ML14035A314

2013 Annual Financial Report. Part 2 of 2

ML14035A314
Person / Time
Site:	Columbia
Issue date:	01/16/2014
From:	Energy Northwest
To:	Office of Nuclear Reactor Regulation
References
G02-14-007
Download: ML14035A314 (34)

Text

Financial Data & Information

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Management Report on Responsibility for Financiat Reporting Energy Northwest management is responsible for preparing the accompanying financial statements and for their integrity. They were prepared in accordance with generally accepted accounting principles applied on a consistent basis, and include amounts that are based on management's best estimates and judgments.

The financial statements have been audited by PricewaterhouseCoopers LLP, Energy Northwest's independent auditors. Management has made available to PricewaterhouseCoopers LLP all financial records and related data, and believes that all representations made to PricewaterhouseCoopers LLP during its audit were valid and appropriate.

Management has established and maintains internal control procedures that provide reasonable assurance as to the integrity and reliability of the financial statements, the protection of assets from unauthorized use or disposition, and the prevention and detection of fraudulent financial reporting. These control procedures provide appropriate division of responsibility and are documented by written policies and procedures.

Energy Northwest maintains an ongoing internal auditing program that provides for independent assessment of the effectiveness of internal controls, and for recommendations of possible improvements thereto. In addition, PricewaterhouseCoopers LLP has considered the internal control structure inorder to determine their auditing procedures for the purpose of expressing an opinion on the financial statements. Management has considered recommendations made by the internal auditor and PricewaterhouseCoopers LLP concerning the control procedures and has taken appropriate action to respond to the recommendations.

Management believes that, as of June 30, 2013, internal control procedures are adequate.

M.E. Reddemann B.J. Ridge Chief Executive Officer Vice President, and Chief Financial & Risk Officer Audit, Legal and Finance Committee Chair's Letter The executive board's Audit, Legal and Finance Committee (committee) is composed of 11 independent directors. Members of the committee are Chair Larry Kenney (July 2012 - February 2013), Marc Daudon, Dan Gunkel, Jack Janda, Skip Orser, Will Purser, Dave Remington, Lori Sanders, Tim Sheldon, Chair Kathy Vaughn (March - June 2013) and Sid Morrison, ex-officio. The committee held 10 meetings during the fiscal year ending June 30, 2013.

The committee oversees Energy Northwest's financial reporting process on behalf of the executive board. In fulfilling its responsibilities, the committee discussed with the internal auditor and the independent auditors the overall scope and specific plans for their respective audits, and reviewed Energy Northwest's financial statements and the adequacy of Energy Northwest's internal controls.

The committee met regularly with Energy Northwest's internal auditor and convened periodic meetings with the independent auditors to discuss the results of their audit, their evaluations of Energy Northwest's internal controls, and the overall quality of Energy Northwest's financial reporting. The meetings were designed to facilitate any private communications with the committee desired by the internal auditor or independent auditors.

Kathy Vaughn

Chair, Audit, Legal and Finance Committee MA Comnmitment to Excetlonc

Independent Auditor's Report To the Executive Board of Energy Northwest:

We have audited the statements of net position and the related statements of revenues, expenses and changes in net position and of cash flows of the Columbia Generating Station, Packwood Lake Hydroelectric Project, Nuclear Project No.1, Nuclear Project No.3, the Business Development Fund, the Nine Canyon Wind Project, and the Internal Service Fund as of and for the year ended June 30, 2013, and the related notes to the financial statements, which collectively comprise the business-type activities of Energy Northwest (the "Company").

Management's Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility Our responsibility is to express opinions on the financial statements based on our audit. We conducted our audit 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 from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinions.

Opinions In our opinion, the financial statements referred to above present fairly, in all material respects, the respective financial position of the business-type activities of the Company at June 30, 2013, and the respective results of its operations and its cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America.

Other Matter The accompanying management's discussion and analysis listed in the table of contents are required by accounting principles generally accepted in the United States of America to supplement the basic financial statements. Such information, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in the appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management's responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

Portland, Oregon September 26, 2013

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Energy Northwest Management's Discussion and Analysis Energy Northwest is a municipal corporation and joint operating agency The Balance Sheets present the financial position of each business unit of the state of Washington. Each Energy Northwest business unit is financed on an accrual basis. The Balance Sheets report financial information about and accounted for separately from all other current or future business construction work in progress, the amount of resources and obligations, assets. The following discussion and analysis is organized by business unit. restricted accounts and due to/from balances for each business unit. (See The management discussion and analysis of the financial performance and Note 1 to the Financial Statements.)

activity is provided as an introduction and to aid in comparing the basic The Statements of Revenues, Expenses, and Changes in Net Assets provide financial statements for the fiscal year (FY) ended June 30, 2013, with the financial information relating to all expenses, revenues and equity that reflect basic financial statements for the fiscal year ended June 30, 2012. the results of each business unit and its related activities over the course Energy Northwest has adopted accounting policies and principles that of the fiscal year. The financial information provided aids in benchmarking are in accordance with Generally Accepted Accounting Principles (GAAP) in activities, conducting comparisons to evaluate progress, and determining the United States of America. Energy Northwest's records are maintained as whether the business unit has successfully recovered its costs.

prescribed by the Governmental Accounting Standards Board (GASB) and, The Statements of Cash Flows reflect cash receipts and disbursements and when not in conflict with GASB pronouncements, accounting standards net changes resulting from operating, financing and investing activities. The prescribed by the Financial Accounting Standards Board (FASB). (See Note 1 Statements of Cash Flows provide insight into what generates cash, where to the Financial Statements.) the cash comes from, and purpose of cash activity.

Because each business unit is financed and accounted for separately, the The Notes to Financial Statements present disclosures that contribute following section on financial performance is discussed by business unit to aid to the understanding of the material presented in the financial statements.

in analysis of assessing the financial position of each individual business unit. This includes, but is not limited to, Schedule of Outstanding Long-Term Debt For comparative purposes only, the table on the following page represents a and Debt Service Requirements (See Note 5 to the Financial Statements),

memorandum total only for Energy Northwest, as a whole, for FY 2013 and accounting policies, significant balances and activities, material risks, FY 2012 in accordance with GASB No. 34, "Basic Financial Statements-and commitments and obligations, and subsequent events, if applicable.

Management's Discussion and Analysis-for State and Local Governments." The basic financial statements of each business unit along with the notes The financial statements for Energy Northwest include the Balance to the financial statements and management discussion and analysis should Sheets; Statements of Revenues, Expenses, and Changes in Net Assets; be used to provide an overview of Energy Northwest's financial performance.

and Statements of Cash Flows for each of the business units, and Notes to Questions concerning any of the information provided inthis report should be Financial Statements. addressed to Energy Northwest at PO Box 968, Richland, WA, 99352.

M A Commitment to Exceetence

Combined Financiat Information June 30, 2013 and 2012 (Doltars in thousands) 2012 2013 Change Assets Current Assets $ 209,345 S 199,122 $ (10,223)

Restricted Assets Special Funds 51,345 51,896 551 Debt Service Funds 516,106 672,455 156,349 Net Plant 1,525,642 1,499,711 (25,931)

Nuclear Fuel 341,535 985,824 644,289 Other Charges 3,658,124 3,258,111 (400,013)

TOTAL ASSETS $ 6,302,097 $ 6,667,119 $ 365,022 Current Liabilities S 501,801 $ 621,867 $ 120,066 Restricted Liabilities Special Funds 138,406 147,047 8,641 Debt Service Funds 144,557 139,029 (5,528)

Long-Term Debt 5,508,467 5,746,882 238,415 Other Long-Term Liabitilies 15,776 18,115 2,339 Other Credits 5,709 5,727 18 Net Position (12,619) (11,548):: 1,071 TOTAL LIABILITIES AND NET POSITION $ 6,302,097 $ 6,667,119 $ 365,022 Operating Revenues $ 425,695 $ 569,863 $ 144,168 Operating Expenses 354,860 443,629 88,769 Net Operating Revenues 70,835 126,234 55,399 Other Income and Expenses (71,049): (125,163). (54,114)

(Distribution) & Contribution Beginning Net Assets (12,405) (12,619): (214)

ENDING NET ASSETS $ (12,619):: $ (11,548): $ 1,071 i1 No,1,11we- , :1 A i ts Ii, Re t

Columbia Generating Station Columbia Generating Station (Columbia) is wholly owned by Energy Balance Sheet Analysis Northwest and its participants and operated by Energy Northwest. The plant The net decrease to Utility Plant (plant) and Construction Work In Progress is a 1,170-megawatt electric (MWe, Design Electric Rating, net) boiling water (CWIP) from FY 2012 to FY 2013 (excluding nuclear fuel) was $18.1 million. The nuclear power plant located on the Department of Energy's (DOE) Hanford Site changes to plant and CWIP were comprised of additions to plant of $8.0 million north of Richland, Washington. with an increase to CWIP of $55.9 million. Remaining changes was the period Columbia produced 8,479 gigawatt-hours (GWh) of electricity in FY 2013, effect of depreciation of $82.0 million. The accumulated decommissioning as compared to 6,984 GWh of electricity in FY 2012, which included economic and site restoration accrued costs related to the Integrated Spent Fuel Storage dispatch of 51 and 140 GWh respectively. Columbia entered its planned Installation (ISFSI) at Columbia were adjusted to reflect the change inthe asset refueling outage (R-21) on May 11, 2013. The 40 day planned outage extended retirement obligation (ARO). Change in the ARO was necessary due to new an additional 5 days and ended June 25, 2013.The FY 2013 generation increase Nuclear Regulatory Commission requirements for fuel storage calculations. Per of 21.4% was due to the extended outage (R-20) incurred in FY 2011 extending ASC 410, "Asset Retirement and Environmental Obligations," the obligation was into a portion of FY 2012, which ended September 27, 2012 which reduced reevaluated and adjusted to reflect the change intiming due to the relicensing the amount of power generated in FY 2012. Additionally, FY 2013 generation of Columbia through December 31, 2043 and to account for estimated costs was approximately 6 GWh higher than budgeted, reflecting the continuous and related to fuel disposition obligations for the post five year period following successful generation run. the end of licensing and generation. The revision resulted inan increase to the Columbia's cost performance is measured by the cost of power indicator. capitalized portion of the asset of $0.5 million. (See Note 11 to the Financial The cost of power for FY 2013 was 4.51 cents per kilowatt-hour (kWh) as Statements.)

compared with 4.73 cents per kWh in FY 2012. The industry cost of power The FY 2013 additions to CWIP of $55.9 million consisted of 20 major fluctuates year to year depending on various factors such as refueling outages projects of at least $0.7 million: Fukushima impacts, Radio Obsolescence, Cobalt and other planned activities. The FY 2013 cost of power decrease of 4.7 Reduction Program, Stack Monitor Performance, ServiceWater Pump and Motor percent was due to the successful cost control and generation run in FY 2013 Overhaul, On-Line Noble Chemical Application, Keep Fill Pump Replacement, as compared to the generation and additional costs incurred during FY 2012 Control Rod Device Refurbishment, Main Transformer Replacement, High due to the extended R-20 outage. Pressure Core Spray Refurbishment, Turbine Blade Procurement, Reactor Feed Water Overhaul, Condensate Pump Refurbishment, Residual Heat Removal Systems, and Plant Telephone Obsolescence. These projects resulted in 76 N

Columbia Generating Station Columbia Generating Station NET GENERATION - GWhrs COST OF POWER - Cents/kWh FY201 8,479 FY2013 4.51 FY201; 6,984 FY2012 4.73 FY2011 7,247 FY2011 5.69 FY 201C 8,124 FY2010 3.74 FY 7,725 FY2009 4.94 S 2,000 4,000 6,000 8,000 10,000 0 1 2 3 4 0A Comniitrnent tu Lxci-hnc

percent of the CWIP activity. The remaining 24 percent were made up of 103 Excess of Billings related to the net effect of payment of current maturities and separate projects. refunding activity related to available debt of $58.1 million. There was also a Nuclear fuel, net of accumulated amortization, increased $644.3 million slight increase to unamortized debt expense of $1.7 million due to debt related from FY 2012 to $985.8 million for FY 2013. The major factor contributing to activity.

the increase in Nuclear Fuel relates to the completion of the Depleted Uranium Current liabilities increased $15.6 million in FY 2013 to $139.6 million.

Enrichment Program (DUEP). This program increased Fuel held for resale from Components of the change were an increase to year end obligations relating

$1.5 million in FY 2012 to $538.9 million in FY 2013. Fuel amounts used for from R-21 year end impacts of $4.1 million, increases to current maturities reload increased $90.0 million with a decrease in net fuel of $37.8 million for of debt of $60.7 million, decrease of $61.8 million due to payment of notes current year amortization. Fuel removed for cooling increased $55.3 million payable obligation related to the DUEP, an increase of $14.6 million for business and remaining change was $0.6 million for fuel loan and purchase activity unit activity and a decreased requirement for participant amounts under the net relating to the cylinder/sampling activity for the DUEP. billing agreement of $2.0 million.

Current assets increased $16.4 million in FY 2013 to $166.2 million. Restricted liabilities increased $12.5 million in FY 2013 to $198.7 million.

Changes were increases to materials and supplies of $10.2 million (nuclear The increase was due to bond activity and related increase of $5.7 million and fuel cask inventory is $4.5 million and inventory is $5.7), increases to cash decommissioning increases of $6.8 million.

and investments of $7.2 million offset by a decrease in accounts and other Long-term debt (Bonds Payable) increased $721.6 million in FY 2013 from receivables of $1.0 million. $2.4 billion to $3.2 billion due to the debt associated with DUEP of $748.6 Special funds decreased $20.4 million to $16.4 million in FY 2013 due to million. The current portion of Bonds Payable increased $60.1 million, which the FY 2013 bond activity and schedule of construction costs for these funds was driven by timing of scheduled maturities.

in FY 2013. Other long-term liabilities increased $2.1 million in FY 2013 to $17.9 million The debt service funds increased $57.6 million in FY 2013 to $147.5 million. related to nuclear fuel cask activity.

