GO2-12-019, 2011 Annual Financial Report

2011 Annual Financial Report

ML12047A130
Person / Time
Site:	Columbia
Issue date:	02/06/2012
From:	Gregoire D Energy Northwest
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
GO2-12-019
Download: ML12047A130 (77)

Text

ENERGY NORTHWEST Donald W. Gregoire Manager, Regulatory Affairs P.O. Box 968, Mail Drop PE20 Richland, WA 99352-0968 Ph. 509-377-8616 F. 509-377-4317 dwgregoire

@ energy-northwest.com February 6, 2012 G02-12-019 10 CFR 50.71 (b)U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

COLUMBIA GENERATING STATION, DOCKET 50-397 2011 ANNUAL FINANCIAL REPORT

Dear Sir or Madam:

In accordance with 10 CFR 50.71 (b), enclosed is a copy of the Energy Northwest 2011 Annual Report for the subject facility.There are no commitments contained in this letter or its enclosure.

Should you have any questions, please call Zachary Dunham at (509) 377-4735.Respectfully, DW Gregoire Manager, Regulatory Affairs

Enclosure:

As stated cc: NRC RIV Regional Administrator w/o NRC NRR Project Manager w/o NRC Sr. Resident Inspector

-988C w/o RN Sherman -BPA/1 399 w/o WA Horin -Winston & Strawn w/o ,4 004 GENERATING POWERFUL SOLUTIONS

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• WILLIAM BAKER -BRIAN BURKE J DAVID CH MICHAEL LAUDISIO -SLAl , DAD N -DOUGLAS WOCR I1I1GON O TARA JONES JEEFERY ILARSEON -VERNO T IMO , ALLEN B FINE ST KIiFIN CARLY KREF 2 JERRY N' BR 0 CHA Sý AAC MOH .TONY 51 0 NNFF L CAR~

• ODFL F --FRE *R .KATH' 'N~P RA WITCH IM JA GAR', BR BARBARA ROGE BR] TIP R LI F.HF T JAC !U lf1 IGUEL LAB BRL', JASON AMBER KEVINMC DONAM I DOUG N RT o DONA ° ST .OY[ S PAUL HFFL ARD EN[tl GUL[F Y HN DOEKEN/\1l PARKER IYFLEMING RtS-ENSEN JOHN MAY I OUIS 110 F W I , STi tiI/ WEBB NMADElIN R SANKER LA' LANL I LAS BEAL]]GEBRFSON 4 A Mesget Our S akeodr 6 Exctv Board .15 Pacwoo Lak Hyreeti Project 19 Wht Blff Soa Statio 20 Geeato Prjc Develpmen 24 Caibato Se-ie Lbrtr 28 Co m nt Service-32 ~ ~~~ MaaeetRprS nRsosblt o iaca eotn 32 AdtS ea n iac o mte him nsLte 3 Report of IndpnetAdtr A MSAG TOOU SAKEODR 20 1 will alasbevee 5 outage, the contractor presented us with a revised work schedule for the 53-day project. We received multiple revisions during the course of the contractor's work, ultimately resulting in a 143-day project and much longer-than-planned outage duration.

We consistently stated our disappointment in their contract breach. Although their performance remains an ongoing issue, the new condenser will provide enormous benefit to Northwest ratepayers, essentially paying for itself over time through increased generation efficiency.

Despite outage challenges at Columbia which impacted the capital budget, the Energy Northwest team took measures to reduce the operations and maintenance budget, to remain within our long-range plan commitment, ending the year $3.4 million under budget, underscoring our dedication to fiscal discipline and responsibility, and our promise to the region's ratepayers.

Additionally, bond sates in March and June translated into approximately

$220 million in reductions for ratepayers during the 2012-2013 rate period. This also enabled Bonneville Power Administration to use the cash freed up by these sates to pay off its higher-interest U.S. Treasury bonds, resulting in savings for the region and restoring BPA's Treasury borrowing authority.

Through this partnership with BPA, debt on Columbia, which was scheduled to be paid off in 2012, was extended into the future.Among our other projects, the agency's first generation resource at Packwood Lake had an incredible year. A high-water season helped Packwood Lake Hydroelectric Project yield nearly 108 gigawatt-hours, the dam's highest output in 12 years.Energy Northwest people also offered powerful solutions through the contribution of their time and skills to support the needs of our communities.

In December, we marked the 30th anniversary of our support to Head Start. We're stilt honored to lead this heartfelt holiday effort that has brought much needed joy to more than 10,000 underprivileged children in the Tri-Cities and surrounding areas since 1980.The greatest strength of Energy Northwest is our remarkable people, who have shown they can rise to any challenge.

We continue to progress in the long process of returning Columbia to top performance.

To achieve this, safety and accountability must remain at the core of everything we do. And we must manage our risks, develop our leaders and continue to demonstrate fiscal responsibility.

We define our success by the enduring value we create for our stakeholders, employees and communities.

We are confident that as we continue to focus on the mission of providing our public power members with safe, reliable and cost-effective power, Energy Northwest will emerge a stronger agency benefiting our stakeholders, employees and communities for many decades to come.Respectfully, Mark Reddemann Sid Morrison Chief Executive Officer Chairman, Executive Board

'ý-,K :-EG OT, S 0 " 0 T\ D Y6 7 ANN CONGDON President Commissioner, Chelan County PUD Manson, Wash.LINDA GOTT Vice President Commissioner, Mason County PUD 3 Shelton, Wash.BILL GORDON Secretary Commissioner, Franklin County PUD Pasco, Wash.JUDY RIDGE Assistant Secretary Commissioner, Asotin County PUD Clarkston, Wash.DOUG AUBERTIN Commissioner, Ferry County PUD Keller, Wash.NANCY BARNES Commissioner, Clark Public Utilities Vancouver, Wash.TERRY BREWER TOM CASEY Commissioner, Commissioner, Grant County PUD 2 Grays Harbor County PUD Soap Lake, Wash. Aberdeen, Wash.LARRY DUNBAR Deputy Director of Power Systems, City of Port Angeles Sequim, Wash.BILL UAIA'lJb Director of Utilities, Tacoma Public Utilities Tacoma, Wash.DAN LiUUNK.L Commissioner, Klickitat County PUD Goldendale, Wash.BOB HAMMOND Energy Services Director, Richland Energy Services Richland, Wash.BOARD OF DIRECTORS T he Energy Northwest Board of Directors includes a representative from each of its member utilities.

The powers and duties of the board of directors include final authority on any decision to purchase, acquire, construct, terminate or decommission any plants and/or facilities of Energy Northwest.

Board members represent utilities with strong histories of serving the public power needs of Washington ratepayers.

Their experience helps guide the agency as a continuing and effective source of powerful energy solutions.

JACK JANDA Commissioner, Mason County PUD I Shelton, Wash.ROBERT JUNGERS Commissioner, Wahkiakum County PUD Cathlamet, Wash.BUZKETCHAM Commissioner, Cowlitz County PUD 1 Kalama, Wash.STEVE KERN Power Supply and Environmental Affairs Officer, Seattle City Light Seattle, Wash.CURT KNAPP Commissioner, Pend Oreille County PUD Newport, Wash.CLYDE LEACH Commissioner, Skamania County PUD Underwood, Wash.CHUCK TENPAS Commissioner, Lewis County PUD Randle, Wash.KEN MCMILLEN Commissioner, Jefferson County PUD Port Hadlock, Wash.MIKE MURPHY Commissioner, Whatcom County PUD Bellingham, Wash.KATHY VAUGHN Commissioner, Snohomish County PUD Lynnwood, Wash.WILL PURSER Commissioner, Clallam County PUD Sequirn, Wash.LORI SANDERS Commissioner Benton County PUD Kennewick, Wash.I DAVE WOMACK Commissioner, Okanogan Public Utilities Okanogan, Wash.ROGER SPARKS Commissioner, Kittitas County PUD Ellensburg, Wash.DIANA THOMPSON Commissioner, Pacific County PUD 2 Oysterville, Wash.ED WILLIAMS Commissioner, Centralia City Light Centralia, Wash.

DAEAKNO RDSWAZE MR ED N J AC BAE RN IG 9 PROJECT 7,247 GWh 107.92 GWh 264.74 GWh Columbia produces 1,150-megawatts of electricity, enough energy to power more than a million homes.COLUMBIA Generating Station Packwood has produced 4,359,610 megawatt-hours of electricity since commercial operation began in 1964.PACKWOOD LAKE Hydroelectric Project The total Nine Canyon generating capability is 95.9 MW, enough energy for approximately 39,000 homes.NINE CANYON Wind Project White Bluffs produced 39,336 net kilowatt-hours of electricity during fiscal year 2011.WHITE BLUFFS Solar Station J 10 Energy Northwest 2011 Annual Report COLUMBIA v KAREN McGAUGHEY"As purchasing lead, preparing for and supporting refueling outages for Columbia is one of my responsibilities.

I worked with my team to meet milestones related to identifying necessary parts; ensuring approvals were given in a timely manner; and that materials were received well in advance of the start of the outage.It's a challenging position but very rewarding." olumbia Generating Station continues to operate safety and efficiently, providing valuable electrical power to the region.Online performance improved in fiscal year 2011 with no shutdowns or forced outages. However, during the fiscal year, reduced power periods were implemented to make necessary repairs to plant equipment, which resulted in not meeting net generation goats by less than two days. Columbia was shut down in early April for its biennial refueling and maintenance outage (see next page).The shutdown marked the end of Columbia's longest continuous run record at 505 days, besting the old record of 485 days set in 2006.However, the challenges driven by equipment problems during the last two years resulted in a lower performance compared to industry peers. In fiscal year 2011, there is a renewed focus and plan for continual improvement with the addition of a nuclear Excellence Model as part of the Excellence in Performance initiative.

