Attached files

file filename
EX-32.2 - EXHIBIT 32.2 - CHUGACH ELECTRIC ASSOCIATION INCex32_2.htm
EX-32.1 - EXHIBIT 32.1 - CHUGACH ELECTRIC ASSOCIATION INCex32_1.htm
EX-31.1 - EXHIBIT 31.1 - CHUGACH ELECTRIC ASSOCIATION INCex31_1.htm
EX-31.2 - EXHIBIT 31.2 - CHUGACH ELECTRIC ASSOCIATION INCex31_2.htm
EX-10.61.1 - EXHIBIT 10.61.1 - CHUGACH ELECTRIC ASSOCIATION INCex10_61-1.htm
EX-10.59.1 - EXHIBIT 10.59.1 - CHUGACH ELECTRIC ASSOCIATION INCex10_59-1.htm
EX-10.60.1 - EXHIBIT 10.60.1 - CHUGACH ELECTRIC ASSOCIATION INCex10_60-1.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, 2009
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
 
(I.R.S. Employer
 
 
incorporation or organization)
 
Identification No.)
 
         
 
5601 Electron Dr., Anchorage, Alaska
 
99518     
 
 
(Address of principal executive offices)
 
(Zip Code)
 
         
 
Registrant’s telephone number, including area code
 
(907) 563-7494
 

Securities registered pursuant to Section 12(b) of the Act:
 
 
Title of each class
 
Name of each exchange on which registered
 
 
N/A               
 
N/A               
 
 
Securities registered pursuant to Section 12(g) of the Act:
 
N/A

(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
o Yes 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 (§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).
o Yes o No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Registration S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
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). o Yes  xNo
 
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.

2009 Form 10-K Annual Report

Table of Contents

 
PART I
Page
     
Item 1
3
     
Item 1A
12
     
Item 1B
17
     
Item 2
17
     
Item 3
26
     
Item 4
26
     
 
PART II
 
Item 5
26
     
     
Item 6
27
     
Item 7
28
     
Item 7A
51
     
Item 8
52
     
Item 9
88
     
Item 9A
88
     
Item 9B
89
     
 
PART III
 
Item 10
89
     
Item 11
93
     
Item 12
99
     
Item 13
99
     
Item 14
99
     
 
PART IV
 
Item 15
100
     
115
 

CAUTION REGARDING FORWARD-LOOKING STATEMENTS

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

PART I

Item 1 - Business
 
 
General

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

Chugach makes its current and periodic reports available, free of charge, on its website at www.chugachelectric.com as soon as practicable after filing with the Securities and Exchange Commission (SEC).  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 81,047 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 $0.000432 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 316 full-time employees as of March 1, 2010.  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, which expire on June 30, 2010.  We also have an agreement with the Hotel Employees & Restaurant Employees (HERE) which also expires on June 30, 2010.  On February 24, 2010, the Board of Directors approved an extension of the IBEW Collective Bargaining Unit Agreements.  The three extensions provide no wage increase in the first year and are attached to 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.  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 or ML&P).

Our members are the consumers of the electricity sold by us.  As of December 31, 2009, we had three major wholesale customers and 66,021 retail members receiving service at approximately 81,047 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 long-term gas contracts. The rest of our generating resources are hydroelectric facilities.  In 2009, 90 percent of our power was generated from gas, which included power generated at Nikiski, and 83 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 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 1,685 miles of distribution line and 533 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, 2009, we sold 2.5 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, 2009:

   
MWh
   
2009 Revenues
   
Percent of Sales Revenue
 
Direct retail sales:
                 
                   
Residential
    551,740     $ 82,365,366       28 %
Commercial
    631,965       79,735,641       28 %
Total
    1,183,705       162,101,007       56 %
                         
Wholesale sales:
                       
                         
MEA
    740,358       69,685,271       24 %
HEA
    472,136       42,865,550       15 %
Seward
    62,509       5,711,358       2 %
Total
    1,275,003       118,262,179       41 %
                         
Economy energy/other sales1
    76,968       7,280,870       3 %
                         
Total from sales
    2,535,676       287,644,056       100 %
                         
Miscellaneous energy revenue
            2,603,252          
                         
Total energy revenues
          $ 290,247,308          

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


Retail Customers

Service Territory
 
Our retail service area covers 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, 2009, we had 66,021 members receiving power from approximately 81,047 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 2009, our wholesale power contracts, including the fuel and purchased power components, produced $118.3 million in revenues, representing 41 percent of our total revenues and 50 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 2009, sales to MEA represented approximately 29 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, on advance notice given after RCA approval, to convert to a net-requirements purchaser of power, and as such MEA would have been obligated to buy its needed power from us net of its power needs satisfied from any of its own or AEG&T’s resources.  The notice period required for such conversion could have been up to five years after RCA approval, depending on which non-Chugach resources MEA proposed to use to satisfy its power needs.  MEA did not invoke this right.  If MEA had converted to a net-requirements purchaser under the contract, MEA could not have reduced its payment for power that it purchases from us below a certain minimum amount.  MEA would have been required to pay demand charges based upon the highest post-1985 historical coincident peak on the MEA system.  Therefore, if MEA had converted to net-requirements service, we would have continued to recover all or substantially all of the fixed costs now assigned to it.  Also, our revenues from energy sales to MEA would have partially declined in proportion to the reduction in the energy sold, but this decline would have been offset to an extent by savings in the variable costs associated with energy production.


MEA also had the right, on seven years advance notice after RCA approval, to convert to a take-or-pay purchase of a fixed amount of power, also subject to minimum payment requirements associated with prior purchases.  MEA did not invoke this right.  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.

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 (APUC), 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 2009, sales to HEA represented approximately 19 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 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 AEG&T 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.

On November 9, 2009, the RCA approved Amendment No. 3 to the Nikiski Cogeneration Plant System Use and Dispatch Agreement between Chugach and HEA effective November 6, 2009.  The contract modification recognizes HEA’s Sustainable Natural Alternative Power (SNAP) program and allows HEA to purchase energy from members that generate power from alternative power sources, including wind, solar and hydro resources.
 
Seward

We currently provide nearly all the power needs of the City of Seward.  In 2009, 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 Golden Valley Electric Association, Inc. (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 Oil Company (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 million cubic feet (MCF) per day to facilitate a 20 megawatt (MW) economy energy sale to GVEA.  The short-term agreement was extended through December 31, 2009.  We are currently using gas from existing contracts to make economy sales to GVEA as we negotiate other agreements.  Sales were and continue to be made under the terms and conditions of Chugach’s economy energy sales tariff.  Non-firm sales to GVEA have been 76,968 MWh, 254,372 MWh and 93,753 MWh for 2009, 2008, and 2007, 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 can seek changes in our base rates by filing general rate cases with the RCA.   On December 15, 2009, Chugach submitted a request to the RCA for approval to adjust base rates through the Simplified Rate Filing (SRF) process.  If approved Chugach would be allowed to adjust rates semi-annually as proposed.  Chugach would still be permitted to adjust base rates by filing general rate cases on an as-needed basis. 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. 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 Times Interest Earned Ratio (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 Amended and Restated Indenture, which became effective January 22, 2003, 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 CoBank Master Loan Agreement also requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense.  The Credit Agreement with NRUCFC, which became effective October 10, 2008, and governs loans and extended credit associated with Chugach’s 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, calculated using the average margins for interest of the two best years out of the three fiscal years most recently ended.

