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{{#Wiki_filter:Financial Data & Information
,J)'ll qv nniliA Rer(-4 tM 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 toPricewaterhouseCoopers LLP all financial records and related data, and believes that all representations made to PricewaterhouseCoopers LLP during its auditwere 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 controlprocedures 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 forrecommendations 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 theinternal 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. RidgeChief Executive Officer Vice President, and Chief Financial
& Risk OfficerAudit, Legal and Finance Committee Chair's LetterThe executive board's Audit, Legal and Finance Committee (committee) is composed of 11 independent directors.
Members of the committee are Chair LarryKenney (July 2012 -February 2013), Marc Daudon, Dan Gunkel, Jack Janda, Skip Orser, Will Purser, Dave Remington, Lori Sanders, Tim Sheldon, Chair KathyVaughn (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 resultsof their audit, their evaluations of Energy Northwest's internal
: controls, and the overall quality of Energy Northwest's financial reporting.
The meetings weredesigned to facilitate any private communications with the committee desired by the internal auditor or independent auditors.
Kathy VaughnChair,Audit, Legal and Finance Committee MA Comnmitment to Excetlonc Independent Auditor's ReportTo 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 theColumbia Generating
: Station, Packwood Lake Hydroelectric
: Project, Nuclear Project No.1, Nuclear Project No.3, the Business Development Fund, the NineCanyon 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, whichcollectively 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 acceptedin 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 whetherthe 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 selecteddepend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In makingthose risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the financial statements in order to designaudit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internalcontrol.
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 auditevidence we have obtained is sufficient and appropriate to provide a basis for our audit opinions.
OpinionsIn 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 MatterThe accompanying management's discussion and analysis listed in the table of contents are required by accounting principles generally accepted in theUnited States of America to supplement the basic financial statements.
Such information, although not a part of the basic financial statements, is required bythe Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in theappropriate 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 theinformation 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 limitedprocedures do not provide us with sufficient evidence to express an opinion or provide any assurance.
: Portland, OregonSeptember 26, 2013'AU Energy Northwest Management's Discussion and AnalysisEnergy Northwest is a municipal corporation and joint operating agencyof the state of Washington.
Each Energy Northwest business unit is financedand accounted for separately from all other current or future businessassets. The following discussion and analysis is organized by business unit.The management discussion and analysis of the financial performance andactivity is provided as an introduction and to aid in comparing the basicfinancial statements for the fiscal year (FY) ended June 30, 2013, with thebasic financial statements for the fiscal year ended June 30, 2012.Energy Northwest has adopted accounting policies and principles thatare in accordance with Generally Accepted Accounting Principles (GAAP) inthe United States of America.
Energy Northwest's records are maintained asprescribed 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 1to the Financial Statements.)
Because each business unit is financed and accounted for separately, thefollowing section on financial performance is discussed by business unit to aidin analysis of assessing the financial position of each individual business unit.For comparative purposes only, the table on the following page represents amemorandum total only for Energy Northwest, as a whole, for FY 2013 andFY 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 BalanceSheets; Statements of Revenues,
: Expenses, and Changes in Net Assets;and Statements of Cash Flows for each of the business units, and Notes toFinancial Statements.
The Balance Sheets present the financial position of each business uniton an accrual basis. The Balance Sheets report financial information aboutconstruction work in progress, the amount of resources and obligations, restricted accounts and due to/from balances for each business unit. (SeeNote 1 to the Financial Statements.)
The Statements of Revenues,
: Expenses, and Changes in Net Assets providefinancial information relating to all expenses, revenues and equity that reflectthe results of each business unit and its related activities over the courseof 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 andnet changes resulting from operating, financing and investing activities.
TheStatements of Cash Flows provide insight into what generates cash, wherethe 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 Debtand 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 notesto the financial statements and management discussion and analysis shouldbe used to provide an overview of Energy Northwest's financial performance.
Questions concerning any of the information provided in this report should beaddressed 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 ChangeAssetsCurrent Assets $ 209,345 S 199,122 $ (10,223)Restricted AssetsSpecial Funds 51,345 51,896 551Debt Service Funds 516,106 672,455 156,349Net Plant 1,525,642 1,499,711 (25,931)Nuclear Fuel 341,535 985,824 644,289Other Charges 3,658,124 3,258,111 (400,013)
TOTAL ASSETS $ 6,302,097
$ 6,667,119
$ 365,022Current Liabilities S 501,801 $ 621,867 $ 120,066Restricted Liabilities Special Funds 138,406 147,047 8,641Debt Service Funds 144,557 139,029 (5,528)Long-Term Debt 5,508,467 5,746,882 238,415Other Long-Term Liabitilies 15,776 18,115 2,339Other Credits 5,709 5,727 18Net Position (12,619)
(11,548)::
1,071TOTAL LIABILITIES AND NET POSITION
$ 6,302,097
$ 6,667,119
$ 365,022Operating Revenues
$ 425,695 $ 569,863 $ 144,168Operating Expenses 354,860 443,629 88,769Net Operating Revenues 70,835 126,234 55,399Other 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):
$ 1,0711 i No, 1,11we- , :1 A i ts I i, Re t Columbia Generating StationColumbia Generating Station (Columbia) is wholly owned by EnergyNorthwest and its participants and operated by Energy Northwest.
The plantis a 1,170-megawatt electric (MWe, Design Electric Rating, net) boiling waternuclear power plant located on the Department of Energy's (DOE) Hanford Sitenorth 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 economicdispatch of 51 and 140 GWh respectively.
Columbia entered its plannedrefueling outage (R-21) on May 11, 2013. The 40 day planned outage extendedan additional 5 days and ended June 25, 2013.The FY 2013 generation increaseof 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 reducedthe amount of power generated in FY 2012. Additionally, FY 2013 generation was approximately 6 GWh higher than budgeted, reflecting the continuous andsuccessful 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) ascompared with 4.73 cents per kWh in FY 2012. The industry cost of powerfluctuates year to year depending on various factors such as refueling outagesand other planned activities.
The FY 2013 cost of power decrease of 4.7percent was due to the successful cost control and generation run in FY 2013as compared to the generation and additional costs incurred during FY 2012due to the extended R-20 outage.Balance Sheet AnalysisThe 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.
Thechanges to plant and CWIP were comprised of additions to plant of $8.0 millionwith an increase to CWIP of $55.9 million.
Remaining changes was the periodeffect of depreciation of $82.0 million.
The accumulated decommissioning and site restoration accrued costs related to the Integrated Spent Fuel StorageInstallation (ISFSI) at Columbia were adjusted to reflect the change in the assetretirement obligation (ARO). Change in the ARO was necessary due to newNuclear Regulatory Commission requirements for fuel storage calculations.
PerASC 410, "Asset Retirement and Environmental Obligations,"
the obligation wasreevaluated and adjusted to reflect the change in timing due to the relicensing of Columbia through December 31, 2043 and to account for estimated costsrelated to fuel disposition obligations for the post five year period following the end of licensing and generation.
The revision resulted in an increase to thecapitalized 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 majorprojects of at least $0.7 million:
Fukushima
: impacts, Radio Obsolescence, CobaltReduction
: Program, Stack Monitor Performance, ServiceWater Pump and MotorOverhaul, On-Line Noble Chemical Application, Keep Fill Pump Replacement, Control Rod Device Refurbishment, Main Transformer Replacement, HighPressure Core Spray Refurbishment, Turbine Blade Procurement, Reactor FeedWater Overhaul, Condensate Pump Refurbishment, Residual Heat RemovalSystems, and Plant Telephone Obsolescence.
These projects resulted in 76NColumbia Generating StationNET GENERATION
-GWhrsColumbia Generating StationCOST OF POWER -Cents/kWh FY201FY201;FY2011FY 201C8,479 FY20136,984 FY20127,247 FY20118,124 FY20104.514.735.693.744.94FY7,725 FY 2009S 2,000 4,000 6,000 8,000 10,0000 1 2 3 40A Comniitrnent tu Lxci-hnc percent of the CWIP activity.
The remaining 24 percent were made up of 103separate projects.
Nuclear fuel, net of accumulated amortization, increased
$644.3 millionfrom FY 2012 to $985.8 million for FY 2013. The major factor contributing tothe increase in Nuclear Fuel relates to the completion of the Depleted UraniumEnrichment 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 forreload increased
$90.0 million with a decrease in net fuel of $37.8 million forcurrent year amortization.
Fuel removed for cooling increased
$55.3 millionand remaining change was $0.6 million for fuel loan and purchase activityrelating 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 (nuclearfuel cask inventory is $4.5 million and inventory is $5.7), increases to cashand investments of $7.2 million offset by a decrease in accounts and otherreceivables of $1.0 million.Special funds decreased
$20.4 million to $16.4 million in FY 2013 due tothe FY 2013 bond activity and schedule of construction costs for these fundsin 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 thesematurities.
Deferred charges increased
$59.8 million in FY 2013 from $835.0 millionto $894.8 million.
Components of this increase were changes in Costs inExcess of Billings related to the net effect of payment of current maturities andrefunding activity related to available debt of $58.1 million.
There was also aslight increase to unamortized debt expense of $1.7 million due to debt relatedactivity.
Current liabilities increased
$15.6 million in FY 2013 to $139.6 million.Components of the change were an increase to year end obligations relatingfrom 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 notespayable obligation related to the DUEP, an increase of $14.6 million for businessunit activity and a decreased requirement for participant amounts under the netbilling 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 anddecommissioning 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 $748.6million.
The current portion of Bonds Payable increased
$60.1 million, whichwas driven by timing of scheduled maturities.
Other long-term liabilities increased
$2.1 million in FY 2013 to $17.9 millionrelated to nuclear fuel cask activity.
Statement of Operations AnalysisColumbia is a net-billed project.
Energy Northwest recognizes revenuesequal to expenses for each period on net-billed projects.
No net revenue or lossis recognized and no net assets are accumulated.
Operating expenses increased
$87.5 million from FY 2012 costs of $331.4million to $418.9 million in FY 2013. The increases in costs were due to FY2013 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 inincreased fuel disposal costs of $8.5 million and increased generation taxesof SO.8 million.
Periodic expenses for depreciation and decommissioning increased
$8.4 million with the remainder of the increase
($0.9 million) a resultColumbia Generating StationTOTAL OPERATING COSTS(dollars in thousands)
FY2013Total ExpensesFY2012FY 2011FY2010FY2009of Administrative and General Expenses.
539,779 Other Income and Expenses increased
$54.2 million from FY 2012 to $1 20.7million 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 asan offset to other income and expense.
This is the major factor in the overallincrease in other income and expenses for FY 2013. Additionally, FY 2012 had522,1 56 $1.8 million in property disposal gains (condenser from R-20) that did not occurin FY 2013. The remaining major components of the increases were $2.0 million448,075 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 FY519,759 2012 to $539.7 million in FY 2013.The increase in costs (and conversely revenueper net billing) of $141.8 million was due to the increased costs incurred in the500,000 completion of R-21. R-21 was originally budgeted for $87.0 million and 40Expenses 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-21.0 100,000 200,000 300,000 400,0000 Operating ExpensesM Other Income II Packwood Lake HydroeLectric ProjectThe Packwood Lake Hydroelectric Project (Packwood) is wholly owned and operated by Energy Northwest.
Packwood consists of a diversion structure at PackwoodLake 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 anddrops 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 perkWh 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 FY2013 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 ProjectCOST OF POWER -Cents/kWh FYBalance Sheet AnalysisTotal assets decreased
$0.1 million from FY 2012, with the drivers beingan 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 totalliabilities of $0.1 million was the decrease in due to participants for the results ofoperations.
Packwood has incurred
$3.7 million in relicensing costs through FY2012 with no new costs incurred for FY 2013. These costs are shown as Deferred2.07 Charges on the Balance Sheet. Packwood has been operating under a 50-yearlicense issued by the Federal Energy Regulatory Commission (FERC), which1.58 expired on February 28, 2010. Energy Northwest submitted the Final LicenseApplication (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 under1.59 the original license which is indefinitely extended for continued operations untilformal decision is issued by FERC and a new operating license is granted.
Asof June 30, 2013, Packwood continues to be relicensed under this extended1.82agreement.
1.62FY 201FY2011FY2010FY20090.0 0.5 1.0 1.5 2.0 2.5Packwood Lake Hydroelectric ProjectNET GENERATION
-GWhrsPackwood Lake Hydroelectric ProjectTOTAL OPERATING COSTS(dollars in thousands)
Total ExpensesFY2013FY2012FY 2011FY 2010FY2009103.74119.43107.9286.0799.34FY2013FY2012FY2011FY2010FY 20092,1661,8721,7421,5351,6410 20 40 60 80 100 1200500 1,000 1,500 2,000 2,5*00U Operating ExpensesM Other Income / ExpensesM A C~ormmiment to Exce~lence Statement of Operations AnalysisThe agreement with Packwood participants obligates them to pay annualcosts and to receive excess revenues.
(See Note 1 to the Financial Statements.)
Accordingly, Energy Northwest recognizes revenues equal to expenses for eachperiod. 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 forthe 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 2012to an $8,000 gain in FY 2013.The
$4,000 increase in net gain is primarily due toa 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.
ThePackwood participants also share project revenue to the extent that the amountsexceed costs. These funds can be returned to the participants or kept within theproject.
As of June 30, 2013 there is $5.7 million recorded as deferred revenues inexcess of costs that are being kept within the project.
Packwood participants arecurrently taking 100 percent of the project generation; there are no additional agreements for power sales.Nuclear Project No. 1Energy Northwest wholly owns Nuclear Project No. 1, a 1,250-MWe plant,which was placed in extended construction delay status in 1982, when itwas 65 percent complete.
On May 13, 1994, Energy Northwest's Board ofDirectors adopted a resolution terminating Nuclear Project No. 1. All fundingrequirements 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 AnalysisLong-term debt decreased
$289.7 million from $1.4 billion in FY 2012to $1.1 billion in FY 2013 as a result of $273.1 million being transferred tocurrent debt to be paid on July 1, 2013 along with a decrease in bond relatedamortization of $16.6 million.
Short term debt increased
$37.0 million perthe debt maturity schedule.
There was a decrease to restricted liabilities of$7.0 million, represented by a decrease to interest payable of $8.8 millionoffset by an increase to the decommissioning estimate of $1.8 million.Statement of Operations AnalysisOther Income and Expenses showed a net decrease to expenses of $20.0million 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 increaseof $0.2 million in plant preservation costs.Nuctear Project No. 3Nuclear Project No. 3, a 1,240-MWe plant, was placed in extendedconstruction delay status in 1983, when it was 75 percent complete.
OnMay 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 theSatsop Redevelopment Project.
The debt service related activities remain theresponsibility of Energy Northwest and are net-billed.
(See Note 13 to theFinancial Statements.)
Balance Sheet AnalysisLong-term debt decreased
$174.4 million from $1.5 billion in FY 2012to $1.3 billion in FY 2013, as a result of $166.2 million being transferred tocurrent debt to be paid on July 1, 2013 along with a decrease in bond relatedamortization of $8.2 million.
Current debt per the debt maturity scheduleincreased
$70.6 million from $95.5 million in FY 2012 to $166.2 million inFY 2013. The remaining changes in liabilities of $6.6 million were due toincreased payable transfers from bond related activities.
Statement of Operations AnalysisOverall expenses decreased
$9.9 million from FY 2012 related to bondactivity with investment income and liquidation costs steady with previousyear levels.Enerily Northwest 201 3 Annual Report Business Development FundEnergy Northwest was created to enable Washington public power utilities and municipalities to build and operate generation projects.
The BusinessDevelopment 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 fromengaging in new energy business opportunities.
The BDF is managed as an enterprise fund. Four business lines havebeen created within the fund: General Services and Facilities, Generation,
.Professional
: Services, and Business Unit Support.
Each line may have one ormore programs that are managed as a unique business activity.
Batance Sheet AnatysisTotal assets increased
$1.0 million from $9.1 million in FY 2012 to $10.1million in FY 2013. Increases were due to cash and investments of $1.1million, net plant of $0.2 million, and decreases to receivables and prepaidamounts of $0.3 million.
Liabilities decreased
$0.4 million from FY 2012 dueto timing of year end outstanding items.Statement of Operations AnatysisOperating Revenues in FY 2013 totaled $9.0 million as compared to FY2012 revenues of $9.8 million, a decrease of $0.8 million.
The decrease inrevenues was driven by four major projects:
Grays Harbor project, which wasa 50 MW power call option that ended in June 2013 at the 600 MW SatsopNatural Gas Combined-Cycle plant as part of a compensation package forselling development rights to Duke Energy in 2001 ($0.3 million),
termination of the Kalama project in FY 2013, which was a proposed development ofa 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, anddecreased lease activity
($0.3 million).
The decreases in the four projectsmentioned above were offset by increased revenues for technical services andengineering services of $0.6 million.
Operating costs decreased
$0.9 milliondue 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 innet revenues in FY 2012 to net revenue of $1.3 million in FY 2013; there wasan adjustment of $0.1 million for completion of the power option derivative contract for the Grays Harbor project, and a decrease of other income andexpenses of $0.1 million, with no significant individual items.The Business Development Fund receives contributions from the InternalService Fund to cover cash needs during startup periods.
Initial startup costsare not expected to be paid back and are shown as contributions.
As anoperating business unit, requests can be made to fund incurred operating expenses.
In FY 2013 there were no contributions (transfers),
which was alsothe case for FY 2012.M A Commnitme~nt to F xcetlec Nine Canyon Wind ProjectThe Nine Canyon Wind Project (Nine Canyon) is wholly owned andoperated by Energy Northwest.
Nine Canyon is located in the HorseHeaven 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 havesigned a power purchase agreement which are part of the 2nd Amendedand Restated Nine Canyon Wind Project Power Purchase Agreement which now has an end date of 2030. Nine Canyon is connected to theBonneville Power Administration transmission grid via a substation andtransmission lines constructed by Benton County Public Utility District.
