intended for Chugach to produce economy energy for GVEA.  GVEA reimburses Chugach for the cost of gas related to economy energy sales.

Cook Inlet Energy, LLC

On November 25, 2013, the RCA approved the Gas Sale and Purchase Agreement (GSPA) between Chugach and Cook Inlet Energy, LLC (CIE), which was filed with the RCA on September 30, 2013, and effective December 2, 2013.  The RCA also approved inclusion of all gas costs incurred under the GSPA through Chugach’s fuel and purchased power cost adjustment process.

The agreement may 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.  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.

Natural Gas Transportation Contracts

The terms of the ConocoPhillips 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:

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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 at a transportation rate of $0.6311 per Mcf.  The agreement contains a fixed monthly customer charge of $2,600 for firm service.

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

Marathon Oil Company sold its share of its subsidiary pipeline company Marathon Pipe Line Company as part of a Cook Inlet asset divestiture effective February 1, 2013, to Hilcorp.  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).  Chugach has entered into tariff agreements to ship gas on the KNPL, BPL and CIGGS. Effective August 1, 2013, Chugach entered into a special contract with KNPL for Firm Service capacity over the Kenai Pipeline Junction (KPL) compressor of 35,000 Mcf per month for the movement of gas to its Beluga power plant at a firm capacity rate of $2.13 per Mcf.  This agreement ended effective October 31, 2014. 

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

General

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.

The Clean Air Act and 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 June 2, 2014, the EPA released a proposed regulation aimed at reducing emissions of CO2 from existing power plants that provide electricity for utility customers.  In the draft 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.  A final rule is expected in June 2015,

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with state plans due to the EPA in June 2016.  Chugach is subject to this proposed regulation, however, in its current form, we do not expect the regulation to have a material effect on our 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 new law or regulation, or limitation 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

Matanuska Electric Association, Inc. v. Chugach Electric Association, Inc., Superior Court Case No. 3PA-13-1006 Civil

On May 14, 2013, MEA served Chugach with a Summons and Complaint in the above referenced case.  MEA fundamentally asked that Chugach be required to repatriate MEA’s capital credits on the same basis as it promised, in a 2007 settlement, that it would repatriate HEA capital credits.  The parties reached an agreement to settle this litigation and on June 5, 2014, the Court issued an order dismissing the case without prejudice.

The margins Chugach earns each year are allocated to the customers who contribute them and are booked as capital credits to those customers’ accounts.  Capital credits are repatriated to customers at the discretion of Chugach’s Board of Directors, typically many years after the margins are earned.  With this litigation, MEA sought to accelerate the return of its capital credits.

Chugach has certain other 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

PART II

Item 5 Market for Registrant's

Common Equity, Related Stockholder Matters and

Issuer Purchases of Equity Securities

Not Applicable

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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

2014

 

2013

 

2012

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric plant, net:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

In service

$

657,899,592 

 

$

670,476,634 

 

$

442,515,434 

 

$

392,080,033 

 

$

407,351,421 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Construction work in progress

 

21,567,341 

 

 

28,674,163 

 

 

263,459,794 

 

 

206,005,783 

 

 

100,787,482 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric plant, net

 

679,466,933 

 

 

699,150,797 

 

 

705,975,228 

 

 

598,085,816 

 

 

508,138,903 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other assets

 

126,244,688 

 

 

139,033,241 

 

 

156,626,138 

 

 

254,843,842 

 

 

121,588,825 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

$

805,711,621 

 

$

838,184,038 

 

$

862,601,366 

 

$

852,929,658 

 

$

629,727,728 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

472,024,497 

 

 

496,914,274 

 

 

521,597,086 

 

 

296,090,108 

 

 

304,450,318 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equities and margins

 

176,925,299 

 

 

175,795,865 

 

 

166,764,373 

 

 

161,231,426 

 

 

161,842,284 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total capitalization

$

648,949,796 

 

$

672,710,139 

 

$

688,361,459 

 

$

457,321,534 

 

$

466,292,602 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Ratio1

 

27.3% 

 

 

26.1% 

 

 

24.2% 

 

 

35.3% 

 

 

34.7% 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operations Data

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

$

281,318,513 

 

$

305,308,427 

 

$

266,971,468 

 

$

283,618,369 

 