On February 6, 2003, we received Order U-01-108(26) from the RCA, based on our 2000 test year general rate case, which revised our overall rate-making TIER from 1.35 to 1.30. For the years ended December 31, 2009, 2008 and 2007, our Margins for Interest/Interest (MFI/I) was 1.27, 1.28 and 1.12, respectively.
 
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 fluctuations in the price of the commodity.  Recent examples include the closure of Agrium’s Kenai facilities in 2008; the largest exporter of value-added product from Alaska until 2007, because it could not acquire an economic supply of gas.  Offsetting this loss, Tesoro (one of the largest Alaska refiners producing gasoline, gasoline blendstocks, jet fuel, diesel fuel, heating oil, heavy fuel oils, marine diesel fuels, propane, and asphalt) refinery expanded its operations and capacity, including the production of ultra low sulfur gasoline and diesel.  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, the University of Alaska, tourism and support of natural resource development in the Interior and northern parts of the state.  Several gold mines 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)
 
2010
   
2011
   
2012
   
2013
   
2014
 
Retail                      
    1,179,633       1,179,224       1,178,818       1,178,494       1,178,631  
Wholesale                      
    1,265,305       1,257,273       1,269,444       1,276,715       844,396  
Losses                      
    139,585       139,285       139,653       139,867       125,587  
Total
    2,584,523       2,575,782       2,587,915       2,595,076       2,148,614  

Overall, retail and wholesale energy requirements are expected to remain relatively flat over the next four years.  The only known growth served by our 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 0.1 percent from 2010 to 2013, with retail sales staying flat and wholesale sales growing at a rate of 0.3 percent.  In 2014, HEA’s contract to purchase their requirements from Chugach expires, causing wholesale sales to fall by approximately one-third from the previous year.

Growth in wholesale energy sales are expected to be partially offset by expected consumer efficiency/conservancy and declining industrial sales by wholesale customer HEA.  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 and results of operations.  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 four 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 will be subject to interest rate risk at the time of refinancing.  In October of 2008, Chugach entered into a $300 million Unsecured Credit Agreement between National Rural Utilities Cooperative Finance Corporation (NRUCFC), KeyBank, CoBank, ACB (CoBank) and US Bank.  Commercial paper will be issued under this facility and will act as a bridge until Chugach converts Commercial Paper balances to long-term debt and will provide flexibility in paying down the 2011 and 2012 bullet maturities to allow us to approach either the public or private debt markets at an optimal time considering interest rates and market volatility.  The credit agreement expires on October 10, 2011.  At this time, management intends to renew this agreement although the terms may be different.  No assurance can be given that Chugach will be able to refinance the commercial paper facility with longer term debt or that it will be able to continue to access the commercial paper market.  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.” The potential 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 $112.6 million, or 39 percent and $104.6 million, or 37 percent in 2009 and 2008, respectively, of total sales revenue.  The HEA and MEA contracts expire January 1, 2014, and December 31, 2014, respectively.  All rates are approved by the RCA.


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 50 percent of Chugach’s power sales load and approximately 40 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.

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 revised 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.

Capital Markets

            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.  We are currently pursuing and expect to have access to long-term funding through several financing sources, including cooperative lenders, banks and private and public market placements.  We will also continue to pursue bond buy back opportunities when available.  We will be subject to interest rate risk and will need to negotiate acceptable terms at the time of refinancing.

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".  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 and receive information concerning its funding status annually.  The AEPF was 100 percent funded as of December 31, 2007, however, its assets declined in value during 2008.  If a funding shortfall in the AEPF exists, we 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.  If another participant in the AEPF goes bankrupt, we would become liable for a pro rata share of the bankrupt participant’s unpaid withdrawal liability only if we terminate participation.  This could result in an unexpected contribution requirement which could be substantial, and may have a material adverse effect on our cash position and other financial results.  The likelihood of this liability is difficult to predict because we do not know the financial condition of all employers in the plan.


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 and we may not be timely informed about the funding status of the Plan. We believe the Plan’s assets have likely declined substantially in value during 2008 and 2009.  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.  Contribution rate updates are difficult to predict.  An unexpected annual contribution rate increase could be substantial, and may have a material effect on our cash position and other financial results.

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.  We are vulnerable to this due to the advanced age of several of our gas-fired generating units.  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 regulated 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.  At this time we are not aware of any substantial risk to this project and expect the project to be completed on time and on budget.

Fuel Supply

In 2009, 90 percent of our power was generated from gas, which included power generated at Nikiski.  Our primary suppliers of natural gas are the Beluga River Field Producers and Marathon.  Chugach currently has a contract in place 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.  Chugach has a tentative agreement on a contract that would fill Chugach’s remaining unmet needs through the near future and expects to file that contract with the RCA for approval by the end of the first quarter of 2010.  The RCA approved inclusion of all fuel (gas) 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 allows Chugach to recover its current fuel and purchased power costs with minimal regulatory lag.  To the extent the regulated fuel recovery process does not provide for the timely recovery of fuel expenses, 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.

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 proved, 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 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 liquefied natural gas (LNG) storage and import options as transition gas until in-state gas options are developed.

Cooper Lake Hydropower Project

The Cooper Lake Hydropower 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 into 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 fuel surcharge process allows Chugach to recover its current fuel and purchased power costs and to recover under-recoveries and refund 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, 2009, Chugach had over-recovered $3.2 million and at December 31, 2008, Chugach had under-recovered $11.8 million. The cost under-recovery in 2008 was due primarily to unplanned maintenance and lower than expected output from our hydro facilities.  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.

Climate Change

There is substantial uncertainty about the potential impacts of climate change on Chugach's operations and whether climate change is 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.  The impact of events caused by climate change could range widely, but under certain conditions, could result in increased expenses. Chugach would also be required to comply with any future climate change regulation which could have a material effect on our results of 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

None

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 December of 2008 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 land.  We operate and maintain the Cooper Lake power plant pursuant to a 50-year license granted to us by the Federal Energy Regulatory Commission (FERC) in August 2007.  Cooper Lake Unit 2 was out of service since August of 2008 when it was forced out of service by damage to its turbine runner and wicket gates.  It was repaired, major maintenance performed, and the unit put back into service in May of 2009.  Inspection of Unit 1 during the Unit 2 outage identified damage on the Unit 1 runner as well, though it was not as extensive as Unit 2.  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.
 
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.