Phase I of Nine Canyon, which began commercial operation inSeptember 2002, consists of 37 wind turbines, each with a maximumgenerating capacity of approximately 1.3 MW, for an aggregate generating capacity of 48.1 MW. Phase II of Nine Canyon, which was declaredoperational in December 2003, includes 12 wind turbines, each with amaximum generating capacity of 1.3 MW, for an aggregate generating capacity of approximately 15.6 MW. Phase III of Nine Canyon, which wasdeclared operational in May 2008, includes 14 wind turbines, each witha maximum generating capacity of 2.3 MW, for an aggregate generating capacity of 32.2 MW. The total Nine Canyon generating capability is 95.9MW, enough energy for approximately 39,000 average homes.Nine Canyon produced 228.23 GWh of electricity in FY 2013 versus261.63 GWh in FY 2012. The decrease of 12.8 percent was due to slightlyless favorable wind conditions in FY 2013 as compared to FY 2012. Theaverage wind speed for the months of January and June were significantly below the 10 year average.
The below average wind conditions combinedwith FY 2012 being the second highest generation year for history of theproject were the drivers for the decrease between years.Nine Canyon's cost performance is measured by the cost of powerindicator.
The cost of power for FY 2013 was $7.91 cents per kWh ascompared to $6.69 cents per kWh in FY 2012. The cost of powerfluctuates year to year depending on various factors such as windNine Canyon Wind ProjectNET GENERATION
-GWhtotals and unplanned maintenance.
The FY 2013 cost of power increaseof 18.2 percent was a result of the decreased generation due to windconditions and higher maintenance costs incurred due to turbine bearingmaintenance.
Balance Sheet AnalysisTotal 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 adecrease of $6.8 million in net plant due to accumulated depreciation.
Theremaining changes consisted of increases to restricted assets of $2.4 millionand 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 overalldecrease 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 toaccrued debt related interest of $0.1 million, and increases to accrued costsand business activities of $0.1 million.
The increase in net assets was $0.2million in FY 2013 as compared to a decrease of $1.3 million in FY 2012. Theslight reversal in net assets reflects the rate stabilization approach for NineCanyon 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 asit applies to the REPI legislation.
REPI was created to promote increases inthe generation and utilization of electricity from renewable energy sourcesand to further the advances of renewable energy technologies.
This program,authorized under Section 1212 of the Energy Policy Act of 1992, providesfinancial incentive payments for electricity produced and sold by newqualifying renewable energy generation facilities.
The payment stream fromNine Canyon participants and the REPI receipts were projected to cover thetotal costs over the purchase agreement.
Continued shortfalls in REPI fundingfor the Nine Canyon project led to a revised rate plan to incorporate theimpact of this shortfall over the life of the project.
The billing rates for theNine Canyon Wind ProjectCOST OF POWER -Cents/kWh FY2013FY2012FY 2011FY 2010FY 2009228.23 FY2013261.63 FY2012264.74 FY20117.916.696.567.887.79226.73 FY201226.27 FY20C0 50 100 150 200 250 300IEl Nine Canyon participants increased 69 percent and 80 percent for Phase I andPhase II participants respectively in FY 2008 in order to cover total projectcosts, projected out to the 2030 proposed project end date. The increases forFY 2008 were a change from the previous plan where a 3 percent increase eachyear over the life of the project was projected.
Going forward, the increase ordecrease in rates will be based on cash requirements of debt repayment andthe cost of operations.
Phase III started with an initial planning rate of $49.82per MWh which increased at 3 percent per year for three years. In year six (FY2013) the rate increased to a rate that will be stabilized over the life of theproject.
Possible adjustments may be necessary to future rates depending onoperating costs and REPI funding, similar to Phase I and II.Statement of Operations AnalysisOperating revenues increased
$2.8 million from $16.2 million in FY2012 to $19.0 million in FY 2013. The project received revenue from thebilling of the purchasers at an average rate of $80.06 per MWh for FY2013 as compared to $61.98 per MWh for FY 2012 which is reflective ofthe implementation of the revised rate plan in FY 2008 to account for REPIfunding shortfalls and costs of operations.
The increased operating revenuesfrom the previous year were due to increased funding requirements for PhaseIll purchasers.
The increase in the average rate billed to purchasers was alsoimpacted 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 inFY 2013. Increased operating costs of $1.8 million for FY 2013 were due toNine Canyon Wind ProjectTOTAL OPERATING COSTS(Dollars in thousands)
Total EFY2013FY 2012FY2011FY2010FY 2009maintenance work related to turbine bearing replacements.
Other income and expenses decreased
$0.5 million from $6.2 million innet expenses FY 2012 to $5.7 million in FY 2013. Decreased interest costsof $0.4 million and decreases in amortized bond expenses of $0.1 millionaccounted for the change. Net gain or change in net assets of $0.2 million forxpenses FY 2013 was a direct result of the planned average rate increase with lowerthan budgeted operating costs.18,805 The original plan anticipated operating at a loss in the early years andgradually increasing the rate charged to the purchasers to avoid a large rate17,467 increase after the REPI expires.
The REPI incentive expires 10 years from theinitial 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 account17,466 for the shortfall experienced in the REPI funding and to provide a new ratescenario out to the 2030 project end date. Energy Northwest did not receive16,506 REPI funding in FY 2013 and is not anticipating receiving any future REPIincentives.
The results from FY 2013 reflect the revised rate plan scenario andgradual increase in the return of total net assets.17,6320 3,000 6,000 9,000 12,000 15,000M Operating ExpensesU Other Income I Expenses0 A Commitment to Excetlence InternaL Service FundThe Internal Service Fund (ISF) (formerly the General Fund) was established in May 1957. The ISF provides services to the other funds. This fund accountsfor the central procurement of certain common goods and services for thebusiness units on a cost reimbursement basis. (See Note 1 to Financial Statements.)
Batance Sheet AnalysisTotal assets increased
$9.1 million from $46.6 million in FY 2012 to $55.7million 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 toreflect FY 2013 recognition of year-end check redemption related to R-21versus the requirements of FY 2012 which was a non-outage year, 3) anincrease of $1.6 million in restricted assets due to the debt maturity scheduleand escrow requirements processing
: schedule,
: 4) an increase to prepaidamounts of $0.4 million, and an increase to due from other business unitsof $14.8 million.The net increase in net assets and liabilities is due to increases in accountspayable and payroll related liabilities of $9.4 million due to year-end timingof expenses for FY 2013, which was an outage year and a decrease of $15.0million due to other business units resulting from the change in year-endactivities.
Statement of Operations AnalysisNet revenues for FY 2013 increased
$112,000 from FY 2012. The increasewas 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 RaEnergy Northwest (Long-Term)
Fitch, Inc.Moodys Investors
: Service, Inc. (Moodys)Standard and Poor's Ratings Services (S & P)tings (Unaudited)
Nine Canyon RatingNet-Billed RatingPhase I & IIPhase IIIAAAalAA-A-A-A2A-A2Antcy Noi thwest 2013 Animalc Repot t Statement Of Net Position As of June 30, 2013 (Dollars in thousands)
Columbia Packwood LakeGenerating Hydroelectric Nuclear NuclearProject ProjectBusiness Nine CanyonDevelopment WindInternalServiceCombinedStation Project Number 1 Number 3* Fund Project Subtotal Fund TotalASSETSCURRENT ASSETSCash $ 33,154 $ 373 $ 606 S 667 $ 5,223 * $ 8,624 $ 48,647 $ -$ 48,647Available-for-sale 10,000 1,023 2,512 2,669 2,542 1,049 19,795 5,065 24,860investments Accounts and other receivables 263 111 3 3 466 144 990 84 1,074Due from other business units -10 270 343 623 16,638Materials and supplies 121,404 ---121,404 -121,404Prepayments and other 1,409 12 --140 76 1,637 1,500 3,137TOTAL CURRENT ASSETS 166,230 1,529 3,391 3,339 8,714 9,893 193,096 23,287 199,122RESTRICTED ASSETS (NOTE 1)Special fundsCash 9,907 -298 699 4 10,908 406 11,314Available-for-sale 6,518 -3,000 7,257 -1,558 18,333 22,227 40,560investments Accounts and other 22 --22 22receivables Debt service fundsCash 125,970 98,267 57,632 9,959 291,828 291,828Available-for-sale 21,482 207,975 139,799 11,364 380,620 380,620investments Accounts and other 3 --3 1 7 7receivables TOTAL RESTRICTED ASSETS 163,902 -309,540 205,390 -22,886 701,718 22,633 724,351NON CURRENT ASSETSUTILITY 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 29,415Construction work in progress 116,483 ----116,483 116,483Accumulated 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 -985,824lated depreciation LONG TERM RECEIVABLES
--" " ----TOTAL NONCURRENTASSETS 2,392,405 1,625 " -1,393 80,344 2,475,767 9,768 2,485,535 OTHER CHARGESCost 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 -22,415Other -3,737 ---3,737 -3,737TOTAL 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 basisThe 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)
ColumbiaGenerating Packwood LakeHydroelectric NuclearProjectNuclearProjectBusinessDevelopment Nine CanyonWindInternalServiceCombinedStation Project Number 1
* Number 3* Fund Project Subtotal Fund TotalLIABILITIES AND NET ASSETSCURRENT LIABILITIES Current maturities of long-term
$ 61,020 $ -$ 273,055 S 166,160 $ -$ 6,835 $ 507,070 S -$ 507,070debtAccounts payable and accrued 36,973 196 183 43 995 486 38,876 49,994 88,870expensesDue to participants 24,959 968 ---25,927 -25,927Due to other business units 16,618 --10 -10 16,638 623TOTAL CURRENT LIABILITIES 139,570 1,164 273,238 166,213 995 7,331 588,511 50,617 621,867LIABILITIES-PAYABLE FROMRESTRICTED ASSETS (NOTE 1)Special fundsAccounts payable and 127,163 18,244 -1,287 146,694 353 147,047accrued expensesDebt service fundsAccrued interest payable 71,522 -33,186 31,259 -3,062 139,029 139,029TOTAL RESTRICTED LIABILITIES:
198,685 -51,430 31,259 -4,349 285,723 353 286,076LONG-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 4,138 190,935 190,935premium on bonds -netUnamortized 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 18,115LIABILITIES OTHER CREDITSAdvances from members -5,727 --5,727 -5,727and othersOther ---TOTAL OTHER CREDITS -5,727 ----5,727 -5,727NET POSITIONInvested in capital assets, net -1,393 (53,110)
(51,717) 9,766 (41,951)of related debtRestricted, net -17,559 17,559 22,633 40,192Unrestricted, 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 basisThe accompanying notes are an integral part of these combined financial statements 0
Statements Of Revenues,
: Expenses, And Changes In Net PositionAs Of June 30, 2013 (Dottars in thousands)
Business Nine CanyonColumbia PackwoodGenerating LakeStation ProjectNuclear NuclearProject ProjectNo.1* No.3*Development FundWindProject SubtotalInternal 2013Service CombinedFund TotalOPERATING REVENUESOPERATING EXPENSESServices to other business unitsNuclear fuelSpent fuel disposal feeDecommissioning Depreciation and amortization Operations and maintenance Administrative
& generalGeneration tax$ 539,667 $ 2,173 $42,4338,0596,30683,967 57246,376 1,93827,775 164-S <$ 9,024 $18,999 ]$ 569,863 $$ 569,8632409,167846,8146,121344942,4338,0596,39091,078263,60227,973 -4,094 -42,4338,0596,39091,078263,60227,9734,0944,02322Iotal operating expenses 418,939 2, 9I, 13,,U/ 44I3 U6 44,436 -9OPERATING INCOME (LOSS) 120,728 (8): (383)! 5,897 126,234 126,234OTHER INCOME & EXPENSEOther 4,785 3 55,032 55,906 1,308 12 117,046 82,214 116,978Investment income 645 5 68 50 20 61 849 11 849Interest 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 unitsTOTAL 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 1,071TOTAL 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 basisThe 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)
PackwoodColumbia Lake Nuclear Nuclear Business Nine Canyon Internal 2013Generating Hydroelectric Project Project Development Wind Service CombinedStation Project No.1 No.3
* Fund Project Fund TotalCASH FLOWS FROM OPERATING AND NON-OPERATING ACTIVITIES Operating revenue receipts
$ 478,335 $ 2,011 $ -$ -$ 5,074 $ 19,002 $ $ 504,422Cash payments for operating expenses (275,172)
(2,033) -(1,159) (6,069) (284,433)
Non-operating revenue receipts 112 338,733 228,232 (67) --567,010Cash 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):
782,251and nonoperating activities CASH FLOWS FROM CAPITALAND RELATED FINANCING ACTIVITIES Proceeds from bond refundings 785,282 ----785,282Payment 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 24,640 935,419Interest on investments
.1,794 41 34 , 31 .62 230 (622) 1,570Net cash providedl(used) by investing activities 24,419 (30) (19,956)
(112,741)
(463) 6,683 (11,472)
(103,560)
NET INCREASE(DECREASE)
IN CASH68,215(822)i 6,713 (45,366)3,0518,861(5,664),
34,988CASH AT JUNE 30, 2012 100,817 1,195 92,458 104,363 2,172 9,726 6,070 316,801CASH AT JUNE 30, 2013 (NOTE B) $ 169,032 $ 373 $ 99,171 $ 58,997 $ 5,223 $ 18,587 $ 406 $ 351,789Project recorded on a liquidation basisThe 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)
PackwoodColumbia i LakeGenerating Hydroelectric Station ProjectNuclearProjectNo.1 *Nuclear Business Nine CanyonProject Development WindNo.3
* Fund ProjectInternal 2013Service CombinedFund TotalRECONCILIATION OF NET OPERATING REVENUES TO NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES Net operating revenues
$ 120,728 $ () $ .$--------------Adjustments to reconcile net operating revenuesto cash provided by operating activities:
-Depreciation and amortization 124,410 48Decommissioning 6,306Other (2,041):
770Change in operating assets and liabilities:
Deferred charges/costs in excess of billings (61,332)'
(48),Accounts receivable 980 11 1Materials and supplies (10 201):Prepaid and other assets (98)1 62Due from/to other business units, funds 14,874 (915)and Participants Accounts payable 9,537 58Non-operating revenue receipts 112 338,733Cash payments for preservation, termination expense --- -(534)Cash payments for services$(383) : $ 5,897 :$$ 126,234157 6,793331,458 37(51) (9):131,4086,339224(61,380)931(10,201)2,73814,0359,594567,077(556)2,57220276(96):95228,232(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)::
$ 782,251and nonoperating activities
_ ________* Project recorded on a liquidation basisThe 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 PoliciesEnergy Northwest, a municipal corporation and joint operating agency ofthe 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.
Allmembers own and operate electric systems within the state of Washington.
Energy Northwest is exempt from federal income tax and has no taxingauthority.
Energy Northwest maintains seven business units. Each unit is financedand accounted for separately from all other current or future business units.All electrical energy produced by Energy Northwest's net-billed businessunits is ultimately delivered to electrical distribution facilities owned andoperated by Bonneville Power Administration (BPA) as part of the FederalColumbia River Power System. BPA in turn distributes the electricity toelectric utility systems throughout the Northwest, including participants inEnergy Northwest's business units, for ultimate distribution to consumers.
Participants in Energy Northwest's net-billed business units consist of publicutilities and rural electric cooperatives located in the western United Stateswho have entered into net-billing agreements with Energy Northwest andBPA 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 recoverthe 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 requiredto operate Columbia.
Columbia was issued a standard 40-year operating license by the Nuclear Regulatory Commission (NRC) in 1983. On January19, 2010 Energy Northwest submitted an application to the NRC to renewthe 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. Packwoodhas been operating under a 50-year license issued by the Federal EnergyRegulatory Commission (FERC), which expired on February 28, 2010. EnergyNorthwest submitted the Final License Application (FLA) for renewal of theoperating license to FERC on February 22, 2008. On March 4, 2010, FERCissued a one-year extension, or until the issuance of a new license for theproject or other disposition under the Federal Power Act, whichever comesfirst. FERC is awaiting issuance of the National Oceanic and Atmospheric Administration's (NOAA) Biological
: Opinion, after which FERC will completethe final license renewal documentation for Packwood.
Costs incurred todate 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 areobligated to pay annual costs of Packwood including debt service, whetheror 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 extendedconstruction delay status in 1982, when it was 65 percent complete.
NuclearProject 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 ownsNuclear Project No. 1. Energy Northwest is no longer responsible for siterestoration costs for Nuclear Project No. 3 (See Note 13).The Business Development Fund was established in April 1997 to pursueand develop new energy related business opportunities.
There are fourmain business lines associated with this business unit: General Services andFacilities, Generation, Professional
: Services, and Business Unit Support.The Nine Canyon Wind Project (Nine Canyon) was established in January2001 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 turbinesto Nine Canyon and adding an aggregate capacity of 32.2 MWe. The totalnumber 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 usedto account for the central procurement of certain common goods and servicesfor the business units on a cost reimbursement basis.Energy Northwest's fiscal year begins on July 1 and ends on June 30. Inpreparing these financial statements, the company has evaluated events andtransactions 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 ofEnergy Northwest conform to Generally Accepted Accounting Principles (GAAP) applicable to governmental units. The Governmental Accounting Standards Board (GASB) is the accepted standard-setting body forestablishing 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 GASBpronouncements.
The accounting and reporting policies of EnergyNorthwest are regulated by the Washington State Auditor's Office andare based on the Uniform System of Accounts prescribed for publicutilities and licensees by FERC. Energy Northwest uses the full accrualbasis of accounting where revenues are recognized when earned andexpenses are recognized when incurred.
Revenues and expenses relatedto 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 andexpenses.
Separate funds and books of accounts are maintained for eachbusiness unit. Payment of the obligations of one business unit with fundsof another business unit is prohibited, and would constitute violation ofbond 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 InternalService Fund are also owned by this Fund and operated for the benefitof other projects.
Depreciation relating to capital assets is charged to theappropriate 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 whichhave been charged directly or indirectly to business units and will befunded 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 businessunits on the Internal Service Fund Balance Sheet.The combined total column on the financial statements is forpresentation (unaudited) only as each Energy Northwest business unitis financed and accounted for separately from all other current andfuture 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 andAnalysis for State and Local Governments."
Pursuant to GASB Statement No. 20, "Accounting and Financial Reporting for Proprietary Funds and Other Governmental Entities ThatUse Proprietary Fund Accounting,"
Energy Northwest has elected toapply 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 andFinancial 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 guidancegoverns 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 andNet Position."
Statement No. 63 amends the current net assets reporting requirements by incorporating deferred inflows of resources and deferredoutflows 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. EnergyNorthwest's financial statements have been modified to conform to therequirements of this statement.
Implementation did not have a materialimpact 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 itemspreviously reported as assets and liabilities as deferred outflows ordeferred inflows of resources, or as outflows or inflows of resources.
Thisstatement 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 thatits impact will be material.
In June 2012, GASB issued Statement No. 68, "Accounting andFinancial 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.
Thisstatement establishes standards for measuring and recognizing liabilities, deferred outflows and deferred inflows of resources and expenses.
Fordefined benefit pension plans, this statement identifies the methodsand assumptions to project benefit payments, discount projected benefitpayments to their actuarial present value and attribute present value toperiods of employee service.
Note disclosure and required supplementary information about pensions are also addressed.
Statement No. 68 iseffective for Energy Northwest beginning in fiscal year 2015. EnergyNorthwest is currently evaluating the financial statement impact ofadopting this statement.
b) Utility Plant and Depreciation:
Utility plant is recorded at originalcost which includes both direct costs of construction or acquisition andindirect costs.Property, plant, and equipment are depreciated using the straight-line method over the following estimated useful lives:Buildings and Improvements Generation PlantTransportation Equipment General Plant and Equipment 20- 60 years40 years6- 9 years3 -15 yearsGroup rates are used for assets and, accordingly, no gain or lossis recorded on the disposition of an asset unless it represents a majorretirement.
When operating plant assets are retired, their original costtogether with removal costs, less salvage, is charged to accumulated depreciation.
