10-K 1 form10k.htm CHUGACH ELECTRIC ASSOCIATION 10-K 12-31-2010 form10k.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended      December 31, 2010
 
or
 
o
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 incorporation or organization)
  
(I.R.S. Employer 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.
oYes x 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.
x Yes o 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.
x Yes o 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 (Sec.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).
oYes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Registration S-K (Sec.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.
x

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 o
Accelerated filer o
Non-accelerated filer x
Smaller reporting company o

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

2010 Form 10-K Annual Report

Table of Contents

 
PART I
Page
     
Item 1 –
3
     
Item 1A –
11
     
Item 1B –
16
     
Item 2 –
16
     
Item 3 –
26
     
Item 4 –
26
     
 
PART II
  
     
Item 5 –
26
     
Item 6 –
27
     
Item 7 –
28
     
Item 7A –
50
     
Item 8 –
51
     
Item 9 –
89
     
Item 9A –
89
     
Item 9B –
90
     
 
PART III
  
     
Item 10 –
90
     
Item 11 –
94
     
Item 12 –
100
     
Item 13 –
100
     
Item 14 –
101
     
 
PART IV
  
     
Item 15 –
101
     
116


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.


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).  Our website provides a link to the SEC website.

Chugach is the largest electric utility in Alaska.  We are engaged in the generation, transmission and distribution of electricity to approximately 81,339 service locations in the Anchorage and upper Kenai Peninsula areas.  We also provide service to three 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 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).  Alaska electric cooperatives must pay to the State of Alaska, a gross receipts tax in lieu of state and local ad valorem, income and excise taxes, a tax at the rate of $0.0005 per kilowatt-hour (kWh) of electricity sold in the retail market during the preceding year.  This tax is accrued monthly and remitted annually.  In addition, we currently collect a regulatory cost charge (RCC) of $0.000552 per kWh of retail electricity sold.  This charge is assessed to fund the operations of the Regulatory Commission of Alaska (RCA).  This tax is collected monthly and remitted to the State of Alaska quarterly.  We also collect sales tax on retail electricity sold to Kenai Peninsula and Whittier consumers.  This tax is also collected monthly and remitted 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 311 full-time employees as of March 12, 2011.  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 agreements were due to expire on June 30, 2010.  On February 24, 2010, the Board of Directors approved three year extensions of all three IBEW CBA’s.  The three extensions provide no wage increase in the first year and wage increases tied to changes in the Consumer Price Index (CPI) in the second and third years, with a floor on the minimum increase and a cap on the maximum increase.  The wage increases also have an indirect connection to Chugach’s financial performance.  The contract extensions expire on June 30, 2013.  On April 28, 2010, the Board of Directors approved a three year extension of the HERE agreement.  The extension contains an increase in the employer health and welfare contribution in each year of the extension but does not provide for a wage or pension increase.  The contract extension expires on June 30, 2013.  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 three wholesale customers, Matanuska Electric Association (MEA), Homer Electric Association (HEA) and the City of Seward (Seward).  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 (AML&P).

Our members are the consumers of the electricity sold by us.  As of December 31, 2010, we had three major wholesale customers and 66,974 retail members receiving service at approximately 81,339 service locations.  No individual retail customer receives more than 5 percent of our power. Our customers’ requirements for capacity and energy generally are seasonal and 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 tariff rate for electrical power consumed during the preceding period.  Billing rates are approved by the RCA (see “Rate Regulation and Rates” below).

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 directors of Chugach deems it appropriate to do so.


We have 530.1 megawatts (MW) of installed generating capacity provided by 17 generating units at our five owned power plants: Beluga Power Plant, Bernice Lake Power Plant, International Station Power Plant (historically known as “IGT”), Cooper Lake Hydroelectric Project and Eklutna Hydroelectric Project, in which we own a 30 percent interest. Approximately 85 percent (by rated capacity) of our generating capacity is fueled by natural gas, which we purchase under gas contracts.  The rest of our generating resources are hydroelectric facilities.  In 2010, 89 percent of our power was generated from gas, which included power generated at Nikiski, and 78 percent of that gas-fired generation took place at Beluga.  The Bradley Lake Hydroelectric Project provides up to 27.4 MW for our retail customers and up to an additional 24.1 MW for our wholesale customers. For more information concerning Bradley Lake, see “Item 2 – Properties – Other Property – Bradley Lake.”  We also purchase approximately 40 MW from the Nikiski power plant on the Kenai Peninsula. We operate 1,693 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, 2010, we sold 2.7 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, 2010:

   
MWh
    
2010 Revenues
    
Percent of Sales Revenue
  
Direct retail sales:
                  
                   
Residential
     545,123     $ 72,355,957       28 %
Commercial
     624,307       67,754,347       26 %
Total
     1,169,430       140,110,304       54 %
                         
Wholesale sales:
                        
                         
MEA
     743,212       55,937,931       22 %
HEA
     454,223       33,189,789       13 %
Seward
     61,651       4,188,989    
2
 %
Total
     1,259,086       93,316,709       37 %
                         
Economy energy/other sales1
     278,093       22,141,341       9 %
                         
Total from sales
     2,706,609       255,568,354       100 %
                         
Miscellaneous energy revenue
             2,756,991          
                         
Total energy revenues
           $ 258,325,345          

1Economy energy/other sales were made to GVEA and AML&P.


Retail Customers

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, to Whittier on the east and to the Glenn Highway on the north.

Customers

As of December 31, 2010, we had 66,974 members receiving power from approximately 81,339 services (some members are served by more than one service).  Our customers are primarily 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.

Wholesale Customers

We are the principal supplier of power to MEA, HEA and Seward under separate wholesale power contracts.  For 2010, our wholesale power contracts, including the fuel and purchased power components, produced $93.3 million in revenues, representing 37 percent of our total revenues and 47 percent of our total MWh sales to customers.

MEA

We currently have a power sales contract with Alaska Electric Generation & Transmission Cooperative, Inc., (AEG&T) for firm, all-requirement sales to MEA.   In 2010, sales to MEA represented approximately 27 percent of Chugach’s total sales of energy (including both retail and wholesale).  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.  MEA had the right under the contract to alter the terms on which it purchased power from Chugach.  MEA did not invoke any of these rights and time periods in which MEA could exercise these rights have expired.  The MEA contract is in effect through December 31, 2014.  Under our contract, MEA is obligated to pay us for power sold to AEG&T even if AEG&T does not pay.

Section 12(c) of the MEA/Chugach Power Sales Agreement requires the parties to meet no later than ten 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.  Pursuant to this provision of the contract, Chugach and MEA met on October 27, 2004.  At that meeting and shortly thereafter by letter dated November 2, 2004, MEA communicated to Chugach that MEA does not desire to renew, extend or modify the Agreement.  Further, MEA stated that it does not envision any type of firm power purchase arrangement with Chugach following expiration of the Agreement on December 31, 2014.  MEA assured Chugach that it intends to continue to purchase power from Chugach in accordance with the Agreement through December 31, 2014.


On August 5, 2008, Chugach and AML&P invited MEA to participate in the development of a gas-fired generation plant near Chugach’s Anchorage headquarters.  On November 21, 2008, MEA elected to not participate in the project.  At an August 26, 2009, Chugach Board of Directors’ meeting and in a letter dated September 3, 2009, MEA’s then Interim General Manager advised Chugach that MEA desires to open discussions regarding power sales possibilities beyond 2014.  Discussions have been ongoing and are expected to continue in 2011.

HEA

We had a power sales contract with AEG&T for firm, partial- requirement sales to HEA until June 19, 2002, when the RCA approved the request by Alaska Electric and Energy Cooperative, Inc. (AEEC) and AEG&T to transfer Certificate of Public Convenience and Necessity No. 345 to serve as the power supplier of HEA to AEEC, instead of AEG&T.  HEA is the sole member of AEEC.  As part of this transaction our power sales agreement was assigned to AEEC and the Nikiski dispatch agreement was assigned to HEA with certain exceptions with the remaining rights and obligations under the Dispatch Agreement being assigned to AEEC (discussed below).  Chugach has not experienced a decline in revenue as a result of this transfer. Under our contract, HEA is obligated to pay us for the power sold to AEEC even if AEEC does not pay.  Under this contract, HEA is obligated (through AEEC) to take or pay for 73 MW of capacity, and not less than 350,000 MWh per year.  The HEA contract, as interpreted by the Alaska Public Utilities Commission, the predecessor to the RCA, limits the costs that may be included in our rates charged to HEA.  The HEA contract expires on January 1, 2014.  HEA’s remaining resource requirements are provided by AEEC’s Nikiski cogeneration facility and AEEC’s contract rights to receive power from the Bradley Lake hydroelectric project for the benefit of HEA.  In 2010, sales to HEA represented approximately 17 percent of Chugach’s total sales of energy (including both retail and wholesale).

In February 1999, we entered into a dispatch agreement with AEG&T, now AEEC, to operate the Nikiski unit as a Chugach system resource.  The agreement provides that, in addition to the energy that we already sell to AEEC and HEA, we will sell energy to AEEC equal to HEA’s residual energy requirements less its allocated share of the Bradley Lake project, up to a maximum of 320,000 MWh per year.  A portion of the Nikiski unit output may be dispatched for HEA needs, provided HEA supplies the fuel, in excess of the sum of our contract demand plus HEA’s share of energy from the Bradley Lake project.  The dispatch agreement will terminate on January 1, 2014, when our power supply contract with HEA terminates.  In a letter dated January 9, 2007, HEA notified Chugach that HEA would not seek to renew, extend or modify the current Agreement for Sale of Electric Power and Energy (the Agreement) when the Agreement expires on January 1, 2014.  On January 15, 2008, Chugach and HEA signed an agreement entitled Settlement of Dispute over Nikiski Cogeneration Plant System Use and Dispatch Agreement and Premium Demand Charges under HEA’s Power Sales Agreement.  This resolved a dispute over the interpretation of the Nikiski Cogeneration Plant System Use and Dispatch agreement.  As part of the Settlement Agreement, Chugach agreed to dispatch HEA’s share of Bradley Lake output for $30,000 per year to minimize, to the extent possible, any premium demand charges to be paid to Chugach by HEA.


On February 18, 2008, Chugach offered AEEC the opportunity to participate in the development of a gas-fired generation plant in order to partially satisfy its power requirements.  In June 2008, AEEC elected to withdraw from further participation discussions and pursue its own generation project.

Seward

We currently provide nearly all the power needs of the City of Seward.  In 2010, sales to Seward represented approximately 2 percent of Chugach’s total sales of energy (including both retail and wholesale).  In February 1998, we entered into a power sales agreement (Old Contract) with Seward that allowed us to interrupt service to Seward up to 12 times per year, not to exceed seventy-two cumulative hours annually.  Seward’s demand charge was adjusted to reflect the level of service provided by Chugach (approximately $350,000 annually).  This agreement expired on May 31, 2006.

We entered into a new power sales agreement (2006 Agreement) with the City of Seward, nominally effective June 1, 2006.  The new contract is for five years with two automatic five-year extensions, after RCA review, unless notice of termination is given by either party.  The 2006 Agreement is an interruptible, all-requirements/no 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, HEA 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 will be 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 in place of more expensive energy that it would have otherwise generated itself or purchased from other sources.

On April 6, 2010, Chugach and GVEA finalized an agreement for Chugach to provide a minimum of 20 MW of economy energy to GVEA on a non-firm basis based on an interruptible gas supply arrangement.  The agreement commenced on May 1, 2010, and will continue through March 31, 2013, pending annual commitments from gas suppliers.  The price to GVEA will include the cost of fuel (based on a system average heat rate), plus variable operations and maintenance expense, plus a margin.  Sales will be made under the terms and conditions of Chugach’s economy energy sales tariff.


Non-firm sales to GVEA have been 277,793 MWh, 76,968 MWh and 254,372 MWh for 2010, 2009, and 2008, respectively.  For sales not covered by a contractual priority right, no seller enjoys a contractual priority in making such sales and GVEA makes purchases from the seller offering the lowest competitive price.

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 not 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 fuel surcharge 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 Surcharge.”

The Second Amended and Restated Indenture of Trust (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, 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 2010 Credit Agreement with National Rural Utilities Cooperative Finance Corporation (NRUCFC), Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch, and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch, which became effective November 17, 2010, and 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.  The Revolving Line of Credit Agreement with NRUCFC requires Chugach to maintain an average TIER of not less than 1.10 times total interest expense.


For the years ended December 31, 2010, 2009 and 2008, our Margins for Interest/Interest (MFI/I) was 1.26, 1.27 and 1.28, respectively.  For the same periods, our TIER was 1.44, 1.28 and 1.30, respectively.  The temporary increase in TIER in 2010 was due to certain debt classified as short term, which will later be replaced with long-term debt.
 
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, 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.

The Kenai Peninsula is south of Anchorage with an economy substantially independent of the Anchorage area.  The most significant basic industry on the Kenai Peninsula is the production and processing of oil and gas from the Cook Inlet region.  Consequently, the Kenai Peninsula economy is sensitive to oil and gas price trends.  Recent examples of the impact from these trends include the closure of Agrium’s Kenai facilities in 2008 due to Agrium’s inability to acquire an economic supply of gas.  Up until the closure, the Agrium facility was the largest value-added product exporter in Alaska.  A more recent example of the impact of world markets is the upcoming closure in April or May 2011 of the Marathon and ConocoPhillips jointly-owned liquefied natural gas (LNG) export facility due to the LNG markets and world pricing.  This LNG export facility, the only one operating in the United States, has been exporting LNG to Japan for 41 years.  Partially offsetting these losses, the Tesoro’s Kenai refinery (one of the largest Alaska refiners producing gasoline, jet fuel, heavy fuel oils, propane and asphalt) expanded its operations and capacity to include the production of ultra low sulfur gasoline and diesel.  Third party oil and gas developers have shown increased interests in multiple developments across the Kenai, which will also help offset the loss of long-time industrial consumers.  Other important basic industries include tourism and commercial fishing and processing.  Principal communities on the Kenai Peninsula are Homer, Seward, Kenai and Soldotna.


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.

Load Forecasts
 
The following table sets forth our projected load forecasts for the next five years:

Load (MWh)
  
2011
    
2012
    
2013
    
2014
    
2015
  
Retail
     1,159,995       1,158,684       1,157,377       1,156,073       1,154,772  
Wholesale
     1,249,919       1,262,491       1,266,362       815,806       58,173  
Losses
     125,000       125,277       125,294       111,739       89,013  
Total
     2,534,914       2,546,452       2,549,033       2,083,618       1,301,958  

Overall, retail and wholesale energy requirements are expected to remain relatively flat over the next three years.  The single largest source of growth in Chugach’s system is the Goose Creek Correctional Center currently under construction in the MEA service area.  Also, while MEA’s growth has slowed over the last three years, the Matanuska-Susitna (MatSu) Borough economy continues to expand to serve an increasing suburban population.  Our total firm energy requirements are expected to grow at an average annual compounded rate of 0.3 percent from 2011 to 2013, with retail requirements slightly declining at a rate of 0.1 percent and wholesale requirements growing at a rate of 0.7 percent.  At the end of 2013, HEA’s contract to purchase their net requirements from Chugach expires, causing system requirements to decrease by 18%.  At the end of 2014, MEA’s contract to purchase their full requirements from Chugach expires, resulting in a decrease of 38% in system requirements. Overall, the expiration of these contracts amounts to a 49% decrease in Chugach system requirements based on 2013 sales levels.

Growth in retail and wholesale energy sales are expected to be partially or more than offset by expected consumer efficiency/conservancy. 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 effect 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, the future direction customers may take 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

Over the next two years Chugach anticipates financing increased capital expenditures due to the construction of a natural gas fired generation plant and on-going capital needs.  On November 17, 2010, Chugach replaced the $300 million unsecured Credit Agreement executed on October 10, 2008, which was due to expire on October 10, 2011.  The 2010 Credit Agreement with National Rural Utilities Cooperative Finance Corporation (NRUCFC), Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch, will expire on November 17, 2013.  The Credit Agreement is used to back Chugach’s Commercial Paper program, which will act as a bridge until Chugach converts commercial paper balances to long-term debt.  Chugach began issuing short term commercial paper in the first quarter of 2009, see “Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Commercial Paper.”  No assurance can be given that Chugach will be able to refinance commercial paper with longer term debt or that it will be able to continue to access the commercial paper market.  Global financial markets and economic conditions have been volatile due to a variety of factors, including current weak economic conditions.  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. The termination of the wholesale power contracts with MEA and HEA could negatively impact our ability to finance or could impact the cost associated with our financing efforts.

Wholesale Contracts

Chugach is the principal supplier of power under long-term wholesale power contracts with MEA and HEA.  These contracts, including the fuel component, represented $89.1 million, or 35 percent and $112.6 million, or 39 percent in 2010 and 2009, respectively, of total sales revenue.  The HEA and MEA contracts expire January 1, 2014, and December 31, 2014, respectively.

Pursuant to provisions of their contracts, notification was made by MEA in 2004 and by HEA in 2007 that neither organization intends to be on the Chugach system under the current contractual arrangements post 2014.  This would result in a loss of approximately 45 percent of Chugach’s power sales load and approximately 35 percent of the utility’s annual sales revenue.  At the August 26, 2009, Chugach Board of Directors’ meeting and in a letter dated September 3, 2009, MEA’s then-Interim General Manager advised Chugach that MEA desires to open discussions regarding power sales possibilities beyond 2014.  Discussions have been ongoing and are expected to continue in 2011.

Chugach’s planning process, however, reflects the termination of the MEA and HEA wholesale contracts post 2014.  Consequently, to mitigate this risk, Chugach will be pursuing replacement sources of revenue through potential new power sales agreements and transmission wheeling and ancillary services tariff revisions.  The loss of these wholesale customers may require Chugach to file a general rate case to recover total costs and/or restructure rates.  To the extent that the general rate case could take up to fifteen months to be completed, Chugach may request an interim and refundable rate increase in which the RCA is required to take action within 45 days.  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 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.  Standard & Poor's Rating Services (S&P), Moody's Investors Service (Moody's) and Fitch Inc. (Fitch) currently rate our outstanding bonds issued under the Amended & Restated Indenture at "A-", "A3" and "A-", 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.

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.  If a funding shortfall in the AEPF exists, we may incur a contingent withdrawal liability.  Our contingent withdrawal liability is an amount based on our pro rata share among AEPF participants of the value of the funding shortfall.  This contingent liability becomes due and payable by us if we terminate our participation in the AEPF.

We also participate in the National Rural Electric Cooperative Association (NRECA) Retirement Security Plan (the “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 our employees not covered by a union agreement become participants in the Plan.  We do not have control over the Plan.  The Plan updates contribution rates on an annual basis to maintain the health of the plan consistent with Pension Protection Act of 2006 minimum funding standards.  Currently, the plan does not require accelerated catch-up 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 a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure.  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 surcharge 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 surcharge to recover those costs at the time of the next quarterly fuel surcharge 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.


Southcentral Power Project (SPP)

We are currently in the process of developing a natural gas-fired generation plant near our Anchorage headquarters.  The generation plant is being developed jointly with AML&P.  All projects of this size and nature are subject to numerous schedule and cost risks including weather conditions, delays in obtaining key materials, labor difficulties, permitting, construction delays, difficulties with partners or other factors beyond our control.  Any of these events could cause the total costs of construction to be higher than anticipated and the performance of our business following the construction to not meet expectations, hence hindering our ability to timely and effectively integrate the SPP into our operations, resulting in unforeseen operating difficulties or unanticipated costs.  Any of these or other factors could adversely affect our ability to realize the anticipated benefits from the project.  We have contracts in place that utilize facilities in Japan.  We have received notification that impact assessments have begun following the March 11, 2011 earthquake and tsunami.  We are not aware of any specific delays at this time.  On December 20, 2010, Chugach received a construction permit from the Alaska Department of Environmental Conservation allowing the project to begin construction in the spring of 2011 as planned.  On March 15, 2011, Chugach received its initial building permit from the Municipality of Anchorage.

Fuel Supply

In 2010, 89 percent of our power was generated from natural gas, which included power generated at Nikiski.  Our primary suppliers of natural gas are ConocoPhillips, AML&P, Chevron/UNOCAL and Marathon. Chugach currently has contracts in place to fill 100 percent of Chugach’s unmet needs through December 2013, approximately 50 percent of Chugach’s unmet needs through December 2014, approximately 60 percent in 2015 and approximately 29 percent in 2016.

The State of Alaska Department of Natural Resources (DNR) completed a preliminary engineering and geological evaluation of the remaining Cook Inlet gas reserves in December of 2009.  The study identified 863 billion cubic feet (BCF) of proven, developed, producing reserves, additional probable reserves of 279 BCF and an additional increment of 353 BCF in high-confidence pay intervals.  Combined, these 1.5 trillion cubic feet of gas reserves are similar to the 1.4 trillion cubic feet of gas reserves identified in a 2004 study undertaken by the Department of Energy.  Given current demand and deliverability, DNR estimates at minimum a 10-year supply of gas exist in currently producing leases.  DNR does note that economic considerations will play a major role in whether producers continue drilling and development activities to meet demand.  Chugach has been working closely with the state and producers to develop a comprehensive Cook Inlet management plan that will meet this goal.


Chugach continues to explore its options for future fuel supply needs by working with developers on commercial terms for natural gas storage and the state of Alaska on energy policies to promote gas development in Cook Inlet and other in-state gas options such as the North Slope Pipeline, Spur Line or Bullet line to South Central Alaska.  Chugach is also evaluating LNG storage and import options as transition gas until in-state gas options are developed.

Cooper Lake Hydroelectric Project

The Cooper Lake Hydroelectric Project received a 50-year license from the Federal Energy Regulatory Commission (FERC) in August of 2007.  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 warm water from Cooper Lake into Cooper Creek potentially enhancing fish habitat.  The cost and feasibility of this project are currently being assessed.  If the project is not feasible or if the cost estimate materially exceeds the terms of the license it may require a license amendment.

Other Environmental Regulations

 We currently are required to comply with numerous federal, state and local laws and regulations relating to the protection of the environment.  While we believe that we have obtained all material environmental-related approvals currently required to own and operate our facilities, we 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 CO2 emissions.  Failure to comply with environmental laws and regulations could have a material effect on us, 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 us.

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 surcharge process which will ensure, in advance, that costs incurred under the contracts can be recovered from Chugach’s customers.  The fuel surcharge process recovers under-recoveries and refunds over-recoveries from prior periods with minimal regulatory lag.  Chugach's fuel surcharge 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 surcharge.  At December 31, 2010, Chugach had under-recovered $2.4 million and at December 31, 2009, Chugach had over-recovered $3.2 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.

Green House Gas Regulations, Carbon Emission and Climate Change

Substantial uncertainty remains regarding the potential impacts of green house gas (GHG) regulations, carbon emissions, and climate change on Chugach's operations. These issues are potentially responsible for increased frequency of warmer weather, including potentially decreased hydroelectric generation resulting from reduced runoff from snow pack.  If climate change reduces Chugach's hydroelectric energy production, there may be a need for additional production even if there is no change in average load.

In response to growing public concerns over these issues, the federal government has actively begun pursuing legislation that calls for the reduction of GHG emissions.  The proposed legislation typically consists of either a tax on GHG emissions or a cap and trade program that requires allowances to emit GHG.  Proposals that implement a GHG emission tax vary widely as to the amount of the tax.  Proposed cap and trade programs vary greatly regarding the number of allowances existing facilities would receive at “no cost”, similar to other Clean Air Act regulations.  Some proposals do not provide “no cost” allowances to existing facilities.

The additional costs related to a GHG tax or cap and trade program could affect the relative cost of the energy Chugach produces.  Because no applicable federal laws regulating GHG emissions have become effective, we cannot predict the cost or effect of future legislation or regulation.  In the event that some form of federal law or regulation regarding GHG emissions is enacted in the future, it could have a material adverse effect on our operations, financial position, and cash flows.

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

Item 1B – Unresolved Staff Comments

Not applicable

Item 2 - Properties

General

We have 530.1 MW of installed capacity consisting of 17 generating units at five power plants.  These include 385.0 MW of operating capacity at the Beluga facility on the west side of Cook Inlet; 67.5 MW of power at the Bernice Lake facility on the Kenai Peninsula; 46.7 MW of power at IGT in Anchorage; and 19.2 MW at the Cooper Lake facility, which is also 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 AML&P. In addition to our own generation, we purchase power from the 126 MW Bradley Lake hydroelectric project owned by the Alaska Energy Authority (AEA) through the Alaska Industrial Development and Export Authority.  The Bradley Lake facility is operated by HEA and dispatched by us.  The Beluga, Bernice Lake and IGT facilities are all fueled by natural gas. We own our offices and headquarters, located adjacent to IGT 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 and IGT. In 2008 and 2009 we purchased land adjacent to our Anchorage headquarters for use during the construction of a new gas fired generation plant we are jointly developing with AML&P.  We also own all improvements comprising our generating plant at Bernice Lake, located on land leased from HEA for an immaterial amount.  The Bernice Lake ground lease expires in 2011.  We are currently involved in discussions with the lease holder concerning a lease extension.

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 2007.  As part of the relicensing process, there was a negotiated Relicensing Settlement Agreement (RSA) entered into in August of 2005.  The RSA required Chugach to paint the powerhouse and Cooper Lake intake structure per United States Forest Service (USFS) color specification to reduce visual impact of project facilities.  This task was completed in August of 2009.  The RSA also required Chugach to design, permit, and construct a winter access parking area.  This project was completed in September of 2009.  The most significant requirement of the RSA requires Chugach to establish a flow regime in Cooper Creek below the Cooper Lake Dam.  This is a complex project that includes a Stetson Creek Diversion (Dam), Pipeline (Conveyance System) and Cooper Lake Outlet Works.  In short, it is designed to remove colder water flowing into Cooper Creek drainage and replace it with warmer Cooper Lake water, possibly improving fish habitat.  Our consultants have completed extensive geotechnical feasibility work over the last two years and recently issued a “Draft” Basis of Design Report.  The next step is to complete the final design package to submit to FERC.  Chugach was successful in obtaining a two year extension on this deliverable, which is now due in August of 2012.

Cooper Lake Unit 2 was taken out of service in August of 2008 to perform repairs and major maintenance.  The unit was put back into service in May of 2009.  Unit 1 was taken out of service in May of 2009, shortly after the return to service of Unit 2, to perform repairs and major maintenance, and returned back into service in February of 2010.  Both units were in service or standby since February of 2010.

In 1997, we acquired a 30 percent interest in the Eklutna Hydroelectric Project.  The plant is located on federal land pursuant to a United States Bureau of Land Management right-of-way grant issued in October 1997.  MEA owns 17 percent of the project and AML&P owns the remaining 53 percent undivided interest and performs maintenance on the units as needed.


Our principal generation units are Beluga 3, 5, 6, 7 and 8.  These units have a combined capacity of 345.8 MW and meet most of our load.  All other units 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.  Due to the age of Unit 3, several of the high risk parts of the turbine rotor were replaced during a major inspection in 2007.  Combustion inspections were performed on Unit 3 in 2008, 2009 and 2010 in accordance with the existing maintenance plan.  Beluga Unit 5 continued to have two combustion inspections per year in 2008, 2009 and 2010.  In 2007, this unit received a hot gas path inspection which involved generator repairs.  Beluga Unit 6 was re-powered in 2000 and received annual inspections in 2007, 2008 and 2009.  In 2010, Unit 6 received a major inspection in which many of the major components were replaced with new or refurbished parts.  Beluga Unit 7 was re-powered in 2001 and had major inspections in 2004 and 2008 with annual inspections in 2007, 2009 and 2010.  Beluga Unit 8, a steam turbine generator, received a major inspection in 2008 with annual inspections in 2009 and 2010.

Chugach is in the process of developing a natural gas-fired generation plant on land owned by Chugach near its Anchorage headquarters.  SPP will be developed and owned by Chugach and AML&P as tenants in common.  Chugach will own and take approximately 70 percent of the new plant’s output and AML&P will own and take the remaining output.  Chugach will proportionately account for its ownership in the SPP.