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 annual 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.  A combustion inspection was performed on Unit 3 in 2006 and again in 2008 and 2009 in accordance with the existing maintenance plan.  Beluga Unit 5 continued to have two combustion inspections per year in 2007, 2008 and 2009 due to high rates of wear observed on aging combustion parts.  One of these inspections in 2007 was a hot gas path inspection involving generator repairs.  Beluga Unit 6 was re-powered in 2000 and had major inspections in 2003 and 2006 with annual inspections in 2007, 2008 and 2009.  During the annual inspection in 2007 the last row of turbine blades was exchanged.  Beluga Unit 7 was re-powered in 2001 and had major inspections in 2004 and 2008 with annual inspections in 2007 and 2009.  Beluga Unit 8, a steam turbine, received a 25,000-hour inspection in 2005 and a major inspection in 2008 with an annual inspection in 2009. 


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.  Chugach and AML&P signed Participation, Operation and Maintenance (O&M) and Lease Agreements (Agreements) for this project on August 28, 2008. On November 17, 2008, Chugach executed a gas turbine purchase agreement for the purchase of three gas turbines with an option for a fourth turbine with General Electric Packaged Power (GEPP).  The option to purchase a fourth turbine expired on January 31, 2009. During 2009 Chugach executed several change orders associated with its purchase agreement with GEPP totaling $7.2 million, which included the purchase of a spare engine for maintenance purposes. Chugach made progress and milestone payments of $5.1 and $24.3 million in 2008 and 2009, respectively, and is expected to make payments of $29.2 million in 2010, pursuant to its purchase agreement and subsequent change orders with GEPP.   In December of 2008, Chugach purchased land adjacent to its Anchorage headquarters for SPP use.    Chugach executed an Owner’s Engineer Services Contract on May 12, 2009.  This contract expired on December 31, 2009, but was later renewed effective January 1, 2010.  Chugach made payments of $0.7 million in 2009, pursuant to its Owner’s Engineer Services Contract.  On January 5, 2010, Chugach executed a Services Contract for the shipment of the combustion turbine generators and related accessories.  Chugach is expected to make payments of $1.1 million in 2010 pursuant to this contract.  On February 25, 2010, Chugach purchased additional land adjacent to its Anchorage headquarters for the laydown of equipment displaced by the new power plant.  Chugach is currently proceeding with a Request for Proposal (RFP) for engineering, procurement and construction services as well as a steam turbine generator purchase agreement to be awarded in 2010.
   
 
The following matrix depicts nomenclature, run hours for 2009 and percentages of contribution and other historical information for all Chugach generation units.
 
Facility
   
Commercial Operation Date
 
Nomenclature
 
Rating
(MW)(1)
   
Run Hours (2009)
   
Percent of Total Run Hours
   
Percent of
Time
Available
 
Beluga Power Plant (3)
                           
1     1968  
GE Frame 5
    19.6       681.8       1.6       97.0  
2     1968  
GE Frame 5
    19.6       504.4       1.2       95.0  
3     1972  
GE Frame 7
    64.8       4,958.9       11.6       91.4  
5     1975  
GE Frame 7
    68.7       5,643.6       13.2       94.1  
6     1975  
AP 11DM-EV
    79.2       8,633.9       20.2       98.6  
7     1978  
AP 11DM-EV
    80.1       8,575.4       20.0       97.9  
8     1981  
BBC DK021150(2)
    53.0       7,530.3       17.6       86.0  
Bernice Lake Power Plant
        385.0                          
                                     
2     1971  
GE Frame 5
    19.0       942.3       2.2       85.3  
3     1978  
GE Frame 5
    26.0       620.1       1.5       92.3  
4     1981  
GE Frame 5
    22.5       268.0       0.6       90.3  
Cooper Lake Hydroelectric Plant
        67.5                          
                                     
1     1960  
BBC MV 230/10
    9.6       1,330.9       3.1       18.7  
2     1960  
BBC MV 230/10
    9.6       2,935.0       6.9       58.7  
IGT Power Plant
          19.2                          
                                       
1     1964  
GE Frame 5
    14.1       35.8       0.1       91.5  
2     1965  
GE Frame 5
    14.1       26.3       0.1       91.5  
3     1969  
Westinghouse 191G
    18.5       48.0       0.1       91.5  
                46.7                          
Eklutna Hydroelectric Plant
                                   
1     1955  
Newport News
    5.8 (4)     N/A (5)     N/A (5)     95.4  
2     1955  
Oerlikon custom
    5.9 (4)     N/A (5)     N/A (5)     94.1  
 
        11.7       42,734.7       100.00          
System Total
              530.1                          

(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.  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, 2009, our transmission and distribution assets included 42 substations and 533 miles of transmission lines, which included 128 miles of leased transmission lines and Chugach’s share of the Eklutna transmission line, 916 miles of overhead distribution lines and 769 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 the Amended and Restated Indenture, all of Chugach’s bonds are general unsecured and unsubordinated obligations.  Chugach is prohibited from creating or permitting to exist any mortgage, lien, pledge, security interest or encumbrance on our 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 we equally and ratably secure all bonds subject to the Amended and Restated Indenture, except that we may incur secured indebtedness in an amount not to exceed $5 million or enter into sale and leaseback or similar agreements.

Many of our 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 our maximum annual liability for our take-or-pay obligations is approximately $5.4 million. 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 $34 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.

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 2009, 90 percent of our power was generated from natural gas, which included power generated at Nikiski, and 83 percent of that gas-fired generation took place at Beluga.

Total gas usage in 2009 was approximately 26 BCF. Our primary sources of natural gas are divided among four long-term contracts with major oil and gas companies. All of the production came from Cook Inlet, Alaska.  Marathon Oil Company provided 52 percent, while ConocoPhillips Alaska Inc., AML&P, and Chevron U.S.A. each provided 16 percent of Chugach’s gas requirements. Approximately 27 BCF of gas remains on the current contracts. We estimate that our contract gas with Marathon will run-out in 2010 and expect the remaining three contracts to run-out in early 2011.  A new contract with ConocoPhillips will provide gas, now estimated to be 62 BCF, beginning in 2010.  Chugach has a tentative agreement on a contract that would fill Chugach’s remaining unmet needs through the near future and expects to file that contract with the RCA for approval by the end of the first quarter of 2010.  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 COP in 2009.  The new contract will provide 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 new contract is now 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 will meet a portion of Chugach’s base load requirements, while “Firm Variable Quantity” gas will meet 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.

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.  ($5.75 per MCF on January 1, 2010), exclusive of taxes.  There will be 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.

Pricing for firm variable gas purchased between January 1, 2010, and March 31, 2011, will be the 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.  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.” ($10.39 per MCF on January 1, 2010), 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 Marathon contract (described below) ($3.44 per thousand cubic feet (MCF) on January 1, 2010), 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) ($4.44 per MCF on January 1, 2010), plus taxes.
 