The utility plant and net assets of Nuclear Projects Nos. 1 and 3 havebeen reduced to their estimated net realizable values due to termination.
A write-down of Nuclear Projects Nos. 1 and 3 was recorded in FY 1995and included in Cost in Excess of Billings.
Interest
: expense, termination expenses and asset disposition costs for Nuclear Projects Nos. 1 and 3have been charged to operations (see Note 15).c) Capitalized Interest:
Energy Northwest analyzes the gross interestexpense relating to the cost of the bond sale, taking into account interestearnings and draws for purchase or construction reimbursements for thepurpose of analyzing impact to the recording of capitalized interest.
Ifestimated costs are more than inconsequential, an adjustment is made toallocate capitalized interest to the appropriate plant account.
Capitalized interest costs were $1.6 million.d) Nuclear Fuel: Energy Northwest has various agreements for uraniumconcentrates, conversion, and enrichment to provide for short-term enriched uranium product and long-term enrichment services.
Allexpenditures 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 ASC410, "Asset Retirement and Environmental Obligations."
This standardrequires Energy Northwest to recognize the fair value of a liability associated with the retirement of a long-lived asset, such as: ColumbiaGenerating
: Station, Nuclear Project No. 1, and Nine Canyon, in theperiod 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 Columbiaand monies are being deposited each year in accordance with anestablished 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 themeasurement, recognition and disclosure of derivative instrument transactions for the purpose of enhancing the usefulness andcomparability of derivative instrument information reported by state andlocal governments (see Note 14).h) Restricted Assets: In accordance with bond resolutions, relatedagreements and laws, separate restricted accounts have beenestablished.
These assets are restricted for specific uses including debtservice, 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 assetsas appropriate.
i) Cash and Investments:
For purposes of the Statements of CashFlows, cash includes unrestricted and restricted cash balances and eachbusiness unit maintains its cash and investments.
Short-term highlyliquid investments are not considered to be cash equivalents, but areclassified as available-for-sale investments and are stated at fair valuewith unrealized gains and losses reported in investment income (seeNote 3). Energy Northwest resolutions and investment policies limitinvestment 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 thebenefit of the individual Energy Northwest business units.j) Accounts Receivable:
The percentage of sales method is used toestimate uncollectible accounts.
The reserve is then reviewed foradequacy against an aging schedule of accounts receivable.
Accountsdeemed uncollectible are transferred to the provision for uncollectible accounts on a yearly basis. Accounts receivable specific to each businessunit are recorded in the residing business unit.k) Other Receivables:
Other receivables include amounts related to theInternal Service Fund from miscellaneous outstanding receivables fromother business units which have not yet been collected.
The amountsdue to each business unit are reflected in Due To/From other businessunits. Other receivables specific to each business unit are recorded in theresiding business unit.1) Materials and Supplies:
Materials and supplies are valued at costusing the weighted average cost method.n) Long-Term Liabilities:
Consist of obligations related to bondspayable and the associated premiums/discounts and gains/losses.
Othernoncurrent 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 areamortized over the terms of the respective bond issues using the bondsoutstanding 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 acomponent of interest expense over the shorter of the remaining life ofthe old or new debt.p) Revenue Recognition:
Energy Northwest accounts for expenses onan accrual basis, and recovers, through various agreements, actual cashrequirements 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.
Suchamounts will be settled during future operating periods (see Note 6).Energy Northwest accounts for revenues and expenses on an accrualbasis for the remaining business units.The difference between cumulative revenues and cumulative expenses is recognized as net revenue or lossand 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 asit applies to the REPI bill. REPI was created as part of the Energy PolicyAct of 1992 to promote increases in the generation and utilization ofelectricity from renewable energy sources and to further the advances ofrenewable energy technologies.
This program, authorized under section 1212 of the Energy Policy Actof 1992, provides financial incentive payments for electricity producedand sold by new qualifying renewable energy generation facilities.
NineCanyon did not record a receivable for FY 2013 REPI funding as nofunds are anticipated to be disbursed to Energy Northwest under thisprogram.
The payment stream from Nine Canyon participants and theanticipated REPI funding were projected to cover the total costs of thepurchase agreement.
Permanent shortfalls in REPI funding for the NineCanyon project led to a revised rate plan to incorporate the impact ofthis shortfall over the life of the project.
The current rate schedule for theNine Canyon participants covers total estimated project costs occurring in FY 2013 and estimated total cost recovery projections out to the 2030proposed end date. During FY 2013 there was no cost recovery obtainedfrom REPI.m) Leases: Consist of separate operating lease agreements.
The total ofthese leases by business unit and their respective amounts paid per yearare listed in the table on the next page.Enot oly >Fui thwtet 2101 2` Aimun Rei eport Projects Operating Lease Costs (Dottars in thousands) 2014201512016201720182019+Columbia
$ 723 $ 723 $ 723 $ 723 $ 723 $ 18,082Nuclear Project No. 1 35 35 35 .35 35 210Nine Canyon 684 684 684 684~ 684 8,209Business Development Fund 169 169 169 169 169 226Internal Service Fund 147 147 147 147 147 1,655Packwood Lake Project 81 81 81 81 81 81Total 1,839 $ 1,839 $ 1,839 $ 1,839 $ 1,839 1 $ 28,463Long-Term Liabilities (Dotlars in thousands)
Balance 6/30/2012 INCREASES DECREASES Balance 6/30/2013 ColumbiaRevenue bonds payable $Unamortized (discount)/premium on bonds -netUnamortized gain/(loss) on bond refundings Other noncurrent liabilities 2,441,385
$120,221(9,966)::
15,776782,655 $2,6323,3712,14261,020 $17,26258043,163,020 105,591(7,175)17,914$2,567,416
$790,800 $78,866 $3,279,350 Nuclear Project No.1Revenue bonds payableUnamortized (discount)/premium on bonds -netUnamortized gain/(loss) on bond refundings
$1,321,060
$56,290(3,614)::
-S$303,905273,055 $20,0694611,048,005 36,251(170)$1,373,736
$3,935 $293,585 $1,084,086 Nuclear Project No.3Revenue bonds payableUnamortized (discount)/premium on bonds -netUnamortized gain/(Iloss) on bond refundings 1,395,405
$53,241(974):8,403913166,160 $16,6898231,229,245 44,955(884)$1,447,672 4 $9,316 i $183,672 : $1,273,316 Nine CanyonRevenue bonds payableUnamortized (discount)/premium on bonds -netUnamortized gain/(Iloss) on bond refundings 130,955$4,743(279)::6,835$60522124,1204,138(214)88$135,419 : $88 $7,462 $128,044fl A Commitment to Exce[Lence r) Compensated Absences:
Employees earn leave in accordance withlength of service.
Energy Northwest accrues the cost of personal leave inthe year when earned. The liability for unpaid leave benefits and relatedpayroll taxes was $20.8 million at June 30, 2013 and is recorded as acurrent liability.
Note 2 -UtiLity PLantUtility 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 makeestimates and assumptions that directly affect the reported amountsof assets and liabilities, disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts ofrevenue and expenses during the reporting period. Actual results coulddiffer from these estimates.
Certain incurred expenses and revenues areallocated to the business units based on specific allocation methods thatmanagement considers to be reasonable.
Balance 6/30/2012 Capital Acquisitions Sale or Other Dispositions Balance 6/30/2013 ColumbiaGeneration
$ 3,791,326
$ 7,482 $ (41): $ 3,798,767 Decommissioning 14,256 512 14,768Construction Work-in-Progress 60,553 282,452 (226,522) 116,483Accumulated 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 PackwoodGeneration
$ 13,625 $ 812 $ .$ 14,437Construction Work-in-Progress 812 (812):Accumulated Depreciation (12,764):
(48): (12,812)Utility Plant, net $ 861 $ 1,576 $ (812)i $ 1,625Business Development General $ 2,174 $ 369.$ -$ 2,543Construction Work-in-Progress 369 (369);Accumulated Depreciation (993), (157)- (1,150)Utility Plant, net $ 1,181 $ 581 $ (369); $ 1,393Nine CanyonGeneration
$ 133,6451$
37 $ (32): $ 133,649Decommissioning 861 861Construction 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 $ 80,345Internal Service FundGeneral $ 48,410 $ 59 $ (500) $ 47,969Construction Work-in-Progress
-59 (59)Accumulated Depreciation (36,594)
(2,109) 500 (38,203)Utility Plant, net $ 11,816 $ (1,990).
$ (59) $ 9,766U Note 3 -Available-for-Sale Investments (Dollars in thousands)
Amortized CostUnrealized GainsUnrealized LossesFair Value (1) (2)ColumbiaPackwoodNuclear Project No. 1Nuclear Project No. 3Business Development FundInternal Service FundNine Canyon$37,986 $1,023213,488149,7252,54027,20213,97114 $$38,0001,023213,488149,7252,54027,20313,97152(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, EnergyNorthwest 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 todebt securities and obligations of the U.S. Treasury U.S. government agenciesFederal 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), andgeneral obligation debt of state and local governments and public authorities recognized with one of the three highest credit ratings (AAA, AA+, AA, orequivalent).
This investment policy is more restrictive than the state law.Concentration of Credit Risk: Energy Northwest's investment policy doesnot 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 theevent of bank failure, Energy Northwest's deposits may not be returned to it.Energy Northwest's interest bearing accounts and certificates of deposits arecovered up to $250,000 by Federal Depository Insurance (FDIC) while non-interest bearing deposits are entirely covered by FDIC and if necessary, all interest andnon-interest bearing deposits are covered by collateral held in a multiple financial institution collateral pool administered by the Washington state Treasurer's LocalGovernment Investment Pool (PDPC). Under state law, public depositories underthe 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 withinstitutions 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. Othercredits of $0.1 million for Nine Canyon consist of turbine elevator purchases to becompleted in FY 2014.Note 5 -Long-Term DebtEach Energy Northwest business unit is financed separately.
The resolutions ofEnergy Northwest authorizing issuance of revenue bonds for each business unitprovide that such bonds are payable from the revenues of that business unit. Allbonds issued under resolutions Nos. 769, 775 and 640 for Nuclear Projects Nos.1, 3 and Columbia, respectively, have the same priority of payment within thebusiness unit (the "prior lien bonds").
All bonds issued under resolutions Nos.835, 838 and 1042 (the "electric revenue bonds") for Nuclear Projects Nos. 1, 3and Columbia, respectively, are subordinate to the prior lien bonds and have thesame subordinated priority of payment within the business unit. Nine Canyon'sbonds were authorized by the following resolutions:
Resolution No. 1214 (2001Bonds), 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 ColumbiaSeries 2012-D and 2012-E fixed rate bonds with a weighted average couponinterest 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 BondProceeds for 2012-D and 2012-E are presented in the following tables:A Cornmnittnent to Excelience Bond Proceeds (Dollars in millions) 2012DColumbia
$ 34.14 $Total $ 34.14 $2012E748.52 $748.52 $Total782.66782.662012E2.50%5.00%Weighted Average Coupon Interest Rate for New Bonds2012DColumbia 4.48%Total 4.08%Energy Northwest did not issue or refund any bonds associated withProject No. 1, Project No. 3, Packwood, and Nine Canyon during FY 2013.Outstanding principal on revenue and refunding bonds for the variousbusiness units as of June 30, 2013, and future debt service requirements forthese 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)
Series2003A2003F2004A2004B2004C2005A2005C2006A2006C2006D2007A2007B2007D2008A200882008C2009A2009B2009C201082010C2010D2011A2011B2011C2012A2012D2012ECoupon Rate (%)5.505.00-5.25 5.255.505.255.004.64-4.74 5.005.005.805.005.10-5.33 5.005.00-5.25 5.955.00-5.25 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 3.555.005.001.06-4.14 Serial or TermMaturities 7-1-20157-1-13/2018 7-1-17/2018 7-1-20137-1-13/2018 7-1-15/2018 7-1-13/2015 7-1-2012024 7-1-20/2024 7-1-20237-1-13/2018 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 7-1-20197-1-18/2021 7-1-25/2044 7-1-15/2037 Amount$ 81,09023,710129,26012,71515,045114,98542,885434,21062,2003,42577,57510,31035,080110,93512,02537,240116,42518,51569,17016,00575,770155,805311,24529,9204,600441,24034,140748,515Series1989B2003A2004A2004B2005A2006A2007A2007B2007C2008A2008D2009A200982010A2012A201282012CICoupon Rate (%)7.1255.505.255.505.005.005.005.105.005.00-5.25 5.003.25-5.00 4.593.00-5.00 5.005.001.26ISerial or TermMaturities 7-1-20167-1-13/2014 7-1-20137-1-20137-1 -1 3/20157-1-13/2017 7-1-13/2017 7-1-- -201--- 37-1-20137-1-1312017 7-1-1312017 7-1-13/2017 7-1-14-2015 7-1-20147-1-13/2017 7-1-13/2017 7-1-20177-1-2015Amount$ 41,070174,40062,4851,13572,175103,12051,7302,290219,020230,53538,10048,90551554,805155,39041,28524,100Revenue 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 theAccounting Standards Codification (ASC) 820 and does not purport to represent the amounts atwhich 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 theAccounting Standards Codification (ASC) 820 and does not purport to represent the amounts atwhich 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 Revenueand Refunding Bonds (Dollars in thousands)
Serial or TermSeries Coupon Rate (%) Maturities Serial or TermCoupon Rate (%) Maturities SeriesAmountAmount1989A1989BSubtotal 1989A and 11993C2003A2004A2004B2005A2006A2007A2007C2008A2008D2009A2009B2010A2010B2011A2012A201282012C(B)(B)7.1259898(A)5.505.255.505.005.004.50-5.00 5.005.255.005.00-5.25 4.595.005.004.00-5.00 5.003.00-5.00 1.26-1.74 7-1-1312014 7-1-13/2014 7-1-20167- 1-3120187- -20137-1-14/2016 7-1-20137-1-13/2015 7-1-16/2018 7- 1-13/2018 7- 1-13/2018 7- -20187-1-13/2017 7-1-14/2018 7-1-20147-1-16/2018 7-1-20167-1-20187-1-20187-1-16/2017 7- 1-15/2016
$ 2,8158,29776,14687,25823,96352,89083,8351,515129,26539,44584,46555,04513,79033,595116,055970279,98029,86592,28567,88530,33061,6352005200620124.50-5.00 4.50-5.00 2.00-5.00 7-1-13/2023 7-1-13/2030 7-1-13/2023
$ 48,37068,83513,750i -Revenue bond payable $ 130,955Estimated fair value at June 30, 2012 $ 136,617 (A)(A) The estimated fair value shown has been reported to meet the disclosure requirements of theAccounting Standards Codification (ASC) 820 and does not purport to represent the amounts atwhich 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 111,334Revenue 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 theAccounting Standards Codification (ASC) 820 and does not purport to represent the amounts atwhich these obligations would be settled.(B) Compound Interest Bonds0 A Commitment to Exceltence Debt Service Requirements As of June 30, 2013 (Dollars in thousands)
Columbia Generating StationNuclear Project No. 1Fiscal Year***Principal InterestTotalFiscal Year* *Principal InterestTotal2013 $ 61,020 $20142015-2017 2018-2022 2023-2024 2025-2028 2029-2044 79,765419,6451,927,765 648,95054,27532,62071,522 $140,052382,322423,44057,4849,79912,972132,542219,817801,9672,351,205 706,43464,07445,5922013 $ 273,055 $2014201520162017332,100191,430239,385285,09033,186 $52,40135,44327,02614,117306,241384,501226,873266,411299,207$ 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. 3Nine Canyon Wind ProjectFiscal Year-Principal InterestTotalFiscal Year **Principal InterestTotal201320142015201620172018$ 131,875 S124,704129,795247,499177,617472,58165,552 $88,73860,48756,83845,12432,625197,427213,442190,283304,337222,741505,20620132014-2017 2018-2021 2022-2025 2026-2029 20306,835 $31,13537,41530,17519,8555,5403,062 $21,43815,2517,8053,3052499,89752,57352,66637,98023,1605,789Adjustment
**111,334 (111,334)-
$ 1,395,405
$ 238,031 $ 1,633,435
$ 130,955 $ 51,109 $ 182,064Principal 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 BillingSecurity
-Nuclear Projects Nos. 1 and 3 and ColumbiaThe participants have purchased all of the capability of Nuclear ProjectsNos. 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 annualcosts of the respective
: projects, including debt service on bonds relating toeach 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 suchpayments whether or not the projects are completed, operable or operating and notwithstanding the suspension, interruption, interference, reduction orcurtailment 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 3project agreements and the net-billing agreements, except for certain sectionswhich 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 providefor continuation of the present budget approval, billing and payment processes.
With respect to Nuclear Project No. 3, the ownership agreement among EnergyNorthwest and private companies was terminated in FY 1999. (See Note 13)Security
-Packwood Lake Hydroelectric ProjectPower produced by Packwood is provided to the 12 member utilities.
Themember utilities pay the annual costs, including any debt service, of Packwoodand are obligated to pay these annual costs whether or not Packwood isoperational.
The Packwood participants also share project revenue to theextent that the amounts exceed project costs.Note 7 -Pension PlansSubstantially all Energy Northwest full-time and qualifying part-time employees participate in one of the following statewide retirement systemsadministered by the Washington State Department of Retirement Systems,under cost-sharing multiple-employer public employee defined benefitretirement plans. The Department of Retirement Systems (DRS), a department within the primary government of the State of Washington, issues a publiclyavailable comprehensive annual financial report (CAFR) that includes financial statements and required supplementary information for each plan. The DRSCAFR may be obtained by writing to: Department of Retirement Systems,Communications Unit, RO. Box 48380, Olympia, Wash., 98504-8380; or itmay be downloaded from the DRS website at www.drs.wa.gov.
The following disclosures are made pursuant to GASB Statements No. 27, "Accounting forPensions by State and Local Government Employers" and No. 50, "PensionDisclosures,"
an Amendment of GASB Statements No. 25 and No. 27.Any information obtained from the DRS is the responsibility of the stateof Washington.
PricewaterhouseCoopers LLP (PwC), independent auditorsfor Energy Northwest, has not audited or examined any of the information available from the DRS; accordingly, PwC does not express an opinion or anyother form of assurance with respect thereto.Public Employees' Retirement System (PERS) Plans 1, 2, and 3The Legislature established PERS in 1947. Membership in the systemincludes:
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 inhigher education retirement programs; employees of district and municipal courts; and employees of local governments.
Approximately 50 percent ofPERS salaries are accounted for by state employment.
PERS retirement benefit provisions are established in chapters 41.34 and 41.40 RCW and maybe amended only by the State Legislature.
PERS is a cost-sharing multiple-employer retirement system comprised ofthree separate plans for membership purposes:
Plans 1 and 2 are definedbenefit 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 Plan1 members.
Those who joined on or after October 1, 1977 and by either,February 28, 2002 for state and higher education employees, or August31, 2002 for local government employees, are Plan 2 members unless theyexercised an option to transfer their membership to Plan 3. PERS membersjoining the system on or after March 1, 2002 for state and higher education employees, or September 1, 2002 for local government employees have theirrevocable option of choosing membership in either PERS Plan 2 or Plan 3.The option must be exercised within 90 days of employment.
Employees whofail to choose within 90 days default to Plan 3. Notwithstanding, PERS Plan2 and Plan 3 members may opt out of plan membership if terminally ill, withless 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 definedbenefits of Plan 1 members.
Plan 2/3 accounts for the defined benefits of Plan2 members and the defined benefit portion of benefits for Plan 3 members.Plan 3 accounts for the defined contribution portion of benefits for Plan 3members.
Although members can only be a member of either Plan 2 or Plan3, the defined benefit portions of Plan 2 and Plan 3 are accounted for in thesame pension trust fund. All assets of this Plan 2/3 defined benefit plan maylegally be used to pay the defined benefits of any of the Plan 2 or Plan 3members or beneficiaries, as defined by the terms of the plan. Therefore, Plan2/3 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.
Employeecontributions to the PERS Plan 1 and Plan 2 defined benefit plans accrueinterest at a rate specified by the Director of DRS. During DRS' fiscal year2012, the rate was five and one-half percent compounded quarterly.
Membersin 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 ofeligible 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 yearsof 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 theAFC. 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 25years of service and have been retired 20 years, or who have 20 years ofservice and have been retired 25 years. If a survivor option is chosen, thebenefit is reduced.