74 7 ial year 2011 T1 11 Columbia Generating Station is a boiling water reactor, or BWR. Columbia produces 1,1 50-megawatts of electricity, enough energy to power more than a million homes. Columbia began commercial operation in December 1984.The excellence plan will also drive improved individual behaviors and accountability for overall improved performance.

In addition to plant performance challenges, the station supported many reviews by external agencies, which al[ concluded the plant is operated safely.Training is maximized to ensure both new and current employees receive the necessary skills and knowledge for achieving excellent performance levels. In fiscal 2011, accreditation was renewed for Energy Northwest's technical training programs by an external independent review board.

1 2 Energy Northwest 2011 Annual Report REFUELING OUTAGE TWENTY V TINA MALTOS Refueling outages are busy times around nuclear energy facilities

-thousands of people performing thousands of tasks. Energy Northwest employs advanced scheduling software to make sure nothing gets missed. This outage, Tina Maltos, Project Control Integration analyst, played a key role in making sure all departments worked seamlessly with the software -increasing efficiency throughout the organization.

R efueling Outage 20 began April 6 and ended Sept. 27 with Columbia Generating Station's reconnection to the Northwest power grid. It involved the largest equipment repair scope in Columbia's history, with the most significant task being the replacement of the steam condenser.

More than 1,800 contract and temporary workers were hired to accomplish the outage work, which included 3,380 work orders and nearly 16,500 individual tasks in support of a more than $170 million overall investment.

Contractor delays in the condenser replacement project extended the outage duration from a scheduled 78 days to 174 days -into fiscal year 2012. As a result, outage duration goals were not met.In addition to the condenser replacement, 244 of Columbia's 764 nuclear fuel assemblies in the reactor core were replaced with new assemblies; there were replacements and repairs of multiple other major components that have contributed to past equipment performance issues. Columbia's reliability will be significantly improved due to these initiatives.

Major R-20 outage PROJECTS: Condenser replacement Non-segregated bus repair and inspection Main generator rotor replacement Overhaul of one low pressure turbine Overhaul of two diesel generators Control rod hydraulic unit directional control valves replacement Reactor recirculation motor oil level alarm modification Reactor water cleanup piping replacement Refurbishment, overhaul and replacement of valves CONDENSER Replacement Project The condenser turns steam that has flowed through the turbine back into water for re-use in the reactor. It comprises 12 modules, each containing more than 6,000 titanium tubes, and nine waterboxes that direct clean water from the cooling towers through the tubes and back to the cooling towers. The 26-year-old condenser was becoming less reliable over time. Columbia is expected to gain more than 12 megawatts of electricity generation with the new condenser.

PUM THERESA NEIDHOLD b"Foreign Material Exclusion programs, or FME, are always important.

But refueling outages are a time when many major components are open -disassembled

-and susceptible to foreign material events, which can cost nuclear energy facilities millions of dollars. The focus has to be preventing the foreign material from entering systems. The results from our recent refueling outage showed we are embracing industry best practices to prevent significant FME events from happening.

I am proud of the job we did and continue to do in this area."

14 Energy Northwest 2011 Annuat Report RENEWAL enewal of Columbia Generating Station's operating license is key to meeting the region's future electricity needs. The initial 40-year license was granted in December 1983 (commercial operation began in December 1984), and in January 2010, Energy Northwest filed a 2,200-page application with the Nuclear Regulatory Commission for a 20-year license extension.

Energy Northwest anticipates Columbia's license to be renewed by summer 2012.To obtain renewal, Energy Northwest must demonstrate to the NRC plant structures and equipment can continue to safety function for the duration of continued operations, through 2043.NRC staff visited Columbia for two separate inspections as part of the renewal process, during October and November 2010. The NRC issued the subsequent inspection report with no violations and no findings.The Energy Northwest team responded to 293 NRC requests for additional information.

Public involvement is an important part of the license renewal process. Energy Northwest held two open house-style "information nights" in January 2011 where the public learned more about the agency, Columbia's safe operation, the local economic impact of Columbia and the license renewal process. Additionally, the NRC held a public meeting in June 2011 in Richland, Wash.Columbia can safety produce electricity many years beyond its current 40-year license. This average licensing term for all U.S. nuclear energy facilities was specified by Congress under the Atomic Energy Act of 1954 and was not based on safety, technical or environmental factors but rather on financing purposes; this was simply a typical amortization period for an electric power plant.years to -cs enrg -muc loe tha wind soa an te eeal wa 10,2 megaatt-our

-up2 pecn fro 2010 -prmail du tom r prcptto an hihe snofal [e t .n the- Cacd range Th caact factor foisa 2011 was 47. peren an the prjc ataie 99. pecn avilailt.Pakodhsprdcd43961 eaathur ic o mrca prto began in 19a64.- g ,-- --The-- -proec was grne a cotnac to oprt une it exstn lie nsa by the Fedra Enrg Reuatr Co mssin thug th fia licns aplcto wa sumite in 209 Snho is Cont Puli Utiit Ditrc cotnudt pucAs aO sgicantprino h ln' upt 16 Energy Northwest 2011 Annual Report NINE CANYON Wnd Project T he Nine Canyon Wind Project is one of the Largest publicly owned wind projects in the nation. With 63 wind turbines -14 rated at 2.3 megawatts and 49 more at 1.3 megawatts

-Nine Canyon's total installed capacity is 95.9 megawatts.

Fiscal year 2011 produced 264,738 net megawatt-hours of electricity, a record for the project, and achieved a 97.4 percent adjusted availability factor, down from 98.2 percent in fiscal 2010. This decline is directly related to tower welding warranty work conducted by the supplier of Phase III equipment to correct manufacturing defects by the vendor. To ensure long-term reliability, Energy Northwest worked with a new bearing supplier to develop a more robust design projected to have twice the service life of the original bearings.Energy Northwest also coordinated plant controls to respond to the Bonneville Power Administration's "limit to schedule" requirement caused by the installation of 3,500 megawatts of wind projects in the region and the operating requirements of BPA's hydropower system.With a vision to be the region's leader in energy generation, Energy Northwest partnered with Walla Walla Community College to host the first wind technician intern program to increase the availability of a local skilled workforce to enter the growing wind energy job market.V DAN ROSS Dan Ross successfully made the transition from water to wind. After years of managing the Packwood Lake project, Ross took over Nine Canyon and led the project during its best generation year ever. Before leaving Packwood, he was instrumental in Energy Northwest's efforts to extend the project's license. Ross now manages both Packwood and Nine Canyon. But why limit yourself?When Columbia's condenser project needed a craft supervisor, the call went to Dan.

GVV infiscal wa:

19 WHITE BLUFFS Solar St]ti hite Bluffs Solar Station, a 242-panel demonstration facility with a rating of 38.7 kilowatts direct current, is located at the Industrial Development Complex near Columbia Generating Station. White Bluffs produced 39,336 net kilowatt-hours of electricity during fiscal year 2011.The Bonneville Power Administration integrates the power from White Bluffs into its system and Bonneville Environmental Foundation markets the displaced air pollution and greenhouse gas emissions as "green tags." Buyers who participate in utility green power programs purchase these tags to replace traditional polluting sources of electricity with clean, secure and sustainable renewable sources of energy from across North America.Energy Northwest is using the White Bluffs site for two additional solar energy demonstration projects.Homestead-01 is a 2,025-watt thin-film demonstration array to compare capture efficiencies against the White Bluffs crystalline panel design. The thin-film type is less expensive, but also less efficient.

Testing on the project occurred throughout fiscal 2011. Homestead-02 is similar, but uses a different manufacturer's panels and has a tower capacity of 1,280-watts.

KWh in fiscal year 2011 20 Energy Northwest 2011 Annual Report GENERATION Project Development E nergy Northwest is recognized in the region as an experienced power generation developer.

The major development activities in fiscal year 2011 centered on providing member utilities generation supply options that align with regional renewable policies and power markets.The agency works with its members to understand and anticipate their thermal and renewable resource needs and identify regional generation supply opportunities to develop appropriate tow-cost resources.

The goal is to offer competitive generation supply options and solutions to meet utility member needs. The process includes technology evaluation, financial analysis, site selection and acquisition, development marketing and funding, plant permitting and infrastructure interconnection (right of way permits and easements, as welt as interconnection agreements to major pipelines, transmission lines, water and discharge, and other utilities) among other supporting services.The major challenges to developing new generation projects in the Northwest include raising investment funding for developments prior to completing power purchase agreements.

The timeline for project site selection, engineering, permitting and infrastructure interconnection ranges from two to four years and construction can range from six months to three years depending on the technology involved and complexity of the project. A typical generation project development needs to anticipate market demand several years in advance of actual utility needs.Additionally, the economy and hydroelectric power in the Northwest drives agency members and other regional utilities to seek the lowest cost power for their customers.

The high percentage of regional hydropower creates market uncertainty and periodic price dilution.Finally, transmission and pipeline interconnection processes are becoming complex and may take more than two years to complete.I I The agency works with its members to understand and anticipate their thermal and renewable resource needs and identify regional generation supply opportunities to develop appropriate low-cost resources.

mm 22 IWOOOAPEL he Applied Process Engineering Laboratory is a business incubator that supports start-Lip and acceleration of nevý technologies, and technotogy-based businesses.

Energy ýIorthwest and local partners createct APEL by convertino a ,,)aoehOUSe into laboratory, office and light manufacturing rental space, making it a key part of Energy florthv,/est's continuring, commitment to local econorý,'Ic de/elopment.