$

258,325,345 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

252,972,879 

 

 

278,738,497 

 

 

248,194,955 

 

 

262,341,866 

 

 

233,967,201 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

23,264,041 

 

 

24,691,582 

 

 

24,085,371 

 

 

18,681,680 

 

 

21,014,387 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capitalized interest

 

(463,335)

 

 

(1,310,110)

 

 

(9,682,440)

 

 

(1,934,703)

 

 

(1,008,689)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating margins

 

5,544,928 

 

 

3,188,458 

 

 

4,373,582 

 

 

4,529,526 

 

 

4,352,446 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nonoperating margins

 

970,617 

 

 

7,355,585 

 

 

1,151,925 

 

 

1,043,736 

 

 

1,057,563 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assignable margins

$

6,515,545 

 

$

10,544,043 

 

$

5,525,507 

 

$

5,573,262 

 

$

5,410,009 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Margins for Interest Ratio2

1.28 

 

 

1.43 

 

 

1.23 

 

 

1.30 

 

 

1.26 

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.

 

Equity ratios and margins for interest ratios are considered non-GAAP measures.  We consider these ratios to be useful to users of Chugach’s financial statements and are components of financial covenants contained in Chugach’s Indenture and debt agreements.

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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, 2014, 2013 and 2012 was $22,820,866, $24,378,162, and $22,944,194, respectively. Chugach’s authorized TIER for ratemaking purposes on a system basis is 1.30, which was established by the RCA in order U-01-08(26) on January 31, 2003.  The increase in TIER in 2013 was caused by the recognition of the gain on the sale of the Bernice Lake Power Plant.  The increase in 2011 and 2010 was due to certain debt classified as short-term, which was replaced with long-term debt in 2012.

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 1.30) 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, 2014, compared to the year ended December 31, 2013, and the year ended December 31, 2013 compared to the year ended December 31, 2012 – Expenses.”  We achieved TIERs for the past five years as follows:

1

24

Year

TIER

2014

1.29

2013

1.43

2012

1.24

2011

1.58

2010

1.44

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Rate Regulation and Rates.   Our 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 Rates.   Chugach’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 percent over a 12-month period and 20 percent over a 36-month period.  Chugach is still permitted to submit general rate case filings while participating in the SRF process.  However, 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.  Chugach resumed the SRF filing process, after receiving approval from the RCA, in the fourth quarter of 2010.

On January 3, 2014, base demand and energy rates increased 11.5 percent to Chugach retail customers. Effective February 1, 2014, base demand and energy rates increased 19.3 percent and 13.8 percent to MEA and Seward, respectively.  These changes were the result of Chugach’s 2013 Test Year General Rate Case, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – 2013 General Rate Case.”

On February 6, 2013, base demand and energy rates increased 26 percent, 40 percent, 35 percent and 20 percent to HEA, MEA, Seward and Chugach retail customers, respectively.  These changes were the result of Chugach’s 2012 Test Year General Rate Case.

On November 12, 2012, base demand and energy rates decreased 2.1 percent, 1.9 percent and 1.7 percent to HEA, MEA and Chugach retail customers, respectively, and increased 1.6 percent to Seward.  These changes were the result of Chugach’s SRF utilizing the 12 months ended June 30, 2012.

On May 14, 2012, base demand and energy rates decreased 3.0 percent, 2.8 percent and 2.4 percent to HEA, MEA and Seward, respectively, and increased 1.3 percent to Chugach retail customers.  These changes were the result of Chugach’s SRF utilizing the 12 months ended December 31, 2011.

On November 14, 2011, base demand and energy rates increased 2.4 percent to HEA and decreased 1.7 percent, 1.9 percent and 5.8 percent to Chugach retail customers, MEA and Seward, respectively.  These changes were the result of Chugach’s SRF utilizing the 12 months ended June 30, 2011.

Fuel and Purchased Power Recovery.    We recover fuel and purchased power costs directly from our wholesale and retail 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 our 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 our fuel and

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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.  We recognize differences between projected recoverable fuel and purchased power costs and amounts actually recovered through rates.  The fuel cost under/over recovery on our balance sheet represent the net accumulation of any under- or over-collection of fuel and purchase 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 our balance sheet and will be refunded to our members in subsequent periods.

