PLA-6742, Reaching Milestones, 2010 Annual Report

Reaching Milestones, 2010 Annual Report

ML11220A366
Person / Time
Site:	Susquehanna
Issue date:	07/29/2011
From:	Susquehanna
To:	Office of Nuclear Reactor Regulation
References
PLA-6742
Download: ML11220A366 (52)

Text

message wemin from the board chairman and president & CEO Allegheny Electric Cooperative, Inc. in 2010 achieved a number of significant milestones in establishing itself as a leader in a changing energy environment.

Taking a look back often provides a nice perspective on things. Like markers on a timeline, we can see events and decisions that have shaped us over time. In the past year, we can see several accomplishments that have established 2010 as a "milestone" year for Allegheny Electric Cooperative, Inc. (Allegheny).

More importantly, we can see how these individual pieces - all tied together in a "Patchwork Quilt" design - help Allegheny continue to successfully fulfill its mission of providing a reliable supply of electricity at a competitive price.

In having this opportunity to look back, we are pleased to report that 2010 has been a successful and productive year for Allegheny. The power provider for 14 electric distribution cooperatives in Pennsylvania and NewJersey recorded another year of excellent operating performance and positive financial results. Highlighted by better-than-expected margins, Allegheny's strong financial position allowed the retirement of more than $3 million in patronage capital In 2010, Allegheny's strono 1aciail pos-ion to its members in2010, bringing the total retired since allowed the retirement ofore than $3 milion 2006 to more than $17 million. Further, Allegheny assigned over $6 million to members as patronage in patronage capitol to its members. capital for 2010.

In recording a solid year financially and operationally, Allegheny delivered wholesale rates that were lower than they were in 1987, and marked some significant achievements along the way.

Most notably, Allegheny ended 2010 by positioning itself to have the lowest generation rate in the region - and the timing could not have been better. The remaining caps on electric generation rates - initiated under the electric restructuring process that began in the mid-1990s in Pennsylvania - were lifted at the close of 2010. With the rate caps off, genratio 0

suppliers have had to prepare for a fully competitive marketplace. As investor-owned utilities (IOUs) suddenly had to contend with market-influenced rate increases, Allegheny members enjoyed continued rate stability - with generation prices that were the lowest in Pennsylvania and New Jersey. Given the volatility of the energy market today, this is a striking achievement, and one in which our cooperative program can take great pride.

Unlike the IOUs, who sold off or transferred ownership of their generation assets under electric restructuring, Allegheny held onto its power resources. Today, this strong foundation in self-owned, baseload generation resources provides approximately two-thirds of our energy needs, leaving Allegheny and its member cooperatives not nearly as affected by market volatility as the IOUs. This foundation also gives us tremendous flexibility both in securing other power needs and in long-range planning.

In 2010, Allegheny's self-owned resources enjoyed an exceptional year. Following a generation record set in 2009, the Susquehanna Steam Electric Station, the nuclear plant we co-own with PPL Corporation, achieved another note of distinction. With equipment and system upgrades completed in 2010, the facility's Unit 1 reactor is now the largest boiling water reactor in terms of thermal power and generating capacity in the United States, according to the Nuclear Regulatory Commission (NRC).

This milestone achievement comes on the heels of the NRC's renewal of the operating licenses for the plant's two units for an additional 20 years, thanks to the plant's record of safe and reliable operation. Together, both units at the Luzerne County, Pa., facility generated close to 2 billion kilowatt-hours of electricity for Pennsylvania and New Jersey cooperatives in 2010.

The license renewal extends production at the facility to 2044, further helping Allegheny meet future energy needs.

Our Raystown Hydroelectric Project also produced impressive results in 2010, maintaining close to 100 percent availability at its Huntingdon County location. Despite receiving less-than-normal rainfall, the facility provided more than 83 million kilowatt-hours of electricity.

message fro- the r wm NoV'%rcs andprsd in t&C O Raystown plays an important role in bringing more renewable generation into the cooperative power supply mix, while providing other significant benefits. Recognized in 2009 as a Tier 1 renewable generation resource, the Raystown Project allows Allegheny to market renewable energy certificates (RECs) generated by the plant. Revenue from the sale of these RECs provides funding for our Renewable Energy Assistance Program (REAP), which has assisted member cooperatives and their consumers with the costs associated in the interconnection of consumer-owned renewable energy units to cooperative systems.

In June 2010, Allegheny achieved another milestone by interconnecting the 100th consumer-owned renewable energy project in the Pennsylvania-New Jersey electric cooperative service area. These interconnections, which include a mix of wind turbines, solar arrays and anaerobic digesters, reached 140 by the end of 2010. Programs like REAP - tied to our Raystown facility - help boost the supply of clean energy resources and further enhance our ability to better serve our members.

Working with our member cooperatives, Allegheny achieved a major Coordinated n~~unc A All, 2ghe i c( c~vJ Fo rr o) bt Load Management System (CLMS) milestone ic ] 004h consu r-ow ii roewcin November 2010. Developed in 1986 the~ e ~va sy e e with our distribution cooperatives, CLMS is a demand-response program that works by CF. FJ rc

• shifting electricity use of residential electric water heaters and other special equipment in the homes of volunteer consumers from times of peak demand (when prices are higher) to times of lesser demand. Reducing the amount of power used during these periods has been a significant factor in stabilizing electric costs. Last November, the program reached the

$100 million mark for gross power cost savings.

This achievement comes at a time when more attention is being focused on energy efficiency and conservation measures. In fact, Allegheny's CLMS has been touted by legislators and governmental officials as the model for demand-side management systems. Many IOUs are now being mandated to develop similar programs. Our CLMS is currently undergoing an hncement project, with equipment upgrades that will continue to improve its capabilities.

~Itogether, these milestone achievements exemplify Allegheny's Patchwork Quilt design:

det pieces working together in an overall strategy that has proved highly successful organization and its members. Looking back on those achievements provides a nice dcive on Allegheny's progress. It also serves as a nice vantage point from which to view Allegheny's future course - a course moving in a very positive direction.

the year

• mmi in review THE YEAR IN REVIEW Marked by solid financial and operational performance, Allegheny in 2010 continued to show the strength of its innovative Patchwork Quilt strategy of power supply management. The strategy involves securing power in different amounts, from different sources, for different periods of time. Developed over the past several years, the plan helps further diversify Allegheny's power resources - all the more prudent, given the volatility of the energy market and difficult economic climate of the past few years.

The Patchwork Quilt plan adds complementary pieces to a solid foundation of Allegheny-owned or -controlled power resources, helping us achieve our core mission of stable and affordable wholesale power rates for our member cooperatives in Pennsylvania and New Jersey.

Here is a look at Allegheny's 2010 power supply portfolio:

RAYSTOWN HYDROELECTRIC PROJECT Allegheny's Raystown Hydroelectric Project is a two-unit, 21-megawatt, run-of-river hydropower facility located at Raystown Lake and Dam in Huntingdon County, Pa. In 2010, Raystown provided 83.2 million kilowatt-hours, equating to 2.6 percent of Allegheny's requirements for the year.

The plant maintained a 99.5 percent availability.

Allegheny staff operates the hydroelectric project in close cooperation with the Baltimore District of the U.S. Army Corps of Engineers, which controls water releases from Raystown Lake, the largest man-made body of water in Pennsylvania.

SUSQUEHANNA STEAM ELECTRIC STATION Allegheny owns 10 percent of the Susquehanna Steam Electric Station (SSES), a 2,450-megawatt, two-unit nuclear power plant located in Luzerne County, Pa. PPL Susquehanna, a division of Allentown, Pa.-based PPL Corporation, owns the remaining 90 percent and operates the boiling water reactor facility.

In 2010, this 10 percent share of SSES provided 1.85 billion kilowatt-hours of electricity to Pennsylvania and New Jersey electric cooperatives. Considering a refueling outage, the capacity factor of Unit 1 was 75.1 percent; Unit 2 achieved a calendar year capacity factor of 95.3 percent.

This corresponds to an average annual composite capacity factor for the facility of 85.2 percent.

Both Unit 1 and Unit 2 operate on a 24-month refueling cycle, and both are in the process of being uprated by approximately 14 percent. During the 2010 Unit 1 refueling outage, the extended power uprate was completed on Unit 1. This increased the plant's output to 1,257 megawatts of net electric output. As a result, Unit 1 is now considered by the Nuclear Regulatory Commission (NRC)

to be the United States' largest boiling water reactor in terms of thermal power and generating capacity. Completion of the extended power uprate for Unit 2 is scheduled for spring of 2011.

In November 2009, the NRC officially renewed the operating licenses for Susquehanna units 1 and 2 for an additional 20 years, extending operation to 2042 for Unit 1 and 2044 for Unit 2.

