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 ,J)'ll qv nniliA Rer(-4 t M 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 in order 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'AU Energy Northwest Management's Discussion and Analysis Energy Northwest is a municipal corporation and joint operating agency of the state of Washington.

Each Energy Northwest business unit is financed and accounted for separately from all other current or future business assets. The following discussion and analysis is organized by business unit.The management discussion and analysis of the financial performance and activity is provided as an introduction and to aid in comparing the basic financial statements for the fiscal year (FY) ended June 30, 2013, with the basic financial statements for the fiscal year ended June 30, 2012.Energy Northwest has adopted accounting policies and principles that are in accordance with Generally Accepted Accounting Principles (GAAP) in the United States of America. Energy Northwest's records are maintained as prescribed by the Governmental Accounting Standards Board (GASB) and, when not in conflict with GASB pronouncements, accounting standards prescribed by the Financial Accounting Standards Board (FASB). (See Note 1 to the Financial Statements.)

Because each business unit is financed and accounted for separately, the following section on financial performance is discussed by business unit to aid in analysis of assessing the financial position of each individual business unit.For comparative purposes only, the table on the following page represents a memorandum total only for Energy Northwest, as a whole, for FY 2013 and FY 2012 in accordance with GASB No. 34, "Basic Financial Statements-and Management's Discussion and Analysis-for State and Local Governments." The financial statements for Energy Northwest include the Balance Sheets; Statements of Revenues, Expenses, and Changes in Net Assets;and Statements of Cash Flows for each of the business units, and Notes to Financial Statements.

The Balance Sheets present the financial position of each business unit on an accrual basis. The Balance Sheets report financial information about construction work in progress, the amount of resources and obligations, restricted accounts and due to/from balances for each business unit. (See Note 1 to the Financial Statements.)

The Statements of Revenues, Expenses, and Changes in Net Assets provide financial information relating to all expenses, revenues and equity that reflect the results of each business unit and its related activities over the course of the fiscal year. The financial information provided aids in benchmarking activities, conducting comparisons to evaluate progress, and determining whether the business unit has successfully recovered its costs.The Statements of Cash Flows reflect cash receipts and disbursements and net changes resulting from operating, financing and investing activities.

The Statements of Cash Flows provide insight into what generates cash, where the cash comes from, and purpose of cash activity.The Notes to Financial Statements present disclosures that contribute to the understanding of the material presented in the financial statements.

This includes, but is not limited to, Schedule of Outstanding Long-Term Debt and Debt Service Requirements (See Note 5 to the Financial Statements), accounting policies, significant balances and activities, material risks, commitments and obligations, and subsequent events, if applicable.

The basic financial statements of each business unit along with the notes to the financial statements and management discussion and analysis should be used to provide an overview of Energy Northwest's financial performance.

Questions concerning any of the information provided in this report should be 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 1 i No, 1,11we- , :1 A i ts I i, Re t Columbia Generating Station Columbia Generating Station (Columbia) is wholly owned by Energy Northwest and its participants and operated by Energy Northwest.

The plant is a 1,170-megawatt electric (MWe, Design Electric Rating, net) boiling water nuclear power plant located on the Department of Energy's (DOE) Hanford Site north of Richland, Washington.

Columbia produced 8,479 gigawatt-hours (GWh) of electricity in FY 2013, as compared to 6,984 GWh of electricity in FY 2012, which included economic dispatch of 51 and 140 GWh respectively.

Columbia entered its planned refueling outage (R-21) on May 11, 2013. The 40 day planned outage extended an additional 5 days and ended June 25, 2013.The FY 2013 generation increase of 21.4% was due to the extended outage (R-20) incurred in FY 2011 extending into a portion of FY 2012, which ended September 27, 2012 which reduced the amount of power generated in FY 2012. Additionally, FY 2013 generation was approximately 6 GWh higher than budgeted, reflecting the continuous and successful generation run.Columbia's cost performance is measured by the cost of power indicator.

The cost of power for FY 2013 was 4.51 cents per kilowatt-hour (kWh) as compared with 4.73 cents per kWh in FY 2012. The industry cost of power fluctuates year to year depending on various factors such as refueling outages and other planned activities.

The FY 2013 cost of power decrease of 4.7 percent was due to the successful cost control and generation run in FY 2013 as compared to the generation and additional costs incurred during FY 2012 due to the extended R-20 outage.Balance Sheet Analysis The net decrease to Utility Plant (plant) and Construction Work In Progress (CWIP) from FY 2012 to FY 2013 (excluding nuclear fuel) was $18.1 million. The changes to plant and CWIP were comprised of additions to plant of $8.0 million with an increase to CWIP of $55.9 million. Remaining changes was the period effect of depreciation of $82.0 million. The accumulated decommissioning and site restoration accrued costs related to the Integrated Spent Fuel Storage Installation (ISFSI) at Columbia were adjusted to reflect the change in the asset retirement obligation (ARO). Change in the ARO was necessary due to new Nuclear Regulatory Commission requirements for fuel storage calculations.

Per ASC 410, "Asset Retirement and Environmental Obligations," the obligation was reevaluated and adjusted to reflect the change in timing due to the relicensing of Columbia through December 31, 2043 and to account for estimated costs related to fuel disposition obligations for the post five year period following the end of licensing and generation.

The revision resulted in an increase to the capitalized portion of the asset of $0.5 million. (See Note 11 to the Financial Statements.)

The FY 2013 additions to CWIP of $55.9 million consisted of 20 major projects of at least $0.7 million: Fukushima impacts, Radio Obsolescence, Cobalt Reduction Program, Stack Monitor Performance, ServiceWater Pump and Motor Overhaul, On-Line Noble Chemical Application, Keep Fill Pump Replacement, Control Rod Device Refurbishment, Main Transformer Replacement, High 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 NET GENERATION

-GWhrs Columbia Generating Station COST OF POWER -Cents/kWh FY201 FY201;FY2011 FY 201C 8,479 FY2013 6,984 FY2012 7,247 FY2011 8,124 FY2010 4.51 4.73 5.69 3.74 4.94 FY 7,725 FY 2009 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 separate projects.Nuclear fuel, net of accumulated amortization, increased

$644.3 million from FY 2012 to $985.8 million for FY 2013. The major factor contributing to the increase in Nuclear Fuel relates to the completion of the Depleted Uranium Enrichment Program (DUEP). This program increased Fuel held for resale from$1.5 million in FY 2012 to $538.9 million in FY 2013. Fuel amounts used for reload increased

$90.0 million with a decrease in net fuel of $37.8 million for current year amortization.

Fuel removed for cooling increased

$55.3 million and remaining change was $0.6 million for fuel loan and purchase activity relating to the cylinder/sampling activity for the DUEP.Current assets increased

$16.4 million in FY 2013 to $166.2 million.Changes were increases to materials and supplies of $10.2 million (nuclear fuel cask inventory is $4.5 million and inventory is $5.7), increases to cash and investments of $7.2 million offset by a decrease in accounts and other receivables of $1.0 million.Special funds decreased

$20.4 million to $16.4 million in FY 2013 due to the FY 2013 bond activity and schedule of construction costs for these funds in FY 2013.The debt service funds increased

$57.6 million in FY 2013 to $147.5 million.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 maturities.

Deferred charges increased

$59.8 million in FY 2013 from $835.0 million to $894.8 million. Components of this increase were changes in Costs in Excess of Billings related to the net effect of payment of current maturities and refunding activity related to available debt of $58.1 million. There was also a slight increase to unamortized debt expense of $1.7 million due to debt related activity.Current liabilities increased

$15.6 million in FY 2013 to $139.6 million.Components of the change were an increase to year end obligations relating from R-21 year end impacts of $4.1 million, increases to current maturities of debt of $60.7 million, decrease of $61.8 million due to payment of notes payable obligation related to the DUEP, an increase of $14.6 million for business unit activity and a decreased requirement for participant amounts under the net billing agreement of $2.0 million.Restricted liabilities increased

$12.5 million in FY 2013 to $198.7 million.The increase was due to bond activity and related increase of $5.7 million and decommissioning increases of $6.8 million.Long-term debt (Bonds Payable) increased

$721.6 million in FY 2013 from$2.4 billion to $3.2 billion due to the debt associated with DUEP of $748.6 million. The current portion of Bonds Payable increased

$60.1 million, which was driven by timing of scheduled maturities.

Other long-term liabilities increased

$2.1 million in FY 2013 to $17.9 million related to nuclear fuel cask activity.Statement of Operations Analysis Columbia is a net-billed project. Energy Northwest recognizes revenues equal to expenses for each period on net-billed projects.

No net revenue or loss 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 increased fuel disposal costs of $8.5 million and increased generation taxes of SO.8 million. Periodic expenses for depreciation and decommissioning increased

$8.4 million with the remainder of the increase ($0.9 million) a result Columbia Generating Station TOTAL OPERATING COSTS (dollars in thousands)

FY2013 Total Expenses FY2012 FY 2011 FY2010 FY2009 of Administrative and General Expenses.539,779 Other Income and Expenses increased

$54.2 million from FY 2012 to $1 20.7 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 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 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$1.7 million. This includes a $1.2 million DUEP leasing adjustment.

Columbia's total operating revenue increased from $397.9 million in FY 519,759 2012 to $539.7 million in FY 2013.The increase in costs (and conversely revenue per net billing) of $141.8 million was due to the increased costs incurred in the 500,000 completion of R-21. R-21 was originally budgeted for $87.0 million and 40 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-21.0 100,000 200,000 300,000 400,000 0 Operating Expenses M Other Income I 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.Packwood Lake Hydroelectric Project COST OF POWER -Cents/kWh FY 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$0.8 million in cash for operating activities.

The corresponding decrease to total liabilities of $0.1 million was the decrease in due 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 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 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 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 of June 30, 2013, Packwood continues to be relicensed under this extended 1.82 agreement.