Plan 1 members retiring from inactive status prior to theage of 65 may also receive actuarially reduced benefits.
Plan 1 members mayelect to receive an optional Cost of Living Adjustment (COLA) that providesan automatic annual adjustment based on the Consumer Price Index. Theadjustment is capped at 3 percent annually.
To offset the cost of this annualadjustment, the benefit is reduced.PERS Plan 2 members are vested after the completion of five years ofeligible service.
Plan 2 members are eligible for normal retirement at theage of 65 with five years of service.
The monthly benefit is 2 percent of theAFC 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; anda 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 andare 55 years of age or older are eligible for early retirement with a reducedbenefit.
The benefit is reduced by an early retirement factor (ERF) that variesaccording to age, for each year before age 65.PERS Plan 3 has a dual benefit structure.
Employer contributions financea defined benefit component and member contributions finance a definedcontribution component.
As established by chapter 41.34 RCW, employeecontribution rates to the defined contribution component range from5 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 ofthe PERS 2/3 defined benefit plan.There are 1,184 participating employers in PERS. Membership in PERSconsisted of the following as of the latest actuarial valuation date for theplans of June 30, 2011:of the State Actuary to fully fund Plan 2 and the defined benefit portionof Plan 3. Under PERS Plan 3, employer contributions finance the definedbenefit portion of the plan and member contributions finance the definedcontribution portion.
The Plan 3 employee contribution rates range from 5 to15 percent, based on member choice. Two of the options are graduated ratesdependent 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 wasdeveloped 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 areestablished under state statute in accordance with chapters 41.40 and 41.45RCW.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 3Employer*
Employee7.25%/**
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 2and 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 bythe PERS 3 member.Both Energy Northwest and the employees made the requiredcontributions.
Energy Northwest's required contributions for the years endingJune 30 were as follows:PERS Plan 1 PERS Plan 2 PERS Plan 3201320122011$$$106,5145124,071 $184,863 $10,630,935
$9,773,209
$7,921,762
$5,075,823 4,710,819 4,281,077 Retirees and Beneficiaries Receiving BenefitsTerminated Plan Members Entitledto But Not Yet Receiving BenefitsActive Plan Members VestedActive Plan Members Non-vested Total79,36329,925105,57846,839261,705Funding PolicyEach biennium, the state Pension Funding Council adopts PERS Plan 1employer 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 andlocal government unit employees, and at 7.5 percent for state government elected officials.
The employer and employee contribution rates for Plan 2and the employer contribution rate for Plan 3 are developed by the Officei(, y Not tlh\Ve2t
"'013 An[Wa~l ep1.oit Note 8 -Deferred Compensation PLansEnergy Northwest provides a 401(k) deferred compensation plan (401(k)plan), and a 457 deferred compensation plan. Both plans are definedcontribution 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 employermatching contribution for each of its employees who is a participant duringthe plan year. The amount of such an employer match shall be 50 percent ofthe 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 toreceive pensions under PERS Plan 1, Plan 2, and Plan 3. There are 62 retireeswho 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 priorto 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 theemployee's annual rate of salary at retirement for non-bargaining employees retiring prior to January 1, 1995. The life insurance benefit has a maximumlimit of $10,000 for retirees after December 31, 1994. The cost of coveragefor retirees remained unchanged for FY 2013 and was $2.82 per $1,000 ofcoverage.
Employees who retired prior to January 1, 1995, contribute 58 centsper $1,000 of coverage while Energy Northwest pays the remainder; retireesafter December 31, 1994, pay 100 percent of the cost coverage.
Premiums arepaid 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 thefuture premium.
Energy Northwest revises the liability for the actuarial valueof 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 andallocated to each business unit based on direct labor dollars.
This allocation basis resulted in the following percentages by business unit for FY 2013 forthis and other allocated costs; Columbia at 94 percent; Business Development at 4 percent; and Project 1, Nine Canyon, Packwood and Project 3 receiving theresidual amount of 2 percent.Note 10 -NucLear Licensing and Insurance Nuclear Licensing Energy Northwest is a licensee of the Nuclear Regulatory Commission and issubject to routine licensing and user fees. Additionally, Energy Northwest maybe subject to license modification, suspension, revocation, or civil penalties inthe 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 bythe Price-Anderson Act (Act), while the property damage, decontamination and premature decommissioning coverage are defined by the Code ofFederal Regulations.
Energy Northwest continues to maintain all regulatory required limits as defined by the NRC, Code of Federal Regulations and theAct. The NRC requires Energy Northwest to certify nuclear insurance limitson an annual basis. Energy Northwest intends to maintain insurance againstnuclear risks to the extent such insurance is available on reasonable termsand in an amount and form consistent with customary practice.
EnergyNorthwest is self-insured to the extent that losses (i) are within the policydeductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered dueto lack of insurance availability.
Such losses could have an effect on EnergyNorthwest's results of operations and cash flows. All dollar figures notedbelow are as of June 30, 2013.American Nuclear Insurance (ANI) Coverage:
The Act providesfinancial protection for the public in the event of a significant nucleargeneration plant incident.
The Act sets the statutory limit of public liability for a single nuclear incident at $12.6 billion.
Energy Northwest addresses thisrequirement 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 ofprotection.
If any US nuclear generation plant has a significant event whichexceeds the plant's first layer of protection, every operating licensed reactorin the US is subject to an assessment up to $117.5 million not including stateinsurance 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 yearsto 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 nucleargeneration plant license-holders to maintain at least $1.06 billion nucleardecontamination and property damage insurance and requires the proceedsthereof to be used to place a plant in a safe and stable condition, todecontaminate it pursuant to a plan submitted to and approved by the NRCbefore the proceeds can be used for plant repair or restoration or to providefor premature decommissioning.
Energy Northwest has aggregate coveragein the amount of $2.25 billion which is subject to a $5 million deductible peraccident.
Note 11 -Asset Retirement ObLigation (ARO)Energy Northwest adopted ASC 410 on July 1,2002. This standard requiresan entity to recognize the fair value of a liability of an ARO for legal obligations related to the dismantlement and restoration costs associated with theretirement of tangible long-lived assets, such as nuclear decommissioning and site restoration liabilities, in the period in which it is incurred.
Uponinitial recognition of the AROs that are measurable, the probability weightedfuture cash flows for the associated retirement costs are discounted using acredit-adjusted-risk-free rate, and are recognized as both a liability and as anincrease in the capitalized carrying amount of the related long-lived assets.Capitalized asset retirement costs are depreciated over the life of the relatedE A Commrindent to Exceetence asset with accretion of the ARO liability classified as an operating expenseon the statement of operations and net assets each period. Upon settlement of the liability, an entity either settles the obligation for its recorded amountor 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 providefor the entire cost of decommissioning and site restoration; therefore, anygain 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 netassets 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 forColumbia and Nuclear Project No. 1 are governed by the NRC regulations and site certification agreements between Energy Northwest and the state ofWashington and regulations adopted by the Washington Energy Facility SiteEvaluation Council (EFSEC) and a lease agreement with the DOE (See Notes1 and 13).As of June 30, 2013, Columbia has a capital decommissioning netasset value of zero and an accumulated liability of $124.9 million for thegenerating plant, and for the ISFSI a net asset value of $1.1 million and anaccumulated 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 andupward revision in future restoration estimates of $1.3 million resulted inthe increase to the ARO liability of $1.8 million.
Nuclear Project No. 1 has acapital decommissioning net asset value of zero and an accumulated liability of $18.2 million.Under the current agreement, Nine Canyon has the obligation to removethe generation facilities upon expiration of the lease agreement if requested by the lessors.
The Nine Canyon Wind Project recorded the related originalARO in FY 2003 for Phase I and I. Phase III began commercial operation inFY 2008 and the original ARO was adjusted to reflect the change in scenariofor the retirement obligation, with current lease agreements reflecting a 2030 expiration date. As of June 30, 2013, Nine Canyon has a capitaldecommissioning 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 frameand extent of the obligation was considered under this statement asindeterminate.
As a result, no reasonable estimate of the ARO obligation canbe made. An ARO will be required to be recorded if circumstances change.Management believes that these assets will be used in utility operations forthe foreseeable future.The following table describes the changes to Energy Northwest's AROliabilities for the year ended June 30, 2013. The balance is included in theaccounts payable and accrued expense balances for each unit. ISFSI isincluded in Columbia's balance:Asset Retirement Obligation (Dollars in millions)
Columbia Generating StationBalance At June 30, 2012Current year accretion expenseARO at June 30, 2013ISFSIBalance At June 30, 2012Current year accretion expenseRevision in future estimates ARO at June 30, 2013Nuclear Project No. 1Balance At June 30, 2012Current year accretion expenseRevision in future restoration estimates ARO at June 30, 2013Nine Canyon Wind ProjectBalance At June 30, 2012Current year accretion expenseARO at June 30, 2013$118.706.21$ 124.91$1.570.080.51$ 2.16$16.400.501.34$ 18.24$1.240.05$ 1.29Note 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 plantsat the end of each plant's operating life (see Note 11 for Columbia ARO). InSeptember 1998, the NRC approved and published its "Final Rule on Financial Assurance Requirements for Decommissioning Power Reactors."
As providedin this rule, each power reactor licensee is required to report to the NRC thestatus of its decommissioning funding for each reactor or share of a reactorit owns. This reporting requirement began March 31, 1999, and reports arerequired every two years thereafter.
Energy Northwest submitted its mostrecent 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 andISFSI -$4.4 million).
This estimate, which is updated biannually, is based onthe 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 sitecertification agreements between Energy Northwest and the state ofWashington and by regulations adopted by the EFSEC. Energy Northwest submitted a site restoration plan for Columbia that was approved by theEFSEC 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 2013study) 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 thedecommissioning and site restoration funds have been made since January1985. 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
$188.6million and $31.3 million, respectively.
Since September 1996, these amountshave 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. bankthat certifies the funds for use when needed to retire the asset. The trustis funded by BPA ratepayers and managed by BPA in accordance with NRCrequirements and site certification agreements; the balances in these externaltrust funds are not reflected on Energy Northwest's balance sheet.Energy Northwest established a decommissioning and site restoration planfor the ISFSI in 1997. Beginning in FY 2003, an annual contribution is madeto the Energy Northwest Decommissioning Fund. These contributions are heldby Energy Northwest and not held in trust by BPA. The fair market value ofcash 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 beenplanning for the demolition of Nuclear Project No. 1 and restoration of thesite, recognizing the fact that there is no market for the sale of the projectin its entirety, and no viable alternative use has been found to-date.
The finallevel 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 votedunanimously to terminate the project.
In 1995, a group from Grays HarborCounty, Wash., formed the Satsop Redevelopment Project (SRP). The SRPintroduced legislation with the state of Washington under Senate BillNo. 6427, which passed and was signed by the governor of the state ofWashington on March 7, 1996. The legislation enables local governments and Energy Northwest to negotiate an arrangement allowing such localgovernments to assume an interest in the site on which Nuclear ProjectNo. 3 exists for economic development by transferring ownership of all or aportion of the site to local government entities.
This legislation also providesfor the local government entities to assume regulatory responsibilities forsite restoration requirements and control of water rights. In February 1999,Energy Northwest entered into a transfer agreement with the SRP to transferthe real and personal property at the site of Nuclear Project No. 3. The SRPalso agreed to assume regulatory responsibility for site restoration.
Therefore, Energy Northwest is no longer responsible to the state of Washington andEFSEC for any site restoration costs.Nuclear Project No. 1 Site Restoration Site restoration requirements for Nuclear Project No. 1 are governed bysite certification agreements between Energy Northwest and the state ofWashington and regulations adopted by EFSEC, and a lease agreement withDOE. Energy Northwest submitted a site restoration plan for Nuclear ProjectNo. 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 withEnergy Northwest's proposed plan. Accordingly, EFSEC's conditional approvalprovides for additional reviews once the details of the plan are finalized.
Anew 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 inNorthwest Open Access NetworkThe Business Development Fund is a member of the Northwest OpenAccess Network (NoaNet).
Members formed NoaNet pursuant to an Interlocal Cooperation Agreement for the development and efficient use by themembers and others of a communication network in conjunction with BPA.The Business Development Fund has a 7.38 percent interest in NoaNetwith a potential mandate of an additional 25 percent step-up possible for amaximum 9.23 percent.
NoaNet has $12.4 million in network revenue bondsand note payables outstanding, based on their December 30, 2012 auditedfinancial statements.
The members are obligated to pay the principal andinterest on the bonds when due in the event and to the extent that NoaNet'sGross Revenue (after payment of costs of Maintenance and Operation) isinsufficient for this purpose.
The maximum principal share (based on step-uppotential) 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 basedon a two-thirds vote of the membership.
In FY 2013 the Business Development Fund was not required to contribute to NoaNet. Financial statements forNoaNet may be obtained by writing to: Northwest Open Access Network,NoaNet Headquarters, 5802 Overlook Ave. NE, Tacoma, Wash., 98422. Anyinformation obtained from NoaNet is the responsibility of NoaNet. PwC hasnot audited or examined any information available from NoaNet; accordingly, PwC does not express an opinion or any other form of assurance with respectthereto.Other Litigation and Commitments Energy Northwest vs. United States of America filed in U.S. Court ofFederal Claims in July 2011 (Cause No. 11-447C-EJD).
This is the secondaction for partial breach of contract brought by Energy Northwest against theUnited States (Department of Energy, "DOE") for damages ranging betweenSeptember 1, 2006 through July 2012, for DOE's continuing failure to meetits 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 millionin this case. Energy Northwest believes DOE does not have a defense onliability, which was established in the prior case.Energy Northwest is involved in other various claims, legal actions andcontractual commitments and in certain claims and contracts arising in thenormal course of business.
Although some suits, claims and commitments aresignificant in amount, final disposition is not determinable.
In the opinion ofmanagement, the outcome of such litigation, claims or commitments will nothave a material adverse effect on the financial positions of the business unitsor 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 ofthese matters.M A Commitment to Excellence Note 14 -Derivative Instruments GASB Statement No. 53, "Accounting and Reporting forDerivative Instruments" was adopted in FY 2010. EnergyNorthwest's policy is to review and apply as appropriate the normal purchase and normal sales exception underGASB No. 53. Energy Northwest has reviewed variouscontractual arrangements to determine applicability of this statement.
Purchases and sales of nuclear fueland components that require physical delivery and areexpected to be used and/or sold in the normal course ofbusiness are generally considered normal purchases andnormal sales. These transactions are excluded Under GASB53 and therefore are not required to be recorded at fairvalue in the financial statements.
Certain contracts forpower options were evaluated and the did not meet the exclusion for normal purchase and normalsale:The Business Development Fund had a power salescontract subject to the provisions'oGASB
: 53. Call optionsassociated with the contract had a- noi:onal amount of 50MWh. The fair value of the powersles option contractis based on the futures price curve for the Mid-Columbia Intercontinental Exchange for electricity and the Sumasindex for natural gas. This contract settled in June 2013.Changes in the fair value of the call options are classified asnon-operating revenue and expenses
-investment incomeon the Statements of Revenues, Expenses and Changesin Net Assets. The total dollars recorded in FY 2013 were$148,000.
Note 15 -Nuclear FuelsIn May 2012, Energy Northwest entered into agreements with three other parties for processing high assay uraniumtails. The Program consists of several agreements betweenthe parties involved, entered into as a joint effort betweenthe Department of Energy (DOE), Tennessee ValleyAuthority (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 enricheduranium product (EUP) with an average assay of 4.4 wt%.DOE and Energy Northwest have entered into anagreement for the transfer of the DUF6 to Energy Northwest.
The agreement addresses delivery and transfer of titleof the DUF6, return of residual DUF6 after enrichment, storage of the EUP, and payment of DOE's costs. The costsfor the handling of the DUF6 and storage of the EUP areanticipated to be $5 million or less. As of June 30, 2013,Energy Northwest had recorded
$0.4 million in charges tothe DOE for delivery of the DUF6, which is capitalized ascost of the fuel being purchased.
Under the Depleted Uranium Enrichment Program(&#xfd;(DUEP),
Energy Northwest purchased from USEC all oftheSeparative Work Units (SWU) contained in the EUP.Upon finalization of the program, Energy Northwest hadpurchased a total of 481.6 MTU of EUP from USEC at a costof $687.5 million, which is recorded in nuclear fuel, net ofaccumulated amortization, as of June 30, 2013.Energy Northwest and IVA have entered into anagreement for the sale and purchase of a portion of theSWU and Feed Component of the EUR The sales underthe agreement are expected to total approximately
$731million.
The sales under this agreement are scheduled totake place between 2015 and 2022.Energy Northwest has a contract with DOE that requiresDOE 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 DOEwill fulfill this legal obligation and begin accepting spentnuclear fuel.When the fuel is placed in the reactor the fuel cost isamortized to operating expense on the basis of quantityof heat produced for generation of electric energy. Theamount moved to spent fuel for cooling increased
$55.3million.
Fees for disposal of fuel in the reactor areexpensed as part of the fuel cost.The current period operating expense for Columbiaincludes an $8.1 million charge from DOE for future spentfuel storage and disposal in accordance with the NuclearWaste 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 atemporary dry cask storage facility to be used until DOEcompletes its plan for a national repository.
ISFSI will storethe spent fuel in commercially available dry storage caskson a concrete pad at the Columbia site. No casks wereissued from the cask inventory account in FY 2013. Spentfuel is transferred from the spent fuel pool to the ISFSIperiodically to allow for future refueling.
Current periodcosts were $2.1 million for dry cask storage costs whichare recorded in nuclear fuel expense.Designer:
Ben StewartEditor: AngeLa WaLzEnergy Northwest 2013 Annual Report
% ENERGY NORTHWEST LEARN MORE About Energy Northwest people and projects on the Web at www.energy-northwest.com Facebook.com/energynorthwest Twitter.com/energynorthwest
* youtube.com/energynorthwest201 1}}