APEL fiRs a community need for bjsiness ýfarter space and provl(IeS SUitable environments for controtted testing, of ad,/anced processes.

Located in the heart of the Tri-Cities Research District inno/ation Partnership Zone, APEL is thp "launch pad" to teveraae reaiona[ techno[ocica[

expertise intr. early stave entiepieneUrial ventUres.

By cteatin,,ý an enviroriment rich resoutce5, terhnical asistance and conn(ýction,, to potentiat paitneis and customr.-,rs, APEL fosters collaboration in innovation and cornmerciahzation.

APEL výekomc--d a new ( hent during fisca( year 2011 , and expects another client to complete the inculbatoi proo.fam ýLiccessfully in earty fiscal 2012.In fisal 2011, APEL viorked effectively to broaden its mission to Include services for non-lenant clients. Historicatly, ervice,, were provided to tenant clients via a[ea.e cr)ntract only. To provide service, to expandino and emeraing businesses, APEL scýjzed the opportunity to expand its rea( h to non-t esident clients. This meets two o5jectives:

Suppotting bu,,jne,,,,es that do not need physical ýpaccý on in onaoin',), haris (hut simply a short-tet m laborMot y ic-rital or use of office/confet en(ýe space for key rneetina,) )nd, (,xl)o,,ij[-(, for rnore husinesses the entrepteneuts and their piodw ts to the APEL. (-orrii-nimill y, whic h rýnhýmce,_, (_o[lriborai jon ý-rnd intitual"uppol t.Mojor 111'Jitution" 11) the -111 Citi(-, mppw t ind APEL in(Indim), Enetoy in(, Poll, of k1rnioii, thf, of Fiw i(ýy, M ishiwý,toii IA(Ite Tti-(M(-,, Ri( h( llottlwýw.l 11,fljon.-il I ýfl)otltoly, 111f, ( Ily ot RI(I)I'llid rll)d tll(, 1-11 (Ow" 111(k]"tri'll DevOnpinont Cotjn(,i(.

APEC,, op(ýiýitinq (o,,tý mc (ovel(ýd hy tenalit tont.

23 T he Industrial Development Complex is located just east of Columbia Generating Station and is operated by Energy Northwest.

A leasing business line was developed to utilize the out-lying buildings at the IDC for use as office and warehouse space, as well as power block facilities.

The revenue from the leasing program reduces the fixed costs for the IDC site, which are the responsibility of the Bonneville Power Administration.

Fiscal year 2011 revenue from the leasing line totaled more than $1.26 million, a net positive margin of $236,000, an increase of $74,000 over fiscal 2010. This success provides ID C Energy Northwest with the ability to continue maintenance efforts on site and prepare additional structures for potential lease. It also reflects expansion of f-A T- business by IDC tenants and additional service needs provided by Energy Northwest.

A significant challenge the DC faced during fiscal 2011 was correcting power outages due to an aging underground electrical system. An underground cable was installed approximately 30 years ago and, at the time, was only meant to be temporary.

Energy Northwest worked closely with BPA in completing approximately

$600,000 of immediate repairs needed to continue servicing IDC customers.

A long-range plan is being developed to replace the remaining temporary cable to ensure reliability of the power system.Energy Northwest will continue to maintain the leasing business line at IDC, focusing on landing an anchor tenant, or tenants, for long-term occupancy of the facilities.

The success of the leasing program will aid in many ways. The program will keep an active Energy Northwest staff on site to maintain and improve the infrastructure, and help complete studies on placing new power generation projects at the IDC, such as solar, nuclear or bio-fueLs facilities.

Fiscal year 2011 revenue from the leasing line at the IDC totaled more than 1.26 24 Energy Northwest 2011 Annual Report CALIBRATION SERVICES Laboratory alibration services operates and maintains the Energy Northwest Standards Laboratory, located adjacent to Columbia Generating Station. This facility is a multi-disciplined applied physics laboratory performing calibrations in virtually every aspect of metrology, including torque, force, pressure, vacuum, mass, dimensional, electrical, electronic, temperature, humidity, flow, vibration, tight and sound.In addition to primarily providing services to Columbia Generating Station, the Standards Laboratory performs work in the commercial sector, which has helped develop and expand the laboratory's capabilities, increased the technical expertise of the staff, and enhanced its quality program.In fiscal year 2011, laboratory staff successfully completed the American Association for Laboratory Accreditation on-site assessment process and the laboratory was officially re-accredited.

This status provides assurance to customers that calibration activities are in compliance with International Standard ANS/ISO/IEC 17025, which designates the Requirements for Competence of Testing and Calibration Laboratories.

The laboratory was first accredited in January 2009, and has since been on an annual assessment schedule.

Having successfully completed its third year of the annual assessments, the association has now moved the laboratory to a two-year accreditation cycle. The laboratory's current accreditation is valid through January 2013.Maintaining accreditation, enhancing capabilities and continually making improvements to technical and quality programs have at[ been factors in securing multi-year contracts with several major clients. The laboratory is heading into its 12th year as the sole source provider for calibration services to the Department of Energy's Hanford Site. The current Hanford service contract was extended to Sept. 30, 2011, while the parties negotiate a new multi-year calibration services contract.

S ato duin fica yea 2011. Opeaton a n Maneac Sevie ha prvie serice ful tim fo th prjc sic 2001.Th Olm i Vie Geeatn Stto is owne by Maso Co6t Pubic U ilt Ditrc 3 an co pie tw 6 .-e t geeatn unts powere bynaturalgas-fired reirctn enins Th no ia l stto oupu is 5.4 ne megaatt. Th pant ma be operate reoey deenin onI load6.Bondr Hyreeti Project~.

Locte on th Pen Oril Rive in noteatr Wahigtn th-a upism r hn n-hr fSateCt EN IR NM N AL or mor tha 15 yerEegotws' ANALY I AL Eniomna an Anltia Sevie Laboator F as prvie chmia anlyi anniomna SE V C Smntrn xets o uiiy uiia n eieta aAO AT 1L customers.

During fica yea 201 aoaoy-tf otne to pefr th key envro mena asseset at the Shphrs lt id amlcae i orhcetas-Orgn Owe yCihesShped-lt L ofSara eno Cai. 6 h prjc' most reen deig has* th faciit prdcn 84 -eawtto elcrct fro 33 win tubns Labraor woke inovm n wit the prjc ha bee on- going sinc S2002.. 55 5 -- S 5 ~ a *Wor onohrpoet nlddprorigiiilainsuisa apooe idfclt oae alon th Wahngo and Orego bode jus sot of Watua Was. *.

26 Energy Northwest 2011 Annual Report V AUDREY DESSERAULT The Energy/Business Services group consists of several business lines. Their business purpose is varied, but they have the same expectation

-maintain environmental stewardship. "We provide several goals so employees at all levels can have an impact on the organization's environmental objectives and targets. I have great advocates in each of the E/BS departments who are ensuring that the EMS program remains strong." ENVIRONMENTAL STEWARD SHIP E nergy Northwest's Environmental Management System is designed to meet the rigorous requirements of the globally recognized International Organization for Standardization 14001:2004 standard, with additional emphasis on compliance and pollution prevention.

Energy Northwest's EMS was registered to ISO 14001 in April 2005 by NSF International Strategic Registrations, an accredited registrar.

After a successful registration audit in February 2011 with no findings of non-conformance, continuation of Energy Northwest's EMS registration to the standard was granted.During fiscal year 2011, Energy Northwest established and exceeded environmental improvement targets for reduction of hazardous materials spills and hazardous waste generation and mixed waste generation at Columbia Generating Station.Energy Northwest is committed to integrating environmental responsibilities into everything the agency does. The agency's environmental stewardship policy is the cornerstone of the environmental management system. This comprehensive program demonstrates commitment and establishes clear expectations for the entire organization.

This means consideration of the environment is integrated into all aspects of the organization, including structure, resources, responsibilities, planning, practices, procedures and processes.

27 The regulated waste program has been enhanced by modifying the process of how waste generation is tracked. Through this change more accurate waste generation data will provide information to identify further waste reduction opportunities.

Several pollution prevention opportunities were identified and implemented in fiscal year 2011. These included changing the management of photochemical waste to minimize the regulated (hazardous waste) volume; reduction of vehicle emissions by use of an electric cart for deliveries of materials from the warehouse to Columbia Generating Station; and reduction of paper/packaging waste through use of technology and re-use.BRAD BARFUSS 1"Environmental stewardship is central to what I do and the decisions I make each day. My role is to support Energy Northwest projects by providing regulation-based guidance to ensure environmental and regulatory compliance.

Environmental stewardship is holding myself and the organization accountable to do the right thing, the first time, with the aim to continuously look at ways to improve our interactions with the environment."

28 Energy Northwest 2011 Annual Report From the CEO to the newest employee, Energy Northwest cares about the Tri-Cities community through direct, hands-on involvement.