NEW YORK POWER AUTHORITY Since 1966, Allegheny has purchased power generated by hydroelectric projects located along the Niagara and 20 0, AJteg / s St. Lawrence rivers in upstate New York. Both facilities are Stea VEecirK Station r operated by the New York Power Authority (NYPA). e t In 2010, Allegheny received an allocation of

• K* coor.cwe, 31 megawatts from the projects for the benefit of its 14 member cooperatives. Since 1966, it is estimated that NYPA generation has saved our electric distribution cooperatives more than $347 million ($10.2 million in 2010), compared to the cost of purchasing the same amount of electricity from other sources.

LOAD MANAGEMENT In 1986, Allegheny and its member electric distribution cooperatives in Pennsylvania and New Jersey launched the Coordinated Load Management System (CLMS) to reduce electricity consumption during peak demand periods.

By shifting use of residential water heaters, electric thermal units, dual fuel home heating systems and other special equipment in the homes of volunteer cooperative consumer-members to off-peak hours, the CLMS improves system efficiency, cuts costly demand and transmission charges Allegheny and its member cooperatives must pay for purchased power, and reduces the need for new generating capacity. The system reduces transmission zone peaks and, during summer peaks, reduces Allegheny's capacity obligation under procedures established by the PJM Interconnection.

Over the past year, the CLMS reduced cooperative purchased power costs by more than

$5.3 million, bringing total net power cost savings achieved since December 1986 to moret

$100.7 million. Currently, 203 substations are being utilized for load control with approxima 48,500 load control receivers installed on appliances (mostly water heaters) in the homes of electric cooperative consumer-members.

Beginning in 2007, Allegheny took steps to update the system. New CLMS-related equipment was placed on-line beginning in 2008 and by the end of 2009, 12 of Allegheny' 14 member cooperatives were in the process of installing new field equipment in their respective substations. At the end of 2010, field equipment installations were completed at 43 of the 203 substations. Further implementation of the CLMS upgrade throughout 2011 will provide even greater system efficiencies.

clean cornmrVtern~

power

• m CLEAN POWER COMMITMENT Allegheny and its 14 member cooperatives continue to be very active in meeting consumer-members' desire to support energy efficiency, clean and renewable energy generation, and a secure energy future for electric cooperatives. In addition to Allegheny's investments in clean and carbon-free nuclear and hydropower resources, and our demand-side efficiency measures, here are some of our other initiatives for a better environment:

INTERCONNECTED PROJECTS Allegheny and its member distribution cooperatives actively worked with cooperative consumer-members who were considering the addition of renewable energy projects to their homes or businesses. By the end of 2010, there were 140 consumer-member-owned renewable energy projects that had been interconnected, including six digesters, 44 wind turbines, 89 solar photovoltaic arrays, and one small hydroelectric facility. We expect to interconnect additional projects on a regular basis. See map next page, foldout.

RENEWABLE ENERGY ASSISTANCE PROGRAM As a positive partner in the Commonwealth's alternative energy initiatives, Allegheny provides a program to assist cooperative consumer-members who want to install a clean energy generation system at their home, farm or business. The Renewable Energy Assistance Program (REAP) provides grants to electric distribution cooperatives to help cover various interconnection costs, such as metering equipment and distribution transformers. The program also pays for certain transitional costs to help ensure that other electric cooperative consumer-members do not subsidize the operation or installation of small renewable energy generation systems - such as anaerobic digesters, wind turbines or solar units. In many ways, REAP reflects the electric cooperative tradition of members helping members, and adds a new chapter to Allegheny's history of addressing environmental and energy challenges in a cost-effective and fair way.

RAYSTOWN EARNS TIER 1 STATUS In July 2009, our Raystown Hydroelectric Project was recognized as a Pennsylvania Tier 1 renewable generation resource by the Commonwealth's Alternative Energy Program Administrator. The certification as a Tier 1 resource allows Allegheny to market renewable energy certificates (RECs) generated by the plant to other load-serving entities in the Commonwealth. Allegheny can also market Raystown RECs as Class II resources in New

<Jersey. Revenue from the sale of Raystown Hydroelectric Project RECs provides funding for our Renewable Energy Assistance Program. This follows the plant's 2007 certification as a low-impact hydroelectric facility by the Low Impact Hydropower Institute. Raystown is the Wenvironmental first and remains the only hydro plant in Pennsylvania to earn this distinction for stewardship.

PEAK DEMAND 0oo0-2c)i HiSTORIC ENERGY SALES 06 201 800 700 000 u3,000 a 500 z 2 .500'000) 4o S400 300 200 2006 2007 2008 ALLEGHENY ELECTRIC COOPERA] IV Adams Electric 4 Claverack Rural Electric 71 REA Energy 101 Sussex Rural Electric 13 Valley Rural Electric Cooperative, Inc. Cooperative, Inc. Cooperative, Inc. Cooperative, Inc. Cooperative, Inc.

Gettysburg, Pa. Wysox, Pa. Indiana, Pa. Sussex, N.J. Huntingdon, Pa.

21 Bedford Rural Electric 5 New Enterprise Rural 8 1 Somerset Rural Electric 1il Tri-County Rural Electric 141 Warren Electric Cooperative, Inc. Electric Cooperative, Inc. Cooperative, Inc. Cooperative, Inc. Cooperative, Inc.

Bedford, Pa. New Enterprise, Pa. Somerset, Pa. Mansfield, Pa. Youngsville, Pa.

3 Central Electric 61 Northwestern Rural 91 Sullivan County Rural 121 United Electric Cooperative, Inc. Electric Cooperative Electric Cooperative, Inc. Cooperative, Inc.

Parker, Pa. Association, Inc. Forksville, Pa. DuBois, Pa.

Cambridge Springs, Pa.

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alleghenyo in

225 N. Water Street, Suite 400 BKDLLP CPAs & Advisors 217.429.2411 P01 Box 1580 Decatur, IL 62525 1580 Fax 217 429.6109 www.bkd.com Independent Accountants' Report Board of Directors Allegheny Electric Cooperative, Inc.

Harrisburg, Pennsylvania We have audited the accompanying consolidated balance sheets of Allegheny Electric Cooperative, Inc.

(Cooperative) as of December 31,2010 and 2009, and the related consolidated statements of margin, members' equities, and cash flows for the years then ended. These financial statements are the responsibility of the Cooperative's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Allegheny Electric Cooperative, Inc. as of December 31,2010 and 2009, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

April 26,2011 PraxitY' experienceBKD 0

consolidated balance sheets e m-ASSETS 2010 2009 Electric Utility Plant, at cost In service (see Note 2) $868,151 $837,703 Less accumulated depreciation (710,597) (697,804) 157,554 139,899 Construction work in progress 10,940 14,620 Nuclear fuel in process (see Notes 1 and 3) 29,235 27,236 Net electric utility plant (see Notes 1, 2 and 3) 197,729 181,755 Investments and Other Assets Investments in associated organizations (see Note 4) 27,556 27,568 Nuclear Decommissioning Trust (NDT) (see Notes 1 and 5) 73,080 63,455 Non-utility property, at cost (net of accumulated depreciation of

$6,254 in 2010 and $6,102 in 2009) 4,171 3,623 Assets of consolidated variable interest entity Non-utility property, at cost (net of accumulated depreciation of $1,052 in 2010 and $1,068 in 2009) 21 34 Deferred tax assets, net (see Note 10) 12,927 11,858 Other noncurrent assets 11,435 7,028 129,190 113,566 Current Assets Cash and cash equivalents 31,345 38,180 Investments (see Note 1 and 4) 57,167 74,837 Derivative investments (see Note 6) 40,764 29,170 Accounts receivable, members (see Note 1) 16,560 16,491 Accounts receivable, affiliated organization 4 Other receivables 825 467 Inventories (see Note 1) 8,516 11,218 Other current assets 2,582 5,147 Assets of consolidated variable interest entities Cash and cash equivalents 543 608 Accounts receivable, affiliated organization 174 Other receivables 10 9 Other current assets 755 732 Total current assets 159,245 176,859 Deferred Charges (see Note 7)

Capital retirement asset 957 1,010 Deferred asset plan - NDT investments 3,315 3,845 Deferred asset plan - forward swaps 6,886 9,170 Other 25 37 11,183 14,062 0 Total assets $497,347 $486,242

S 5. . 0

• MEMBERS' EQUITIES AND LIABILITIES 2010 2009 Members' Equities (see Note 1)