On November 17, 2008, Chugach executed a gas turbine purchase agreement for the purchase of three gas turbines with General Electric Packaged Power (GEPP).  During 2009 Chugach executed several amendments associated with its purchase agreement with GEPP, which included the purchase of a spare engine for maintenance purposes.  Chugach executed an Owner’s Engineer Services Contract on May 12, 2009.  On January 5, 2010, Chugach executed a Services Contract for the shipment of the combustion turbine generators and related accessories.  On February 25, 2010, Chugach purchased land adjacent to its Anchorage headquarters for the laydown of equipment displaced by the new power plant.  On April 13, 2010, Chugach executed a steam turbine generator (STG) purchase agreement.  On June 18, 2010, Chugach executed an Engineering, Procurement, and Construction (EPC) contract with SNC-Lavalin Constructors, Inc. (SLCI).  On August 27, 2010, Chugach executed a Once Through Steam Generator (OTSG) equipment contract with Innovative Steam Technologies (IST).  Chugach amended the contract for transportation of combustion turbine generators on September 28, 2010, to include transportation of the steam turbine generator.  On December 20, 2010, Chugach received a construction permit from the Alaska Department of Environmental Conservation allowing the project to begin construction in the spring of 2011 as planned.  On March 15, 2011, Chugach received its initial building permit from the Municipality of Anchorage.  Chugach made payments of $74.3 million in 2010 and $25.0 million in 2009, with additional payments of $153.7 million expected in 2011, pursuant to all these contracts.


The following matrix depicts nomenclature, run hours for 2010 and percentages of contribution and other historical information for all Chugach generation units.

Facility
    
Commercial Operation Date
  
Nomenclature
  
Rating
(MW)(1)
    
Run Hours (2010)
    
Percent of Total Run Hours
    
Percent of
Time
Available
  
Beluga Power Plant (3)
                                  
  1     1968  
GE Frame 5
     19.6       1,920.6       3.9       98.2  
  2     1968  
GE Frame 5
     19.6       2,199.9       4.4       96.9  
  3     1972  
GE Frame 7
     64.8       7,891.0       15.9       95.0  
  5     1975  
GE Frame 7
     68.7       7,697.8       15.5       94.2  
  6     1976  
AP 11DM-EV
     79.2       6,877.7       13.8       78.5  
  7     1978  
AP 11DM-EV
     80.1       8,241.1       16.6       94.1  
  8     1981  
BBC DK021150(2)
     53.0       7,740.4       15.6       88.6  
Bernice Lake Power Plant (3)
               385.0                          
  2     1971  
GE Frame 5
     19.0       1,051.2       2.1       91.6  
  3     1978  
GE Frame 5
     26.0       214.9       0.4       51.0  
  4     1981  
GE Frame 5
     22.5       456.3       0.9       75.9  
Cooper Lake Hydroelectric Plant
               67.5                          
  1     1960  
BBC MV 230/10
     9.6       2,570.5       5.2       85.2  
  2     1960  
BBC MV 230/10
     9.6       2,506.1       5.1       95.9  
IGT Power Plant
               19.2                          
                                             
  1     1964  
GE Frame 5
     14.1       51.9       0.1       98.5  
  2     1965  
GE Frame 5
     14.1       142.3       0.3       92.6  
  3     1969  
Westinghouse 191G
     18.5       86.9       0.2       98.3  
Eklutna Hydroelectric Plant
               46.7                          
  1     1955  
Newport News
     5.8 (4)     N/A (5)     N/A (5)     93.8  
  2     1955  
Oerlikon custom
     5.9 (4)     N/A (5)     N/A (5)     98.6  
                  11.7                          
System Total
               530.1       49,648.6       100.0          

(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 and Bernice Lake Unit 1 were retired during 1994.
(4)
The Eklutna Hydroelectric Project is jointly owned by Chugach, MEA and AML&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 23.5MW.
(5)
Because Eklutna Hydroelectric Project is managed by a committee of the three owners, we do not record run hours or in-commission rates.

Note: GE = General Electric, BBC = Brown Boveri Corporation, AP = Alstom Power


Transmission and Distribution Assets

As of December 31, 2010, our transmission and distribution assets included 42 substations and 539 miles of transmission lines, which included 128 miles of leased transmission lines and Chugach’s share of the Eklutna transmission line, 914 miles of overhead distribution lines and 779 miles of underground distribution line.  We own the land on which 22 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 facility, we also acquired a partial interest in two substations and additional transmission facilities.

Many substations and a substantial number of our transmission and distribution rights-of-way are subject to federal or state permits, leases and licenses.  Under a federal license and a permit from the United States Forest Service, we operate the Quartz Creek transmission substation and the Hope substation.  We also operate transmission lines over federal, state and borough lands.  Under a State of Alaska permit from the Department of Natural Resources, we operate the Summit Lake and Daves Creek substations.  Long-term permits from the Alaska Division of Lands and the Alaska Railroad Corporation govern much of the rest of our transmission system outside the Anchorage area.  Within the Anchorage area, we operate our University substation and several major transmission lines pursuant to long-term rights-of-way grants from the U.S. Department of the Interior, Bureau of Land Management, and transmission and distribution lines have been constructed across privately owned lands via easements and across public rights-of-way and waterways pursuant to authority granted by the appropriate governmental entity.

Title

Under Chugach’s Amended and Restated Indenture dated April 1, 2001, all of Chugach’s bonds were general unsecured and unsubordinated obligations.  On January 20, 2011, Chugach and the indenture trustee entered into a Second Amended and Restated Indenture of Trust (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 U.S. 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.


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 126 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 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 million principal amount of revenue bonds supported by power sales agreements with six electric utilities that share the output from the facility (AML&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 fifty years from the date of commercial operation of the facility (September 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 surcharge process.  The share of Bradley Lake indebtedness for which we are responsible is approximately $33 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 $5.3 million as a result of Chugach’s Bradley Lake take-or-pay obligations.


On July 1, 2010, AEA issued $28,800,000 of Power Revenue Refunding Bonds, Sixth Series, for purposes of refunding $30,640,000 of the Fifth Series Bonds.  The refunded Fifth Series Bonds were called on August 2, 2010.  The refunding resulted in aggregate debt service payments over the next eleven years in a total amount approximately $3.3 million less than the debt service payments which would have been due on the refunded bonds.  Refunding the Fifth Series Bonds resulted in an economic gain of approximately $2.4 million.  Chugach’s share of these savings will be approximately $714,300, which represents the reduction in debt-service costs recorded as purchased power expense.

Eklutna.  We purchased a 30 percent undivided interest in the Eklutna Hydroelectric Project from the federal government in 1997.  MEA owns 17 percent of the Eklutna Hydroelectric Project.  The power MEA purchases from the Eklutna Hydroelectric Project is pooled with our purchases and sold back to MEA to be used in meeting MEA’s overall power requirements.  AML&P owns the remaining 53 percent undivided interest in the Eklutna Hydroelectric Project.

Fuel Supply

In 2010, 89 percent of our power was generated from natural gas, which included power generated at Nikiski, and 78 percent of that gas-fired generation took place at Beluga.

Total gas usage in 2010 was approximately 28.9 BCF.  Our primary sources of natural gas are divided among four long-term contracts with three major oil and gas companies and one utility.  All of the production came from Cook Inlet, Alaska.  ConocoPhillips Alaska Inc. under their Beluga River Unit (BRU) and new contract provided 42.0 percent of gas supplied for generation, while Marathon Oil Company provided 34.0 percent.  Chevron U.S.A. provided 15.0 percent and AML&P provided 10.0 percent of Chugach’s gas requirements.  Approximately 2.2 BCF of gas remains on the current contracts.  Our contract gas with Marathon expired in 2010 and we expect the remaining three contracts to run-out in early 2011.  The new contract with ConocoPhillips provides gas beginning in 2010, through December 31, 2016.  A new contract with Marathon will provide gas, now estimated to be 26 BCF, beginning in April of 2011, which together, will fill Chugach’s unmet needs through December 31, 2013.  Under almost all circumstances the deliverability supplied under our contracts is sufficient to meet all of our generating requirements.
 
ConocoPhillips

We entered into a contract with ConocoPhillips Alaska Inc. (COP) in 2009.  The new contract provides gas starting January 1, 2010, and will terminate December 31, 2016.  The total amount of gas under the contract is now estimated to be 62 BCF.  The new contract is designed to fill 100 percent of Chugach’s unmet needs until April 2011, approximately 50 percent of Chugach’s unmet needs from May 2011 through December 2014, approximately 60 percent in 2015 and approximately 29 percent in 2016.

The gas supplied by COP 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.  Chugach expects that ninety percent of the gas purchased under the contract will be firm fixed and ten percent will be firm variable.  The dividing line between firm fixed and firm variable volumes will be calculated based on a methodology that involves using a multiplier and the simple average of Chugach’s average daily volumes for the thirty lowest volume days during the last calendar year.  For example, in 2011 the Firm Fixed Quantity value has been calculated at 34,500 thousand cubic feet (Mcf) per day, which is the contract minimum.


Pricing for firm fixed gas will be based on the average of five Lower 48 natural gas production areas.  The contract price will be 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.  For the first half of 2010 there was a price collar, floor of $5.75 per Mcf and cap of $6.25 per Mcf, on the firm fixed gas between January 1, 2010 and June 30, 2010. After the initial period we experienced firm fixed price levels below the initial price floor of $5.75.  For the period July 1 through September 30, 2010, the Firm Fixed Quantity price was $4.15.  For the final quarter of 2010, (October 1 through December 21, 2010) the Firm Fixed Quantity price was $4.078.

Pricing for firm variable gas purchased between January 1, 2010, and March 31, 2011, was set based on one quarter trailing average of ninety-five percent of the average monthly price of Kenai liquefied natural gas delivered to Japan, as officially reported to the U.S. Department of Energy.  The price for the first quarter of 2010 was $10.388 per Mcf, while the price for the second quarter was $11.016 per Mcf.  Hourly volumes delivered up to this hourly rate will be priced based on the Firm Fixed Quantity price.  Hourly volumes delivered in excess of this hourly rate will be priced based on the Firm Variable Quantity price.  For the first quarter of 2011, the Firm Fixed Quantity is calculated at $3.689 per Mcf.  Pricing for firm variable gas purchased from April 1, 2011, to December 31, 2013, will be 120 percent of the one calendar quarter trailing average of “Platts National Average Price” as published in Platts Gas Daily for each “flow day.” ($4.31 per Mcf on January 1, 2011), plus taxes in excess of $0.25 per Mcf.  The price for firm variable gas is capped at two-hundred percent of the firm fixed price.  Firm variable gas is not provided by the contract after December 31, 2013.

Chugach also has the option to receive a fixed price quote from COP 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.

Beluga River Field Producers
 
We have similar requirements contracts with each of the one third working interest owners of the Beluga River Field, ConocoPhillips, AML&P and Chevron, which were executed in April 1989, superseding contracts that had been in place since 1973.

The current contracts continue until the earlier of the delivery of 180 BCF of natural gas or December 31, 2013.  Chugach is entitled to 180 BCF of natural gas (60 BCF per Beluga River Field producer).  During the term of the contracts, we are required to take 60 percent of our total fuel requirements at Beluga Power Plant from the three Beluga River Field producers, exclusive of gas purchased at Beluga Power Plant under the Marathon contract for use in making sales to GVEA.  The price for gas during this period under the ConocoPhillips and AML&P contracts is approximately 88 percent of the price of gas under the new Marathon contract (described below) ($5.90 per Mcf on April 1, 2011), plus taxes.  The price during this period under the Chevron contract is approximately 110 percent of the price of gas under the Marathon contract (described below) ($5.15 per Mcf on January 1, 2011), plus taxes.


Chevron/UNOCAL

In May of 2010, Chugach entered into an interruptible gas purchase agreement with UNOCAL to supply gas for economy energy sales to GVEA.  Chugach has no exposure to the cost of gas related to economy energy sales since the cost of gas is directly paid for by its economy energy gas customer.
 
Marathon Alaska Production
 
We entered into a requirements contract with Marathon in September 1988 for an initial commitment of 215 BCF.  The contract was due to expire on the earlier of December 31, 2015, or the date on which Marathon delivered to us a volume of gas in total, which equaled 215 BCF.  The base price for gas under the Marathon contract was $1.35 per Mcf, adjusted quarterly to reflect the percentage change between the preceding twelve-month period and a base period in the average closing prices of New York Mercantile Exchange (NYMEX) Light, Sweet Crude Oil Futures, the Producer Price Index for natural gas, and the Consumer Price Index for heating fuel oil.

Under the terms of the Marathon contract, Marathon was to provide all of Chugach’s requirements at Bernice Lake, IGT and Nikiski.  Additionally, Marathon had responsibility to supply 40 percent of gas volumes to the Beluga plant.  This contract was estimated to expire and did expire in 2010.  During 2010, Marathon volumes were not sufficient to meet the 40% gas requirements for the full year.  To make the transition from the expiring Marathon contract to the new COP gas contract, Marathon and ConocoPhillips shared the gas deliverability of the 40% gas volume for the entire year.

The RCA approved a new long-term natural gas supply contract with Marathon Alaska Production, LLC (MAP) effective May 17, 2010.  The new MAP contract will provide gas beginning April 1, 2011, terminating March 31, 2013.  MAP has two contract extension options that can be exercised during the first year of the initial contract.  MAP extended the contract to December 31, 2013, by exercising the first contract extension on January 12, 2011.  The second contract option could be exercised by December 31, 2011, and would extend the contract through December 31, 2014.  The total amount of gas under contract is estimated at 26 billion cubic feet (BCF) for the initial two year term of the contract with volumetric and delivery terms to be determined for each contract extension period that could provide up to an additional 16 BCF through December 31, 2014.

Pricing for the first twelve month term of the MAP contract has been set at the contract floor price of $5.90 per Mcf.  This was established based on the average price point of the Platts Gas Daily NYMEX twelve month forward curve (PLATTS report as of February 1, 2011) for the period April, 2011 through March 2012 being set at $4.68 per Mcf, which was lower than the price floor making the price floor the pricing level for the first twelve month period.


Natural Gas Transportation Contracts

The terms of the new COP, MAP and UNOCAL agreements require Chugach to handle the natural gas transportation over the connecting pipeline systems.  Chugach took over the transportation obligation for natural gas shipments for gas supplied under its new contracts on October 1, 2010.  Chugach started shipping significant quantities of gas over Marathon Pipe Line Company (MPL) operated pipelines and ENSTAR Natural Gas pipeline system.  Chugach entered into tariff supported contracts to serve its power plants through MPL effective October 1, 2010, and ENSTAR November 15, 2010.  The following information summarizes the transportation obligations for Chugach:

ENSTAR (Alaska Pipeline Company)
 
ENSTAR Natural Gas Company (ENSTAR) has a tariff to transport our gas purchased from gas suppliers on a firm basis to our IGT Power Plant at a transportation rate of $0.63 per Mcf.  The agreement contains a fixed monthly charge of $2,840 for firm service.  In December of 2010, Chugach applied for extension of this tariff rate with ENSTAR to service the Bernice Lake Power Plant.  Chugach expects regulatory approval in the first quarter of 2011.

Chugach entered into a special transportation agreement with ENSTAR for the transportation of natural gas to the Beluga Power Plant from points of receipt on the Kenai to the Beluga Power Plant on ENSTAR’s west side pipeline system.  This agreement has an initial term of November 15, 2010, through October 31, 2011.

Marathon Pipeline System

Marathon Oil Company, through its subsidiary Marathon Pipe Line Company, operates four major pipelines in the Cook Inlet basin, including the Kenai Nikiski Pipeline (KNPL), Granite Point Beluga Line (BPL), Cook Inlet Gas Gathering System (CIGGS) and the Kenai Katchemak Pipeline (KKPL).  Chugach has entered into two tariff agreements to ship gas over the KNPL and BPL.

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 Environmental Protection Agency (EPA) regulations under the act (the “Clean Air Act”) establish ambient air quality standards and limit the emission of many air pollutants.  Some Clean Air Act programs that regulate electric utilities, notably the Title IV “acid rain” requirements, do not apply to facilities located in Alaska.

New Clean Air Act regulations impacting electric utilities may result from future events or may result from new regulatory programs.  On October 30, 2009, the EPA published new federal regulations requiring the mandatory reporting of greenhouse gases from all sectors of the economy. Chugach is subject to this new regulation, which is not expected to have a material effect on our results of operations, financial position, or cash flows.  While we cannot predict whether any additional new regulation would occur or the effect of that regulation, it is possible that new laws or regulations could increase our capital and operating costs.  We have obtained or applied for all Clean Air Act permits currently required for the operation of our 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.  We do not believe that compliance with these statutes and regulations to date has had a material impact on our financial condition, results of operation or cash flows.  However, new laws or regulations, implementation of final regulations or changes in or new interpretations of these laws or regulations could result in significant additional capital or operating expenses.

Item 3 - Legal Proceedings

Chugach has certain litigation matters and pending claims that arise in the ordinary course of Chugach’s business.  In the opinion of management, no individual matter or the matters in the aggregate is likely to have a material adverse effect on Chugach’s results of operations, financial condition or liquidity.

Item 4 – Reserved

None

PART II

Item 5 - Market for Registrant's
Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities

Not Applicable


Item 6 - Selected Financial Data
 
The following table presents selected historical information relating to financial condition and results of operations for the years ended December 31:

Balance Sheet Data
  
2010
    
2009
    
2008
    
2007
    
2006
  
                               
Electric plant, net:
                              
In service
   $ 407,351,421     $ 414,002,926     $ 432,460,336     $ 438,239,286     $ 439,268,514  
                                         
Construction work in progress
     100,787,482       48,383,610       25,151,072       17,712,884       20,683,335  
                                         
Electric plant, net
     508,138,903       462,386,536       457,611,408       455,952,170       459,951,849  
                                         
Other assets
     121,588,825       105,958,000       119,080,561       101,773,948       103,733,881  
                                         
Total assets
   $ 629,727,728     $ 568,344,536     $ 576,691,969     $ 557,726,118     $ 563,685,730  
                                         
Capitalization:
                                        
Long-term debt
     304,450,318       307,301,819       354,383,506       345,423,500       350,803,530  
                                         
Equities and margins
     161,842,284       156,320,597       153,766,999       149,310,436       150,716,100  
                                         
Total capitalization
   $ 466,292,602     $ 463,622,416     $ 508,150,505     $ 494,733,936     $ 501,519,630  
                                         
Equity Ratio1
     34.7 %     33.7 %     30.3 %     30.2 %     30.1 %
                                         
Summary Operations Data
                                        
                                         
Operating revenues
   $ 258,325,345     $ 290,247,308     $ 288,292,112     $ 257,443,919     $ 267,542,713  
                                         
Operating expenses
     233,967,201       264,872,577       260,580,365       232,367,023       234,969,329  
                                         
Interest expense, net
     20,005,698       20,606,349       22,532,797       23,712,797       24,010,874  
                                         
Net operating margins
     4,352,446       4,768,382       5,178,950       1,364,099       8,562,510  
                                         
Nonoperating margins
     1,057,563       891,966       1,232,800       1,521,157       1,476,549  
                                         
Assignable margins
   $ 5,410,009     $ 5,660,348     $ 6,411,750     $ 2,885,256     $ 10,039,059  
                                         
Margins for Interest Ratio2
     1.26       1.27       1.28       1.12       1.41  

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.

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 Second Amended and Restated Indenture of Trust and debt agreements.


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

Margins.  We 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, 2010, 2009 and 2008 was $12,377,668, $20,159,196 and $21,309,900, 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.

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 - Years ended December 31, 2010, compared to the years ended December 31, 2009, and December 31, 2008 – Expenses.”  We achieved TIERs for the past three years as follows:

Year
TIER
2010
1.44
2009
1.28
2008
1.30

The temporary increase in TIER in 2010 was due to certain debt classified as short term, which will later be replaced with long-term debt.


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

The RCA approves both base rates and fuel surcharge rates paid by our retail and wholesale customers.  In addition, an RCC is assessed on each retail customer invoice to fund Chugach’s share of the RCA’s budget.  In general, the RCC tax is revised annually by the RCA.

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.

On November 15, 2010, base rates increased 0.2 percent to Chugach retail customers and 0.3 percent to Seward and decreased 0.6 percent and 1.2 percent to HEA and MEA, respectively. The base rate changes were the result of Chugach’s SRF utilizing the twelve months ended June 30, 2010, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Rate Regulation and Rates – Request for Participation in the Simplified Rate Filing Process.”

On November 1, 2010, base rates charged to retail customers decreased 1.5 percent and base rates charged to wholesale customers HEA, MEA and Seward decreased 2.3 percent, 2.2 percent and 1.8 percent, respectively.  The base rate changes were the result of final rates associated with Chugach’s 2008 Test Year Rate Case, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Rate Regulation and Rates – 2008 Test Year General Rate Case (Docket U-09-080).”

On October 9, 2009, base rates charged to retail customers increased 3.3 percent and base rates charged to wholesale customers HEA, MEA and Seward increased 7.8 percent, 2.0 percent and 9.7 percent, respectively.  The base rate changes were effective on an interim and refundable basis and were the result of proposed rates included in Chugach’s 2008 Test Year Rate Case filed with the RCA on June 23, 2009, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Overview – Rate Regulation and Rates - 2008 Test Year General Rate Case (Docket U-09-080).”

In June of 2008, the base rates charged to retail customers decreased 4.8 percent and base rates charged to wholesale customers HEA, MEA and Seward increased 13.0 percent, 10.5 percent and 9.6 percent, respectively.  The base rate changes were the result of Chugach’s 2005 Test Year Rate Case adjudicated under Docket U-06-134, see “Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations - Overview – Rate Regulation and Rates - 2005 Test Year General Rate Case (Docket  U-06-134).”


Request for Participation in the Simplified Rate Filing Process

On December 15, 2009, Chugach submitted a request to the RCA for approval to implement the SRF process for the adjustment of base energy and demand rates in accordance with Alaska Statute 42.05.381(e).  Chugach requested that base rate adjustments under SRF be completed on a semi-annual basis, utilizing the twelve months ended June and December as the test periods in each year.

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.  Utilization of SRF will allow Chugach to more efficiently adjust base rates in response to lower sales resulting from both energy conservation and technological improvements.  Chugach is also interested in SRF as a means to expedite the rate adjustment process with the goal of timely cost recovery and lower adjudicatory costs.

On April 21, 2010, the RCA opened docket U-10-20 to consider Chugach’s request to implement the simplified rate filing process.  A technical conference was held on June 1, 2010, to discuss guidelines that Chugach should follow in future simplified rate filings.  All parties agreed to modify the deadline for a final order to July 26, 2010.

A public hearing was held on July 19, 2010.  The parties to the docket entered into a stipulation on the outstanding issues in the case and the RCA issued a bench order at the hearing approving the stipulation.  A formal written order was issued on July 26, 2010.

On September 28, 2010, Chugach filed its initial filing under this process to decrease base rate revenue by $0.2 million, with increases of 0.2 percent to Chugach retail customers and 0.3 percent to Seward and decreases of 0.6 percent and 1.2 percent to HEA and MEA, respectively.  The RCA approved Chugach’s Simplified Rate Filing on November 4, 2010, for base rate changes effective November 15, 2010.

2008 Test Year General Rate Case (Docket U-09-080)

On June 23, 2009, Chugach filed a general rate case with the RCA to increase base rate revenue by $4.2 million, with increases of $2.7 million to Chugach retail customers and $1.5 million to wholesale customers.  Base rates charged to retail customers increased 3.3 percent and base rates charged to wholesale customers HEA, MEA and Seward increased 7.8 percent, 2.0 percent and 9.7 percent, respectively.

On October 9, 2009, the RCA granted Chugach’s original request that the proposed rates go into effect on an interim and refundable basis.

On October 15, 2009, the RCA consolidated Docket U-09-080 (General Rate Case) and Docket U-09-097 (Depreciation Study Update).

Chugach reached a settlement with its wholesale customers, HEA, MEA and Seward, which resolved issues in both the general rate case and the depreciation study update.


After a June 2010 hearing, the RCA issued a final order in the consolidated case (2008 Test Year General Rate Case and Revision to Current Depreciation Rates) on September 16, 2010.  The RCA accepted Chugach’s settlements with its wholesale customers, HEA, MEA and Seward and resolved depreciation issues disputed by the Attorney General, which resulted in no change to the depreciation rates contained in the settlement agreements.

As a result of the RCA accepting the settlement agreements and resolving depreciation issues, Chugach refunded its wholesale and retail customers approximately $0.7 million, including interest.

On November 1, 2010, the RCA materially accepted Chugach’s compliance filing.  Base rate changes were approved effective November 1, 2010.

2005 Test Year General Rate Case (Docket U-06-134)

On September 29, 2006, Chugach filed a general rate case based on a 2005 test year with the RCA.  Overall revenues were proposed to increase $2.8 million in the initial filing.

A settlement agreement reached in July 2007 between several of the intervenors and Chugach was accepted by the RCA in Order No. 15.  On April 1, 2008, the RCA issued Order No. 21 in Docket U-06-134, approving the rates from the Settlement Agreement among Chugach, HEA and Seward. MEA did not join the Settlement Agreement.  The effect of Order 21 was that overall revenues decreased by 0.8 percent, or $0.9 million, with retail base rate revenue decreasing by 4.8 percent, or $4.2 million and wholesale base rate revenue increasing by 11.0 percent, or $3.3 million. Order No. 21 was effective June 1, 2008.

After reconsiderations concerning a long-term debt allocator, the computation of depreciation expense and re-affirming filing requirements, the RCA issued Order No. 25 on November 7, 2008, accepting Chugach’s filings and closed docket U-06-134.  In this rate case, we modified the rate design so that all fuel and purchased power costs would be recovered through the fuel and purchased power process, which was approved by the RCA.
 
Fuel Surcharge.  We recover fuel and purchased power costs directly from our wholesale and retail customers through the fuel surcharge process.  Changes in fuel and purchased power costs are primarily due to fuel price adjustment mechanisms in our gas-supply contracts based on natural gas, crude oil and fuel oil indexed price changes.  Other factors, including generation unit availability also impact fuel surcharge rate levels.  The fuel surcharge is approved on a quarterly basis by the RCA.  There are no limitations on the number or amount of fuel surcharge rate changes.  Increases in our fuel and purchased power costs result in increased revenues while decreases in these costs result in lower revenues.  Therefore, revenue from the fuel surcharge does not impact margins.  We recognize differences between projected recoverable fuel costs and amounts actually recovered through rates.  The fuel cost under/over recovery on our Balance Sheet represents the net accumulation of any under or over collection of fuel and purchase power costs.  Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods.  Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods.


Years ended December 31, 2010, compared to the years ended December 31, 2009, and December 31, 2008

Margins

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

   
2010
    
2009
    
2008
  
Net Operating Margins
   $ 4,352,446     $ 4,768,382     $ 5,178,950  
Nonoperating Margins
   $ 1,057,563     $ 891,966     $ 1,232,800  
Assignable Margins
   $ 5,410,009     $ 5,660,348     $ 6,411,750  

The decrease in net operating margins in 2010 from 2009 of $415.9 thousand, or 8.7 percent, was due to an increase in power production and administrative, general and other expense, which was partially offset by a decrease in interest expense.  The decrease in net operating margins in 2009 from 2008 of $410.6 thousand, or 7.9 percent, was due primarily to a decrease in sales revenue and an increase in depreciation and administrative and general expense, which was partially offset by a decrease in net interest expense, see “Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Years ended December 31, 2010, compared to the years ended December 31, 2009, and December 31, 2008 – Expenses.”