The increase is due to the maturity of outstanding debt along with restructuring and funding activities and the requirement of making funds available for these Statement of Operations Analysis maturities. Columbia is a net-billed project. Energy Northwest recognizes revenues Deferred charges increased $59.8 million in FY 2013 from $835.0 million equal to expenses for each period on net-billed projects. No net revenue or loss to $894.8 million. Components of this increase were changes in Costs in is recognized and no net assets are accumulated.

Operating expenses increased $87.5 million from FY 2012 costs of $331.4 million to $418.9 million in FY 2013. The increases in costs were due to FY 2013 being a planned refueling year. The majority of the impacts to operating expenses were for Operations and Maintenance costs. These costs were

$68.9 million higher in FY 2013. Increased generation in FY 2013 resulted in Columbia Generating Station increased fuel disposal costs of $8.5 million and increased generation taxes TOTAL OPERATING COSTS of SO.8 million. Periodic expenses for depreciation and decommissioning (dollars in thousands) increased $8.4 million with the remainder of the increase ($0.9 million) a result Total Expenses of Administrative and General Expenses.

FY2013 539,779 Other Income and Expenses increased $54.2 million from FY 2012 to $120.7 million net expenses in FY 2013. In FY 2012 there was a spent fuel litigation 397,881 settlement from the Department of Energy (DOE) of $48.7 million recorded as FY2012 an offset to other income and expense. This is the major factor in the overall increase in other income and expenses for FY 2013. Additionally, FY 2012 had FY2011 522,1 56 $1.8 million in property disposal gains (condenser from R-20) that did not occur in FY 2013. The remaining major components of the increases were $2.0 million 448,075 due to bond and interest related activity and decreases to leasing activity of FY2010

$1.7 million. This includes a $1.2 million DUEP leasing adjustment.

Columbia's total operating revenue increased from $397.9 million in FY FY2009 519,759 2012 to $539.7 million inFY 2013.The increase in costs (and conversely revenue per net billing) of $141.8 million was due to the increased costs incurred inthe 0 100,000 200,000 300,000 400,000 500,000 completion of R-21. R-21 was originally budgeted for $87.0 million and 40 0 Operating Expenses M Other Income I Expenses days. Actual cost and days were $85.1 million and 45 days. Columbia officially synced to the grid on June 25, 2013 signaling the completion of R-21.

I

Packwood Lake HydroeLectric Project The Packwood Lake Hydroelectric Project (Packwood) is wholly owned and operated by Energy Northwest. Packwood consists of a diversion structure at Packwood Lake and a powerhouse located near the town of Packwood, Washington. The water is carried from the lake to the powerhouse through a five-mile long buried tunnel and drops nearly 1,800 feet in elevation. Packwood produced 103.70 GWh of electricity in FY 2013 versus 119.43 GWh in FY 2012. The 13.2 percent decrease in generation can be attributed to less favorable water availability compared to the previous year in addition to FY 2012 being the fourth highest generation in the life of the plant.

Generation results for FY 2013 did exceed the estimated amount of 92.7 GWh by 11.9 percent.

Packwood's cost performance is measured by the cost of power indicator. The cost of power for FY 2013 was $2.07 cents per kWh as compared to $1.58 cents per kWh in FY 2012. The cost of power fluctuates year-to-year depending on various factors such as outage, maintenance, generation, and other operating costs. The FY 2013 cost of power increase of 31.0 percent was a result of less generation due to water availability and increased costs due to maintenance and transmission charges.

Balance Sheet Analysis Total assets decreased $0.1 million from FY 2012, with the drivers being an increase of $0.7 million in capital activity for utility plant and a decrease of Packwood Lake Hydroelectric Project $0.8 million incash for operating activities. The corresponding decrease to total COST OF POWER - Cents/kWh liabilities of $0.1 million was the decrease indue to participants for the results of operations. Packwood has incurred $3.7 million in relicensing costs through FY 2012 with no new costs incurred for FY 2013. These costs are shown as Deferred FY 2.07 Charges on the Balance Sheet. Packwood has been operating under a 50-year license issued by the Federal Energy Regulatory Commission (FERC), which 1.58 expired on February 28, 2010. Energy Northwest submitted the Final License FY 201 Application (FLA) for renewal of the operating license to FERC on February 22, 2008. On March 4, 2010, FERC issued a one-year extension to operate under FY2011 1.59 the original license which is indefinitely extended for continued operations until formal decision is issued by FERC and a new operating license is granted. As 1.82 of June 30, 2013, Packwood continues to be relicensed under this extended FY2010 agreement.

FY2009 1.62 0.0 0.5 1.0 1.5 2.0 2.5 Packwood Lake Hydroelectric Project Packwood Lake Hydroelectric Project NET GENERATION - GWhrs TOTAL OPERATING COSTS (dollars in thousands)

Total Expenses FY2013 103.74 FY2013 2,166 FY2012 119.43 1,872 FY2012 FY2011 107.92 FY2011 1,742 FY2010 86.07 FY2010 1,535 FY2009 99.34 FY2009 1,641 0 20 40 60 80 100 120 0 500 1,000 1,500 2,000 2,5*00 U Operating Expenses M Other Income / Expenses M AC~ormmiment to Exce~lence

Statement of Operations Analysis The agreement with Packwood participants obligates them to pay annual Packwood participants are obligated to pay annual costs of the project costs and to receive excess revenues. (See Note 1 to the Financial Statements.) (including any applicable debt service), whether or not the project is operable. The Accordingly, Energy Northwest recognizes revenues equal to expenses for each Packwood participants also share project revenue to the extent that the amounts period. No net revenue or loss is recognized and no net assets are accumulated. exceed costs. These funds can be returned to the participants or kept within the Operating expenses increased $0.3 million to $2.2 million in FY 2013 from project. As of June 30, 2013 there is $5.7 million recorded as deferred revenues in

$1.9 million in FY 2012. Operations and Maintenance was the major reason for excess of costs that are being kept within the project. Packwood participants are the increase due to increased transmission and scheduling costs of $57,000 and currently taking 100 percent of the project generation; there are no additional

$245,000 of hydraulic and electrical expenses. agreements for power sales.

Other Income and Expense increased from a net gain of $4,000 in FY 2012 to an $8,000 gain in FY 2013.The $4,000 increase innet gain is primarily due to a small gain on property disposed of $2,000 and a small increase ininvestment income from FY 2012 of $2,000.

Nuclear Project No. 1 Nuctear Project No. 3 Energy Northwest wholly owns Nuclear Project No. 1, a 1,250-MWe plant, Nuclear Project No. 3, a 1,240-MWe plant, was placed in extended which was placed in extended construction delay status in 1982, when it construction delay status in 1983, when it was 75 percent complete. On was 65 percent complete. On May 13, 1994, Energy Northwest's Board of May 13, 1994, Energy Northwest's Board of Directors adopted a resolution Directors adopted a resolution terminating Nuclear Project No. 1. All funding terminating Nuclear Project No. 3. Energy Northwest is no longer responsible requirements are net-billed obligations of Nuclear Project No. 1.Termination for any site restoration costs as they were transferred with the assets to the expenses and debt service costs comprise the activity of Nuclear Project No. Satsop Redevelopment Project. The debt service related activities remain the 1 and are net-billed. responsibility of Energy Northwest and are net-billed. (See Note 13 to the Financial Statements.)

Balance Sheet Analysis Long-term debt decreased $289.7 million from $1.4 billion in FY 2012 Balance Sheet Analysis to $1.1 billion in FY 2013 as a result of $273.1 million being transferred to Long-term debt decreased $174.4 million from $1.5 billion in FY 2012 current debt to be paid on July 1,2013 along with a decrease in bond related to $1.3 billion in FY 2013, as a result of $166.2 million being transferred to amortization of $16.6 million. Short term debt increased $37.0 million per current debt to be paid on July 1,2013 along with a decrease in bond related the debt maturity schedule. There was a decrease to restricted liabilities of amortization of $8.2 million. Current debt per the debt maturity schedule

$7.0 million, represented by a decrease to interest payable of $8.8 million increased $70.6 million from $95.5 million in FY 2012 to $166.2 million in offset by an increase to the decommissioning estimate of $1.8 million. FY 2013. The remaining changes in liabilities of $6.6 million were due to increased payable transfers from bond related activities.

Statement of Operations Analysis Other Income and Expenses showed a net decrease to expenses of $20.0 Statement of Operations Analysis million from $75.0 million in FY 2012 to $55.0 million in FY 2013. Investment Overall expenses decreased $9.9 million from FY 2012 related to bond revenue stayed steady, bond related expenses decreased $21.5 million, activity with investment income and liquidation costs steady with previous decommissioning costs increased $1.3 million and there was a slight increase year levels.

of $0.2 million in plant preservation costs.

Enerily Northwest 201 3 Annual Report

Business Development Fund Energy Northwest was created to enable Washington public power utilities Natural Gas Combined-Cycle plant as part of a compensation package for and municipalities to build and operate generation projects. The Business selling development rights to Duke Energy in2001 ($0.3 million), termination Development Fund (BDF) was created by Executive Board Resolution No. of the Kalama project in FY 2013, which was a proposed development of 1006 in April 1997, for the purpose of holding, administering, disbursing, a 346 MW Natural Gas Combined-Cycle plant in southwestern Washington and accounting for Energy Northwest costs and revenues generated from state ($0.4 million), decreases in Hanford calibration services ($0.3 million) engaging in new energy business opportunities. due to the expiration of a portion of the contracted scope of work, and The BDF is managed as an enterprise fund. Four business lines have decreased lease activity ($0.3 million). The decreases in the four projects been created within the fund: General Services and Facilities, Generation, mentioned above were offset by increased revenues for technical services and

.Professional Services, and Business Unit Support. Each line may have one or engineering services of $0.6 million. Operating costs decreased $0.9 million more programs that are managed as a unique business activity. due to decreased business activity resulting in a net operating increase of

$0.1 million.

Batance Sheet Anatysis Other Income and Expenses decreased $0.2 million from $1.5 million in Total assets increased $1.0 million from $9.1 million in FY 2012 to $10.1 net revenues in FY 2012 to net revenue of $1.3 million in FY 2013; there was million in FY 2013. Increases were due to cash and investments of $1.1 an adjustment of $0.1 million for completion of the power option derivative million, net plant of $0.2 million, and decreases to receivables and prepaid contract for the Grays Harbor project, and a decrease of other income and amounts of $0.3 million. Liabilities decreased $0.4 million from FY 2012 due expenses of $0.1 million, with no significant individual items.

to timing of year end outstanding items. The Business Development Fund receives contributions from the Internal Service Fund to cover cash needs during startup periods. Initial startup costs Statement of Operations Anatysis are not expected to be paid back and are shown as contributions. As an Operating Revenues in FY 2013 totaled $9.0 million as compared to FY operating business unit, requests can be made to fund incurred operating 2012 revenues of $9.8 million, a decrease of $0.8 million. The decrease in expenses. In FY 2013 there were no contributions (transfers), which was also revenues was driven by four major projects: Grays Harbor project, which was the case for FY 2012.

a 50 MW power call option that ended in June 2013 at the 600 MW Satsop M A Commnitme~nt to Fxcetlec

Nine Canyon Wind Project The Nine Canyon Wind Project (Nine Canyon) is wholly owned and totals and unplanned maintenance. The FY 2013 cost of power increase operated by Energy Northwest. Nine Canyon is located in the Horse of 18.2 percent was a result of the decreased generation due to wind Heaven Hills area southwest of Kennewick, Wash. Electricity generated conditions and higher maintenance costs incurred due to turbine bearing by Nine Canyon is purchased by Pacific Northwest Public Utility Districts maintenance.