Membership fees $3 $3 Patronage capital 54,369 49,462 Donated capital 38 38 Unrestricted net assets 100 100 Retained earnings 9,123 7,917 Members' equities 63,633 57,520 Accumulated other comprehensive income 14,158 9,826 Total equities 77,791 67,346 Asset Retirement Obligation (see Note 8) 142,355 136,880 Long-Term Debt (see Note 9) 152,401 158,508 Current Liabilities Current installments of long-term debt 5,858 5,219 Derivative liability-forward swaps (see Note 6) 34,621 25,287 Accounts payable and accrued expenses 18,734 17,140 Accounts payable, affiliated organization 3 38 Liabilities of consolidated variable interest entities Accounts payable and accrued expenses 1,996 1,718 Accrued postretirement benefit cost 216 Accounts payable, affiliated organization 88 175 Total current liabilities 61,516 49,577 Other Liabilities and Deferred Revenue Deferred income tax obligation from safe harbor lease (see Note 15) 617 926 Financial transmission rights (see Note 6) 13,030 13,053 Deferred credits (see Note 16) 49,637 59,952 63,284 73,931 Total liabilities and members' equities

consolidated statements

• a of margn 2010 2009 Operating Revenues $ 204,921 $ 202,922 Operating Expenses Operations Purchased capacity and energy costs 97,160 95,865 Transmission Operation 23,871 22,501 Maintenance 255 251 Production Operation 25,177 23,088 Maintenance 13,160 9,784 Fuel 10,586 9,982 Depreciation 5,822 4,895 Accretion of asset retirement obligation 5,475 5,265 Amortization of capital retirement asset 54 9,280 Administrative and general 11,676 10,888 Property and other taxes 728 686 Total Operating Expenses Before Interest 193,964 192,485 Operating Margin Before Interest Expense 10,957 10,437 Interest Expense (10,467) (9,391)

Operating Margin 490 1,046 0

2010 2009 Non-operating Margins Non-operating rental income 1,399 1,531 Non-operating rental expense (1,367) (1,431)

Interest income 6,061 5,987 Capital Credits and Other income 2,540 784 8,633 6,871 Net Margin 9,123 7,917 Other Comprehensive Margin Postretirement benefit plan 17 Unrealized appreciation in investments 4,444 6,745

consolidated statements le a MEMBERSHIP DONATED PATRONAGE FEES CAPITAL CAPITAL Balance, January 1, 2009 $3 $38 $43,781 Patronage capital retirement (3,478)

Patronage capital assignment 10,000 Patronage capital - NDT (earnings) losses 841 Comprehensive margin Net margin Change in unrealized depreciation on investments Balance, December 31, 2009 3 38 49,462 Patronage capital retirement (3,010)

Patronage capital assignment 7,058 Patronage capital - NDT (earnings) losses 859 Comprehensive margin Net margin Transfer of postretirement benefit obligation Net change in postretirement plan arising during period Change in unrealized appreciation on investments Balance, December 31, 2010

.lloi, , ;S 5 TOTAL ACCUMULATED OTHER UNRESTRICTED RETAINED MEMBERS' COMPREHENSIVE TOTAL NET ASSETS EARNINGS EQUITIES MARGIN EQUITIES

$ lOO $ 9,159 $ 53,081 $ 3,081 $56,162 (3,478) (3,478)

(10,000) 841 7,917 7917 7,917 6,745 6,745 100 7,917 57,520 9,826 67,346 (3,010) (3,010)

(7,058)

(859) 9,123 9,123 9,123 (129) (129) 17 17 4,444 4,444 S$100 S$9,123 $63,633 $14,158 $ 77,791

consolidated statements e e of cash flows 2010 2009 Operating Activities Net margin $9,123 $7,917 Items not requiring cash Depreciation and fuel amortization 14,498 12,763 Amortization of capital retirement asset 53 9,280 Accretion of asset retirement obligation 5,475 5,265 Deferred income taxes (1,069) 4,512 Loss on disposal of equipment 9 3 Other than temporary losses (160)

Change in Investments in associated organizations 12 (9,835)

Accounts receivable, members (69) 2,707 Other receivables (359) (63)

Inventories 2,702 (3,497)

Derivative investments (11,594) (21,930)

Other current and non-current assets (1,865) (1,367)

Accounts payable and accrued expenses 1,872 5,528 Accounts payable, affiliated organizations (196) 141 Derivative liability -forward swaps 9,334 25,287 Other liabilities and deferred charges (7,821) (17,580)

ZOOA; 00 2010 2009 Investing Activities Additions to electric utility plant and non-utility property, net (31,016) (33,036)

Proceeds from investments, net 18,325 1,630 Purchase of other investments (5,836) (2,717)

Net cash used in investing activities (18,527) (34,123)

Financing Activities Principal payments on long-term debt (5,468) (4,458)

Proceeds from issuance of long-term debt 40,000 Patronage capital retirement (3,010) (3,478)

Net cash provided by (used in) financing activities (8,478) 32,064 Net Increase (Decrease) In Cash and Cash Equivalents (6,900) 16,912 Cash and Cash Equivalents, Beginning of Year 38,788 21,876 Cash and Cash Equivalents, End of Year $ 31,888 $ 38,788 Supplemental Cash Flows Information Interest paid $10,521 $9,038 Income tax paid 375

notes

• to onsohiaed te Note 1: Nature of Operations and Summary of Significant Accounting Policies Allegheny Electric Cooperative, Inc. (Cooperative) is a rural electric cooperative corporation established under the laws of the Commonwealth of Pennsylvania. The Cooperative extends unsecured credit to its members, with credit extended to one member of 18% and 22% of accounts receivable at December 31, 2010 and 2009, respectively. The Cooperative finances 100 percent of its outstanding debt with the National Rural Utilities Cooperative Finance Corporation (CFC).

The Cooperative is a generation and transmission cooperative. The member cooperatives' primary service areas are rural areas throughout much of Pennsylvania and a portion of New Jersey. The Cooperative extends unsecured credit to its members. The Cooperative's primary operating asset is its 10 percent undivided interest in the Susquehanna Steam Electric Station (SSES), a 2,450-megawatt, two-unit nuclear power plant, co-owned by a subsidiary of PPL Corporation (PPL).

The Board of Directors of the Cooperative, elected by its members, has full authority to establish electric rates to its member cooperatives. Rates are established on a cost of service basis. The Cooperative's Board of Directors has established a deferred revenue account to offset future increases in power supply costs.

The financial statements include the accounts of the Cooperative and a variable interest entity, Continental Electric Cooperative Services, Inc. (CCS), of which the Cooperative has determined it is the primary beneficiary. All significant intercompany accounts and transactions have been eliminated in consolidation.

A legal entity is referred to as a variable interest entity (VIE) if any of the following conditions exist, which are outlined in the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) variable interest accounting guidance (ASC 810-10-15-04): (1) the total equity investment at risk is insufficient to permitthe legal entity to finance its activities without additional subordinated financial support from other parties, or (2) the entity has equity investors who cannot make significant decisions about the entity's operations or who do not absorb their proportionate share of the expected losses or receive the expected returns of the entity.

On January 1, 2010, the Cooperative adopted ASU 2009-17, Consolidations (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities, which amended the consolidation guidance applicable to variable interest entities. ASU 2009-17 identifies a VI E's primary beneficiary as the entity that has the power to direct the VI E's significant activities and has an obligation to absorb losses or the right to receive benefits that could be potentially significant to the VIE.

A VIE must be consolidated by the Cooperative if it is deemed to be the primary beneficiary of the VIE.

All facts and circumstances are taken into consideration when determining whether the Cooperative has variable interests that would deem it the primary beneficiary and, therefore, require consolidation of the related VIE or otherwise rise to the level where disclosure would provide useful information to the users of the Cooperative's financial statements. In many cases, it is qualitatively clear whether the Cooperative is obligated to absorb significant losses of or has a right to receive significant benefits from the VIE.

In other cases, a more detailed qualitative analysis and possibly a quantitative analysis are required to make such a determination.

The Cooperative monitors the consolidated VIE to determine if any reconsideration events have occurred that could cause it to no longer be a VIE. The Cooperative reconsiders whether it is the primary beneficiary of a VIE on an ongoing basis. A previously consolidated VIE is deconsolidated when the Cooperative ceases to be the primary beneficiary or the entity is no longer a VIE.

Initial adoption of ASU 2009-17 resulted in continuing to consolidate the VIE previously included in the consolidated financial statements and did not cause consolidation of any additional VIEs.

Continental Electric Cooperative Services, Inc. (CCS) is considered to be a variable interest entity and the Cooperative is determined to be the primary beneficiary of CCS. As such, the assets, liabilities, and results of operations have been consolidated into these financial statements.