Marathon
 
We entered into a requirements contract with Marathon in September 1988 for an initial commitment of 215 BCF.  The contract expires on the earlier of December 31, 2015, or the date on which Marathon has delivered to us a volume of gas in total, which equals 215 BCF.  Chugach estimates that the contract will run-out in 2010.  The base price for gas under the Marathon contract is $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.  The price on January 1, 2010, exclusive of taxes, was $4.04 per MCF.
 
Under the terms of the Marathon contract, Marathon provides 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.  For the last year of the Marathon contract, year 2010, Marathon volumes are 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 are sharing the gas deliverability of the 40% gas volume for the entire year.

ENSTAR
 
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.


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.  In 2008 the EPA vacated regulations to limit mercury emissions from fossil-fired steam-electric generating facilities.

New Clean Air Act regulations impacting electric utilities may result from future events or may result from new regulatory programs.  On October 30, 2009, 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.

In March 2007, Chugach conducted emissions testing at the Bernice Lake Power Plant which indicated that two of the gas turbines at the facility were exceeding the New Source Performance Standards (NSPS) emission limit for nitrogen oxides (NOx).  Chugach voluntarily limited the power output of these turbines to ensure interim compliance with the NSPS regulations until a water injection system to control NOx emissions from the turbines was installed and operational.  With the water injection system, Chugach is able to fully utilize the power output from these turbines while complying with the NSPS regulations.


The Alaska Department of Environmental Conservation (ADEC) issued a Notice of Violation (NOV) on March 26, 2008, regarding the NSPS NOx emission limit exceedances.  Chugach entered into a settlement with ADEC regarding the NOV for the past NSPS non-compliance.  Chugach and the ADEC signed the settlement agreement on February 18, 2009.  As part of the settlement, Chugach paid a civil penalty of $112,161 to ADEC on April 3, 2009, bringing the issue to a close.

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.

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
 
2009
   
2008
   
2007
   
2006
   
2005
 
                               
Electric plant, net:
                             
In service
  $ 414,002,926     $ 432,460,336     $ 438,239,286     $ 439,268,514     $ 435,474,237  
                                         
Construction work in
                                       
Progress
    48,383,610       25,151,072       17,712,884        20,683,335        32,505,401  
                                         
Electric plant, net
    462,386,536       457,611,408       455,952,170       459,951,849       467,979,638  
                                         
Other assets
    102,912,190       119,080,561       101,773,948       103,733,881       97,155,862  
                                         
Total assets
  $ 565,298,726     $ 576,691,969     $ 557,726,118     $ 563,685,730     $ 565,135,500  
                                         
Capitalization:
                                       
Long-term debt
    307,301,819       354,383,506       345,423,500       350,803,530       364,532,099  
                                         
Equities and margins
    156,320,597       153,766,999       149,310,436       150,716,100       145,039,152  
                                         
Total capitalization
  $ 463,622,416     $ 508,150,505     $ 494,733,936     $ 501,519,630     $ 509,571,251  
                                         
Equity Ratio1
    33.7 %     30.3 %     30.2 %     30.1 %     28.5 %
                                         
Summary Operations Data
                                       
                                         
Operating revenues
  $ 290,247,308     $ 288,292,112     $ 257,443,919     $ 267,542,713     $ 225,697,349  
                                         
Operating expenses
    264,872,577       260,580,365       232,367,023       234,969,329       194,823,965  
                                         
Interest expense, net
    20,606,349       22,532,797       23,712,797       24,010,874       22,586,054  
                                         
Net operating margins
    4,768,382       5,178,950       1,364,099       8,562,510       8,287,330  
                                         
Nonoperating margins
    891,966       1,232,800       1,521,157       1,476,549       1,227,401  
                                         
Assignable margins
  $ 5,660,348     $ 6,411,750     $ 2,885,256     $ 10,039,059     $ 9,514,731  
                                         
Margins for Interest Ratio2
    1.27       1.28       1.12       1.41       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 Amended and Restated Indenture 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 prospectus 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.  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 authorized TIER for rate-making 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 reflects non-operating 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, 2009, compared to the years ended December 31, 2008, and December 31, 2007 – Expenses.”  We achieved TIERs for the past five years as follows:

Year
TIER
2009
1.28
2008
1.30
2007
1.12
2006
1.41
2005
1.41


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, a 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.  We recover operating and maintenance and other non-fuel and purchased power costs through our base rates established through an order of the RCA following a general rate case, where we propose a rate increase or decrease for each class of customer.  The RCA may authorize, after a notice period, rate changes on an interim and refundable basis.

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 No. U-06-134).”  There were no base rate changes for our retail customers or for our wholesale customers in 2007.

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).

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.

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.  The Commission has not yet issued an order on Chugach’s request.

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 estimated increase to Chugach’s retail end-users was approximately 1.7 percent, while the increase to retail end-users of Chugach’s wholesale customers was approximately 0.9 percent.  Chugach requested that the proposed rates become effective on an interim and refundable basis beginning August 7, 2009.

On August 7, 2009, the RCA suspended Chugach’s filing into Docket U-09-080 and issued Order No. 1.  The RCA indicated that it would issue a final order in this case no later than September 16, 2010.  The RCA did not issue a decision on Chugach’s interim rate request.  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 issued Order No. 2 granting Chugach’s original request that the proposed rates go into effect on an interim and refundable basis.

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, 2009, compared to the years ended December 31, 2008, and December 31, 2007

Margins

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

   
2009
   
2008
   
2007
 
Net Operating Margins
  $ 4,768,382     $ 5,178,950     $ 1,364,099  
Non-Operating Margins
  $ 891,966     $ 1,232,800     $ 1,521,157  
Assignable Margins
  $ 5,660,348     $ 6,411,750     $ 2,885,256  

The decrease in assignable margins in 2009 from 2008 of $751.4 thousand, or 11.7 percent, was due primarily to a decrease in sales revenue, an increase in depreciation and administrative and general expense and a decrease in interest income, which was partially offset by a decrease in net interest expense. The increase in assignable margins in 2008 from 2007 of $3.5 million, or 122.2 percent, was due primarily to a decrease in transmission, distribution and 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, 2009, compared to the years ended December 31, 2008, and December 31, 2007 – Expenses.

Non-operating margins include interest income, allowance for funds used in construction, capital credits and patronage capital allocations.  Non-operating 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.  Non-operating margins decreased in 2008 from 2007 by $288.4 thousand, or 19.0 percent due primarily to lower interest income as a result of a lower cash balance and lower interest rates and lower Allowance for Funds Used During Construction (AFUDC) as a result of lower 2007 margins which is used in the average equity balance calculation of AFUDC.

Revenues

Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. 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.


In 2008, operating revenues were $30.8 million, or 12.0 percent higher than in 2007 due primarily to higher fuel costs recovered in revenue through the fuel surcharge process and an increase in wholesale and economy revenue.  These increases were partially offset by a decrease in retail revenue due to a decrease in kWh sales.

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 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.