Nonoperating margins include interest income, allowance for funds used in construction, capital credits and patronage capital allocations and other.  Nonoperating margins increased in 2010 from 2009 by $165.6 thousand, or 18.6 percent due primarily to higher interest income as a result of a higher cash balance and higher interest rates, higher Allowance for Funds Used During Construction (AFUDC) due to more construction activity and higher other nonoperating margins caused by a gain associated with the sale of land and settlement funds, which was partially offset by a lower patronage capital allocation from CoBank as our outstanding CoBank debt decreased.  Nonoperating margins decreased in 2009 from 2008 by $340.8 thousand, or 27.6 percent due primarily to lower interest income as a result of a lower cash balance and lower interest rates and a lower patronage capital allocation.  Our patronage capital allocation from CoBank decreased in 2009 as our total debt outstanding with CoBank decreased.

Revenues

Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues.  In 2010, operating revenues were $31.9 million, or 11.0 percent lower than in 2009.  The decrease was due primarily to lower fuel and purchased power costs recovered in revenue through the fuel surcharge process.

In 2009, operating revenues were $2.0 million, or 0.7 percent higher than in 2008.  The increase was due primarily to higher purchased power costs recovered in revenue through the fuel surcharge process which was partially offset by lower overall base revenue.  The increase was also offset by a decrease in kWh and economy energy sales and a decrease in fuel recovered in revenue through the fuel surcharge process due primarily to lower kWh and economy energy sales.


Overall, retail revenue decreased in 2010 from 2009.  The decrease was due primarily to lower fuel and purchased power costs recovered in revenue through the fuel surcharge process.  Lower kWh sales, which also contributed to the variance was somewhat offset by higher net rates charged to retail customers as a result of the 2008 Test Year Rate Case and September 28, 2010, SRF.

Overall, retail revenue increased in 2009 from 2008.  The increase was due primarily to higher purchased power costs recovered in revenue through the fuel surcharge process due primarily to an increase in MWh purchased and a higher average effective price caused by higher fuel prices, which was partially offset by a decrease in base revenue due to lower kWh sales caused by observed patterns of conservation and implementation of protective measures in response to the threat of volcanic ash fall that continued as additional conservation measures.

Wholesale revenue decreased in 2010 from 2009.  The decrease was due primarily to lower fuel and purchased power costs recovered in revenue through the fuel surcharge process.  Lower kWh sales were somewhat offset by higher net rates charged to wholesale customers as a result of the 2008 Test Year Rate Case and September 28, 2010, SRF.

Wholesale revenue was higher in 2009 from 2008 caused by higher base rates charged to wholesale customers as a result of Chugach’s 2008 Test Year Rate Case and higher purchased power costs recovered in revenue through the fuel surcharge process.  These increases were offset by lower kWh sales caused by conservation and protection measures in response to the threat of volcanic ash fall that continued as additional conservation measures.

Based on the results of fixed and variable cost recovery established in Chugach’s last rate case, wholesale sales to MEA, HEA and Seward contributed approximately $27.2 million, $28.6 million and $27.7 million to Chugach’s fixed costs for the years ended December 31, 2010, 2009 and 2008, respectively.

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, 2010, and 2009.

   
Base Rate Sales Revenue
    
Fuel and Purchased Power Revenue
    
Total Revenue
  
   
2010
    
2009
    
% Variance
    
2010
    
2009
    
% Variance
    
2010
    
2009
    
% Variance
  
                     
 
                                
Retail
                    
 
                                
Residential
   $ 45.5     $ 45.0       1.1 %   $ 26.9     $ 37.3       (27.9 %)   $ 72.4     $ 82.3       (12.0 %)
Small Commercial
   $ 7.5     $ 8.0       (6.3 %)   $ 5.8     $ 7.9       (26.6 %)   $ 13.3     $ 15.9       (16.4 %)
Large Commercial
   $ 28.3     $ 27.8       1.8 %   $ 24.6     $ 34.5       (28.7 %)   $ 52.9     $ 62.3       (15.1 %)
Lighting
   $ 1.3     $ 1.3       0.0 %   $ 0.2     $ 0.3       (33.3 %)   $ 1.5     $ 1.6       (6.3 %)
Total Retail
   $ 82.6     $ 82.1       0.6 %   $ 57.5     $ 80.0       (28.1 %)   $ 140.1     $ 162.1       (13.6 %)
                                                                         
Wholesale
                                                                        
HEA
   $ 11.9     $ 11.8       0.8 %   $ 21.3     $ 31.1       (31.5 %)   $ 33.2     $ 42.9       (22.6 %)
MEA
   $ 21.4     $ 21.9       (2.3 %)   $ 34.5     $ 47.8       (27.8 %)   $ 55.9     $ 69.7       (19.8 %)
SES
   $ 1.4     $ 1.3       7.7 %   $ 2.8     $ 4.4       (36.4 %)   $ 4.2     $ 5.7       (26.3 %)
Total Wholesale
   $ 34.7     $ 35.0       (0.9 %)   $ 58.6     $ 83.3       (29.7 %)   $ 93.3     $ 118.3       (21.1 %)
                                                                         
Economy Sales
   $ 4.0     $ 1.2       233.3 %   $ 18.1     $ 6.1       196.7 %   $ 22.1     $ 7.3       202.7 %
Miscellaneous
   $ 2.8     $ 2.6       7.7 %   $ 0.0     $ 0.0       0.0 %   $ 2.8     $ 2.6       7.7 %
                                                                         
Total Revenue
   $ 124.1     $ 120.9       2.6 %   $ 134.2     $ 169.4       (20.8 %)   $ 258.3     $ 290.3       (11.0 %)


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, 2009, and 2008.

   
Base Rate Sales Revenue
    
Fuel and Purchased Power Revenue
    
Total Revenue
  
   
2009
    
2008
    
% Variance
    
2009
    
2008
    
% Variance
    
2009
    
2008
    
% Variance
  
                     
 
                                
Retail
                    
 
                                
Residential
   $ 45.0     $ 46.4       (3.0 %)   $ 37.3     $ 33.9       10.0 %   $ 82.3     $ 80.3       2.5 %
Small Commercial
   $ 8.0     $ 8.4       (4.8 %)   $ 7.9     $ 7.2       9.7 %   $ 15.9     $ 15.6       1.9 %
Large Commercial
   $ 27.8     $ 28.3       (1.8 %)   $ 34.5     $ 31.8       8.5 %   $ 62.3     $ 60.1       3.7 %
Lighting
   $ 1.3     $ 1.3       0.0 %   $ 0.3     $ 0.2       50.0 %   $ 1.6     $ 1.5       6.7 %
Total Retail
   $ 82.1     $ 84.4       (2.7 %)   $ 80.0     $ 73.1       9.4 %   $ 162.1     $ 157.5       2.9 %
                                                                         
Wholesale
                                                                        
HEA
   $ 11.8     $ 11.4       3.5 %   $ 31.1     $ 29.8       4.4 %   $ 42.9     $ 41.2       4.1 %
MEA
   $ 21.9     $ 20.9       4.8 %   $ 47.8     $ 42.6       12.2 %   $ 69.7     $ 63.5       9.8 %
SES
   $ 1.3     $ 1.1       18.2 %   $ 4.4     $ 3.7       18.9 %   $ 5.7     $ 4.8       18.8 %
Total Wholesale
   $ 35.0     $ 33.4       4.8 %   $ 83.3     $ 76.1       9.5 %   $ 118.3     $ 109.5       8.0 %
                                                                         
Economy Sales
   $ 1.2     $ 4.6       (73.9 %)   $ 6.1     $ 13.9       (56.1 %)   $ 7.3     $ 18.5       (60.5 %)
Miscellaneous
   $ 2.6     $ 2.8       (7.1 %)   $ 0.0     $ 0.0       0.0 %   $ 2.6     $ 2.8       (7.1 %)
                                                                         
Total Revenue
   $ 120.9     $ 125.2       (3.4 %)   $ 169.4     $ 163.1       3.9 %   $ 290.3     $ 288.3       0.7 %
 
The major components of our operating revenue for the year ending December 31 were as follows:

   
2010
    
2010
    
2009
    
2009
    
2008
    
2008
  
   
Sales (MWh)
    
Revenue
    
Sales (MWh)
    
Revenue
    
Sales (MWh)
    
Revenue
  
                                     
Retail
     1,169,430     $ 140,110,304       1,183,705     $ 162,101,007       1,205,832     $ 157,549,359  
Wholesale:
                                                
HEA
     454,223       33,189,789       472,136       42,865,550       517,368       41,133,287  
MEA
     743,212       55,937,931       740,358       69,685,271       742,666       63,500,034  
Seward
     61,651       4,188,989       62,509       5,711,358       63,734       4,798,286  
Total Wholesale
     1,259,086       93,316,709       1,275,003       118,262,179       1,323,768       109,431,607  
Economy energy
     278,093       22,141,341       76,968       7,280,870       256,105       18,526,481  
Other
     N/A       2,756,991       N/A       2,603,252       N/A       2,784,665  
Total
     2,706,609     $ 258,325,345       2,535,676     $ 290,247,308       2,785,705     $ 288,292,112  

Since 1989, we have sold economy (non-firm) energy to GVEA under an agreement that expired on March 31, 2009.  Under that agreement, we used available generation in excess of our own needs to produce electric energy for sale to GVEA, which used that energy to serve its own loads in place of more expensive energy that it would have otherwise generated itself or purchased from other sources. We purchased gas from Marathon to produce energy for sale to GVEA.  Chugach negotiated a three-month gas sales agreement, spanning September through November of 2009, with Marathon, to provide between 5,000 and 7,000 Mcf per day to facilitate a 20 MW economy energy sale to GVEA.  The short-term agreement was extended through December 31, 2009.  On April 6, 2010, Chugach and GVEA finalized an agreement for Chugach to provide a minimum of 20 MW of economy energy to GVEA on a non-firm basis based on an interruptible gas supply arrangement.  The agreement commenced on May 1, 2010, and will continue through March 31, 2013, pending annual commitments from gas suppliers.  The price to GVEA will include the cost of fuel (based on a system average heat rate), plus variable operations and maintenance expense, plus a margin.  Sales will be made under the terms and conditions of Chugach’s economy energy sales tariff.

In 2010, 2009, and 2008, economy sales to GVEA constituted approximately 9 percent, 3 percent, and 6 percent, respectively, of our sales revenues.  Economy energy revenue increased in 2010 from 2009 due to the agreement Chugach finalized with GVEA on April 6, 2010.  Economy energy revenue decreased in 2009 from 2008 due primarily to the expiration of our original agreement with GVEA.


Expenses

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

   
2010
    
2009
    
2008
  
Fuel
   $ 111,718,947     $ 136,416,761     $ 137,894,553  
Power production
     18,248,656       16,406,911       16,718,777  
Purchased power
     26,691,968       35,690,476       31,486,621  
Transmission
     5,697,446       5,709,578       5,841,405  
Distribution
     12,216,252       12,740,381       12,398,832  
Consumer accounts
     5,323,551       5,259,348       5,396,662  
Administrative, general and other
     21,434,273       20,518,688       20,014,239  
Depreciation
     32,636,108       32,130,434       30,829,276  
Total operating expenses
   $ 233,967,201     $ 264,872,577     $ 260,580,365  

Fuel

Chugach recognizes actual fuel expense as incurred.  Fuel expense decreased $24.7 million, or 18.1 percent, in 2010 from 2009 due primarily to a lower average effective fuel price, which was somewhat offset by an increase in Mcf used as a result of higher economy sales.  In 2010, Chugach used 28,908,216 Mcf of fuel at an average effective price of $4.38 per Mcf, which did not include 3,409,580 Mcf of fuel that is recorded as purchased power expense.  Fuel expense decreased $1.5 million, or 1.1 percent, in 2009 from 2008 due primarily to a decrease in Mcf used as a result of lower kWh and economy sales, which was somewhat offset by a higher average effective fuel price.  In 2009, Chugach used 26,139,407 Mcf of fuel at an average effective price of $6.08 per Mcf, which did not include 3,711,074 Mcf of fuel that is recorded as purchased power expense.

Power Production

Power production expense increased $1.8 million, or 11.2 percent, in 2010 from 2009 due primarily to maintenance associated with Beluga unit 6 and Bernice Lake units 3 and 4, which was partially offset by a decrease in maintenance associated with Beluga unit 8.

Power production expense did not materially change in 2009 from 2008.
 
Purchased Power

Purchased power costs decreased $9.0 million, or 25.2 percent, in 2010 from 2009 due primarily to a lower average effective price caused by lower fuel prices.  In 2010, Chugach purchased 504,205 MWh of energy at an average effective price of 5.01 cents per kWh.  Purchased power costs increased $4.2 million, or 13.4 percent, in 2009 from 2008 due primarily to an increase in MWh purchased and a higher average effective price caused by higher fuel prices.  In 2009, Chugach purchased 502,063 MWh of energy at an average effective price of 6.81 cents per kWh.


Transmission

Transmission expense did not materially change in 2010 from 2009 or in 2009 from 2008.

Distribution

Distribution expense did not materially change in 2010 from 2009 or in 2009 from 2008.

Consumer Accounts

Consumer Accounts did not materially change in 2010 from 2009 or in 2009 from 2008.

Administrative, General and Other Charges

Overall, administrative, general and other charges did not materially change in 2010 from 2009, however, an increase in current costs associated with prior workers compensation claims, labor and indirect labor associated with vacation and cash in lieu and the amortization of gas contract negotiations was offset by a decrease in other deductions caused by the write off of obsolete inventory and cancelled projects in 2009.

 Overall, administrative, general and other charges did not materially change in 2009 from 2008, however, an increase in other deductions caused by the write off of obsolete inventory and cancelled projects and an increase in labor was partially offset by a decrease in legal expenses and credit card fees.

Depreciation

Depreciation expense did not materially change in 2010 from 2009.

Depreciation expense increased $1.3 million, or 4.2 percent, in 2009 from 2008 due to a full year of new depreciation rates as a result of Chugach’s 2005 Test Year Rate Case and the closeout of construction projects.

Interest

Interest on long-term obligations decreased $7.8 million, or 38.6 percent, in 2010 from 2009 due to the reclassification of the interest expense associated with the 2001 Series A Bonds, due March 15, 2011, from long-term to short-term.  Interest on long-term obligations decreased $1.2 million, or 5.4 percent, in 2009 from 2008 due primarily to the use of our NRUCFC line of credit to redeem the outstanding principal amount of the 2002 Series B Bonds in March of 2008, resulting in a shift from long-term to short-term interest expense, lower interest rates in 2009 and lower principal balances on our CoBank debt.


Interest on short-term obligations increased $7.6 million, or 723.8 percent, in 2010 from 2009 due primarily to the reclassification of the interest expense associated with the 2001 Series A Bonds, due March 15, 2011 from long-term to short-term and the difference between the use and interest rates of commercial paper in 2010 and the interest associated with the NRUCFC line of credit and the use and interest rates on commercial paper in 2009.  Interest on short-term borrowings decreased $0.6 million, or 37.2 percent, in 2009 from 2008 due primarily to the difference between the balance of the NRUCFC line of credit used in 2008 to redeem the 2002 Series B Bonds and the balance of commercial paper outstanding which was used to pay the balance of the NRUCFC line of credit in 2009.  The decrease is also due to the difference in interest rates between the NRUCFC line of credit in 2008 and the commercial paper interest rates in 2009.  The decreases were slightly offset by a shift from long-term to short-term interest expense described above.

Interest charged to construction increased $407.4 thousand, or 67.8 percent, in 2010 from 2009 due primarily to a higher average balance in Construction Work In Progress, primarily due to capital spending associated with SPP, which was slightly offset by a lower weighted average rate during 2010 of 4.8 percent compared to 4.9 percent during 2009.  Interest charged to construction increased $154.8 thousand, or 34.7 percent, in 2009 from 2008 due primarily to a higher average balance in Construction Work In Progress (CWIP), primarily due to capital spending associated with SPP, which was slightly offset by a lower weighted average rate during 2009 of 4.9 percent compared to 5.1 percent during 2008.

 Patronage Capital (Equity)

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

   
2010
    
2009
    
2008
  
                   
Patronage capital at beginning of year
   $ 144,228,221     $ 142,009,998     $ 138,713,338  
Retirement of capital credits
     (94,278 )     (3,442,125 )     (3,115,090 )
Assignable margins
     5,410,009       5,660,348       6,411,750  
Patronage capital at end of year
     149,543,952       144,228,221       142,009,998  
Other equity1
     12,298,332       12,092,376       11,757,001  
Total equity at end of year
   $ 161,842,284     $ 156,320,597     $ 153,766,999  
1Other equity includes memberships, donated capital and gain on capital credit retirements.

We credit to our members all amounts received from them for the furnishing of electricity in excess of our operating costs, expenses and provision for reasonable reserves.  These excess amounts (i.e., assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by us until such future time as they are retired and returned without interest. Approval of distributions of these amounts to members, also known as capital credits, is at the discretion of our Board.   We currently have a practice of retiring patronage capital on a first-in, first-out basis for retail customers.  The Board may also return capital credits to former members and estates who have requested early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September 2002. Chugach retired $94,278, $3,442,125, and $3,115,090 in capital credits for the years ended December 31, 2010, 2009, and 2008, respectively.  Prior to 2000, wholesale capital credits had been retired on a 10-year cycle pursuant to an approved capital credit retirement program, which was contained in the Chugach business plan.  However, in 2000 we implemented a plan to return the capital credits of wholesale and retail customers on a 15-year rotation. In 2010, no wholesale capital credits were retired.  In 2009 and 2008, $1,674,809 and $1,478,779, respectively, of 1999 and 1998 wholesale capital credits were retired to MEA, HEA and SES pursuant to a prior settlement agreement.


Under the Second Amended and Restated Indenture of Trust, which became effective January 20, 2011, and the Amended and Restated Master Loan Agreement with CoBank, which became effective January 19, 2011, Chugach is prohibited from making any distribution of patronage capital to Chugach’s customers if an event of default under the Amended and Restated Master Loan Agreement exists.  Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5 percent of Chugach’s patronage capital or 50 percent of assignable margins for the prior fiscal year.  This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30 percent of Chugach’s total liabilities and equities and margins.

During 2008 the Board of Directors approved the deferral of capital credit retirements after 2009 due to the construction of new generation and the anticipated loss of wholesale load in 2014.

Changes in Financial Condition

Assets

Total assets increased $61.4 million, or 10.8 percent, from December 31, 2009, to December 31, 2010.  The increase was due in part to a $45.7 million, or 9.9 percent, increase in net utility plant due to extension and replacement of plant in excess of depreciation expense and an increase of $2.1 million, or 752.6 percent, increase in fuel cost under-recovery due to the under collection of fuel and purchased power costs through the fuel surcharge process.  The increase was also caused by a $6.0 million, or 20.0 percent, increase in materials and supplies caused primarily by the purchase of a spare engine associated with SPP and materials for other planned generation projects, an $8.6 million, or 244.5 percent, increase in cash and cash equivalents and a $663.5 thousand, or 52.6 percent increase in prepayments caused primarily by the prepayment of Bradley Lake purchased power for the month of January.  The increase was offset by a $1.1 million, or 4.7 percent, decrease in deferred charges due to the amortization of deferred charges which exceeded the costs associated with financing and commercial paper renewal and a $670.4 thousand, or 1.9 percent, decrease in accounts receivable primarily caused by lower fuel and purchased power costs.

Liabilities

Total liabilities increased by $55.9 million, or 13.6 percent, in 2010 as compared to 2009. Contributors to this change include a $47.0 million, or 91.3 percent, increase in commercial paper outstanding due to the continued construction of the SPP and an $8.6 million, or 84.7 percent, increase in accounts payable primarily caused by the timing of cash payments on invoices for goods and services and capital spending.  Fuel payable increased by $6.9 million, or 47.2 percent, and salaries, wages and benefits payable increased $777.5 thousand, or 13.1 percent, caused by the timing of cash payments on invoices for fuel and labor and benefits, respectively.  Other liabilities increased $637.9 thousand, or 51.7 percent, due primarily to an increase in the municipal underground ordinance payable.  These increases were offset by a $4.1 million, or 9.9 percent, decrease in the net of total long-term obligations and current installments of long-term debt caused by the principal payments on outstanding CoBank debt and a $3.5 million, or 100 percent, decrease in fuel cost over-recovery due to the under-collection of fuel and purchased power costs through the fuel surcharge process.  The increases were also offset by a $249.5 thousand, or 15.4 percent, decrease in deferred credits caused primarily by the transfer of customer advances to construction projects which was somewhat offset by an increase in Chugach’s postretirement benefit obligation.


Equities and Margins

Total margins and equities increased $5.5 million, or 3.5 percent, in 2010 compared to 2009 due primarily to a $5.3 million, or 3.7 percent, net increase in patronage capital ($5.4 million increase in margins coupled with a $0.1 million retirement of capital credits).

Inflation

Chugach is subject to the inflationary trends existing in the general economy.  We do not believe that inflation had a significant effect on our operations in 2010.  Chugach’s gas contracts provide for adjustments to gas prices based on fluctuations of certain commodity prices and indices. Because fuel and purchased power costs are passed directly to our wholesale and retail customers through a fuel surcharge process, fluctuations in the price paid for gas pursuant to long-term gas supply contracts does not significantly affect our operations.

Contractual Obligations and Commercial Commitments

The following are Chugach’s contractual and commercial commitments as of December 31, 2010:
 
Contractual cash obligations – Payments Due By Period

(In thousands)
  
Total
    
2011
       2012-2013       2014-2015    
Thereafter
  
                                   
Long-term debt, including current portion
   $ 307,302     $ 152,852     $ 124,770     $ 4,739     $ 24,941  
Long-term interest expense1
     16,570       10,426       2,287       1,427       2,430  
Commercial Paper2
     98,500       98,500       0       0       0  
Bradley Lake3
     45,048       3,694       7,339       7,326       26,689  
Fuel and fuel transportation expense4
     555,457       140,457       287,000       107,000       21,000  
SPP Contracts5
     220,854       153,758       67,096       0       0  
Capital credit retirements6
     7,500       0       0       3,000       4,500  
Total
   $ 1,251,231     $ 559,687     $ 488,492     $ 123,492     $ 79,560  


1 Long-term interest expense includes fixed and variable rates.  Variable rates are based on rates at December 31, 2010, for years 2011-2015 and thereafter.  (See “Part II – Item 8 – Financial Statements and Supplementary Data – Note (8) Debt.”)
2 At December 31, 2010, Chugach’s Commercial Paper Program was backed by a $300 million Unsecured Credit Agreement between NRUCFC, Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch, which funds capital requirements.  At December 31, 2010, there was $98.5 million of commercial paper outstanding, therefore, the available borrowing capacity under the Commercial Paper Program was $201.5 million and could be used for future operational and capital funding requirements.
3 Estimated annual cost
4 Estimated committed fuel and fuel transportation expense
5 In accordance with contractual commitments associated with SPP
6 Estimated capital credit retirements

Purchase obligations

Chugach is a participant and has a 30.4 percent share in the Bradley Lake hydroelectric project (See “Item 2-Properties-Other Property-Bradley Lake.”)  This contract runs through 2041.  We have agreed to pay a like percentage of annual costs of the project, which has averaged $4.8 million over the past five years.  We believe these costs, adjusted for inflation, reasonably reflect anticipated future project costs.

Our primary sources of natural gas are the Beluga River Field producers and Marathon Oil Company (See “Item 2-Properties-Fuel Supply-Beluga River Field Producers-Marathon Alaska Production.”)  Our fuel costs vary due to the impact of the energy future indices used to index the price of fuel and are inherently difficult to predict. We pass fuel costs directly to our wholesale and retail customers through the fuel surcharge process (See “Item 7-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations-Overview-Rate Regulation and Rates-Fuel Surcharge.”)

Chugach is in the process of developing a natural gas fired generation plant on land currently owned by Chugach near its Anchorage headquarters.  The SPP will be developed and owned jointly with AML&P.  Chugach will own and take 70 percent of the new plant’s output and AML&P will own and take the remaining 30 percent.  Chugach will account for its ownership in the SPP proportionately.  On November 17, 2008, Chugach executed a gas turbine purchase agreement for the purchase of three gas turbines with GEPP.  During 2009 Chugach executed several amendments associated with its purchase agreement with GEPP, which included the purchase of a spare engine for maintenance purposes.  Chugach executed an Owner’s Engineer Services Contract on May 12, 2009.  On January 5, 2010, Chugach executed a Services Contract for the shipment of the combustion turbine generators and related accessories.  On February 25, 2010, Chugach purchased land adjacent to its Anchorage headquarters for the laydown of equipment displaced by the new power plant.  On April 13, 2010, Chugach executed a STG purchase agreement.  On June 18, 2010, Chugach executed an EPC contract with SLCI.  On August 27, 2010, Chugach executed an OTSG equipment contract with IST.  Chugach amended the contract for transportation of combustion turbine generators on September 28, 2010, to include transportation of the steam turbine generator.  On December 20, 2010, Chugach received a construction permit from the Alaska Department of Environmental Conservation allowing the project to begin construction in spring of 2011.  On March 15, 2011, Chugach received its initial building permit from the Municipality of Anchorage.  Chugach made payments of $74.3 in 2010 and $25.0 million in 2009, with additional payments of $153.7 million expected in 2011, pursuant to all these contracts.


Liquidity And Capital Resources

We ended 2010 with $12.1 million of cash and cash equivalents, up from $3.5 and $7.5 million at December 31, 2009 and 2008, respectively.  Cash equivalents consist of all highly liquid debt instruments with a maturity of three months or less when purchased and an Overnight Repurchase Agreement with First National Bank Alaska (FNBA).

The following table summarizes our cash flows from operating, investing and financing activities for the periods ended December 31, 2010.

   
2010
    
2009
    
2008
  
Total cash provided by (used in):
                  
                   
Operating activities
   $ 41,124,009     $ 42,409,427     $ 23,651,941  
Investing activities
     (74,875,800 )     (38,100,312 )     (30,276,605 )
Financing activities
     42,318,739       (8,296,652 )     7,906,030  
                         
Increase (decrease) in cash and cash equivalents
   $ 8,566,948     $ (3,987,537 )   $ 1,281,366  

Operating activities in 2010 were primarily impacted by changes in fuel cost over and under recovery, materials and supplies, fuel and other liabilities.  In 2009, changes included fuel cost over and under recovery, materials and supplies and fuel.  In 2008, changes included accounts receivable, fuel cost over and under recovery, deferred charges, accounts payable and fuel.

Investing activities in 2010 and 2009 were primarily impacted by expenditures associated with the SPP.

Financing activities in 2010, 2009 and 2008 were primarily impacted by changes in the amount of commercial paper used to finance expenditures associated with the SPP and the retirement of patronage capital and estate payments.

Sources of Liquidity

Chugach has satisfied its operational and capital cash requirements through internally generated funds, a $50 million line of credit from NRUCFC and a $300 million Commercial Paper Program.  At December 31, 2010, there was no outstanding balance on our NRUCFC line of credit and $98.5 million of outstanding commercial paper.  Thus, at December 31, 2010, our available borrowing capacity under our line of credit was $50 million and our available commercial paper capacity was $201.5 million.

Over the next two years, Chugach anticipates financing increased capital expenditures due to the construction of a natural gas fired generation plant and on-going capital needs.  Commercial paper is being issued and will act as a bridge until Chugach converts commercial paper balances to long term debt.  On November 17, 2010, Chugach replaced the $300 million unsecured Credit Agreement executed on October 10, 2008, which was due to expire on October 10, 2011.  The 2010 Credit Agreement with National Rural Utilities Cooperative Finance Corporation (NRUCFC), Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch, will expire on November 17, 2013.  The Credit Agreement is used to back Chugach’s Commercial Paper program, which will act as a bridge until Chugach converts commercial paper balances to long-term debt. The 2010 Credit Agreement was priced with an all-in drawn spread of one month LIBOR plus 150 basis points, along with a 25 basis points facility fee (based on an A-/A3 unsecured debt rating).