1.62 FY 201 FY2011 FY2010 FY2009 0.0 0.5 1.0 1.5 2.0 2.5 Packwood Lake Hydroelectric Project NET GENERATION

-GWhrs Packwood Lake Hydroelectric Project TOTAL OPERATING COSTS (dollars in thousands)

Total Expenses FY2013 FY2012 FY 2011 FY 2010 FY2009 103.74 119.43 107.92 86.07 99.34 FY2013 FY2012 FY2011 FY2010 FY 2009 2,166 1,872 1,742 1,535 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 A C~ormmiment to Exce~lence Statement of Operations Analysis The agreement with Packwood participants obligates them to pay annual costs and to receive excess revenues. (See Note 1 to the Financial Statements.)

Accordingly, Energy Northwest recognizes revenues equal to expenses for each period. No net revenue or loss is recognized and no net assets are accumulated.

Operating expenses increased

$0.3 million to $2.2 million in FY 2013 from$1.9 million in FY 2012. Operations and Maintenance was the major reason for the increase due to increased transmission and scheduling costs of $57,000 and$245,000 of hydraulic and electrical expenses.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 in net gain is primarily due to a small gain on property disposed of $2,000 and a small increase in investment income from FY 2012 of $2,000.Packwood participants are obligated to pay annual costs of the project (including any applicable debt service), whether or not the project is operable.

The Packwood participants also share project revenue to the extent that the amounts exceed costs. These funds can be returned to the participants or kept within the project. As of June 30, 2013 there is $5.7 million recorded as deferred revenues in excess of costs that are being kept within the project. Packwood participants are currently taking 100 percent of the project generation; there are no additional agreements for power sales.Nuclear Project No. 1 Energy Northwest wholly owns Nuclear Project No. 1, a 1,250-MWe plant, which was placed in extended construction delay status in 1982, when it was 65 percent complete.

On May 13, 1994, Energy Northwest's Board of Directors adopted a resolution terminating Nuclear Project No. 1. All funding requirements are net-billed obligations of Nuclear Project No. 1. Termination expenses and debt service costs comprise the activity of Nuclear Project No.1 and are net-billed.

Balance Sheet Analysis Long-term debt decreased

$289.7 million from $1.4 billion in FY 2012 to $1.1 billion in FY 2013 as a result of $273.1 million being transferred to current debt to be paid on July 1, 2013 along with a decrease in bond related amortization of $16.6 million. Short term debt increased

$37.0 million per the debt maturity schedule.

There was a decrease to restricted liabilities of$7.0 million, represented by a decrease to interest payable of $8.8 million offset by an increase to the decommissioning estimate of $1.8 million.Statement of Operations Analysis Other Income and Expenses showed a net decrease to expenses of $20.0 million from $75.0 million in FY 2012 to $55.0 million in FY 2013. Investment revenue stayed steady, bond related expenses decreased

$21.5 million, decommissioning costs increased

$1.3 million and there was a slight increase of $0.2 million in plant preservation costs.Nuctear Project No. 3 Nuclear 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's Board of Directors adopted a resolution terminating Nuclear Project No. 3. Energy Northwest is no longer responsible for any site restoration costs as they were transferred with the assets to the Satsop Redevelopment Project. The debt service related activities remain the responsibility of Energy Northwest and are net-billed. (See Note 13 to the Financial Statements.)

Balance Sheet Analysis Long-term debt decreased

$174.4 million from $1.5 billion in FY 2012 to $1.3 billion in FY 2013, as a result of $166.2 million being transferred to current debt to be paid on July 1, 2013 along with a decrease in bond related amortization of $8.2 million. Current debt per the debt maturity schedule increased

$70.6 million from $95.5 million in FY 2012 to $166.2 million in 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 Overall expenses decreased

$9.9 million from FY 2012 related to bond activity with investment income and liquidation costs steady with previous year levels.Enerily Northwest 201 3 Annual Report Business Development Fund Energy Northwest was created to enable Washington public power utilities and municipalities to build and operate generation projects.

The Business Development Fund (BDF) was created by Executive Board Resolution No.1006 in April 1997, for the purpose of holding, administering, disbursing, and accounting for Energy Northwest costs and revenues generated from engaging in new energy business opportunities.

The BDF is managed as an enterprise fund. Four business lines have been created within the fund: General Services and Facilities, Generation,.Professional Services, and Business Unit Support. Each line may have one or more programs that are managed as a unique business activity.Batance Sheet Anatysis Total assets increased

$1.0 million from $9.1 million in FY 2012 to $10.1 million in FY 2013. Increases were due to cash and investments of $1.1 million, net plant of $0.2 million, and decreases to receivables and prepaid amounts of $0.3 million. Liabilities decreased

$0.4 million from FY 2012 due to timing of year end outstanding items.Statement of Operations Anatysis Operating Revenues in FY 2013 totaled $9.0 million as compared to FY 2012 revenues of $9.8 million, a decrease of $0.8 million. The decrease in revenues was driven by four major projects:

Grays Harbor project, which was a 50 MW power call option that ended in June 2013 at the 600 MW Satsop Natural Gas Combined-Cycle plant as part of a compensation package for selling development rights to Duke Energy in 2001 ($0.3 million), termination of the Kalama project in FY 2013, which was a proposed development of a 346 MW Natural Gas Combined-Cycle plant in southwestern Washington state ($0.4 million), decreases in Hanford calibration services ($0.3 million)due to the expiration of a portion of the contracted scope of work, and decreased lease activity ($0.3 million).

The decreases in the four projects mentioned above were offset by increased revenues for technical services and engineering services of $0.6 million. Operating costs decreased

$0.9 million due to decreased business activity resulting in a net operating increase of$0.1 million.Other Income and Expenses decreased

$0.2 million from $1.5 million in net revenues in FY 2012 to net revenue of $1.3 million in FY 2013; there was an adjustment of $0.1 million for completion of the power option derivative contract for the Grays Harbor project, and a decrease of other income and expenses of $0.1 million, with no significant individual items.The Business Development Fund receives contributions from the Internal Service Fund to cover cash needs during startup periods. Initial startup costs are not expected to be paid back and are shown as contributions.

As an operating business unit, requests can be made to fund incurred operating expenses.

In FY 2013 there were no contributions (transfers), which was also the case for FY 2012.M A Commnitme~nt to F xcetlec Nine Canyon Wind Project The Nine Canyon Wind Project (Nine Canyon) is wholly owned and operated by Energy Northwest.

Nine Canyon is located in the Horse Heaven Hills area southwest of Kennewick, Wash. Electricity generated by Nine Canyon is purchased by Pacific Northwest Public Utility Districts (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 and Restated Nine Canyon Wind Project Power Purchase Agreement which now has an end date of 2030. Nine Canyon is connected to the Bonneville Power Administration transmission grid via a substation and transmission lines constructed by Benton County Public Utility District.Phase I of Nine Canyon, which began commercial operation in September 2002, consists of 37 wind turbines, each with a maximum generating capacity of approximately 1.3 MW, for an aggregate generating capacity of 48.1 MW. Phase II of Nine Canyon, which was declared operational in December 2003, includes 12 wind turbines, each with a maximum generating capacity of 1.3 MW, for an aggregate generating capacity of approximately 15.6 MW. Phase III of Nine Canyon, which was declared operational in May 2008, includes 14 wind turbines, each with a maximum generating capacity of 2.3 MW, for an aggregate generating capacity of 32.2 MW. The total Nine Canyon generating capability is 95.9 MW, enough energy for approximately 39,000 average homes.Nine Canyon produced 228.23 GWh of electricity in FY 2013 versus 261.63 GWh in FY 2012. The decrease of 12.8 percent was due to slightly less favorable wind conditions in FY 2013 as compared to FY 2012. The average wind speed for the months of January and June were significantly below the 10 year average. The below average wind conditions combined with FY 2012 being the second highest generation year for history of the project were the drivers for the decrease between years.Nine Canyon's cost performance is measured by the cost of power indicator.

The cost of power for FY 2013 was $7.91 cents per kWh as compared to $6.69 cents per kWh in FY 2012. The cost of power fluctuates year to year depending on various factors such as wind Nine Canyon Wind Project NET GENERATION

-GWh totals and unplanned maintenance.

The FY 2013 cost of power increase of 18.2 percent was a result of the decreased generation due to wind conditions and higher maintenance costs incurred due to turbine bearing maintenance.

Balance Sheet Analysis Total assets decreased

$5.0 million from $119.5 million in FY 2012 to$114.5 million in FY 2013. The major driver for the change in assets was a decrease of $6.8 million in net plant due to accumulated depreciation.

The remaining changes consisted of increases to restricted assets of $2.4 million and decreases in cash and investments of $0.2 million, prepaid amounts of$0.2 million and debt related expenses of $0.2 million. There was an overall decrease to liabilities of $5.2 million with a decrease to long term debt of$7.4 million, increases to current debt maturities of $2.3 million, increases to accrued debt related interest of $0.1 million, and increases to accrued costs and business activities of $0.1 million. The increase in net assets was $0.2 million in FY 2013 as compared to a decrease of $1.3 million in FY 2012. The slight reversal in net assets reflects the rate stabilization approach for Nine Canyon planning out through the 2030 period.In previous years Energy Northwest has accrued, as income (contribution) from the Department of Energy, Renewable Energy Production Incentive (REPI)payments that enable Nine Canyon to receive funds based on generation as it applies to the REPI legislation.

REPI was created to promote increases in the generation and utilization of electricity from renewable energy sources and to further the advances of renewable energy technologies.

This program, authorized under Section 1212 of the Energy Policy Act of 1992, provides financial incentive payments for electricity produced and sold by new qualifying renewable energy generation facilities.

The payment stream from Nine Canyon participants and the REPI receipts were projected to cover the total costs over the purchase agreement.