Overall, retail revenue increased in 2008 from 2007.  Base revenue decreased due to lower kWh sales caused by a change in consumer consumption patterns, as well as base rates charged to retail customers decreased effective June 1, 2008, as a result of Chugach’s 2005 Test Year Rate Case.  This base revenue decrease was more than offset by higher fuel costs recovered in revenue through the fuel surcharge process due in part to higher fuel prices and the impact of credits received in 2007 for reduced fuel production taxes.

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.

Wholesale revenue was higher in 2008 from 2007.  Base revenue increased due to the June 1, 2008, base rate increase charged to wholesale customers as a result of Chugach’s 2005 Test Year Rate Case and higher kWh sales.  The wholesale revenue increase was also due to higher fuel costs recovered in revenue through the fuel surcharge process due to higher fuel prices and the impact of credits received in 2007 for reduced fuel production taxes.

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 $28.6 million, $27.7 million and $26 million to Chugach’s fixed costs for the years ended December 31, 2009, 2008 and 2007, 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, 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 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, 2008, and 2007.
   
Base Rate Sales Revenue
   
Fuel and Purchased Power Revenue
   
Total Revenue
 
   
2008
   
2007
   
% Variance
   
2008
   
2007
   
% Variance
   
2008
   
2007
   
% Variance
 
                     
 
                               
Retail
                   
 
                               
Residential
  $ 46.4     $ 46.8       (0.9 %)   $ 33.9     $ 30.1       12.6 %   $ 80.3     $ 76.9       4.4 %
Small Commercial
  $ 8.4     $ 8.5       (1.2 %)   $ 7.2     $ 6.4       12.5 %   $ 15.6     $ 14.9       4.7 %
Large Commercial
  $ 28.3     $ 29.5       (4.1 %)   $ 31.8     $ 28.2       12.8 %   $ 60.1     $ 57.7       4.2 %
Lighting
  $ 1.3     $ 1.3       0.0 %   $ 0.2     $ 0.1       100.0 %   $ 1.5     $ 1.4       7.1 %
Total Retail
  $ 84.4     $ 86.1       (2.0 %)   $ 73.1     $ 64.8       12.8 %   $ 157.5     $ 150.9       4.4 %
                                                                         
Wholesale
                                                                       
HEA
  $ 11.4     $ 10.5       8.6 %   $ 29.8     $ 26.3       13.3 %   $ 41.2     $ 36.8       12.0 %
MEA
  $ 20.9     $ 19.0       10.0 %   $ 42.6     $ 37.6       13.3 %   $ 63.5     $ 56.6       12.2 %
SES
  $ 1.1     $ 1.2       (8.3 %)   $ 3.7     $ 3.2       15.6 %   $ 4.8     $ 4.4       9.1 %
Total Wholesale
  $ 33.4     $ 30.7       8.8 %   $ 76.1     $ 67.1       13.4 %   $ 109.5     $ 97.8       12.0 %
                                                                         
Economy Sales
  $ 4.6     $ 1.5       206.7 %   $ 13.9     $ 4.2       231.0 %   $ 18.5     $ 5.7       224.6 %
Miscellaneous
  $ 2.8     $ 3.0       (6.7 %)   $ 0.0     $ 0.0       0.0 %   $ 2.8     $ 3.0       (6.7 %)
                                                                         
Total Revenue
  $ 125.2     $ 121.3       3.2 %   $ 163.1     $ 136.1       19.8 %   $ 288.3     $ 257.4       12.0 %


The major components of our operating revenue for the year ending December 31 were as follows:
   
2009
   
2009
   
2008
   
2008
   
2007
   
2007
 
   
Sales (MWh)
   
Revenue
   
Sales (MWh)
   
Revenue
   
Sales (MWh)
   
Revenue
 
                                     
Retail
    1,183,705     $ 162,101,007       1,205,832     $ 157,549,359       1,206,037     $ 150,891,863  
Wholesale:
                                               
HEA
    472,136       42,865,550       517,368       41,133,287       522,901       36,812,475  
MEA
    740,358       69,685,271       742,666       63,500,034       724,465       56,566,527  
Seward
    62,509       5,711,358       63,734       4,798,286       63,941       4,454,186  
Total Wholesale
    1,275,003       118,262,179       1,323,768       109,431,607       1,311,307       97,833,188  
Economy energy
    76,968       7,280,870       256,105       18,526,481       93,753       5,745,732  
Other
    N/A       2,603,252       N/A       2,784,665       N/A       2,973,136  
Total revenue
    2,535,676     $ 290,247,308       2,785,705     $ 288,292,112       2,611,097     $ 257,443,919  


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 charged GVEA a rate sufficient to recover the gas cost, the costs of incremental operations and maintenance expense resulting from increased use of our generators for GVEA, and an agreed-upon margin for each kWh sold.  Consequently, sales to GVEA did not significantly affect margins. 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 million cubic feet (MCF) per day to facilitate a 20 MW economy energy sale to GVEA.  The short-term agreement was extended through December 31, 2009.  We are currently using gas from existing contracts to make economy sales to GVEA as we negotiate other agreements.  Sales were and continue to be made under the terms and conditions of Chugach’s economy energy sales tariff.  In 2009, 2008, and 2007, economy sales to GVEA constituted approximately 3 percent, 6 percent, and 2 percent, respectively, of our sales revenues. Economy energy revenue decreased in 2009 from 2008 due primarily to the expiration of our agreement with GVEA.  Economy energy revenue increased in 2008 from 2007 due to transmission line work, maintenance on several Beluga units and contracted fuel limitations in 2007.

Expenses

The major components of our operating expenses for the years ended December 31 were as follows:
   
2009
   
2008
   
2007
 
Fuel
  $ 136,416,761     $ 137,894,553     $ 106,023,734  
Power production
    16,406,911       16,718,777       16,171,717  
Purchased power
    35,690,476       31,486,621       33,947,828  
Transmission
    5,709,578       5,841,405       6,781,166  
Distribution
    12,740,381       12,398,832       13,716,105  
Consumer accounts
    5,259,348       5,396,662       4,899,878  
Administrative, general and other
    20,518,688       20,014,239       21,776,968  
Depreciation
    32,130,434       30,829,276       29,049,627  
Total operating expenses
  $ 264,872,577     $ 260,580,365     $ 232,367,023  

Fuel

Chugach recognizes actual fuel expense as incurred. 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.  Fuel expense increased by $31.9 million, or 30.1 percent, in 2008 from 2007 due primarily to an increase in MCF used as a result of higher economy sales, the unavailability of our steam generating unit, Beluga Unit 8, due to maintenance and a higher average effective fuel price.  The increase was also due in part to the impact of credits received in 2007 for reduced fuel production taxes.  In 2008, Chugach used 30,792,658 MCF of fuel at an average effective price of $5.13 per MCF, which did not include 3,895,468 MCF of fuel that is recorded as purchased power expense.


Power Production

Power production expense did not materially change in 2009 from 2008.
 