(purchasers). Each of the purchasers of Phase I, Phase II,and Phase Ill have signed a power purchase agreement which are part of the 2nd Amended Balance Sheet Analysis and Restated Nine Canyon Wind Project Power Purchase Agreement Total assets decreased $5.0 million from $119.5 million in FY 2012 to which now has an end date of 2030. Nine Canyon is connected to the $114.5 million in FY 2013. The major driver for the change in assets was a Bonneville Power Administration transmission grid via a substation and decrease of $6.8 million in net plant due to accumulated depreciation. The transmission lines constructed by Benton County Public Utility District. remaining changes consisted of increases to restricted assets of $2.4 million Phase I of Nine Canyon, which began commercial operation in and decreases in cash and investments of $0.2 million, prepaid amounts of September 2002, consists of 37 wind turbines, each with a maximum $0.2 million and debt related expenses of $0.2 million. There was an overall generating capacity of approximately 1.3 MW, for an aggregate generating decrease to liabilities of $5.2 million with a decrease to long term debt of capacity of 48.1 MW. Phase II of Nine Canyon, which was declared $7.4 million, increases to current debt maturities of $2.3 million, increases to operational in December 2003, includes 12 wind turbines, each with a accrued debt related interest of $0.1 million, and increases to accrued costs maximum generating capacity of 1.3 MW, for an aggregate generating and business activities of $0.1 million. The increase in net assets was $0.2 capacity of approximately 15.6 MW. Phase III of Nine Canyon, which was million in FY 2013 as compared to a decrease of $1.3 million in FY 2012. The declared operational in May 2008, includes 14 wind turbines, each with slight reversal in net assets reflects the rate stabilization approach for Nine a maximum generating capacity of 2.3 MW, for an aggregate generating Canyon planning out through the 2030 period.

capacity of 32.2 MW. The total Nine Canyon generating capability is 95.9 In previous years Energy Northwest has accrued, as income (contribution)

MW, enough energy for approximately 39,000 average homes. from the Department of Energy, Renewable Energy Production Incentive (REPI)

Nine Canyon produced 228.23 GWh of electricity in FY 2013 versus payments that enable Nine Canyon to receive funds based on generation as 261.63 GWh in FY 2012. The decrease of 12.8 percent was due to slightly it applies to the REPI legislation. REPI was created to promote increases in less favorable wind conditions in FY 2013 as compared to FY 2012. The the generation and utilization of electricity from renewable energy sources average wind speed for the months of January and June were significantly and to further the advances of renewable energy technologies. This program, below the 10 year average. The below average wind conditions combined authorized under Section 1212 of the Energy Policy Act of 1992, provides with FY 2012 being the second highest generation year for history of the financial incentive payments for electricity produced and sold by new project were the drivers for the decrease between years. qualifying renewable energy generation facilities. The payment stream from Nine Canyon's cost performance is measured by the cost of power Nine Canyon participants and the REPI receipts were projected to cover the indicator. The cost of power for FY 2013 was $7.91 cents per kWh as total costs over the purchase agreement. Continued shortfalls in REPI funding compared to $6.69 cents per kWh in FY 2012. The cost of power for the Nine Canyon project led to a revised rate plan to incorporate the fluctuates year to year depending on various factors such as wind impact of this shortfall over the life of the project. The billing rates for the Nine Canyon Wind Project Nine Canyon Wind Project NET GENERATION - GWh COST OF POWER - Cents/kWh FY2013 228.23 FY2013 7.91 FY2012 261.63 FY2012 6.69 FY2011 264.74 FY2011 6.56 FY2010 226.73 FY201 7.88 FY2009 226.27 FY20C 7.79 0 50 100 150 200 250 300 I El

Nine Canyon participants increased 69 percent and 80 percent for Phase I and Statement of Operations Analysis Phase II participants respectively in FY 2008 in order to cover total project Operating revenues increased $2.8 million from $16.2 million in FY costs, projected out to the 2030 proposed project end date. The increases for 2012 to $19.0 million in FY 2013. The project received revenue from the FY 2008 were a change from the previous plan where a 3 percent increase each billing of the purchasers at an average rate of $80.06 per MWh for FY year over the life of the project was projected. Going forward, the increase or 2013 as compared to $61.98 per MWh for FY 2012 which is reflective of decrease in rates will be based on cash requirements of debt repayment and the implementation of the revised rate plan in FY 2008 to account for REPI the cost of operations. Phase IIIstarted with an initial planning rate of $49.82 funding shortfalls and costs of operations. The increased operating revenues per MWh which increased at 3 percent per year for three years. In year six (FY from the previous year were due to increased funding requirements for Phase 2013) the rate increased to a rate that will be stabilized over the life of the Ill purchasers. The increase inthe average rate billed to purchasers was also project. Possible adjustments may be necessary to future rates depending on impacted by the reduced generation in FY 2013 as compared to FY 2012.

operating costs and REPI funding, similar to Phase I and II. Operating costs increased from $11.3 million in FY 2012 to $13.1 million in FY 2013. Increased operating costs of $1.8 million for FY 2013 were due to maintenance work related to turbine bearing replacements.

Other income and expenses decreased $0.5 million from $6.2 million in net expenses FY 2012 to $5.7 million in FY 2013. Decreased interest costs Nine Canyon Wind Project of $0.4 million and decreases in amortized bond expenses of $0.1 million TOTAL OPERATING COSTS accounted for the change. Net gain or change in net assets of $0.2 million for (Dollars in thousands)

Total Expenses FY 2013 was a direct result of the planned average rate increase with lower than budgeted operating costs.

FY2013 18,805 The original plan anticipated operating at a loss in the early years and gradually increasing the rate charged to the purchasers to avoid a large rate FY2012 17,467 increase after the REPI expires. The REPI incentive expires 10 years from the initial operation startup date for each phase. Reserves that were established are used to facilitate this plan.The rate plan in FY 2008 was revised to account FY2011 17,466 for the shortfall experienced in the REPI funding and to provide a new rate scenario out to the 2030 project end date. Energy Northwest did not receive FY2010 16,506 REPI funding in FY 2013 and is not anticipating receiving any future REPI incentives. The results from FY 2013 reflect the revised rate plan scenario and gradual increase in the return of total net assets.

FY 2009 17,632 0 3,000 6,000 9,000 12,000 15,000 M Operating Expenses U Other Income I Expenses 0 ACommitment to Excetlence

InternaL Service Fund The Internal Service Fund (ISF) (formerly the General Fund) was established The net increase in net assets and liabilities is due to increases in accounts in May 1957. The ISF provides services to the other funds. This fund accounts payable and payroll related liabilities of $9.4 million due to year-end timing for the central procurement of certain common goods and services for the of expenses for FY 2013, which was an outage year and a decrease of $15.0 business units on a cost reimbursement basis. (See Note 1 to Financial million due to other business units resulting from the change in year-end Statements.) activities.

Batance Sheet Analysis Statement of Operations Analysis Total assets increased $9.1 million from $46.6 million in FY 2012 to $55.7 Net revenues for FY 2013 increased $112,000 from FY 2012. The increase million in FY 2013. The five major items contributing to the change were 1) was due to decreased amounts of other business expenses of $146,000, decreases to net plant of $2.0 million, 2) decrease of $5.7 million to cash to decrease in depreciation of $194,000 offset by decreases in operating reflect FY 2013 recognition of year-end check redemption related to R-21 revenue due to operations of $452,000.

versus the requirements of FY 2012 which was a non-outage year, 3) an increase of $1.6 million in restricted assets due to the debt maturity schedule and escrow requirements processing schedule, 4) an increase to prepaid amounts of $0.4 million, and an increase to due from other business units of $14.8 million.

Current Debt Ra tings (Unaudited)

Nine Canyon Rating Energy Northwest (Long-Term) Net-Billed Rating Phase I & II Phase III Fitch, Inc. AA A- A-Moodys Investors Service, Inc. (Moodys) Aal A2 A2 Standard and Poor's Ratings Services (S & P) AA- A- A ntcy Noi thwest 2013 Animalc Repot t

Statement Of Net Position As of June 30, 2013 (Dollars in thousands)

Columbia Packwood Lake Nuclear Nuclear Business Nine Canyon Internal Generating Hydroelectric Project Project Development Wind Service Combined Station Project Number 1 Number 3* Fund Project Subtotal Fund Total ASSETS CURRENT ASSETS Cash $ 33,154 $ 373 $ 606 S 667 $ 5,223 * $ 8,624 $ 48,647 $ - $ 48,647 Available-for-sale 10,000 1,023 2,512 2,669 2,542 1,049 19,795 5,065 24,860 investments Accounts and other receivables 263 111 3 3 466 144 990 84 1,074 Due from other business units - 10 270 343 623 16,638 Materials and supplies 121,404 - - - 121,404 - 121,404 Prepayments and other 1,409 12 - - 140 76 1,637 1,500 3,137 TOTAL CURRENT ASSETS 166,230 1,529 3,391 3,339 8,714 9,893 193,096 23,287 199,122 RESTRICTED ASSETS (NOTE 1)

Special funds Cash 9,907 - 298 699 4 10,908 406 11,314 Available-for-sale 6,518 - 3,000 7,257 - 1,558 18,333 22,227 40,560 investments Accounts and other 22 - - 22 22 receivables Debt service funds Cash 125,970 98,267 57,632 9,959 291,828 291,828 Available-for-sale 21,482 207,975 139,799 11,364 380,620 380,620 investments Accounts and other 3 - - 3 1 7 7 receivables TOTAL RESTRICTED ASSETS 163,902 - 309,540 205,390 - 22,886 701,718 22,633 724,351 NON CURRENT ASSETS UTILITY PLANT (Note 2)

In service 3,813,536 14,437 - - 2,543 134,510 3,965,026 47,971 4,012,997 Not in service 29,415 - - 29,415 29,415 Construction work in progress 116,483 - - - - 116,483 116,483 Accumulated depreciation (2,523,438) (12,812)! (29,415): - (1,150) (54,166) (2,620,981):: (38,203): (2,659,184)

Net Utility Plant 1,406,581 1,625 - - 1,393 80,344 1,489,943 9,768 1,499,711 Nuclear fuel, net of accumu- 985,824 - - - - 985,824 - 985,824 lated depreciation LONG TERM RECEIVABLES - - " " - - - -

TOTAL NONCURRENTASSETS 2,392,405 1,625 " - 1,393 80,344 2,475,767 9,768 2,485,535 OTHER CHARGES Cost in excess of billings 880,778 " 1,093,010 1,258,171 - 3,231,959 " 3,231,959 Unamortized debt expense 14,290 - 2,813 3,888 1,424 22,415 - 22,415 Other - 3,737 - - - 3,737 - 3,737 TOTAL OTHER CHARGES 895,068 3,737 1,095,823 1,262,059 1,424 3,258,111 - 3258,111

........... .$ 3,617,6

. . .... S- - $ , 114,547. . 6,2

.. ,9 . 5 ,8 .1. S. .

TOTALASSETS $ 3,617,605 !$ 6,891 i$ 1,408,754 i$ 1,470,788 !$ 10,107 !$ 114,547 !$ 6,628,692 i$ 55,688 i$ 6,667,119'"

• Project recorded on a liquidation basis The accompanying notes are an integral part of these combined financial statements a A Comnittnent to Exceltence

Statement Of Net Position As of June 30, 2013 (Dollars in thousands)

Columbia Packwood Lake Nuclear Nuclear Business Nine Canyon Internal Generating Hydroelectric Project Project Development Wind Service Combined Station Project Number 1* Number 3* Fund Project Subtotal Fund Total LIABILITIES AND NET ASSETS CURRENT LIABILITIES Current maturities of long-term $ 61,020 $ - $ 273,055 S 166,160 $ - $ 6,835 $ 507,070 S - $ 507,070 debt Accounts payable and accrued 36,973 196 183 43 995 486 38,876 49,994 88,870 expenses Due to participants 24,959 968 - - - 25,927 - 25,927 Due to other business units 16,618 - - 10 - 10 16,638 623 TOTAL CURRENT LIABILITIES 139,570 1,164 273,238 166,213 995 7,331 588,511 50,617 621,867 LIABILITIES-PAYABLE FROM RESTRICTED ASSETS (NOTE 1)

Special funds Accounts payable and 127,163 18,244 - 1,287 146,694 353 147,047 accrued expenses Debt service funds Accrued interest payable 71,522 - 33,186 31,259 - 3,062 139,029 139,029 TOTAL RESTRICTED LIABILITIES: 198,685 - 51,430 31,259 - 4,349 285,723 353 286,076 LONG-TERM DEBT (NOTE 5)

Revenue bonds payable 3,163,020 - 1,048,005 1,229,245 124,120 5,564,390 " 5,564,390 Unamortized (discount)/ 105,591- 36,251 44,955 4,138 190,935 190,935 premium on bonds - net Unamortized loss on bond (7,175) (170): (884) - (214): (8,443) - (8,443) refundings -

TOTAL LONG-TERM DEBT 3,261,436 1,084,086 1,273,316 - 128,044 5,746,882 - 5,746,882 OTHER LONG-TERM 17,914 195 18,109 6 18,115 LIABILITIES OTHER CREDITS Advances from members - 5,727 - - 5,727 - 5,727 and others Other - - -

TOTAL OTHER CREDITS - 5,727 - - - - 5,727 - 5,727 NET POSITION Invested in capital assets, net - 1,393 (53,110) (51,717) 9,766 (41,951) of related debt Restricted, net - 17,559 17,559 22,633 40,192 Unrestricted, net 7,524 10,374 17,898 (27,687): (9,789)

NET POSITION , - " " 8,917 (25,177). (16,260): 4,712 (11,548)

TOTAL LIABILITIES 3,617,605 6,891 1,408,754 1,470,788 1,190 139,724 6,644,952 50,976 6,678,667 TOTAL LIABILITIES AND NET $ 3,617,605 $ 6,891 $ 1,408,754 $ 1,470,788 S 10,107 $ 114,547 $ 6,628,692 $ 55,688 $ 6,667,119 POSITION

• Project recorded on a liquidation basis The accompanying notes are an integral part of these combined financial statements 0

Statements Of Revenues, Expenses, And Changes In Net Position As Of June 30, 2013 (Dottars in thousands)

Columbia Packwood Nuclear Nuclear Business Nine Canyon Internal 2013 Generating Lake Project Project Development Wind Service Combined Station Project No.1* No.3* Fund Project Subtotal Fund Total OPERATING REVENUES $ 539,667 $ 2,173 $ -S <$ 9,024 $ 18,999 ]$ 569,863 $ $ 569,863 OPERATING EXPENSES Services to other business units Nuclear fuel 42,433 42,433 42,433 Spent fuel disposal fee 8,059 8,059 8,059 Decommissioning 6,306 84 6,390 6,390 Depreciation and amortization 83,967 57 240 6,814 91,078 91,078 Operations and maintenance 246,376 1,938 9,167 6,121 263,602 263,602 Administrative & general 27,775 164 34 27,973 - 27,973 Generation tax 4,023 22 49 4,094 - 4,094 Iotal operating expenses 418,939 2, 9I, 13,,U/U6 44I3 44,436 -9 OPERATING INCOME (LOSS) 120,728 (8): (383)! 5,897 126,234 126,234 OTHER INCOME &EXPENSE Other 4,785 3 55,032 55,906 1,308 12 117,046 82,214 116,978 Investment income 645 5 68 50 20 61 849 11 849 Interest expense and discount amortization (126,158): (51,919): (55,594) (5,776): (239,447): (239,447)

Plant preservation and termination costs (1,336): (362): (1,698): (1,698)