The Cooperative maintains its accounting records in accordance with the Federal Energy Regulatory Commission's (FERC) uniform system of accounts as modified and adopted by the U.S. Department of Agriculture, Rural Utilities Service (RUS).

In accordance with FERC guidelines, the Cooperative also maintains its accounts in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, Regulated Operations.

Pennsylvania retail electric customers have the choice of selecting the power supplier, or generator, from which they buy electricity. The ability to choose alternative energy suppliers has not significantly affected the Cooperative's operations or ability to recover its costs through future rates charged to members.

On a regular basis, the Cooperative reevaluates its application of FASB ASC Topic 980, Regulated Operations, and Topic 980-20, Discontinuation of Rate Regulated Accounting. The Cooperative has determined that regulatory assets and liabilities should continue to be accounted for under the provisions of Topic 980 because it is reasonable to assume that the Cooperative will continue to be able to charge and collect its cost of service-based rates.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial report and the reported amounts of revenues and expenses during the years then ended. Actual results could differ from those estimates.

Electric utility plant is carried at cost. Depreciation of electric utility plant is provided over the estimated useful lives of the respective assets on a straight-line basis, except for nuclear fuel, as follows:

Nuclear Utility Plant Production Remaining License Life (Extended to 2044)

Transmission 2.75%

General plant 3%- 12.5%

Nuclear fuel Units of heat production Non-Nuclear Utility Plant 3%- 33%

notes

• to c osolidated I staItIe nets Maintenance and repairs of property, and replacements and renewals of items determined to be less than units of property are charged to expense. Replacements and renewals of items considered to be units of property are charged to the property accounts. At the time properties are disposed of, the original cost, plus cost of removal less salvage of such property, is charged to accumulated depreciation.

Non-utility property acquisitions are stated at cost less accumulated depreciation and amortization. Depreciation and amortization is charged to expense on a straight-line basis over the estimated useful life of each asset.

The estimated useful lives of non-utility property range from 3 to 50 years.

Nuclear fuel is charged to fuel expense based on the quantity of heat produced for electric generation. Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) is responsible for the permanent storage and disposal of spent nuclear fuel removed from nuclear reactors. The Cooperative currently pays PPL for its portion of DOE fees for such future disposal services.

Investments are classified as "available for sale" and recorded at fair value, with unrealized gains and losses excluded from earnings and reported in other comprehensive income. Purchase premiums and discounts are recognized in interest income using the interest method over the terms of the securities. Gains and losses on the sale of securities are recorded on the trade date and are determined using the specific identification method.

For debt securities with fair value below carrying value when the Cooperative does not intend to sell a debt security, and it is more likely than not, the Cooperative will not have to sell the security before recovery of its cost basis, it recognizes the credit component of an other-than-temporary impairment of a debt security in earnings and the remaining portion in other comprehensive income.

The Cooperative's consolidated statement of margin as of December 31, 2010, reflects the full impairment (that is, the difference between the security's amortized cost basis and fair value) on debt securities that the Cooperative intends to sell, or would more likely than not be required to sell before the expected recovery of the amortized cost basis. For available-for-sale debt securities that management has no intent to sell and believes that it more likely than not will not be required to sell prior to recovery, only the credit loss component of the impairment is recognized in earnings, while the noncredit loss is recognized in other comprehensive income. The credit loss component recognized in earnings is identified as the amount of principal cash flows not expected to be received over the remaining term of the security as projected based on cash flow projections.

For equity securities, when the Cooperative has decided to sell an impaired available-for-sale security and the entity does not expect the fair value of the security to fully recover before the expected time of the sale, the security is deemed other-than-temporarily impaired in the period in which the decision to sell is made. The Cooperative recognizes an impairment loss when the impairment is deemed other than temporary even if a decision to sell has not been made.

Cash and cash equivalents consist of bank deposits in federally insured accounts, temporary investments, money market funds and commercial paper.

The Cooperative places its cash and temporary investments with high quality financial institutions. For purposes of the statements of cash flows, the Cooperative considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents. Cash equivalents are carried at cost.

One or more of the financial institutions holding the Cooperative's cash accounts are participating in the FDIC's Transaction Account Guarantee Program. Under that program through December 31, 2010, all noninterest-bearing transaction accounts at these institutions were fully guaranteed by the FDIC for the entire amount in the account.

For financial institutions opting out of the FDIC's Transaction Account Guarantee Program or interest-bearing cash accounts, the FDIC's insurance limits were permanently increased to $250,000, effective July 21, 2010. At December 31, 2010, the Cooperative's cash accounts exceeded federally insured limits by approximately $9,519,000, which was held at the following institutions:

Wells Fargo Sweep and money market $ 7,755,000 BB&T Capital Markets Repurchase agreement 897,000 M&T Bank Money market and commercial paper 867,000

$ 9,519,000 The Cooperative's cash and investments are in a variety of financial instruments. The related values as presented in the financial statements are subject to various market fluctuations, which include changes in the equity markets, interest rate environment and the general economic conditions. The Cooperative's credit losses have historically been minimal and within management's expectations.

Accounts receivable are stated at the amount billed to members. Accounts receivable are due in accordance with approved policies. An allowance for doubtful accounts has not been recorded because all accounts receivable are considered fully collectible.

Derivatives are recognized as assets and liabilities on the consolidated balance sheet and measured at fair value. For exchange-traded contracts, fair value is based on quoted market prices. For nonexchange-traded contracts, fair value is based on dealer quotes, pricing models, discounted cash flow methodologies, or similar techniques for which the determination of fair value may require significant management judgment or estimation.

The Cooperative accounts for certain power plant spare parts using a deferred inventory method. Under this method, purchases of spare parts under inventory control are included in an inventory account and then charged to the appropriate capital or expense accounts when the parts are used or consumed. Inventories are carried at cost, with cost determined on the average cost method.

Current and future margins (excluding earnings from the Nuclear Decommissioning Trust), will be assigned as patronage capital.

notes to co s ld o tdf m n .ca ta e e The Cooperative accounts for income taxes in accordance with income tax accounting guidance (ASC 740, Income Taxes).

The income tax accounting guidance results in two components of income tax expense: current and deferred. Current income tax expense reflects taxes to be paid or refunded for the current period by applying the provisions of the enacted tax law to the taxable income or excess of deductions over revenues. The Cooperative determines deferred income taxes using the liability (or balance sheet) method. Under this method, the net deferred tax assets or liabilities, and enacted changes in tax rates and laws are recognized in the period in which they occur.

Deferred tax assets and liabilities are recognized for the tax effects of differences between the financial statement and tax bases of assets and liabilities. Deferred tax assets are reduced by a valuation allowance if, based on the weight of evidence available, it is more likely than not that some portion or all of a deferred tax asset will not be realized.

Uncertain tax positions are recognized if it is more likely than not, based on the technical merits, that the tax position will be realized or sustained upon examination. (The term more-likely-than-not means a likelihood of more than 50 percent; the terms examined and upon examination also include resolution of the related appeals or litigation processes, if any.) A tax position that meets the more-likely-than-not recognition threshold is initially and subsequently measured as the largest amount of tax benefit that has a greater than 50 percent likelihood of being realized upon settlement with a taxing authority that has full knowledge of all relevant information. The determination of whether or not a tax position has met the more-likely-than-not recognition threshold considers the facts, circumstances and information available at the reporting date and is subject to management's judgment. At December 31, 2010 and 2009, no uncertain tax positions have been identified.

The Cooperative would recognize interest and penalties on income taxes, if any, as a component of income tax expense.

Revenue from the sale of electricity to members is recorded based on contracted power usage billed under the Cooperative's current rate schedule.

Comprehensive margin consists of net margin and other comprehensive margin, net of applicable income taxes. Other comprehensive margin includes unrealized appreciation (depreciation) on available-for-sale securities, unrealized appreciation (depreciation) for which a portion of an other-than-temporary impairment has been recognized in margin, and changes in the funded status of the postretirement plan.

The Cooperative evaluates the recoverability of the carrying value of long-lived assets whenever events or circumstances indicate that carrying amount may not be recoverable. If a long-lived asset is tested for recoverability and the undiscounted estimated future cash flows is expected to result from the use and eventual disposition of the asset is less than the carrying amount of the asset, the asset cost is adjusted to fair value and an impairment loss is recognized as the amount by which the carrying amount of a long-lived asset exceeds its fair value. No asset impairment was recognized during the years ended December 31, 2010 and 2009.

Certain reclassifications have been made to the 2009 financial statements to conform to the 2010 financial statement presentation. These reclassifications had no effect on net margins.