Continued shortfalls in REPI funding for the Nine Canyon project led to a revised rate plan to incorporate the impact of this shortfall over the life of the project. The billing rates for the Nine Canyon Wind Project COST OF POWER -Cents/kWh FY2013 FY2012 FY 2011 FY 2010 FY 2009 228.23 FY2013 261.63 FY2012 264.74 FY2011 7.91 6.69 6.56 7.88 7.79 226.73 FY201 226.27 FY20C 0 50 100 150 200 250 300 I El Nine Canyon participants increased 69 percent and 80 percent for Phase I and Phase II participants respectively in FY 2008 in order to cover total project costs, projected out to the 2030 proposed project end date. The increases for FY 2008 were a change from the previous plan where a 3 percent increase each year over the life of the project was projected.

Going forward, the increase or decrease in rates will be based on cash requirements of debt repayment and the cost of operations.

Phase III started with an initial planning rate of $49.82 per MWh which increased at 3 percent per year for three years. In year six (FY 2013) the rate increased to a rate that will be stabilized over the life of the project. Possible adjustments may be necessary to future rates depending on operating costs and REPI funding, similar to Phase I and II.Statement of Operations Analysis Operating revenues increased

$2.8 million from $16.2 million in FY 2012 to $19.0 million in FY 2013. The project received revenue from the billing of the purchasers at an average rate of $80.06 per MWh for FY 2013 as compared to $61.98 per MWh for FY 2012 which is reflective of the implementation of the revised rate plan in FY 2008 to account for REPI funding shortfalls and costs of operations.

The increased operating revenues from the previous year were due to increased funding requirements for Phase Ill purchasers.

The increase in the average rate billed to purchasers was also impacted by the reduced generation in FY 2013 as compared to FY 2012.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 Nine Canyon Wind Project TOTAL OPERATING COSTS (Dollars in thousands)

Total E FY2013 FY 2012 FY2011 FY2010 FY 2009 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 of $0.4 million and decreases in amortized bond expenses of $0.1 million accounted for the change. Net gain or change in net assets of $0.2 million for xpenses FY 2013 was a direct result of the planned average rate increase with lower than budgeted operating costs.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 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 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 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.17,632 0 3,000 6,000 9,000 12,000 15,000 M Operating Expenses U Other Income I Expenses 0 A Commitment to Excetlence InternaL Service Fund The Internal Service Fund (ISF) (formerly the General Fund) was established in May 1957. The ISF provides services to the other funds. This fund accounts for the central procurement of certain common goods and services for the business units on a cost reimbursement basis. (See Note 1 to Financial Statements.)

Batance Sheet Analysis Total assets increased

$9.1 million from $46.6 million in FY 2012 to $55.7 million in FY 2013. The five major items contributing to the change were 1)decreases to net plant of $2.0 million, 2) decrease of $5.7 million to cash to reflect FY 2013 recognition of year-end check redemption related to R-21 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.The net increase in net assets and liabilities is due to increases in accounts payable and payroll related liabilities of $9.4 million due to year-end timing of expenses for FY 2013, which was an outage year and a decrease of $15.0 million due to other business units resulting from the change in year-end activities.

Statement of Operations Analysis Net revenues for FY 2013 increased

$112,000 from FY 2012. The increase was due to decreased amounts of other business expenses of $146,000, decrease in depreciation of $194,000 offset by decreases in operating revenue due to operations of $452,000.Current Debt Ra Energy Northwest (Long-Term)

Fitch, Inc.Moodys Investors Service, Inc. (Moodys)Standard and Poor's Ratings Services (S & P)tings (Unaudited)

Nine Canyon Rating Net-Billed Rating Phase I & II Phase III AA Aal AA-A-A-A2 A-A2 A ntcy Noi thwest 2013 Animalc Repot t Statement Of Net Position As of June 30, 2013 (Dollars in thousands)

Columbia Packwood Lake Generating Hydroelectric Nuclear Nuclear Project Project Business Nine Canyon Development Wind Internal 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 S. .... ..1. .TOTAL ASSETS $ 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 Generating Packwood Lake Hydroelectric Nuclear Project Nuclear Project Business Development Nine Canyon Wind Internal 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)

Business Nine Canyon Columbia Packwood Generating Lake Station Project Nuclear Nuclear Project Project No.1* No.3*Development Fund Wind Project Subtotal Internal 2013 Service Combined Fund Total OPERATING REVENUES OPERATING EXPENSES Services to other business units Nuclear fuel Spent fuel disposal fee Decommissioning Depreciation and amortization Operations and maintenance Administrative

& general Generation tax$ 539,667 $ 2,173 $42,433 8,059 6,306 83,967 57 246,376 1,938 27,775 164-S <$ 9,024 $18,999 ]$ 569,863 $$ 569,863 240 9,167 84 6,814 6,121 34 49 42,433 8,059 6,390 91,078 263,602 27,973 -4,094 -42,433 8,059 6,390 91,078 263,602 27,973 4,094 4,023 22 Iotal operating expenses 418,939 2, 9I, 13,,U/ 44I3 U6 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 Sales of investment securities (592,637)615,262 (1,046): (214,700)

(181,777)975 194,710 69,005 (2,560): (22,339).

(25,490) (1,040,549) 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 AT JUNE 30, 2012 100,817 1,195 92,458 104,363 2,172 9,726 6,070 316,801 CASH AT JUNE 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 Generating Hydroelectric Station Project Nuclear Project No.1 *Nuclear Business Nine Canyon Project Development Wind No.3

• Fund Project Internal 2013 Service Combined Fund Total RECONCILIATION OF NET OPERATING REVENUES TO NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES Net operating revenues $ 120,728 $ () $ .$--------------Adjustments to reconcile net operating revenues to cash provided by operating activities:

-Depreciation and amortization 124,410 48 Decommissioning 6,306 Other (2,041): 770 Change in operating assets and liabilities:

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

(48), Accounts receivable 980 11 1 Materials and supplies (10 201): Prepaid and other assets (98)1 62 Due from/to other business units, funds 14,874 (915)and Participants Accounts payable 9,537 58 Non-operating revenue receipts 112 338,733 Cash payments for preservation, termination expense --- -(534)Cash payments for services$(383) : $ 5,897 :$$ 126,234 157 6,793 33 1,458 37 (51) (9): 131,408 6,339 224 (61,380)931 (10,201)2,738 14,035 9,594 567,077 (556)2,572 202 76 (96): 95 228,232 (22)i (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 statementsA Cot miitment to Exceltence Notes To Financiat Statements Note 1 -Summary of Operations and Significant Accounting Policies Energy Northwest, a municipal corporation and joint operating agency of the state of Washington, was organized in 1957 to finance, acquire, construct and operate facilities for the generation and transmission of electric power.Membership consists of 22 public utility districts and 5 municipalities.

All members own and operate electric systems within the state of Washington.

Energy Northwest is exempt from federal income tax and has no taxing authority.

Energy Northwest maintains seven business units. Each unit is financed and accounted for separately from all other current or future business units.All electrical energy produced by Energy Northwest's net-billed business units is ultimately delivered to electrical distribution facilities owned and operated by Bonneville Power Administration (BPA) as part of the Federal Columbia River Power System. BPA in turn distributes the electricity to electric utility systems throughout the Northwest, including participants in Energy Northwest's business units, for ultimate distribution to consumers.

Participants in Energy Northwest's net-billed business units consist of public utilities and rural electric cooperatives located in the western United States who have entered into net-billing agreements with Energy Northwest and BPA for participation in one or more of Energy Northwest's business units.BPA is obligated by law to establish rates for electric power which will recover the cost of electric energy acquired from Energy Northwest and other sources, as well as BPA's other costs (see Note 6).Energy Northwest operates the Columbia Generating Station (Columbia), a 1,170-MWe (Design Electric Rating, net) generating plant completed in 1984. Energy Northwest has obtained all permits and licenses required to operate Columbia.

Columbia was issued a standard 40-year operating license by the Nuclear Regulatory Commission (NRC) in 1983. On January 19, 2010 Energy Northwest submitted an application to the NRC to renew the license for an additional 20 years, thus continuing operations to 2043.A renewal license was granted by the NRC on May 22, 2012 for continued operation of Columbia to December 31, 2043.Energy Northwest also operates the Packwood Lake Hydroelectric Project (Packwood), a 27.5-MWe generating plant completed in 1964. Packwood has been operating under a 50-year license issued by the Federal Energy Regulatory Commission (FERC), which expired on February 28, 2010. Energy Northwest submitted the Final License Application (FLA) for renewal of the operating license to FERC on February 22, 2008. On March 4, 2010, FERC issued a one-year extension, or until the issuance of a new license for the project or other disposition under the Federal Power Act, whichever comes first. FERC is awaiting issuance of the National Oceanic and Atmospheric Administration's (NOAA) Biological Opinion, after which FERC will complete the final license renewal documentation for Packwood.

Costs incurred to date for relicensing are $3.7 million included in other deferred charges.The electric power produced by Packwood is sold to 12 project participant utilities which pay the costs of Packwood.

The Packwood participants are obligated to pay annual costs of Packwood including debt service, whether or not Packwood is operable.

The participants also share Packwood revenue.(See Note 6).Nuclear Project No. 1, a 1,250-MWe plant, was placed in extended construction delay status in 1982, when it was 65 percent complete.

Nuclear 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's Board of Directors adopted resolutions terminating Nuclear Projects Nos. 1 and 3. All funding requirements remain as net-billed obligations of Nuclear Projects Nos. 1 and 3. Energy Northwest wholly owns Nuclear Project No. 1. Energy Northwest is no longer responsible for site restoration costs for Nuclear Project No. 3 (See Note 13).The Business Development Fund was established in April 1997 to pursue and develop new energy related business opportunities.