COMMUNITY SERVICE D uring fiscal year 2011, Energy Northwest increased community outreach efforts to strengthen the agency's image as a regional energy leader and to educate key audiences about energy issues facing Washington state.The need to reach stakeholders beyond the immediate support base in the Tri-Cities is of vital interest to the agency, especially as it undertakes Columbia Generating Station's license renewal effort and explores new power generation development for member utilities in other parts of the region.One of the community and educational outreach opportunities Energy Northwest participated in this past fiscal year included energy conservation and efficiency education trivia, which appeared across Washington state in movie theaters, newspapers, online, and ran on radio and television stations.Energy Northwest participated in several energy and environmentally related events such as the Sustainable Energy and Environmental Expo; the Hanford Health and Safety Expo; Harvesting Clean Energy; Energy Independence Day; and Imagine Tomorrow, a Washington State University science and energy-oriented event for high school students.Energy Northwest employees also spoke to a wide range of audiences, including a workshop in Olympia for the Washington state House Technology, Energy and Communications Committee to inform legislators about nuclear energy, Energy Northwest, its projects and people.Additionally, Energy Northwest has been a member of the local Tri-Cities business community for more than 50 years. As a major non-Hanford employer, the agency strongly believes in the importance of supporting the communities and non-profit agencies where employees work and live.4 CINDY WAY"Our 2010 Head Start campaign was our 30th year. We could not accomplish this year after year without the overwhelming generosity of our employees.

Our employees enjoy the experience just as much as the kids who receive the gifts. Our internal committee volunteers work diligently through November and December, and with the folks at Head Start, to ensure all children are"adopted," all gifts have been received, and all parties are a success." 10 CRAIG WITTE The professionals at Energy Northwest are experts in many fields, which benefits the organization in the daily operation of multiple power generation projects.

But it can also benefit the community.

When a local non-profit organization needed help in the field of architecture, Craig Witte was able to step up and volunteer his expertise.

Energy Northwest is proud to support its employees who volunteer their time-and their knowledge

-to make the community a better place to live.

29 The agency officially sponsors three vital community organizations:

Head Start, United Way and March of Dimes.Head Start In fiscal year 2011, Energy Northwest celebrated the 30th anniversary of supporting the Benton Franklin Head Start program (since 1980).Each year, Energy Northwest commits to adopting every Head Start child for the holiday season. In fiscal 2011, nearly 400 children were "adopted" by employees.

Each child provided a wish list to Santa and received at least one toy and one clothing item. The gifts were distributed by Energy Northwest employees, playing Santa and his elves, during various Head Start parties.The Head Start program is the most successful and longest-running school readiness program in the U.S. It provides comprehensive education, health, nutrition and parental involvement services to low-income children and their families.More than 25 million pre-school aged children have benefited from Head Start and the number of children served in Benton and Franklin counties has more than doubled in the past two decades.United Way Approximately 171 employees donated nearly $79,000 to United Way in 2010. And four stepped forward to join the United Way Vintner Club leadership program for a total of 29 employees currently in the Vintner Club. These pledges help provide hot meals to elderly neighbors, fund youth developmental programs, provide disaster relief planning for our community and build self-esteem in at-risk youths.March of Dimes Energy Northwest's "power marchers" team raised$21,020 this year for the March of Dimes, exceeding the goal and once again demonstrating the philanthropy and generosity of employees.

About 35 walkers from Energy Northwest, along with their spouses, children and pets, participated in the 2011 Tri-Cities March for Babies event that helps support neo-natal birth centers and local families in need.Head StartIM Unite 1, 1 Ivl I 4 Other activities Energy Northwest participated in include: Earth Day Clean-up Energy Northwest and AREVA employees worked together for the community during a volunteer Earth Day clean-up project. In all, 21 Energy Northwest employees participated, filling about 60, 40-gallon bags with paper, plastic, cans and other debris.Energy Northwest is committed to taking care of the environment.

Energy Northwest's commitment is formally certified by the International Organization for Standardization, which underscores the agency's compliance to international environmental standards and provides third-party validation that Energy Northwest's environmental stewardship and management efforts are both effective and sustainable.

The clean-up activity reflects both organizations' commitment to the Tri-Cities community and the environment.

Member Forum Climate change, wind power and the legislative energy landscape were key topics during the Energy Northwest 13th annual Member Forum.Headlining the event was Dr. Patrick Moore, a co-founder of Greenpeace and staunch commercial nuclear power advocate.More than 90 commissioners, managers and other representatives from the agency's 28 member utilities attended the annual event, which is an important venue for a regional public power community that serves more than 1.5 million ratepayers across Washington state. The forum provides utility representatives an opportunity to meet and listen to speakers on regional and national energy issues, and to discuss solutions to key challenges facing public power. Participants also have the opportunity to network with other members and utility leaders.

30 Energy Northwest 2011 Annual Report PEOPLE S..'GENERATING POWERFUL SOLUTIONS I RAVIS BLST JOHN STEIGERS TRACEY BROWN 0@FINANCIAL DATA &INFORMATION 32 [nerp~ North~wets 2011 AnnuaL Report Management Report on Responsibility for Financial Reporting Energy Northwest management is responsible for preparing the accompanying financial statements and for their integrity.

They were prepared in accordance with generally accepted accounting principles applied on a consistent basis, and include amounts that are based on management's best estimates and judgments.

The financial statements have been audited by PricewaterhouseCoopers LLP, Energy Northwest's independent auditors.

Management has made available to PricewaterhouseCoopers LLP all financial records and related data, and believes that all representations made to PricewaterhouseCoopers LLP during its audit were valid and appropriate.

Management has established and maintains internal control procedures that provide reasonable assurance as to the integrity and reliability of the financial statements, the protection of assets from unauthorized use or disposition, and the prevention and detection of fraudulent financial reporting.

These control procedures provide appropriate division of responsibility and are documented by written policies and procedures.

Energy Northwest maintains an ongoing internal auditing program that provides for independent assessment of the effectiveness of internal controls, and for recommendations of possible improvements thereto.In addition, PricewaterhouseCoopers LLP has considered the internal control structure in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements.

Management has considered recommendations made by the internal auditor and PricewaterhouseCoopers LLP concerning the control procedures and has taken appropriate action to respond to the recommendations.

Management believes that, as of June 30, 2011, internal control procedures are adequate.M.E. Reddemann Chief Executive Officer B.J. Ridge Vice President, Chief Financial Officer/Chief Risk Officer Audit, Legal and Finance Committee Chairman's Letter The Executive Board's Audit, Legal and Finance Committee (Committee) is composed of 11 independent directors.

Members of the Committee are Chair Larry Kenney, Marc Daudon, Dan Gunkel, Jack Janda, Skip Orser, Will Purser, Dave Remington, Lori Sanders, Tim Sheldon, Kathy Vaughn and Sid Morrison, Ex-Officio.

The Committee held 10 meetings during the fiscal year ending June 30, 2011.The Committee oversees Energy Northwest's financial reporting process on behalf of the Executive Board. In fufilling its responsibilities, the Committee discussed with the internal auditor and the independent auditors the overall scope and specific plans for their respective audits, and reviewed Energy Northwest's financial statements and the adequacy of Energy Northwest's internal controls.The Committee met regularly with Energy Northwest's internal auditor and convened periodic meetings with the independent auditors to discuss the results of their audit, their evaluations of Energy Northwest's internal controls, and the overall quality of Energy Northwest's financial reporting.

The meetings were designed to facilitate any private communications with the Committee desired by the internal auditor or independent auditors.Larry Kenney Chairman, Audit, Legal and Finance Committee I f() 33 Report of Independent Auditors To the Executive Board of Energy Northwest:

In our opinion, the financial statements of the business-type activities of Energy Northwest (the "Company"), including the Columbia Generating Station, Packwood Lake Hydroelectric Project, Nuclear Project No. 1, Nuclear Project No. 3, the Business Development Fund, the Nine Canyon Wind Project, and the Internal Service Fund which collectively comprise the Company's balance sheets, statements of revenues, expenses and changes in net assets, and of cash flows, present fairly, in all material respects, the respective financial position of the business-type activities of the Company at June 30, 2011, and the respective changes in financial position and cash flows, where applicable, thereof for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management.

Our responsibility is to express opinions on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.

We believe that our audit provides a reasonable basis for our opinions.The Management's Discussion and Analysis listed in the table of contents is not a required part of the basic financial statements but is supplementary information required by the Governmental Accounting Standards Board. We have applied certain limited procedures, which consisted principally of inquiries of management regarding the methods of measurement and presentation of the required supplementary information.

However, we did not audit the information and express no opinion on it.LI-," Portland, Oregon October 27, 2011 34 [nervy Nor thwest 201 1 Annual, Report 000 Energy Northwest Management's Discussion

& Analysis Energy Northwest is a municipal corporation and joint operating agency of the State of Washington.

Each Energy Northwest business unit is financed and accounted for separately from all other current or future business assets.The following discussion and analysis is organized by business unit. The management discussion and analysis of the financial performance and activity is provided as an introduction and to aid in comparing the basic financial statements for the Fiscal Year (FY) ended June 30, 2011, with the basic financial statements for the FY ended June 30, 2010.Energy Northwest has adopted accounting policies and principles that are in accordance with Generally Accepted Accounting Principles (GAAP) in the United States of America. Energy Northwest's records are maintained as prescribed by the Governmental Accounting Standards Board (GASB) and, when not in conflict with GASB pronouncements, accounting standards prescribed by the Financial Accounting Standards Board (FASB). (See Note 1 to the Financial Statements.)

Effective July 1, 2009, the FASB issued the Accounting Standards Codification (ASC).The ASC does not change GAAP and does not have an effect on Energy Northwest's financial position or results of operation.

Technical references to GAAP included in this report are provided under the new ASC structure.

Because each business unit is financed and accounted for separately, the following section on financial performance is discussed by business unit to aid in analysis of assessing the financial position of each individual business unit. For comparative purposes only, the table on the following page represents a memorandum total only for Energy Northwest, as a whole, for FY 2011 and FY 2010 in accordance with GASB No. 34, "Basic Financial Statements-and Management's Discussion and Analysis-for State and Local Governments." The financial statements for Energy Northwest include the Balance Sheets, Statements of Revenues, Expenses, and Changes in Net Assets, and Statements of Cash Flows for each of the business units, and Notes to Financial Statements.