, S.. Ot Note 2: Electric Utility Plant in Service 2010 2009 (in thousands)

Production $604,190 $ 592,770 Transmission 41,232 41,232 General plant 3,842 3,394 Nuclear fuel 198,608 186,151 Other 20,279 14,156 Total $868,151 $837,703 Note 3: Susquehanna Steam Electric Station The Cooperative owns a 10 percent undivided interest in SSES. PPL owns the remaining 90 percent. Both participants provide their own financing. The Cooperative's portion of SSES's gross assets, which includes electric utility plant in service, construction and nuclear fuel in progress, totaled $643 million and $633 million as of December 31, 2010 and 2009, respectively. The Cooperative's share of anticipated costs for ongoing construction and nuclear fuel for SSES is estimated to be approximately $115 million over the next five years. The Cooperative receives a portion of the total SSES output equal to its percentage ownership. SSES accounted for approximately 59% and 62% of the total kilowatt hours sold by the Cooperative during the years ended December 31, 2010 and 2009, respectively. The balance sheets and statements of income reflect the Cooperative's respective share of assets, liabilities and operations associated with SSES.

Note 4: Investments 2010 20 National Rural Utilities Cooperative Finance Corporation (in thousands)

(CFC) Subordinated Term Certificates, bearing interest at 5.8%, maturing January 1, 20261 $ 15,569 $16,101 National Rural Utilities Cooperative Finance Corporation (CFC) Subordinated Term Certificates, bearing interest from 0% to 5%, maturing January 1, 20141 128 National Rural Utilities Cooperative Finance Corporation (CFC) Member Capital Securities, bearing interest at 75%, maturing March 24, 20441 10,000 Other 1,859 Total $ 27,556 $ 27,568 1 The Cooperative is required to maintain these investments pursuant to certain loan and guarantee agreements-Such investments are carried at cost.

notes e m to consohdated fna tatm et The Cooperative makes temporary investments of excess corporate funds in investment accounts managed by qualified registered investment advisors. The amortized cost, which includes any premiums or discounts at acquisition, and approximate fair values of these investments are as follows:

2010 2009 (in thousands)

Certificates of deposit Amortized cost $ 997 Unrealized gains 2 999 Debt securities Amortized cost 50,061 60,308 Unrealized gains 2,078 1,546 Unrealized losses (233) (167) 51,906 61,687 Equity securities Amortized cost 2,447 1,575 Unrealized gains 314 249 2,761 1,824 Total investments at fair value 54,667 64,510 Investments, at cost with National Rural Utilities Cooperative Finance Corporation Medium term notes 2,500 10,000 Commercial paper 327

$ 74,837

0@.. *~l Maturities of investments at December 31, 2010:

Amortized Approximate Cost Fair Value (in thousands)

One year or less $23,914 $ 23,921 After one through five years 31,561 33,246

$55,475 $ 57,167 No other-than-temporary impairment has been recorded for 2010 and 2009.

Note 5: Nuclear Decommissioning Trust The Nuclear Decommissioning Trust consists of the following as of December 31, 2010 and 2009:

2010 Gross Gross Unrealized Unrealized Realized Fair Cost Gains Losses Losses Value (in thousands)

Decommissioning Trust Fund A:

Money market funds $ 759 $759 U.S. Government securities 8,725 30 (130) 8,625 Corporate bonds 4,542 249 (37) 4,754 Other obligations 201 15 216 Common stocks 7,200 3,949 (48) 11,101 21,427 4,243 (215) 25,455 NRC mandated Decommissioning Trust Fund B:

Money market funds 444 444 U.S. Government securities 12,900 105 (208) 12,797 Corporate bonds 8,276 378 (61) 8,593 Other obligations 875 27 (14) 888 Common stocks 17,164 7,863 (124) 24,903 39,659 8,373 (407) 47,625 Total $ 61,086 $ 12,616 $ (622) - $73,080

notes

• mn to consolidated financial statements 2009 Gross Gross Unrealized Unrealized Realized Fair Cost Gains Losses Losses Value (in thousands)

Decommissioning Trust Fund A:

Money market funds $ 173 $- $$173 U.S. Government securities 7,248 21 (72) 7,197 Corporate bonds 5,467 307 (14) 5,760 Other obligations 254 13 - 267 Common stocks 7,000 2,591 (37) (39) 9,515 20,142 2,932 (123) (39) 22,912 NRC mandated Decommissioning Trust Fund B:

Money market funds 307 - 307 U.S. Government securities 12,795 62 (135) 12,722 Corporate bonds 7,154 401 (18) 7,537 Other obligations 642 22 (7) 657 Common stocks 14,379 5,137 (75) (121) 19,320 35,277 5,622 (235) (121) 40,543 Total $55,419 $8,554 $(358) $(160) $63,455 Certain investments in debt and equity securities are reported in the financial statements at an amount less than their historical cost. Total fair value of these investments at December 31, 2010 and 2009, was $21.4 million and $19.8 million, respectively. These declines primarily resulted from increases in market interest rates prior to the balance sheet date and the failure of certain investments to meet projected earnings targets. The gross unrealized losses at December 31, 2010 for a period of less than 12 months were $549,000 and for a period of greater than 12 months were $73,000. Gross unrealized losses of $358,000 at December 31, 2009 were for a period of less than 12 months.

For 2009, the Cooperative recorded other-than-temporary impairments on equity securities and specific debt securities in the amount of $160,000. The cost-basis of these investments has been adjusted to reflect the recognition of these impairments. No other-than-temporary impairment has been recorded for 2010.

Under ASC Topic 980, Regulated Operations, the Cooperative has elected to defer these losses and pass them on to members through the future rate structure. As of December 31, 2010 and 2009, total deferred charges for the Nuclear Decommissioning Trust other-than-temporary impairment were $3,315,000 and $3,845,000.

Note 6: Derivatives and Hedging ASC Topic 815-10 seeks to improve financial reporting for derivative instruments and hedging activities by requiring enhanced disclosures regarding the impact on financial position, financial performance, and cash flows. To achieve this increased transparency, the additional guidance requires (a) the disclosure of the fair value of derivative instruments and gains and losses in a tabular format; (b) the disclosure of derivative features that are credit risk-related;

and (c) cross-referencing within the footnotes. The Cooperative adopted this Topic as of January 1,,20 The Cooperative does not engage in speculative derivative transactions, however, the Cooperative engages in hedging activities that are a natural part of power supply and transmission activities.

The Cooperative uses hedging instruments, including forwards, futures, financial transmission rights, and options, to manage power market price risks. In addition, substantial reliance on the purchase of energy from other powet',

suppliers exposes the Cooperative to the risk that counterparties will default. Therefore, an assessment is performed on the creditworthiness of counterparties and other credit issues related to these purchases, which may require the counterparties to post collateral. Defaults, however, may still occur. Ifa default occurs, the Cooperative may be forced to enter into alternative contractual arrangements or purchase energy in the forward, short-term or spot markets at then-current market prices that could vary from the prices previously agreed upon with the defaulting counterparty.

The Cooperative has never had a counterparty default or fail to perform, but past performance is no guarantee of future results.

The Cooperative is issued Financial Transmission Rights (FTRs) by PJM Interconnection LLC, (PJM). These FTRs have been found to meet the FASB ASC Topic 815, Derivatives and Hedging, definition of a derivative, and therefore must have special derivative accounting procedures applied to them.

The Cooperative received an entitlement of FTRs. FTRs are defined from a "source" node to a "sink" node (path) for a specific amount of megawatts of electric power. The holder of an FTR is entitled to receive whole or partial offsets of transmission congestion charges that arise when that specific path is congested. The purpose of the FTR mechanism is to act as a hedge against volatile congestion charges.

Market values of FTRs are only observable based on the clearing prices of the FTRs in multi-year, annual, seasonal and monthly auctions. The expected value of FTRs fluctuates based on seasonal expectations of the supply and demand of energy for each specific path. Significant assumptions and modeling projections are necessary to value FTRs. The expected FTR values are considered in the rate-making process and therefore the fair value of FTRs are recognized on the balance sheet and recorded as deferred income under ASC Topic 980, Regulated Operations. The fair value of FTRs was $13,030,000 and $13,053,000 as of December 31, 2010 and 2009 for the remainder of the current PJM planning periods that end May 31, 2011 and 2010 and beyond.

2010 2009 (in thousands)

Fair value of FTRs $ 13,030 $ 13,053 Balance sheet locations Current assets Current assets Noncurrent liabilities Noncurrent liabilities The Cooperative is exposed to market purchases of power and natural gas to meet the power supply needs of the member distribution cooperatives that are not met by Cooperative owned generation. While the Cooperative does not engage in speculative practices, the Cooperative utilizes derivative contracts to manage this exposure. Power is purchased under both long-term and short-term physically-delivered and financially-settled forward contracts to supply power to member cooperatives. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of the forward purchase derivative contracts qualify for the normal purchases/normal sales exception under previously issued

notes e to(inConsolidated c cl staternents guidance. As a result, these contracts are not recorded at fair value and are not subject to the disclosure requirements.