Our commercial paper can be repriced between one day and two hundred and seventy days.  The following table provides information regarding monthly average commercial paper balances outstanding (dollars in millions), as well as corresponding weighted average interest rates:

Month
  
Average Balance
  
Weighted Average Interest Rate
January 2010
  
54.2
  
0.26
February 2010
  
57.1
  
0.26
March 2010
  
60.2
  
0.27
April 2010
  
59.8
  
0.28
May 2010
  
59.0
  
0.32
June 2010
  
58.7
  
0.37
July 2010
  
58.6
  
0.33
August 2010
  
60.8
  
0.33
September 2010
  
67.6
  
0.31
October 2010
  
71.4
  
0.31
November 2010
  
77.4
  
0.30
December 2010
  
87.5
  
0.31

Chugach had a term loan facility with CoBank.  Loans made under that facility were evidenced by promissory notes governed by a Master Loan Agreement, which became effective on January 22, 2003.  On January 19, 2011, Chugach and CoBank amended and restated the existing Master Loan Agreement.  The existing loans from CoBank are now governed by the Amended and Restated Master Loan Agreement dated January 19, 2011, evidenced by a promissory note dated January 19, 2011, and secured by the Second Amended and Restated Indenture of Trust dated January 20, 2011.  At December 31, 2010, Chugach had $37.3 million outstanding with CoBank.

Under the Second Amended and Restated Indenture of Trust, additional obligations may be sold by Chugach upon the basis of bondable additions and the retirement or defeasance of or principal payments on previously outstanding obligations.  The beginning balance of bondable additions on January 20, 2011 was $322.2 million, which would support the issuance of additional debt of approximately $293 million.  Chugach’s ability to sell additional debt obligations will be dependent on the market’s perception of Chugach’s financial condition and credit rating, and Chugach’s continuing compliance with the financial covenants, including the rate covenant, contained in the Second Amended and Restated Indenture of Trust and its other credit documents.  No assurance can be given that Chugach will be able to sell additional debt obligations even if otherwise permitted under the Second Amended and Restated Indenture of Trust.


Financing

On January 21, 2011, Chugach issued $90,000,000 of First Mortgage Bonds, 2011 Series A, due March 15, 2031 and $185,000,000 of First Mortgage Bonds, 2011 Series A, due March 15, 2041 for the purpose of refinancing the 2001 and 2002 Series A Bonds due March 15, 2011, and February 1, 2012, respectively, and for general corporate purposes. The 2011 Series A Bonds due March 15, 2031, will bear interest at 4.20% per annum, payable semi-annually on March 15 and September 15 of each year commencing on September 15, 2011.  Principal on the 2011 Series A Bonds due March 15, 2031 will be paid in equal annual installments beginning March 15, 2012, resulting in an average life of approximately 10 years.  The 2011 Series A Bonds due March 15, 2041, will bear interest at 4.75% per annum, payable semi-annually on March 15 and September 15 of each year commencing on September 15, 2011.  Principal on the 2011 Series A Bonds due March 15, 2041 will be paid in equal annual installments beginning March 15, 2012, resulting in an average life of approximately 15.5 years.  The bonds and all other long-term debt obligations of Chugach are secured by a lien on substantially all of Chugach’s assets, as set forth in the Second Amended and Restated Indenture of Trust, which became effective January 20, 2011.

Principal maturities of our outstanding indebtedness, including commercial paper, at December 31, 2010 are set forth below:

Year Ending
December 31
  
Principal Maturities
  
       
2011
   $ 251,351,500  
2012
     122,693,543  
2013
     2,076,355  
2014
     2,266,145  
2015
     2,473,110  
Thereafter
     24,941,165  
    $ 405,801,818  

During 2010 we spent approximately $74.9 million on capital-construction projects, net of reimbursements, which includes interest capitalized during construction.  We develop five-year capital improvement plans that are updated every year. Our capital improvement requirements are based on long-range plans and other supporting studies and are executed through the five-year capital improvement program.

Set forth below is an estimate of capital expenditures for the years 2011 through 2015 as contained in the Capital Improvement Plan (CIP), which was approved by the board on October 27, 2010:

Year
  
Estimated Expenditures
2011
  
$166.3 million
2012
  
$83.6 million
2013
  
$26.1 million
2014    $32.1 million
2015
  
$15.3 million


We expect that cash flows from operations and external funding sources, including our available lines of credit and commercial paper program, will be sufficient to cover future operational and capital funding requirements.

Outlook

Constructing a new, highly efficient power generation facility, managing natural gas contracts, securing low cost financing and replacement revenue sources for wholesale customer loads that will be leaving in 2014, all while controlling operating expenses to minimize adverse customer rate impacts, are some of the challenges Chugach has faced and will continue to face in the near and intermediate term.  These issues, along with emerging energy issues and plans at the state level, will shape how Chugach proceeds into the future.

Chugach has partnered with AML&P to construct and jointly own a new 183 MW natural gas fired power plant.  Chugach will own and take 70 percent of the new plant’s output and AML&P will own and take the remaining 30 percent.  The plant is scheduled to be placed into service in 2012. Currently, major components have been ordered, engineering is moving forward and initial construction permits allowing the project to begin construction in the spring of 2011 have been received. Chugach’s interim financing for the plant will come from a commercial paper borrowing program that was initially established via a $300 million unsecured credit agreement in 2008 and refinanced in 2010.

Chugach will continue to explore all potential sources of long term financing to include federal, state, private placement and the public markets to obtain the lowest cost financing available for our capital additions that are expected to continue in 2011.

Chugach currently has fuel contracts in place to fill 100 percent of Chugach’s unmet needs through December 2013, approximately 50 percent of Chugach’s unmet needs through December 2014, approximately 60 percent in 2015 and approximately 29 percent in 2016.  The State of Alaska Department of Natural Resources (DNR) completed a preliminary engineering and geological evaluation of the remaining Cook Inlet gas reserves in December of 2009.  The study identified 863 billion cubic feet (BCF) of proven, developed, producing reserves, additional probable reserves of 279 BCF and an additional increment of 353 BCF in high-confidence pay intervals.  Combined, these 1.5 trillion cubic feet of gas reserves are similar to the 1.4 trillion cubic feet of gas reserves identified in a 2004 study undertaken by the Department of Energy in 2004.  Given current demand and deliverability, DNR estimates at minimum a 10-year supply of gas exists in currently producing leases.  DNR does note that economic considerations will play a major role in whether producers continue drilling and development activities to meet demand.  Chugach has been working closely with the state and producers to develop a comprehensive Cook Inlet management plan that will meet this goal.  Chugach continues to explore its options for future fuel supply needs by working with developers on commercial terms for natural gas storage and the state of Alaska on energy policies to promote gas development in Cook Inlet and other in-state gas options such as the North Slope Pipeline, Spur Line or Bullet line to Southcentral Alaska.  Chugach is also evaluating LNG storage and import options as transition gas until in-state gas options are developed.


In 2010 the Alaska Legislature passed legislation House Bill 280 and Senate Bill 309 (HB280 and SB309) providing incentives (including tax credits) intended to spur exploration and development of natural gas and oil in Cook Inlet.  It is too early to know just how successful the bills will be in achieving their intended purposes.  The legislation does underscore the point that legislators are paying close attention to Cook Inlet natural gas issues.

Chugach and other utilities have a need for gas storage.  A storage facility will provide a place for gas to flow to during times of lower demand and flow from as customer demand rises.  Cook Inlet Natural Gas Storage Alaska (CINGSA) is a project to develop a gas storage facility using a depleted underground reservoir.  The facility will have an initial storage capacity of 11 bcf so that local utilities, including Chugach, will have gas available to meet deliverability requirements during peak periods.  Chugach's share of the initial capacity is 2.3 bcf. Injections into the facility are expected to begin in the spring of 2012 and withdrawals of gas are expected to begin in the winter of 2012.  Chugach is entitled to withdraw gas a rate of up to 35 MMcf per day.  On December 17, 2010, the RCA approved a certificate of public convenience and necessity for the natural gas storage facility.

Notification was made by MEA in 2004 and by HEA in 2007 that neither organization intends to be on the Chugach system under the current contractual arrangements post 2014.  This would result in a loss of approximately 50 percent of Chugach’s power sales load and approximately 40 percent of the utility’s annual sales revenue.  On April 13, 2010, HEA issued a press release stating that HEA’s solely-owned power generation and transmission entity, AEEC, approved a design engineer to complete design for the Nikiski generation conversion project. AEEC currently owns a 40 MW natural gas fired generation plant that is dispatched as part of Chugach’s overall system.  The conversion project entails adding a steam turbine and increasing the output of the plant to 77 MW.  HEA intends to purchase all of the output from this unit upon expiration of the Chugach contract in 2013.  Chugach is currently negotiating with HEA for generation and transmission reserves necessary to meet the balance of HEA’s power requirements.  Negotiations with MEA were also ongoing throughout 2010 and are anticipated to continue into 2011.  While financial management plan scenarios indicate Chugach can sustain operations and meet financial covenants in the event these two customers leave the system, the remaining customers will have to shoulder the burden imposed by the remaining costs and will likely face higher rates.  Chugach, however, is continuing to pursue replacement sources of revenue through potential new firm power sales agreements and transmission wheeling and ancillary services tariff revisions.  We believe that successful implementation of new power sales agreements and revised tariffs will mitigate anticipated rate increases in the 2014 and 2015 timeframe.  However, we cannot assure that we will be able to replace sources of revenue or that any replacement of revenue sources or revised tariffs will fully mitigate any anticipated rate increases in this timeframe.

A State of Alaska Energy Policy was amended to include legislature intent that the state achieve a 15 percent increase in energy efficiency on a per capita basis between 2010 and 2020; receive 50 percent of its electric generation from renewable and alternative energy sources by 2025, work to ensure a reliable in-state gas supply for residents of the state, the state power project fund serve as the main source of state assistance for energy projects, remain a leader in petroleum and natural gas production and become a leader in renewable and alternative energy development.

Chugach is coordinating with other parties, including the State of Alaska, private developers and other utilities in the planning and potential development of renewable energy resources.  The proposed operating and capital budgets released by the state on December 15, 2010, included strong backing for energy activities.  The budget contained $65.7 million for the Alaska Energy Authority to conduct planning, design and permitting for a major hydro project on the Susitna River.  The proposed project could provide up to half the electric energy needed in the Railbelt.  In November of 2010, the AEA released a decision document concluding that Susitna should be considered the primary hydroelectric project for the region.  Chugach will work with AEA and other parties on this effort.  Other potential renewable resources that Chugach is actively exploring with developers include Mt. Spurr Geothermal being proposed by Ormat Technologies, Inc., landfill gas, wind power and a potential waste-to-energy project in Anchorage.  Other potential projects include wind power developments in the HEA and GVEA service areas.


Five Railbelt electric utilities have joined together to create a new organization that will help plan, construct and operate key components of the regional electric grid.  The organization, Alaska Railbelt Cooperative Transmission and Electric Company (ARCTEC), is a generation and transmission cooperative organized under existing state law.  Chugach, GVEA, HEA, MEA and SES organized the G&T to provide a framework for collective action on projects of mutual benefit.  Each of the organizations has two seats on the 10-member board of directors.  Another advantage of ARCTEC is its ability to prioritize capital project requests and speak with a unified regional voice at the state capitol.  ARCTEC was incorporated on December 23, 2010.

Off-Balance Sheet Arrangements

We have not created, and are not party to, any special-purpose or off-balance-sheet entities for the purpose of raising capital, incurring debt or operating parts of our business that are not consolidated into our financial statements.  We do not have any arrangements or relationships with entities that are not consolidated into our financial statements that are reasonably likely to materially affect our liquidity or the availability of our capital resources.

Critical Accounting Policies

Our accounting and reporting policies comply with U.S. generally accepted accounting principles (GAAP).  The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and reported amounts of assets and liabilities in the financial statements.  Significant accounting policies are described in Note 1 to the financial statements (See “Item 8 -Financial Statements and Supplementary Data.”). Critical accounting policies are those policies that management believes are the most important to the portrayal of Chugach's financial condition and results of its operations, and require management's most difficult, subjective, or complex judgments, often as a result of the need to make estimates about matters that are inherently uncertain. Most accounting policies are not considered by management to be critical accounting policies.  Several factors are considered in determining whether or not a policy is critical in the preparation of financial statements.  These factors include, among other things, whether the estimates are significant to the financial statements, the nature of the estimates, the ability to readily validate the estimates with other information including third parties or available prices, and sensitivity of the estimates to changes in economic conditions and whether alternative accounting methods may be utilized under GAAP.  For all of these policies management cautions that future events rarely develop exactly as forecast, and the best estimates routinely require adjustment.  Management has discussed the development and the selection of critical accounting policies with Chugach's Audit Committee. The following policies are considered to be critical accounting policies for the year ended December 31, 2010.


Electric Utility Regulation

Chugach is subject to regulation by the RCA. The RCA sets the rates Chugach is permitted to charge customers based on our specific allowable costs. As a result, Chugach applies FASB ASC 980, “Topic 980 – Regulated Operations.”  Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of FASB ASC 980 has a further effect on Chugach's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by Chugach; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and post-retirement benefits have less of a direct impact on Chugach's results of operations than they would on a non-regulated company. As reflected in the financial statements (See “Item 8 -Financial Statements and Supplementary Data – Note 1k – Deferred Charges and Credits”), significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines. However, adverse legislation and judicial or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact Chugach’s financial statements.

Unbilled revenue

Chugach calculates unbilled retail revenue at the end of each month to ensure the recognition of a full month’s revenue.  Chugach estimates calendar-month unbilled sales based on billing cycle sales, billing cycle read dates, weather and hours of darkness to produce an estimate of calendar sales.  This estimate of calendar sales is then calibrated to deliveries measured at Chugach distribution substations, net of losses.  Until September of 2008, calendar unbilled revenue was determined by multiplying kWh sales by an average rate.  Beginning in September of 2008, Chugach fully implemented an unbilled estimate based on respective billing class determinants to produce an estimate of calendar month revenue.  Chugach accrued $8,612,454 and $9,417,906 of unbilled retail revenue at December 31, 2010 and 2009, respectively.

Allowance for Doubtful Accounts

We maintain an allowance for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We base our estimates on the aging of our accounts receivable balances, historical bad debt reserves, historical percent of retail revenue that has been deemed uncollectible, our collections process and regulatory requirements.  If the financial condition of our customers were to deteriorate resulting in an impairment of their ability to make payments, additional allowances may be required.  If their financial condition improves, allowances may be reduced.  Such allowance changes could have a material effect on our consolidated financial condition and results of operations.


New Accounting Standards

ASC Update 2010-29 “Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations (a consensus of the FASB Emerging Issues Task Force)
 
In December 2010, the FASB issued ASC Update 2010-29, “Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations (a consensus of the FASB Emerging Issues Task Force).”  ASC Update 2010-29 clarifies the pro forma information disclosure requirements of public entities that enter into business combinations that are material on an individual or aggregate basis.  This update is effective for the first annual reporting period beginning on or after December 15, 2010.  Chugach will begin application of ASC 2010-29 on January 1, 2011, which is not expected to have any effect on results of operations, financial position, and cash flows.

ASC Update 2010-06 “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements”

In January 2010, the FASB issued ASC Update 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.”  ASC Update 2010-06 applies to all entities that are required to make disclosures about recurring or nonrecurring fair value measurements and expands the disclosures required based on the measurement Level.  This update is effective for the first reporting period (including interim periods) beginning after December 15, 2009, except for certain Level 3 transactions.  Those transaction disclosure requirements are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years.  Chugach began application of ASC Update 2010-06 to the financial statements for the period ended March 31, 2010, which did not have a material effect on our results of operations, financial position, and cash flows.  Chugach will begin application of the Level 3 transaction disclosures on January 1, 2011, which is not expected to have any effect on results of operations, financial position and cash flows.

SFAS 167 “Amendments to FASB Interpretation No. 46(R)”

In June 2009, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 167, “Amendments to FASB Interpretation No. 46(R).”  SFAS No. 167 applies to all entities except for those identified in FASB Interpretation No. (FIN) 46(R), “Consolidation of Variable Interest Entities,” as well as entities previously considered qualifying special-purpose entities, as the concept of these entities was eliminated by SFAS No. 166, “Accounting for Transfers of Financial Assets.”  SFAS No. 167 amends FIN 46(R) to require additional disclosures regarding an entity’s involvement in variable interest entities.  SFAS No. 167 is effective for interim and annual reporting periods beginning after November 15, 2009.  Chugach began application of SFAS No. 167 on January 1, 2010, which did not have any effect on our results of operations, financial position, and cash flows.

In December 2009, the FASB issued ASC Update 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” an adaptation of SFAS No. 167 into the Codification.  To view the adapted content, see FASB ASC 810-10-30, for the Initial Measurement Section of Subtopic 10, and FASB ASC 810-10-65, for the Transition and Open Effective Date Information Section of Subtopic 810-10.  The update did not have any effect on our results of operations, financial position and cash flows.


SFAS 166 “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140”

In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140.”  SFAS No. 166 applies to all entities and amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 140 was amended to enhance the disclosure requirements as well as to define some of the terms and measurements to be used, by removing the concept of a qualifying special-purpose entity and the exception from applying FIN 46, “Consolidation of Variable Interest Entities,” to qualifying special-purpose entities.  SFAS No. 166 is effective for interim and annual reporting periods beginning after November 15, 2009.  Chugach began application of SFAS No. 166 on January 1, 2010, which did not have any effect on our results of operations, financial position, and cash flows.

In December 2009, the FASB issued ASC Update 2009-16,”Accounting for Transfers of Financial Assets,” an adaptation of SFAS No. 166 into the Codification.  To view the adapted content, see FASB ASC 860-10-40, for the Derecognition Section of Subtopic 10, and FASB ASC 860-10-65, for the Transition and Open Effective Date Information of Subtopic 860-10.  The update did not have any effect on our results of operations, financial position and cash flows.
 
FAS 164 “Not-for-Profit Entities: Mergers and Acquisitions – Including an amendment of FASB Statement No. 142”

In April 2009, the FASB issued SFAS No. 164, “Not-for-Profit Entities: Mergers and Acquisitions – Including an amendment of FASB Statement No. 142.”  SFAS No. 164 applies to the combination of not-for-profit entities meeting the definition of a merger or acquisition, with specific exceptions.  SFAS No. 164 provides guidance on the accounting and disclosure of these combinations.  SFAS No. 164 is effective for annual reporting periods beginning after December 15, 2009.  Chugach began application of SFAS No. 164 on January 1, 2010, which did not have any effect on our results of operations, financial position, and cash flows.

In January 2010, the FASB issued ASC Update 2010-07, “Not-for-Profit Entities (Topic 958): Not-for-Profit Entities: Mergers and Acquisitions,” an adaptation of SFAS No. 164 into the Codification. To view the adapted content, see FASB ASC 954-805 for the Business Combinations Subtopic of Topic 954, FASB ASC 958-805 for the Business Combinations Subtopic of 958, FASB ASC 805-10-15 for the Scope and Scope Exceptions Section of Subtopic 805-10, FASB ASC 805-50-15 for the Scope and Scope Exceptions Section of Subtopic 805-50, and FASB ASC 350-10-65 for the Transition and Open Effective Date Information Section of Subtopic 350-10.


Item 7A - Quantitative and Qualitative Disclosures About Market Risk

Chugach is exposed to a variety of risks, including changes in interest rates and changes in commodity prices due to repricing mechanisms inherent in gas supply contracts.  In the normal course of our business, we manage our exposure to these risks as described below.  We do not engage in trading market risk-sensitive instruments for speculative purposes.

Interest Rate Risk
 
At December 31, 2010, our short- and long- term debt was comprised of our 2001 and 2002 Series A Bonds, promissory notes owed to CoBank and outstanding commercial paper.

The interest rates of our 2001 and 2002 Series A Bonds are fixed at 6.55 and 6.20 percent, respectively, per annum.  At December 31, 2010, we had $270 million of 2001 and 2002 Series A Bonds outstanding.  The fair value at December 31, 2010, was $278.1 million.

Chugach is exposed to market risk from changes in interest rates associated with our other credit facilities.  Our credit facilities’ interest rates may be reset due to fluctuations in a market-based index, such as the London Interbank Offered Rate (LIBOR) or the base rate or prime rate of our lenders.  A 100 basis-point change rise in interest rates would increase our interest expense by approximately $1.4 million, and a 100 basis point decline in interest rates would decrease our interest expense by approximately $678.4 thousand, based on $135.8 million of variable rate debt outstanding at December 31, 2010.
 
Commodity Price Risk

Chugach’s gas contracts provide for adjustments to gas prices based on fluctuations of certain commodity prices and indices.  Because fuel and purchased power costs are passed directly to our wholesale and retail customers through a fuel surcharge process, fluctuations in the price paid for gas pursuant to gas supply contracts does not normally impact margins.


Item 8 – Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm
 
The Board of Directors
Chugach Electric Association, Inc.
 
We have audited the accompanying balance sheets of Chugach Electric Association, Inc. as of December 31, 2010 and 2009, and the related statements of operations, changes in equities and margins, and cash flows for each of the years in the three-year period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Chugach Electric Association, Inc. as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.
 
/s/ KPMG, LLP

March 30, 2011
Anchorage, Alaska


Chugach Electric Association, Inc.
Balance Sheets
December 31, 2010 and 2009

Assets
  
2010
    
2009
  
             
Utility Plant (notes 1d, 3, 10 and 11):
            
Electric plant in service
   $ 853,933,739     $ 834,467,734  
                 
Construction work in progress
     100,787,482       48,383,610  
Total utility plant
     954,721,221       882,851,344  
                 
Less accumulated depreciation
     (446,582,318 )     (420,464,808 )
Net utility plant
     508,138,903       462,386,536  
                 
Other property and investments, at cost:
                
Nonutility property
     84,735       24,461  
                 
Special Funds
     395,833       345,792  
                 
Investments in associated organizations (note 4)
     12,163,097       12,333,936  
Total other property and investments
     12,643,665       12,704,189  
                 
Current assets:
                
Cash and cash equivalents, including repurchase agreements of $12,008,821 in 2010 and $3,026,893 in 2009
     12,070,713       3,503,765  
                 
Special deposits
     211,858       125,037  
                 
Fuel cost under-recovery (note 1n)
     2,371,631       278,164  
                 
Accounts receivable, less provision for doubtful accounts of $307,169 in 2010 and $397,815 in 2009
     35,140,119       35,810,543  
                 
Materials and supplies
     35,974,170       29,990,618  
                 
Prepayments
     1,925,424       1,261,897  
                 
Other current assets
     256,290       246,380  
Total current assets
     87,950,205       71,216,404  
                 
Deferred charges, net (notes 5 and 12)
     20,994,955       22,037,407  
                 
Total assets
   $ 629,727,728     $ 568,344,536  


Chugach Electric Association, Inc.
Balance Sheets (continued)
December 31, 2010 and 2009

Liabilities, Equities and Margins
  
2010
    
2009
  
             
Equities and margins (notes 6 and 7):
            
             
Memberships
   $ 1,474,869     $ 1,432,054  
                 
Patronage capital
     149,543,952       144,228,221  
                 
Other
     10,823,463       10,660,322  
Total equities and margins
     161,842,284       156,320,597  
                 
Long-term obligations, excluding current installments (note 8):
          
                 
Bonds payable
     270,000,000       270,000,000  
                 
National Bank for Cooperatives bonds payable
     34,450,318       37,301,819  
                 
Total long-term obligations
     304,450,318       307,301,819  
                 
Current liabilities:
                
                 
Current installments of long-term obligations (note 8)
     2,851,500       4,118,028  
                 
Commercial Paper
     98,500,000       51,500,000  
                 
Accounts payable
     18,860,926       10,212,105  
                 
Consumer deposits
     5,225,729       5,492,950  
                 
Fuel cost over-recovery (note 1n)
     0       3,511,422  
                 
Accrued interest
     6,049,531       6,067,630  
                 
Salaries, wages and benefits
     6,733,842       5,956,320  
                 
Fuel
     21,569,538       14,658,058  
                 
Other current liabilities
     1,872,314       1,234,371  
Total current liabilities
     161,663,380       102,750,884  
                 
Deferred compensation
     395,833       345,792  
                 
Deferred credits (note 5)
     1,375,913       1,625,444  
                 
Total liabilities, equities and margins
   $ 629,727,728     $ 568,344,536  
 
See accompanying notes to financial statements.


Chugach Electric Association, Inc.
Statements of Operations
Years Ended December 31, 2010, 2009 and 2008

   
2010
    
2009
    
2008
  
Operating revenues (notes 1m, 2 and 12)
   $ 258,325,345     $ 290,247,308     $ 288,292,112  
                         
Operating expenses:
                        
                         
Fuel (note 12)
     111,718,947       136,416,761       137,894,553  
                         
Power production
     18,248,656       16,406,911       16,718,777  
                         
Purchased power
     26,691,968       35,690,476       31,486,621  
                         
Transmission
     5,697,446       5,709,578       5,841,405  
                         
Distribution
     12,216,252       12,740,381       12,398,832  
                         
Consumer accounts
     5,323,551       5,259,348       5,396,662  
                         
Administrative, general and other charges
     21,434,273       20,518,688       20,014,239  
                         
Depreciation
     32,636,108       32,130,434       30,829,276  
                         
Total operating expenses
     233,967,201       264,872,577       260,580,365  
                         
Interest expense:
                        
                         
Long-term debt and other
     21,014,387       21,207,600       22,979,276  
                         
Charged to construction
     (1,008,689 )     (601,251 )     (446,479 )
                         
Interest expense, net
     20,005,698       20,606,349       22,532,797  
                         
Net operating margins
     4,352,446       4,768,382       5,178,950  
                         
Nonoperating margins:
                        
                         
Interest income
     310,964       250,958       553,362  
                         
Allowance for Funds Used During Construction
     83,966       145,281       112,611  
                         
Capital credits, patronage dividends and other
     662,633       495,727       566,827  
                         
Total nonoperating margins
     1,057,563       891,966       1,232,800  
                         
Assignable margins
   $ 5,410,009     $ 5,660,348     $ 6,411,750  

See accompanying notes to financial statements.
 


Chugach Electric Association, Inc.
Statements of Changes in Equities and Margins
Years Ended December 31, 2010, 2009 and 2008

 
   
Memberships
    
Other Equities and Margins
    
Patronage Capital
    
Total
  
Balance, January 1, 2008
   $ 1,345,013     $ 9,252,085     $ 138,713,338     $ 149,310,436  
                                 
Assignable margins
     0       0       6,411,750       6,411,750  
Retirement of capital credits
     0       0       (3,115,090 )     (3,115,090 )
Unclaimed capital credit retirements
     0       963,133       0       963,133  
Memberships and donations received
     45,400       151,370       0       196,770  
                                 
Balance, December 31, 2008
     1,390,413       10,366,588       142,009,998       153,766,999  
                                 
Assignable margins
     0       0       5,660,348       5,660,348  
Retirement of capital credits
     0       0       (3,442,125 )     (3,442,125 )
Unclaimed capital credit retirements
     0       213,527       0       213,527  
Memberships and donations received
     41,641       80,207       0       121,848  
                                 
Balance, December 31, 2009
     1,432,054       10,660,322       144,228,221       156,320,597  
                                 
Assignable margins
     0       0       5,410,009       5,410,009  
Retirement of capital credits
     0       0       (94,278 )     (94,278 )
Unclaimed capital credit retirements
     0       90,320       0       90,320  
Memberships and donations received
     42,815       72,821       0       115,636  
                                 
Balance, December 31, 2010
   $ 1,474,869     $ 10,823,463     $ 149,543,952     $ 161,842,284  

 
See accompanying notes to financial statements.