Power production expense increased $547.1 thousand, or 3.4 percent, in 2008 from 2007 due primarily to the amortization associated with the Beluga River Gas Compression project, as well as the accelerated amortization of the prior Beluga Unit 8 overhaul caused by a change to the maintenance schedule.

Purchased Power

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.  Purchased power costs decreased $2.5 million, or 7.2 percent, in 2008 from 2007 due primarily to less MWh purchased, which was somewhat offset by a higher price caused by higher fuel prices.  Transmission line work and other maintenance activities in 2007 limited our generation, resulting in higher purchased power costs in 2007.  In 2008, Chugach purchased 483,742 MWh of energy at an average effective price of 6.24 cents per kWh.

Transmission

Transmission expense did not materially change in 2009 from 2008.

Transmission expense decreased $939.8 thousand, or 13.9 percent, in 2008 from 2007 due primarily to lower labor expense related to substation maintenance as well as lower information services allocated compliance costs.

Distribution

Distribution expense did not materially change in 2009 from 2008.

Distribution expense decreased $1.3 million, or 9.6 percent, in 2008 from 2007 due primarily to lower labor and professional services associated with line maintenance, as well as lower information services allocated compliance costs.

Consumer Accounts

Consumer accounts expense did not materially change in 2009 from 2008.

Consumer accounts expense, which represents costs associated with maintaining customer accounts and membership, increased $496.8 thousand, or 10.1 percent, in 2008 from 2007 due primarily to an increase in uncollectible accounts and higher advertising and imaging costs associated with capital credit retirements.

Administrative, General and Other Charges

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.


Administrative, general and other charges decreased $1.8 million, or 8.1 percent, in 2008 from 2007 due primarily to lower professional services and information services allocated compliance costs in 2007.  The decrease was also due to a decrease in credit card fees in 2008 compared to 2007.

Depreciation

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.

Depreciation expense increased $1.8 million, or 6.1 percent, in 2008 from 2007 due in part to a change in depreciation rates as a result of Chugach’s 2005 Test Year Rate Case, as well as the continued closeout of construction projects.

Interest

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 continued principal payments on our CoBank debt.

Interest on long-term obligations decreased $2.9 million, or 12.1 percent, in 2008 from 2007 due primarily to the use of our NRUCFC line of credit to redeem the outstanding principal amount and pay accrued interest on the 2002 Series B Bonds in March of 2008.  The decrease was also due to continued principal payments as well as lower interest rates in 2008 compared to 2007.

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 on short-term borrowing increased $1.6 million in 2008 from 2007 due primarily to the use of the NRUCFC line of credit described above and the increased use of our CoBank line of credit in 2008 compared to 2007.  This increase is net of the affects of a decrease in interest rates in 2008 compared to 2007.

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.


 Interest charged to construction decreased $170.7 thousand, or 27.7 percent, in 2008 from 2007 due primarily to a lower weighted average rate during 2008 of 5.1 percent compared to 6.3 percent during 2007.

Patronage Capital (Equity)

The following table summarizes our patronage capital and total equity position for the years ended December 31:
 
   
2009
   
2008
   
2007
 
                   
Patronage capital at beginning of year
  $ 142,009,998     $ 138,713,338     $ 141,117,620  
Retirement of capital credits
    (3,442,125 )     (3,115,090 )     (5,289,538 )
Assignable margins
    5,660,348       6,411,750       2,885,256  
Patronage capital at end of year
    144,228,221       142,009,998       138,713,338  
Other equity1
    12,092,376       11,757,001       10,597,098  
Total equity at end of year
  $ 156,320,597     $ 153,766,999     $ 149,310,436  
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 $3,442,125, $3,115,090, and $5,289,538 in capital credits for the years ended December 31, 2009, 2008, and 2007, 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. For the years 1997, 1998 and 1999, wholesale capital credits were retired on a 10-year cycle pursuant to a prior settlement agreement.  In 2009, 2008 and 2007, $1,674,809, $1,478,779 and $79,079, respectively, of 1999, 1998 and 1997 wholesale capital credits were retired to MEA, HEA and SES.

The Amended and Restated Indenture prohibits us from making any distributions, payment or retirement of patronage capital to our customers if an event of default under the Amended and Restated Indenture exists.  Otherwise, we may make distributions to our members in each year equal to the lesser of 5 percent of our patronage capital or 50 percent of assignable margins for the prior fiscal year.  This restriction does not apply if, after the distribution, our aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30 percent of our total liabilities and equities and margins.

Under our Master Loan Agreement with CoBank, Chugach is prohibited from making any distribution of patronage capital to Chugach’s customers if an event of default under the 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 decreased $11.4 million, or 2.0 percent, from December 31, 2008, to December 31, 2009.  The decrease was due in part to a $4.0 million, or 53.2 percent decrease in cash and cash equivalents.  The decrease was also due to an $11.5 million, or 97.6 percent decrease in fuel cost under-recovery due to the collection of fuel and purchased power costs through the fuel surcharge process.  The decrease was also due to a $0.3 million, or 18.3 percent decrease in prepayments and a $1.5 million, or 6.5 percent decrease in deferred charges due to the amortization of deferred charges which exceeded the costs associated with the overhauls of units at the Cooper Lake Power Plant, fuel supply negotiations and the charges associated with Cooper Lake license requirements.  The decreases were offset by a $4.8 million, or 1.0 percent increase in net utility plant due to extension and replacement of plant in excess of depreciation expense, as well as a $1.2 million, or 4.1 percent, increase in materials and supplies due primarily to the purchase of materials for planned generation and distribution projects.

Liabilities

Total liabilities decreased by $13.9 million, or 3.3 percent, in 2009 as compared to 2008.  Contributors to this change include a $2.9 million, or 100 percent, decrease in promissory notes payable caused by the payment of the note associated with the property Chugach acquired for construction of an additional electrical generation facility.  The decrease also includes a $7.5 million, or 100 percent decrease in short-term obligations due to the payment of the outstanding balance on the CoBank line of credit.  Fuel payable also decreased $13.8 million, or 48.6 percent, due primarily to less fuel purchased as a result of lower kWh and economy sales.  Other liabilities decreased $432.2 thousand, or 25.9 percent, due primarily to a decrease in the municipal underground ordinance payable. The decrease was also due to a $676.5 thousand, or 29.4 percent decrease in deferred credits caused primarily by the transfer of customer advances to construction projects.  These decreases were offset by a $3.5 million, or 100 percent increase in fuel cost over-recovery due to the over-collection of fuel and purchased power costs through the fuel surcharge process.  The net of total long-term obligations and current installments of long-term debt and commercial paper increased $4.1 million, or 1.2 percent, caused by the difference in commercial paper borrowing in 2009 compared to the NRUCFC line of credit in 2008, which was somewhat offset by the principal payments made on CoBank 2, 3, 4 and 5 in 2009.  Salaries, wages and benefits payable increased $474.7 thousand, or 8.7 percent and accounts payable increased $3.2 million, or 45.9 percent due to the timing of cash payments on invoices for good and services.