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

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

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

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

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

Questions concerning any of the information provided in this report should be addressed to Energy Northwest at PO Box 968, Richland, WA, 99352.

35 Combined Financial Information June 30, 2011 and 2010 (in thousands) 2010 2011 Change Assets Current Assets 189,918 $ 225,932 $ 36,014 Restricted Assets Special Funds 93,454 118,860 25,406 Debt Service Funds 421,110 459,183 38,073 Net Plant 1,485,233 1,519,569 34,336 Nuclear Fuel 196,379 266,949 70,570 Deferred Charges 4,306,114 4,027,612 (278,502)TOTAL ASSETS $ 6,692,208

$ 6,618,105

$ (74,103)Current Liabilities 374,924 $ 435,218 $ 60,294 Restricted Liabilities Special Funds 141,811 149,430 7,619 Debt Service Funds 145,396 150,832 5,436 Long-Term Debt 6,022,980 5,875,190 (147,790)Other Long Term Liabilities 12,373 14,028 1,655 Deferred Credits 6,020 5,820 (200)Net Assets (11,296) (12,413) (1,117)TOTAL LIABILITIES AND NET ASSETS $ 6,692,208

$ 6,618,105

$ (74,103)Operating Revenues $ 475,985 $ 552,292 $ 76,307 Operating Expenses 360,876 415,020 54,144 Net Operating Revenues 115,109 137,272 22,163 Other Income and Expenses (113,498)

(138,790)

(25,292)(Distribution)

& Contribution (650) 1,000 1,650 Beginning Net Assets (12,856) (11,895) 961 ENDING NET ASSETS $ (11,895) $ (12,413) $ (518) 36 Eneray Noi~Kt0 Ai[Columbia Generating Station The Columbia Generating Station (Columbia) is wholly owned by Energy Northwest and its Participants and operated by Energy Northwest.

The plant is a 1,150-megawatt electric (MWe, Design Electric Rating, net) boiling water nuclear power plant located on the Department of Energy's (DOE) Hanford Site north of Richland, Wash.Columbia produced 7,247 gigawatt-hours (GWh) of electricity in FY 2011, as compared to 8,124 GWh of electricity in FY 2010, which included economic dispatch of 99 and 119 GWh respectively.

Columbia set a record run of 505 days which ended when Columbia entered its longest planned refueling cycle (R-20) of 78 days on April 1. The planned outage extended past the 78 days and into September of FY 2012. The extended outage, along with the record run occurring mostly in FY 2010 were the factors in the decreased generation of 10.8 percent in FY 2011.Columbia's cost performance is measured by the cost of power indicator.

The cost of power for FY 2011, was 5.69 cents per kilowatt-hour (kWh) as compared with 3.74 cents per kWh in FY 2010. The industry cost of power fluctuates Columbia Generating Station COST OF POWER -Cents/kWh FY2011 FY201C FY 2009 5.69 3.74 4.94 2.75 FY2007 3.69 0 1 2 3 4 5 6 year to year depending on various factors such as refueling outages and other planned activities.

The cost of power increase of 52.1 percent from FY 2010 was due to the planned outage and the impact of the extension of the outage through the end of the fiscal year.Balance Sheet Analysis Columbia Generating Station NET GENERATION

-GWhrs FY2011 FY2010O The net increase to Utility Plant (Plant) and.. Construction Work In Progress (CWIP) from FY 2010 to FY 2011 (excluding nuclear fuel) was $34.4 million. The additions to Ptant/CWIP of $13.3 million were additions to Plant of $59.5 million offset by retirements of $86.0 S7,247 million and an increase to CWIP of $39.8 million. The remaining change of $21.1 million to net Plant was a result 8,124 of a decrease in accumulated depreciation for retirement of the main condenser unit, as part of R-20 ($61.0 million)7,725 and adjustment for a historical correction to accumulated depreciation and net book value of $34.3 million (See 9,594 Note 2 to Financial Statements).

These items were offset against the normal period impacts for FY 2011 of $66.6 8,016 million resulting in the net decrease to accumulated 8,000 10,000 depreciation.

FYI FY 2(FY 200;0 2,000 4,000 6,000 37 The gross addition of $101.1 million to CWIP in FY 2011 was captured in six major projects of at least $2.0 million: Main Condenser Replacement, Main Generator Rotor, Non-Segmented Bus Hardware, Turbine Blade Replacement, Main Transformer, and Cooling Tower Fitl Replacement.

These projects resulted in 81 percent of CWIP activity.The remaining 19 percent were made up of 100 separate projects.Nuclear fuel, net of accumulated amortization, increased

$70.6 million from FY 2010 to $267.0 million for FY 2011. Fuel amounts used for reload increased$47.8 million, fuel removed for cooling increased

$53.5 million. These increases were offset by decreases in fuel loan amount of $3.4 million and $27.3 million in current year amortization.

Current assets increased

$41.0 million in FY 2011 to$193.7 million. The main cause of this increase was due to timing of FY 2012 obligations due July 1 and timing of transfers between current and restricted funds. This resulted in an increase of $25.9 million. Decreases in normal year timing and obligations resulted in the remaining change of $0.3 million.Special funds increased

$26.3 million to $104.2 million in FY 2011 due to the FY 2011 bond financing plan and schedule of construction costs for these funds in FY 2011.The debt service funds decreased

$137.1 million in FY 2011 to $62.8 million. The decrease is due in part to the maturity schedule of outstanding debt along with restructuring and funding activities associated with the Spring 2011 Bond Sate.Deferred Charges increased

$32.5 million in FY 2011 from $821.7 million to $854.2 million. Components of this increase were changes in Costs in Excess of Billings related to the net effect of payment of current maturities and refunding activity related to available debt of $24.9 million. There was also a slight decrease to unamortized debt expense of $1 .6 million due to refunding activity.Relicensing activities of $6.0 million for Columbia accounted for the remainder of the change. Columbia was issued a standard 40-year operating license by the Nuclear Regulatory Commission (NRC) in 1983. On January 19, 2010 Energy Northwest submitted an application to the NRC to renew the license for an additional 20 years, thus continuing operations to 2043. The estimated duration of the license renewal process is 20 to 24 months from acceptance of the application; notice is expected in FY 2013. The accumulated decommissioning and site restoration accrued costs related to Columbia will be affected by any relicensing decisions.

These costs are not currently billed to Bonneville Power Administration (BPA).BPA holds and manages a trust fund for the purpose of funding decommissioning and site restoration. (See Note 12 to the Financial Statements.)

Current Liabilities decreased

$131.1 million in FY 2011 to $87.5 million mostly due to the decrease of$140.7 million in current maturities of long-term debt.This decrease was offset by an increase of $9.6 million in year-end obligations related to the extended R-20 activity.Restricted Liabilities (Special Funds and Debt Service)increased

$30.0 million in FY 2011 to $225.6 million due to bond activity.Long-Term Debt increased

$176.1 million in FY 2011 from $2.40 billion to $2.57 billion due to the FY 2011 refunding issuance.

Current maturing debt is not included.In FY 2011, new debt was issued for various Columbia operational and construction projects, the extension of some maturing debt, the early redemption of certain callable maturities, and to pay for a portion of the costs of issuing debt.Other long-term liabilities increased

$1.6 million in FY 2011 to $14.0 million related to nuclear fuel cask activity.

38 E ' o% ,4 S Statement of Operations Analysis Columbia is a net-billed project. Energy Northwest recognizes revenues equal to expense for each period on net-billed projects.

No net revenue or loss is recognized and no equity is accumulated.

Operating expenses increased

$54.5 million from FY 2010 to $388.9 million from the effects of the planned R-20 78 day outage activity combined with the extension of the outage through fiscal year end. Operations and Maintenance costs increased

$74.6 million, which is attributable to the increased maintenance projects performed during R-20. The increase to Operations and Maintenance costs was offset by lower nuclear fee costs of$5.5 million and generation taxes of $0.5 million which are a direct result of decreased generation.

Administrative and general expenses decreased

$5.2 million; drivers for this change were a decrease of $8.7 million in litigation costs related to the spent fuel project (see note 13 for further discussion), offset by increases of $3.5 million for staffing requirements, related benefit programs and regulatory requirements.

Other Income and Expenses increased

$19.6 million from FY 2010 to $133.3 million net expenses in FY 2011.Expenses associated with the retirement of the condenser contributed to $25.0 million of the increase.

The loss on the condenser was offset by gains of $6.4 million for enrichment services and loaned fuel. The remaining net changes in other income and expenses of $3.0 million resulted from increased cost due to bond activity of $4.4 million, offset by increased investment income of $0.2 million due to market condition and increases to non-generation related revenue of $3.2 million.Columbia's total operating revenue increased from$448.1 million in FY 2010 to $522.2 million in FY 2011. The increase of $74.1 million was due to the originally planned 78 day R-20 activities and the impacts of the extension of the outage through the end of the fiscal year. R-20 was originally budgeted for $153.7 million and 78 days. Actual cost and days through June 30, 2011 were $171.6 million and 85 days. R-20 activities continued through September of FY 2012. Columbia officially synced to the grid on September 27, 2011, signaling the end of R-20.Columbia's insurer, NEIL, paid BPA $3.4 million for settlement of the final payment of the reactor building siding repair which resulted from costs incurred for this and previous fiscal years. Damage was incurred in February 2008. The $3.4 million received in FY 2011 represents the final portion of the $14.0 million dollar total claim that was reimbursable.