Depreciation and (6)1 (6): 2,109 (6) amortization Decommissioning (1,839)- (1,839): -i_ (1,839)

Services to other (84,402):

business units TOTAL OTHER INCOME &EXPENSE (120,728):: 8 - - 1,328 (5,703): (125,095): (68): (125,163) 4 4 --------

INCOME (LOSS) - 945 194 1,139 (68)i 1,071 TOTAL NETASSETS, BEGINNING OFYEAR - -. 7,972 (25,371): (17,399): 4,780 (12,619)

TOTAL NETASSETS, END OFYEAR $ $ $ - $ -* $ 8,917 $ (25,177): $ (16,260)i $ 4,712 . $ (11,548)

• Project recorded on a liquidation basis The accompanying notes are an integral part of these combined financial statements M A Commitment to Excelence

Statement of Cash FLows As of June 30, 2013 (DolLars in thousands)

Packwood Columbia Lake Nuclear Nuclear Business Nine Canyon Internal 2013 Generating Hydroelectric Project Project Development Wind Service Combined Station Project No.1 No.3

• Fund Project Fund Total CASH FLOWS FROM OPERATING AND NON-OPERATING ACTIVITIES Operating revenue receipts $ 478,335 $ 2,011 $ - $ - $ 5,074 $ 19,002 $ $ 504,422 Cash payments for operating expenses (275,172) (2,033) - (1,159) (6,069) (284,433)

Non-operating revenue receipts 112 338,733 228,232 (67) - - 567,010 Cash payments for preservation, termination expense - - (534): (22) (556)

Cash payments for services - - - - - (4,192): (4,192)

Net cash provided/l(used) by operating 203,275 (22) 338,199 228,210 3,848 12,933 (4,192): 782,251 and nonoperating activities CASH FLOWS FROM CAPITALAND RELATED FINANCING ACTIVITIES Proceeds from bond refundings 785,282 - - - - 785,282 Payment for bond issuance and financing costs (4,063) _ (295) (306) (1) (24) .. (4,689)

Payment for capital items (65,339). (770) - .. (333) . (37) (66,479)

Nuclear fuel acquisitions . (679,614) - - - (679,614)

Interest paid on bonds (133,511) (75,205) (64,989) (6,119) - (279,824)

Principal paid on revenue bond maturities (355) - (236,030) (95,540) - (4,575) - (336,500)

Note Payment (61,769) -....- (61,769)

Interest paid on Notes (110). - - - - (110)

Net cash provided/l(used) by capital and related (159,479) (770) (311,530) (160,835): (334): (10,755) (643,703) financing activities CASH FLOWS FROM NON-CAPITAL FINANCE ACTIVITIES CASH FLOWS FROM INVESTING ACTIVITIES Purchases of investment securities (592,637) (1,046): (214,700) (181,777) (2,560): (22,339). (25,490) (1,040,549)

Sales of investment securities 615,262 975 194,710 69,005 2,035 28,792 24,640 935,419 Interest on investments . 1,794 41 34 , 31 . 62 230 (622) 1,570 Net cash providedl(used) by investing activities 24,419 (30) (19,956) (112,741) (463) 6,683 (11,472) (103,560)

NET INCREASE(DECREASE) IN CASH 68,215 (822)i 6,713 (45,366) 3,051 8,861 (5,664), 34,988 CASH ATJUNE 30, 2012 100,817 1,195 92,458 104,363 2,172 9,726 6,070 316,801 CASH ATJUNE 30, 2013 (NOTE B) $ 169,032 $ 373 $ 99,171 $ 58,997 $ 5,223 $ 18,587 $ 406 $ 351,789 Project recorded on a liquidation basis The accompanying notes are an integral part of these combined financial statements (jVNoiipi',t20]AinuaIl~tep(i M

Statement of Cash Flows As of June 30, 2013 (Dottars in thousands)

Packwood Columbia i Lake Nuclear Nuclear Business Nine Canyon Internal 2013 Generating Hydroelectric Project Project Development Wind Service Combined Station Project No.1

• No.3

• Fund Project Fund Total RECONCILIATION OF NET OPERATING REVENUES TO NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES Net operating revenues -- ---- - - - - -

120,728 $ () $. $ $ (383) : $ 5,897 :$ $ 126,234 Adjustments to reconcile net operating revenues to cash provided by operating activities: -

Depreciation and amortization 124,410 48 157 6,793 131,408 Decommissioning 6,306 33 6,339 Other (2,041): 770 1,458 37 224 Change in operating assets and liabilities:

Deferred charges/costs in excess of billings (61,332)' (48), (61,380)

Accounts receivable 980 11 1 (51) (9): 931 Materials and supplies (10 201): (10,201)

Prepaid and other assets (98)1 62 2,572 202 2,738 Due from/to other business units, funds 14,874 (915) 76 14,035 and Participants Accounts payable 9,537 58 95 (96): 9,594 Non-operating revenue receipts 112 338,733 228,232 567,077 Cash payments for preservation, termination expense - -- - (534) (22)i (556)

Cash payments for services (4,192) (4,192)

Net cash provided (used) by operating $ 203,275 $ (22): $ 338,199 $ 228,210 $ 3,848 $ 12,933 $ (4,192):: $ 782,251 and nonoperating activities _ ________

• Project recorded on a liquidation basis The accompanying notes are an integral part of these combined financial statements

• A Cot miitment to Exceltence

Notes To Financiat Statements Note 1 - Summary of Operations and Significant construction delay status in 1982, when it was 65 percent complete. Nuclear Accounting Policies Project No. 3, a 1,240-MWe plant, was placed in extended construction delay status in 1983, when it was 75 percent complete. On May 13, 1994, Energy Northwest, a municipal corporation and joint operating agency of Energy Northwest's Board of Directors adopted resolutions terminating the state of Washington, was organized in 1957 to finance, acquire, construct Nuclear Projects Nos. 1 and 3. All funding requirements remain as net-billed and operate facilities for the generation and transmission of electric power. obligations of Nuclear Projects Nos. 1 and 3. Energy Northwest wholly owns Membership consists of 22 public utility districts and 5 municipalities. All Nuclear Project No. 1. Energy Northwest is no longer responsible for site members own and operate electric systems within the state of Washington. restoration costs for Nuclear Project No. 3 (See Note 13).

Energy Northwest is exempt from federal income tax and has no taxing The Business Development Fund was established in April 1997 to pursue authority. and develop new energy related business opportunities. There are four Energy Northwest maintains seven business units. Each unit is financed main business lines associated with this business unit: General Services and and accounted for separately from all other current or future business units. Facilities, Generation, Professional Services, and Business Unit Support.

All electrical energy produced by Energy Northwest's net-billed business The Nine Canyon Wind Project (Nine Canyon) was established in January units is ultimately delivered to electrical distribution facilities owned and 2001 for the purpose of exploring and establishing a wind energy project.

operated by Bonneville Power Administration (BPA) as part of the Federal Phase I of the project was completed in FY 2003 and Phase IIwas completed Columbia River Power System. BPA in turn distributes the electricity to in FY 2004. Phase I and II combined capacity is approximately 63.7 MWe.

electric utility systems throughout the Northwest, including participants in Phase III was completed in FY 2008 adding an additional 14 wind turbines Energy Northwest's business units, for ultimate distribution to consumers. to Nine Canyon and adding an aggregate capacity of 32.2 MWe. The total Participants in Energy Northwest's net-billed business units consist of public number of turbines at Nine Canyon is 63 and the total capacity is 95.9 MWe.

utilities and rural electric cooperatives located inthe western United States The Internal Service Fund was established in May 1957. It iscurrently used who have entered into net-billing agreements with Energy Northwest and to account for the central procurement of certain common goods and services BPA for participation in one or more of Energy Northwest's business units. for the business units on a cost reimbursement basis.

BPA is obligated by law to establish rates for electric power which will recover Energy Northwest's fiscal year begins on July 1 and ends on June 30. In the cost of electric energy acquired from Energy Northwest and other sources, preparing these financial statements, the company has evaluated events and as well as BPA's other costs (see Note 6). transactions for potential recognition or disclosure through October 30, 2013, Energy Northwest operates the Columbia Generating Station (Columbia), the date the financial statements were issued.

a 1,170-MWe (Design Electric Rating, net) generating plant completed The following is a summary of the significant accounting policies:

in 1984. Energy Northwest has obtained all permits and licenses required to operate Columbia. Columbia was issued a standard 40-year operating a) Basis of Accounting and Presentation: The accounting policies of license by the Nuclear Regulatory Commission (NRC) in 1983. On January Energy Northwest conform to Generally Accepted Accounting Principles 19, 2010 Energy Northwest submitted an application to the NRC to renew (GAAP) applicable to governmental units. The Governmental Accounting the license for an additional 20 years, thus continuing operations to 2043. Standards Board (GASB) is the accepted standard-setting body for A renewal license was granted by the NRC on May 22, 2012 for continued establishing governmental accounting and financial reporting principles.

operation of Columbia to December 31, 2043. Energy Northwest has applied all applicable GASB pronouncements Energy Northwest also operates the Packwood Lake Hydroelectric Project and elected to apply Financial Accounting Standards Board (FASB)

(Packwood), a 27.5-MWe generating plant completed in 1964. Packwood standards except for those conflicting with or in contradiction to GASB has been operating under a 50-year license issued by the Federal Energy pronouncements. The accounting and reporting policies of Energy Regulatory Commission (FERC), which expired on February 28, 2010. Energy Northwest are regulated by the Washington State Auditor's Office and Northwest submitted the Final License Application (FLA) for renewal of the are based on the Uniform System of Accounts prescribed for public operating license to FERC on February 22, 2008. On March 4, 2010, FERC utilities and licensees by FERC. Energy Northwest uses the full accrual issued a one-year extension, or until the issuance of a new license for the basis of accounting where revenues are recognized when earned and project or other disposition under the Federal Power Act, whichever comes expenses are recognized when incurred. Revenues and expenses related first. FERC is awaiting issuance of the National Oceanic and Atmospheric to Energy Northwest's operations are considered to be operating Administration's (NOAA) Biological Opinion, after which FERC will complete revenues and expenses; while revenues and expenses related to capital, the final license renewal documentation for Packwood. Costs incurred to financing and investing activities are considered to be other income and date for relicensing are $3.7 million included inother deferred charges. expenses. Separate funds and books of accounts are maintained for each The electric power produced by Packwood is sold to 12 project participant business unit. Payment of the obligations of one business unit with funds utilities which pay the costs of Packwood. The Packwood participants are of another business unit is prohibited, and would constitute violation of obligated to pay annual costs of Packwood including debt service, whether bond resolution covenants (See Note 5).

or not Packwood is operable. The participants also share Packwood revenue. Energy Northwest maintains an Internal Service Fund for centralized (See Note 6). control and accounting of certain capital assets such as data processing Nuclear Project No. 1, a 1,250-MWe plant, was placed in extended equipment, and for payment and accounting of internal services, payroll, Fnetgy Northwest 2013 Annual Report

benefits, administrative and general expenses, and certain contracted statement establishes standards for measuring and recognizing liabilities, services on a cost reimbursement basis. Certain assets in the Internal deferred outflows and deferred inflows of resources and expenses. For Service Fund are also owned by this Fund and operated for the benefit defined benefit pension plans, this statement identifies the methods of other projects. Depreciation relating to capital assets is charged to the and assumptions to project benefit payments, discount projected benefit appropriate business units based upon assets held by each project. payments to their actuarial present value and attribute present value to Liabilities of the Internal Service Fund represent accrued payroll, periods of employee service. Note disclosure and required supplementary vacation pay, employee benefits, and common accounts payable which information about pensions are also addressed. Statement No. 68 is have been charged directly or indirectly to business units and will be effective for Energy Northwest beginning in fiscal year 2015. Energy funded by the business units when paid. Net amounts owed to, or from, Northwest is currently evaluating the financial statement impact of Energy Northwest business units are recorded as Current Liabilities-Due adopting this statement.

to other business units, or as Current Assets-Due from other business units on the Internal Service Fund Balance Sheet. b) Utility Plant and Depreciation: Utility plant is recorded at original The combined total column on the financial statements is for cost which includes both direct costs of construction or acquisition and presentation (unaudited) only as each Energy Northwest business unit indirect costs.

is financed and accounted for separately from all other current and Property, plant, and equipment are depreciated using the straight-future business units. The FY 2013 Combined Total includes eliminations line method over the following estimated useful lives:

for transactions between business units as required in GASB Statement No. 34, "Basic Financial Statements and Management's Discussion and Buildings and Improvements 20- 60 years Analysis for State and Local Governments." Generation Plant 40 years Pursuant to GASB Statement No. 20, "Accounting and Financial Transportation Equipment 6- 9 years Reporting for Proprietary Funds and Other Governmental Entities That General Plant and Equipment 3 - 15 years Use Proprietary Fund Accounting," Energy Northwest has elected to apply all FASB standards, except for those that conflict with, or contradict, Group rates are used for assets and, accordingly, no gain or loss GASB pronouncements. Specifically, GASB No. 7, "Advance Refundings is recorded on the disposition of an asset unless it represents a major Resulting in Defeasance of Debt," and GASB No. 23, "Accounting and retirement. When operating plant assets are retired, their original cost Financial Reporting for Refundings of Debt Reported by Proprietary together with removal costs, less salvage, is charged to accumulated Activities," conflict with ASC 860, "Transfers and Servicing." As such, depreciation.

the guidance under GASB No. 7 and No. 23 is followed. Such guidance The utility plant and net assets of Nuclear Projects Nos. 1 and 3 have governs the accounting for bond defeasances and refundings. been reduced to their estimated net realizable values due to termination.