There are four main business lines associated with this business unit: General Services and Facilities, Generation, Professional Services, and Business Unit Support.The Nine Canyon Wind Project (Nine Canyon) was established in January 2001 for the purpose of exploring and establishing a wind energy project.Phase I of the project was completed in FY 2003 and Phase II was completed in FY 2004. Phase I and II combined capacity is approximately 63.7 MWe.Phase III was completed in FY 2008 adding an additional 14 wind turbines to Nine Canyon and adding an aggregate capacity of 32.2 MWe. The total number of turbines at Nine Canyon is 63 and the total capacity is 95.9 MWe.The Internal Service Fund was established in May 1957. It is currently used to account for the central procurement of certain common goods and services for the business units on a cost reimbursement basis.Energy Northwest's fiscal year begins on July 1 and ends on June 30. In preparing these financial statements, the company has evaluated events and transactions for potential recognition or disclosure through October 30, 2013, the date the financial statements were issued.The following is a summary of the significant accounting policies: a) Basis of Accounting and Presentation:

The accounting policies of Energy Northwest conform to Generally Accepted Accounting Principles (GAAP) applicable to governmental units. The Governmental Accounting Standards Board (GASB) is the accepted standard-setting body for establishing governmental accounting and financial reporting principles.

Energy Northwest has applied all applicable GASB pronouncements and elected to apply Financial Accounting Standards Board (FASB)standards except for those conflicting with or in contradiction to GASB pronouncements.

The accounting and reporting policies of Energy Northwest are regulated by the Washington State Auditor's Office and are based on the Uniform System of Accounts prescribed for public utilities and licensees by FERC. Energy Northwest uses the full accrual basis of accounting where revenues are recognized when earned and expenses are recognized when incurred.

Revenues and expenses related to Energy Northwest's operations are considered to be operating revenues and expenses; while revenues and expenses related to capital, financing and investing activities are considered to be other income and expenses.

Separate funds and books of accounts are maintained for each business unit. Payment of the obligations of one business unit with funds of another business unit is prohibited, and would constitute violation of bond resolution covenants (See Note 5).Energy Northwest maintains an Internal Service Fund for centralized control and accounting of certain capital assets such as data processing equipment, and for payment and accounting of internal services, payroll, Fnet gy Northwest 20 13 Annual Report benefits, administrative and general expenses, and certain contracted services on a cost reimbursement basis. Certain assets in the Internal Service Fund are also owned by this Fund and operated for the benefit of other projects.

Depreciation relating to capital assets is charged to the appropriate business units based upon assets held by each project.Liabilities of the Internal Service Fund represent accrued payroll, vacation pay, employee benefits, and common accounts payable which have been charged directly or indirectly to business units and will be funded by the business units when paid. Net amounts owed to, or from, Energy Northwest business units are recorded as Current Liabilities-Due to other business units, or as Current Assets-Due from other business units on the Internal Service Fund Balance Sheet.The combined total column on the financial statements is for presentation (unaudited) only as each Energy Northwest business unit is financed and accounted for separately from all other current and future business units. The FY 2013 Combined Total includes eliminations for transactions between business units as required in GASB Statement No. 34, "Basic Financial Statements and Management's Discussion and Analysis for State and Local Governments." Pursuant to GASB Statement No. 20, "Accounting and Financial Reporting for Proprietary Funds and Other Governmental Entities That Use Proprietary Fund Accounting," Energy Northwest has elected to apply all FASB standards, except for those that conflict with, or contradict, GASB pronouncements.

Specifically, GASB No. 7, "Advance Refundings Resulting in Defeasance of Debt," and GASB No. 23, "Accounting and Financial Reporting for Refundings of Debt Reported by Proprietary Activities," conflict with ASC 860, "Transfers and Servicing." As such, the guidance under GASB No. 7 and No. 23 is followed.

Such guidance governs the accounting for bond defeasances and refundings.

In June 2011, GASB issued Statement No. 63, "Financial Reporting of Deferred Outflows of Resources, Deferred Inflows of Resources and Net Position." Statement No. 63 amends the current net assets reporting requirements by incorporating deferred inflows of resources and deferred outflows of resources into the definitions of required financial statement components and renames "Net Assets" as "Net Position." Statement No.63 is effective for Energy Northwest beginning in fiscal year 2013. Energy Northwest's financial statements have been modified to conform to the requirements of this statement.

Implementation did not have a material impact on the Energy Northwest's financial results.In March 2012, GASB issued Statement No. 65, "Items, Previously Reported as Assets and Liabilities." Statement No. 65 establishes accounting and financial reporting standards to reclassify certain items previously reported as assets and liabilities as deferred outflows or deferred inflows of resources, or as outflows or inflows of resources.

This statement also limits the use of the term deferred in financial statement presentations.

This statement is effective for Energy Northwest beginning in fiscal year 2014. The District is currently assessing the financial statement impact of adopting this statement, but does not believe that its impact will be material.In June 2012, GASB issued Statement No. 68, "Accounting and Financial Reporting for Pensions -An Amendment of GASB Statement No.27." The primary objective of Statement No. 68 is to improve accounting and financial reporting by state and local governments for pensions.

This statement establishes standards for measuring and recognizing liabilities, deferred outflows and deferred inflows of resources and expenses.

For defined benefit pension plans, this statement identifies the methods and assumptions to project benefit payments, discount projected benefit payments to their actuarial present value and attribute present value to periods of employee service. Note disclosure and required supplementary information about pensions are also addressed.

Statement No. 68 is effective for Energy Northwest beginning in fiscal year 2015. Energy Northwest is currently evaluating the financial statement impact of adopting this statement.

b) Utility Plant and Depreciation:

Utility plant is recorded at original cost which includes both direct costs of construction or acquisition and indirect costs.Property, plant, and equipment are depreciated using the straight-line method over the following estimated useful lives: Buildings and Improvements Generation Plant Transportation Equipment General Plant and Equipment 20- 60 years 40 years 6- 9 years 3 -15 years Group rates are used for assets and, accordingly, no gain or loss is recorded on the disposition of an asset unless it represents a major retirement.

When operating plant assets are retired, their original cost together with removal costs, less salvage, is charged to accumulated depreciation.

The utility plant and net assets of Nuclear Projects Nos. 1 and 3 have been reduced to their estimated net realizable values due to termination.

A write-down of Nuclear Projects Nos. 1 and 3 was recorded in FY 1995 and included in Cost in Excess of Billings.

Interest expense, termination expenses and asset disposition costs for Nuclear Projects Nos. 1 and 3 have been charged to operations (see Note 15).c) Capitalized Interest:

Energy Northwest analyzes the gross interest expense relating to the cost of the bond sale, taking into account interest earnings and draws for purchase or construction reimbursements for the purpose of analyzing impact to the recording of capitalized interest.

If estimated costs are more than inconsequential, an adjustment is made to allocate capitalized interest to the appropriate plant account. Capitalized interest costs were $1.6 million.d) Nuclear Fuel: Energy Northwest has various agreements for uranium concentrates, conversion, and enrichment to provide for short-term enriched uranium product and long-term enrichment services.

All expenditures related to the initial purchase of nuclear fuel for Columbia, including interest, were capitalized and carried at cost.e) Asset Retirement Obligation:

Energy Northwest has adopted ASC 410, "Asset Retirement and Environmental Obligations." This standard requires Energy Northwest to recognize the fair value of a liability associated with the retirement of a long-lived asset, such as: Columbia 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 established decommissioning and site restoration funds for Columbia and monies are being deposited each year in accordance with an established funding plan (see Note 12).g) Derivative Instruments:

In June 2008, GASB issued Statement No.53, "Accounting and Financial Reporting for Derivative Instruments." Statement No. 53 provides a comprehensive framework for the measurement, recognition and disclosure of derivative instrument transactions for the purpose of enhancing the usefulness and comparability of derivative instrument information reported by state and local governments (see Note 14).h) Restricted Assets: In accordance with bond resolutions, related agreements and laws, separate restricted accounts have been established.

These assets are restricted for specific uses including debt service, construction, capital additions and fuel purchases, unplanned operation and maintenance costs, termination, decommissioning, operating reserves, financing, long-term disability, and workers'compensation claims. They are classified as current or non-current assets as appropriate.

i) Cash and Investments:

For purposes of the Statements of Cash Flows, cash includes unrestricted and restricted cash balances and each business unit maintains its cash and investments.

Short-term highly liquid investments are not considered to be cash equivalents, but are classified as available-for-sale investments and are stated at fair value with unrealized gains and losses reported in investment income (see Note 3). Energy Northwest resolutions and investment policies limit investment authority to obligations of the United States Treasury, Federal National Mortgage Association and Federal Home Loan Banks.Safe keeping agents, custodians, or trustees hold all investments for the benefit of the individual Energy Northwest business units.j) Accounts Receivable:

The percentage of sales method is used to estimate uncollectible accounts.

The reserve is then reviewed for adequacy against an aging schedule of accounts receivable.

Accounts deemed uncollectible are transferred to the provision for uncollectible accounts on a yearly basis. Accounts receivable specific to each business unit are recorded in the residing business unit.k) Other Receivables:

Other receivables include amounts related to the Internal Service Fund from miscellaneous outstanding receivables from other business units which have not yet been collected.

The amounts due to each business unit are reflected in Due To/From other business units. Other receivables specific to each business unit are recorded in the residing business unit.1) Materials and Supplies:

Materials and supplies are valued at cost using the weighted average cost method.n) Long-Term Liabilities:

Consist of obligations related to bonds payable and the associated premiums/discounts and gains/losses.

Other noncurrent liabilities for Columbia relates to the dry storage cask activity.o) Debt Premium, Discount and Expense: Original issue and reacquired bond premiums, discounts and expenses relating to the bonds are amortized over the terms of the respective bond issues using the bonds outstanding method which approximates the effective interest method.In accordance with GASB Statement No. 23, "Accounting and Financial Reporting for Refundings of Debt Reported by Proprietary Activities," losses on debt refundings have been deferred and amortized as a component of interest expense over the shorter of the remaining life of the old or new debt.p) Revenue Recognition:

Energy Northwest accounts for expenses on an accrual basis, and recovers, through various agreements, actual cash requirements for operations and debt service for Columbia, Packwood, Nuclear Project No. 1 and Nuclear Project No. 3. For these business units, Energy Northwest recognizes revenues equal to expenses for each period.No net revenue or loss is recognized, and no net assets are accumulated.

The difference between cumulative billings received and cumulative expenses is recorded as either billings in excess of costs (deferred credit)or as costs in excess of billings (deferred debit), as appropriate.