Columbia Generating Station TOTAL OPERATING COSTS (dollars in thousands)

FY 2011 Total Expenses 522,156 FY 2010 FY 2009 FY 2008'448,075 519,759 428,993 436,972 FY 2007 o $100,000 $200,000 N Operating Expenses$300,000 $400,000 $500,000 U Other Income I Expenses 39 Packwood Lake Hydroelectric Project The Packwood Lake Hydroelectric Project (Packwood) is wholly owned and operated by Energy Northwest.

Packwood consists of a diversion structure at Packwood Lake and a powerhouse located near the town of Packwood, Wash. The water is carried from the Lake to the powerhouse through a five-mite long buried tunnel and drops nearly 1,800 feet in elevation.

Packwood produced 107.92 GWh of electricity in FY 2011 versus 86.07 GWh in FY 2010. The 25.4 percent increase in generation can be attributed to increased water availability compared to the previous year. FY 2011 was the 4th highest generation in the last 18 years while FY 2010 was near the 90.5 GWh 46 year average.Packwood's cost performance is measured by the cost of power indicator.

The cost of power for FY 2011 was $1.59 cents/kWh as compared to $1.82 cents/kWh in FY 2010. The cost of power fluctuates year-to-year depending on various factors such as outage, maintenance, generation, and other operating costs. The FY 2011 cost of power decrease of 12.6 percent was a result of increased generation from FY 2010 partially offset by increased costs in FY 2011 due to maintenance and miscellaneous hydro costs.Packwood Lake Hydroelectric Project NET GENERATION

-GWhrs FY 2011 107.92 FY 2010 86.07 FY 2009 ".934 FY 2008 77.47 FY 2007 97.80 Packwood Lake Hydroelectric Project COST OF POWER -Cents/kWh FY 2011 FY201 (FY 200 FY 2O0N FY 2001 1.59 1.82 1.62 3.87 1.31 0.5 LO 2 2.5 3.0 3.5 4.0 Balance Sheet Analysis Total assets decreased

$0.2 million from FY 2010, with the drivers being a decrease to cash due to operations of$0.1 million and a decrease to plant of $0.1 million with$22k related to historical adjustment to accumulated depreciation and net book value of assets (See Note 2 to Financial Statements).

The corresponding increases to total liabilities resulted from year end costing recognition.

Packwood has incurred $3.7 million in relicensing costs through FY 2011. These costs are shown as Deferred Charges on the Balance Sheet. Packwood has been operating under a 50-year license issued by the Federal Energy Regulatory Commission (FERC), which expired on February 28, 2010. Energy Northwest submitted the Final License Application (FLA) for renewal of the operating license to FERC on February 22, 2008. On March 4, 2010, FERC issued a one-year extension to operate under the original license which is indefinitely extended for continued operations until formal decision is issued by FERC and a new operating license is granted. As of June 30, 2011, Packwood is relicensed under this extended agreement.

0 20 40 40 Energy Northwest 2011 AnnMat Report Statement of Operations Analysis The agreement with Packwood participants obligates them to pay annual costs and to receive excess revenues.(See Note 1 to the Financial Statements.)

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

Operating expenses increased

$0.2 million from FY 2010 amounts. Most costs remained steady from FY 2010 to FY 2011; the increased costs related to repairs of the turbine runner ($44k), purchases of backup batteries

($48k), and additional project management costs ($175k). Remaining changes in costs were increases to generation tax related to the generation increase (S8k), increases resulting from staffing and related benefits ($10k), and changes to power and depreciation expenses ($2k). Overall increases were offset by lower operating and maintenance costs of $87k.Packwood is obligated to supply a specified amount of power hourly, known as Priority Firm Energy (PFE).The amount varies monthly based on historical average generation.

If the project cannot deliver PFE, replacement power must be purchased on the spot market. Electrical energy from Packwood is currently sold directly to Snohomish PUD which purchases all of the output directly.

The power purchase agreement (PPA) provides a predetermined rate for all firm delivery, per the contract schedule and the Mid-Columbia (Mid-C) based rate for any deliveries above firm, or secondary power. Conversely, if there is excess capacity per the PPA with Snohomish PUD, Energy Northwest sells the excess on the open market for additional revenues to be included as part of the PPA with the participants of the project. (See Note 6 to the Financial Statements.)

Other Income and Expenses increased from a net loss of$15k in FY 2010 to a net toss of $23k in FY 2011. The $8k increase in net loss from other income and expenses was due to increased expenses related to the line of credit and lower investment earnings.Packwood Lake Hydroelectric Project TOTAL OPERATING COSTS (dollars in thousands)

FY2011 FY 2010 FY 2009-I --I-Total Expenses 1,742 1,535 1,641 2,962 1,323 FY 2007 0 500 1000 1500 2000 2500 3000 U Operating Expenses U Other Income / Expenses 41 o Nuclear project No. 1 Energy Northwest wholly owns Nuclear Project No. 1.Nuclear Project No. 1, a 1,250-MWe plant, was placed in extended construction delay status in 1982, when it was 65 percent complete.

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

Balance Sheet Analysis Long-term debt decreased

$176.7 million from $1 .799 billion in FY 2010 to $1 .622 billion in FY 2011 as a result of maturing debt per schedule.

The decrease in tong term debt was offset by the $90.5 million increase in the current debt per the debt maturity schedule.Nuclear project No. 3 Nuclear Project No. 3, a 1,240-MWe plant, was placed in extended construction delay status in 1983, when it was 75 percent complete.

On May 13, 1994, Energy Northwest's Board of Directors adopted a resolution terminating Nuclear Project No. 3. Energy Northwest is no longer responsible for any site restoration costs as they were transferred with the assets to the Satsop Redevelopment Project. The debt service related activities remain and are net-billed. (See Note 13 to the Financial Statements.)

Statement of Operations Analysis Other Income and Expenses showed a net decrease to expenses of $2.0 million from $86.2 million in FY 2010 to $84.2 million in FY 2011. Investment revenue stayed steady, bond related expenses decreased

$2.3 million but were offset by an increase in $0.3 million for plant preservation and decommissioning costs.Balance Sheet Analysis Long-term debt decreased

$133.4 million from $1 .681 billion in FY 2010 to $1.548 billion in FY 2011, as a result of maturing debt per schedule.

The decrease in long term debt was offset by the $85.4 million increase in the current debt per the debt maturity schedule.

The remaining change of $9.3 million was related to year-end timing of planned expenses and effects of net-billing operations.

Statement of Operations Analysis Overall expenses decreased

$2.0 million from FY 2010 related to bond activity with Investment income steady with previous year levels.

42 Enetvy Northwest 2011 Anm~ Ik~Business Development Fund Energy Northwest was created to enable Washington public power utilities and municipalities to build and operate generation projects.

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

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

$0.9 million from $9.5 million in FY 2010 to $8.6 million in FY 2011. Net Plant decreased$0.5 million, due to increases of $0.1 million from Plant activity offset by a decrease of $0.6 million due the historical adjustment made to accumulated depreciation and net book value (See Note 2 to Financial Statements), and $0.1 of accumulated depreciation.

Current assets increased

$0.5 million due to current funding of operations.

The remaining change was due to a decrease in deferred charges of $1.0 million related to power options derivatives (see note 14). Liabilities remained steady between fiscal years. Net Assets decreased

$1.0 million from $7.9 million in FY 2010 to $6.9 million in FY 2011 due to the decrease in value of power option derivatives.

Statement of Operations Analysis Operating Revenues in FY 2011 totaled $12.1 million as compared to FY 2010 revenues of $10.6 million, an increase of $1.5 million. The majority of the increase was in two sectors, Environmental t Information

($0.8 million)and Professional Services ($0.6 million).

Generation has a small increase of $0.1 million to account for the remaining change in revenue.Other Income and Expenses decreased

$3.5 million from$4.5 million in net revenues in FY 2010 to net revenue of$1.0 million FY 2011. Major drivers for the overall change from the previous year were a $1.4 million power sales settlement in FY 2010 which did not recur in 2011. In FY 2011 there was a $0.9 million decrease to power sales options (see note 14). These major drivers were offset by a $1.2 million increase in miscellaneous reimbursements.

The Business Development Fund receives contributions from the Internal Service Fund to cover cash needs during startup periods. Initial startup costs are not expected to be paid back and are shown as contributions.

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

In FY 2011 there were no contributions (transfers);

in FY 2010, the Business Development Fund received contributions (transfers) of$2.5 million.

43 Nine Canyon Wind Project The Nine Canyon Wind Project (Nine Canyon) is wholly owned and operated by Energy Northwest.

Nine Canyon is located in the Horse Heaven Hills area southwest of Kennewick, Wash. Electricity generated by Nine Canyon is purchased by Pacific Northwest Public Utility Districts (purchasers).

Each of the purchasers of Phase I, Phase II, and Phase III have signed a power purchase agreement which is part of the 2nd Amended and Restated Nine Canyon Wind Project Power Purchase Agreement which now has an end date of 2030. Nine Canyon is connected to the Bonneville Power Administration transmission grid via a substation and transmission lines constructed by Benton County Public Utility District.Phase I of Nine Canyon, which began commercial operation in September 2002, consists of 37 wind turbines, each with a maximum generating capacity of approximately 1.3 MW, for an aggregate generating capacity of 48.1 MW.Phase 11 of Nine Canyon, which was declared operational in December 2003, includes 12 wind turbines, each with a maximum generating capacity of 1.3 MW, for an aggregate generating capacity of approximately 15.6 MW. Phase III of Nine Canyon, which was declared operational in May 2008, includes 14 wind turbines, each with a maximum generating capacity of 2.3 MW, for an aggregate generating capacity of 32.2 MW. The total Nine Canyon generating capability is 95.9 MW, enough energy for approximately 39,000 homes.Nine Canyon produced 264.74 GWh of electricity in FY 2011 versus 226.73 GWh in FY 2010. FY 2011 was the highest generation in the history of the project.Nine Canyon's cost performance is measured by the cost of power indicator.