Revision as of 23:08, 2 July 2018

Columbia Generating Station, 2013 Annual Financial Report. Part 2 of 2
ML14035A314
Person / Time
Site: Columbia Energy Northwest icon.png
Issue date: 01/16/2014
From:
Energy Northwest
To:
Office of Nuclear Reactor Regulation
References
G02-14-007
Download: ML14035A314 (34)
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Text

Financial Data & Information

,J)'ll qv nniliA Rer(-4 tM 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 toPricewaterhouseCoopers LLP all financial records and related data, and believes that all representations made to PricewaterhouseCoopers LLP during its auditwere 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 controlprocedures 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 forrecommendations 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 theinternal 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. RidgeChief Executive Officer Vice President, and Chief Financial

& Risk OfficerAudit, Legal and Finance Committee Chair's LetterThe executive board's Audit, Legal and Finance Committee (committee) is composed of 11 independent directors.

Members of the committee are Chair LarryKenney (July 2012 -February 2013), Marc Daudon, Dan Gunkel, Jack Janda, Skip Orser, Will Purser, Dave Remington, Lori Sanders, Tim Sheldon, Chair KathyVaughn (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 resultsof their audit, their evaluations of Energy Northwest's internal

controls, and the overall quality of Energy Northwest's financial reporting.

The meetings weredesigned to facilitate any private communications with the committee desired by the internal auditor or independent auditors.

Kathy VaughnChair,Audit, Legal and Finance Committee MA Comnmitment to Excetlonc Independent Auditor's ReportTo 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 theColumbia Generating

Station, Packwood Lake Hydroelectric
Project, Nuclear Project No.1, Nuclear Project No.3, the Business Development Fund, the NineCanyon 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, whichcollectively 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 acceptedin 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 whetherthe 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 selecteddepend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In makingthose risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the financial statements in order to designaudit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internalcontrol.

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 auditevidence we have obtained is sufficient and appropriate to provide a basis for our audit opinions.

OpinionsIn 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 MatterThe accompanying management's discussion and analysis listed in the table of contents are required by accounting principles generally accepted in theUnited States of America to supplement the basic financial statements.

Such information, although not a part of the basic financial statements, is required bythe Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in theappropriate 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 theinformation 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 limitedprocedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

Portland, OregonSeptember 26, 2013'AU Energy Northwest Management's Discussion and AnalysisEnergy Northwest is a municipal corporation and joint operating agencyof the state of Washington.

Each Energy Northwest business unit is financedand accounted for separately from all other current or future businessassets. The following discussion and analysis is organized by business unit.The management discussion and analysis of the financial performance andactivity is provided as an introduction and to aid in comparing the basicfinancial statements for the fiscal year (FY) ended June 30, 2013, with thebasic financial statements for the fiscal year ended June 30, 2012.Energy Northwest has adopted accounting policies and principles thatare in accordance with Generally Accepted Accounting Principles (GAAP) inthe United States of America.

Energy Northwest's records are maintained asprescribed 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 1to the Financial Statements.)

Because each business unit is financed and accounted for separately, thefollowing section on financial performance is discussed by business unit to aidin analysis of assessing the financial position of each individual business unit.For comparative purposes only, the table on the following page represents amemorandum total only for Energy Northwest, as a whole, for FY 2013 andFY 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 BalanceSheets; Statements of Revenues,

Expenses, and Changes in Net Assets;and Statements of Cash Flows for each of the business units, and Notes toFinancial Statements.

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

The Statements of Revenues,

Expenses, and Changes in Net Assets providefinancial information relating to all expenses, revenues and equity that reflectthe results of each business unit and its related activities over the courseof 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 andnet changes resulting from operating, financing and investing activities.

TheStatements of Cash Flows provide insight into what generates cash, wherethe 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 Debtand 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 notesto the financial statements and management discussion and analysis shouldbe used to provide an overview of Energy Northwest's financial performance.

Questions concerning any of the information provided in this report should beaddressed 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 ChangeAssetsCurrent Assets $ 209,345 S 199,122 $ (10,223)Restricted AssetsSpecial Funds 51,345 51,896 551Debt Service Funds 516,106 672,455 156,349Net Plant 1,525,642 1,499,711 (25,931)Nuclear Fuel 341,535 985,824 644,289Other Charges 3,658,124 3,258,111 (400,013)

TOTAL ASSETS $ 6,302,097

$ 6,667,119

$ 365,022Current Liabilities S 501,801 $ 621,867 $ 120,066Restricted Liabilities Special Funds 138,406 147,047 8,641Debt Service Funds 144,557 139,029 (5,528)Long-Term Debt 5,508,467 5,746,882 238,415Other Long-Term Liabitilies 15,776 18,115 2,339Other Credits 5,709 5,727 18Net Position (12,619)

(11,548)::

1,071TOTAL LIABILITIES AND NET POSITION

$ 6,302,097

$ 6,667,119

$ 365,022Operating Revenues

$ 425,695 $ 569,863 $ 144,168Operating Expenses 354,860 443,629 88,769Net Operating Revenues 70,835 126,234 55,399Other 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):

$ 1,0711 i No, 1,11we- , :1 A i ts I i, Re t Columbia Generating StationColumbia Generating Station (Columbia) is wholly owned by EnergyNorthwest and its participants and operated by Energy Northwest.

The plantis a 1,170-megawatt electric (MWe, Design Electric Rating, net) boiling waternuclear power plant located on the Department of Energy's (DOE) Hanford Sitenorth 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 economicdispatch of 51 and 140 GWh respectively.

Columbia entered its plannedrefueling outage (R-21) on May 11, 2013. The 40 day planned outage extendedan additional 5 days and ended June 25, 2013.The FY 2013 generation increaseof 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 reducedthe amount of power generated in FY 2012. Additionally, FY 2013 generation was approximately 6 GWh higher than budgeted, reflecting the continuous andsuccessful 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) ascompared with 4.73 cents per kWh in FY 2012. The industry cost of powerfluctuates year to year depending on various factors such as refueling outagesand other planned activities.

The FY 2013 cost of power decrease of 4.7percent was due to the successful cost control and generation run in FY 2013as compared to the generation and additional costs incurred during FY 2012due to the extended R-20 outage.Balance Sheet AnalysisThe 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.

Thechanges to plant and CWIP were comprised of additions to plant of $8.0 millionwith an increase to CWIP of $55.9 million.

Remaining changes was the periodeffect of depreciation of $82.0 million.

The accumulated decommissioning and site restoration accrued costs related to the Integrated Spent Fuel StorageInstallation (ISFSI) at Columbia were adjusted to reflect the change in the assetretirement obligation (ARO). Change in the ARO was necessary due to newNuclear Regulatory Commission requirements for fuel storage calculations.

PerASC 410, "Asset Retirement and Environmental Obligations,"

the obligation wasreevaluated and adjusted to reflect the change in timing due to the relicensing of Columbia through December 31, 2043 and to account for estimated costsrelated to fuel disposition obligations for the post five year period following the end of licensing and generation.

The revision resulted in an increase to thecapitalized 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 majorprojects of at least $0.7 million:

Fukushima

impacts, Radio Obsolescence, CobaltReduction
Program, Stack Monitor Performance, ServiceWater Pump and MotorOverhaul, On-Line Noble Chemical Application, Keep Fill Pump Replacement, Control Rod Device Refurbishment, Main Transformer Replacement, HighPressure Core Spray Refurbishment, Turbine Blade Procurement, Reactor FeedWater Overhaul, Condensate Pump Refurbishment, Residual Heat RemovalSystems, and Plant Telephone Obsolescence.

These projects resulted in 76NColumbia Generating StationNET GENERATION

-GWhrsColumbia Generating StationCOST OF POWER -Cents/kWh FY201FY201;FY2011FY 201C8,479 FY20136,984 FY20127,247 FY20118,124 FY20104.514.735.693.744.94FY7,725 FY 2009S 2,000 4,000 6,000 8,000 10,0000 1 2 3 40A Comniitrnent tu Lxci-hnc percent of the CWIP activity.

The remaining 24 percent were made up of 103separate projects.

Nuclear fuel, net of accumulated amortization, increased

$644.3 millionfrom FY 2012 to $985.8 million for FY 2013. The major factor contributing tothe increase in Nuclear Fuel relates to the completion of the Depleted UraniumEnrichment 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 forreload increased

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

Fuel removed for cooling increased

$55.3 millionand remaining change was $0.6 million for fuel loan and purchase activityrelating 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 (nuclearfuel cask inventory is $4.5 million and inventory is $5.7), increases to cashand investments of $7.2 million offset by a decrease in accounts and otherreceivables of $1.0 million.Special funds decreased

$20.4 million to $16.4 million in FY 2013 due tothe FY 2013 bond activity and schedule of construction costs for these fundsin 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 thesematurities.

Deferred charges increased

$59.8 million in FY 2013 from $835.0 millionto $894.8 million.

Components of this increase were changes in Costs inExcess of Billings related to the net effect of payment of current maturities andrefunding activity related to available debt of $58.1 million.

There was also aslight increase to unamortized debt expense of $1.7 million due to debt relatedactivity.

Current liabilities increased

$15.6 million in FY 2013 to $139.6 million.Components of the change were an increase to year end obligations relatingfrom 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 notespayable obligation related to the DUEP, an increase of $14.6 million for businessunit activity and a decreased requirement for participant amounts under the netbilling 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 anddecommissioning 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 $748.6million.

The current portion of Bonds Payable increased

$60.1 million, whichwas driven by timing of scheduled maturities.

Other long-term liabilities increased

$2.1 million in FY 2013 to $17.9 millionrelated to nuclear fuel cask activity.

Statement of Operations AnalysisColumbia is a net-billed project.

Energy Northwest recognizes revenuesequal to expenses for each period on net-billed projects.

No net revenue or lossis recognized and no net assets are accumulated.

Operating expenses increased

$87.5 million from FY 2012 costs of $331.4million to $418.9 million in FY 2013. The increases in costs were due to FY2013 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 inincreased fuel disposal costs of $8.5 million and increased generation taxesof SO.8 million.

Periodic expenses for depreciation and decommissioning increased

$8.4 million with the remainder of the increase

($0.9 million) a resultColumbia Generating StationTOTAL OPERATING COSTS(dollars in thousands)

FY2013Total ExpensesFY2012FY 2011FY2010FY2009of Administrative and General Expenses.

539,779 Other Income and Expenses increased

$54.2 million from FY 2012 to $1 20.7million 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 asan offset to other income and expense.

This is the major factor in the overallincrease in other income and expenses for FY 2013. Additionally, FY 2012 had522,1 56 $1.8 million in property disposal gains (condenser from R-20) that did not occurin FY 2013. The remaining major components of the increases were $2.0 million448,075 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 FY519,759 2012 to $539.7 million in FY 2013.The increase in costs (and conversely revenueper net billing) of $141.8 million was due to the increased costs incurred in the500,000 completion of R-21. R-21 was originally budgeted for $87.0 million and 40Expenses 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-21.0 100,000 200,000 300,000 400,0000 Operating ExpensesM Other Income II Packwood Lake HydroeLectric ProjectThe Packwood Lake Hydroelectric Project (Packwood) is wholly owned and operated by Energy Northwest.

Packwood consists of a diversion structure at PackwoodLake 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 anddrops 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 perkWh 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 FY2013 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 ProjectCOST OF POWER -Cents/kWh FYBalance Sheet AnalysisTotal assets decreased

$0.1 million from FY 2012, with the drivers beingan 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 totalliabilities of $0.1 million was the decrease in due to participants for the results ofoperations.

Packwood has incurred

$3.7 million in relicensing costs through FY2012 with no new costs incurred for FY 2013. These costs are shown as Deferred2.07 Charges on the Balance Sheet. Packwood has been operating under a 50-yearlicense issued by the Federal Energy Regulatory Commission (FERC), which1.58 expired on February 28, 2010. Energy Northwest submitted the Final LicenseApplication (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 under1.59 the original license which is indefinitely extended for continued operations untilformal decision is issued by FERC and a new operating license is granted.

Asof June 30, 2013, Packwood continues to be relicensed under this extended1.82agreement.

1.62FY 201FY2011FY2010FY20090.0 0.5 1.0 1.5 2.0 2.5Packwood Lake Hydroelectric ProjectNET GENERATION

-GWhrsPackwood Lake Hydroelectric ProjectTOTAL OPERATING COSTS(dollars in thousands)

Total ExpensesFY2013FY2012FY 2011FY 2010FY2009103.74119.43107.9286.0799.34FY2013FY2012FY2011FY2010FY 20092,1661,8721,7421,5351,6410 20 40 60 80 100 1200500 1,000 1,500 2,000 2,5*00U Operating ExpensesM Other Income / ExpensesM A C~ormmiment to Exce~lence Statement of Operations AnalysisThe agreement with Packwood participants obligates them to pay annualcosts and to receive excess revenues.

(See Note 1 to the Financial Statements.)

Accordingly, Energy Northwest recognizes revenues equal to expenses for eachperiod. 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 forthe 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 2012to an $8,000 gain in FY 2013.The

$4,000 increase in net gain is primarily due toa 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.

ThePackwood participants also share project revenue to the extent that the amountsexceed costs. These funds can be returned to the participants or kept within theproject.

As of June 30, 2013 there is $5.7 million recorded as deferred revenues inexcess of costs that are being kept within the project.

Packwood participants arecurrently taking 100 percent of the project generation; there are no additional agreements for power sales.Nuclear Project No. 1Energy Northwest wholly owns Nuclear Project No. 1, a 1,250-MWe plant,which was placed in extended construction delay status in 1982, when itwas 65 percent complete.

On May 13, 1994, Energy Northwest's Board ofDirectors adopted a resolution terminating Nuclear Project No. 1. All fundingrequirements 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 AnalysisLong-term debt decreased

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

Short term debt increased

$37.0 million perthe debt maturity schedule.

There was a decrease to restricted liabilities of$7.0 million, represented by a decrease to interest payable of $8.8 millionoffset by an increase to the decommissioning estimate of $1.8 million.Statement of Operations AnalysisOther Income and Expenses showed a net decrease to expenses of $20.0million 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 increaseof $0.2 million in plant preservation costs.Nuctear Project No. 3Nuclear Project No. 3, a 1,240-MWe plant, was placed in extendedconstruction delay status in 1983, when it was 75 percent complete.

OnMay 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 theSatsop Redevelopment Project.

The debt service related activities remain theresponsibility of Energy Northwest and are net-billed.

(See Note 13 to theFinancial Statements.)