Equities and Margins

           Total margins and equities increased $2.6 million, or 1.7 percent, in 2009 compared to 2008 due to a $2.2 million, or 1.6 percent, net increase in patronage capital ($5.6 million increase in margins coupled with a $3.4 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 2009.  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, 2009:
 
Contractual cash obligations: (In thousands)
Payments Due By Period

   
Total
   
2010
      2011-2012       2013-2014    
Thereafter
 
                                   
Long-term debt, including current portion
  $ 311,420     $ 4,118     $ 275,545     $ 4,343     $ 27,414  
Long-term interest expense1
    33,824       18,166       11,660       1,328       2,670  
Commercial Paper2
    51,500       51,500       0       0       0  
Bradley Lake3
    48,744       3,696       7,366       7,332       30,350  
Fuel and fuel transportation expense4
    795,620       94,374       355,474       283,029       62,743  
Gas turbine purchase agreement5
    29,192       29,192       0       0       0  
Transportation services contract6
    1,116       1,116       0       0       0  
Total
  $ 1,271,416     $ 202,162     $ 650,045     $ 296,032     $ 123,177  

1 Long-term interest expense includes fixed and variable rates.  Variable rates are based on rates at December 31, 2009, for years 2010-2014 and thereafter.  (See “Part II – Item 8 – Financial Statements and Supplementary Data – Note (8) Debt.”)
2 At December 31, 2009, Chugach’s Commercial Paper Program was backed by a $300 million Unsecured Credit Agreement between NRUCFC, KeyBank, CoBank and US Bank, which funds capital requirements.  At December 31, 2009, there was $51.5 million of commercial paper outstanding, therefore, the available borrowing capacity under the Commercial Paper Program was $248.5 million and could be used for future operational and capital funding requirements.
3 Estimated annual cost
4 Estimated committed and uncommitted fuel and fuel transportation expense
5 In accordance with the General Electric Packaged Power gas turbine purchase agreement executed on November 17, 2008 and subsequent change orders
6 In accordance with the Services Contract for the shipment of the combustion turbine generators and related accessories


         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.”)  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.  Chugach and AML&P signed Participation, O&M and Lease Agreements (Agreements) for this project on August 28, 2008. On November 17, 2008, Chugach executed a gas turbine purchase agreement for the purchase of three gas turbines with an option for a fourth turbine with GEPP.  The option to purchase a fourth turbine expired on January 31, 2009. During 2009 Chugach executed several change orders associated with its purchase agreement with GEPP totaling $7.2 million, which included the purchase of a spare engine for maintenance purposes.  Chugach made progress and milestone payments of $5.1 and $24.3 million in 2008 and 2009, respectively, and is expected to make payments of $29.2 million in 2010, pursuant to its purchase agreement and subsequent change orders with GEPP.   In December of 2008, Chugach purchased land adjacent to its Anchorage headquarters for SPP use.  Chugach executed an Owner’s Engineer Services Contract on May 12, 2009.  This contract expired on December 31, 2009, but was later renewed effective January 1, 2010.  Chugach made payments of $0.7 million in 2009, pursuant to its Owner’s Engineer Services Contract.  On January 5, 2010, Chugach executed a Services Contract for the shipment of the combustion turbine generators and related accessories.  Chugach is expected to make payments of $1.1 million in 2010 pursuant to this contract.  On February 25, 2010, Chugach purchased additional land adjacent to its Anchorage headquarters for the laydown of equipment displaced by the new power plant.  Chugach is currently proceeding with a RFP for engineering, procurement and construction services as well as a steam turbine generator purchase agreement to be awarded in 2010.


Liquidity And Capital Resources

Lines of Credit

Chugach maintained a $7.5 million line of credit with CoBank.  The line of credit expired on October 31, 2009, and was subject to annual renewal at the discretion of the parties.  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.  Chugach had activity on this line of credit in the first half of 2009, however, this line of credit wasn’t utilized in the third or fourth quarters of 2009 and had no outstanding balance upon its expiration on October 31, 2009.  At December 31, 2008, the outstanding balance on this line of credit was $7.5 million.  The borrowing rate is calculated using the CoBank Base Rate on the first business day of the week plus 3 percent.  The average borrowing rate for 2009 and 2008 was 2.25 percent and 3.82 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 permanently reduced to $50 million on January 30, 2009.  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 described below.  In February of 2009, Chugach repaid the balance on this line of credit by issuing additional commercial paper.

 In March of 2008 Chugach borrowed $29.7 million on this line of credit to redeem the outstanding principal amount and pay accrued interest on the 2002 Series B Bonds.  Chugach also utilized this line of credit for general working capital in 2008 and had a balance of $43.0 million at December 31, 2008.  The borrowing rate on the transaction to redeem the 2002 Series B Bonds was 2.75 percent at December 31, 2008.  The borrowing rate on all other transactions at December 31, 2009 and 2008 was 4.95 percent and 5.00 percent, respectively and is calculated using the total rate per annum as may be fixed by CFC and will not exceed the Prevailing Prime Rate, plus one percent per annum.  The NRUCFC line of credit expires October 14, 2012.

Commercial Paper

Over the next five years Chugach anticipates incurring increased amounts of capital expenditures due to the construction of a gas fired generation unit, on-going capital needs and the refinancing of $150 million of 2001 Series A Bonds that is due March 15, 2011, and $120 million of 2002 Series A Bonds due February 1, 2012.  Commercial paper is being issued and will act as a bridge until Chugach converts Commercial Paper balances to long term debt and to refinance the 2011 and 2012 Series A bonds.  Chugach’s Commercial Paper program is backed by a $300 million Unsecured Credit Agreement, executed on October 10, 2008, between NRUCFC, KeyBank, CoBank and US Bank. The agreement expires on October 10, 2011, however, at this time, management intends to renew this agreement although the terms may be different.  On January 30, 2009, Chugach issued $36.0 million of commercial paper to repay its NRUCFC line of credit.  On February 5, 2009, Chugach issued $10.0 million of commercial paper to repay the balance of its NRUCFC line of credit.  Chugach continued to issue additional commercial paper in 2009 and had a balance of $51.5 million outstanding at December 31, 2009.  Our commercial paper can be repriced between one and two hundred and seventy days.  The following table provides information regarding average commercial paper balances outstanding (dollars in millions), as well as corresponding weighted average interest rates:

 
 
 
Month
Average
Balance
Weighted Average
Interest Rate
January 2009
36.0
1.17
February 2009
44.6
1.48
March 2009
46.6
1.19
April 2009
47.0
0.60
May 2009
43.0
0.53
June 2009
41.7
0.49
July 2009
41.5
0.44
August 2009
48.6
0.36
September 2009
53.1
0.32
October 2009
54.2
0.28
November 2009
52.9
0.26
December 2009
53.5
0.26

Principal maturities and sinking fund payments of our outstanding indebtedness, including commercial paper, at December 31, 2009 are set forth below:

Year Ending
December 31
 
Sinking Fund Requirements
   
Principal Maturities
   
Total
 
                   
2010
    0       55,618,028       55,618,028  
2011
    150,000,000       2,851,501       152,851,501  
2012
    120,000,000       2,693,543       122,693,543  
2013
    0       2,076,355       2,076,355  
2014
    0       2,266,145       2,266,145  
Thereafter
    0       27,414,275       27,414,275  
    $ 270,000,000     $ 92,919,847     $ 362,919,847  


During 2009 we spent approximately $37.5 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 2010 through 2014 as contained in the Capital Improvement Plan (CIP), which was approved on October 28, 2009:
 
 
Year
 
Estimated Expenditures
2010
 
$111.9 million
2011
 
$131.9 million
2012
 
$65.5 million
2013
 
$44.2 million
2014
 
$20.9 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

Procuring a new, highly efficient power generation facility, natural gas contracts, 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 2013.  Currently, major components have been ordered and engineering is moving forward with the anticipation of awarding an Engineer, Procure and Construct (EPC) contract in May of 2010.  Chugach’s interim financing for the plant will come from a commercial paper borrowing program that was established via a $300 million unsecured credit agreement in 2008.  Given the past volatility in the bond and commercial paper market, close attention will be given to the timing and type of permanent financing Chugach obtains for the new plant and other capital additions.

Chugach will 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 the 2011 and 2012 maturing long-term debt refinancing and requirements for new, long-term financing for our capital additions that are expected to begin in 2010.


On May 12, 2009, Chugach submitted a new long-term natural gas supply contract with COP to the RCA.  The new contract will provide gas beginning in 2010 and terminating December 31, 2016.  The total amount of gas under the contract is now estimated to be 62 BCF.  The new contract is now 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 RCA approved the gas supply contract between Chugach and COP effective August 21, 2009.  The RCA also approved inclusion of all fuel (gas) and transportation costs related to the contract in the calculation of Chugach’s fuel surcharge process.  Chugach has a tentative agreement on a contract that would fill Chugach’s remaining unmet needs through the near future and expects to file that contract with the RCA for approval by the end of the first quarter of 2010.  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 proved, 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 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 liquefied natural gas (LNG) storage and import options as transition gas until in-state gas options are developed.
 
 
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.  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.  Neither MEA nor HEA have significant resources in place at this time that would indicate a complete reduction in service from Chugach is possible.  Due to the lack of this necessary physical evidence, Chugach is preparing for a continuation of some business with HEA and MEA.  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.  Chugach, however, is continuing to pursue replacement sources of revenue through potential new firm power sales agreements and revised 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 Plan called for a migration to alternative fuel sources for one half of the state by 2025.  This is in concert with Chugach’s conceptual goal to move from a “90 – 10” (90 percent natural gas fuel source – 10 percent alternative fuel source) generation mix to a “10 – 90” generation mix.  Chugach’s challenge in the coming years will be to find low cost, highly efficient generation projects that fulfill this goal.

On March 5, 2009, the governor of Alaska transmitted a bill to the Alaska State Legislature that creates the Greater Railbelt Energy and Transmission Corporation (GRETC).  In the Governor’s transmittal letter, she identified the purpose of the corporation was to “plan for the financing, acquisition, construction, ownership, and operation of necessary electric power generation and transmission assets and services that would be necessary to provide the Railbelt with adequate, reliable, safe, and stable electric power and transmission services at the lowest feasible long-term cost.”  The legislation (HB 182 and SB 143) was introduced in both the House and Senate special committees on energy and is being held in committee until the 2010 legislative session.  In the interim, the six Railbelt utility governing bodies agreed to form a special task force to further discuss the legislation and make recommendations to the state administration and the legislative committees.  On November 13, 2009, Chugach, MEA and Seward issued a joint resolution in support of the GRETC concept.  The three organizations outlined their vision in a resolution that noted many of the benefits the new organization would bring. On January 27, 2010, the Chugach Board of Directors passed a resolution supporting HB 182, enacting the establishment of GRETC.  The task force of the boards of all Railbelt electric utilities will continue their work on GRETC and related issues.

Chugach has three CBA with the IBEW, which expire on June 30, 2010.  We also have an agreement with the HERE which also expires on June 30, 2010.  On February 24, 2010, the Board of Directors approved an extension of the IBEW Collective Bargaining Unit Agreements.  The three extensions provide no wage increase in the first year and are attached to the 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. 

Ratings

Our bond ratings with Fitch Investor Service, Moody’s Investors Service and Standard & Poors Ratings Services remained unchanged in 2009 at A- Stable, A3 Stable and A- Stable, respectively.  In 2008, Standard & Poors Ratings Services and Moody’s Investors Services rated our Commercial Paper A-1 and P-2, respectively.  Management does not believe this rating will materially affect interest rates associated with future financing.

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, 2009.

Electric Utility Regulation

Chugach is subject to regulation by the RCA. The RCA sets the rates Chugach is permitted to charge customers based on 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 $9,417,906 and $10,024,312 of unbilled retail revenue at December 31, 2009 and 2008, 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 2009-01 “Topic 105 – Generally Accepted Accounting Principles – amendments based on – Statement No. 168 – The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles”

In June 2009, the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (ASC) Update 2009-01, “Topic 105 – Generally Accepted Accounting Principles – amendments based on Statement No. 168 – The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles.”  This update applies to all financial statements of nongovernmental entities that are presented in conformity with U.S. GAAP.  ASC Update 2009-01 does not change GAAP, it establishes the FASB Accounting Standards CodificationTM (Codification) as the source of authoritative GAAP to be applied by nongovernmental entities, while also acknowledging the rules and interpretive releases of the SEC under authority of federal securities laws as sources of authoritative GAAP for SEC registrants.  Additionally, the Codification creates a new format for tracking, identifying, and citing GAAP, by numbered topics, subtopics, sections and paragraphs. As of the effective date of this update, all then-existing non-SEC standards will be superseded by the Codification and any non-SEC accounting literature not grandfathered will become non-authoritative.  ASC Update 2009-01 is effective for financial statements issued for periods ending after September 15, 2009.  Chugach began application of ASC Update 2009-01 to the financial statements for the period ended September 30, 2009, which did not have a material effect on our 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 will begin application of ASC Update 2010-06 to the financial statements for the period ended March 31, 2010, which we do not expect to have a material effect on our results of operations, financial position, and cash flows.


ASC Update 2009-05 “Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value”

In August 2009, the FASB issued ASC Update 2009-05, “Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value.”  ASC Update 2009-05 applies to all entities that measure liabilities at fair value within the scope of Topic 820 and clarifies the measurement techniques to be used.  This update is effective for the first reporting period (including interim periods) beginning after issuance.  Chugach began application of ASC Update 2009-05 to the financial statements for the period ended December 31, 2009, which did not have a material effect on our 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 will begin application of SFAS No. 167 on January 1, 2010, which is not expected to have a material 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.

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 will begin application of SFAS No. 166 on January 1, 2010, which is not exp