Such amounts will be settled during future operating periods (see Note 6).Energy Northwest accounts for revenues and expenses on an accrual basis for the remaining business units.The difference between cumulative revenues and cumulative expenses is recognized as net revenue or loss and included in Net Assets for each period.q) Capital Contribution:

Renewable Energy Performance Incentive (REPI)payments enable Nine Canyon to receive funds based on generation as it applies to the REPI bill. REPI was created as part of the Energy Policy Act of 1992 to promote increases in the generation and utilization of electricity from renewable energy sources and to further the advances of renewable energy technologies.

This program, authorized under section 1212 of the Energy Policy Act of 1992, provides financial incentive payments for electricity produced and sold by new qualifying renewable energy generation facilities.

Nine Canyon did not record a receivable for FY 2013 REPI funding as no funds are anticipated to be disbursed to Energy Northwest under this program. The payment stream from Nine Canyon participants and the anticipated REPI funding were projected to cover the total costs of the purchase agreement.

Permanent shortfalls in REPI funding for the Nine Canyon project led to a revised rate plan to incorporate the impact of this shortfall over the life of the project. The current rate schedule for the Nine Canyon participants covers total estimated project costs occurring in FY 2013 and estimated total cost recovery projections out to the 2030 proposed end date. During FY 2013 there was no cost recovery obtained from REPI.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 2101 2` 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 $Unamortized (discount)/premium on bonds -net Unamortized gain/(loss) on bond refundings Other noncurrent liabilities 2,441,385

$120,221 (9,966):: 15,776 782,655 $2,632 3,371 2,142 61,020 $17,262 580 4 3,163,020 105,591 (7,175)17,914$2,567,416

$790,800 $78,866 $3,279,350 Nuclear Project No.1 Revenue bonds payable Unamortized (discount)/premium on bonds -net Unamortized gain/(loss) on bond refundings

$1,321,060

$56,290 (3,614)::-S$30 3,905 273,055 $20,069 461 1,048,005 36,251 (170)$1,373,736

$3,935 $293,585 $1,084,086 Nuclear Project No.3 Revenue bonds payable Unamortized (discount)/premium on bonds -net Unamortized gain/(Iloss) on bond refundings 1,395,405

$53,241 (974): 8,403 913 166,160 $16,689 823 1,229,245 44,955 (884)$1,447,672 4 $9,316 i $183,672 : $1,273,316 Nine Canyon Revenue bonds payable Unamortized (discount)/premium on bonds -net Unamortized gain/(Iloss) on bond refundings 130,955$4,743 (279):: 6,835$605 22 124,120 4,138 (214)88$135,419 : $88 $7,462 $128,044 fl A Commitment to Exce[Lence r) Compensated Absences:

Employees earn leave in accordance with length of service. Energy Northwest accrues the cost of personal leave in the year when earned. The liability for unpaid leave benefits and related payroll taxes was $20.8 million at June 30, 2013 and is recorded as a current liability.

Note 2 -UtiLity PLant Utility plant activity for the year ended June 30, 2013 was as follows: Utility Plant Activity (Dottars in thousands)

S) Use of Estimates:

The preparation of Energy Northwest financial statements in conformity with GAAP requires management to make estimates and assumptions that directly affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities 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.

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 Packwood Nuclear Project No. 1 Nuclear Project No. 3 Business Development Fund Internal Service Fund Nine Canyon$37,986 $1,023 213,488 149,725 2,540 27,202 13,971 14 $$38,000 1,023 213,488 149,725 2,540 27,203 13,971 5 2 (4)(2)(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 Northwest manages its exposure to declines in fair values by limiting investments to those with maturities designated in specific bond resolutions.

Credit Risk: Energy Northwest's investment policy restricts investments to debt securities and obligations of the U.S. Treasury U.S. government agencies Federal National Mortgage Association and the Federal Home Loan Banks, certificates of deposit and other evidences of deposit at financial institutions qualified by the Washington Public Deposit Protection Commission (PDPC), and general obligation debt of state and local governments and public authorities recognized with one of the three highest credit ratings (AAA, AA+, AA, or equivalent).

This investment policy is more restrictive than the state law.Concentration of Credit Risk: Energy Northwest's investment policy does 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.Custodial Credit Risk, Deposits:

For a deposit, this is the risk that in the event of bank failure, Energy Northwest's deposits may not be returned to it.Energy Northwest's interest bearing accounts and certificates of deposits are covered up to $250,000 by Federal Depository Insurance (FDIC) while non-interest bearing deposits are entirely covered by FDIC and if necessary, all interest and non-interest bearing deposits are covered by collateral held in a multiple financial institution collateral pool administered by the Washington state Treasurer's Local Government Investment Pool (PDPC). Under state law, public depositories under the PDPC may be assessed on a prorated basis if the pool's collateral is insufficient to cover a loss. All deposits are insured by collateral held in the multiple financial institution collateral pool. State law requires deposits may only be made with institutions that are approved by the PDPC.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 Energy Northwest authorizing issuance of revenue bonds for each business unit provide that such bonds are payable from the revenues of that business unit. All bonds issued under resolutions Nos. 769, 775 and 640 for Nuclear Projects Nos.1, 3 and Columbia, respectively, have the same priority of payment within the business unit (the "prior lien bonds"). All bonds issued under resolutions Nos.835, 838 and 1042 (the "electric revenue bonds") for Nuclear Projects Nos. 1, 3 and Columbia, respectively, are subordinate to the prior lien bonds and have the same subordinated priority of payment within the business unit. Nine Canyon's bonds were authorized by the following resolutions:

Resolution No. 1214 (2001 Bonds), Resolution No. 1299 (2003 Bonds), Resolution No. 1376 (2005 Bonds), Resolution No.1482 (2006 Bonds), and Resolution No. 1722 (2012 Bonds).During the year ended June 30,2013, Energy Northwest issued, for Columbia Series 2012-D and 2012-E fixed rate bonds with a weighted average coupon interest rate ranging from 1.06 percent to 5.0 percent.The Series 2012-D bonds issued for Columbia are tax-exempt fixed-rate bonds. Series 2012-E bonds issued for Columbia are taxable fixed rate bonds.These bonds were issued in majority to cover fuel purchases (See Note 1).The Bond Proceeds, Weighted Average Coupon Interest Rates and Bond Proceeds for 2012-D and 2012-E are presented in the following tables: A Cornmnittnent to Excelience Bond Proceeds (Dollars in millions)2012D Columbia $ 34.14 $Total $ 34.14 $2012E 748.52 $748.52 $Total 782.66 782.66 2012E 2.50%5.00%Weighted Average Coupon Interest Rate for New Bonds 2012D Columbia 4.48%Total 4.08%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 (Dollars in thousands)

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

Series 2003A 2003F 2004A 2004B 2004C 2005A 2005C 2006A 2006C 2006D 2007A 2007B 2007D 2008A 20088 2008C 2009A 2009B 2009C 20108 2010C 2010D 2011A 2011B 2011C 2012A 2012D 2012E Coupon Rate (%)5.50 5.00-5.25 5.25 5.50 5.25 5.00 4.64-4.74 5.00 5.00 5.80 5.00 5.10-5.33 5.00 5.00-5.25 5.95 5.00-5.25 3.00-5.00 4.59-6.80 4.25-5.00 3.75-4.25 4.52-5.12 5.61-5.71 3.00-5.00 4.19-5.19 3.55 5.00 5.00 1.06-4.14 Serial or Term Maturities 7-1-2015 7-1-13/2018 7-1-17/2018 7-1-2013 7-1-13/2018 7-1-15/2018 7-1-13/2015 7-1-2012024 7-1-20/2024 7-1-2023 7-1-13/2018 7-1-13/2021 7-1-21/2024 7-1-14/2018 7-1-20/2021 7-1-21/2024 7-1-14/2018 7-1-1412024 7-1-20/2024 7-1-20/2024 7-1-20/2024 7-1-23/2024 7-1-13/2023 7-1-19/2024 7-1-2019 7-1-18/2021 7-1-25/2044 7-1-15/2037 Amount$ 81,090 23,710 129,260 12,715 15,045 114,985 42,885 434,210 62,200 3,425 77,575 10,310 35,080 110,935 12,025 37,240 116,425 18,515 69,170 16,005 75,770 155,805 311,245 29,920 4,600 441,240 34,140 748,515 Series 1989B 2003A 2004A 2004B 2005A 2006A 2007A 2007B 2007C 2008A 2008D 2009A 20098 2010A 2012A 20128 2012C I Coupon Rate (%)7.125 5.50 5.25 5.50 5.00 5.00 5.00 5.10 5.00 5.00-5.25 5.00 3.25-5.00 4.59 3.00-5.00 5.00 5.00 1.26 I Serial or Term Maturities 7-1-2016 7-1-13/2014 7-1-2013 7-1-2013 7-1 -1 3/2015 7-1-13/2017 7-1-13/2017 7-1-- -201--- 3 7-1-2013 7-1-1312017 7-1-1312017 7-1-13/2017 7-1-14-2015 7-1-2014 7-1-13/2017 7-1-13/2017 7-1-2017 7-1-2015 Amount$ 41,070 174,400 62,485 1,135 72,175 103,120 51,730 2,290 219,020 230,535 38,100 48,905 515 54,805 155,390 41,285 24,100 Revenue bonds payable $ 1,321,060 Estimated fair value at June 30, 2013 $ 1,425,123 (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.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, 2 0 13 Ani it a Rp Nuclear Project No. 3 Refunding Revenue Bonds (Dollars in thousands)

Nine Canyon Wind Project Revenue and Refunding Bonds (Dollars in thousands)