Balance Sheet AnalysisLong-term debt decreased

$174.4 million from $1.5 billion in FY 2012to $1.3 billion in FY 2013, as a result of $166.2 million being transferred tocurrent debt to be paid on July 1, 2013 along with a decrease in bond relatedamortization of $8.2 million.

Current debt per the debt maturity scheduleincreased

$70.6 million from $95.5 million in FY 2012 to $166.2 million inFY 2013. The remaining changes in liabilities of $6.6 million were due toincreased payable transfers from bond related activities.

Statement of Operations AnalysisOverall expenses decreased

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

The BusinessDevelopment 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 fromengaging in new energy business opportunities.

The BDF is managed as an enterprise fund. Four business lines havebeen created within the fund: General Services and Facilities, Generation,

.Professional

Services, and Business Unit Support.

Each line may have one ormore programs that are managed as a unique business activity.

Batance Sheet AnatysisTotal assets increased

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

Liabilities decreased

$0.4 million from FY 2012 dueto timing of year end outstanding items.Statement of Operations AnatysisOperating Revenues in FY 2013 totaled $9.0 million as compared to FY2012 revenues of $9.8 million, a decrease of $0.8 million.

The decrease inrevenues was driven by four major projects:

Grays Harbor project, which wasa 50 MW power call option that ended in June 2013 at the 600 MW SatsopNatural Gas Combined-Cycle plant as part of a compensation package forselling development rights to Duke Energy in 2001 ($0.3 million),

termination of the Kalama project in FY 2013, which was a proposed development ofa 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, anddecreased lease activity

($0.3 million).

The decreases in the four projectsmentioned above were offset by increased revenues for technical services andengineering services of $0.6 million.

Operating costs decreased

$0.9 milliondue 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 innet revenues in FY 2012 to net revenue of $1.3 million in FY 2013; there wasan adjustment of $0.1 million for completion of the power option derivative contract for the Grays Harbor project, and a decrease of other income andexpenses of $0.1 million, with no significant individual items.The Business Development Fund receives contributions from the InternalService Fund to cover cash needs during startup periods.

Initial startup costsare not expected to be paid back and are shown as contributions.

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

In FY 2013 there were no contributions (transfers),

which was alsothe case for FY 2012.M A Commnitme~nt to F xcetlec Nine Canyon Wind ProjectThe Nine Canyon Wind Project (Nine Canyon) is wholly owned andoperated by Energy Northwest.

Nine Canyon is located in the HorseHeaven 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 havesigned a power purchase agreement which are part of the 2nd Amendedand Restated Nine Canyon Wind Project Power Purchase Agreement which now has an end date of 2030. Nine Canyon is connected to theBonneville Power Administration transmission grid via a substation andtransmission lines constructed by Benton County Public Utility District.

Phase I of Nine Canyon, which began commercial operation inSeptember 2002, consists of 37 wind turbines, each with a maximumgenerating capacity of approximately 1.3 MW, for an aggregate generating capacity of 48.1 MW. Phase II of Nine Canyon, which was declaredoperational in December 2003, includes 12 wind turbines, each with amaximum generating capacity of 1.3 MW, for an aggregate generating capacity of approximately 15.6 MW. Phase III of Nine Canyon, which wasdeclared operational in May 2008, includes 14 wind turbines, each witha maximum generating capacity of 2.3 MW, for an aggregate generating capacity of 32.2 MW. The total Nine Canyon generating capability is 95.9MW, enough energy for approximately 39,000 average homes.Nine Canyon produced 228.23 GWh of electricity in FY 2013 versus261.63 GWh in FY 2012. The decrease of 12.8 percent was due to slightlyless favorable wind conditions in FY 2013 as compared to FY 2012. Theaverage wind speed for the months of January and June were significantly below the 10 year average.

The below average wind conditions combinedwith FY 2012 being the second highest generation year for history of theproject were the drivers for the decrease between years.Nine Canyon's cost performance is measured by the cost of powerindicator.

The cost of power for FY 2013 was $7.91 cents per kWh ascompared to $6.69 cents per kWh in FY 2012. The cost of powerfluctuates year to year depending on various factors such as windNine Canyon Wind ProjectNET GENERATION

-GWhtotals and unplanned maintenance.

The FY 2013 cost of power increaseof 18.2 percent was a result of the decreased generation due to windconditions and higher maintenance costs incurred due to turbine bearingmaintenance.

Balance Sheet AnalysisTotal 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 adecrease of $6.8 million in net plant due to accumulated depreciation.

Theremaining changes consisted of increases to restricted assets of $2.4 millionand 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 overalldecrease 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 toaccrued debt related interest of $0.1 million, and increases to accrued costsand business activities of $0.1 million.

The increase in net assets was $0.2million in FY 2013 as compared to a decrease of $1.3 million in FY 2012. Theslight reversal in net assets reflects the rate stabilization approach for NineCanyon 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 asit applies to the REPI legislation.

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

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

The payment stream fromNine Canyon participants and the REPI receipts were projected to cover thetotal costs over the purchase agreement.

Continued shortfalls in REPI fundingfor the Nine Canyon project led to a revised rate plan to incorporate theimpact of this shortfall over the life of the project.

The billing rates for theNine Canyon Wind ProjectCOST OF POWER -Cents/kWh FY2013FY2012FY 2011FY 2010FY 2009228.23 FY2013261.63 FY2012264.74 FY20117.916.696.567.887.79226.73 FY201226.27 FY20C0 50 100 150 200 250 300IEl Nine Canyon participants increased 69 percent and 80 percent for Phase I andPhase II participants respectively in FY 2008 in order to cover total projectcosts, projected out to the 2030 proposed project end date. The increases forFY 2008 were a change from the previous plan where a 3 percent increase eachyear over the life of the project was projected.

Going forward, the increase ordecrease in rates will be based on cash requirements of debt repayment andthe cost of operations.

Phase III started with an initial planning rate of $49.82per MWh which increased at 3 percent per year for three years. In year six (FY2013) the rate increased to a rate that will be stabilized over the life of theproject.

Possible adjustments may be necessary to future rates depending onoperating costs and REPI funding, similar to Phase I and II.Statement of Operations AnalysisOperating revenues increased

$2.8 million from $16.2 million in FY2012 to $19.0 million in FY 2013. The project received revenue from thebilling of the purchasers at an average rate of $80.06 per MWh for FY2013 as compared to $61.98 per MWh for FY 2012 which is reflective ofthe implementation of the revised rate plan in FY 2008 to account for REPIfunding shortfalls and costs of operations.

The increased operating revenuesfrom the previous year were due to increased funding requirements for PhaseIll purchasers.

The increase in the average rate billed to purchasers was alsoimpacted 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 inFY 2013. Increased operating costs of $1.8 million for FY 2013 were due toNine Canyon Wind ProjectTOTAL OPERATING COSTS(Dollars in thousands)

Total EFY2013FY 2012FY2011FY2010FY 2009maintenance work related to turbine bearing replacements.

Other income and expenses decreased

$0.5 million from $6.2 million innet expenses FY 2012 to $5.7 million in FY 2013. Decreased interest costsof $0.4 million and decreases in amortized bond expenses of $0.1 millionaccounted for the change. Net gain or change in net assets of $0.2 million forxpenses FY 2013 was a direct result of the planned average rate increase with lowerthan budgeted operating costs.18,805 The original plan anticipated operating at a loss in the early years andgradually increasing the rate charged to the purchasers to avoid a large rate17,467 increase after the REPI expires.

The REPI incentive expires 10 years from theinitial 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 account17,466 for the shortfall experienced in the REPI funding and to provide a new ratescenario out to the 2030 project end date. Energy Northwest did not receive16,506 REPI funding in FY 2013 and is not anticipating receiving any future REPIincentives.

The results from FY 2013 reflect the revised rate plan scenario andgradual increase in the return of total net assets.17,6320 3,000 6,000 9,000 12,000 15,000M Operating ExpensesU Other Income I Expenses0 A Commitment to Excetlence InternaL Service FundThe Internal Service Fund (ISF) (formerly the General Fund) was established in May 1957. The ISF provides services to the other funds. This fund accountsfor the central procurement of certain common goods and services for thebusiness units on a cost reimbursement basis. (See Note 1 to Financial Statements.)

Batance Sheet AnalysisTotal assets increased

$9.1 million from $46.6 million in FY 2012 to $55.7million 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 toreflect FY 2013 recognition of year-end check redemption related to R-21versus the requirements of FY 2012 which was a non-outage year, 3) anincrease of $1.6 million in restricted assets due to the debt maturity scheduleand escrow requirements processing
schedule,
4) an increase to prepaidamounts of $0.4 million, and an increase to due from other business unitsof $14.8 million.The net increase in net assets and liabilities is due to increases in accountspayable and payroll related liabilities of $9.4 million due to year-end timingof expenses for FY 2013, which was an outage year and a decrease of $15.0million due to other business units resulting from the change in year-endactivities.

Statement of Operations AnalysisNet revenues for FY 2013 increased

$112,000 from FY 2012. The increasewas 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 RaEnergy Northwest (Long-Term)

Fitch, Inc.Moodys Investors

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

Nine Canyon RatingNet-Billed RatingPhase I & IIPhase IIIAAAalAA-A-A-A2A-A2Antcy Noi thwest 2013 Animalc Repot t Statement Of Net Position As of June 30, 2013 (Dollars in thousands)

Columbia Packwood LakeGenerating Hydroelectric Nuclear NuclearProject ProjectBusiness Nine CanyonDevelopment WindInternalServiceCombinedStation Project Number 1 Number 3* Fund Project Subtotal Fund TotalASSETSCURRENT ASSETSCash $ 33,154 $ 373 $ 606 S 667 $ 5,223 * $ 8,624 $ 48,647 $ -$ 48,647Available-for-sale 10,000 1,023 2,512 2,669 2,542 1,049 19,795 5,065 24,860investments Accounts and other receivables 263 111 3 3 466 144 990 84 1,074Due from other business units -10 270 343 623 16,638Materials and supplies 121,404 ---121,404 -121,404Prepayments and other 1,409 12 --140 76 1,637 1,500 3,137TOTAL CURRENT ASSETS 166,230 1,529 3,391 3,339 8,714 9,893 193,096 23,287 199,122RESTRICTED ASSETS (NOTE 1)Special fundsCash 9,907 -298 699 4 10,908 406 11,314Available-for-sale 6,518 -3,000 7,257 -1,558 18,333 22,227 40,560investments Accounts and other 22 --22 22receivables Debt service fundsCash 125,970 98,267 57,632 9,959 291,828 291,828Available-for-sale 21,482 207,975 139,799 11,364 380,620 380,620investments Accounts and other 3 --3 1 7 7receivables TOTAL RESTRICTED ASSETS 163,902 -309,540 205,390 -22,886 701,718 22,633 724,351NON CURRENT ASSETSUTILITY 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 29,415Construction work in progress 116,483 ----116,483 116,483Accumulated 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 -985,824lated depreciation LONG TERM RECEIVABLES

--" " ----TOTAL NONCURRENTASSETS 2,392,405 1,625 " -1,393 80,344 2,475,767 9,768 2,485,535 OTHER CHARGESCost 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 -22,415Other -3,737 ---3,737 -3,737TOTAL 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 basisThe 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)

ColumbiaGenerating Packwood LakeHydroelectric NuclearProjectNuclearProjectBusinessDevelopment Nine CanyonWindInternalServiceCombinedStation Project Number 1

  • Number 3* Fund Project Subtotal Fund TotalLIABILITIES AND NET ASSETSCURRENT LIABILITIES Current maturities of long-term

$ 61,020 $ -$ 273,055 S 166,160 $ -$ 6,835 $ 507,070 S -$ 507,070debtAccounts payable and accrued 36,973 196 183 43 995 486 38,876 49,994 88,870expensesDue to participants 24,959 968 ---25,927 -25,927Due to other business units 16,618 --10 -10 16,638 623TOTAL CURRENT LIABILITIES 139,570 1,164 273,238 166,213 995 7,331 588,511 50,617 621,867LIABILITIES-PAYABLE FROMRESTRICTED ASSETS (NOTE 1)Special fundsAccounts payable and 127,163 18,244 -1,287 146,694 353 147,047accrued expensesDebt service fundsAccrued interest payable 71,522 -33,186 31,259 -3,062 139,029 139,029TOTAL RESTRICTED LIABILITIES:

198,685 -51,430 31,259 -4,349 285,723 353 286,076LONG-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 4,138 190,935 190,935premium on bonds -netUnamortized 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 18,115LIABILITIES OTHER CREDITSAdvances from members -5,727 --5,727 -5,727and othersOther ---TOTAL OTHER CREDITS -5,727 ----5,727 -5,727NET POSITIONInvested in capital assets, net -1,393 (53,110)

(51,717) 9,766 (41,951)of related debtRestricted, net -17,559 17,559 22,633 40,192Unrestricted, 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 basisThe accompanying notes are an integral part of these combined financial statements 0

Statements Of Revenues,

Expenses, And Changes In Net PositionAs Of June 30, 2013 (Dottars in thousands)

Business Nine CanyonColumbia PackwoodGenerating LakeStation ProjectNuclear NuclearProject ProjectNo.1* No.3*Development FundWindProject SubtotalInternal 2013Service CombinedFund TotalOPERATING REVENUESOPERATING EXPENSESServices to other business unitsNuclear fuelSpent fuel disposal feeDecommissioning Depreciation and amortization Operations and maintenance Administrative

& generalGeneration tax$ 539,667 $ 2,173 $42,4338,0596,30683,967 57246,376 1,93827,775 164-S <$ 9,024 $18,999 ]$ 569,863 $$ 569,8632409,167846,8146,121344942,4338,0596,39091,078263,60227,973 -4,094 -42,4338,0596,39091,078263,60227,9734,0944,02322Iotal operating expenses 418,939 2, 9I, 13,,U/ 44I3 U6 44,436 -9OPERATING INCOME (LOSS) 120,728 (8): (383)! 5,897 126,234 126,234OTHER INCOME & EXPENSEOther 4,785 3 55,032 55,906 1,308 12 117,046 82,214 116,978Investment income 645 5 68 50 20 61 849 11 849Interest 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 unitsTOTAL 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 1,071TOTAL 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 basisThe 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)

PackwoodColumbia Lake Nuclear Nuclear Business Nine Canyon Internal 2013Generating Hydroelectric Project Project Development Wind Service CombinedStation Project No.1 No.3

  • Fund Project Fund TotalCASH FLOWS FROM OPERATING AND NON-OPERATING ACTIVITIES Operating revenue receipts

$ 478,335 $ 2,011 $ -$ -$ 5,074 $ 19,002 $ $ 504,422Cash payments for operating expenses (275,172)

(2,033) -(1,159) (6,069) (284,433)

Non-operating revenue receipts 112 338,733 228,232 (67) --567,010Cash 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):

782,251and nonoperating activities CASH FLOWS FROM CAPITALAND RELATED FINANCING ACTIVITIES Proceeds from bond refundings 785,282 ----785,282Payment 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 24,640 935,419Interest on investments

.1,794 41 34 , 31 .62 230 (622) 1,570Net cash providedl(used) by investing activities 24,419 (30) (19,956)

(112,741)

(463) 6,683 (11,472)

(103,560)

NET INCREASE(DECREASE)

IN CASH68,215(822)i 6,713 (45,366)3,0518,861(5,664),

34,988CASH AT JUNE 30, 2012 100,817 1,195 92,458 104,363 2,172 9,726 6,070 316,801CASH AT JUNE 30, 2013 (NOTE B) $ 169,032 $ 373 $ 99,171 $ 58,997 $ 5,223 $ 18,587 $ 406 $ 351,789Project recorded on a liquidation basisThe 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)

PackwoodColumbia i LakeGenerating Hydroelectric Station ProjectNuclearProjectNo.1 *Nuclear Business Nine CanyonProject Development WindNo.3

  • Fund ProjectInternal 2013Service CombinedFund TotalRECONCILIATION OF NET OPERATING REVENUES TO NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES Net operating revenues

$ 120,728 $ () $ .$--------------Adjustments to reconcile net operating revenuesto cash provided by operating activities:

-Depreciation and amortization 124,410 48Decommissioning 6,306Other (2,041):

770Change in operating assets and liabilities:

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

(48),Accounts receivable 980 11 1Materials and supplies (10 201):Prepaid and other assets (98)1 62Due from/to other business units, funds 14,874 (915)and Participants Accounts payable 9,537 58Non-operating revenue receipts 112 338,733Cash payments for preservation, termination expense --- -(534)Cash payments for services$(383) : $ 5,897 :$$ 126,234157 6,793331,458 37(51) (9):131,4086,339224(61,380)931(10,201)2,73814,0359,594567,077(556)2,57220276(96):95228,232(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)::

$ 782,251and nonoperating activities

_ ________* Project recorded on a liquidation basisThe 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 PoliciesEnergy Northwest, a municipal corporation and joint operating agency ofthe 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.

Allmembers own and operate electric systems within the state of Washington.

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

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

Participants in Energy Northwest's net-billed business units consist of publicutilities and rural electric cooperatives located in the western United Stateswho have entered into net-billing agreements with Energy Northwest andBPA 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 recoverthe 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 requiredto operate Columbia.

Columbia was issued a standard 40-year operating license by the Nuclear Regulatory Commission (NRC) in 1983. On January19, 2010 Energy Northwest submitted an application to the NRC to renewthe 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. Packwoodhas been operating under a 50-year license issued by the Federal EnergyRegulatory Commission (FERC), which expired on February 28, 2010. EnergyNorthwest submitted the Final License Application (FLA) for renewal of theoperating license to FERC on February 22, 2008. On March 4, 2010, FERCissued a one-year extension, or until the issuance of a new license for theproject or other disposition under the Federal Power Act, whichever comesfirst. FERC is awaiting issuance of the National Oceanic and Atmospheric Administration's (NOAA) Biological

Opinion, after which FERC will completethe final license renewal documentation for Packwood.

Costs incurred todate 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 areobligated to pay annual costs of Packwood including debt service, whetheror 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 extendedconstruction delay status in 1982, when it was 65 percent complete.