Purchased power is expensed when the power under the forward contract is delivered.

The Cooperative purchases natural gas futures contracts to hedge the price of natural gas for use as a basis in determining the price of power in certain forward power purchase agreements. The Cooperative also purchases capacity swap forward contracts in order to lock in capacity pricing prior to the completion of capacity auctions. These derivatives do not qualify for the normal purchases/normal sales exception; however, the Cooperative has opted out of the cash flow hedge accounting as allowed under previously issued guidance. For these derivative contracts that do not qualify for the normal purchases/normal sales exception, the Cooperative defers all gains and losses on a net basis as a regulatory asset or liability in accordance with ASC Topic 980, Regulated Operations. These amounts are subsequently reclassified as purchased power in the consolidated statements of margin as the power is delivered and/or the contract settles.

Generally, derivatives are reported on the consolidated balance sheet at fair value. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, indicative price information is sought from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contract's estimated fair value.

Changes in the fair value of the derivative instruments are recorded as a regulatory asset or regulatory liability. The change in these accounts is included in the operating section of the statement of cash flows.

As of December 31, 2010 and 2009, the Cooperative had the following outstanding derivative futures contracts:

Unit of Quantity Quantity Commodity Measure 2010 2009 Natural gas MMBTU 30,000 150,000 Capacity swap MW 197,585 130,390 As of December 31, 2010 and 2009, the fair value of the derivative instruments, excluding contracts accounted for as a normal purchase/normal sale, were as follows:

Remaining Cost Fair value 2010 (in thousands) (in thousands)

Natural gas futures contracts Capacity swap forward contracts

"OWN*4t Remaining Cost Fair value 2009 (in thousands) (in thousands)

Natural gas futures contracts $ 966 $716 Capacity swap forward contracts 24,321 15,401 Total $ 25,287 $16,117 Balance sheet locations Current liabilities Current assets As of December 31, 2010 and 2009, the Cooperative has deferred the following losses on a net basis as a regulatory asset in accordance with ASC Topic 980, Regulated Operations.

Amount of Location of Loss Deferred Loss at in the Statement of December 31, 2010 Margin at Settlement (in thousands)

Natural gas futures contracts Purchased Power $(65)

Capacity swap forward contracts Purchased Power (6,821)

Total $ (6,886)

Amount of Location of Loss Deferred Loss at in the Statement of December 31, 2009 Margin at Settlement (in thousands)

Natural gas futures contracts Purchased Power $ (250)

Capacity swap forward contracts Purchased Power (8,920)

Total $ (9,170)

Note 7: Deferred Charges Deferred charges consist of the following regulatory assets as of December 31, 2010 and 2009.

2010 2009 (in thousands)

Capital retirement asset $ 957 $ 1,010 Deferred asset plan - NDT investments 3,315 3,845 Deferred asset plan- forward swaps 6,886 9,170 Safe harbor lease closing costs 25 37

$ 11,183 $ 14,062

notes

• Based on agreements signed by the 14 member distribution cooperatives on March 29, 1999, with an effective date of January 1, 1999, and amended in 2004 and 2006, a portion of the SSES impairment writedown that took place in 1998 has been recognized as a regulatory asset and is referred to as the capital retirement asset. Under these agreements, the Cooperative was to recover from members certain financing costs related primarily to the Cooperative's investment in SSES in the amount of $311 million no later than December 31, 2009. During 2009, certain members elected to extend repayment under these agreements to 2011.

Note 8: Asset Retirement Obligation Amounts collected from the Cooperative's members for decommissioning, less applicable taxes, are deposited in external trust funds for investment and can only be used for future decommissioning costs. The fair value of the nuclear decommissioning trust was $73.1 million and $63.5 million for the years ended December 31, 2010 and 2009, respectively.

The changes in the carrying amounts of asset retirement obligations were as follows:

2010 2009 (in thousands)

Beginning balance $ 136,880 $ 131,615 Accretion expense 5,475 5,265 Ending balance $142,355 $136,880 The amount of actual obligation could differ materially from the estimates reflected in these financial statements.

Note 9: Long-Term Debt 2010 2009 (in thousands)

Note payable CFC, payable in varying quarterly installments beginning April 2008, plus interest at 68%, final paymentJanuary 2014 $ 12,775 $ 16,225 Note payable CFC, payable in varying quarterly installments beginning April 2014, plus interest at 6.9%, final paymentJanuary 2021 38,600 38,600 Note payable CFC, payable in varying quarterly installments beginning April 2021, plus interest at 7.0%, final payment April 2025 39,700 39,700 Note payable CFC, payable in varying quarterly installments beginning July 2006, plus interest at 6.8%, final payment-January 2014 1,925 2,425 Note payable CFC, payable in varying quarterly installments beginning April 2014, plus interest at 6.9%, final paymentJanuary 2021 5,800 5,800 Note payable CFC, payable in varying quarterly installments beginning April 2021, plus interest at 7.0%, final payment April 2025 6,200 6,200 Note payable CFC, payable in varying quarterly installments beginning July 2006, plus interest at 7.25%, final payment October 2025 12,507 12,956 Note payable CFC, payable in varying quarterly installments beginning July 2006, plus interest at 7.25%, final payment October 2025 2,002 2,071 Note payable CFC, payable in varying quarterly installments beginning October 2009, plus interest ranging from 4.05% to 6.65%,

final payment October 2025 38,750 39,750 Total long-term debt 158,259 163,727 Less current installments 5,858 5,219 Long-term debt, net of current installments $ 152,401 $ 158,508 The Cooperative has an additional available borrowing balance with CFC totaling $40,716,000 at December 31, 2010.

Included in the above, the Cooperative has a $35,000,000 operating line of credit with CFC that expires on March 31, 2011. Subsequent to December 31, 2010, the Cooperative renewed the operating line of credit through March 31, 2016 at $50,000,000 under the same basic terms. There were no outstanding borrowings against this line as of December 31, 2010 and 2009. The interest rate on the line of credit fluctuates as established by CFC.

Additionally, the Cooperative has a commitment from CFC to provide unsecured letters of credit of up to $25,000,000.

Under this commitment, the Cooperative has an unsecured letter of credit facility for $5,000,000 which expires November 30, 2011. As of December 31, 2010 and 2009, no funds have been drawn against this facility.

notes e m to conso iated firan cn tatemenst Future maturities of all long-term debt are as follows (in thousands):

2011 $5,858 2012 6,074 2013 6,494 2014 7,292 2015 7,668 Thereafter 124,873 The Cooperative is required to maintain certain covenants including an annual debt service coverage ratio. The Cooperative was in compliance with the applicable covenant as of December 31, 2010 and 2009, respectively.

During 2010 and 2009, the Cooperative incurred interest costs of $10,467,000 and $9,391,000, respectively.

Note 10: Income Taxes As of December 31, 2010 and 2009, the Cooperative had available nonmember net operating loss carryforwards of approximately $22 and $26 million, respectively for tax reporting purposes expiring in 2011 through 2019, and alternative minimum tax credit carryforwards of approximately $1,008,000 and $1,130,000 respectively, which carry forward indefinitely.

There was no provision for federal income taxes at December 31, 2010 and 2009. The Cooperative is not subject to state income taxes. The Cooperative is no longer subject to federal income tax examinations by tax authorities for years before 2007.

Temporary differences that give rise to deferred tax balances are principally attributable to fixed asset basis, safe harbor lease treatment, gain on installment sale, and financial statement accruals. Deferred tax assets also include the effect of net operating loss carryforwards. The temporary differences and the carryforward items produce a deferred tax asset at December 31, 2010 and 2009, of approximately $18 and $17 million, respectively. Realization of the net deferred tax asset is contingent upon the Cooperative's future earnings. A valuation allowance of approximately $5 million has been established against this asset because it has been determined that this portion of the deferred tax asset more likely than not will be unrealized. The Cooperative will include the utilization of the net deferred tax asset of approximately $13 million and $12 million at December 31, 2010 and 2009, respectively, in future rates charged to members. Therefore, a deferred credit has been recorded equal to the net deferred tax asset under FASB ASC Topic 980, Regulated Operations.

Note 11: Related Party Transaction A related organization, the Pennsylvania Rural Electric Association (PREA) has provided the Cooperative with certain management, general, and administrative services on a cost reimbursement basis. The costs for services provided by PREA were $891,000 and $921,000 for the years ended December 31, 2010 and 2009, respectively.