In June 2011, GASB issued Statement No. 63, "Financial Reporting A write-down of Nuclear Projects Nos. 1 and 3 was recorded in FY 1995 of Deferred Outflows of Resources, Deferred Inflows of Resources and and included in Cost in Excess of Billings. Interest expense, termination Net Position." Statement No. 63 amends the current net assets reporting expenses and asset disposition costs for Nuclear Projects Nos. 1 and 3 requirements by incorporating deferred inflows of resources and deferred have been charged to operations (see Note 15).

outflows of resources into the definitions of required financial statement components and renames "Net Assets" as "Net Position." Statement No. c) Capitalized Interest: Energy Northwest analyzes the gross interest 63 iseffective for Energy Northwest beginning in fiscal year 2013. Energy expense relating to the cost of the bond sale, taking into account interest Northwest's financial statements have been modified to conform to the earnings and draws for purchase or construction reimbursements for the requirements of this statement. Implementation did not have a material purpose of analyzing impact to the recording of capitalized interest. If impact on the Energy Northwest's financial results. estimated costs are more than inconsequential, an adjustment is made to In March 2012, GASB issued Statement No. 65, "Items, Previously allocate capitalized interest to the appropriate plant account. Capitalized Reported as Assets and Liabilities." Statement No. 65 establishes interest costs were $1.6 million.

accounting and financial reporting standards to reclassify certain items previously reported as assets and liabilities as deferred outflows or d) Nuclear Fuel: Energy Northwest has various agreements for uranium deferred inflows of resources, or as outflows or inflows of resources. This concentrates, conversion, and enrichment to provide for short-term statement also limits the use of the term deferred in financial statement enriched uranium product and long-term enrichment services. All presentations. This statement is effective for Energy Northwest beginning expenditures related to the initial purchase of nuclear fuel for Columbia, in fiscal year 2014. The District is currently assessing the financial including interest, were capitalized and carried at cost.

statement impact of adopting this statement, but does not believe that its impact will be material. e) Asset Retirement Obligation: Energy Northwest has adopted ASC In June 2012, GASB issued Statement No. 68, "Accounting and 410, "Asset Retirement and Environmental Obligations." This standard Financial Reporting for Pensions -An Amendment of GASB Statement No. requires Energy Northwest to recognize the fair value of a liability 27." The primary objective of Statement No. 68 is to improve accounting associated with the retirement of a long-lived asset, such as: Columbia and financial reporting by state and local governments for pensions. This Generating Station, Nuclear Project No. 1, and Nine Canyon, in the period in which it is incurred (see Note 11).

M A Commitment to Excellence

f) Decommissioning and Site Restoration: Energy Northwest n) Long-Term Liabilities: Consist of obligations related to bonds established decommissioning and site restoration funds for Columbia payable and the associated premiums/discounts and gains/losses. Other and monies are being deposited each year in accordance with an noncurrent liabilities for Columbia relates to the dry storage cask activity.

established funding plan (see Note 12).

o) Debt Premium, Discount and Expense: Original issue and reacquired g) Derivative Instruments: In June 2008, GASB issued Statement No. bond premiums, discounts and expenses relating to the bonds are 53, "Accounting and Financial Reporting for Derivative Instruments." amortized over the terms of the respective bond issues using the bonds Statement No. 53 provides a comprehensive framework for the outstanding method which approximates the effective interest method.

measurement, recognition and disclosure of derivative instrument In accordance with GASB Statement No. 23, "Accounting and Financial transactions for the purpose of enhancing the usefulness and Reporting for Refundings of Debt Reported by Proprietary Activities,"

comparability of derivative instrument information reported by state and losses on debt refundings have been deferred and amortized as a local governments (see Note 14). component of interest expense over the shorter of the remaining life of the old or new debt.

h) Restricted Assets: In accordance with bond resolutions, related agreements and laws, separate restricted accounts have been p) Revenue Recognition: Energy Northwest accounts for expenses on established. These assets are restricted for specific uses including debt an accrual basis, and recovers, through various agreements, actual cash service, construction, capital additions and fuel purchases, unplanned requirements for operations and debt service for Columbia, Packwood, operation and maintenance costs, termination, decommissioning, Nuclear Project No. 1 and Nuclear Project No. 3. For these business units, operating reserves, financing, long-term disability, and workers' Energy Northwest recognizes revenues equal to expenses for each period.

compensation claims. They are classified as current or non-current assets No net revenue or loss is recognized, and no net assets are accumulated.

as appropriate. The difference between cumulative billings received and cumulative expenses is recorded as either billings inexcess of costs (deferred credit) i) Cash and Investments: For purposes of the Statements of Cash or as costs in excess of billings (deferred debit), as appropriate. Such Flows, cash includes unrestricted and restricted cash balances and each amounts will be settled during future operating periods (see Note 6).

business unit maintains its cash and investments. Short-term highly Energy Northwest accounts for revenues and expenses on an accrual liquid investments are not considered to be cash equivalents, but are basis for the remaining business units.The difference between cumulative classified as available-for-sale investments and are stated at fair value revenues and cumulative expenses is recognized as net revenue or loss with unrealized gains and losses reported in investment income (see and included in Net Assets for each period.

Note 3). Energy Northwest resolutions and investment policies limit investment authority to obligations of the United States Treasury, q) Capital Contribution: Renewable Energy Performance Incentive (REPI)

Federal National Mortgage Association and Federal Home Loan Banks. payments enable Nine Canyon to receive funds based on generation as Safe keeping agents, custodians, or trustees hold all investments for the it applies to the REPI bill. REPI was created as part of the Energy Policy benefit of the individual Energy Northwest business units. Act of 1992 to promote increases in the generation and utilization of electricity from renewable energy sources and to further the advances of j) Accounts Receivable: The percentage of sales method is used to renewable energy technologies.

estimate uncollectible accounts. The reserve is then reviewed for This program, authorized under section 1212 of the Energy Policy Act adequacy against an aging schedule of accounts receivable. Accounts of 1992, provides financial incentive payments for electricity produced deemed uncollectible are transferred to the provision for uncollectible and sold by new qualifying renewable energy generation facilities. Nine accounts on a yearly basis. Accounts receivable specific to each business Canyon did not record a receivable for FY 2013 REPI funding as no unit are recorded in the residing business unit. funds are anticipated to be disbursed to Energy Northwest under this program. The payment stream from Nine Canyon participants and the k) Other Receivables: Other receivables include amounts related to the anticipated REPI funding were projected to cover the total costs of the Internal Service Fund from miscellaneous outstanding receivables from purchase agreement. Permanent shortfalls in REPI funding for the Nine other business units which have not yet been collected. The amounts Canyon project led to a revised rate plan to incorporate the impact of due to each business unit are reflected in Due To/From other business this shortfall over the life of the project. The current rate schedule for the units. Other receivables specific to each business unit are recorded in the Nine Canyon participants covers total estimated project costs occurring residing business unit. inFY 2013 and estimated total cost recovery projections out to the 2030 proposed end date. During FY 2013 there was no cost recovery obtained

1) Materials and Supplies: Materials and supplies are valued at cost from REPI.

using the weighted average cost method.

m) Leases: Consist of separate operating lease agreements. The total of these leases by business unit and their respective amounts paid per year are listed in the table on the next page.

Enot oly>Fui thwtet 21012`Aimun Rei eport

Projects Operating Lease Costs (Dottars in thousands) 2014 20151 2016 2017 2018 2019+

Columbia $ 723 $ 723 $ 723 $ 723 $ 723 $ 18,082 Nuclear Project No. 1 35 35 35 . 35 35 210 Nine Canyon 684 684 684 684~ 684 8,209 Business Development Fund 169 169 169 169 169 226 Internal Service Fund 147 147 147 147 147 1,655 Packwood Lake Project 81 81 81 81 81 81 Total 1,839 $ 1,839 $ 1,839 $ 1,839 $ 1,839 1 $ 28,463 Long-Term Liabilities (Dotlars in thousands)

Balance 6/30/2012 INCREASES DECREASES Balance 6/30/2013 Columbia Revenue bonds payable $ 2,441,385 $ 782,655 $ 61,020 $ 3,163,020 Unamortized (discount)/premium on bonds - net 120,221 2,632 17,262 105,591 Unamortized gain/(loss) on bond refundings (9,966):: 3,371 580 (7,175)

Other noncurrent liabilities 15,776 2,142 4 17,914

$ 2,567,416 $ 790,800 $ 78,866 $ 3,279,350 Nuclear Project No.1 Revenue bonds payable $ 1,321,060 $ -S$ 273,055 $ 1,048,005 Unamortized (discount)/premium on bonds - net 56,290 30 20,069 36,251 Unamortized gain/(loss) on bond refundings (3,614):: 3,905 461 (170)

$ 1,373,736 $ 3,935 $ 293,585 $ 1,084,086 Nuclear Project No.3 Revenue bonds payable 1,395,405 $ 166,160 $ 1,229,245 Unamortized (discount)/premium on bonds -net 53,241 8,403 16,689 44,955 Unamortized gain/(Iloss) on bond refundings (974): 913 823 (884)

$ 1,447,672 4$ 9,316 i $ 183,672 : $ 1,273,316 Nine Canyon Revenue bonds payable 130,955$ 6,835$ 124,120 Unamortized (discount)/premium on bonds -net 4,743 605 4,138 Unamortized gain/(Iloss) on bond refundings (279):: 88 22 (214)

$ 135,419 : $ 88 $ 7,462 $ 128,044 fl A Commitment to Exce[Lence

r) Compensated Absences: Employees earn leave in accordance with S) Use of Estimates: The preparation of Energy Northwest financial length of service. Energy Northwest accrues the cost of personal leave in statements in conformity with GAAP requires management to make the year when earned. The liability for unpaid leave benefits and related estimates and assumptions that directly affect the reported amounts payroll taxes was $20.8 million at June 30, 2013 and is recorded as a of assets and liabilities, disclosures of contingent assets and liabilities current liability. at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from these estimates. Certain incurred expenses and revenues are allocated to the business units based on specific allocation methods that management considers to be reasonable.

Note 2 - UtiLity PLant Utility plant activity for the year ended June 30, 2013 was as follows:

Utility Plant Activity (Dottars in thousands)

Balance 6/30/2012 Capital Acquisitions Sale or Other Dispositions Balance 6/30/2013 Columbia Generation $ 3,791,326 $ 7,482 $ (41): $ 3,798,767 Decommissioning 14,256 512 14,768 Construction Work-in-Progress 60,553 282,452 (226,522) 116,483 Accumulated Depreciation and Decommissioning (2,441,485). (81,993) 41 (2,523,438)

Utility Plant, net* $ 1,424.650 $ 208,453 $ (226,522) $ 1,406,581 Packwood Generation $ 13,625 $ 812 $ . $ 14,437 Construction Work-in-Progress 812 (812):

Accumulated Depreciation (12,764): (48): (12,812)

Utility Plant, net $ 861 $ 1,576 $ (812)i $ 1,625 Business Development General $ 2,174 $ 369.$ - $ 2,543 Construction Work-in-Progress 369 (369);

Accumulated Depreciation (993), (157)- (1,150)

Utility Plant, net $ 1,181 $ 581 $ (369); $ 1,393 Nine Canyon Generation $ 133,6451$ 37 $ (32): $ 133,649 Decommissioning 861 861 Construction Work-in-Progress 37 (37).

Accumulated Depreciation and Decommissioning (47,372)!: (6,826): 32 (54,166)

Utility Plant, net $ 87,133 $ (6,752)] $ (37)i $ 80,345 Internal Service Fund General $ 48,410 $ 59 $ (500) $ 47,969 Construction Work-in-Progress - 59 (59)

Accumulated Depreciation (36,594) (2,109) 500 (38,203)

Utility Plant, net $ 11,816 $ (1,990). $ (59) $ 9,766 U

Note 3 -

Available-for-Sale Investments (Dollars in thousands)

Amortized Cost Unrealized Gains Unrealized Losses Fair Value (1) (2)

Columbia $ 37,986 $ 14 $ $ 38,000 Packwood 1,023 1,023 Nuclear Project No. 1 213,488 213,488 Nuclear Project No. 3 149,725 149,725 Business Development Fund 2,540 2,540 Internal Service Fund 27,202 5 (4) 27,203 Nine Canyon 13,971 2 (2) 13,971 (1) All investments are in U.S. Government backed securities including U.S. Government Agencies and Treasury Bills.

(2) The majority of investments have maturities of less than 1 year. Approximately $1.5 million have a maturity beyond 1 year with the longest maturity being July 5th, 2014.

Of the total $1.5 million maturing beyond 1 year, $1.0 million resides in the Business Development Fund and the remaining $0.5 million resides with Packwood.

Interest Rate Risk: In accordance with its investment policy, Energy Custodial Credit Risk, Deposits: For a deposit, this is the risk that in the Northwest manages its exposure to declines in fair values by limiting investments event of bank failure, Energy Northwest's deposits may not be returned to it.

to those with maturities designated in specific bond resolutions. Energy Northwest's interest bearing accounts and certificates of deposits are Credit Risk: Energy Northwest's investment policy restricts investments to covered up to $250,000 by Federal Depository Insurance (FDIC) while non-interest debt securities and obligations of the U.S. Treasury U.S. government agencies bearing deposits are entirely covered by FDIC and if necessary, all interest and Federal National Mortgage Association and the Federal Home Loan Banks, non-interest bearing deposits are covered by collateral held in a multiple financial certificates of deposit and other evidences of deposit at financial institutions institution collateral pool administered by the Washington state Treasurer's Local qualified by the Washington Public Deposit Protection Commission (PDPC), and Government Investment Pool (PDPC). Under state law, public depositories under general obligation debt of state and local governments and public authorities the PDPC may be assessed on a prorated basis ifthe pool's collateral is insufficient recognized with one of the three highest credit ratings (AAA, AA+, AA, or to cover a loss. All deposits are insured by collateral held inthe multiple financial equivalent). This investment policy is more restrictive than the state law. institution collateral pool. State law requires deposits may only be made with Concentration of Credit Risk: Energy Northwest's investment policy does institutions that are approved by the PDPC.

not specifically address concentration of credit risk. An individual authorized security or obligation can receive up to 100 percent of the authorized investment amount; there are no individual concentration limits.