Chugach Electric Association, Inc.
Statements of Cash Flows
Years Ended December 31, 2010, 2009 and 2008

Cash flows from operating activities:
  
2010
    
2009
    
2008
  
Assignable margins
   $ 5,410,009     $ 5,660,348     $ 6,411,750  
                         
Adjustments to reconcile assignable margins to net cash provided by operating activities:
                  
Depreciation
     32,636,108       32,130,434       30,829,276  
Amortization and depreciation cleared to operating expenses
     5,457,480       4,755,265       5,029,029  
Allowance for funds used during construction
     (83,966 )     (145,281 )     (112,611 )
Property losses, net / other
     74,726       (121,417 )     (182,159 )
Write-off of inventory, deferred charges and projects
     210,596       1,461,349       18,000  
                         
Changes in assets and liabilities:
                        
(Increase) decrease in assets:
                        
Accounts receivable
     670,424       35,367       (2,427,101 )
Fuel cost under-recovery
     (2,093,467 )     11,509,914       (11,788,078 )
Materials and supplies
     (6,061,005 )     (1,407,931 )     (384,553 )
Prepayments/Other assets
     (448,456 )     298,537       (183,715 )
Deferred charges
     (1,511,639 )     (2,522,027 )     (6,640,741 )
                         
Increase (decrease) in liabilities:
                        
Accounts payable
     339,929       169,466       (1,673,495 )
Consumer deposits/Other liabilities
     2,434,124       515,513       758,655  
Fuel cost over-recovery
     (3,511,422 )     3,511,422       (1,596,010 )
Accrued interest
     (18,099 )     (91,297 )     (145,682 )
Salaries, wages and benefits
     777,522       474,699       (472,252 )
Fuel
     6,911,480       (13,836,153 )     6,156,558  
Deferred credits
     (70,335 )     11,219       55,070  
Net cash provided by operating activities
     41,124,009       42,409,427       23,651,941  
                         
Investing activities:
                        
Extension and replacement of plant
     (74,875,800 )     (38,100,312 )     (30,276,605 )
Net cash used in investing activities
     (74,875,800 )     (38,100,312 )     (30,276,605 )
                         
Financing activities:
                        
Payments of notes payable
     0       (2,860,000 )     0  
Payments for debt issue costs
     (1,493,572 )     0       0  
Proceeds from short-term obligations
     47,000,000       66,998,000       7,500,000  
Proceeds from long-term obligations
     0       0       38,560,006  
Repayments of short-term obligations
     0       (22,998,000 )     0  
Repayments of long-term obligations
     (4,118,029 )     (47,367,312 )     (35,303,151 )
Memberships and donations received
     205,956       21,624       70,761  
Retirement of patronage capital and estate payments
     (146,596 )     (3,022,246 )     (4,027,156 )
Net receipts of consumer advances for construction
     870,980       931,282       1,105,570  
Net cash provided by (used in) financing activities
     42,318,739       (8,296,652 )     7,906,030  
                         
Net changes in cash and cash equivalents
     8,566,948       (3,987,537 )     1,281,366  
                         
Cash and cash equivalents at beginning of period
   $ 3,503,765     $ 7,491,302     $ 6,209,936  
                         
Cash and cash equivalents at end of period
   $ 12,070,713     $ 3,503,765     $ 7,491,302  
                         
Supplemental disclosure of non-cash investing and financing activities
                        
Retirement of plant (net of salvage)
   $ 6,666,875     $ 991,011     $ 9,027,644  
Notes payable on land
   $ 0     $ 0     $ 2,860,000  
Extension and replacement of plant included in accounts payable
   $ 14,054,396     $ 5,712,404     $ 2,656,989  
Non-cash capital credit retirements
   $ 0     $ 331,987     $ 1,089,142  
Patronage capital retired and estate payments included in other current liabilities
   $ 388,463     $ 503,237     $ 415,345  
Supplemental disclosure of cash flow information – interest expense paid, including amounts capitalized
   $ 19,173,013     $ 19,710,442     $ 21,536,503  

See accompanying notes to financial statements.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(1)
Description of Business and Significant Accounting Policies

a. Description of Business

Chugach Electric Association, Inc. (Chugach) is the largest electric utility in Alaska.  Chugach is engaged in the generation, transmission and distribution of electricity to directly serve retail customers in the Anchorage and upper Kenai Peninsula areas.  Through an interconnected regional electrical system, Chugach's power flows 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.

Chugach also supplies much of the power requirements of three wholesale customers, Matanuska Electric Association, Inc. (MEA), Homer Electric Association, Inc. (HEA) and the City of Seward (Seward).  Chugach’s retail and wholesale members are the consumers of the electricity sold.

Chugach operates on a not-for-profit basis and, accordingly, seeks only to generate revenues sufficient to pay operating and maintenance costs, the cost of purchased power, capital expenditures, depreciation, and principal and interest on all indebtedness and to provide for reserves.  Chugach is subject to the regulatory authority of the Regulatory Commission of Alaska (RCA).

b. Management Estimates

In preparing the financial statements in conformity with generally accepted accounting principles, management of Chugach is required to make estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the balance sheet and revenues and expenses for the reporting period.  Estimates include allowance for doubtful accounts, deferred charges and credits, unbilled revenue and the estimated useful life of utility plant.  Actual results could differ from those estimates.
 
c. Regulation

The accounting records of Chugach conform to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission (FERC).  Chugach meets the criteria, and accordingly, follows the accounting and reporting requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 980, “Topic 980 - Regulated Operations.”

FASB ASC 980 provides for the recognition of regulatory assets and liabilities as allowed by regulators for costs or credits that are reflected in current rates or are considered probable of being included in future rates.  Our regulated rates are established to recover all 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.  The regulatory assets or liabilities are then reduced as the cost or credit is reflected in earnings.  See Note (1k) – “Deferred Charges and Credits.”


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

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

d. Utility Plant and Depreciation

Additions to electric plant in service are recorded at original cost of contracted services, direct labor and materials, indirect overhead charges and capitalized interest.  For property replaced or retired, the book value of the property, plus removal cost, less salvage, is charged to accumulated depreciation.  Renewals and betterments are capitalized, while maintenance and repairs are normally charged to expense as incurred.

In accordance with FASB ASC 360, “Topic 360 – Property, Plant, and Equipment,” certain utility plant is reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable in rates.  Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset.  If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.

Depreciation and amortization rates have been applied on a straight-line basis and at December 31 are as follows:
 
Annual Depreciation Rate Ranges

 
01/01/05
-
05/31/08
  
06/01/08
-
10/31/10
  
11/01/10
-
12/31/10
                       
Steam production plant
2.55%
-
3.24%
  
4.45%
-
5.85%
  
4.81%
-
7.04%
Hydraulic production plant
1.63%
-
3.00%
  
1.22%
-
3.00%
  
1.06%
-
3.00%
Other production plant
3.32%
-
9.81%
  
3.77%
-
10.56%
  
3.98%
-
10.15%
Transmission plant
1.72%
-
5.26%
  
1.61%
-
6.67%
  
1.58%
-
7.86%
Distribution plant
2.10%
-
9.98%
  
1.95%
-
9.77%
  
2.17%
-
9.63%
General plant
2.23%
-
27.25%
  
1.25%
-
26.11%
  
1.57%
-
20.00%
Other
2.75%
-
2.75%
  
2.75%
-
2.75%
  
2.75%
-
2.75%

On November 1, 2010, the RCA approved revised depreciation rates effective November 1, 2010. See Note (2) – “Regulatory Matters – Revision to Current Depreciation Rates (Docket U-09-097).”  Chugach’s depreciation rates include a provision for cost of removal. Given that the estimated timing and amount cannot be reasonably estimated, Chugach does not record a separate liability for its obligation associated with the retirement of plant.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

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

e. Capitalized Interest

Allowance for funds used during construction (AFUDC) and interest charged to construction - credit (IDC) are the estimated costs of the funds used during the period of construction from both equity and borrowed funds.  AFUDC and IDC are applied to specific projects during construction.  AFUDC and IDC uses the net cost of borrowed funds and a rate of return on member’s equity when used and is recovered through rates as utility plant is depreciated.  Chugach capitalized such funds at the weighted average rate (adjusted monthly) of 4.8 percent during 2010, 4.9 percent during 2009 and 5.1 percent during 2008.  Chugach capitalized actual interest expense and related fees associated with the construction of the Southcentral Power Project (SPP).

f. Investments in Associated Organizations

The loan agreements with CoBank, ACB (CoBank) and National Rural Utilities Cooperative Finance Corporation (NRUCFC) require as a condition of the extension of credit, that an equity ownership position be established by all borrowers.  Chugach’s equity ownership in these organizations is less than 1 percent.  These investments are non-marketable and accounted for at cost.  Management evaluates these investments annually for impairment.  No impairment was recorded during 2010, 2009 and 2008.

g. Fair Value of Financial Instruments

FASB ASC 825, “Topic 825 – Financial Instruments,” requires disclosure of the fair value of certain on and off balance sheet financial instruments for which it is practicable to estimate that value.  The following methods are used to estimate the fair value of financial instruments:

Cash and cash equivalents - the carrying amount approximates fair value because of the short maturity of those instruments.

Consumer deposits - the carrying amount approximates fair value because of the short refunding term.

Long-term obligations - the fair value is estimated based on the quoted market price for same or similar issues (note 8).

Deferred compensation – the fair value is based on the quoted market price for identical instruments traded in active exchange markets.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

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

h. Cash and Cash Equivalents

For purposes of the statement of cash flows, Chugach considers all highly liquid instruments with a maturity of three months or less upon acquisition by Chugach to be cash equivalents.  Chugach has an Overnight Repurchase Agreement with First National Bank Alaska (FNBA).  Each day the balance is invested by FNBA and Chugach receives varying interest rates for our investment pursuant to our Overnight Purchase Agreement.  The Overnight Repurchase Agreement account had an average balance in 2010 and 2009 of $5,092,665 and $4,103,891, at an average interest rate of 0.14 percent and 0.17 percent, respectively.

i. Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount.  The allowance for doubtful accounts is management’s best estimate of the amount of probable credit losses in existing accounts receivable.  Chugach determines the allowance based on its historical write-off experience and current economic conditions.  Chugach reviews its allowance for doubtful accounts monthly.  Past due balances over 90 days in a specified amount are reviewed individually for collectability.  All other balances are reviewed in aggregate.  Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.  Chugach does not have any off–balance-sheet credit exposure related to its customers.

j. Materials and Supplies

Materials and supplies are stated at average cost.

k. Deferred Charges and Credits

In accordance with FASB ASC 980, Chugach’s financial statements reflect regulatory assets and liabilities.  Continued accounting under FASB ASC 980, requires that certain criteria be met.  We capitalize all or part of costs that would otherwise be charged to expense if it is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for ratemaking purposes and future revenue will be provided to permit recovery of the previously incurred cost.  Management believes Chugach’s operations currently satisfy these criteria.  Chugach regulatory asset recoveries are embedded in base rates approved by the RCA.  Specific costs incurred and recorded as Regulatory Assets, including the amortization period for recovery, are approved by the RCA either in standard SRFs, general rate case filings or specified independent requests.  The rates approved related to the regulatory assets are matched to the amortization of actual expenditures recognized on the books. The regulatory assets are amortized and collected through rates over differing periods depending upon the period of benefit as established by the RCA.   Deferred credits, primarily representing regulatory liabilities, are amortized to operating expense over the period allowed for ratemaking purposes.  It also includes refundable contributions in aid of construction, which are credited to the associated cost of construction of property units.  Refundable contributions in aid of construction are held in deferred credits pending their return or other disposition.  If events or circumstances


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

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

k. Deferred Charges and Credits (continued)

should change so the criteria are not met, the write off of regulatory assets and liabilities could have a material effect on Chugach’s financial position or results of operations.

l. Patronage Capital

 
Revenues in excess of current period costs (net operating margins and nonoperating margins) in any year are designated on Chugach's statement of revenues and expenses as assignable margins. These excess amounts (i.e. assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by Chugach until such future time as they are retired and returned without interest at the discretion of the Board of Directors.  Retained assignable margins are designated on Chugach's balance sheet as patronage capital.  This patronage capital constitutes the principal equity of Chugach.  The Board of Directors may also approve the return of capital to former members and estates who request early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September 2002.

m. Operating Revenues

Revenues are recognized upon delivery of electricity.  Operating revenues are based on billing rates authorized by the RCA, which are applied to customers' usage of electricity.  Chugach’s rates are established, in part, on test period sales levels that reflect actual operating results.  Chugach calculates unbilled revenue at the end of each month to ensure the recognition of a calendar year’s revenue.  Chugach accrued $8,612,454 and $9,417,906 of unbilled retail revenue at December 31, 2010 and 2009, respectively. Wholesale revenue is recorded from metered locations on a calendar month basis, so no accrual is made.  Chugach's tariffs include provisions for the recovery of gas costs according to gas supply contracts, as well as purchased power costs.

n. Fuel and Purchased Power Costs Recovery

Expenses associated with electric services include fuel used to generate electricity and power purchased from others.  Chugach is authorized by the RCA to recover fuel and purchased power costs through the fuel surcharge process, which is adjusted quarterly to reflect increases and decreases of such costs.  We recognize differences between projected recoverable fuel costs and amounts actually recovered through rates.  The fuel cost under/over recovery on our Balance Sheet represents the net accumulation of any under or over collection of fuel and purchase power costs.  Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods.  Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods.  Fuel costs were under-recovered by $2,371,631 in 2010 and over-recovered by $3,233,258 in 2009.  Total fuel and purchased power costs in 2010, 2009, and 2008 were $138,410,915, $172,107,237, and $169,381,174, respectively.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

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

o. Environmental Remediation Costs

Chugach accrues for losses and establishes a liability associated with environmental remediation obligations when such losses are probable and can be reasonably estimated.  Such accruals are adjusted as further information develops or circumstances change.   Estimates of future costs for environmental remediation obligations are not discounted to their present value. However, various remediation costs may be recoverable through rates and accounted for as a regulatory asset.

p. Income Taxes

Chugach is exempt from federal income taxes under the provisions of Section 501(c)(12) of the Internal Revenue Code and for the years ended December 31, 2010, 2009 and 2008 was in compliance with that provision.  In addition, as described in “Note (12) - Commitments, Contingencies and Concentrations,” Chugach collects sales tax and is assessed gross receipts and excise taxes which are presented on a net basis in accordance with FASB ASC 605-45-50, “Topic 605 - Revenue Recognition – Subtopic 45 - Principal Agent Considerations – Section 50 - Disclosure.”

Chugach applies a more-likely-than-not recognition threshold for all tax uncertainties.  FASB ASC 740 only allows the recognition of those tax benefits that have a greater than fifty percent likelihood of being sustained upon examination by the taxing authorities.  Chugach’s management reviewed Chugach’s tax positions and determined there were no outstanding, or retroactive tax positions, that were not highly certain of being sustained upon examination by the taxing authorities.

Management has concluded that there are no significant uncertain tax positions requiring recognition in its financial statements for all periods presented. Chugach’s evaluation was performed for the tax periods ended December 31, 2006 through December 31, 2010 for U.S. Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2010.

q. Consumer deposits

Consumer deposits are the amounts certain customers are required to deposit to receive electric service.  Consumer deposits for the years ended December 31, 2010 and 2009, totaled $2.1 million and $2.4 million, respectively.  Consumer deposits also represent customer credit balances as a result of prepaid accounts.  Credit balances for the years ended December 31, 2010 and 2009 totaled $3.1 million and $3.0 million, respectively.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

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

r. Recently Issued Accounting Pronouncements

ASC Update 2010-29 “Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations (a consensus of the FASB Emerging Issues Task Force)

In December 2010, the FASB issued ASC Update 2010-29, “Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations (a consensus of the FASB Emerging Issues Task Force).”  ASC Update 2010-29 clarifies the pro forma information disclosure requirements of public entities that enter into business combinations that are material on an individual or aggregate basis.  This update is effective for the first annual reporting period beginning on or after December 15, 2010.  Chugach will begin application of ASC 2010-29 on January 1, 2011, which is not expected to have any effect on results of operations, financial position, and cash flows.

ASC Update 2010-06 “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements”

In January 2010, the FASB issued ASC Update 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.”  ASC Update 2010-06 applies to all entities that are required to make disclosures about recurring or nonrecurring fair value measurements and expands the disclosures required based on the measurement Level.  This update is effective for the first reporting period (including interim periods) beginning after December 15, 2009, except for certain Level 3 transactions.  Those transaction disclosure requirements are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years.  Chugach began application of ASC Update 2010-06 to the financial statements for the period ended March 31, 2010, which did not have a material effect on our results of operations, financial position, and cash flows.  Chugach will begin application of the Level 3 transaction disclosures on January 1, 2011, which is not expected to have any effect on results of operations, financial position and cash flows.

SFAS 167 “Amendments to FASB Interpretation No. 46(R)”

In June 2009, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 167, “Amendments to FASB Interpretation No. 46(R).”  SFAS No. 167 applies to all entities except for those identified in FIN 46(R), “Consolidation of Variable Interest Entities,” as well as entities previously considered qualifying special-purpose entities, as the concept of these entities was eliminated by SFAS No. 166, “Accounting for Transfers of Financial Assets.”  SFAS No. 167 amends FIN 46(R) to require additional disclosures regarding an entity’s involvement in variable interest entities.  SFAS No. 167 is effective for interim and annual reporting periods beginning after November 15, 2009.  Chugach began application of SFAS No. 167 on January 1, 2010, which did not have any effect on our results of operations, financial position, and cash flows.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

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

r. Recently Issued Accounting Pronouncements (continued)

In December 2009, the FASB issued ASC Update 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” an adaptation of SFAS No. 167 into the Codification.  To view the adapted content, see FASB ASC 810-10-30, for the Initial Measurement Section of Subtopic 10, and FASB ASC 810-10-65, for the Transition and Open Effective Date Information Section of Subtopic 810-10.  The update did not have any effect on our results of operations, financial position, and cash flows.

SFAS 166 “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140”

In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140.”  SFAS No. 166 applies to all entities and amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 140 was amended to enhance the disclosure requirements as well as to define some of the terms and measurements to be used, by removing the concept of a qualifying special-purpose entity and the exception from applying FIN 46, “Consolidation of Variable Interest Entities,” to qualifying special-purpose entities.  SFAS No. 166 is effective for interim and annual reporting periods beginning after November 15, 2009.  Chugach began application of SFAS No. 166 on January 1, 2010, which did not have any effect on our results of operations, financial position, and cash flows.

In December 2009, the FASB issued ASC Update 2009-16,”Accounting for Transfers of Financial Assets,” an adaptation of SFAS No. 166 into the Codification.  To view the adapted content, see FASB ASC 860-10-40, for the Derecognition Section of Subtopic 10, and FASB ASC 860-10-65, for the Transition and Open Effective Date Information of Subtopic 860-10.  The update did not have any effect on our results of operations, financial position, and cash flows.
 
FAS 164 “Not-for-Profit Entities: Mergers and Acquisitions – Including an amendment of FASB Statement No. 142”

In April 2009, the FASB issued SFAS No. 164, “Not-for-Profit Entities: Mergers and Acquisitions – Including an amendment of FASB Statement No. 142.”  SFAS No. 164 applies to the combination of not-for-profit entities meeting the definition of a merger or acquisition, with specific exceptions.  SFAS No. 164 provides guidance on the accounting and disclosure of these combinations.  SFAS No. 164 is effective for annual reporting periods beginning after December 15, 2009.  Chugach began application of SFAS No. 164 on January 1, 2010, which did not have any effect on our results of operations, financial position, and cash flows.

In January 2010, the FASB issued ASC Update 2010-07, “Not-for-Profit Entities (Topic 958): Not-for-Profit Entities: Mergers and Acquisitions,” an adaptation of SFAS No. 164 into the Codification. To view the adapted content, see FASB ASC 954-805 for the Business Combinations Subtopic of Topic 954, FASB ASC 958-805 for the Business Combinations Subtopic of 958, FASB ASC 805-10-15 for the Scope and Scope Exceptions Section of Subtopic 805-10, FASB ASC 805-50-15 for the Scope and Scope Exceptions Section of Subtopic 805-50, and FASB ASC 350-10-65 for the Transition and Open Effective Date Information Section of Subtopic 350-10.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

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

s. Fair Values of Assets and Liabilities

Fair Value Hierarchy

In accordance with FASB ASC 820, Chugach groups its financial assets and liabilities measured at fair value in three levels, based on the markets in which the assets and liabilities are traded and the reliability of the assumptions used to determine fair value.  These levels are:

Level 1 – Valuation is based upon quoted prices for identical instruments traded in active exchange markets, such as the New York Stock Exchange.  Level 1 also includes U.S. Treasury and federal agency securities, which are traded by dealers or brokers in active markets.  Valuations are obtained from readily available pricing sources for market transactions involving identical assets or liabilities.

Level 2 – Valuation is based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-based valuation techniques for which all significant assumptions are observable in the market.

Level 3 – Valuation is generated from model-based techniques that use significant assumptions not observable in the market.  These unobservable assumptions reflect Chugach’s estimates of assumptions that market participants would use in pricing the asset or liability.  Valuation techniques include use of option pricing models, discounted cash flow models and similar techniques.

The table below presents the balance of Chugach’s non-qualified deferred compensation plan and Overnight Repurchase Agreement assets measured at fair value on a recurring basis at December 31, 2010, and December 31, 2009.

   
Total
    
Level 1
    
Level 2
    
Level 3
  
December 31, 2010
                        
Deferred compensation
   $ 395,833     $ 395,833     $ 0     $ 0  
Repurchase agreement
   $ 12,008,821     $ 0     $ 12,008,821     $ 0  
                                 
December 31, 2009
                                
Deferred compensation
   $ 345,792     $ 345,792     $ 0     $ 0  
Repurchase agreement
   $ 3,026,893     $ 0     $ 3,026,893     $ 0  

Chugach had no Level 3 assets or liabilities measured at fair value on a recurring basis.  Fair value estimates are dependent upon subjective assumptions and involve significant uncertainties resulting in variability in estimates with changes in assumptions.  The fair value of long-term debt has been determined using discounted future cash flows at borrowing rates currently available to Chugach.  The fair value of cash and cash equivalents, accounts receivable and payable, and other short-term monetary assets and liabilities approximate carrying value due to their short-term nature.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

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

t. Presentation of Financial Information

For the year ended December 31, 2010, Chugach recorded a reclassification to more accurately present accounts receivable and consumer deposits for the year ended December 31, 2009.  The reclassification represents customer credit balances as a result of prepaid accounts previously included as a reduction to accounts receivable and now included as consumer deposits.  The impact was to increase accounts receivable and consumer deposits by $3.0 million in 2009.

For the year ended December 31, 2010, Chugach recorded a reclassification to present the amount of capitalized interest previously included as a reduction of cash provided by operating activities and now included as an increase of cash used in investing activities.  The impact was to increase cash provided by operating activities and increase cash used in investing activities by $601,251 in 2009 and $446,479 in 2008.

(2) 
Regulatory Matters

2008 Test Year General Rate Case (Docket U-09-080)

On June 23, 2009, Chugach filed a general rate case with the RCA to increase base rate revenue by $4.2 million, with increases of $2.7 million to Chugach retail customers and $1.5 million to wholesale customers.  Base rates charged to retail customers increased 3.3 percent and base rates charged to wholesale customers HEA, MEA and Seward increased 7.8 percent, 2.0 percent and 9.7 percent, respectively.

The RCA named the Attorney General and Chugach’s wholesale customers HEA, MEA and Seward parties to the docket.

On October 9, 2009, the RCA granted Chugach’s original request that the proposed rates go into effect on an interim and refundable basis.  On October 15, 2009, the RCA consolidated Docket U-09-080 (General Rate Case) and Docket U-09-097 (Depreciation Study Update, explained below).

Chugach reached a settlement with its wholesale customers, HEA, MEA and Seward, which resolved issues in both the general rate case and the depreciation study update.  The settlement, along with a request to vacate schedule, was filed with the RCA on May 21, 2010.  On June 2, 2010, the RCA granted the request to vacate schedule.  A final order in the consolidated case is explained below.

Revision to Current Depreciation Rates (Docket U-09-097)

In accordance with a stipulation with its wholesale customers, HEA and MEA, Chugach filed on August 31, 2009, an updated depreciation study based on plant balances as of December 31, 2008. The RCA opened Docket U-09-097 to consider Chugach’s updated depreciation study.  The RCA named Chugach’s wholesale customers HEA, MEA and Seward parties to the docket.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(2)
Regulatory Matters (continued)

Revision to Current Depreciation Rates (Docket U-09-097) (continued)

As indicated in the discussion under the 2008 Test Year General Rate Case above, the RCA consolidated the depreciation study update with the general rate case.  A hearing was held in June of 2010, which addressed unresolved depreciation issues between Chugach and the Attorney General, who acts as the public advocate on behalf of rate payers in RCA cases.

On September 16, 2010, the RCA issued a final order in the consolidated case (2008 Test Year General Rate Case and Revision to Current Depreciation Rates), accepting the settlements with its wholesale customers, HEA, MEA and Seward and resolving depreciation issues disputed by the Attorney General, which resulted in no change to the depreciation rates contained in the settlement agreements.

On September 28, 2010, Chugach filed revised tariffs in compliance with the settlement agreements, refund calculations, and a plan for refunding its customers the difference between the amounts paid under the interim and refundable rates and the amounts established by the settlement agreements.  As a result of the RCA accepting the settlement agreements and resolving depreciation issues, Chugach refunded its wholesale and retail customers approximately $0.7 million, including interest.

On November 1, 2010, the RCA materially accepted Chugach’s compliance filing.  Base rate changes were approved effective November 1, 2010.

Request for Participation in the Simplified Rate Filing Process

On December 15, 2009, Chugach submitted a request to the RCA for approval to implement the Simplified Rate Filing (SRF) process for the adjustment of base energy and demand rates in accordance with Alaska Statute 42.05.381(e).  Chugach requested that base rate adjustments under SRF be completed on a semi-annual basis, utilizing the twelve months ended June and December as the test periods in each year.  Chugach requested that its initial SRF be submitted on the June 2010 test year for rate adjustments, if necessary, during fourth quarter, 2010.

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.  Utilization of SRF will allow Chugach to more efficiently adjust base rates in response to lower sales resulting from both energy conservation and technological improvements.  Chugach is also interested in SRF as a means to expedite the rate adjustment process with the goal of timely cost recovery and lower adjudicatory costs.

On April 21, 2010, the RCA opened docket U-10-20 to consider Chugach’s request to implement the simplified rate filing process.  A technical conference was held on June 1, 2010, to discuss guidelines that Chugach should follow in future simplified rate filings.  All parties agreed to modify the deadline for a final order to July 26, 2010.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(2)
Regulatory Matters (continued)

Request for Participation in the Simplified Rate Filing Process (continued)

A public hearing was held on July 19, 2010.  The parties to the docket entered into a stipulation on the outstanding issues in the case and the RCA issued a bench order at the hearing approving the stipulation.  A formal written order was issued on July 26, 2010.

On September 28, 2010, Chugach filed its initial filing under this process to decrease base rate revenue by $0.2 million, with increases of 0.2 percent to Chugach retail customers and 0.3 percent to Seward and decreases of 0.6 percent and 1.2 percent to HEA and MEA, respectively.  The RCA approved Chugach’s Simplified Rate Filing on November 4, 2010, for base rate changes effective November 15, 2010.

Natural Gas Contract Submittal

On April 2, 2010, Chugach submitted a new long-term natural gas supply contract with Marathon Alaska Production, LLC (MAP), to the RCA.  The new MAP contract will provide gas beginning April 1, 2011, terminating March 31, 2013.  MAP has two contract extension options that can be exercised during the first year of the initial contract.  MAP extended the contract to December 31, 2013, by exercising the first contract extension on January 12, 2011.  The second contract option could be exercised by December 31, 2011, and would extend the contract through December 31, 2014.  The total amount of gas under contract is estimated at 26 billion cubic feet (BCF) for the initial two year term of the contract with volumetric and delivery terms to be determined for each contract extension period that could provide up to an additional 16 BCF through December 31, 2014.  The RCA approved the gas supply contract effective May 17, 2010.

Net Metering Regulations

On June 16, 2010, regulations establishing net metering requirements for certain electric utilities became effective.  Net metering allows a customer to install and use certain types of renewable generation to offset their monthly usage and sell excess power to their serving utility at the utility’s avoided generation cost.  The net metering requirements adopted by the RCA apply to Chugach and nine other Alaska electric utilities.  The RCA’s order limits customer generation to units up to 25 kilowatts and installations must comply with approved interconnection standards.  Chugach has approved interconnection standards and non-firm buy-back rates in its tariff.  On June 17, 2010, Chugach filed with the RCA the final summary tariff necessary to implement net metering.  The RCA approved the tariff effective August 2, 2010.