The cost of power for FY 2011 was$6.56 cents/kWh as compared to $7.88 cents/kWh in FY 2010. The cost of power fluctuates year to year depending on various factors such as wind totals and unplanned maintenance.

The decrease of 16.8 percent cost of power was a result of the record generation coupled with lower operations and maintenance costs due to no major component outages.Nine Canyon Wind Project NET GENERATION

-GWhrs FY 2011 264.7 FY 2010 226.7 FY 2009 226.2 FY 2008 237.3 FY 2007 1 56.7 4 3:7'3'1 50 100 150 200 250 300 Nine Canyon Wind Project COST OF POWER -Cents/kWh FY 2011 FY 2010 FY 2009 6.56 7.88 7.79 6.05 8.20 FYI FY200;0 2 4 6 8 10 44 Energy Northwest 2011 Annual Report Balance Sheet Analysis Total Assets decreased

$5.6 million from $133.0 million in FY 2010 to $127.4 million in FY 2011. Major drivers for the change in assets was a decrease of $6.9 million due to plant activity and a small adjustment related to a historical adjustment to accumulated depreciation and net book value of assets (See Note 2 to Financial Statements).

The remaining change was an increase to cash of $1.3 million from operations.

There was an overall decrease to liabilities of $4.6 million with a decrease to long-term debt of $4.7 million, increases to current debt maturities of $0.3 million, decreases to accrued debt-related interest of $0.1 million and other deferred credits of $0.1 million.The decrease in Net Assets was $1.2 million in FY 2011 as compared to $0.7 million in FY 2010. The decline experienced in previous years is continuing, though the trend is consistent with the rate stabilization approach for Nine Canyon planning.

The original plan anticipated operating at a loss in the early years and gradually increasing the rate charged to the purchasers to avoid a large rate increase after the Renewable Energy Production Incentive (REPI) expires. The REPI incentive expires 10 years from the initial operation startup date for each phase. Reserves that were established are used to facilitate this plan. The rate plan in FY 2008 was revised to account for the shortfall experienced in the REPI funding and to provide a new rate scenario out to the 2030 project end date. Energy Northwest did not receive REPI funding in FY 2011 and is not anticipating future REPI incentives.

Statement of Operations Analysis Operating Revenues increased

$0.5 million from $15.8 million in FY 2010 to $16.3 million in FY 2011. The project received revenue from the billing of the purchasers at an average rate of $60.69 per MWh for FY 2011 as compared to $66.81 per MWh for FY 2010, which is reflective of the implementation of the revised rate plan in FY 2008 to account for REPI funding shortfalls and costs of operations.

The slight increase in operating revenues was due to the planned MWh budgeted rate. Operating costs decreased from $12.0 million in FY 2010 to $10.9 million in FY 2011. Decreased operating costs were due to lower wind technician costs and decreased need for expenditures on main bearings as compared to FY 2010.Other Income and Expenses increased

$2.1 million from$4.5 million in net expenses FY 2010 to $6.6 million in FY 2011. Other revenues decreased due to FY 2010 showing a$2.0 million settlement for bearing replacement on Phase I and II. There was a net cost to Nine Canyon of $0.1 million for BPA scheduling.

Investment income associated with bond funds decreased

$0.1 million due to market conditions with tower bond related expenses of $0.2 accounting for the remainder of other revenues and expenses.

Net losses of $1.2 million for FY 2011 were incurred and are consistent with the expectations of a gradual revenue recovery of operating costs. A declining net asset balance is expected in future years until bond principal payments exceed annual depreciation requirements.

In previous years Energy Northwest has accrued, as income (contribution) from DOE, REPI payments that enable Nine Canyon to receive funds based on generation as it applies to the REPI bill. REPI was created to promote increases in the generation and utilization of electricity from renewable energy sources and to further the advances of renewable energy technologies.

Energy Northwest had no REPI activity for FY 2011.This program, authorized under Section 1212 of the Energy Policy Act of 1992, provides financial incentive payments for electricity produced and sold by new qualifying renewable energy generation facilities.

Nine Canyon did not receive funding for FY 2010. The payment stream from Nine Canyon participants and the REPI receipts were projected to cover the total costs over the purchase agreement.

Continued shortfalls in REPI funding for the Nine Canyon project led to a revised rate plan to incorporate the impact of this shortfall over the life of the project. The billing rates for the Nine Canyon participants increased 69 percent and 80 percent for Phase I and Phase II participants respectively in FY 2008 in order to cover total project costs, projected out to the 2030 proposed project end date. The increases for FY 2008 were a change from the previous plan where a 3 percent increase each year over the life of the project was projected.

Going 45 forward, the increase or decrease in rates will be based on cash requirements of debt repayment and the cost of operations.

Phase III started with an initial planning rate of$49.82 per MWh which increased at 3 percent per year for three years. In year six (FY 2013) the rate will increase to a rate that will be stabilized over the life of the project.Possible adjustments may be necessary to future rates depending on operating costs and REPI, similar to Phase I and II.Nine Canyon Wind Project TOTAL OPERATING COSTS (dollars in thousands)

FY.FY20'Total Expenses 17,466 16,506 17,632 15,484 FY 200i FY 200W FY 2001 12,672 S3,000 $6,000 U Operating Expenses$9,000 $12,000 $15,000 E Other Income / Expenses Internal Service Fund The Internal Service Fund, formerly the General Fund, was established in May 1957. The Internal Service Fund provides services to the other funds. This fund accounts for the central procurement of certain common goods and services for the business units on a cost reimbursement basis. (See Note 1 to Financial Statements.)

Balance Sheet Analysis Total Assets for FY 2011 increased

$18.0 million from$37.6 million in FY 2010 to $55.6 million in FY 2011. The six major items for the change were 1) increases to net plant of $7.4 million, reflecting

$9.6 million of an historical adjustment to plant activity and $2.2 million decrease due to period activity, 2) increase of $8.2 million to Cash for anticipated year end check and warrant redemption, 3) an increase in performance fee of $1.0 million for payments from other business units, 4) an increase of $0.9 million to Personal Time Bank investments and cash, 5) an increase of$0.3 million in restricted assets due to maturity schedule and escrow requirements processing schedule, and 6) an increase to operational activities of $0.2 million.The net increase in Net Assets and Liabilities is due to increases in Accounts Payable and Payroll related liabilities of $9.3 million due to year-end timing, an increase to Sales Tax Payable of $4.0 million due to off-cycle year fuel activity, an increase of $1.9 million in retention payable related to increased public works activity, a $1.7 million increase in due to other business units, and a $0.3 million decrease to bearer bond activity.Statement of Operations Analysis Net Revenues for FY 2011 decreased

$29k from FY 2010. The decrease was due to increased costs for lease activity of $36k, decrease in investment returns of $9k, and increases to depreciation of $467k offset by increases in revenue due to operations of $484K.

46 Energy Northwest 2011 AnLual Report M@0 B alance Sheets As of June 30, 2011 (dollars in thousands)

Columbia Packwood Lake Generating Hydroelectric Station Project Nuclear Project Nuclear Project No.1* No.3*Business Development Nine Canyon Fund Wind Project Internal Service 2011 Subtotal Fund Combined Total ASSETS CURRENT ASSETS Cash Available-for-sale investments Accounts and other receivables Due from other business units Due from other funds Materials and supplies Prepayments and other TOTAL CURRENT ASSETS RESTRICTED ASSETS (NOTE 1)Special funds Cash Available-for-sale investments Accounts and other receivables Debt service funds Cash Available-for-sale investments Accounts and other receivables TOTAL CURRENT RESTRICTED ASSETS NONCURRENT ASSETS Utility Plant (Note 2)In service Not in service Construction work in progress Accumulated depreciation Net Utility Plant Nuclear fuel, net of accumulated amortization TOTAL NONCURRENT ASSETS DEFERRED CHARGES Costs in excess of billings Unamortized debt expense Other deferred charges TOTAL DEFERRED CHARGES$ 39,100 $13,858 802 4,567 30,669 103,099 861 $471 16 69 $3,137 255 1,038 287 $7,560 87 26,248 1,357 $4,737 501 699 9,671 $ 51,345 $-29,292 194 1,968-5,624 951 58,906-103,099 13,680 $23,481 92 362 65,025 52,773 2,060 103,099 1,645 67 ---114 1,826 1,149 2,975 193,740 1,415 4,499 34,182 7,294 10,930 252,060 38,764 225,932 1,125 -150 1,168 -5 2,448 293 2,741 102,846 3,096 5,608 1,549 113,099 2,699 115,798 194 55 72 -321 321 42,747 97,458 18,545 7,831 166,581 166,581 20,101 114,877 146,268 11,172 292,418 292,418--184 -184 184 167,013 -215,636 171,845 20,557 575,051 2,992 578,043 3,594,468 13,625 --2,065 134,447 3,744,605 48,961 3,793,566--25,253 -25,253 25,253 185,801 --185,801 185,801 (2,370,557)

(12,716) (25,253) (862) (40,572) (2,449,960)

(35,091) (2,485,051) 1,409,712 909 1,203 93,875 1,505,699 13,870 1,519,569 266,949 ---266,949 -266,949 1,676,661 909 --1,203 93,875 1,772,648 13,870 1,786,518 822,956 -1,625,119 1,530,596