Note 4 - Other Charges and Credits for Resources Other credits of $3.7 million relate to the Packwood relicensing effort. Other credits of $0.1 million for Nine Canyon consist of turbine elevator purchases to be completed in FY 2014.

Note 5 - Long-Term Debt Each Energy Northwest business unit is financed separately. The resolutions of Bonds), Resolution No. 1299 (2003 Bonds), Resolution No. 1376 (2005 Bonds),

Energy Northwest authorizing issuance of revenue bonds for each business unit Resolution No.1482 (2006 Bonds), and Resolution No. 1722 (2012 Bonds).

provide that such bonds are payable from the revenues of that business unit. All During the year ended June 30,2013, Energy Northwest issued, for Columbia bonds issued under resolutions Nos. 769, 775 and 640 for Nuclear Projects Nos. Series 2012-D and 2012-E fixed rate bonds with a weighted average coupon 1, 3 and Columbia, respectively, have the same priority of payment within the interest rate ranging from 1.06 percent to 5.0 percent.

business unit (the "prior lien bonds"). All bonds issued under resolutions Nos. The Series 2012-D bonds issued for Columbia are tax-exempt fixed-rate 835, 838 and 1042 (the "electric revenue bonds") for Nuclear Projects Nos. 1, 3 bonds. Series 2012-E bonds issued for Columbia are taxable fixed rate bonds.

and Columbia, respectively, are subordinate to the prior lien bonds and have the These bonds were issued in majority to cover fuel purchases (See Note 1).

same subordinated priority of payment within the business unit. Nine Canyon's The Bond Proceeds, Weighted Average Coupon Interest Rates and Bond bonds were authorized by the following resolutions: Resolution No. 1214 (2001 Proceeds for 2012-D and 2012-E are presented in the following tables:

A Cornmnittnent to Excelience

Bond Proceeds (Dollars in millions) 2012D 2012E Total Columbia $ 34.14 $ 748.52 $ 782.66 Total $ 34.14 $ 748.52 $ 782.66 Weighted Average Coupon Interest Rate for New Bonds 2012D 2012E Columbia 4.48% 2.50%

Total 4.08% 5.00%

Energy Northwest did not issue or refund any bonds associated with Project No. 1, Project No. 3, Packwood, and Nine Canyon during FY 2013.

Outstanding principal on revenue and refunding bonds for the various business units as of June 30, 2013, and future debt service requirements for these bonds are presented in the following tables:

Columbia Generating Revenue and Refunding Bonds Nuclear Project No. 1 Refunding Revenue Bonds (Dollars in thousands) (Dollars in thousands)

Serial or Term Serial or Term Series Coupon Rate (%) Maturities Amount Series Coupon Rate (%) Maturities Amount I I 2003A 5.50 7-1-2015 $ 81,090 1989B 7.125 7-1-2016 $ 41,070 2003F 5.00-5.25 7-1-13/2018 23,710 2003A 5.50 7-1-13/2014 174,400 2004A 5.25 7-1-17/2018 129,260 2004A 5.25 7-1-2013 62,485 2004B 5.50 7-1-2013 12,715 2004B 5.50 7-1-2013 1,135 2004C 5.25 7-1-13/2018 15,045 2005A 5.00 7-1-13/2015 72,175 2005A 5.00 7-1-15/2018 114,985 2006A 5.00 7-1-13/2017 103,120 2005C 4.64-4.74 7-1-13/2015 42,885 2007A 5.00 7-1-13/2017 51,730

- 201---

7-1-- 3 2006A 5.00 7-1-2012024 434,210 2007B 5.10 7-1-2013 2,290 2006C 5.00 7-1-20/2024 62,200 2007C 5.00 7-1-1312017 219,020 2006D 5.80 7-1-2023 3,425 2008A 5.00-5.25 7-1-1312017 230,535 2007A 5.00 7-1-13/2018 77,575 2008D 5.00 7-1-13/2017 38,100 2007B 5.10-5.33 7-1-13/2021 10,310 2009A 3.25-5.00 7-1-14-2015 48,905 2007D 5.00 7-1-21/2024 35,080 20098 4.59 7-1-2014 515 2008A 5.00-5.25 7-1-14/2018 110,935 2010A 3.00-5.00 7-1-13/2017 54,805 20088 5.95 7-1-20/2021 12,025 2012A 5.00 7-1-13/2017 155,390 2008C 5.00-5.25 7-1-21/2024 37,240 20128 5.00 7-1-2017 41,285 3.00-5.00 7-1-14/2018 116,425 2012C 1.26 7-1-2015 24,100 2009A 2009B 4.59-6.80 7-1-1412024 18,515 2009C 4.25-5.00 7-1-20/2024 69,170 Revenue bonds payable $ 1,321,060 20108 3.75-4.25 7-1-20/2024 16,005 Estimated fair value at June 30, 2013 $ 1,425,123 (A) 2010C 4.52-5.12 7-1-20/2024 75,770 (A) The estimated fair value shown has been reported to meet the disclosure requirements of the 2010D 5.61-5.71 7-1-23/2024 155,805 Accounting Standards Codification (ASC) 820 and does not purport to represent the amounts at which these obligations would be settled.

2011A 3.00-5.00 7-1-13/2023 311,245 2011B 4.19-5.19 7-1-19/2024 29,920 2011C 3.55 7-1-2019 4,600 2012A 5.00 7-1-18/2021 441,240 2012D 5.00 7-1-25/2044 34,140 2012E 1.06-4.14 7-1-15/2037 748,515 Revenue bonds payable $ 3,224,040 Estimated fair value at June 30, 2013 1$ 3,512,957 (A)

(A) The estimated fair value shown has been reported to meet the disclosure requirements of the Accounting Standards Codification (ASC) 820 and does not purport to represent the amounts at which these obligations would be settled.

Lntg y Not t / weA, 20 13 Aniit a Rp

Nuclear Project No. 3 Refunding Revenue Bonds Nine Canyon Wind Project Revenue (Dollars in thousands) and Refunding Bonds (Dollars inthousands)

Serial or Term Series Coupon Rate (%) Maturities Amount Serial or Term Series Coupon Rate (%) Maturities Amount 1989A (B) 7-1-1312014 $ 2,815 i -

2005 4.50-5.00 7-1-13/2023 $ 48,370 1989B (B) 7-1-13/2014 8,297 2006 4.50-5.00 7-1-13/2030 68,835 7.125 7-1-2016 76,146 2012 2.00-5.00 7-1-13/2023 13,750 Subtotal 1989A and 19898 87,258 Revenue bond payable $ 130,955 1993C (A) 7-1-312018 23,963 Estimated fair value at June 30, 2012 $ 136,617 (A) 2003A 5.50 7- -2013 52,890 (A) The estimated fair value shown has been reported to meet the disclosure requirements of the 2004A 5.25 7-1-14/2016 83,835 Accounting Standards Codification (ASC) 820 and does not purport to represent the amounts at 2004B 5.50 7-1-2013 1,515 which these obligations would be settled.

2005A 5.00 7-1-13/2015 129,265 2006A 5.00 7-1-16/2018 39,445 2007A 4.50-5.00 7-1-13/2018 84,465 2007C 5.00 7-1-13/2018 55,045 Total Bonds Payable $6,071,460 2008A 5.25 7- -2018 13,790 Estimated Fair Value at June 30,2013 $6,612,359 2008D 5.00 7-1-13/2017 33,595 2009A 5.00-5.25 7-1-14/2018 116,055 2009B 4.59 7-1-2014 970 2010A 5.00 7-1-16/2018 279,980 2010B 5.00 7-1-2016 29,865 2011A 4.00-5.00 7-1-2018 92,285 2012A 5.00 7-1-2018 67,885 20128 3.00-5.00 7-1-16/2017 30,330 2012C 1.26-1.74 7-1-15/2016 61,635 Compound interest bonds accretion 111,334 Revenue bonds payable $ 1,395,405 Estimated fair value at June 30, 2013 $ 1,537,662 (A)

(A) The estimated fair value shown has been reported to meet the disclosure requirements of the Accounting Standards Codification (ASC) 820 and does not purport to represent the amounts at which these obligations would be settled.

(B)Compound Interest Bonds 0 A Commitment to Exceltence

Debt Service Requirements As of June 30, 2013 (Dollars in thousands)

Columbia Generating Station Nuclear Project No. 1 Fiscal Year*** Principal Interest Total Fiscal Year*

• Principal Interest Total 2013 $ 61,020 $ 71,522 $ 132,542 2013 $ 273,055 $ 33,186 $ 306,241 2014 79,765 140,052 219,817 2014 332,100 52,401 384,501 2015-2017 419,645 382,322 801,967 2015 191,430 35,443 226,873 2018-2022 1,927,765 423,440 2,351,205 2016 239,385 27,026 266,411 2023-2024 648,950 57,484 706,434 2017 285,090 14,117 299,207 2025-2028 54,275 9,799 64,074 2029-2044 32,620 12,972 45,592

$ 3,224,040 $ 1,097,591 $ 4,321,631 $ 1,321,060 $ 162,174 $ 1,483,234 Principal and Interest due July 1, 2013. Principal and Interest due July 1, 2013.

• Fiscal year for this report indicates when the obligations are expected to be paid.

• Fiscal year for this report indicates when the obligations are expected to be paid.

Nuclear Project No. 3 Nine Canyon Wind Project Fiscal Year- Principal Interest Total Fiscal Year ** Principal Interest Total 2013 $ 131,875 S 65,552 $ 197,427 2013 6,835 $ 3,062 $ 9,897 2014 124,704 88,738 213,442 2014-2017 31,135 21,438 52,573 2015 129,795 60,487 190,283 2018-2021 37,415 15,251 52,666 2016 247,499 56,838 304,337 2022-2025 30,175 7,805 37,980 2017 177,617 45,124 222,741 2026-2029 19,855 3,305 23,160 2018 472,581 32,625 505,206 2030 5,540 249 5,789 Adjustment ** 111,334 (111,334)-

$ 1,395,405 $ 238,031 $ 1,633,435 $ 130,955 $ 51,109 $ 182,064 Principal and Interest due July 1, 2013. Principal and Interest due July 1,2013.

• Adjustment for Compound Interest Bonds accretion; Compound Interest Bonds are reflected Fiscal year for this report indicates when the obligations are expected to be paid.

at their face amount less discount on the balance sheet.

Fiscal year for this report indicates when the obligations are expected to be paid.

U!

Note 6 - Net Billing Public Employees' Retirement System (PERS) Plans 1, 2, and 3 The Legislature established PERS in 1947. Membership in the system Security - Nuclear Projects Nos. 1 and 3 and Columbia includes: elected officials; state employees; employees of the Supreme, The participants have purchased all of the capability of Nuclear Projects Appeals, and Superior courts; employees of legislative committees; community Nos. 1 and 3 and Columbia. BPA has in turn acquired the entire capability and technical colleges, college and university employees not participating in from the participants under contracts referred to as net-billing agreements. higher education retirement programs; employees of district and municipal Under the net-billing agreements for each of the business units, participants courts; and employees of local governments. Approximately 50 percent of are obligated to pay Energy Northwest a pro-rata share of the total annual PERS salaries are accounted for by state employment. PERS retirement costs of the respective projects, including debt service on bonds relating to benefit provisions are established in chapters 41.34 and 41.40 RCW and may each business unit. BPA is then obligated to reduce amounts from participants be amended only by the State Legislature.

under BPA power sales agreements by the same amount. The net-billing PERS is a cost-sharing multiple-employer retirement system comprised of agreements provide that participants and BPA are obligated to make such three separate plans for membership purposes: Plans 1 and 2 are defined payments whether or not the projects are completed, operable or operating benefit plans and Plan 3 is a defined benefit plan with a defined contribution and notwithstanding the suspension, interruption, interference, reduction or component.

curtailment of the projects' output. PERS members who joined the system by September 30, 1977 are Plan On May 13,1994, Energy Northwest's Board of Directors adopted resolutions 1 members. Those who joined on or after October 1, 1977 and by either, terminating Nuclear Projects Nos. 1 and 3. The Nuclear Projects Nos. 1 and 3 February 28, 2002 for state and higher education employees, or August project agreements and the net-billing agreements, except for certain sections 31, 2002 for local government employees, are Plan 2 members unless they which relate only to billing processes and accrued liabilities and obligations exercised an option to transfer their membership to Plan 3. PERS members under the net-billing agreements, ended upon termination of the projects. joining the system on or after March 1, 2002 for state and higher education Energy Northwest previously entered into an agreement with BPA to provide employees, or September 1, 2002 for local government employees have the for continuation of the present budget approval, billing and payment processes. irrevocable option of choosing membership in either PERS Plan 2 or Plan 3.

With respect to Nuclear Project No. 3, the ownership agreement among Energy The option must be exercised within 90 days of employment. Employees who Northwest and private companies was terminated inFY 1999. (See Note 13) fail to choose within 90 days default to Plan 3. Notwithstanding, PERS Plan 2 and Plan 3 members may opt out of plan membership if terminally ill, with Security - Packwood Lake Hydroelectric Project less than five years to live.