Southcentral Power Project (SPP)

On June 30, 2010, Chugach filed a petition with the RCA for advance determination of decisional prudence and assurance of cost recovery for the Southcentral Power Project.  The petition requested regulatory assurance of future recovery in rates of the contract amounts Chugach has already executed.  Recovery would begin after an appropriate rate proceeding is completed such that recovery of SPP costs begin coincident with the date the SPP goes into service.  Chugach


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(2)
Regulatory Matters (continued)

Southcentral Power Project (SPP)(continued)

determined that substantial benefit could flow to our members if certain advance regulatory approvals were obtained to provide additional assurances to potential lenders. Public hearings were held in September of 2010.  On October 5, 2010, the RCA concluded that Chugach may include in future rates $197 million in costs attributable to three principal contracts to build the SPP when the plant becomes used and useful.  The RCA found that “it is in the public interest to provide cost recovery assurance” to Chugach regarding these costs.  Chugach’s share of the project cost is estimated to be $256 million, as budgeted.  Chugach will request approval of the additional costs associated with the project in a future general rate case that is expected to be filed in 2012.

(3)
Utility Plant

Major classes of utility plant as of December 31 are as follows:

Electric plant in service:
  
2010
    
2009
  
Steam production plant
   $ 60,462,671     $ 60,462,671  
Hydraulic production plant
     20,402,466       20,315,628  
Other production plant
     134,400,210       132,645,379  
Transmission plant
     248,084,767       247,810,006  
Distribution plant
     249,408,094       242,798,640  
General plant
     49,275,336       47,756,148  
Unclassified electric plant in service1
     80,498,560       71,053,056  
Intangible plant
     4,710,912       4,710,912  
Other
     6,690,723       6,915,294  
Total electric plant in service
     853,933,739       834,467,734  
Construction work in progress 2
     100,787,482       48,383,610  
Total electric plant in service and construction work in progress
   $ 954,721,221     $ 882,851,344  

1Unclassified electric plant in service consists of complete unclassified general plant, generation plant, transmission plant and distribution plant.  Depreciation of unclassified electric plant in service has been included in functional plant depreciation accounts in accordance with the anticipated eventual classification of the plant investment.  Intangible plant represents Chugach's share of a Bradley Lake transmission line financed internally.  Other represents Electric Plant Held for Future Use.

2The amount associated with the construction of the SPP included in construction work in progress was $84.9 and $26.5 million at December 31, 2010 and 2009, respectively.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(4)
Investments in Associated Organizations

Investments in associated organizations include the following at December 31:

   
2010
    
2009
  
National Rural Utilities Cooperative Finance Corporation
   $ 6,095,980     $ 6,095,980  
CoBank, ACB
     6,003,555       6,174,680  
NRUCFC capital term certificates / Other
     63,562       63,276  
Total Investments in Associated Organizations
   $ 12,163,097     $ 12,333,936  

The Farm Credit Administration, CoBank's federal regulators, requires minimum capital adequacy standards for all Farm Credit System institutions.  Loan agreements and financing arrangements with CoBank and NRUCFC require, as a condition of the extension of credit, that an equity ownership position be established by all borrowers.

(5)
Deferred Charges and Credits

Deferred Charges

Deferred charges, or regulatory assets, net of amortization, consisted of the following at December 31:

   
2010
    
2009
  
Debt issuance and reacquisition costs
   $ 2,851,601     $ 3,439,420  
Refurbishment of transmission equipment
     160,495       169,754  
Feasibility Studies
     334,853       111,121  
Beluga Gas Compression
     3,053,198       3,772,461  
Cooper Lake Relicensing / projects
     6,052,811       6,119,493  
Fuel supply negotiations
     1,467,986       1,587,238  
Major overhaul of steam generating unit
     3,020,092       3,775,114  
Other regulatory deferred charges
     2,757,644       1,721,180  
Environmental matters and other
     1,296,275       1,341,626  
Total deferred charges
   $ 20,994,955     $ 22,037,407  


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(5)
Deferred Charges and Credits (continued)

Deferred Charges (continued)

Deferred charges, or regulatory assets, not currently being recovered in rates charged to consumers, consisted of the following at December 31, 2010 and 2009:

   
2010
    
2009
  
Fuel supply negotiations
   $ 203,231     $ 1,444,789  
Studies/Other
     334,853       111,122  
Cooper Lake Unit 1 Major Overhaul
     1,356,489       1,053,269  
Cooper Lake Relicensing
     491,091       438,380  
Rate case costs
     0       14,315  
Financing costs
     350,380       0  
Total deferred charges
   $ 2,736,044     $ 3,061,875  

We believe all regulatory assets not currently being recovered in rates charged to consumers are probable of recovery in the future based upon prior recovery of similar costs allowed by our regulator.  The recovery of regulatory assets is requested in SRF rate adjustments filed with the RCA on a semi-annual basis. In most cases, deferred charges are recovered over the life of the underlying asset.

 
Deferred Credits

Deferred credits, or regulatory liabilities, at December 31 consisted of the following:
 
   
2010
    
2009
  
Refundable consumer advances for construction
   $ 447,025     $ 857,322  
Estimated initial installation costs for meters
     89,208       120,185  
Post retirement benefit obligation
     824,700       593,600  
Other
     14,980       54,337  
Total deferred credits
   $ 1,375,913     $ 1,625,444  


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(6)
Patronage Capital

Chugach has a Board approved capital credit retirement policy, which is contained in Chugach’s Financial Management Plan.  This establishes, in general, a plan to return the capital credits of wholesale and retail customers based on the members’ proportionate contribution to Chugach’s assignable margins.  At December 31, 2010, Chugach had $149,543,952 of patronage capital (net of capital credits retired in 2010), which included $144,133,943 of patronage capital that had been assigned and $5,410,009 of patronage capital to be assigned to its members.  Approval of actual capital credit retirements is at the discretion of Chugach's Board of Directors.  Chugach records a liability when the retirements are approved by the Board of Directors. The Second Amended and Restated Indenture of Trust and the CoBank Amended and Restated Master Loan Agreement prohibit Chugach from making any distribution of patronage capital to Chugach’s customers if an event of default under the Second Amended and Restated Indenture of Trust or CoBank Amended and Restated Master Loan Agreement exists.  Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5 percent of Chugach’s patronage capital or 50 percent of assignable margins for the prior fiscal year.  This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30 percent of Chugach’s total liabilities and equities and margins.

Capital credits retired were $94,278, $3,442,125, and $3,115,090 for the years ended December 31, 2010, 2009, and 2008, respectively.  The outstanding liability for capital credits authorized but not paid was $388,463 and $503,237 at December 31, 2010 and 2009, respectively.

 
During 2008, the Board of Directors approved the deferral of capital credit retirements after 2009 due to the construction of new generation and the anticipated loss of wholesale load in 2014.

(7)
Other Equities

A summary of other equities at December 31 follows:

   
2010
    
2009
  
Nonoperating margins, prior to 1967
   $ 23,625     $ 23,625  
Donated capital
     1,453,305       1,380,484  
Unclaimed capital credit retirement1
     9,346,533       9,256,213  
Total other equities
   $ 10,823,463     $ 10,660,322  

1Represents unclaimed capital credits that have met all requirements of section 34.45.200 of Alaska’s unclaimed property law and has therefore reverted to Chugach.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(8)
Debt

Long-term obligations at December 31 are as follows:
  
2010
    
2009
  
CoBank 2, 5.50% fixed rate note matured in 2010, with interest and principal payable monthly
   $ 0     $ 1,500,000  
                 
CoBank 3 and 4, 2.61% variable rate notes maturing in 2022, with interest payable monthly and principal due annually beginning in 2003
     35,402,290       36,999,447  
                 
CoBank 5, 2.61% variable rate note maturing in 2012, with interest and principal payable monthly
     1,899,528       2,920,400  
                 
2001 Series A Bond of 6.55%, maturing in 2011, with interest payable semi-annually March 15 and September 15
     150,000,000       150,000,000  
                 
2002 Series A Bond of 6.20%, maturing in 2012, with interest payable semi-annually February 1 and August 1
     120,000,000       120,000,000  
Total long-term obligations
   $ 307,301,818     $ 311,419,847  
                 
Less current installments
     2,851,500       4,118,028  
                 
Long-term obligations, excluding current installments
   $ 304,450,318     $ 307,301,819  

Covenants

Chugach was required to comply with all covenants set forth in the Amended and Restated Indenture, dated April 1, 2001, and effective January 22, 2003.  Effective January 20, 2011, Chugach is required to comply with all covenants set forth in the Second Amended and Restated Indenture of Trust that now secures the 2011 Series A Bonds and the 2011 promissory note to CoBank, which has replaced the outstanding CoBank 3, 4 and 5 promissory notes.

Chugach was also required to comply with the Master Loan Agreement between Chugach and CoBank dated December 27, 2002, which governed the outstanding CoBank 3, 4 and 5 promissory notes. On January 19, 2011, CoBank and Chugach replaced the CoBank 3, 4 and 5 promissory notes with a promissory note that is governed by the Amended and Restated Master Loan Agreement, which is now secured by the Second Amended and Restated Indenture of Trust dated January 20, 2011.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(8)
Debt (continued)

Covenants (continued)

Chugach is also required to comply with the 2010 Credit Agreement, between Chugach and NRUCFC, Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch dated November 17, 2010, governing loans and extensions of credit associated with Chugach’s commercial paper program, in an aggregate principal amount not exceeding $300 million at any one time outstanding.

Chugach is also required to comply with other covenants set forth in the Revolving Line of Credit Agreement with NRUCFC and the Reimbursement and Indemnity Agreement with MBIA Insurance Corporation, relating to Chugach’s outstanding 2001 Series A and 2002 Series A bonds.

Security

Under the Amended and Restated Indenture of Trust, Chugach was prohibited from creating or permitting to exist any mortgage, lien, pledge, security interest or encumbrance on Chugach’s properties and assets (other than those arising by operation of law) to secure the repayment of borrowed money or the obligation to pay the deferred purchase price of property unless Chugach equally and ratably secured the Bonds subject to the Amended and Restated Indenture, except that Chugach was permitted to incur secured indebtedness in an amount not to exceed $5 million or enter into sale and leaseback or similar agreements.

On January 20, 2011, Chugach and the indenture trustee entered into a Second Amended and Restated Indenture of Trust (the Indenture) imposing a lien on substantially all of Chugach’s assets to secure Chugach’s long-term debt obligations.  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 U.S. 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.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(8)
Debt (continued)

 
Rates

Under the Amended and Restated Indenture of Trust, dated April 1, 2001, Chugach was required, subject to any necessary regulatory approval, to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense.  If there occurred any material change in the circumstances contemplated at the time rates were most recently reviewed, the Amended and Restated Indenture required Chugach to seek appropriate adjustment to those rates so that they would generate revenues reasonably expected to yield margins for interest equal to at least 1.10 times interest charges.

The Second Amended and Restated Indenture of Trust, which became effective on January 20, 2011, also requires Chugach, subject to any necessary regulatory approval, to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense.  If there occurs any material change in the circumstances contemplated at the time rates were most recently reviewed, the Second Amended and Restated Indenture of Trust requires Chugach to seek appropriate adjustment to those rates so that they would generate revenues reasonably expected to yield margins for interest equal to a least 1.10 times interest charges, provided, however, upon review of rates based on a material change in circumstances, rates are required to be revised in order to comply and there are less than six calendar months remaining in the current fiscal year, Chugach can revise its rates so as to reasonably expect to meet the covenant for the next succeeding twelve-month period after the date of any such revision.

The old CoBank Master Loan Agreement also required Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense.  The Amended and Restated Master Loan Agreement with CoBank, which became effective on January 19, 2011, did not change this requirement.

The NRUCFC Revolving Line of Credit Agreement requires Chugach to maintain an average Times Interest Earned Ratio (TIER) of not less than 1.10.

The 2010 Credit Agreement governing the unsecured facility providing liquidity for Chugach’s Commercial paper program requires Chugach to maintain a minimum margins for interest of at least 1.10 times interest charges for each fiscal year.  Margins for interest generally consist of Chugach’s assignable margins plus total interest expense.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(8)
Debt (continued)

Distributions to Members

The Amended and Restated Indenture and the CoBank Master Loan Agreement prohibited Chugach from making any distribution of patronage capital to Chugach’s customers if an event of default under the Amended and Restated Indenture or CoBank Master Loan Agreement exists.  Otherwise, Chugach could make distributions to Chugach’s members in each year equal to the lesser of 5 percent of Chugach’s patronage capital or 50 percent of assignable margins for the prior fiscal year.  This restriction did not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter were equal to at least 30 percent of Chugach’s total liabilities and equities and margins.

The Second Amended and Restated Indenture of Trust, which became effective on January 20, 2011, and the CoBank Amended and Restated Master Loan Agreement, which became effective on January 19, 2011, prohibits Chugach from making any distribution of patronage capital to Chugach’s customers if an event of default under the Second Amended and Restated Indenture of Trust or CoBank Amended and Restated Master Loan Agreement exists.  Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5 percent of Chugach’s patronage capital or 50 percent of assignable margins for the prior fiscal year.  This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30 percent of Chugach’s total liabilities and equities and margins.

Maturities of Long-term Obligations

Long-term obligations at December 31, 2010, mature as follows:

Year ending December 31
  
Principal Maturities
2001 Series A Bonds
    
Principal Maturities
2002 Series A Bonds
    
Principal Maturities
CoBank Note
    
Total
  
2011
     150,000,000       0       2,851,500       152,851,500  
2012
     0       120,000,000       2,693,543       122,693,543  
2013
     0       0       2,076,355       2,076,355  
2014
     0       0       2,266,145       2,266,145  
2015
     0       0       2,473,110       2,473,110  
Thereafter
     0       0       24,941,165       24,941,165  
    $ 150,000,000     $ 120,000,000     $ 37,301,818     $ 307,301,818  


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(8)
Debt (continued)

Lines of credit

Chugach maintained a $7.5 million line of credit with CoBank, ACB (CoBank).  The line of credit expired on October 31, 2009.  Chugach did not renew this line of credit upon its expiration date due to unused carrying costs, its lack of use and the existence of the NRUCFC line of credit and commercial paper borrowing capacity.  The borrowing rate is calculated using the CoBank Base Rate on the first business day of the week plus 3 percent.  The borrowing rate at December 31, 2010 and 2009 was 2.61 percent and 2.24 percent, respectively.

In addition, Chugach had an annual line of credit of $50 million available with NRUCFC until October 9, 2008, when Chugach reduced this line of credit to $45 million.  The reduction to the borrowing limit was temporary in order that a full $300 million commitment on an unsecured credit agreement backstopping Chugach’s Commercial Paper program, could be met.  On December 22, 2008, this line of credit was increased to $75 million, however, pursuant to the terms of the Amendment To Revolving Line of Credit Agreement with NRUCFC, this line of credit was reduced to $50 million on January 30, 2009.

Chugach did not utilize this line of credit in 2010 and therefore, had no balance at December 31, 2010.  Chugach utilized this line of credit in the first quarter of 2009 and had a balance of $38 million on January 30, 2009, when we repaid $30.0 million by issuing commercial paper under our Commercial Paper program.  In February of 2009, Chugach repaid the balance on this line of credit by issuing additional commercial paper.

The borrowing rate at December 31, 2010 and 2009 was 5.25 percent and 4.95 percent, respectively and is calculated using the total rate per annum as may be fixed by NRUCFC and will not exceed the Prevailing Prime Rate, plus one percent per annum.  The NRUCFC Revolving Line Of Credit Agreement requires that Chugach, for each 12-month period, for a period of at least five consecutive days, pay down the entire outstanding principal balance.  The NRUCFC line of credit expires October 14, 2012.

The NRUCFC line of credit was immediately available for unconditional borrowing.

Commercial Paper

Over the next two years, Chugach anticipates financing increased capital expenditures due to the construction of a natural gas fired generation plant and on-going capital needs and plans to refinance $150 million of 2001 Series A Bonds due March 15, 2011, and $120 million of 2002 Series A Bonds due February 1, 2012.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(8)
Debt (continued)

Commercial Paper (continued)

On November 17, 2010, Chugach replaced the $300 million unsecured Credit Agreement executed on October 10, 2008, which was due to expire on October 10, 2011.  The 2010 Credit Agreement with National Rural Utilities Cooperative Finance Corporation (NRUCFC), Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch, will expire on November 17, 2013.  The Credit Agreement is used to back Chugach’s Commercial Paper program, which will act as a bridge until Chugach converts commercial paper balances to long-term debt. The 2010 Credit Agreement was priced with an all-in drawn spread of one month LIBOR plus 150 basis points, along with a 25 basis points facility fee (based on an A-/A3 unsecured debt rating).  Chugach had $98.5 and $51.5 million of commercial paper outstanding at December 31, 2010 and 2009, respectively.  Our commercial paper can be repriced between one day and two hundred and seventy days.

The following table provides information regarding monthly average commercial paper balances outstanding (dollars in millions), as well as corresponding weighted average interest rates:

Month
  
Average Balance
  
Weighted Average Interest Rate
         
January 2010
  
54.2
  
0.26
February 2010
  
57.1
  
0.26
March 2010
  
60.2
  
0.27
April 2010
  
59.8
  
0.28
May 2010
  
59.0
  
0.32
June 2010
  
58.7
  
0.37
July 2010
  
58.6
  
0.33
August 2010
  
60.8
  
0.33
September 2010
  
67.6
  
0.31
October 2010
  
71.4
  
0.31
November 2010
  
77.4
  
0.30
December 2010
  
87.5
  
0.31


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(8)
Debt (continued)

Financing

On January 21, 2011, Chugach issued $90,000,000 of First Mortgage Bonds, 2011 Series A, due March 15, 2031 and $185,000,000 of First Mortgage Bonds, 2011 Series A, due March 15, 2041 for the purpose of refinancing the 2001 and 2002 Series A Bonds due March 15, 2011, and February 1, 2012, respectively, and for general corporate purposes.  The 2011 Series A Bonds due March 15, 2031, will bear interest at 4.20% per annum, payable semi-annually on March 15 and September 15 of each year commencing on September 15, 2011.  Principal on the 2011 Series A Bonds due March 15, 2031 will be paid in equal annual installments beginning March 15, 2012, resulting in an average life of approximately 10 years.  The 2011 Series A Bonds due March 15, 2041, will bear interest at 4.75% per annum, payable semi-annually on March 15 and September 15 of each year commencing on September 15, 2011.  Principal on the 2011 Series A Bonds due March 15, 2041 will be paid in equal annual installments beginning March 15, 2012, resulting in an average life of approximately 15.5 years.  The bonds and all other long-term debt obligations are secured by a lien on substantially all of Chugach’s assets.

Chugach had a term loan facility with CoBank.  Loans made under that facility were evidenced by promissory notes governed by the Master Loan Agreement, which was effective January 22, 2003.  On January 19, 2011, Chugach and CoBank amended and restated the existing Master Loan Agreement.  The existing obligations under the existing loan are evidenced by the 2011 CoBank Note, which is governed by the Amended and Restated Master Loan Agreement dated January 19, 2011 and secured by the Second Amended and Restated Indenture.

Fair Value of Debt Instruments

The estimated fair values (in thousands) of the long-term obligations included in the financial statements at December 31 are as follows:
 
   
2010
    
2009
  
   
Carrying Value
    
Fair Value
    
Carrying Value
    
Fair Value
  
Long-term obligations (including current installments)
   $ 307,302     $ 315,401     $ 311,420     $ 330,358  


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(9)
Employee Benefit Plans

Pension Plans

Pension benefits for substantially all union employees are provided through the Alaska Electrical Pension Trust Fund and the Alaska Hotel, Restaurant and Camp Employees Health and Welfare and Pension Trust Fund, multi-employer plans.  Chugach pays an hourly amount per eligible union employee pursuant to the collective bargaining unit agreements.  In these master, multi-employer plans, the accumulated benefits and plan assets are not determined or allocated separately to the individual employer.

The costs for the union plans were approximately $3.0 million, $3.0 million, and $2.9 million in 2010, 2009, and 2008, respectively.  Chugach has no responsibility for any unfunded benefit obligation of the Plan at this time.

Pension benefits for non-union employees are provided by the National Rural Electric Cooperative Association (NRECA) Retirement and Security Program, a multi-employer plan.  Chugach makes annual contributions to the pension plan equal to the amounts accrued for pension expense.  Chugach contributed $3.1 million, $2.1 million, and $1.8 million in 2010, 2009, and 2008, respectively, to the NRECA plan.  Chugach has no responsibility for any unfunded benefit obligation of the Plan at this time.

Health and Welfare Plans

 
Health and welfare benefits for union employees are provided through the Alaska Electrical Health and Welfare Trust and the Alaska Hotel, Restaurant and Camp Employees Health and Welfare and Pension Trust Fund.  Chugach participates in multi-employer plans that provide substantially all union workers with health care and other welfare benefits during their employment with Chugach.  Chugach pays a defined amount per union employee pursuant to collective bargaining unit agreements.  Amounts charged to benefit costs and contributed to the health and welfare plans for these benefits for the years ending December 31, 2010, 2009, and 2008 were $3.7 million, $3.4 million, and $3.5 million respectively.

Chugach participates in a multi-employer plan through the Group Benefits Program of NRECA for non-union employees.  Amounts charged to benefit cost and contributed to this Plan for those benefits for the years ended December 31, 2010, 2009, and 2008 totaled $2.2 million, $2.1 million, and $1.9 million respectively.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(9)
Employee Benefit Plans (continued)

Money Purchase Pension Plan

Chugach participates in a multi-employer defined contribution money purchase pension plan covering some employees who are covered by a collective bargaining agreement.  Contributions to the Plan are made based on a percentage of each employee’s compensation.  Contributions to the money purchase pension plan for the years ending December 31, 2010, 2009, and 2008 were $124.1 thousand, $99.7 thousand, and $91.8 thousand, respectively.

401(k) Plan

Chugach has a defined contribution 401(k) retirement plan which covers substantially all employees who, effective January 1, 2008, can participate immediately.

Employees who elect to participate may contribute up to the Internal Revenue Service’s maximum of $16,500, $16,500, and $15,500 in 2010, 2009, and 2008 respectively, and allowed catch-up contributions for those over 50 years of age of $5,500, $5,500, and $5,000 in 2010, 2009, and 2008 respectively.  Chugach does not make contributions to the plan.

Deferred Compensation

Chugach adopted NRECA’s unfunded Deferred Compensation Program (the Program) to allow highly compensated employees who elect to participate in the Program to defer a portion of their current compensation and avoid paying tax on the deferrals until received.  The program is a non-qualified plan under Internal Revenue Code 457(b).

Deferred compensation accounts are established for the individual employees, however, they are considered to be owned by Chugach until a distribution is made.  The amounts credited to the deferred compensation account, including gains or losses, are retained by Chugach until the entire amount credited to the account has been distributed to the participant or to the participant’s beneficiary.  The balance of the Program for the years ending December 31, 2010, 2009 and 2008 was $395,833, $345,792 and $264,427, respectively.

Potential Termination Payments

Pursuant to a Chugach Operating Policy, non-represented employees, including the executive officers except the Chief Executive Officer, who are terminated by Chugach for reasons unrelated to employee performance are entitled to severance pay for each year or partial year of service as follows:  two weeks for each year of service to a maximum of twenty-six (26) weeks for thirteen (13) years or more of service.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(10)
Bradley Lake Hydroelectric Project

Chugach is a participant in the Bradley Lake Hydroelectric Project (Bradley Lake).  Bradley Lake was built and financed by the Alaska Energy Authority (AEA) through State of Alaska grants and $166,000,000 of revenue bonds.  Chugach and other participating utilities have entered into take-or-pay power sales agreements under which shares of the project capacity have been purchased and the participants 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).  Under these take-or-pay power sales agreements, the participants have agreed to pay all project costs from the date of commercial operation even if no energy is produced.  Chugach has a 30.4 percent share, or 27.4 megawatts as currently operated, of the project’s capacity.  The share of Bradley Lake indebtedness for which we are responsible is approximately $33 million.  Upon the default of a Bradley Lake participant, and subject to certain other conditions, AEA, through Alaska Industrial Development and Export Authority, is entitled to increase each participant’s share of costs pro rata, to the extent necessary to compensate for the failure of another 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 $5.3 million as a result of Chugach’s Bradley Lake take-or-pay obligations.  Management believes that such expenditures, if any, would be recoverable through the fuel surcharge ratemaking process.

On July 1, 2010, AEA issued $28,800,000 of Power Revenue Refunding Bonds, Sixth Series, for purposes of refunding $30,640,000 of the Fifth Series Bonds.  The refunded Fifth Series Bonds were called on August 2, 2010.  The refunding resulted in aggregate debt service payments over the next eleven years in a total amount approximately $3.3 million less than the debt service payments which would have been due on the refunded bonds.  Refunding the Fifth Series Bonds resulted in an economic gain of approximately $2.4 million.  Chugach’s share of these savings will be approximately $714,300, which represents the reduction in debt-service costs recorded as purchased power expense.

The following represents information with respect to Bradley Lake at June 30, 2010 (the most recent date for which information is available).  Chugach's share of expenses was $5,120,958 in 2010, $5,152,716 in 2009, and $4,746,965 in 2008 and is included in purchased power in the accompanying financial statements.

(In thousands)
  
Total
    
Proportionate Share
  
Plant in service
   $ 191,550     $ 58,231  
Long-term debt
     101,424       30,833  
Interest expense
     6,393       1,943  

Chugach's share of a Bradley Lake transmission line financed internally is included in Other Electric Plant.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(11)
Eklutna Hydroelectric Project

 
During October 1997, the ownership of the Eklutna Hydroelectric Project formally transferred from the Alaska Power Administration to the participating utilities.  This group, including their corresponding interest in the project, consists of Chugach (30 percent), MEA (16.7 percent) and Anchorage Municipal Light & Power (AML&P) (53.3 percent).

 
Plant in service in 2010 includes $2,386,571, net of accumulated depreciation of $996,593, which represents Chugach’s share of the Eklutna Hydroelectric Plant.  In 2009 plant in service included $2,397,677, net of accumulated depreciation of $898,649.  Chugach and AML&P jointly operate the facility.  Each participant contributes their proportionate share for operation, maintenance and capital improvement costs to the plant, as well as to the transmission line between Anchorage and the plant.  Under net billing arrangements, Chugach then reimburses MEA for their share of the costs.  Chugach’s share of expenses was $664,747, $615,060, and $886,261 in 2010, 2009, and 2008, respectively and is included in power production and depreciation expense in the accompanying financial statements.  AML&P performs major maintenance at the plant.  Chugach provides personnel for the daily operation and maintenance of the power plant, who perform daily plant inspections, meter reading, monthly report preparation, and other activities as required.

(12)
Commitments, Contingencies and Concentrations

 
Contingencies

 
Chugach is a participant in various legal actions, rate disputes, personnel matters and claims both for and against Chugach’s interests.  Management believes the outcome of any such matters will not materially impact Chugach’s financial condition, results of operations or liquidity.