Serial or Term Series Coupon Rate (%) Maturities Serial or Term Coupon Rate (%) Maturities Series Amount Amount 1989A 1989B Subtotal 1989A and 1 1993C 2003A 2004A 2004B 2005A 2006A 2007A 2007C 2008A 2008D 2009A 2009B 2010A 2010B 2011A 2012A 20128 2012C (B)(B)7.125 9898 (A)5.50 5.25 5.50 5.00 5.00 4.50-5.00 5.00 5.25 5.00 5.00-5.25 4.59 5.00 5.00 4.00-5.00 5.00 3.00-5.00 1.26-1.74 7-1-1312014 7-1-13/2014 7-1-2016 7- 1-312018 7- -2013 7-1-14/2016 7-1-2013 7-1-13/2015 7-1-16/2018 7- 1-13/2018 7- 1-13/2018 7- -2018 7-1-13/2017 7-1-14/2018 7-1-2014 7-1-16/2018 7-1-2016 7-1-2018 7-1-2018 7-1-16/2017 7- 1-15/2016$ 2,815 8,297 76,146 87,258 23,963 52,890 83,835 1,515 129,265 39,445 84,465 55,045 13,790 33,595 116,055 970 279,980 29,865 92,285 67,885 30,330 61,635 2005 2006 2012 4.50-5.00 4.50-5.00 2.00-5.00 7-1-13/2023 7-1-13/2030 7-1-13/2023

$ 48,370 68,835 13,750 i -Revenue bond payable $ 130,955 Estimated fair value at June 30, 2012 $ 136,617 (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.Total Bonds Payable $6,071,460 Estimated Fair Value at June 30,2013 $6,612,359 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 $2014 2015-2017 2018-2022 2023-2024 2025-2028 2029-2044 79,765 419,645 1,927,765 648,950 54,275 32,620 71,522 $140,052 382,322 423,440 57,484 9,799 12,972 132,542 219,817 801,967 2,351,205 706,434 64,074 45,592 2013 $ 273,055 $2014 2015 2016 2017 332,100 191,430 239,385 285,090 33,186 $52,401 35,443 27,026 14,117 306,241 384,501 226,873 266,411 299,207$ 3,224,040

$ 1,097,591

$ 4,321,631 Principal and Interest due July 1, 2013.* Fiscal year for this report indicates when the obligations are expected to be paid.$ 1,321,060

$ 162,174 $ 1,483,234 Principal and Interest due July 1, 2013.* 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 2014 2015 2016 2017 2018$ 131,875 S 124,704 129,795 247,499 177,617 472,581 65,552 $88,738 60,487 56,838 45,124 32,625 197,427 213,442 190,283 304,337 222,741 505,206 2013 2014-2017 2018-2021 2022-2025 2026-2029 2030 6,835 $31,135 37,415 30,175 19,855 5,540 3,062 $21,438 15,251 7,805 3,305 249 9,897 52,573 52,666 37,980 23,160 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.Fiscal year for this report indicates when the obligations are expected to be paid.Principal and Interest due July 1, 2013.* Adjustment for Compound Interest Bonds accretion; Compound Interest Bonds are reflected 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 Security -Nuclear Projects Nos. 1 and 3 and Columbia The participants have purchased all of the capability of Nuclear Projects Nos. 1 and 3 and Columbia.

BPA has in turn acquired the entire capability from the participants under contracts referred to as net-billing agreements.

Under the net-billing agreements for each of the business units, participants are obligated to pay Energy Northwest a pro-rata share of the total annual costs of the respective projects, including debt service on bonds relating to each business unit. BPA is then obligated to reduce amounts from participants under BPA power sales agreements by the same amount. The net-billing agreements provide that participants and BPA are obligated to make such payments whether or not the projects are completed, operable or operating and notwithstanding the suspension, interruption, interference, reduction or curtailment of the projects' output.On May 13,1994, Energy Northwest's Board of Directors adopted resolutions terminating Nuclear Projects Nos. 1 and 3. The Nuclear Projects Nos. 1 and 3 project agreements and the net-billing agreements, except for certain sections which relate only to billing processes and accrued liabilities and obligations under the net-billing agreements, ended upon termination of the projects.Energy Northwest previously entered into an agreement with BPA to provide for continuation of the present budget approval, billing and payment processes.

With respect to Nuclear Project No. 3, the ownership agreement among Energy Northwest and private companies was terminated in FY 1999. (See Note 13)Security -Packwood Lake Hydroelectric Project Power produced by Packwood is provided to the 12 member utilities.

The member utilities pay the annual costs, including any debt service, of Packwood and are obligated to pay these annual costs whether or not Packwood is operational.

The Packwood participants also share project revenue to the extent that the amounts exceed project costs.Note 7 -Pension Plans Substantially all Energy Northwest full-time and qualifying part-time employees participate in one of the following statewide retirement systems administered by the Washington State Department of Retirement Systems, under cost-sharing multiple-employer public employee defined benefit retirement plans. The Department of Retirement Systems (DRS), a department within the primary government of the State of Washington, issues a publicly available comprehensive annual financial report (CAFR) that includes financial statements and required supplementary information for each plan. The DRS CAFR may be obtained by writing to: Department of Retirement Systems, Communications Unit, RO. Box 48380, Olympia, Wash., 98504-8380; or it may be downloaded from the DRS website at www.drs.wa.gov.

The following disclosures are made pursuant to GASB Statements No. 27, "Accounting for Pensions by State and Local Government Employers" and No. 50, "Pension Disclosures," an Amendment of GASB Statements No. 25 and No. 27.Any information obtained from the DRS is the responsibility of the state of Washington.

PricewaterhouseCoopers LLP (PwC), independent auditors for Energy Northwest, has not audited or examined any of the information available from the DRS; accordingly, PwC does not express an opinion or any other form of assurance with respect thereto.Public Employees' Retirement System (PERS) Plans 1, 2, and 3 The Legislature established PERS in 1947. Membership in the system includes:

elected officials; state employees; employees of the Supreme, Appeals, and Superior courts; employees of legislative committees; community and technical colleges, college and university employees not participating in higher education retirement programs; employees of district and municipal courts; and employees of local governments.

Approximately 50 percent of PERS salaries are accounted for by state employment.

PERS retirement benefit provisions are established in chapters 41.34 and 41.40 RCW and may be amended only by the State Legislature.

PERS is a cost-sharing multiple-employer retirement system comprised of three separate plans for membership purposes:

Plans 1 and 2 are defined benefit plans and Plan 3 is a defined benefit plan with a defined contribution component.

PERS members who joined the system by September 30, 1977 are Plan 1 members. Those who joined on or after October 1, 1977 and by either, February 28, 2002 for state and higher education employees, or August 31, 2002 for local government employees, are Plan 2 members unless they exercised an option to transfer their membership to Plan 3. PERS members joining the system on or after March 1, 2002 for state and higher education employees, or September 1, 2002 for local government employees have the irrevocable option of choosing membership in either PERS Plan 2 or Plan 3.The option must be exercised within 90 days of employment.

Employees who 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 less than five years to live.PERS is comprised of and reported as three separate plans for accounting purposes:

Plan 1, Plan 2/3, and Plan 3. Plan 1 accounts for the defined benefits of Plan 1 members. Plan 2/3 accounts for the defined benefits of Plan 2 members and the defined benefit portion of benefits for Plan 3 members.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 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 legally be used to pay the defined benefits of any of the Plan 2 or Plan 3 members or beneficiaries, as defined by the terms of the plan. Therefore, Plan 2/3 is considered to be a single plan for accounting purposes.PERS Plan 1 and Plan 2 retirement benefits are financed from a combination of investment earnings and employer and employee contributions.

Employee contributions to the PERS Plan 1 and Plan 2 defined benefit plans accrue interest at a rate specified by the Director of DRS. During DRS' fiscal year 2012, the rate was five and one-half percent compounded quarterly.

Members in PERS Plan 1 and Plan 2 can elect to withdraw total employee contributions and interest thereon upon separation from PERS-covered employment.

PERS Plan 1 members are vested after the completion of five years of eligible service.PERS Plan 1 members are eligible for retirement after 30 years of service, or at the age of 60 with five years of service, or at the age of 55 with 25 years of service. The monthly benefit is 2 percent of the average final compensation (AFC) per year of service, but the benefit may not exceed 60 percent of the AFC. The AFC is the monthly average of the 24 consecutive highest-paid service credit months.E A Commitment to Exceltence The monthly benefit is subject to a minimum for retirees who have 25 years of service and have been retired 20 years, or who have 20 years of service and have been retired 25 years. If a survivor option is chosen, the benefit is reduced. Plan 1 members retiring from inactive status prior to the age of 65 may also receive actuarially reduced benefits.

Plan 1 members may elect to receive an optional Cost of Living Adjustment (COLA) that provides an automatic annual adjustment based on the Consumer Price Index. The adjustment is capped at 3 percent annually.

To offset the cost of this annual adjustment, the benefit is reduced.PERS Plan 2 members are vested after the completion of five years of eligible service. Plan 2 members are eligible for normal retirement at the age of 65 with five years of service. The monthly benefit is 2 percent of the AFC per year of service. The AFC is the monthly average of the 60 consecutive highest-paid service months. There is no cap on years of service credit; and a cost-of-living allowance is granted (based on the Consumer Price Index), capped at 3 percent annually.PERS Plan 2 members who have at least 20 years of service credit and are 55 years of age or older are eligible for early retirement with a reduced benefit. The benefit is reduced by an early retirement factor (ERF) that varies according to age, for each year before age 65.PERS Plan 3 has a dual benefit structure.

Employer contributions finance a defined benefit component and member contributions finance a defined contribution component.

As established by chapter 41.34 RCW, employee contribution rates to the defined contribution component range from 5 to 15 percent of salaries, based on member choice. There are currently no requirements for employer contributions to the defined contribution component of PERS Plan 3.PERS Plan 3 defined contribution retirement benefits are dependent upon the results of investment activities.

Members may elect to self-direct the investment of their contributions.