Power produced by Packwood is provided to the 12 member utilities. The PERS is comprised of and reported as three separate plans for accounting member utilities pay the annual costs, including any debt service, of Packwood purposes: Plan 1, Plan 2/3, and Plan 3. Plan 1 accounts for the defined and are obligated to pay these annual costs whether or not Packwood is benefits of Plan 1 members. Plan 2/3 accounts for the defined benefits of Plan operational. The Packwood participants also share project revenue to the 2 members and the defined benefit portion of benefits for Plan 3 members.

extent that the amounts exceed project costs. Plan 3 accounts for the defined contribution portion of benefits for Plan 3 members. Although members can only be a member of either Plan 2 or Plan Note 7 - Pension Plans 3, the defined benefit portions of Plan 2 and Plan 3 are accounted for in the same pension trust fund. All assets of this Plan 2/3 defined benefit plan may Substantially all Energy Northwest full-time and qualifying part-time legally be used to pay the defined benefits of any of the Plan 2 or Plan 3 employees participate in one of the following statewide retirement systems members or beneficiaries, as defined by the terms of the plan. Therefore, Plan administered by the Washington State Department of Retirement Systems, 2/3 is considered to be a single plan for accounting purposes.

under cost-sharing multiple-employer public employee defined benefit PERS Plan 1 and Plan 2 retirement benefits are financed from a combination retirement plans. The Department of Retirement Systems (DRS), a department of investment earnings and employer and employee contributions. Employee within the primary government of the State of Washington, issues a publicly contributions to the PERS Plan 1 and Plan 2 defined benefit plans accrue available comprehensive annual financial report (CAFR) that includes financial interest at a rate specified by the Director of DRS. During DRS' fiscal year statements and required supplementary information for each plan. The DRS 2012, the rate was five and one-half percent compounded quarterly. Members CAFR may be obtained by writing to: Department of Retirement Systems, in PERS Plan 1 and Plan 2 can elect to withdraw total employee contributions Communications Unit, RO. Box 48380, Olympia, Wash., 98504-8380; or it and interest thereon upon separation from PERS-covered employment.

may be downloaded from the DRS website at www.drs.wa.gov. The following PERS Plan 1 members are vested after the completion of five years of disclosures are made pursuant to GASB Statements No. 27, "Accounting for eligible service.

Pensions by State and Local Government Employers" and No. 50, "Pension PERS Plan 1 members are eligible for retirement after 30 years of service, Disclosures," an Amendment of GASB Statements No. 25 and No. 27. or at the age of 60 with five years of service, or at the age of 55 with 25 years Any information obtained from the DRS is the responsibility of the state of service. The monthly benefit is 2 percent of the average final compensation of Washington. PricewaterhouseCoopers LLP (PwC), independent auditors (AFC) per year of service, but the benefit may not exceed 60 percent of the for Energy Northwest, has not audited or examined any of the information AFC. The AFC is the monthly average of the 24 consecutive highest-paid available from the DRS; accordingly, PwC does not express an opinion or any service credit months.

other form of assurance with respect thereto.

E A Commitment to Exceltence

The monthly benefit is subject to a minimum for retirees who have 25 of the State Actuary to fully fund Plan 2 and the defined benefit portion years of service and have been retired 20 years, or who have 20 years of of Plan 3. Under PERS Plan 3, employer contributions finance the defined service and have been retired 25 years. If a survivor option is chosen, the benefit portion of the plan and member contributions finance the defined benefit is reduced. Plan 1 members retiring from inactive status prior to the contribution portion. The Plan 3 employee contribution rates range from 5 to age of 65 may also receive actuarially reduced benefits. Plan 1 members may 15 percent, based on member choice. Two of the options are graduated rates elect to receive an optional Cost of Living Adjustment (COLA) that provides dependent on the employee's age.

an automatic annual adjustment based on the Consumer Price Index. The As a result of the implementation of the Judicial Benefit Multiplier adjustment is capped at 3 percent annually. To offset the cost of this annual Program in January 2007, a second tier of employer and employee rates was adjustment, the benefit is reduced. developed to fund, along with investment earnings, the increased retirement PERS Plan 2 members are vested after the completion of five years of benefits of those justices and judges that participate in the program.

eligible service. Plan 2 members are eligible for normal retirement at the The methods used to determine the contribution requirements are age of 65 with five years of service. The monthly benefit is 2 percent of the established under state statute in accordance with chapters 41.40 and 41.45 AFC per year of service. The AFC is the monthly average of the 60 consecutive RCW.

highest-paid service months. There is no cap on years of service credit; and The required contribution rates expressed as a percentage of current-year a cost-of-living allowance is granted (based on the Consumer Price Index), covered payroll, as of December 31, 2012, are as follows:

capped at 3 percent annually.

PERS Plan 2 members who have at least 20 years of service credit and i PERS Plan 1 PERS Plan 2 PERS Plan 3 are 55 years of age or older are eligible for early retirement with a reduced Employer* 7.25%/** 7.25%/** i 7.25%***

benefit. The benefit is reduced by an early retirement factor (ERF) that varies Employee 6.000/o* 4.***

according to age, for each year before age 65.

PERS Plan 3 has a dual benefit structure. Employer contributions finance The employer rates include the employer administrative expense fee currently set at 0.16 percent.

a defined benefit component and member contributions finance a defined The employer rate for state elected officials is 10.74 percent for Plan I and 7.21 percent for Plan 2 contribution component. As established by chapter 41.34 RCW, employee and Plan 3.

contribution rates to the defined contribution component range from

• Plan 3 defined benefit portion only.

5 to 15 percent of salaries, based on member choice. There are currently The employee rate for state elected officials is 7.50 percent for Plan 1and 4.64 percent for Plan 2.

no requirements for employer contributions to the defined contribution Variable from 5.0 percent minimum to 15.0 percent maximum based on rate selected by component of PERS Plan 3.

the PERS3 member.

PERS Plan 3 defined contribution retirement benefits are dependent upon the results of investment activities. Members may elect to self-direct Both Energy Northwest and the employees made the required the investment of their contributions. Any expenses incurred in conjunction contributions. Energy Northwest's required contributions for the years ending with self-directed investments are paid by members. Absent a member's self- June 30 were as follows:

direction, PERS Plan 3 investments are made in the same portfolio as that of the PERS 2/3 defined benefit plan. PERS Plan 1 PERS Plan 2 PERS Plan 3 There are 1,184 participating employers in PERS. Membership in PERS 2013 $ 106,5145 10,630,935 $ 5,075,823 consisted of the following as of the latest actuarial valuation date for the $

2012 124,071 $ 9,773,209 $ 4,710,819 plans of June 30, 2011:

2011 $ 184,863 $ 7,921,762 $ 4,281,077 Retirees and Beneficiaries Receiving Benefits 79,363 Terminated Plan Members Entitled to But Not Yet Receiving Benefits 29,925 Active Plan Members Vested 105,578 Active Plan Members Non-vested 46,839 Total 261,705 Funding Policy Each biennium, the state Pension Funding Council adopts PERS Plan 1 employer contribution rates, PERS Plan 2 employer and employee contribution rates, and PERS Plan 3 employer contribution rates. Employee contribution rates for Plan 1 are established by statute at 6 percent for state agencies and local government unit employees, and at 7.5 percent for state government elected officials. The employer and employee contribution rates for Plan 2 and the employer contribution rate for Plan 3 are developed by the Office i(, y Not tlh\Ve2t "'013 An[Wa~l ep1.oit

Note 8 - Deferred Compensation PLans Nuclear Insurance Nuclear insurance includes liability coverage, property damage, Energy Northwest provides a 401(k) deferred compensation plan (401(k) decontamination and premature decommissioning coverage and accidental plan), and a 457 deferred compensation plan. Both plans are defined outage and/or extra expense coverage. The liability coverage is governed by contribution plans that were established to provide a means for investing the Price-Anderson Act (Act), while the property damage, decontamination savings by employees for retirement purposes. All permanent, full-time and premature decommissioning coverage are defined by the Code of employees are eligible to enroll in the plans. Participants are immediately Federal Regulations. Energy Northwest continues to maintain all regulatory vested intheir contributions and direct the investment of their contribution. required limits as defined by the NRC, Code of Federal Regulations and the Each participant may elect to contribute pre-tax annual compensation, Act. The NRC requires Energy Northwest to certify nuclear insurance limits subject to current Internal Revenue Service limitations. on an annual basis. Energy Northwest intends to maintain insurance against For the 401(k) plan, Energy Northwest may elect to make an employer nuclear risks to the extent such insurance is available on reasonable terms matching contribution for each of its employees who is a participant during and in an amount and form consistent with customary practice. Energy the plan year. The amount of such an employer match shall be 50 percent of Northwest is self-insured to the extent that losses (i) are within the policy the maximum salary deferral percentage. During FY 2013 Energy Northwest deductibles, (ii) are not covered per policy exclusions, terms and limitations, contributed $3.1 million in employer matching funds while employees (iii) exceed the amount of insurance maintained, or (iv)are not covered due contributed $10.8 million for FY 2013. to lack of insurance availability. Such losses could have an effect on Energy Northwest's results of operations and cash flows. All dollar figures noted Note 9 - Other EmpLoyment Benefits - Post-Employment below are as of June 30, 2013.

American Nuclear Insurance (ANI) Coverage: The Act provides Inaddition to the pension benefits available through PERS, Energy Northwest financial protection for the public in the event of a significant nuclear offers post-employment life insurance benefits to retirees who are eligible to generation plant incident. The Act sets the statutory limit of public liability receive pensions under PERS Plan 1, Plan 2, and Plan 3. There are 62 retirees for a single nuclear incident at $12.6 billion. Energy Northwest addresses this who remain participants inthe insurance program. In1994, Energy Northwest's requirement through a combination of private insurance and an industry-wide Executive Board approved provisions which continued the life insurance retrospective payment program called Secondary Financial Protection (SFP).

benefit to retirees at 25 percent of the premium for employees who retire prior Energy Northwest has $375 million of liability insurance as the first layer of to January 1, 1995, and charged the full 100 percent premium to employees protection. Ifany US nuclear generation plant has a significant event which who retired after December 31, 1994. The life insurance benefit is equal to the exceeds the plant's first layer of protection, every operating licensed reactor employee's annual rate of salary at retirement for non-bargaining employees in the US is subject to an assessment up to $117.5 million not including state retiring prior to January 1, 1995. The life insurance benefit has a maximum insurance premium tax. Assessments are limited to $17.5 million per reactor, limit of $10,000 for retirees after December 31, 1994. The cost of coverage per year, per incident, excluding tax. The SFP is adjusted at least every 5 years for retirees remained unchanged for FY 2013 and was $2.82 per $1,000 of to account for inflation and any changes in the number of operating plants.

coverage. Employees who retired prior to January 1, 1995, contribute 58 cents The SFP and liability coverage are not subject to any deductibles.

per $1,000 of coverage while Energy Northwest pays the remainder; retirees NEIL Coverage: The Code of Federal Regulations requires nuclear after December 31, 1994, pay 100 percent of the cost coverage. Premiums are generation plant license-holders to maintain at least $1.06 billion nuclear paid to the insurer on a current period basis. At the time each employee retired, decontamination and property damage insurance and requires the proceeds Energy Northwest accrued an estimated liability for the actuarial value of the thereof to be used to place a plant in a safe and stable condition, to future premium. Energy Northwest revises the liability for the actuarial value decontaminate it pursuant to a plan submitted to and approved by the NRC of estimated future premiums, net of retiree contributions. The total liability before the proceeds can be used for plant repair or restoration or to provide recorded at June 30, 2013, was $0.6 million for these benefits. for premature decommissioning. Energy Northwest has aggregate coverage During FY 2013, pension costs for Energy Northwest employees and post- in the amount of $2.25 billion which is subject to a $5 million deductible per employment life insurance benefit costs for retirees were calculated and accident.

allocated to each business unit based on direct labor dollars. This allocation basis resulted inthe following percentages by business unit for FY 2013 for Note 11 - Asset Retirement ObLigation (ARO) this and other allocated costs; Columbia at 94 percent; Business Development at 4 percent; and Project 1, Nine Canyon, Packwood and Project 3 receiving the Energy Northwest adopted ASC 410 on July 1,2002. This standard requires residual amount of 2 percent. an entity to recognize the fair value of a liability of an ARO for legal obligations related to the dismantlement and restoration costs associated with the Note 10 - NucLear Licensing and Insurance retirement of tangible long-lived assets, such as nuclear decommissioning and site restoration liabilities, in the period in which it is incurred. Upon Nuclear Licensing initial recognition of the AROs that are measurable, the probability weighted Energy Northwest is a licensee of the Nuclear Regulatory Commission and is future cash flows for the associated retirement costs are discounted using a subject to routine licensing and user fees. Additionally, Energy Northwest may credit-adjusted-risk-free rate, and are recognized as both a liability and as an be subject to license modification, suspension, revocation, or civil penalties in increase in the capitalized carrying amount of the related long-lived assets.

the event regulatory or license requirements are violated. Capitalized asset retirement costs are depreciated over the life of the related E A Commrindent to Exceetence

asset with accretion of the ARO liability classified as an operating expense Asset Retirement Obligation (Dollars inmillions) on the statement of operations and net assets each period. Upon settlement of the liability, an entity either settles the obligation for its recorded amount Columbia Generating Station Balance At June 30, 2012 $ 118.70 or incurs a gain or loss if the actual costs differ from the recorded amount.