NuclearProject 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 ownsNuclear Project No. 1. Energy Northwest is no longer responsible for siterestoration costs for Nuclear Project No. 3 (See Note 13).The Business Development Fund was established in April 1997 to pursueand develop new energy related business opportunities.

There are fourmain business lines associated with this business unit: General Services andFacilities, Generation, Professional

Services, and Business Unit Support.The Nine Canyon Wind Project (Nine Canyon) was established in January2001 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 turbinesto Nine Canyon and adding an aggregate capacity of 32.2 MWe. The totalnumber 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 usedto account for the central procurement of certain common goods and servicesfor the business units on a cost reimbursement basis.Energy Northwest's fiscal year begins on July 1 and ends on June 30. Inpreparing these financial statements, the company has evaluated events andtransactions 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 ofEnergy Northwest conform to Generally Accepted Accounting Principles (GAAP) applicable to governmental units. The Governmental Accounting Standards Board (GASB) is the accepted standard-setting body forestablishing 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 GASBpronouncements.

The accounting and reporting policies of EnergyNorthwest are regulated by the Washington State Auditor's Office andare based on the Uniform System of Accounts prescribed for publicutilities and licensees by FERC. Energy Northwest uses the full accrualbasis of accounting where revenues are recognized when earned andexpenses are recognized when incurred.

Revenues and expenses relatedto 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 andexpenses.

Separate funds and books of accounts are maintained for eachbusiness unit. Payment of the obligations of one business unit with fundsof another business unit is prohibited, and would constitute violation ofbond 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 InternalService Fund are also owned by this Fund and operated for the benefitof other projects.

Depreciation relating to capital assets is charged to theappropriate 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 whichhave been charged directly or indirectly to business units and will befunded 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 businessunits on the Internal Service Fund Balance Sheet.The combined total column on the financial statements is forpresentation (unaudited) only as each Energy Northwest business unitis financed and accounted for separately from all other current andfuture 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 andAnalysis for State and Local Governments."

Pursuant to GASB Statement No. 20, "Accounting and Financial Reporting for Proprietary Funds and Other Governmental Entities ThatUse Proprietary Fund Accounting,"

Energy Northwest has elected toapply 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 andFinancial 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 guidancegoverns 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 andNet Position."

Statement No. 63 amends the current net assets reporting requirements by incorporating deferred inflows of resources and deferredoutflows 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. EnergyNorthwest's financial statements have been modified to conform to therequirements of this statement.

Implementation did not have a materialimpact 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 itemspreviously reported as assets and liabilities as deferred outflows ordeferred inflows of resources, or as outflows or inflows of resources.

Thisstatement 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 thatits impact will be material.

In June 2012, GASB issued Statement No. 68, "Accounting andFinancial 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.

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

Fordefined benefit pension plans, this statement identifies the methodsand assumptions to project benefit payments, discount projected benefitpayments to their actuarial present value and attribute present value toperiods of employee service.

Note disclosure and required supplementary information about pensions are also addressed.

Statement No. 68 iseffective for Energy Northwest beginning in fiscal year 2015. EnergyNorthwest is currently evaluating the financial statement impact ofadopting this statement.

b) Utility Plant and Depreciation:

Utility plant is recorded at originalcost which includes both direct costs of construction or acquisition andindirect costs.Property, plant, and equipment are depreciated using the straight-line method over the following estimated useful lives:Buildings and Improvements Generation PlantTransportation Equipment General Plant and Equipment 20- 60 years40 years6- 9 years3 -15 yearsGroup rates are used for assets and, accordingly, no gain or lossis recorded on the disposition of an asset unless it represents a majorretirement.

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

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

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

Interest

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

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

Ifestimated costs are more than inconsequential, an adjustment is made toallocate capitalized interest to the appropriate plant account.

Capitalized interest costs were $1.6 million.d) Nuclear Fuel: Energy Northwest has various agreements for uraniumconcentrates, conversion, and enrichment to provide for short-term enriched uranium product and long-term enrichment services.

Allexpenditures 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 ASC410, "Asset Retirement and Environmental Obligations."

This standardrequires Energy Northwest to recognize the fair value of a liability associated with the retirement of a long-lived asset, such as: ColumbiaGenerating

Station, Nuclear Project No. 1, and Nine Canyon, in theperiod 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 Columbiaand monies are being deposited each year in accordance with anestablished 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 themeasurement, recognition and disclosure of derivative instrument transactions for the purpose of enhancing the usefulness andcomparability of derivative instrument information reported by state andlocal governments (see Note 14).h) Restricted Assets: In accordance with bond resolutions, relatedagreements and laws, separate restricted accounts have beenestablished.

These assets are restricted for specific uses including debtservice, 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 assetsas appropriate.

i) Cash and Investments:

For purposes of the Statements of CashFlows, cash includes unrestricted and restricted cash balances and eachbusiness unit maintains its cash and investments.

Short-term highlyliquid investments are not considered to be cash equivalents, but areclassified as available-for-sale investments and are stated at fair valuewith unrealized gains and losses reported in investment income (seeNote 3). Energy Northwest resolutions and investment policies limitinvestment 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 thebenefit of the individual Energy Northwest business units.j) Accounts Receivable:

The percentage of sales method is used toestimate uncollectible accounts.

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

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

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

The amountsdue to each business unit are reflected in Due To/From other businessunits. Other receivables specific to each business unit are recorded in theresiding business unit.1) Materials and Supplies:

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

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

Othernoncurrent 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 areamortized over the terms of the respective bond issues using the bondsoutstanding 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 acomponent of interest expense over the shorter of the remaining life ofthe old or new debt.p) Revenue Recognition:

Energy Northwest accounts for expenses onan accrual basis, and recovers, through various agreements, actual cashrequirements 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.

Suchamounts will be settled during future operating periods (see Note 6).Energy Northwest accounts for revenues and expenses on an accrualbasis for the remaining business units.The difference between cumulative revenues and cumulative expenses is recognized as net revenue or lossand 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 asit applies to the REPI bill. REPI was created as part of the Energy PolicyAct of 1992 to promote increases in the generation and utilization ofelectricity from renewable energy sources and to further the advances ofrenewable energy technologies.

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

NineCanyon did not record a receivable for FY 2013 REPI funding as nofunds are anticipated to be disbursed to Energy Northwest under thisprogram.

The payment stream from Nine Canyon participants and theanticipated REPI funding were projected to cover the total costs of thepurchase agreement.

Permanent shortfalls in REPI funding for the NineCanyon project led to a revised rate plan to incorporate the impact ofthis shortfall over the life of the project.

The current rate schedule for theNine Canyon participants covers total estimated project costs occurring in FY 2013 and estimated total cost recovery projections out to the 2030proposed end date. During FY 2013 there was no cost recovery obtainedfrom REPI.m) Leases: Consist of separate operating lease agreements.

The total ofthese leases by business unit and their respective amounts paid per yearare listed in the table on the next page.Enot oly >Fui thwtet 2101 2` Aimun Rei eport Projects Operating Lease Costs (Dottars in thousands) 2014201512016201720182019+Columbia

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

Balance 6/30/2012 INCREASES DECREASES Balance 6/30/2013 ColumbiaRevenue bonds payable $Unamortized (discount)/premium on bonds -netUnamortized gain/(loss) on bond refundings Other noncurrent liabilities 2,441,385

$120,221(9,966)::

15,776782,655 $2,6323,3712,14261,020 $17,26258043,163,020 105,591(7,175)17,914$2,567,416

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

$1,321,060

$56,290(3,614)::

-S$303,905273,055 $20,0694611,048,005 36,251(170)$1,373,736

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

$53,241(974):8,403913166,160 $16,6898231,229,245 44,955(884)$1,447,672 4 $9,316 i $183,672 : $1,273,316 Nine CanyonRevenue bonds payableUnamortized (discount)/premium on bonds -netUnamortized gain/(Iloss) on bond refundings 130,955$4,743(279)::6,835$60522124,1204,138(214)88$135,419 : $88 $7,462 $128,044fl A Commitment to Exce[Lence r) Compensated Absences:

Employees earn leave in accordance withlength of service.

Energy Northwest accrues the cost of personal leave inthe year when earned. The liability for unpaid leave benefits and relatedpayroll taxes was $20.8 million at June 30, 2013 and is recorded as acurrent liability.

Note 2 -UtiLity PLantUtility 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 makeestimates and assumptions that directly affect the reported amountsof assets and liabilities, disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts ofrevenue and expenses during the reporting period. Actual results coulddiffer from these estimates.

Certain incurred expenses and revenues areallocated to the business units based on specific allocation methods thatmanagement considers to be reasonable.

Balance 6/30/2012 Capital Acquisitions Sale or Other Dispositions Balance 6/30/2013 ColumbiaGeneration

$ 3,791,326

$ 7,482 $ (41): $ 3,798,767 Decommissioning 14,256 512 14,768Construction Work-in-Progress 60,553 282,452 (226,522) 116,483Accumulated 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 PackwoodGeneration

$ 13,625 $ 812 $ .$ 14,437Construction Work-in-Progress 812 (812):Accumulated Depreciation (12,764):

(48): (12,812)Utility Plant, net $ 861 $ 1,576 $ (812)i $ 1,625Business Development General $ 2,174 $ 369.$ -$ 2,543Construction Work-in-Progress 369 (369);Accumulated Depreciation (993), (157)- (1,150)Utility Plant, net $ 1,181 $ 581 $ (369); $ 1,393Nine CanyonGeneration

$ 133,6451$

37 $ (32): $ 133,649Decommissioning 861 861Construction 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 $ 80,345Internal Service FundGeneral $ 48,410 $ 59 $ (500) $ 47,969Construction Work-in-Progress

-59 (59)Accumulated Depreciation (36,594)

(2,109) 500 (38,203)Utility Plant, net $ 11,816 $ (1,990).

$ (59) $ 9,766U Note 3 -Available-for-Sale Investments (Dollars in thousands)

Amortized CostUnrealized GainsUnrealized LossesFair Value (1) (2)ColumbiaPackwoodNuclear Project No. 1Nuclear Project No. 3Business Development FundInternal Service FundNine Canyon$37,986 $1,023213,488149,7252,54027,20213,97114 $$38,0001,023213,488149,7252,54027,20313,97152(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, EnergyNorthwest 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 todebt securities and obligations of the U.S. Treasury U.S. government agenciesFederal 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), andgeneral obligation debt of state and local governments and public authorities recognized with one of the three highest credit ratings (AAA, AA+, AA, orequivalent).

This investment policy is more restrictive than the state law.Concentration of Credit Risk: Energy Northwest's investment policy doesnot 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 theevent of bank failure, Energy Northwest's deposits may not be returned to it.Energy Northwest's interest bearing accounts and certificates of deposits arecovered up to $250,000 by Federal Depository Insurance (FDIC) while non-interest bearing deposits are entirely covered by FDIC and if necessary, all interest andnon-interest bearing deposits are covered by collateral held in a multiple financial institution collateral pool administered by the Washington state Treasurer's LocalGovernment Investment Pool (PDPC). Under state law, public depositories underthe 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 withinstitutions 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. Othercredits of $0.1 million for Nine Canyon consist of turbine elevator purchases to becompleted in FY 2014.Note 5 -Long-Term DebtEach Energy Northwest business unit is financed separately.

The resolutions ofEnergy Northwest authorizing issuance of revenue bonds for each business unitprovide that such bonds are payable from the revenues of that business unit. Allbonds issued under resolutions Nos. 769, 775 and 640 for Nuclear Projects Nos.1, 3 and Columbia, respectively, have the same priority of payment within thebusiness unit (the "prior lien bonds").

All bonds issued under resolutions Nos.835, 838 and 1042 (the "electric revenue bonds") for Nuclear Projects Nos. 1, 3and Columbia, respectively, are subordinate to the prior lien bonds and have thesame subordinated priority of payment within the business unit. Nine Canyon'sbonds were authorized by the following resolutions:

Resolution No. 1214 (2001Bonds), 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 ColumbiaSeries 2012-D and 2012-E fixed rate bonds with a weighted average couponinterest 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 BondProceeds for 2012-D and 2012-E are presented in the following tables:A Cornmnittnent to Excelience Bond Proceeds (Dollars in millions) 2012DColumbia

$ 34.14 $Total $ 34.14 $2012E748.52 $748.52 $Total782.66782.662012E2.50%5.00%Weighted Average Coupon Interest Rate for New Bonds2012DColumbia 4.48%Total 4.08%Energy Northwest did not issue or refund any bonds associated withProject No. 1, Project No. 3, Packwood, and Nine Canyon during FY 2013.Outstanding principal on revenue and refunding bonds for the variousbusiness units as of June 30, 2013, and future debt service requirements forthese 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)

Series2003A2003F2004A2004B2004C2005A2005C2006A2006C2006D2007A2007B2007D2008A200882008C2009A2009B2009C201082010C2010D2011A2011B2011C2012A2012D2012ECoupon Rate (%)5.505.00-5.25 5.255.505.255.004.64-4.74 5.005.005.805.005.10-5.33 5.005.00-5.25 5.955.00-5.25 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 3.555.005.001.06-4.14 Serial or TermMaturities 7-1-20157-1-13/2018 7-1-17/2018 7-1-20137-1-13/2018 7-1-15/2018 7-1-13/2015 7-1-2012024 7-1-20/2024 7-1-20237-1-13/2018 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 7-1-20197-1-18/2021 7-1-25/2044 7-1-15/2037 Amount$ 81,09023,710129,26012,71515,045114,98542,885434,21062,2003,42577,57510,31035,080110,93512,02537,240116,42518,51569,17016,00575,770155,805311,24529,9204,600441,24034,140748,515Series1989B2003A2004A2004B2005A2006A2007A2007B2007C2008A2008D2009A200982010A2012A201282012CICoupon Rate (%)7.1255.505.255.505.005.005.005.105.005.00-5.25 5.003.25-5.00 4.593.00-5.00 5.005.001.26ISerial or TermMaturities 7-1-20167-1-13/2014 7-1-20137-1-20137-1 -1 3/20157-1-13/2017 7-1-13/2017 7-1-- -201--- 37-1-20137-1-1312017 7-1-1312017 7-1-13/2017 7-1-14-2015 7-1-20147-1-13/2017 7-1-13/2017 7-1-20177-1-2015Amount$ 41,070174,40062,4851,13572,175103,12051,7302,290219,020230,53538,10048,90551554,805155,39041,28524,100Revenue 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 theAccounting Standards Codification (ASC) 820 and does not purport to represent the amounts atwhich 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 theAccounting Standards Codification (ASC) 820 and does not purport to represent the amounts atwhich 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 Revenueand Refunding Bonds (Dollars in thousands)

Serial or TermSeries Coupon Rate (%) Maturities Serial or TermCoupon Rate (%) Maturities SeriesAmountAmount1989A1989BSubtotal 1989A and 11993C2003A2004A2004B2005A2006A2007A2007C2008A2008D2009A2009B2010A2010B2011A2012A201282012C(B)(B)7.1259898(A)5.505.255.505.005.004.50-5.00 5.005.255.005.00-5.25 4.595.005.004.00-5.00 5.003.00-5.00 1.26-1.74 7-1-1312014 7-1-13/2014 7-1-20167- 1-3120187- -20137-1-14/2016 7-1-20137-1-13/2015 7-1-16/2018 7- 1-13/2018 7- 1-13/2018 7- -20187-1-13/2017 7-1-14/2018 7-1-20147-1-16/2018 7-1-20167-1-20187-1-20187-1-16/2017 7- 1-15/2016

$ 2,8158,29776,14687,25823,96352,89083,8351,515129,26539,44584,46555,04513,79033,595116,055970279,98029,86592,28567,88530,33061,6352005200620124.50-5.00 4.50-5.00 2.00-5.00 7-1-13/2023 7-1-13/2030 7-1-13/2023

$ 48,37068,83513,750i -Revenue bond payable $ 130,955Estimated fair value at June 30, 2012 $ 136,617 (A)(A) The estimated fair value shown has been reported to meet the disclosure requirements of theAccounting Standards Codification (ASC) 820 and does not purport to represent the amounts atwhich 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 111,334Revenue 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 theAccounting Standards Codification (ASC) 820 and does not purport to represent the amounts atwhich these obligations would be settled.(B) Compound Interest Bonds0 A Commitment to Exceltence Debt Service Requirements As of June 30, 2013 (Dollars in thousands)

Columbia Generating StationNuclear Project No. 1Fiscal Year***Principal InterestTotalFiscal Year* *Principal InterestTotal2013 $ 61,020 $20142015-2017 2018-2022 2023-2024 2025-2028 2029-2044 79,765419,6451,927,765 648,95054,27532,62071,522 $140,052382,322423,44057,4849,79912,972132,542219,817801,9672,351,205 706,43464,07445,5922013 $ 273,055 $2014201520162017332,100191,430239,385285,09033,186 $52,40135,44327,02614,117306,241384,501226,873266,411299,207$ 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. 3Nine Canyon Wind ProjectFiscal Year-Principal InterestTotalFiscal Year **Principal InterestTotal201320142015201620172018$ 131,875 S124,704129,795247,499177,617472,58165,552 $88,73860,48756,83845,12432,625197,427213,442190,283304,337222,741505,20620132014-2017 2018-2021 2022-2025 2026-2029 20306,835 $31,13537,41530,17519,8555,5403,062 $21,43815,2517,8053,3052499,89752,57352,66637,98023,1605,789Adjustment

    • 111,334 (111,334)-

$ 1,395,405

$ 238,031 $ 1,633,435

$ 130,955 $ 51,109 $ 182,064Principal 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 BillingSecurity

-Nuclear Projects Nos. 1 and 3 and ColumbiaThe participants have purchased all of the capability of Nuclear ProjectsNos. 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 annualcosts of the respective

projects, including debt service on bonds relating toeach 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 suchpayments whether or not the projects are completed, operable or operating and notwithstanding the suspension, interruption, interference, reduction orcurtailment 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 3project agreements and the net-billing agreements, except for certain sectionswhich 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 providefor continuation of the present budget approval, billing and payment processes.

With respect to Nuclear Project No. 3, the ownership agreement among EnergyNorthwest and private companies was terminated in FY 1999. (See Note 13)Security

-Packwood Lake Hydroelectric ProjectPower produced by Packwood is provided to the 12 member utilities.