Note 12: Consolidated Variable Interest Entity As the primary beneficiary, the Cooperative consolidates CCS. The general creditors of CCS have no recourse against the general credit of the Cooperative.

The following table summarizes the carrying amount of the assets and liabilities of CCS included in the Cooperative's consolidated balance sheets at December 31, 2010 and 2009:

rITI777 0OMMM MI 2010 2009 (in thousands)

Current assets Cash and cash equivalents $ 543 $ 608 Accounts receivable, affiliated organization 174 Other receivables 10 9 Other current assets 755 732 Non-utility property 21 34 Total assets $ 1,503 $ 1,383 Current liabilities Accounts payable and accrued expenses $ 1,996 $ 1,718 Accrued postretirement benefit cost 216 Accounts payable, affiliated organization 88 175 Total liabilities $ 2,300 $ 1,893 Note 13: Postretirement Benefits During 2010, the administration of the postretirement benefit plan, including the obligation liability and all accounting for it, was transferred from PREA to CCS. As of November 1, 1995 (the effective date), PREA eliminated postretirement medical benefits to all of its employees except for grandfathered employees. There were two different levels of benefits for those grandfathered retirees. For each retiree over the age of 62 on the effective date, PREA, and now CCS, pays the full premium for the appropriate medical insurance for the remainder of the retiree's life. For those that were over the age of 55 but younger than 62 on the effective date, PREA, and now CCS, pays a maximum premium for medical insurance equal to the policy premium on November 1, 1995. In this second group, the retiree is responsible for any increases above this amount. On December 31, 2010, there were seven retirees covered under this plan. CCS expects to contribute $27,000 to the plan in 2011. This amount will be allocated to the Cooperative and PREA based on historical payroll allocations of the retirees covered under the plan.

CCS uses a December 31 measurement date for the plan. Information about the plan's funded status follows:

2010 (in thousands)

Benefit obligation, projected $216 Fair value of plan assets -

Funded status $ (216)

notes

• to consolid'A'ted fnancial Ittm NtS Amounts recognized in the statements of financial position:

2010 (in thousands)

Accrued postretirement benefit cost liability $ 216 Amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic benefit cost consist of:

2010 (in thousands)

Net loss $30 Transition obligation 82

$ 112 The accumulated benefit obligation for the plan was $104,000 at December 31, 2010.

Other significant balances and costs are:

2010 (in thousands)

Employer contributions $6 Benefits paid 6 Benefit cost 9 The following amounts have been recognized in the consolidated statement of margins for the year ended December 31, 2010:

2010 (in thousands)

Amounts arising during the period:

Net loss S-Net transition obligation 17 The estimated net loss and transition obligation for the plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $0 and $17,000, respectively.

The discount rate used to determine the benefit obligation was 5.75% for 2010.

For measurement purposes, a 6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2010 and should remain at that level.

0

As of December 31, 2010, the expected future payments, which reflect expected future service, are as follows:

2011 $27 2012 26 2013 25 2014 24 2015 and thereafter 114 Note 14: Employee Benefit Plans All employment relationships are through CCS, the consolidated variable interest entity of the Cooperative. CCS's leave policies provide for payment of unused leave after the end of each calendar year for 2010 and 2009. A provision has been recorded for this liability.

The Cooperative through CCS, participates in a multi-employer defined-benefit pension plan and a 401 (k) defined-contribution plan (Plans) covering substantially all of its employees. The Cooperative makes annual contributions to the Plans equal to the amount accrued for pension expense. Total pension expense for both plans amounted to $2,203,000 and $1,586,000 for the years ended December 31, 2010 and 2009, respectively.

The Cooperative, through CCS, has an employment agreement, that contains a funded deferred compensation agreement, with its President and CEO.

Note 15: Commitments and Contingencies The Cooperative has entered into power supply and transmission agreements with various service providers. A significant number of these agreements are umbrella type agreements and do not bind the Cooperative to enter into any type of transaction.

Since June 2007, the Cooperative has issued periodic Requests for Proposal (RFP) for energy and/or capacity products for varying quantities and terms between one and five years with delivery beginning in 2009 or later.

As of December 31, 2010, there were several significant capacity and energy transactions under these umbrella agreements with some energy deliveries beginning as early as 2009 and extending through 2013. Additional arrangements were made in 2009 and 2010 for energy deliveries beginning in 2012 and extending through 2014.

The Cooperative also purchased capacity for 2009 through June 2014, in a series of transactions. These transactions contained specific quantities of capacity, all of which were or will be needed to serve the Cooperative's load.

A summary of the power supply agreements are as follows:

New York Power Authority This contract meets a portion of the Cooperative's base load and peaking requirements and its delivered cost to the Cooperative's members is below market. The current contract terminates in 2025 for the Niagara Project. The current contract for the St. Lawrence Project expires in 2017 2010 Energy Provider The Cooperative entered into an arrangement in October 2009 to provide the Cooperative's remaining unmet load requirements beginning in January 2010. The agreement requires the Cooperative to supply monthly a predetermined minimum amount of energy from its generation resources and power purchase agreements and purchase any remaining requirements to meet its load pursuant to the contract. If it does not supply the minimum amount of generation required in

notes

• to consoi ate fi nan, latements any given month, the Cooperative is required to purchase replacement energy for any shortfalls at a market-based price.

The transition to the new supplier occurred on January 1, 2010. The agreement expires in December 2011.

Future Power Supply Using the RFP process, the Cooperative had entered into power purchase agreements in 2009 with various counterparties for a combination of around-the-clock, on-peak and off-peak energy and call option products that would meet approximately 95 percent of its projected energy requirements in 2010.

Various purchased power agreements require the Cooperative to post collateral deposits for exposure exceeding specified thresholds. As of December 31, 2010, collateral deposits totaled $11,407,000. Additionally, one agreement requires the Cooperative to provide additional credit support in the form on an irrevocable standby letter of credit in the amount of

$5,000,000. The letter of credit is provided by CFC and is valid until November 30, 2011.

SSES Replacement Power Insurance Policy The Cooperative mitigated a portion of the economic risk of an outage at SSES by purchasing a Replacement Power Insurance Policy from Arrow Syndicate 1910. Under the terms of the policy, if SSES had a forced outage event, the Cooperative would have been reimbursed for the cost of replacement power for the insured quantity of 250 MW. The policy stipulates that the outage limit for each such forced outage is 90 consecutive days, and the aggregate coverage limit is $15 million. For this coverage, the Cooperative purchased a two-year policy terminating December 31, 2012.

Transmission Service Transmission service for the Cooperative's load is provided through a hybrid arrangement consisting of the PJM Open Access Transmission Tariff (OATT) and the pre-existing Wheeling and Supplemental Power Agreement with Pennsylvania Electric Company.

PPL, as the 90 percent owner and sole operator of SSES, and the Cooperative, as owner of a 10 percent undivided interest in SSES, are members of certain insurance programs which provide coverage for property damage to the SSES nuclear generation plant. Under these programs, the plant, as a whole, has property damage coverage for up to $2.75 billion.

Additionally, there is coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions. Under the property and replacement power insurance programs, PPL and the Cooperative could be assessed retrospective premiums in the event the insurers' losses exceed their reserves. At December 31, 2010, the maximum amount PPL and the Cooperative jointly could be assessed under these programs was $40 million annually.

PPL and the Cooperative's public liability for claims resulting from a nuclear incident is currently limited to $12.6 billion under provisions of the Price-Anderson Act Amendments of 2005.

In the event of a nuclear incident at any of the reactors covered by the Act, PPL and the Cooperative could be assessed up to

$235 million per incident, payable at $35 million per year.

The Cooperative previously sold certain investment and energy tax credits and depreciation deductions pursuant to a safe harbor lease. The proceeds from the sale, including interest earned thereon, have been deferred and are being recognized on the statements of operations over the 30-year term lease. The deferred gain was $0.7 million and $1.0 million as of December 31, 2010 and 2009, respectively.

Under the terms of the safe harbor lease, the Cooperative is contingently liable in varying amounts in the event the lessor's tax benefits are disallowed and in the event of certain other occurrences. The maximum amount for which the Cooperative

I 00..

was contingently liable as of December 31, 2010 was approximately $2.6 million. Payment of this contingent liability has been guaranteed by CFC.

The Cooperative may be subject to claims and lawsuits that arise primarily in the ordinary course of business. At December 31, 2010, no such claims or lawsuits existed.

Note 16: Deferred Credits The Cooperative previously completed a sale and leaseback of its hydroelectric generation facility at the Raystown Dam (the Facility). The Facility was sold to a trustee bank representing Ford Motor Credit Company (Ford) for $32 million in cash. During 1996, Ford transferred its interest in the Facility to a third party. Under terms of the arrangement, the Cooperative is leasing the Facility for an initial term of 30 years beginning June 1988. Payments under the lease are due in semi-annual installments which commenced January 10, 1989. At the end of the 30-year term, the Cooperative will have the option to purchase the Facility for an amount equal to the Facility's fair market value or for a certain amount fixed by the transaction documents.