However, with regard to the net-billed projects, BPA is obligated to provide Current year accretion expense 6.21 for the entire cost of decommissioning and site restoration; therefore, any ARO at June 30, 2013 $ 124.91 gain or loss recognized upon settlement of the ARO results in an adjustment to either the billings in excess of costs (liability) or costs in excess of billings ISFSI (asset), as appropriate, as no net revenue or loss is recognized, and no net Balance At June 30, 2012 $ 1.57 assets are accumulated for the net-billed projects. Current year accretion expense 0.08 Energy Northwest has identified legal obligations to retire generating Revision in future estimates 0.51 plant assets at the following business units: Columbia, Nuclear Project No. ARO at June 30, 2013 $ 2.16 1 and Nine Canyon. Decommissioning and site restoration requirements for Columbia and Nuclear Project No. 1 are governed by the NRC regulations Nuclear Project No. 1 and site certification agreements between Energy Northwest and the state of Balance At June 30, 2012 $ 16.40 Washington and regulations adopted by the Washington Energy Facility Site Current year accretion expense 0.50 Evaluation Council (EFSEC) and a lease agreement with the DOE (See Notes Revision in future restoration estimates 1.34 1 and 13). ARO at June 30, 2013 $ 18.24 As of June 30, 2013, Columbia has a capital decommissioning net asset value of zero and an accumulated liability of $124.9 million for the Nine Canyon Wind Project generating plant, and for the ISFSI a net asset value of $1.1 million and an Balance At June 30, 2012 $ 1.24 accumulated liability of $2.2 million. The adjustment to ISFSI was associated Current year accretion expense 0.05 with new Nuclear Regulatory Commission (NRC) spent fuel decommissioning ARO at June 30, 2013 $ 1.29 requirements.

Nuclear Project No. 1 in FY 2013 current year accretion of $.5 million and upward revision in future restoration estimates of $1.3 million resulted in Note 12 - Decommissioning and Site Restoration the increase to the ARO liability of $1.8 million. Nuclear Project No. 1 has a capital decommissioning net asset value of zero and an accumulated liability The NRC has issued rules to provide guidance to licensees of operating of $18.2 million. nuclear plants on providing financial assurance for decommissioning plants Under the current agreement, Nine Canyon has the obligation to remove at the end of each plant's operating life (see Note 11 for Columbia ARO). In the generation facilities upon expiration of the lease agreement if requested September 1998, the NRC approved and published its "Final Rule on Financial by the lessors. The Nine Canyon Wind Project recorded the related original Assurance Requirements for Decommissioning Power Reactors." As provided ARO in FY 2003 for Phase I and I. Phase IIIbegan commercial operation in in this rule, each power reactor licensee is required to report to the NRC the FY 2008 and the original ARO was adjusted to reflect the change in scenario status of its decommissioning funding for each reactor or share of a reactor for the retirement obligation, with current lease agreements reflecting it owns. This reporting requirement began March 31, 1999, and reports are a 2030 expiration date. As of June 30, 2013, Nine Canyon has a capital required every two years thereafter. Energy Northwest submitted its most decommissioning net asset value of $0.6 million and an accumulated liability recent report to the NRC in March 2013.

of $1.3 million. Energy Northwest's current estimate of Columbia's decommissioning Packwood's obligation has not been calculated because the time frame costs in FY 2013 dollars is $459.0 million (Columbia - $454.6 million and and extent of the obligation was considered under this statement as ISFSI - $4.4 million). This estimate, which is updated biannually, is based on indeterminate. As a result, no reasonable estimate of the ARO obligation can the NRC minimum amount required to demonstrate reasonable financial be made. An ARO will be required to be recorded if circumstances change. assurance for a boiling water reactor with the power level of Columbia.

Management believes that these assets will be used in utility operations for Site restoration requirements for Columbia are governed by the site the foreseeable future. certification agreements between Energy Northwest and the state of The following table describes the changes to Energy Northwest's ARO Washington and by regulations adopted by the EFSEC. Energy Northwest liabilities for the year ended June 30, 2013. The balance is included in the submitted a site restoration plan for Columbia that was approved by the accounts payable and accrued expense balances for each unit. ISFSI is EFSEC on June 12, 1995. Energy Northwest's current estimate of Columbia's included in Columbia's balance: site restoration costs is $109.0 million inconstant dollars (based on the 2013 study) and is updated biannually along with the decommissioning estimate.

Both decommissioning and site restoration estimates (based on 2013 study) are used as the basis for establishing a funding plan that includes escalation and interest earnings until decommissioning activities occur. Payments to the decommissioning and site restoration funds have been made since January 1985. The fair value of cash and investment securities inthe decommissioning

' ;t!hW.-e 13A it Ai2)1 IPI I r

and site restoration funds as of June 30, 2013, totaled approximately $188.6 or other techniques such that the sites pose minimal hazard to the public.

million and $31.3 million, respectively. Since September 1996, these amounts EFSEC approved Energy Northwest's site restoration plan on June 12, 1995.

have been held in an irrevocable trust that recognizes asset retirement In its approval, EFSEC recognized that there is uncertainty associated with obligations according to the fair value of the dismantlement and restoration Energy Northwest's proposed plan. Accordingly, EFSEC's conditional approval costs of certain Energy Northwest assets. The trustee is a domestic U.S. bank provides for additional reviews once the details of the plan are finalized. A that certifies the funds for use when needed to retire the asset. The trust new plan with additional details was submitted in FY 2003. This submittal is funded by BPA ratepayers and managed by BPA in accordance with NRC was used to calculate the ARO discussed in Note 11.

requirements and site certification agreements; the balances in these external trust funds are not reflected on Energy Northwest's balance sheet. Business Development Fund Interest in Energy Northwest established a decommissioning and site restoration plan Northwest Open Access Network for the ISFSI in 1997. Beginning in FY 2003, an annual contribution is made The Business Development Fund is a member of the Northwest Open to the Energy Northwest Decommissioning Fund. These contributions are held Access Network (NoaNet). Members formed NoaNet pursuant to an Interlocal by Energy Northwest and not held in trust by BPA. The fair market value of Cooperation Agreement for the development and efficient use by the cash and investments as of June 30, 2013, is $1.1 million. These contributions members and others of a communication network in conjunction with BPA.

will occur through FY 2044; cash payments will begin for decommissioning The Business Development Fund has a 7.38 percent interest in NoaNet and site restoration in FY 2045 with equal installments for five years totaling with a potential mandate of an additional 25 percent step-up possible for a

$10.6 million in constant dollars based on the study. maximum 9.23 percent. NoaNet has $12.4 million in network revenue bonds and note payables outstanding, based on their December 30, 2012 audited Note 13 - Commitments And Contingencies financial statements. The members are obligated to pay the principal and interest on the bonds when due in the event and to the extent that NoaNet's Nuclear Project No. 1 Termination Gross Revenue (after payment of costs of Maintenance and Operation) is Since the Nuclear Project No.1 termination, Energy Northwest has been insufficient for this purpose. The maximum principal share (based on step-up planning for the demolition of Nuclear Project No. 1 and restoration of the potential) that the Business Development Fund could be required to pay is site, recognizing the fact that there is no market for the sale of the project $1.1 million. The Business Development Fund is not obligated to reimburse in its entirety, and no viable alternative use has been found to-date. The final losses of NoaNet unless an assessment is made to NoaNet's members based level of demolition and restoration will be in accordance with agreements on a two-thirds vote of the membership. In FY 2013 the Business Development discussed below under "Nuclear Project No. 1 Site Restoration. Fund was not required to contribute to NoaNet. Financial statements for NoaNet may be obtained by writing to: Northwest Open Access Network, Nuclear Project No. 3 Termination NoaNet Headquarters, 5802 Overlook Ave. NE, Tacoma, Wash., 98422. Any In June 1994, the Nuclear Project No. 3 Owners Committee voted information obtained from NoaNet is the responsibility of NoaNet. PwC has unanimously to terminate the project. In 1995, a group from Grays Harbor not audited or examined any information available from NoaNet; accordingly, County, Wash., formed the Satsop Redevelopment Project (SRP). The SRP PwC does not express an opinion or any other form of assurance with respect introduced legislation with the state of Washington under Senate Bill thereto.

No. 6427, which passed and was signed by the governor of the state of Washington on March 7, 1996. The legislation enables local governments Other Litigation and Commitments and Energy Northwest to negotiate an arrangement allowing such local Energy Northwest vs. United States of America filed in U.S. Court of governments to assume an interest in the site on which Nuclear Project Federal Claims in July 2011 (Cause No. 11-447C-EJD). This is the second No. 3 exists for economic development by transferring ownership of all or a action for partial breach of contract brought by Energy Northwest against the portion of the site to local government entities. This legislation also provides United States (Department of Energy, "DOE") for damages ranging between for the local government entities to assume regulatory responsibilities for September 1, 2006 through July 2012, for DOE's continuing failure to meet site restoration requirements and control of water rights. In February 1999, its legal obligations to accept and dispose of spent nuclear fuel and high-Energy Northwest entered into a transfer agreement with the SRP to transfer level radioactive waste per the Standard Contract. After extensive discovery, the real and personal property at the site of Nuclear Project No. 3. The SRP Energy Northwest is claiming total damages of approximately $24.9 million also agreed to assume regulatory responsibility for site restoration. Therefore, in this case. Energy Northwest believes DOE does not have a defense on Energy Northwest is no longer responsible to the state of Washington and liability, which was established in the prior case.

EFSEC for any site restoration costs. Energy Northwest is involved in other various claims, legal actions and contractual commitments and in certain claims and contracts arising in the Nuclear Project No. 1 Site Restoration normal course of business. Although some suits, claims and commitments are Site restoration requirements for Nuclear Project No. 1 are governed by significant in amount, final disposition is not determinable. In the opinion of site certification agreements between Energy Northwest and the state of management, the outcome of such litigation, claims or commitments will not Washington and regulations adopted by EFSEC, and a lease agreement with have a material adverse effect on the financial positions of the business units DOE. Energy Northwest submitted a site restoration plan for Nuclear Project or Energy Northwest as a whole. The future annual cost of the business units, No. 1 to EFSEC on March 8, 1995, which complied with EFSEC requirements however, may either be increased or decreased as a result of the outcome of to remove the assets and restore the sites by demolition, burial, entombment, these matters.

M A Commitment to Excellence

Note 14 - Derivative Instruments (wt%) that will yield approximately 482 MTU of enriched uranium product (EUP) with an average assay of 4.4 wt%.

GASB Statement No. 53, "Accounting and Reporting for DOE and Energy Northwest have entered into an Derivative Instruments" was adopted in FY 2010. Energy agreement for the transfer of the DUF6 to Energy Northwest.

Northwest's policy is to review and apply as appropriate The agreement addresses delivery and transfer of title the normal purchase and normal sales exception under of the DUF6, return of residual DUF6 after enrichment, GASB No. 53. Energy Northwest has reviewed various storage of the EUP, and payment of DOE's costs. The costs contractual arrangements to determine applicability for the handling of the DUF6 and storage of the EUP are of this statement. Purchases and sales of nuclear fuel anticipated to be $5 million or less. As of June 30, 2013, and components that require physical delivery and are Energy Northwest had recorded $0.4 million in charges to expected to be used and/or sold in the normal course of the DOE for delivery of the DUF6, which is capitalized as business are generally considered normal purchases and cost of the fuel being purchased.

normal sales. These transactions are excluded Under GASB Under the Depleted Uranium Enrichment Program 53 and therefore are not required to be recorded at fair (ý(DUEP), Energy Northwest purchased from USEC all of value in the financial statements. Certain contracts for theSeparative Work Units (SWU) contained in the EUP.

power options were evaluated and the followiv*ig-cbntract Upon finalization of the program, Energy Northwest had did not meet the exclusion for normal purchase and normal purchased a total of 481.6 MTU of EUP from USEC at a cost sale: of $687.5 million, which is recorded in nuclear fuel, net of The Business Development Fund had a power sales accumulated amortization, as of June 30, 2013.

contract subject to the provisions'oGASB 53. Call options Energy Northwest and IVA have entered into an associated with the contract had a- noi:onal amount of 50 agreement for the sale and purchase of a portion of the MWh. The fair value of the powersles option contract SWU and Feed Component of the EUR The sales under is based on the futures price curve for the Mid-Columbia the agreement are expected to total approximately $731 Intercontinental Exchange for electricity and the Sumas million. The sales under this agreement are scheduled to index for natural gas. This contract settled in June 2013. take place between 2015 and 2022.

Changes in the fair value of the call options are classified as Energy Northwest has a contract with DOE that requires non-operating revenue and expenses - investment income DOE to accept title and dispose of spent nuclear fuel.

on the Statements of Revenues, Expenses and Changes Although the courts have ruled that DOE had the obligation in Net Assets. The total dollars recorded in FY 2013 were to accept title to spent nuclear fuel by January 31, 1998,

$148,000. currently, there is no known date established when DOE will fulfill this legal obligation and begin accepting spent Note 15 - Nuclear Fuels nuclear fuel.

When the fuel is placed in the reactor the fuel cost is In May 2012, Energy Northwest entered into agreements amortized to operating expense on the basis of quantity with three other parties for processing high assay uranium of heat produced for generation of electric energy. The tails. The Program consists of several agreements between amount moved to spent fuel for cooling increased $55.3 the parties involved, entered into as a joint effort between million. Fees for disposal of fuel in the reactor are the Department of Energy (DOE), Tennessee Valley expensed as part of the fuel cost.

Authority (TVA), United States Enrichment Corporation The current period operating expense for Columbia (USEC) and Energy Northwest to enrich approximately includes an $8.1 million charge from DOE for future spent 9,082 metric tons (MTU) of Depleted Uranium Hexafluoride fuel storage and disposal in accordance with the Nuclear (DUF6) with an average assay of 0.44 weight percent U235 Waste Policy Act of 1982 and $40.3 million for amortization of fuel used in the reactor.

Energy Northwest has completed the Independent Spent Fuel Storage Installation (ISFSI) project, which is a temporary dry cask storage facility to be used until DOE completes its plan for a national repository. ISFSI will store the spent fuel in commercially available dry storage casks on a concrete pad at the Columbia site. No casks were issued from the cask inventory account in FY 2013. Spent fuel is transferred from the spent fuel pool to the ISFSI periodically to allow for future refueling. Current period costs were $2.1 million for dry cask storage costs which are recorded in nuclear fuel expense.

Designer: Ben Stewart Editor: AngeLa WaLz Energy Northwest 2013 Annual Report

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