Any expenses incurred in conjunction with self-directed investments are paid by members. Absent a member's self-direction, PERS Plan 3 investments are made in the same portfolio as that of the PERS 2/3 defined benefit plan.There are 1,184 participating employers in PERS. Membership in PERS consisted of the following as of the latest actuarial valuation date for the plans of June 30, 2011: of the State Actuary to fully fund Plan 2 and the defined benefit portion of Plan 3. Under PERS Plan 3, employer contributions finance the defined benefit portion of the plan and member contributions finance the defined contribution portion. The Plan 3 employee contribution rates range from 5 to 15 percent, based on member choice. Two of the options are graduated rates dependent on the employee's age.As a result of the implementation of the Judicial Benefit Multiplier Program in January 2007, a second tier of employer and employee rates was developed to fund, along with investment earnings, the increased retirement benefits of those justices and judges that participate in the program.The methods used to determine the contribution requirements are established under state statute in accordance with chapters 41.40 and 41.45 RCW.The required contribution rates expressed as a percentage of current-year covered payroll, as of December 31, 2012, are as follows: i PERS Plan 1 PERS Plan 2 PERS Plan 3 Employer*Employee 7.25%/** 7.25%/**6.000/o* 4.***i 7.25%***The employer rates include the employer administrative expense fee currently set at 0.16 percent.The employer rate for state elected officials is 10.74 percent for Plan I and 7.21 percent for Plan 2 and Plan 3.* Plan 3 defined benefit portion only.The employee rate for state elected officials is 7.50 percent for Plan 1 and 4.64 percent for Plan 2.Variable from 5.0 percent minimum to 15.0 percent maximum based on rate selected by the PERS 3 member.Both Energy Northwest and the employees made the required contributions.

Energy Northwest's required contributions for the years ending June 30 were as follows: PERS Plan 1 PERS Plan 2 PERS Plan 3 2013 2012 2011$$$106,5145 124,071 $184,863 $10,630,935

$9,773,209

$7,921,762

$5,075,823 4,710,819 4,281,077 Retirees and Beneficiaries Receiving Benefits Terminated Plan Members Entitled to But Not Yet Receiving Benefits Active Plan Members Vested Active Plan Members Non-vested Total 79,363 29,925 105,578 46,839 261,705 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 Energy Northwest provides a 401(k) deferred compensation plan (401(k)plan), and a 457 deferred compensation plan. Both plans are defined contribution plans that were established to provide a means for investing savings by employees for retirement purposes.

All permanent, full-time employees are eligible to enroll in the plans. Participants are immediately vested in their contributions and direct the investment of their contribution.

Each participant may elect to contribute pre-tax annual compensation, subject to current Internal Revenue Service limitations.

For the 401(k) plan, Energy Northwest may elect to make an employer matching contribution for each of its employees who is a participant during the plan year. The amount of such an employer match shall be 50 percent of the maximum salary deferral percentage.

During FY 2013 Energy Northwest contributed

$3.1 million in employer matching funds while employees contributed

$10.8 million for FY 2013.Note 9 -Other EmpLoyment Benefits -Post-Employment In addition to the pension benefits available through PERS, Energy Northwest offers post-employment life insurance benefits to retirees who are eligible to receive pensions under PERS Plan 1, Plan 2, and Plan 3. There are 62 retirees who remain participants in the insurance program. In 1994, Energy Northwest's Executive Board approved provisions which continued the life insurance benefit to retirees at 25 percent of the premium for employees who retire prior to January 1, 1995, and charged the full 100 percent premium to employees who retired after December 31, 1994. The life insurance benefit is equal to the employee's annual rate of salary at retirement for non-bargaining employees retiring prior to January 1, 1995. The life insurance benefit has a maximum limit of $10,000 for retirees after December 31, 1994. The cost of coverage for retirees remained unchanged for FY 2013 and was $2.82 per $1,000 of coverage.

Employees who retired prior to January 1, 1995, contribute 58 cents per $1,000 of coverage while Energy Northwest pays the remainder; retirees after December 31, 1994, pay 100 percent of the cost coverage.

Premiums are paid to the insurer on a current period basis. At the time each employee retired, Energy Northwest accrued an estimated liability for the actuarial value of the future premium. Energy Northwest revises the liability for the actuarial value of estimated future premiums, net of retiree contributions.

The total liability recorded at June 30, 2013, was $0.6 million for these benefits.During FY 2013, pension costs for Energy Northwest employees and post-employment life insurance benefit costs for retirees were calculated and allocated to each business unit based on direct labor dollars. This allocation basis resulted in the following percentages by business unit for FY 2013 for 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 residual amount of 2 percent.Note 10 -NucLear Licensing and Insurance Nuclear Licensing Energy Northwest is a licensee of the Nuclear Regulatory Commission and is subject to routine licensing and user fees. Additionally, Energy Northwest may be subject to license modification, suspension, revocation, or civil penalties in the event regulatory or license requirements are violated.Nuclear Insurance Nuclear insurance includes liability coverage, property damage, decontamination and premature decommissioning coverage and accidental outage and/or extra expense coverage.

The liability coverage is governed by the Price-Anderson Act (Act), while the property damage, decontamination and premature decommissioning coverage are defined by the Code of Federal Regulations.

Energy Northwest continues to maintain all regulatory required limits as defined by the NRC, Code of Federal Regulations and the Act. The NRC requires Energy Northwest to certify nuclear insurance limits on an annual basis. Energy Northwest intends to maintain insurance against nuclear risks to the extent such insurance is available on reasonable terms and in an amount and form consistent with customary practice.

Energy Northwest is self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due 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 below are as of June 30, 2013.American Nuclear Insurance (ANI) Coverage:

The Act provides financial protection for the public in the event of a significant nuclear generation plant incident.

The Act sets the statutory limit of public liability for a single nuclear incident at $12.6 billion. Energy Northwest addresses this requirement through a combination of private insurance and an industry-wide retrospective payment program called Secondary Financial Protection (SFP).Energy Northwest has $375 million of liability insurance as the first layer of protection.

If any US nuclear generation plant has a significant event which exceeds the plant's first layer of protection, every operating licensed reactor in the US is subject to an assessment up to $117.5 million not including state insurance premium tax. Assessments are limited to $17.5 million per reactor, per year, per incident, excluding tax. The SFP is adjusted at least every 5 years to account for inflation and any changes in the number of operating plants.The SFP and liability coverage are not subject to any deductibles.

NEIL Coverage:

The Code of Federal Regulations requires nuclear generation plant license-holders to maintain at least $1.06 billion nuclear decontamination and property damage insurance and requires the proceeds thereof to be used to place a plant in a safe and stable condition, to decontaminate it pursuant to a plan submitted to and approved by the NRC before the proceeds can be used for plant repair or restoration or to provide for premature decommissioning.

Energy Northwest has aggregate coverage in the amount of $2.25 billion which is subject to a $5 million deductible per accident.Note 11 -Asset Retirement ObLigation (ARO)Energy Northwest adopted ASC 410 on July 1,2002. This standard requires 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 retirement of tangible long-lived assets, such as nuclear decommissioning and site restoration liabilities, in the period in which it is incurred.

Upon initial recognition of the AROs that are measurable, the probability weighted future cash flows for the associated retirement costs are discounted using a credit-adjusted-risk-free rate, and are recognized as both a liability and as an increase in the capitalized carrying amount of the related long-lived assets.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 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 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 for the entire cost of decommissioning and site restoration; therefore, any 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 (asset), as appropriate, as no net revenue or loss is recognized, and no net assets are accumulated for the net-billed projects.Energy Northwest has identified legal obligations to retire generating plant assets at the following business units: Columbia, Nuclear Project No.1 and Nine Canyon. Decommissioning and site restoration requirements for Columbia and Nuclear Project No. 1 are governed by the NRC regulations and site certification agreements between Energy Northwest and the state of Washington and regulations adopted by the Washington Energy Facility Site Evaluation Council (EFSEC) and a lease agreement with the DOE (See Notes 1 and 13).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 generating plant, and for the ISFSI a net asset value of $1.1 million and an accumulated liability of $2.2 million. The adjustment to ISFSI was associated with new Nuclear Regulatory Commission (NRC) spent fuel decommissioning 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 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 of $18.2 million.Under the current agreement, Nine Canyon has the obligation to remove the generation facilities upon expiration of the lease agreement if requested by the lessors. The Nine Canyon Wind Project recorded the related original ARO in FY 2003 for Phase I and I. Phase III began commercial operation in FY 2008 and the original ARO was adjusted to reflect the change in scenario for the retirement obligation, with current lease agreements reflecting a 2030 expiration date. As of June 30, 2013, Nine Canyon has a capital decommissioning net asset value of $0.6 million and an accumulated liability of $1.3 million.Packwood's obligation has not been calculated because the time frame and extent of the obligation was considered under this statement as indeterminate.

As a result, no reasonable estimate of the ARO obligation can be made. An ARO will be required to be recorded if circumstances change.Management believes that these assets will be used in utility operations for the foreseeable future.The following table describes the changes to Energy Northwest's ARO liabilities for the year ended June 30, 2013. The balance is included in the accounts payable and accrued expense balances for each unit. ISFSI is included in Columbia's balance: Asset Retirement Obligation (Dollars in millions)Columbia Generating Station Balance At June 30, 2012 Current year accretion expense ARO at June 30, 2013 ISFSI Balance At June 30, 2012 Current year accretion expense Revision in future estimates ARO at June 30, 2013 Nuclear Project No. 1 Balance At June 30, 2012 Current year accretion expense Revision in future restoration estimates ARO at June 30, 2013 Nine Canyon Wind Project Balance At June 30, 2012 Current year accretion expense ARO at June 30, 2013$118.70 6.21$ 124.91$1.57 0.08 0.51$ 2.16$16.40 0.50 1.34$ 18.24$1.24 0.05$ 1.29 Note 12 -Decommissioning and Site Restoration The NRC has issued rules to provide guidance to licensees of operating nuclear plants on providing financial assurance for decommissioning plants at the end of each plant's operating life (see Note 11 for Columbia ARO). In September 1998, the NRC approved and published its "Final Rule on Financial Assurance Requirements for Decommissioning Power Reactors." As provided in this rule, each power reactor licensee is required to report to the NRC the status of its decommissioning funding for each reactor or share of a reactor it owns. This reporting requirement began March 31, 1999, and reports are required every two years thereafter.