 
Fuel Supply Contracts

Chugach has long-term fuel supply contracts from various producers at market terms.  These contracts will expire at the end of the currently committed volumes or the contract expiration dates of 2015 and 2025.  The committed 215 billion cubic feet (BCF) for the 2015 contract expired in 2010.  The 180 BCF commitment for the 2025 contracts is expected to run out in early 2011. The RCA approved a gas supply contract between Chugach and ConocoPhillips Alaska, Inc. and ConocoPhillips, Inc. (collectively “COP”), effective August 21, 2009.  The new contract provides gas beginning in 2010 and will terminate December 31, 2016.  The total amount of gas under the contract is now estimated to be 62 BCF.  The RCA approved a new long-term natural gas supply contract with MAP effective May 17, 2010.  The new MAP contract will provide gas beginning April 1, 2011, terminating March 31, 2013.  MAP has two contract extension options that can be exercised during the first year of the initial contract.  MAP extended the contract to December 31, 2013, by exercising the first contract extension on January 12, 2011.  The second contract option could be exercised by December 31, 2011, and would extend the contract through December 31, 2014.  The total amount of gas under contract is estimated at 26 billion cubic feet (BCF) for the initial two year term of the contract with volumetric and delivery terms to be determined for each contract extension period that could provide up to an additional 16 BCF through December 31, 2014. These contracts fill 100 percent of Chugach’s unmet needs through December 2013, approximately 50 percent of Chugach’s unmet needs through December 2014, approximately 60 percent in 2015 and approximately 29 percent in 2016.  In 2010, 89 percent of our power was generated from gas, compared to 90 percent and 91 percent in 2009 and 2008 respectively.  Of that gas-fired power, 78 percent was generated at Chugach’s Beluga Power Plant in 2010 compared with 83 percent in 2009 and 76 percent in 2008.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(12)
Commitments, Contingencies and Concentrations (continued)

Fuel Supply Contracts (continued)

In 2010, fuel was purchased directly primarily from Marathon Oil Company, Chevron/UNOCAL, AML&P and COP.  The following represents the cost of fuel purchased from these vendors as a percentage of total fuel costs for the years ended December 31:

   
2010
    
2009
    
2008
  
Marathon Oil Company
     24.1 %     44.6 %     49.7 %
Chevron/UNOCAL
     26.4 %     20.9 %     19.1 %
AML&P
     14.2 %     16.7 %     15.4 %
ConocoPhillips (COP)
     35.1 %     17.8 %     15.8 %

 
Concentrations

Approximately 70 percent of Chugach’s employees are represented by 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 agreements were due to expire on June 30, 2010.  On February 24, 2010, the Board of Directors approved three year extensions of all three IBEW CBA’s.  The three extensions provide no wage increase in the first year and wage increases tied to changes in the Consumer Price Index (CPI) in the second and third years, with a floor on the minimum increase and a cap on the maximum increase.  The wage increases also have an indirect connection to Chugach’s financial performance.  The contract extensions expire on June 30, 2013.  On April 28, 2010, the Board of Directors approved a three year extension of the HERE agreement.  The extension contains an increase in the employer health and welfare contribution in each year of the extension but does not provide for a wage or pension increase.  The contract extension expires on June 30, 2013.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(12) 
Commitments, Contingencies and Concentrations (continued)

 
Concentrations (continued)

Chugach is the principal supplier of power under long-term wholesale power contracts with MEA and HEA.  These contracts represented $89.1 million or 35 percent of sales revenue in 2010, $112.6 million or 39 percent in 2009, and $104.6 million or 37 percent in 2008.  The HEA contract expires January 1, 2014, and the MEA contract expires December 31, 2014.  Non-renewal of these contracts could have a negative impact on the rates charged to other Chugach customers.  Notification was made by MEA and HEA that neither organization intends to renew these contracts, however, MEA has recently advised Chugach that it desires to open discussions regarding power sales possibilities beyond 2014.  All rates are established by the RCA.

Regulatory Cost Charge

In 1992, the State of Alaska Legislature passed legislation authorizing the Department of Revenue to collect a Regulatory Cost Charge from utilities to fund the governing regulatory commission, which is currently the RCA.  The tax is assessed on all retail consumers and is based on kilowatt-hour (kWh) consumption.  The tax is collected monthly and remitted to the State of Alaska quarterly.  The Regulatory Cost Charge has changed since its inception (November 1992) from an initial rate of $0.000626 per kWh to the current rate of $0.000552, effective July 1, 2010. The tax is reported on a net basis and the tax is not included in revenue or expense.

Sales Tax

Chugach collects sales tax on retail electricity sold to Kenai and Whittier consumers.  The tax is collected monthly and remitted to the Kenai Peninsula Borough quarterly.  Sales tax is reported on a net basis and the tax is not included in revenue or expense.

Gross Receipts Tax

Chugach pays to the State of Alaska a gross receipts tax in lieu of state and local ad valorem, income and excise taxes on electricity sold in the retail market.  The tax is accrued monthly and remitted annually.  The tax is reported on a net basis and the tax is not included in revenue.

Excise taxes

Excise taxes on Chugach fuel purchases are paid directly to our gas producers and are recorded under “Fuel” in Chugach’s financial statements.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009

(12)
Commitments, Contingencies and Concentrations (continued)

Underground Compliance Charge

In 2005 the Anchorage Municipal Assembly adopted an ordinance to require utilities to convert overhead distribution lines to underground.  To comply with the ordinance, Chugach must invest two percent of gross retail revenue in the Municipality of Anchorage annually in moving existing distribution overhead lines underground.  Consistent with State of Alaska undergrounding requirement, Chugach is permitted to amend its rates by adding a 2 percent surcharge to its retail members’ bills to recover the actual costs of the program.  The rate amendments are not subject to RCA review or approval.  Chugach implemented the surcharge in June 2005.  Chugach’s liability was $726,209 and $0 for this surcharge at December 31, 2010 and December 31, 2009, respectively and will use the funds to offset the costs of the projects.

Environmental Matters

The Clean Air Act and Environmental Protection Agency (EPA) regulations under the act (the “Clean Air Act”) establish ambient air quality standards and limit the emission of many air pollutants.  Some Clean Air Act programs that regulate electric utilities, notably the Title IV “acid rain” requirements, do not apply to facilities located in Alaska.

New Clean Air Act regulations impacting electric utilities may result from future events or may result from new regulatory programs.  On October 30, 2009, the EPA published new federal regulations requiring the mandatory reporting of greenhouse gases from all sectors of the economy. Chugach is subject to this new regulation, which is not expected to have a material effect on our results of operations, financial position, and cash flows.  While we cannot predict whether any additional new regulation would occur or its limitation, it is possible that new laws or regulations could increase our capital and operating costs.  We have obtained or applied for all Clean Air Act permits currently required for the operation of our 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.  We do not believe that compliance with these statutes and regulations to date has had a material impact on our financial condition or results of operation.  However, new laws or regulations, implementation of final regulations or changes in or new interpretations of these laws or regulations could result in significant additional capital or operating expenses.

 
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009
(12)
Commitments, Contingencies and Concentrations (continued)

Generation Commitments

Chugach is in the process of developing a natural gas-fired generation plant on land owned by Chugach near its Anchorage headquarters.  SPP will be developed and owned by Chugach and AML&P as tenants in common.  Chugach will own and take approximately 70 percent of the new plant’s output and AML&P will own and take the remaining output.  Chugach will proportionately account for its ownership in the SPP.  On November 17, 2008, Chugach executed a gas turbine purchase agreement for the purchase of three gas turbines with General Electric Packaged Power (GEPP).  During 2009 Chugach executed several amendments associated with its purchase agreement with GEPP, which included the purchase of a spare engine for maintenance purposes.  Chugach executed an Owner’s Engineer Services Contract on May 12, 2009.  On January 5, 2010, Chugach executed a Services Contract for the shipment of the combustion turbine generators and related accessories.  On February 25, 2010, Chugach purchased land adjacent to its Anchorage headquarters for the laydown of equipment displaced by the new power plant.  On April 13, 2010, Chugach executed a steam turbine generator (STG) purchase agreement.  On June 18, 2010, Chugach executed an Engineering, Procurement, and Construction (EPC) contract with SNC-Lavalin Constructors, Inc. (SLCI).  On August 27, 2010, Chugach executed a Once Through Steam Generator (OTSG) equipment contract with Innovative Steam Technologies (IST).  Chugach amended the contract for transportation of combustion turbine generators on September 28, 2010, to include transportation of the steam turbine generator.  On December 20, 2010, Chugach received a construction permit from the Alaska Department of Environmental Conservation allowing the project to begin construction in spring of 2011 as planned.  On March 15, 2011, Chugach received its initial building permit from the Municipality of Anchorage.  Chugach made payments of $74.3 in 2010 and $25.0 million in 2009, with additional payments of $153.7 million expected in 2011, pursuant to all these contracts.

 
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2010 and 2009
(13)
Quarterly Results of Operations (unaudited)

2010 Quarter Ended

   
Dec. 31
    
Sept. 30
    
June 30
    
March 31
  
Operating Revenue
   $ 73,895,221     $ 58,274,912     $ 59,444,167     $ 66,711,045  
Operating Expense
     65,584,673       55,445,222       55,716,842       57,220,464  
Net Interest
     5,015,213       4,949,813       5,023,767       5,016,905  
Net Operating Margins
     3,295,335       (2,120,123 )     (1,296,442 )     4,473,676  
Nonoperating Margins
     753,600       110,850       98,250       94,863  
Assignable Margins
   $ 4,048,935     $ (2,009,273 )   $ (1,198,192 )   $ 4,568,539  

2009 Quarter Ended

   
Dec. 31
    
Sept. 30
    
June 30
    
March 31
  
Operating Revenue
   $ 74,025,693     $ 63,565,392     $ 69,239,153     $ 83,417,070  
Operating Expense
     64,737,009       60,092,648       65,798,407       74,244,513  
Net Interest
     5,013,421       5,122,410       5,164,488       5,306,030  
Net Operating Margins
     4,275,263       (1,649,666 )     (1,723,742 )     3,866,527  
Nonoperating Margins
     577,889       140,868       61,508       111,701  
Assignable Margins
   $ 4,853,152     $ (1,508,798 )   $ (1,662,234 )   $ 3,978,228  


Item 9 - Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure

None

Item 9A – Controls and Procedures

Evaluation of Controls and Procedures

As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 (“Exchange Act”) Rule 13a-15(e)) under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO).  Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be disclosed in our periodic reports to the SEC, ensures that such information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and such information is accumulated and communicated to our management, including our CEO and CFO, to allow timely decisions regarding required disclosure.  The design of any system of controls is based in part upon various assumptions about the likelihood of future events, and there can be no assurance that any of our plans, products, services or procedures will succeed in achieving their intended goals under future conditions.  In addition, there were no changes in Chugach’s internal controls over financial reporting identified in connection with the evaluation that occurred during the fourth quarter that has materially affected, or is reasonably likely to materially affect, Chugach’s internal controls over financial reporting.
 
           Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal controls over financial reporting as defined in Rule 13a-15(f) under the Exchange Act.  Our internal controls over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.  Because of its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements.  Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.  Under the supervision and with the participation of our management, including our CEO and CFO, we assessed the effectiveness of our internal controls over financial reporting as of December 31, 2010, using the criteria set forth in “Internal Control Integrated Framework”, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this assessment, management believes that, as of December 31, 2010, Chugach maintained effective internal controls over financial reporting.  In addition, there were no changes in Chugach’s internal controls over financial reporting (as defined in Rules 13a-15(f) or 15d-15(f) of the Exchange Act) identified in connection with the evaluation that occurred during the fourth quarter that has materially affected, or is reasonably like to materially affect, Chugach’s internal controls over financial reporting.


Item 9B – Other Information

None

PART III
 
Item 10 – Directors, Executive Officers and Corporate Governance
 
Chugach operates under the direction of a Board of Directors that is elected at large by our membership.  Day-to-day business and affairs are administered by the CEO. Our seven-member Board sets policy and provides direction to the CEO.  Each statutory officer must be a member of the Board, but these officers do not participate in the day-to-day management of Chugach.  No member of the Board is an employee of the company nor does any member of the Board have a material relationship with the company.  Therefore, the Chugach Board has determined that all members are independent.  Our Board of Directors oversees Chugach’s risk management, satisfying itself that our risk management practices are consistent with our corporate strategy.

Identification of Directors

The following is a summary of experience and qualifications, if identified by the Nominating Committee, of the current members of Chugach’s Board of Directors.

James Nordlund, 58, Chairman, is currently the director of rural development for the U.S. Department of Agriculture (USDA).  He is also a self-employed homebuilder and general contractor with Nordlund Carpentry, LLC.  He was elected to the board in 2006 and re-elected in 2009.  Nordlund is a former legislator and state Director of Public Assistance.  He currently serves on the board’s Audit, Finance and Operations committees.  He is an NRECA Credentialed Cooperative Director.  His term expires in May of 2012.

Janet Reiser, 55, Vice Chairman, is an engineer and Managing Partner of Salus Management Services and managing member of Jet Enviro De-Icing, LLC.  She was elected to the board in 2008.  She serves as chair of the board’s Operations Committee, serves as a representative to the ARCTEC Board of Directors and is board liaison to the Renewable Energy Committee and the SPP.  She is an NRECA Credentialed Cooperative Director and has earned her Board Leadership Certificate.  Her term expires in May of 2011.  Janet Reiser was nominated by petition.

Susan Reeves, 62, Treasurer, is the managing member of Reeves Amodio LLC, where she practices law.  She has been active on Alaska non-profit boards and commissions for many years.  She was elected to the board in 2010.  She serves as chair of the board’s Finance Committee and is a member of the board’s Audit Committee.  Her term expires in May of 2013.  Susan Reeves’ qualifications to serve on the board include her professional leadership, human resources, non-profit corporate governance and public affairs experience and her civic and community involvement.

P.J. Hill, 66, Secretary, is a retired professor from the School of Business and Public Policy at the University of Alaska Anchorage.  He is also an economic consultant and a commercial fisherman.  He was elected to the board in 2007 and re-elected in 2010.  He chairs the board’s Audit Committee and serves on the Finance Committee.  He is an NRECA Credentialed Cooperative Director.  His term expires in May of 2013.  P.J. Hill’s qualifications to serve on the board include his professional leadership, financial and corporate governance and public affairs experience and his civic and community involvement.


Rebecca Logan, 47, Director, is the General Manager for the Alaska Support Industry Alliance.  She was appointed to fill a board vacancy in 2007 and elected to the board in 2008.  She has previously served as Chairman of the Board and currently serves as a representative to the ARCTEC Board of Directors.  She is a board member of the Alaska Power Association and serves on Chugach’s audit and operations committee.  Her term expires in May of 2011.

Elizabeth Vazquez, 59, Director, is a supervising Hearing Examiner (Administrative Law Judge) with the State of Alaska, Department of Health and Social Services and has a Master’s of Business Administration.  She was elected to the board in 2005 and re-elected in 2008.  She serves on the board’s Operations and Finance committees and is board liaison to the Bylaws Committee.  She is an NRECA Credentialed Cooperative Director and has earned her Board Leadership Certificate.  Her term expires in May of 2011.

Doug Robbins, 54, Director, is a retired petroleum geologist and manager with 26 years experience at Marathon Oil Company.  He served as geologic manager and reserves reporting coordinator for Marathon’s Alaska Business Unit in 1993-94 and 2000-02, respectively.  Robbins holds a master’s degree in geology and is currently a volunteer with the Alaska Volcano Observatory.  Robbins was appointed by the board to fill a board vacancy on December 16, 2010.  He serves on the board’s Finance, Audit and Operations committees.  His term expires in May of 2011.  Doug Robbins’ qualifications to serve on the board, as determined by the Board of Directors, include his professional leadership and operational, industry and public company experience.

Identification of Executive Officers

Bradley W. Evans, 56, was appointed Chief Executive Officer on July 1, 2008.  Prior to that appointment, Mr. Evans had served as Interim CEO since December 5, 2007.  Prior to that appointment, he had served as Sr. Vice President, Power Supply since March 20, 2006, General Manager, G&T Division since January 31, 2005, Sr. Vice President, Energy Supply since June 5, 2002 and Director, Energy Supply since February 26, 2001.  Prior to his current Chugach employment, Mr. Evans served as Manager, System Dispatch for Golden Valley Electric Association.

Michael R. Cunningham, 61, was appointed Chief Financial Officer on June 5, 2002.  Upon the retirement of the Sr. Vice President, Administration in January of 2011, Mr. Cunningham assumed the responsibilities of the administration department.  Prior to the CFO appointment he served as Controller since 1986.  Prior to that, he was Budget Analyst and Manager of Accounting since beginning his Chugach employment in 1982.  Prior to his Chugach employment, Mr. Cunningham spent 15 years in various capacities with Pacific Northwest Bell Telephone Company.


Edward M. Jenkin, 50, was appointed Vice President, Power Delivery on August 22, 2008.  Prior to that appointment he had served as Acting Sr. Vice President, Power Delivery since January 14, 2008.  Mr. Jenkin has over 20 years utility experience in engineering, system operations, and planning.  He is a Registered Engineer in the State of Alaska.  Mr. Jenkin was promoted from the position of the Director, Engineering Services Division that he held since July of 2004.  Prior to that Mr. Jenkin served as System Operations Supervisor beginning in February of 2000 and was the Senior Planning Engineer starting August of 1995.  Mr. Jenkin began his utility career as an Engineering Technician for Matanuska Electric Association in April of 1982.
 
Paul R. Risse, 56, was appointed Sr. Vice President, Power Supply on October 27, 2008.  Prior to that appointment, Mr. Risse had served as Acting Sr. Vice President, Power Supply since December 6, 2007.  Prior to that appointment, Mr. Risse had served as Director of Generation Technical Services since March 27, 2006; Manager, Plant Technical Services since January 1, 2003; Project Manager since August 15, 2000; Project Engineer since April 5, 2000; and Manager Substation Operations since January 25, 1995.  Prior to his current Chugach employment, Mr. Risse served in various Transmission and Generation positions at Southern California Edison.
 
David R. Smith, 64, retired from Chugach Electric Association, Inc. on January 14, 2011, after more than 16 years of service.  Mr. Smith was appointed Sr. Vice President, Administration on October 1, 2008.  Prior to that appointment, Mr. Smith had served as Acting Sr. Vice President, Administration since December 6, 2007.  Mr. Smith was promoted from the position of Director, Information Services that he held since September 2001.  Prior to that he had served as the Manager of Applications and Programming beginning in 1996.  Mr. Smith began his utility career as a Project Manager in 1980, consulting with several utilities.

Lee D. Thibert, 55, was appointed Sr. Vice President, Strategic Planning and Corporate Affairs on June 11, 2008.  Prior to that appointment he had served as Sr. Vice President, Power Delivery from March 20, 2006 to February 1, 2008.  Prior to that appointment he had served as General Manager, Distribution Division since January 31, 2005.  Prior to that appointment he had served as Sr. Vice President, Power Delivery since June 3, 2002.  Prior to that, he served as Executive Manager, Transmission & Distribution Network Services since June 1, 1997.  Prior to that, he was Executive Manager, Operating Divisions from June of 1994. Before moving up to the Executive Manager position, he served as Director of Operations from May 1987.
 
Tyler E. Andrews, 45, was appointed Vice President, Human Resources on March 17, 2008.  Mr. Andrews has over 15 years of experience in Human Resources and Labor Relations.  Since June of 2008, Mr. Andrews has also served as an appointed board member of the State of Alaska’s labor relations agency.  Prior to his employment with Chugach, Mr. Andrews served as the Sr. Manager of Labor Relations for Alaska Communications Systems.  Prior to that, he served 10 years with the State of Alaska in a wide range of Human Resources and Labor Relations functions including Human Resources Manager and Chief Spokesperson on numerous collective bargaining teams.  Mr. Andrews holds a bachelor’s degree in economics from the University of North Carolina Chapel Hill.


Code of Ethics

Chugach finalized a code of ethics that applies to its principal executive officer, principal financial officer, principal accounting officer and any person performing similar functions on June 16, 2004.  In February of 2009, Chugach contracted with an outside firm to provide a financial reporting hotline to support the code of ethics.  It is also posted on Chugach’s website at www.chugachelectric.com.

Nominating Committee

Chugach has not made any material changes to the procedures by which our membership may recommend nominees to our Board of Directors.

The Board appoints a nominating committee each year.  The committee consists of members selected from different sections of the service area of Chugach.  No member of the Board may serve on such committee.  The committee reviews the qualifications of the Board candidates and nominates candidates for election at the annual meeting.  The committee considers diversity, skills, and such other factors as it deems appropriate given the current needs of the Board and Chugach.  Any fifty or more members, acting together, may make other nominations by petition.

Five of our current board members were nominated by the Nominating Committee based on a combination of his or her background, experience and answers to questions concerning Chugach’s goals and challenges.  One board member was nominated by petition and one was appointed by the board to fill a board vacancy.

Audit Committee Financial Expert

Chugach is a cooperative and each Board member must be a member of the cooperative.  The Board relies on the advice of all members of the Finance and Audit Committees, therefore the Board has not formally designated an Audit Committee financial expert.

Identification of the Audit Committee

Chugach Board Policy No. 127, “Audit Committee Charter,” defines the Audit Committee as follows:

The Audit Committee shall be comprised of three or more directors as determined by the Board.  Unless otherwise determined by the Board, the members of the Board Finance Committee shall be the members of the Audit Committee.  Committee members may enhance their familiarity with finance and accounting by participating in educational programs conducted by the Association or an outside consultant or other programs.  The Committee may also retain the services of a qualified accounting professional with auditing expertise to assist it in the performance of its responsibilities.


The Board Chairman shall appoint the Audit Committee chairperson, with the consent of the Board, who need not be the Board Treasurer.  The Audit Committee shall elect from its members a vice chairman, and appoint a recording secretary as needed. Members of the 2011 Audit Committee include Chair P.J. Hill and Directors James Nordlund, Susan Reeves, Rebecca Logan and Doug Robbins.

The disclosure required by Sec.240.10A-3(d) regarding exemption from the listing standards for the audit committees is not applicable to the Chugach Audit Committee.

Item 11 - Executive Compensation

Compensation Discussion and Analysis

In 1986, the NRECA developed the COMPensate wage and salary plan to provide its members with a systematic and standardized method to evaluate jobs in their specific cooperative, grade them, compare wages and salaries with those in similar electric utility systems and in the external marketplace and then create and apply statistically determined, equitable pay scales.  In 1988, the Chugach Board approved implementation of NRECA’s COMPensate wage and salary plan for non-bargaining unit employees with the objective of establishing wages and salaries for non-bargaining unit employees that would attract and retain qualified personnel and encourage their superior performance, growth and development.

Each year the regression analysis/compensation model is updated with current salary survey values to insure that the ranges reflect fair market value.  The overall change to the salary ranges reflects market changes to the midpoint of the salary ranges and creates an opportunity for but not a guarantee of salary increases.  Salary increases are not automatic and are based on performance.  Any changes to the COMPensate wage and salary plan for Chugach are approved by the Chugach Board.

CEO Brad Evans is eligible for performance based bonuses at the discretion of the Board of Directors based on performance standards they develop.  In 2010 and 2011, upon review of the performance of the CEO, Mr. Evans received a discretionary bonus of $12,500 and $20,000, respectively, before taxes.

The salary and bonuses for all other named executive officers are set annually by the CEO within annual budget guidelines approved by the Board of Directors.


Cash Compensation

The following table sets forth all remuneration paid by us for the last three fiscal years to each of our executive officers, each of whose total cash and cash equivalent compensation exceeded $100,000 for 2010 and for all such executive officers as a group:

Summary Compensation Table

Name
  
Year
  
Salary
    
Bonus
    
Change in
Pension Value and Nonqualified Deferred Compensation Earnings
    
All
Other
Compensation1
    
Total
  
                                   
Bradley W. Evans,
  
2010
   $ 251,938     $ 12,500     $ 108,663     $ 3,612     $ 376,713  
Chief Executive Officer
  
2009
   $ 250,029     $ 40,000     $ 98,704     $ 3,612     $ 392,345  
   
2008
   $ 224,218     $ 16,230     $ 55,256     $ 7,873     $ 303,577  
                                             
Michael R. Cunningham,
  
2010
   $ 177,012     $ 0     $ 147,530     $ 16,218     $ 340,760  
Chief Financial Officer
  
2009
   $ 172,263     $ 15,000     $ 184,648     $ 9,027     $ 380,938  
   
2008
   $ 166,468     $ 3,000     $ 147,412     $ 13,438     $ 330,318  
                                             
Tyler E. Andrews,
  
2010
   $ 136,858     $ 5,000     $ 20,447     $ 3,093     $ 165,398  
Vice President,
  
2009
   $ 136,821     $ 5,000     $ 11,525     $ 2,855     $ 156,201  
Human Resources
  
2008
   $ 103,276     $ 2,000       N/A     $ 1,295     $ 106,571  
                                             
Edward M. Jenkin,
  
2010
   $ 163,087     $ 0     $ 90,446     $ 1,202     $ 254,735  
Vice President,
  
2009
   $ 160,570     $ 5,000     $ 152,802     $ 18,641     $ 337,013  
Power Delivery
  
2008
   $ 153,249     $ 0     $ 64,145     $ 721     $ 218,115  
                                             
Paul R. Risse,
  
2010
   $ 163,970     $ 0     $ 86,543     $ 2,281     $ 252,794  
Sr. Vice President,
  
2009
   $ 163,660     $ 10,000     $ 84,645     $ 7,083     $ 265,388  
Power Supply
  
2008
   $ 155,791     $ 3,000     $ 54,445     $ 2,554     $ 215,790  
                                             
David R. Smith,
  
2010
   $ 161,162     $ 0     $ 45,407     $ 20,243     $ 226,812  
Former Sr. Vice President,
  
2009
   $ 160,949     $ 10,000     $ 38,558     $ 17,154     $ 226,661  
Administration
  
2008
   $ 152,717     $ 2,000     $ 82,657     $ 4,129     $ 241,503  
                                             
Lee D. Thibert,
  
2010
   $ 186,121     $ 10,000     $ 108,314     $ 6,218     $ 310,653  
Sr. Vice President, Strategic
  
2009
   $ 185,786     $ 15,000     $ 127,212     $ 7,288     $ 335,286  
Planning & Corporate Affairs
  
2008
   $ 119,951     $ 0     $ 99,323     $ 3,830     $ 223,104  

1Includes costs for life insurance premiums, tax withholdings on bonuses and payment for unused vacation days.


Pension Benefits

We have elected to participate in the NRECA Retirement Security Plan (the “Plan”), a multiple employer defined benefit master pension plan maintained and administered by the NRECA for the benefit of its members and their employees. Under ASC 960, the plan is a multi employer plan, in which the accumulated benefits and plan assets are not determined or allocated separately to individual employers.  The Plan is intended to be a qualified pension plan under Section 401(a) of the Code.  All our employees not covered by a union agreement become participants in the Plan on the first day of the month following completion of one year of eligibility service.  An employee is credited with one year of eligibility service if he or she completes 1,000 hours of service either in his or her first twelve consecutive months of employment or in any calendar year for us or certain other employers in rural electrification (related employers). Pension benefits vest at the rate of 10 percent for each of the first four years of vesting service and become fully vested and nonforfeitable on the earlier of the date a participant has five years of vesting service or the date the participant attains age fifty-five while employed by us or a related employer. A participant is credited with one year of vesting service for each calendar year in which he or she performs at least one hour of service for us or a related employer.  Pension benefits are generally paid upon the participant's retirement or death.  A participant may also elect to receive pension benefits while still employed by us if he or she has reached his normal retirement date by completing thirty years of benefit service (defined below) or, if earlier, by attaining age sixty-two. A participant may elect to receive actuarially reduced early retirement pension benefits before his or her normal retirement date provided he or she has attained age fifty-five.

Pension benefits paid in normal form are paid monthly for the remaining lifetime of the participant.  Unless an actuarially equivalent optional form of benefit payment to the participant is elected, upon the death of a participant the participant's surviving spouse will receive pension benefits for life equal to 50 percent of the participant's benefit. The annual amount of a participant's pension benefit and the resulting monthly payments the participant receives under the normal form of payment are based on the number of his or her years of participation in the Plan (benefit service) and the highest five-year average of the annual rate of his or her base salary during the last ten years of his or her participation in the Plan (final average salary).  Annual compensation in excess of $200,000, as adjusted by the Internal Revenue Service for cost of living increases, is disregarded after January 1, 1989. The participant's annual pension benefit at his or her normal retirement date is equal to the product of his or her years of benefit service times final average salary times 2 percent. In 1998, NRECA notified us that there were employees whose pension benefits from NRECA's Retirement & Security Program would be reduced because of limitations on retirement benefits payable under Section 401(a)(17) or 415 of the Code. NRECA made available a Pension Restoration Severance Pay Plan and a Pension Restoration Deferred Compensation Plan for cooperatives to adopt in order to make employees whole for their lost benefits. In May 1998, we adopted both of these plans to protect the benefits of current and future employees whose pension benefits would be reduced because of these limitations.