Themember utilities pay the annual costs, including any debt service, of Packwoodand are obligated to pay these annual costs whether or not Packwood isoperational.

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

The following disclosures are made pursuant to GASB Statements No. 27, "Accounting forPensions by State and Local Government Employers" and No. 50, "PensionDisclosures,"

an Amendment of GASB Statements No. 25 and No. 27.Any information obtained from the DRS is the responsibility of the stateof Washington.

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

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 inhigher education retirement programs; employees of district and municipal courts; and employees of local governments.

Approximately 50 percent ofPERS salaries are accounted for by state employment.

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

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

Plans 1 and 2 are definedbenefit 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 Plan1 members.

Those who joined on or after October 1, 1977 and by either,February 28, 2002 for state and higher education employees, or August31, 2002 for local government employees, are Plan 2 members unless theyexercised an option to transfer their membership to Plan 3. PERS membersjoining the system on or after March 1, 2002 for state and higher education employees, or September 1, 2002 for local government employees have theirrevocable option of choosing membership in either PERS Plan 2 or Plan 3.The option must be exercised within 90 days of employment.

Employees whofail to choose within 90 days default to Plan 3. Notwithstanding, PERS Plan2 and Plan 3 members may opt out of plan membership if terminally ill, withless 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 definedbenefits of Plan 1 members.

Plan 2/3 accounts for the defined benefits of Plan2 members and the defined benefit portion of benefits for Plan 3 members.Plan 3 accounts for the defined contribution portion of benefits for Plan 3members.

Although members can only be a member of either Plan 2 or Plan3, the defined benefit portions of Plan 2 and Plan 3 are accounted for in thesame pension trust fund. All assets of this Plan 2/3 defined benefit plan maylegally be used to pay the defined benefits of any of the Plan 2 or Plan 3members or beneficiaries, as defined by the terms of the plan. Therefore, Plan2/3 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.

Employeecontributions to the PERS Plan 1 and Plan 2 defined benefit plans accrueinterest at a rate specified by the Director of DRS. During DRS' fiscal year2012, the rate was five and one-half percent compounded quarterly.

Membersin 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 ofeligible 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 yearsof 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 theAFC. 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 25years of service and have been retired 20 years, or who have 20 years ofservice and have been retired 25 years. If a survivor option is chosen, thebenefit is reduced.

Plan 1 members retiring from inactive status prior to theage of 65 may also receive actuarially reduced benefits.

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

To offset the cost of this annualadjustment, the benefit is reduced.PERS Plan 2 members are vested after the completion of five years ofeligible service.

Plan 2 members are eligible for normal retirement at theage of 65 with five years of service.

The monthly benefit is 2 percent of theAFC 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; anda 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 andare 55 years of age or older are eligible for early retirement with a reducedbenefit.

The benefit is reduced by an early retirement factor (ERF) that variesaccording to age, for each year before age 65.PERS Plan 3 has a dual benefit structure.

Employer contributions financea defined benefit component and member contributions finance a definedcontribution component.

As established by chapter 41.34 RCW, employeecontribution rates to the defined contribution component range from5 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 ofthe PERS 2/3 defined benefit plan.There are 1,184 participating employers in PERS. Membership in PERSconsisted of the following as of the latest actuarial valuation date for theplans of June 30, 2011:of the State Actuary to fully fund Plan 2 and the defined benefit portionof Plan 3. Under PERS Plan 3, employer contributions finance the definedbenefit portion of the plan and member contributions finance the definedcontribution portion.

The Plan 3 employee contribution rates range from 5 to15 percent, based on member choice. Two of the options are graduated ratesdependent 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 wasdeveloped 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 areestablished under state statute in accordance with chapters 41.40 and 41.45RCW.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 3Employer*

Employee7.25%/**

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 2and 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 bythe PERS 3 member.Both Energy Northwest and the employees made the requiredcontributions.

Energy Northwest's required contributions for the years endingJune 30 were as follows:PERS Plan 1 PERS Plan 2 PERS Plan 3201320122011$$$106,5145124,071 $184,863 $10,630,935

$9,773,209

$7,921,762

$5,075,823 4,710,819 4,281,077 Retirees and Beneficiaries Receiving BenefitsTerminated Plan Members Entitledto But Not Yet Receiving BenefitsActive Plan Members VestedActive Plan Members Non-vested Total79,36329,925105,57846,839261,705Funding PolicyEach biennium, the state Pension Funding Council adopts PERS Plan 1employer 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 andlocal government unit employees, and at 7.5 percent for state government elected officials.

The employer and employee contribution rates for Plan 2and the employer contribution rate for Plan 3 are developed by the Officei(, y Not tlh\Ve2t

"'013 An[Wa~l ep1.oit Note 8 -Deferred Compensation PLansEnergy Northwest provides a 401(k) deferred compensation plan (401(k)plan), and a 457 deferred compensation plan. Both plans are definedcontribution 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 employermatching contribution for each of its employees who is a participant duringthe plan year. The amount of such an employer match shall be 50 percent ofthe 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 toreceive pensions under PERS Plan 1, Plan 2, and Plan 3. There are 62 retireeswho 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 priorto 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 theemployee's annual rate of salary at retirement for non-bargaining employees retiring prior to January 1, 1995. The life insurance benefit has a maximumlimit of $10,000 for retirees after December 31, 1994. The cost of coveragefor retirees remained unchanged for FY 2013 and was $2.82 per $1,000 ofcoverage.

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

Premiums arepaid 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 thefuture premium.

Energy Northwest revises the liability for the actuarial valueof 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 andallocated to each business unit based on direct labor dollars.

This allocation basis resulted in the following percentages by business unit for FY 2013 forthis and other allocated costs; Columbia at 94 percent; Business Development at 4 percent; and Project 1, Nine Canyon, Packwood and Project 3 receiving theresidual amount of 2 percent.Note 10 -NucLear Licensing and Insurance Nuclear Licensing Energy Northwest is a licensee of the Nuclear Regulatory Commission and issubject to routine licensing and user fees. Additionally, Energy Northwest maybe subject to license modification, suspension, revocation, or civil penalties inthe 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 bythe Price-Anderson Act (Act), while the property damage, decontamination and premature decommissioning coverage are defined by the Code ofFederal Regulations.

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

EnergyNorthwest is self-insured to the extent that losses (i) are within the policydeductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered dueto lack of insurance availability.

Such losses could have an effect on EnergyNorthwest's results of operations and cash flows. All dollar figures notedbelow are as of June 30, 2013.American Nuclear Insurance (ANI) Coverage:

The Act providesfinancial protection for the public in the event of a significant nucleargeneration plant incident.

The Act sets the statutory limit of public liability for a single nuclear incident at $12.6 billion.

Energy Northwest addresses thisrequirement 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 ofprotection.

If any US nuclear generation plant has a significant event whichexceeds the plant's first layer of protection, every operating licensed reactorin the US is subject to an assessment up to $117.5 million not including stateinsurance 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 yearsto 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 nucleargeneration plant license-holders to maintain at least $1.06 billion nucleardecontamination and property damage insurance and requires the proceedsthereof to be used to place a plant in a safe and stable condition, todecontaminate it pursuant to a plan submitted to and approved by the NRCbefore the proceeds can be used for plant repair or restoration or to providefor premature decommissioning.

Energy Northwest has aggregate coveragein the amount of $2.25 billion which is subject to a $5 million deductible peraccident.

Note 11 -Asset Retirement ObLigation (ARO)Energy Northwest adopted ASC 410 on July 1,2002. This standard requiresan entity to recognize the fair value of a liability of an ARO for legal obligations related to the dismantlement and restoration costs associated with theretirement of tangible long-lived assets, such as nuclear decommissioning and site restoration liabilities, in the period in which it is incurred.

Uponinitial recognition of the AROs that are measurable, the probability weightedfuture cash flows for the associated retirement costs are discounted using acredit-adjusted-risk-free rate, and are recognized as both a liability and as anincrease in the capitalized carrying amount of the related long-lived assets.Capitalized asset retirement costs are depreciated over the life of the relatedE A Commrindent to Exceetence asset with accretion of the ARO liability classified as an operating expenseon the statement of operations and net assets each period. Upon settlement of the liability, an entity either settles the obligation for its recorded amountor 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 providefor the entire cost of decommissioning and site restoration; therefore, anygain 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 netassets 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 forColumbia and Nuclear Project No. 1 are governed by the NRC regulations and site certification agreements between Energy Northwest and the state ofWashington and regulations adopted by the Washington Energy Facility SiteEvaluation Council (EFSEC) and a lease agreement with the DOE (See Notes1 and 13).As of June 30, 2013, Columbia has a capital decommissioning netasset value of zero and an accumulated liability of $124.9 million for thegenerating plant, and for the ISFSI a net asset value of $1.1 million and anaccumulated 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 andupward revision in future restoration estimates of $1.3 million resulted inthe increase to the ARO liability of $1.8 million.

Nuclear Project No. 1 has acapital decommissioning net asset value of zero and an accumulated liability of $18.2 million.Under the current agreement, Nine Canyon has the obligation to removethe generation facilities upon expiration of the lease agreement if requested by the lessors.

The Nine Canyon Wind Project recorded the related originalARO in FY 2003 for Phase I and I. Phase III began commercial operation inFY 2008 and the original ARO was adjusted to reflect the change in scenariofor the retirement obligation, with current lease agreements reflecting a 2030 expiration date. As of June 30, 2013, Nine Canyon has a capitaldecommissioning 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 frameand extent of the obligation was considered under this statement asindeterminate.

As a result, no reasonable estimate of the ARO obligation canbe made. An ARO will be required to be recorded if circumstances change.Management believes that these assets will be used in utility operations forthe foreseeable future.The following table describes the changes to Energy Northwest's AROliabilities for the year ended June 30, 2013. The balance is included in theaccounts payable and accrued expense balances for each unit. ISFSI isincluded in Columbia's balance:Asset Retirement Obligation (Dollars in millions)

Columbia Generating StationBalance At June 30, 2012Current year accretion expenseARO at June 30, 2013ISFSIBalance At June 30, 2012Current year accretion expenseRevision in future estimates ARO at June 30, 2013Nuclear Project No. 1Balance At June 30, 2012Current year accretion expenseRevision in future restoration estimates ARO at June 30, 2013Nine Canyon Wind ProjectBalance At June 30, 2012Current year accretion expenseARO at June 30, 2013$118.706.21$ 124.91$1.570.080.51$ 2.16$16.400.501.34$ 18.24$1.240.05$ 1.29Note 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 plantsat the end of each plant's operating life (see Note 11 for Columbia ARO). InSeptember 1998, the NRC approved and published its "Final Rule on Financial Assurance Requirements for Decommissioning Power Reactors."

As providedin this rule, each power reactor licensee is required to report to the NRC thestatus of its decommissioning funding for each reactor or share of a reactorit owns. This reporting requirement began March 31, 1999, and reports arerequired every two years thereafter.

Energy Northwest submitted its mostrecent 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 andISFSI -$4.4 million).

This estimate, which is updated biannually, is based onthe 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 sitecertification agreements between Energy Northwest and the state ofWashington and by regulations adopted by the EFSEC. Energy Northwest submitted a site restoration plan for Columbia that was approved by theEFSEC 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 2013study) 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 thedecommissioning and site restoration funds have been made since January1985. 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

$188.6million and $31.3 million, respectively.

Since September 1996, these amountshave 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. bankthat certifies the funds for use when needed to retire the asset. The trustis funded by BPA ratepayers and managed by BPA in accordance with NRCrequirements and site certification agreements; the balances in these externaltrust funds are not reflected on Energy Northwest's balance sheet.Energy Northwest established a decommissioning and site restoration planfor the ISFSI in 1997. Beginning in FY 2003, an annual contribution is madeto the Energy Northwest Decommissioning Fund. These contributions are heldby Energy Northwest and not held in trust by BPA. The fair market value ofcash 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 beenplanning for the demolition of Nuclear Project No. 1 and restoration of thesite, recognizing the fact that there is no market for the sale of the projectin its entirety, and no viable alternative use has been found to-date.

The finallevel 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 votedunanimously to terminate the project.

In 1995, a group from Grays HarborCounty, Wash., formed the Satsop Redevelopment Project (SRP). The SRPintroduced legislation with the state of Washington under Senate BillNo. 6427, which passed and was signed by the governor of the state ofWashington on March 7, 1996. The legislation enables local governments and Energy Northwest to negotiate an arrangement allowing such localgovernments to assume an interest in the site on which Nuclear ProjectNo. 3 exists for economic development by transferring ownership of all or aportion of the site to local government entities.

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

Therefore, Energy Northwest is no longer responsible to the state of Washington andEFSEC for any site restoration costs.Nuclear Project No. 1 Site Restoration Site restoration requirements for Nuclear Project No. 1 are governed bysite certification agreements between Energy Northwest and the state ofWashington and regulations adopted by EFSEC, and a lease agreement withDOE. Energy Northwest submitted a site restoration plan for Nuclear ProjectNo. 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 withEnergy Northwest's proposed plan. Accordingly, EFSEC's conditional approvalprovides for additional reviews once the details of the plan are finalized.

Anew 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 inNorthwest Open Access NetworkThe Business Development Fund is a member of the Northwest OpenAccess Network (NoaNet).

Members formed NoaNet pursuant to an Interlocal Cooperation Agreement for the development and efficient use by themembers and others of a communication network in conjunction with BPA.The Business Development Fund has a 7.38 percent interest in NoaNetwith a potential mandate of an additional 25 percent step-up possible for amaximum 9.23 percent.

NoaNet has $12.4 million in network revenue bondsand note payables outstanding, based on their December 30, 2012 auditedfinancial statements.

The members are obligated to pay the principal andinterest on the bonds when due in the event and to the extent that NoaNet'sGross Revenue (after payment of costs of Maintenance and Operation) isinsufficient for this purpose.

The maximum principal share (based on step-uppotential) 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 basedon a two-thirds vote of the membership.

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

This is the secondaction for partial breach of contract brought by Energy Northwest against theUnited States (Department of Energy, "DOE") for damages ranging betweenSeptember 1, 2006 through July 2012, for DOE's continuing failure to meetits 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 millionin this case. Energy Northwest believes DOE does not have a defense onliability, which was established in the prior case.Energy Northwest is involved in other various claims, legal actions andcontractual commitments and in certain claims and contracts arising in thenormal course of business.

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

In the opinion ofmanagement, the outcome of such litigation, claims or commitments will nothave a material adverse effect on the financial positions of the business unitsor 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 ofthese matters.M A Commitment to Excellence Note 14 -Derivative Instruments GASB Statement No. 53, "Accounting and Reporting forDerivative Instruments" was adopted in FY 2010. EnergyNorthwest's policy is to review and apply as appropriate the normal purchase and normal sales exception underGASB No. 53. Energy Northwest has reviewed variouscontractual arrangements to determine applicability of this statement.

Purchases and sales of nuclear fueland components that require physical delivery and areexpected to be used and/or sold in the normal course ofbusiness are generally considered normal purchases andnormal sales. These transactions are excluded Under GASB53 and therefore are not required to be recorded at fairvalue in the financial statements.

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

53. Call optionsassociated with the contract had a- noi:onal amount of 50MWh. The fair value of the powersles option contractis based on the futures price curve for the Mid-Columbia Intercontinental Exchange for electricity and the Sumasindex for natural gas. This contract settled in June 2013.Changes in the fair value of the call options are classified asnon-operating revenue and expenses

-investment incomeon the Statements of Revenues, Expenses and Changesin Net Assets. The total dollars recorded in FY 2013 were$148,000.

Note 15 -Nuclear FuelsIn May 2012, Energy Northwest entered into agreements with three other parties for processing high assay uraniumtails. The Program consists of several agreements betweenthe parties involved, entered into as a joint effort betweenthe Department of Energy (DOE), Tennessee ValleyAuthority (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 enricheduranium product (EUP) with an average assay of 4.4 wt%.DOE and Energy Northwest have entered into anagreement for the transfer of the DUF6 to Energy Northwest.

The agreement addresses delivery and transfer of titleof the DUF6, return of residual DUF6 after enrichment, storage of the EUP, and payment of DOE's costs. The costsfor the handling of the DUF6 and storage of the EUP areanticipated to be $5 million or less. As of June 30, 2013,Energy Northwest had recorded

$0.4 million in charges tothe DOE for delivery of the DUF6, which is capitalized ascost of the fuel being purchased.

Under the Depleted Uranium Enrichment Program(ý(DUEP),

Energy Northwest purchased from USEC all oftheSeparative Work Units (SWU) contained in the EUP.Upon finalization of the program, Energy Northwest hadpurchased a total of 481.6 MTU of EUP from USEC at a costof $687.5 million, which is recorded in nuclear fuel, net ofaccumulated amortization, as of June 30, 2013.Energy Northwest and IVA have entered into anagreement for the sale and purchase of a portion of theSWU and Feed Component of the EUR The sales underthe agreement are expected to total approximately

$731million.

The sales under this agreement are scheduled totake place between 2015 and 2022.Energy Northwest has a contract with DOE that requiresDOE 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 DOEwill fulfill this legal obligation and begin accepting spentnuclear fuel.When the fuel is placed in the reactor the fuel cost isamortized to operating expense on the basis of quantityof heat produced for generation of electric energy. Theamount moved to spent fuel for cooling increased

$55.3million.

Fees for disposal of fuel in the reactor areexpensed as part of the fuel cost.The current period operating expense for Columbiaincludes an $8.1 million charge from DOE for future spentfuel storage and disposal in accordance with the NuclearWaste 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 atemporary dry cask storage facility to be used until DOEcompletes its plan for a national repository.

ISFSI will storethe spent fuel in commercially available dry storage caskson a concrete pad at the Columbia site. No casks wereissued from the cask inventory account in FY 2013. Spentfuel is transferred from the spent fuel pool to the ISFSIperiodically to allow for future refueling.

Current periodcosts were $2.1 million for dry cask storage costs whichare recorded in nuclear fuel expense.Designer:

Ben StewartEditor: AngeLa WaLzEnergy Northwest 2013 Annual Report

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