Year ended December 31, 2014, compared to the year ended December 31, 2013, and the year ended December 31, 2013 compared to the year ended December 31, 2012

Margins

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

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

Net Operating Margins

$

5,544,928 

 

$

3,188,458 

 

$

4,373,582 

Nonoperating Margins

$

970,617 

 

$

7,355,585 

 

$

1,151,925 

Assignable Margins

$

6,515,545 

 

$

10,544,043 

 

$

5,525,507 

The increase in net operating margins in 2014 from 2013 of $2.4 million, or 73.9%, was due primarily to a decrease in depreciation expense associated with Beluga Unit 8 assets, and a decrease in net interest, and was somewhat offset by a decrease in revenue.  The decrease in net operating margins in 2013 from 2012 of $1.2 million, or 27.1%, percent, was due primarily to an increase in depreciation expense associated with SPP, which was somewhat offset by an increase in economy revenue and a decrease in distribution expense.

Nonoperating margins include interest income, Allowance for Funds Used During Construction (AFUDC), capital credits and patronage capital allocations and other.  Nonoperating margins decreased in 2014 over 2013 and increased in 2013 over 2012 due primarily by the recognition of the gain on the sale of the Bernice Lake Power Plant on December 31, 2013.

Revenues

Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues.  In 2014, operating revenues were $24.0 million, or 7.9% percent lower than 2013.  The decrease was due primarily to lower wholesale revenue caused by the expiration of the HEA wholesale contract, which was somewhat offset by higher rates charged to both retail and wholesale customers as a result of Chugach’s 2013 Test Year Rate Case and higher economy energy sales.

In 2013, operating revenues were $38.3 million, or 14.3% percent higher than 2012.  The increase was due primarily to an increase in rates to both retail and wholesale customers as a result of Chugach’s 2012 Test Year Rate Case, higher economy energy revenue and higher fuel and purchased power expense recovered through the fuel and purchased power adjustment process, which was somewhat offset by lower firm energy sales.

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Retail revenue increased $7.1 million, or 4.6%, in 2014 from 2013.  Base revenue increased due to an increase in rates charged to retail customers as a result of Chugach’s 2013 Test Year General Rate Case, which was somewhat offset by lower retail energy sales caused by warmer weather.  Fuel and purchased power revenue did not materially change in 2014 from 2013.

Wholesale revenue decreased $32.5 million, or 30.1%, in 2014 from 2013, due primarily to the expiration of HEA’s wholesale contract.

Overall, retail and wholesale revenue increased in 2013 from 2012.  Base retail and wholesale revenue increased due to an increase in rates charged to all customers as discussed above, which was somewhat offset by lower firm kWh sales caused by warmer weather.  An increase in fuel and purchased power expense recovered through the fuel and purchased power adjustment process was more than offset by the effect of economy energy and wheeling transactions.

Based on the results of fixed and variable cost recovery established in Chugach’s rate filings, wholesale sales to MEA, HEA and Seward in total contributed approximately $27.5 million, $35.5 million, and $27.5 million to Chugach’s fixed costs for the years ended December 31, 2014, 2013 and 2012, respectively.

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, 2014, and 2013.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Base Rate Sales Revenue

Fuel and Purchased Power Revenue

Total Revenue

 

 

2014

 

2013

 

% Variance

 

2014

 

2013

 

% Variance

 

2014

 

2013

 

% Variance

Retail

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

$

54.4 

 

$

50.9 

 

6.9 

%

 

$

27.5 

 

$

28.3 

 

(2.8 

%)

 

$

81.9 

 

$

79.2 

 

3.4 

%

Small Commercial

 

$

9.6 

 

$

8.8 

 

9.1 

%

 

$

6.4 

 

$

6.5 

 

(1.5 

%)

 

$

16.0 

 

$

15.3 

 

4.6 

%

Large Commercial

 

$

36.1 

 

$

32.5 

 

11.1 

%

 

$

26.6 

 

$

26.6 

 

0.0 

%

 

$

62.7 

 

$

59.1 

 

6.1 

%

Lighting

 

$

1.5 

 

$

1.4 

 

7.1 

%

 

$

0.2 

 

$

0.2 

 

0.0 

%

 

$

1.7 

 

$

1.6 

 

6.3 

%

Total Retail

 

$

101.6 

 