On October 16, 2002, the Board authorized an amendment to the Plan with an effective date of November 1, 2002.  Under the amended Plan, the retirement benefit payable to any Participant whose retirement is postponed beyond his or her Normal Retirement Date shall be computed as of the Participant’s actual retirement date.  The retirement benefit payable to any Participant under the 30-Year Plan shall be computed as of the first day of the month in which the Participant’s actual retirement date occurs.

Benefit service as of December 31, 2010 that is taken into account under the Plan for the executive officers is shown below with the assumptions for calculation of the present value of accumulated benefits.
 
Pension Benefits Table

Name
  
Plan
  
Credited Years of Service
    
Present Value of Accumulated Benefit
    
Payments During Last Fiscal Year
  
                             
Bradley W. Evans,
  
Retirement
    9.83     $ 442,289     $ 0  
Chief Executive Officer
   Security                        
   
Pension
     9.83     $ 4,656          
   
Restoration
                        
                             
Michael R. Cunningham,
  
Retirement
    27.08     $ 1,283,459     $ 0  
Chief Financial Officer
   Security                        
                             
Lee D. Thibert,
  
Retirement
    22.33     $ 873,170     $ 0  
Sr. Vice President,
  Security                        
Strategic Planning & Corporate Affairs
                            
                             
Paul R. Risse,
  
Retirement
     14.92     $ 471,073     $ 0  
Sr. Vice President, Power Supply
   Security                        
                             
David R. Smith,1
  
Retirement
    2.5     $ 103,298     $ 0  
Former Sr. Vice President, Administration
   Security                        
                             
Edward M. Jenkin,
  
Retirement
     20.08     $ 565,985     $ 0  
Vice President, Power Delivery
  
Security
                        
                             
Tyler E. Andrews,
  
Retirement
     1.8     $ 31,972     $ 0  
Vice President, Human Resources
  
Security
                        

1 Mr. Smith was paid the value of all of his pension benefits attributable to service prior to July 1, 2008.

It is assumed that participants retire at the earlier of age 62 or 30 years of benefit service and elect a lump sum benefit.

Lump sum amounts are calculated using the 30-year Treasury rate (4.31 percent for 2010 and 4.00 percent for 2009) and the Pension Protection Act (PPA) three-segment yield rates (3.13 percent, 5.07 percent, and 5.50 percent for 2010 and 5.24 percent, 5.69 percent, and 5.37 percent for 2009) and the required IRS mortality table for lump sum payments (1994 Guaranteed Annuity Rate (GAR), projected to 2002, blended 50 percent/50 percent for unisex mortality in combination with the 30-year Treasury rates and Retirement Plan (RP) 2000 PPA at 2010 and 2009, respectively, combined unisex 50 percent/50 percent mortality in combination with the PPA rates). The lump sum is then discounted at 5.15 percent interest only (no mortality is assumed) from assumed retirement date back to December 31, 2010, and 5.50 percent interest only (no mortality is assumed) from assumed retirement date back to December 31, 2009, to determine the present value for the appropriate year.


Deferred Compensation

Chugach adopted NRECA’s unfunded Deferred Compensation Program (the Program) to allow highly compensated employees who elect to participate in the Program to defer a portion of their current compensation and avoid paying tax on the deferrals until received.  As a non-qualified plan under Internal Revenue Code 457(b), NRECA’s Deferred Compensation Plan is not subject to non-discrimination testing.  The Program is designed to help decrease current taxable income, take advantage of tax deferred compounding and set aside additional money for retirement.  The money is accessible only upon separation of service, disability or death (in which case it is paid to the designated beneficiary).  The distribution is taxable as income in the year received.

Deferred compensation accounts are established for the individual employees, however, they are considered to be owned by Chugach until a distribution is made.  Deferred compensation plan assets would be subject to creditors’ demands in the case of bankruptcy.  Deferred compensation assets are invested with Homestead Funds, a family of no-load mutual funds.  Homestead Funds’ investment managers, RE Advisers, is a wholly-owned subsidiary of NRECA. Each participant in the Program determines the investment fund or funds into which their accounts are invested.  The amounts credited to the deferred compensation account, including gains and losses, are retained by Chugach until the entire amount credited to the account has been distributed to the Participant or to the Participant’s beneficiary.

Deferred Compensation Table

Name
  
Executive Contributions in last FY
    
Registrant Contributions in last FY
    
Aggregate Earnings
in last FY
    
Aggregate Withdrawals/
Distributions
    
Aggregate balance at
FYE
  
                               
Bradley W. Evans,
   $ 16,500     $ 0     $ 11,883     $ 0     $ 136,069  
Chief Executive Officer
                                        
                                         
Michael R. Cunningham,
   $ 16,500     $ 0     $ 3     $ 0     $ 48,596  
Chief Financial Officer
                                        


Potential Termination Payments

Pursuant to a Chugach Operating Policy, non-represented employees, including the executive officers except the Chief Executive Officer, who are terminated by Chugach for reasons unrelated to employee performance are entitled to severance pay for each year or partial year of service as follows:  two weeks for each year of service to a maximum of twenty-six (26) weeks for thirteen (13) years or more of service.  If Mr. Evans is terminated by Chugach without cause, he will receive one year’s salary and benefits, or the amounts left to be paid under the remaining term of the contract, whichever is less.

The following is a list of the estimated severance payments, including the payment of accrued vacation that would be made to each of the executive officers in the case of termination not related to employee performance:

Potential Termination Payments Table

 
Name
  
Estimated
Severance Payment
  
       
Bradley W. Evans,
Chief Executive Officer
   $ 193,052  
         
Michael R. Cunningham,
Chief Financial Officer
   $ 129,246  
         
Tyler E. Andrews,
Vice President, Human Resources
   $ 33,407  
         
Edward M. Jenkin,
Vice President, Power Delivery
   $ 108,705  
         
Paul R. Risse,
Sr. Vice President, Power Supply
   $ 171,461  
         
David R. Smith,
Former Sr. Vice President, Administration
   $ 101,443  
         
Lee D. Thibert,
Sr. Vice President, Strategic Planning & Corporate Affairs
   $ 120,877  

Director Compensation

Directors are compensated for their services at the rate of $200 per Board meeting or other meeting at which they are representing the Association in an official capacity within the State of Alaska, and $250 per day when attending meetings or training outside of the State, including each day of travel, plus reimbursement of reasonable out of pocket expenses, up to a maximum of 70 meetings per year for a director and 85 meetings per year for the Chairman.


The following table sets forth the dollar amounts of all fees paid in cash by us for the fiscal year ending December 31, 2010 to each of our current and former Board members:

Director Compensation Table

Name
  
Fees Paid
In Cash
  
James Nordlund, Chairman and Director
   $ 10,300  
         
Janet Reiser, Vice-Chairman and Director
   $ 14,850  
         
Susan Reeves, Treasurer and Director
   $ 7,600  
         
P.J. Hill, Secretary and Director
   $ 13,700  
         
Rebecca Logan, Director
   $ 16,400  
         
Doug Robbins, Director
   $ 0  
         
Elizabeth Vazquez, Director
   $ 12,200  
         
Elizabeth “Pat” Kennedy, Former Director
   $ 11,850  
         
Alex Gimarc, Former Director
   $ 5,000  

One new board member was elected, while one current board member was re-elected at Chugach’s annual membership meeting held on April 29, 2010.  Susan Reeves was elected to a three-year term, replacing Alex Gimarc, and P.J. Hill was re-elected to a three-year term.

Item 12 - Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters

Not Applicable

Item 13 - Certain Relationships and Related Transactions, and Director Independence

Not Applicable


Item 14 – Principal Accounting Fees and Services

The Audit Committee of the Board retained KPMG LLP as the independent registered public accounting firm for Chugach during the fiscal year ended December 31, 2010.

Fees and Services

KPMG LLP has provided certain audit, audit-related, tax and non-audit services, the fees for which are as follows:

   
2010
    
2009
  
Audit and audit-related services:
            
Audit and quarterly reviews
   $ 141,950     $ 211,165  
Audit-related services (Single audit and employee benefit plans)
     17,000       30,465  
Non-audit services:
                
Tax consulting and return preparation
     14,430       20,305  
Other services1
     23,725       3,431  
Total
   $ 197,105     $ 265,366  

1
Other services in 2010 included Sarbanes-Oxley implementation and contract reviews
Other services in 2009 included Sarbanes-Oxley procedure reviews

The Audit Committee of the Board has a policy to pre-approve all services to be provided by Chugach’s independent public accountants.  All services from Chugach’s independent registered public accounting firm for fiscal years ended December 31, 2010 and 2009 were approved by the Audit Committee.
 

Item 15 – Exhibits and Financial Statement Schedules




 
Page
Financial Statements
  
   
Included in Part II of this Report:
  
Report of Independent Registered Public Accounting Firm
51
Balance Sheets, December 31, 2010 and 2009
52-53
Statements of Operations, Years ended December 31, 2010, 2009 and 2008
54
Statements of Changes in Equities and Margins, Years ended December 31, 2010, 2009 and 2008
55
Statements of Cash Flows, Years ended December 31, 2010, 2009 and 2008
56
Notes to Financial Statements
57-88

 
Financial Statement Schedules
  
   
Included in Part IV of this Report:
  
Report of Independent Registered Public Accounting Firm
103
Schedule II - Valuation and Qualifying Accounts, Years ended December 31, 2010, 2009 and 2008
104

Other schedules are omitted as they are not required or are not applicable, or the required information is shown in the applicable financial statements or notes thereto.


Report of Independent Registered Public Accounting Firm

The Board of Directors
Chugach Electric Association, Inc.

Under date of March 30, 2011, we reported on the balance sheets of Chugach Electric Association, Inc. as of December 31, 2010 and 2009, and the related statements of operations, changes in equities and margins and cash flows for each of the years in the three-year period ended December 31, 2010, which are included in the 2010 Annual Report on Form 10-K.  In connection with our audits of the aforementioned financial statements, we also audited the related financial statement schedule in the 2010 Annual Report on Form 10-K.  This financial statement schedule is the responsibility of the Company’s management.  Our responsibility is to express an opinion on this financial statement schedule based on our audit.

In our opinion, the financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ KPMG, LLP

March 30, 2011
Anchorage, Alaska


Schedule II

CHUGACH ELECTRIC ASSOCIATION, INC.
 
Valuation and Qualifying Accounts

 
   
Balance at Beginning Of year
    
Charged To costs And expenses
    
Deductions
    
Balance at end of year
  
Allowance for doubtful accounts:
                        
Activity for year ended:
                        
December 31, 2010
     (397,815 )     (205,402 )     296,048       (307,169 )
December 31, 2009
     (408,632 )     (245,157 )     255,974       (397,815 )
December 31, 2008
     (541,368 )     (295,313 )     428,049       (408,632 )



EXHIBITS

Listed below are the exhibits, which are filed as part of this Report:

Exhibit Number
  
Description
     
3.1
  
Articles of Incorporation of the Registrant.  Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2001, SEC File No. 033-42125.
     
3.2
  
Bylaws of the Registrant. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated April 30, 2009, SEC File No. 033-42125.
     
4.11
  
Tenth Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National Association dated April 1, 2001. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.
     
4.12
  
Eleventh Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National Association. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated December 21, 2001, SEC File No. 333-75840.
     
4.13
  
Amended and Restated Indenture between the Registrant and U.S. Bank Trust National Association dated April 1, 2001. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.
     
4.14
  
Form of 2001 Series A Bond due 2011. Previously filed as an exhibit to the Registrant’s Amendment No. 1 to Registration Statement on Form S-1 dated April 10, 2001, SEC File No. 333-57400.
     
4.15
  
Form of 2002 Series A Bond due 2012. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated December 21, 2001, SEC File No. 333-75840.
     
 
First Supplemental Indenture to the Amended and Restated Indenture dated April 1, 2001 between the Registrant and U.S. Bank National Association dated January 19, 2011.  Filed Herewith.
     
 
Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated January 20, 2011.  Filed Herewith.
     
 
First Supplemental Indenture to the Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated January 20, 2011.  Filed Herewith.
     
 
Bond Purchase Agreement between the Registrant and the 2011 Series A Bond Purchasers dated January 21, 2011.  Filed Herewith.
     
 
Form of 2011 Series A Bond (Tranche A) due March 15, 2031.  Filed Herewith.
     
 
Form of 2011 Series A Bond (Tranche B) due March 15, 2041.  Filed Herewith.

 
10.2
  
Joint Use Agreement between the Registrant and the City of Seward dated effective as of September 11, 1998. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.3
  
Net Billing Agreement among the Registrant and the City of Seward dated effective as of September 11, 1998. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1991, SEC File No. 033-42125.
     
10.4.2
  
2006 Agreement for the Sale and Purchase of Electric Power and Energy between the Registrant and the City of Seward dated effective February 27, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.
     
10.5
  
Agreement for Sale of Electric Power and Energy by and among the Registrant, Homer Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated September 27, 1985. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.5.1
  
Assignment of Agreement for Sale of Electric Power and Energy by and among the Registrant, Homer Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003.  Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.
     
10.6
  
Modified Agreement for the Sale and Purchase of Electric Power and Energy by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated effective as of January 30, 1989. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.6.1
  
First Amendment to Modified Agreement for the Sale and Purchase of Electric Power and Energy by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated effective as of February 10, 1995. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1994, SEC File No. 033-42125.
     
10.6.2
  
Net Billing Agreement by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 16, 1987. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.8
  
Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc. dated April 21, 1989. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

 
10.8.1
  
Amendment No. 1 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc., dated August 1, 1990. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.8.2
  
Letter Agreement dated April 23, 1999, regarding the Registrant’s consent to the assignment to ARCO Beluga, Inc. of the Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.
     
10.8.3
  
Amendment No. 2 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Beluga, Inc., dated May 6, 1999. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1999, SEC File No. 033-42125.
     
10.9
  
Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and ARCO Alaska, Inc. dated October 3, 1991. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.10
  
Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company dated September 26, 1988. (Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.10.1
  
Letter Agreement dated September 26, 1988 between the Registrant and Marathon Oil Company, amending the Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.10.2
  
Amendatory Agreement No. 1 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated effective as of February 21, 1990. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.10.3
  
Amendatory Agreement No. 2 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated effective as of February 21, 1990. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.10.4
  
Amendatory Agreement No. 3 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated January 28, 1991. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.10.5
  
Amendatory Agreement No. 4 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated October 6, 1993. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.

 
10.10.6
  
Letter Agreement dated January 18, 1996 between the Registrant and Marathon Oil Company, amending the Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.
     
10.10.7
  
Amendatory Agreement No. 5 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated May 24, 1999. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1999, SEC File No. 033-42125.
     
10.11
  
Agreement for the Sale and Purchase of Natural Gas between the Registrant and Shell Western E&P Inc. dated April 25, 1989. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.11.1
  
Amendatory Agreement No. 1 to the Agreement for the Sale of Natural Gas between the Registrant and Shell Western E&P Inc., dated October 1, 1989. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.11.2
  
Amendment No. 2 to the Agreement for the Sale of Natural Gas between the Registrant and Shell Western E&P Inc., dated June 20, 1990. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.11.3
  
Amendatory Agreement No. 3 to the Agreement for the Sale of Natural Gas between the Registrant and Shell Western E&P Inc. dated October 14, 1996. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1996, SEC File No. 033-42125.
     
10.12
  
Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and Shell Western E&P Inc. dated November 2, 1990. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.13
  
Agreement for the Sale and Purchase of Natural Gas between the Registrant and Chevron USA Inc. dated April 27, 1989 (including Attachment No. 1 thereto dated December 20, 1989). Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.13.2
  
Amendment No. 2 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Chevron USA Inc., dated June 7, 1990. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.13.3
  
Amendment No. 3 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Chevron U.S.A. Inc., dated May 26, 1999. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1999, SEC File No. 33-42125.

 
10.14
  
Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and Chevron USA, Inc. dated September 25, 1990. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.15
  
Alaska Intertie Agreement between Alaska Power Authority, Municipality of Anchorage, the Registrant, City of Fairbanks, Alaska Municipal Utilities System, Golden Valley Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 23, 1985. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.16
  
Addendum No. 1 to the Alaska Intertie Agreement-Reserve Capacity and Operating Reserve Responsibility dated December 23, 1985. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.17
  
Memorandum of Understanding Regarding Intertie Upgrades among Alaska Energy Authority, the Registrant, Golden Valley Electric Association, Inc., Homer Electric Association, Inc., Matanuska Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light and Power, and the City of Seward d/b/a Seward Electric System dated March 21, 1990. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.18
  
Amendment No. 1 to the Alaska Intertie Agreement-Insurance and Liability dated March 28, 1991. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.
     
10.19
  
Intertie Grant Agreement between the Registrant, Golden Valley Electric Association, Inc., Fairbanks Municipal Utility System, Anchorage Municipal Light and Power, Alaska Electric Generation and Transmission Cooperative, Inc. (on behalf of Matanuska Electric Association, Inc. and Homer Electric Association, Inc.), City of Seward, the State of Alaska, Department of Administration and Alaska Industrial Development and Export Authority dated August 17, 1993. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1993, SEC File No. 033-42125.
     
10.20
  
Grant Transfer and Delegation Agreement between the Registrant and Golden Valley Electric Association, Inc., Fairbanks Municipal Utility System, Anchorage Municipal Light and Power, Alaska Electric Generation and Transmission Cooperative, Inc., Matanuska Electric Association, Inc., Homer Electric Association, Inc., Seward, the State of Alaska, Department of Administration, and AMEA dated November 5, 1993. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1993, SEC File No. 033-42125.
     
10.21
  
1993 Alaska Intertie Project Participants Agreement by and among Alaska Power Authority, Municipality of Anchorage, the Registrant, City of Fairbanks, Alaska Municipal Utilities System, Golden Valley Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc., City of Seward d/b/a Seward Electric System, Homer Electric Association, Inc. and Matanuska Electric Association, Inc. dated January 24, 1994. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.

 
10.22
  
Amendment No. 1 to the 1993 Alaska Intertie Project Participants Agreement dated December 10, 1999. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.
     
10.23
  
Grant Administration Agreement by and among the Registrant, Alaska Industrial Development and Export Authority, Golden Valley Electric Association, Inc., Fairbanks Municipal Utilities System, Anchorage Municipal Light & Power, Alaska Electric Generation and Transmission Cooperative, Inc. (on behalf of Homer Electric Association, Inc. and Matanuska Electric Association, Inc.) and City of Seward dated August 30, 1994. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.
     
10.24
  
Bradley Lake Agreement for the Sale and Purchase of Electric Power by and among the Registrant, the Alaska Power Authority, Golden Valley Electric Association, Inc., the Municipality of Anchorage, the City of Seward, the Alaska Electric Generation and Transmission Cooperative, Inc., Homer Electric Association, Inc. and Matanuska Electric Association Inc. dated December 8, 1987. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.24.1
  
Partial Assignment of Bradley Lake Hydroelectric Project Agreement for the Sale and Purchase of Electric Power by and among the Registrant, the Alaska Power Authority, Golden Valley Electric Association, Inc., the Municipality of Anchorage, the City of Seward, the Alaska Electric Generation and Transmission Cooperative, Inc., Homer Electric Association, Inc. and Matanuska Electric Association Inc. dated June 30, 2003. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.
     
10.25
  
Agreement for the Wheeling of Electric Power and for Related Services by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc., Matanuska Electric Association, Inc., the Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 8, 1987. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.25.1
  
Partial Assignment of Bradley Lake Hydroelectric Project Agreement for the Wheeling of Electric Power and for Related Services by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc., Matanuska Electric Association, Inc., the Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.
     
10.26
  
Transmission Sharing Agreement by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light and Power. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

 
10.27
  
Amendment to Agreement for Sale of Transmission Capability by and among the Registrant, Homer Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc., Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light and Power dated March 7, 1989. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.28
  
Bradley Lake Hydroelectric Agreement for the Dispatch of Electric Power and for Related Services between the Registrant and the Alaska Energy Authority dated February 19, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1991, SEC File No. 033-42125.
     
10.29
  
Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated September 29, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1992, SEC File No. 033-42125.
     
10.29.1
  
Assignment of Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.
     
10.30
  
Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated December 2, 1983. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.30.1
  
Addendum No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated August 8, 1984. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.30.2
  
Amendment No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated November 28, 1984. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.31
  
Gas Transportation Agreement by and among the Registrant, Alaska Pipeline Company and ENSTAR Natural Gas Company dated December 7, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1992, SEC File No. 033-42125.
     
10.32
  
Eklutna Purchase Agreement by and among the Registrant, Matanuska Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light and Power and Alaska Power Administration. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

 
10.33
  
Eklutna Hydroelectric Project Closing Documents dated October 2, 1997. Previously reported as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1997, SEC File No. 033-42125.
     
10.36
  
Agreement by and among the Registrant, Municipality of Anchorage d/b/a Anchorage Municipal Light and Power, Matanuska Electric Association, Inc., U.S. Fish and Wildlife Service, National Marine Fisheries Service, Alaska Energy Authority and the State of Alaska re: the Eklutna and Snettisham Hydroelectric Projects. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1991, SEC File No. 033-42125.
     
10.37
  
Daves Creek Substation Agreement between the Registrant and the Alaska Energy Authority dated March 13, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1992, SEC File No. 033-42125.
     
10.39
  
Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Alaska Electric Generation and Transmission Cooperative, Inc. dated February 12, 1999. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1999, SEC File No. 033-42125.
     
10.39.1
  
Second Amendment to the Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 1, 2001. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2001, SEC File No. 033-42125.
     
10.39.2
  
Assignment of Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.
     
10.39.3
  
Settlement of Dispute Over Nikiski Cogeneration Plant System Use and Dispatch Agreement and Premium Demand Charges Under HEA PSA between the Registrant and Alaska Electric and Energy Cooperative, Inc. and Homer Electric Association, Inc. dated January 15, 2008. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.
     
10.39.4
  
Third Amendment to the Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Homer Electric Association, Inc. dated effective November 6, 2009.  Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2009, SEC File No. 033-42125.
     
10.40
  
Lease Amendment between the Registrant and Standard Oil Company of California dated June 1, 1975. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
     
10.41
  
Lease Amendment between the Registrant and Chevron USA, Inc. dated September 1, 1985. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

 
 
Amended and Restated Master Loan Agreement between the Registrant and CoBank, ACB dated January 19, 2011.  Filed Herewith.
     
 
Second Amended and Restated Supplement between the Registrant and CoBank, ACB, dated January 19, 2011.  Filed Herewith.
     
 
Form of 2011 CoBank Note dated January 19, 2011.  Filed Herewith.
     
10.47.1
  
Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation dated October 14, 2007. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2007, SEC File No. 033-42125.
     
10.47.2
  
Amendment to Revolving Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation dated effective December 22, 2008. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2008, SEC File No. 033-42125.
     
 
2010 Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation (NRUCFC), Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch dated November 17, 2010.  Filed Herewith.
     
10.56
  
Order On Offer Of Settlement And Issuing New License between the Registrant and the Federal Energy Regulatory Commission dated effective August 24, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.
     
10.58
  
Agreement Covering Terms and Conditions of Employment for Beluga Power Plant Culinary Employees between the Registrant and the Hotel Employees & Restaurant Employees Union Local 878 dated effective December 13, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.
     
10.59
  
Agreement Covering Terms and Conditions of Employment for Office and Engineering Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective September 13, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.
     
10.59.1
  
Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Office and Engineering Personnel dated effective July 1, 2010.  Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2009, SEC File No. 033-42125.
     
10.60
  
Agreement Covering Terms and Conditions of Employment for Generation Plant Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective November 9, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.

 
10.60.1
  
Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Generation Plant Personnel dated effective July 1, 2010.  Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2009, SEC File No. 033-42125.
     
10.61
  
Agreement Covering Terms and Conditions of Employment for Outside Plant Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective December 12, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.
     
10.61.1
  
Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Outside Plant Personnel dated effective July 1, 2010.  Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2009, SEC File No. 033-42125.
     
10.62
  
Memorandum of Understanding Regarding Joint Development of South Anchorage Power Project between the Registrant and Anchorage Municipal Light and Power dated effective February 28, 2008. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.
     
10.64
  
Employment Agreement between the Registrant and Bradley W. Evans dated effective July 1, 2008.  Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated August 27, 2008, SEC File No. 033-42125.
     
10.65
  
Agreement for the Sale and Purchase of Natural Gas between the Registrant and ConocoPhillips Alaska, Inc. and ConocoPhillips, Inc. (collectively, ConocoPhillips) effective August 21, 2009.  Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated August 21, 2009, SEC File No. 033-42125.
     
10.66
  
Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Alaska Production, LLC (MAP) effective May 17, 2010.  Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated May 17, 2010, SEC File No. 033-42125.
     
10.67
  
Engineering, Procurement and Construction Contract between the Registrant and SNC-Lavalin Constructors, Inc. dated effective June 18, 2010.  Confidential portions have been omitted and filed separately with the Commission on a Confidential Treatment Request.  Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2010, SEC File No. 033-42125.
     
10.68
  
Transportation Agreement between the Registrant and Beluga Pipeline Company dated effective October 1, 2010.  Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2010, SEC File No. 033-42125.
     
10.69
  
Transportation Agreement For Interruptible Transportation Of Natural Gas between the Registrant and Kenai Nikiski Pipeline dated effective October 1, 2010.  Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2010, SEC File No. 033-42125.

 
10.70
  
Gas Exchange Contract between the Registrant and Union Oil Company of California dated effective October 1, 2010.  Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2010, SEC File No. 033-42125.
     
 
Gas Transportation Agreement between the Registrant and Alaska Pipeline Company and ENSTAR Natural Gas Company effective November 17, 2010.  Filed Herewith.
     
14
  
Code of Ethics for Senior Financial Officers of the Registrant dated effective June 16, 2004. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2004, SEC File No. 033-42125.
     
 
Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
     
 
Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
     
 
Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
     
 
Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.



Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on March 28, 2011.

 
CHUGACH ELECTRIC ASSOCIATION, INC.
     
 
By:
/s/ Bradley W. Evans
   
Bradley W. Evans, Chief Executive Officer
     
 
Date:
March 28, 2011
 
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 28, 2011, by the following persons on behalf of the registrant and in the capacities indicated:

/s/ Bradley W. Evans
  
Bradley W. Evans
Chief Executive Officer
 
(Principal Executive Officer)
   
/s/ Michael R. Cunningham
  
Michael R. Cunningham
Chief Financial Officer
 
(Principal Financial Officer)
 
(Principal Accounting Officer)
/s/ Paul R. Risse
  
Paul R. Risse
Sr. Vice President, Power Supply
   
/s/ Lee D. Thibert
  
Lee D. Thibert
Sr. Vice President, Strategic Planning &
 
Corporate Affairs
/s/ Luke Sliman
  
Luke Sliman acting for
  
Edward M. Jenkin
Vice President, Power Delivery
   
/s/ Tyler E. Andrews
  
Tyler E. Andrews
Vice President, Human Resources
   
/s/ James Nordlund
  
James Nordlund
Director & Chairman of the Board
   
/s/ Janet Reiser
  
Janet Reiser
Director & Vice-Chairman of the Board
   
/s/ Susan Reeves
  
Susan Reeves
Director & Treasurer of the Board
   
/s/ P. J. Hill
  
P. J. Hill
Director & Secretary of the Board


/s/ Rebecca Logan
  
Rebecca Logan
Director
   
/s/ Elizabeth Vazquez
  
Elizabeth Vazquez
Director
   
/s/ Doug Robbins
  
Doug Robbins
Director

Supplemental Information to be Furnished With Reports Filed
Pursuant to Section 15(d) of the Act by Registrants
Which Have Not Registered Securities Pursuant to Section 12 of the Act

Chugach has not made an Annual Report to securities holders for 2010 and will not make such a report after the filing of this Form 10-K.  As a consequence, no copies of any such report will be furnished to the Securities and Exchange Commission.
 
 
118