The Cooperative also has the option to renew the lease for a five-year fixed rate renewal and three fair market renewal periods, each of which may not be for a term of less than two years. Payments during the fixed rate renewal period are 30 percent of the average semi-annual installments during the initial lease term. The Cooperative will retain co-licensee status for the Facility throughout the term of the lease. The gain of $1.9 million related to the sale is being recognized over the lease term. The unrecognized gain is recorded in other deferred revenue and was $632,000 and $711,000 as of December 31, 2010 and 2009, respectively.

The payments by the Cooperative under this lease were determined in part on the assumption that Ford, or its successor, will be entitled to certain income tax benefits as a result of the sale and leaseback of the Facility. In the event that Ford, or its successor, were to lose all or any portion of such tax benefits, the Cooperative would be required to indemnify Ford, or its successor, for the amount of the additional federal income tax payable by Ford, or its successor, as a result of any such loss.

The leaseback of the Facility is accounted for as an operating lease by the Cooperative. As of December 31, 2010, future minimum lease payments under this lease, which can vary based on the interest paid on the debt used to finance the transaction, are estimated as follows (in thousands):

2011 $2,361 2012 2,361 2013 2,361 2014 2,361 2015 2,361 Thereafter 7,082 Total minimum lease payments $ 18,887 The future minimum lease payments shown above are for the initial lease term and the five-year renewal period. These payments are based on an assumed interest rate of 8.8 percent and may fluctuate based on differences between the future interest rate and the assumed interest rate.

Rental expense for this lease totaled $1.9 and $1.8 million in years ended December 31, 2010 and 2009, respectively.

notes to consote

• fina n,-. st t me t The Board has established a Deferred Revenue Plan, which seeks to stabilize members' rates for 2011 and as long as possible thereafter to mitigate the effects of expected increases in rates. The deferral of revenue for 2010 was determined as any amount above $500,000 operating margins, and for 2009 was determined as any amount above the budgeted assignable margins, after excluding earnings from the Nuclear Decommissioning Trust. Deferred revenue additions and deletions are recorded in operating revenues in the consolidated statements of margin. At December 31, 2010 and 2009, deferred revenues associated with the Deferred Revenue Plan were $35,732,000 and $46,943,000, respectively. The changes in deferred revenues in 2010 and 2009 were as follows:

2010 2009 (in thousands)

Beginning balance $ 46,943 $ 57,980 Additions 3,079 10,276 Deletions (14,290) (21,313)

Ending balance $ 35,732 $ 46,943 With the establishment of a deferred tax asset to record the effect of the temporary differences related to net operating loss carryforwards, fixed asset basis, safe harbor lease treatment, gain on installment sale and financial statement accruals, the Cooperative established a deferred credit of $13 and $12 million for 2010 and 2009, respectively, under FASB ASC Topic 980, Regulated Operations. The value of the deferred tax asset is considered in the rate making process as required by Topic 980.

Note 17.: Disclosures About Fair Value of Assets and Liabilities ASC Topic 820, Fair Value Measurements, defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Topic 820 also specifies a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standard describes three levels of inputs that may be used to measure fair value:

Level 1 Quoted prices in active markets for identical assets or liabilities Level 2 Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in active markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities Level 3 Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities

Where quoted market prices are available in an active market, securities are classified within Level 1 of the valuation hierarchy. Level 1 securities include highly liquid government bonds and exchange-traded equities. If quoted market prices are not available, then fair values are estimated by using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. For these investments, the inputs used by the pricing service to determine fair value may include, one, or a combination of: observable inputs such as benchmark yields, reported trades, broker/dealer quotes, benchmark securities, bids, offers, and reference data market research publications and are classified within Level 2 of the valuation hierarchy. Level 2 securities include certain collateralized mortgage and debt obligations and certain municipal securities. In certain cases where Level 1 or Level 2 inputs are not available, securities are classified within Level 3 of the hierarchy and include auction rate securities. Inputs include quoted market prices, benchmark securities, bids, offers and broker/dealer quotes.

The fair value is estimated using inputs that are observable or that can be corroborated by observable market data and, therefore, are classified within Level 2 of the valuation hierarchy. For financial transmission rights, inputs include clearing prices of the FTRs at multi-year, annual, seasonal and monthly auctions adjusted for seasonal expectations of the supply and demand of energy. For forward swaps, inputs include actively quoted market prices, broker quotes and industry publications.

The following table presents the fair value measurements of assets recognized in the accompanying consolidated balance sheet measured at fair value on a recurring basis and the level within the fair value hierarchy in which the fair value measurements fall at December 31, 2010 and 2009:

2010 FAIR VALUE MEASUREMENTS USING Quoted Prices in Significant Other Significant Active Markets for Observable Unobservable Identical Assets Inputs Inputs Fair Value (Level 1) (Level 2) (Level 3)

(in thousands)

Available-for-sale securities Nuclear Decommissioning Trust $ 73,080 $56,970 $ 16,110 S-Investments 54,667 4,733 46,656 3,278 Derivatives Financial transmission rights 13,030 - 13,030 Forward swaps 27,734 27,734

notes

• to consolidated financial statem ents 2009 FAIR VALUE MEASUREMENTS USING Quoted Prices in Significant Other Significant Active Markets for Observable Unobservable Identical Assets Inputs Inputs Fair Value (Level 1) (Level 2) (Level 3)

(in thousands)

Available-for-sale securities Nuclear Decommissioning Trust $ 63,455 $ 45,079 $ 18,376 Investments 64,510 1,824 59,108 3,578 13,053 13,053 16,117 16,117 The following is a reconciliation of the beginning and ending balances of recurring fair value measurements recognized in the accompanying balance sheet using significant unobservable (Level 3) inputs:

Debt Security (in thousands)

$ 4,078 i: realized and unrealized gains and losses Included in net margin I*ncluded in other comprehensive margin

ýhases issuances and settlements (500) isfefsind/or out of Level 3 3,578 I realized and unrealized gains and losses Included in net margin Included in other comprehensive margin hases, issuances and settlements (300) 3nce, December 31, 2010 $ 3,278 ng 2010 and 2009, there were no realized and unrealized gains and losses for items reflected in the table above ded in net margin in the accompanying consolidated statements of margin.

igmthods were used to estimate the fair value of all other financial instruments not recognized in the ba balance sheet.

I- *O.. @

The carrying amount approximates fair value.

Management was not able to estimate the fair value of investments that represent the Cooperative's investment in memberships and other associated organizations and they remain at their carrying value.

Due to the current market interest rates and/or short-term maturities of the Cooperative's debt, carrying amounts approximate fair value.

The estimated fair values of the Cooperative's financial instruments at December 31, 2010 and 2009 are as follow (in thousands):

2010 2009 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Cash and cash equivalents $ 31,888 $ 31,888 $ 38,788 $ 38,788 Investments 57,167 57,167 74,837 74,837 Nuclear Decommissioning Trust 73,080 73,080 63,455 63,455 Investment in associated organizations 27,556 27,556 27,568 27,568 Derivative investments 40,764 40,764 29,170 29,170 Long-term debt 158,259 158,259 163,727 163,727 Note 18: Realty Taxes The Cooperative's portion of local real estate taxes related to SSES are billed by and paid to PPL. The Cooperative is billed and pays directly to various local tax jurisdictions local real estate taxes on other property that is exclusively owned by the Cooperative.

Note 19: Current Economic Condition The current protracted economic decline continues to present electric cooperatives with difficult circumstances and challenges, which in some cases have resulted in large and unanticipated declines in the fair value of investments and other assets. The financial statements have been prepared using values and information currently available to the Cooperative.

Current economic conditions have put additional pressure on many cooperatives and affiliated organizations to meet their financing and liquidity needs. A significant decline in operating revenues could have an adverse impact on the Cooperative's future operating results.

In addition, given the volatility of current economic conditions, the values of assets and liabilities recorded in the financial statements could change, resulting in material future adjustments in investment values, allowances for receivables, etc. All known impairments and changes to fair value have been recorded in these financial statements.

notes

• A to consoidatedl financial tatemrents Note 20: Subsequent Events Subsequent to December 31, 2010, the Board of Directors of the Cooperative authorized the submission of a $100 million request for long-term financing with CFC for future construction and utility plant additions.

Subsequent events have been evaluated through April 26, 2011, which is the date the financial statements were available to be issued.

Deebe- 1 200. an*2