$

93.6 

 

8.5 

%

 

$

60.7 

 

$

61.6 

 

(1.5 

%)

 

$

162.3 

 

$

155.2 

 

4.6 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Wholesale

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

HEA

 

$

0.0 

 

$

15.5 

 

(100.0 

%)

 

$

0.0 

 

$

22.3 

 

(100.0 

%)

 

$

0.0 

 

$

37.8 

 

(100.0 

%)

MEA

 

$

34.6 

 

$

28.4 

 

21.8 

%

 

$

36.1 

 

$

37.0 

 

(2.4 

%)

 

$

70.7 

 

$

65.4 

 

8.1 

%

SES

 

$

1.9 

 

$

1.7 

 

11.8 

%

 

$

2.9 

 

$

3.1 

 

(6.5 

%)

 

$

4.8 

 

$

4.8 

 

0.0 

%

Total Wholesale

 

$

36.5 

 

$

45.6 

 

(20.0 

%)

 

$

39.0 

 

$

62.4 

 

(37.5 

%)

 

$

75.5 

 

$

108.0 

 

(30.1 

%)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Economy

 

$

2.6 

 

$

2.7 

 

(3.7 

%)

 

$

34.3 

 

$

35.1 

 

(2.3 

%)

 

$

36.9 

 

$

37.8 

 

(2.4 

%)

Miscellaneous

 

$

1.7 

 

$

2.0 

 

(15.0 

%)

 

$

4.9 

 

$

2.3 

 

113.0 

%

 

$

6.6 

 

$

4.3 

 

53.5 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Revenue

 

$

142.4 

 

$

143.9 

 

(1.0 

%)

 

$

138.9 

 

$

161.4 

 

(13.9 

%)

 

$

281.3 

 

$

305.3 

 

(7.9 

%)

29

 


 

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, 2013, and 2012.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Base Rate Sales Revenue

Fuel and Purchased Power Revenue

Total Revenue

 

 

2013

 

2012

 

% Variance

 

2013

 

2012

 

% Variance

 

2013

 

2012

 

% Variance

Retail

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

$

50.9 

 

$

45.4 

 

12.1 

%

 

$

28.3 

 

$

30.7 

 

(7.8 

%)

 

$

79.2 

 

$

76.1 

 

4.1 

%

Small Commercial

 

$

8.8 

 

$

7.7 

 

14.3 

%

 

$

6.5 

 

$

6.8 

 

(4.4 

%)

 

$

15.3 

 

$

14.5 

 

5.5 

%

Large Commercial

 

$

32.5 

 

$

28.6 

 

13.6 

%

 

$

26.6 

 

$

28.6 

 

(7.0 

%)

 

$

59.1 

 

$

57.2 

 

3.3 

%

Lighting

 

$

1.4 

 

$

1.3 

 

7.7 

%

 

$

0.2 

 

$

0.3 

 

(33.3 

%)

 

$

1.6 

 

$

1.6 

 

0.0 

%

Total Retail

 

$

93.6 

 

$

83.0 

 

12.8 

%

 

$

61.6 

 

$

66.4 

 

(7.2 

%)

 

$

155.2 

 

$

149.4 

 

3.9 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Wholesale

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

HEA

 

$

15.5 

 

$

12.3 

 

26.0 

%

 

$

22.3 

 

$

26.0 

 

(14.2 

%)

 

$

37.8 

 

$

38.3 

 

(1.3 

%)

MEA

 

$

28.4 

 

$

21.9 

 

29.7 

%

 

$

37.0 

 

$

40.4 

 

(8.4 

%)

 

$

65.4 

 

$

62.3 

 

5.0 

%

SES

 

$

1.7 

 

$

1.3 

 

30.8 

%

 

$

3.1 

 

$

3.5 

 

(11.4 

%)

 

$

4.8 

 

$

4.8 

 

0.0 

%

Total Wholesale

 

$

45.6 

 

$

35.5 

 

28.5 

%

 

$

62.4 

 

$

69.9 

 

(10.7 

%)

 

$

108.0 

 

$

105.4 

 

2.5 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Economy

 

$

2.7 

 

$

0.6 

 

350.0 

%

 

$

35.1 

 

$

8.4 

 

317.9 

%

 

$

37.8 

 

$

9.0