Energy Northwest submitted its most recent report to the NRC in March 2013.Energy Northwest's current estimate of Columbia's decommissioning costs in FY 2013 dollars is $459.0 million (Columbia

-$454.6 million and ISFSI -$4.4 million).

This estimate, which is updated biannually, is based on the NRC minimum amount required to demonstrate reasonable financial assurance for a boiling water reactor with the power level of Columbia.Site restoration requirements for Columbia are governed by the site certification agreements between Energy Northwest and the state of Washington and by regulations adopted by the EFSEC. Energy Northwest submitted a site restoration plan for Columbia that was approved by the EFSEC on June 12, 1995. Energy Northwest's current estimate of Columbia's site restoration costs is $109.0 million in constant 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 in the decommissioning

' ;t! hW.-e Ai2)1 13 A it I PI I r and site restoration funds as of June 30, 2013, totaled approximately

$188.6 million and $31.3 million, respectively.

Since September 1996, these amounts have been held in an irrevocable trust that recognizes asset retirement obligations according to the fair value of the dismantlement and restoration costs of certain Energy Northwest assets. The trustee is a domestic U.S. bank that certifies the funds for use when needed to retire the asset. The trust is funded by BPA ratepayers and managed by BPA in accordance with NRC requirements and site certification agreements; the balances in these external trust funds are not reflected on Energy Northwest's balance sheet.Energy Northwest established a decommissioning and site restoration plan for the ISFSI in 1997. Beginning in FY 2003, an annual contribution is made to the Energy Northwest Decommissioning Fund. These contributions are held by Energy Northwest and not held in trust by BPA. The fair market value of cash and investments as of June 30, 2013, is $1.1 million. These contributions will occur through FY 2044; cash payments will begin for decommissioning and site restoration in FY 2045 with equal installments for five years totaling$10.6 million in constant dollars based on the study.Note 13 -Commitments And Contingencies Nuclear Project No. 1 Termination Since the Nuclear Project No.1 termination, Energy Northwest has been planning for the demolition of Nuclear Project No. 1 and restoration of the site, recognizing the fact that there is no market for the sale of the project in its entirety, and no viable alternative use has been found to-date. The final level of demolition and restoration will be in accordance with agreements discussed below under "Nuclear Project No. 1 Site Restoration.

Nuclear Project No. 3 Termination In June 1994, the Nuclear Project No. 3 Owners Committee voted unanimously to terminate the project. In 1995, a group from Grays Harbor County, Wash., formed the Satsop Redevelopment Project (SRP). The SRP introduced legislation with the state of Washington under Senate Bill No. 6427, which passed and was signed by the governor of the state of Washington on March 7, 1996. The legislation enables local governments and Energy Northwest to negotiate an arrangement allowing such local governments to assume an interest in the site on which Nuclear Project No. 3 exists for economic development by transferring ownership of all or a portion of the site to local government entities.

This legislation also provides for the local government entities to assume regulatory responsibilities for site restoration requirements and control of water rights. In February 1999, Energy Northwest entered into a transfer agreement with the SRP to transfer the real and personal property at the site of Nuclear Project No. 3. The SRP also agreed to assume regulatory responsibility for site restoration.

Therefore, Energy Northwest is no longer responsible to the state of Washington and EFSEC for any site restoration costs.Nuclear Project No. 1 Site Restoration Site restoration requirements for Nuclear Project No. 1 are governed by site certification agreements between Energy Northwest and the state of Washington and regulations adopted by EFSEC, and a lease agreement with DOE. Energy Northwest submitted a site restoration plan for Nuclear Project No. 1 to EFSEC on March 8, 1995, which complied with EFSEC requirements to remove the assets and restore the sites by demolition, burial, entombment, or other techniques such that the sites pose minimal hazard to the public.EFSEC approved Energy Northwest's site restoration plan on June 12, 1995.In its approval, EFSEC recognized that there is uncertainty associated with Energy Northwest's proposed plan. Accordingly, EFSEC's conditional approval provides for additional reviews once the details of the plan are finalized.

A new plan with additional details was submitted in FY 2003. This submittal was used to calculate the ARO discussed in Note 11.Business Development Fund Interest in Northwest Open Access Network The Business Development Fund is a member of the Northwest Open Access Network (NoaNet).

Members formed NoaNet pursuant to an Interlocal Cooperation Agreement for the development and efficient use by the members and others of a communication network in conjunction with BPA.The Business Development Fund has a 7.38 percent interest in NoaNet with a potential mandate of an additional 25 percent step-up possible for a maximum 9.23 percent. NoaNet has $12.4 million in network revenue bonds and note payables outstanding, based on their December 30, 2012 audited 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 Gross Revenue (after payment of costs of Maintenance and Operation) is insufficient for this purpose. The maximum principal share (based on step-up potential) that the Business Development Fund could be required to pay is$1 .1 million. The Business Development Fund is not obligated to reimburse losses of NoaNet unless an assessment is made to NoaNet's members based on a two-thirds vote of the membership.

In FY 2013 the Business Development Fund was not required to contribute to NoaNet. Financial statements for NoaNet may be obtained by writing to: Northwest Open Access Network, NoaNet Headquarters, 5802 Overlook Ave. NE, Tacoma, Wash., 98422. Any information obtained from NoaNet is the responsibility of NoaNet. PwC has not audited or examined any information available from NoaNet; accordingly, PwC does not express an opinion or any other form of assurance with respect thereto.Other Litigation and Commitments Energy Northwest vs. United States of America filed in U.S. Court of Federal Claims in July 2011 (Cause No. 11-447C-EJD).

This is the second action for partial breach of contract brought by Energy Northwest against the United States (Department of Energy, "DOE") for damages ranging between September 1, 2006 through July 2012, for DOE's continuing failure to meet its legal obligations to accept and dispose of spent nuclear fuel and high-level radioactive waste per the Standard Contract.

After extensive discovery, Energy Northwest is claiming total damages of approximately

$24.9 million in this case. Energy Northwest believes DOE does not have a defense on liability, which was established in the prior case.Energy Northwest is involved in other various claims, legal actions and contractual commitments and in certain claims and contracts arising in the normal course of business.

Although some suits, claims and commitments are significant in amount, final disposition is not determinable.

In the opinion of management, the outcome of such litigation, claims or commitments will not have a material adverse effect on the financial positions of the business units or Energy Northwest as a whole. The future annual cost of the business units, however, may either be increased or decreased as a result of the outcome of these matters.M A Commitment to Excellence Note 14 -Derivative Instruments GASB Statement No. 53, "Accounting and Reporting for Derivative Instruments" was adopted in FY 2010. Energy Northwest's policy is to review and apply as appropriate the normal purchase and normal sales exception under GASB No. 53. Energy Northwest has reviewed various contractual arrangements to determine applicability of this statement.

Purchases and sales of nuclear fuel and components that require physical delivery and are expected to be used and/or sold in the normal course of business are generally considered normal purchases and normal sales. These transactions are excluded Under GASB 53 and therefore are not required to be recorded at fair value in the financial statements.

Certain contracts for power options were evaluated and the did not meet the exclusion for normal purchase and normal sale: The Business Development Fund had a power sales contract subject to the provisions'oGASB

53. Call options associated with the contract had a- noi:onal amount of 50 MWh. The fair value of the powersles option contract is based on the futures price curve for the Mid-Columbia Intercontinental Exchange for electricity and the Sumas index for natural gas. This contract settled in June 2013.Changes in the fair value of the call options are classified as non-operating revenue and expenses -investment income on the Statements of Revenues, Expenses and Changes in Net Assets. The total dollars recorded in FY 2013 were$148,000.Note 15 -Nuclear Fuels In May 2012, Energy Northwest entered into agreements with three other parties for processing high assay uranium tails. The Program consists of several agreements between the parties involved, entered into as a joint effort between the Department of Energy (DOE), Tennessee Valley Authority (TVA), United States Enrichment Corporation (USEC) and Energy Northwest to enrich approximately 9,082 metric tons (MTU) of Depleted Uranium Hexafluoride (DUF6) with an average assay of 0.44 weight percent U235 (wt%) that will yield approximately 482 MTU of enriched uranium product (EUP) with an average assay of 4.4 wt%.DOE and Energy Northwest have entered into an agreement for the transfer of the DUF6 to Energy Northwest.

The agreement addresses delivery and transfer of title of the DUF6, return of residual DUF6 after enrichment, storage of the EUP, and payment of DOE's costs. The costs for the handling of the DUF6 and storage of the EUP are anticipated to be $5 million or less. As of June 30, 2013, Energy Northwest had recorded $0.4 million in charges to the DOE for delivery of the DUF6, which is capitalized as cost of the fuel being purchased.

Under the Depleted Uranium Enrichment Program (ý(DUEP), Energy Northwest purchased from USEC all of theSeparative Work Units (SWU) contained in the EUP.Upon finalization of the program, Energy Northwest had purchased a total of 481.6 MTU of EUP from USEC at a cost of $687.5 million, which is recorded in nuclear fuel, net of accumulated amortization, as of June 30, 2013.Energy Northwest and IVA have entered into an agreement for the sale and purchase of a portion of the SWU and Feed Component of the EUR The sales under the agreement are expected to total approximately

$731 million. The sales under this agreement are scheduled to take place between 2015 and 2022.Energy Northwest has a contract with DOE that requires DOE to accept title and dispose of spent nuclear fuel.Although the courts have ruled that DOE had the obligation to accept title to spent nuclear fuel by January 31, 1998, currently, there is no known date established when DOE will fulfill this legal obligation and begin accepting spent nuclear fuel.When the fuel is placed in the reactor the fuel cost is amortized to operating expense on the basis of quantity of heat produced for generation of electric energy. The amount moved to spent fuel for cooling increased

$55.3 million. Fees for disposal of fuel in the reactor are expensed as part of the fuel cost.The current period operating expense for Columbia includes an $8.1 million charge from DOE for future spent fuel storage and disposal in accordance with the Nuclear 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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