--3,978,671 3,978,671 12,551 -5,803 5,994 -2,019 26,367 26,367 18,721 3,737 116 -22,574 22,574 854,228 3,737 1,630,922 1,536,590 116 2,019 4,027,612 4,027,612 TOTALASSETS

$ 2,891,642

$ 6,061 $ 1,851,057

$ 1,742,617

$ 8,613 $ 127,381 $ 6,627,371

$ 55,626 $ 6,618,105*Project recorded on a liquidation basis The accompanying notes are an integral part of these combined financial statements Data.[ h l~nfornIation 47 Columbia Packwood Lake Business Generating Hydroelectric Nuclear Project Nuclear Project Development Nine Canyon Station Project No.1

• No.3* Fund Wind Project Subtotal Internal Service 2011 Fund Combined Total LIABILITIES AND NET ASSETS CURRENT LIABILITIES Current maturities of long-term debt Accounts payable and accrued expenses Due to Participants Due to other business units TOTAL CURRENT LIABILITIES

$ 45 $$ 166,030 $ 129,435 $50,991 36,488 182 868 247 172 1,675$ 4,260 $ 299,770 $ -$ 299,770 506 53,773 44,319 98,092-37,356 -37,356 362 362 5,624 -87,524 1,050 166,277 129,607 1,675 5,128 391,261 49,943 435,218 LIABILITIES-PAYABLE FROM CURRENT RESTRICTED ASSETS (NOTE 1)Special funds Accounts payable and accrued expenses Due to other funds Debt service funds Accrued interest payable Due to other funds TOTAL CURRENT RESTRICTED LIABILITIES LONG-TERM DEBT (NOTE 5)Revenue bonds payable Unamortized (discount)/

premium on bonds -net Unamortized loss on bond refundings TOTAL LONG-TERM DEBT OTHER LONG-TERM LIABILITIES DEFERRED CREDITS Advances from Members and others Advances from Members and others Other deferred credits TOTAL DEFERRED CREDITS NET ASSETS Invested in capital assets, net of related debt Restricted, net Unrestricted, net NET ASSETS TOTAL LIABILITIES 132,111 30,667 62,801 2 15,839 301 3,848 1,187 149,137 951 35,767 3,387 150,832-23,139 293 149,430 150,832 45,568 39,076 737 22,400 225,581 62,445 65,324 5,525 358,875 293 300,262 2,487,355 1,573,805 1,495,480 136,505 5,693,145

-5,693,145 92,655 55,641 53,430 4,155 205,881 205,881 (15,501) (7,111) (1,224) -(23,836) (23,836)2,564,509 1,622,335 1,547,686 140,660 5,875,190 5,875,190 14,028 ---14,028 14,028 5,011 5,011 5,011---651 651-153 153 5 158 5,011 153 5,164 656 5,820-1,203 (49,026) (47,823) 13,870 (33,953)-14,879 14,879 2,699 17,578 5,735 10,062 15,797 (11,835) 3,962----6,938 (24,085) (17,147) 4,734 (12,413)2,891,642 6,061 1,851,057 1,742,617 1,675 151,466 6,644,518 50,892 6,630,518 TOTAL LIABILITIESAND

$ 2,891,642

$ 6,061 $ 1,851,057

$ 1,742,617

$ 8,613 $ 127,381 $ 6,627,371

$ 55,626 $ 6,618,105 NET ASSETS*Project recorded on a liquidation basis The accompanying notes are an integral part of these combined financial statements 48 Energy Northwest 2011 Annual Report MOO Statements Of Revenues, Expenses, And Changes In Net Assets As of June 30, 2011 (dotlars in thousands)

Columbia Packwood Lake Generating Hydroelectric Station Project Nuclear Project Nuclear Project No.1

• No.3*Business Development Fund Nine Canyon Wind Project Internal Service 2011 Subtotal Fund Combined Total OPERATING REVENUES$ 522,156 $ 1,742 $$$ 12,144 $ 16,250 $ 552,292 $$ 552,292 OPERATING EXPENSES Nuclear fuel Spent fuel disposal fee Decommissioning Depreciation and amortization Operations and maintenance Other power supply expense Administrative

& general Generation tax TOTAL OPERATING EXPENSES NET OPERATING REVENUES OTHER INCOME AND EXPENSE Other Investment income Interest expense and discount amortization Plant preservation and termination costs Depreciation and amortization Decommissioning Services to other business units TOTAL OTHER INCOME AND EXPENSE Changes in Net Assets (DISTRIBUTION)/CONTRIBUTION TOTAL NET ASSETS, BEGINNING OF YEAR 30,772 6,845 7,090 66,636 247,008 27,358 59 1,462 17 156 196 13,331 30,772 6,845 80 7,170 6,790 73,681 3,938 265,739-17 34 27,548 30,772 6,845 7,170 73,681 265,739 17 27,548 3,166 25 -57 ,248 3 ,248 388,875 1,719 13,527 10,899 415,020 415,020 133,281 23 (1,383) 5,351 137,272 137,272 (14,210) -84,228 76,356 1,939 (129) 148,184 71,909 148,269 721 3 72 70 (943) 81 4 38 4 (119,792)

(26) (82,094) (76,064) -(6,519) (284,495)

-(284,495)(1,656) (362) (2,018) (2,018)(6) -(6) (2,268) (6)(544) (544) (544)(69,594)(133,281)

(23) 996 (6,567) (138,875) 85 (138,790)-(387) (1,216) (1,603) 85 (1,518)1,000 1,000 7,325 (22,869) (15,544) 3,649 (11,895)TOTAL NET ASSETS, $ $ $ $ $ 6,938 $ (24,085) $ (17,147) $ 4,734 $ (12,413)END OF YEAR*Project recorded on a liquidation basis The accompanying notes are an integral part of these combined financial statements I a & Information 49 Statements Of Cash Flows As of June 30, 2011 (dollars in thousands)

Columbia Packwood Lake Generating Hydroelectric Business Nuclear Project Nuclear Project Development Nine Canyon Internal Service 2011 Station Project No.I *No.3*Fund Wind Project Fund Combined Total CASH FLOWS FROM OPERATING AND OTHER ACTIVITIES Operating revenue receipts Cash payments for operating expenses Other revenue receipts Cash payments for preservation, termination expense Cash payments for services Net cash provided/(used) by operating and other activities CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES Proceeds from bond refundings Deposit to Debt Service Fund Payment for bond issuance and financing costs Payment for capital items Receipts from sales of plant assets Nuclear fuel acquisitions Interest paid on revenue bonds Principal paid on revenue bond maturities Net cash provided/(used) by capital and related financing activities CASH FLOWS FROM NON-CAPITAL FINANCE ACTIVITIES CASH FLOWS FROM INVESTING ACTIVITIES Purchases of investment securities Sales of investment securities Interest on investments Net cash provided/(used) by investing activities NET INCREASE (DECREASE)

IN CASH CASH AT JUNE 30, 2010$ 464,563 $(267,790)1,569 $(1,721)$$ 8,965 $ 16,685 $(8,728) (4,619)130$ 491,782 (282,858)466,329 259,036 207,163 (1,006)(256)(1,262)------11,243 11,243 196,773 (152) 258,030 206,907 237 12,196 11,243 685,234 532,565 -106,667 ---639,232 (347,355)

---(347,355)(3,224) (203) (107,297)

(1) (32) (110,757)(109,930) 23 -311 78 (1,421) (110,939)3 3 (93,890) -(93,890)(123,727)

-(92,525) (107,645)

(6,868) (330,765)(140,790)

(4) (75,505) (10,167) -(3,965) (230,431)(286,351) 19 (168,230)

(118,442) 310 (10,787) (1,421) (584,902)(409,128)

(644) (405,856)

(371,135)

(10,046) (29,975) (27,494) (1,254,278) 553,860 644 406,182 297,175 9,470 30,062 25,566 1,322,959 903 3 72 (4) 9 91 349 1,423 145,635 3 398 (73,964) (567) 178 (1,579) 70,104 56,057 (130) 90,198 14,501 (20) 1,587 8,243 170,436 26,915 991 7,479 5,499 1,377 15,920 5,730 63,911 CASH AT JUNE 30, 2011 $ 82,972 $ 861 $ 97,677 $ 20,000 $ 1,357 $ 17,507 $ 13,973 $ 234,347*Project recorded on a liquidation basis The accompanying notes are an integral part of these combined financial statements 50 Energy Northwest 2011 Annual Report M OO Statements Of Cash Flows (Cont'd)As of June 30, 2011 (dottars in thousands)

Columbia Packwood Lake Generating Hydroelectric Station Project Business Nuclear Project Nuclear Project Development No,1* No.3* Fund Nine Canyon Internal Service 2010 Wind Project Fund Combined Total RECONCILIATION OF NET OPERATING REVENUES TO NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES Net operating revenues Adjustments to reconcile net operating revenues to cash provided by operating activities:

Depreciation and amortization Decommissioning Other Change in operating assets and liabilities:

Deferred charges/costs in excess of billings Accounts receivable Materials and supplies Prepaid and other assets Due from/to other business units, funds and Participants Accounts payable Other revenue receipts Cash payments for preservation, termination expense Cash payments for services Net cash provided (used) by operating and other activities

$ 133,281 $23 $$$ (1,383) $ 5,351 $$ 137,272 95,105 7,090 (13,745)(57,192)146 1,951 (395)(1,306)31,838 48 26 108 6,770 33 813 (97)(48)(49)590 (57)102,031 7,123 (13,003)(57,240)630 1,951 (389)(929)31,608 466,199 (1,262)6 (14)(138)-391 109 (201)259,036 207,163 (1,006)(256)-11,243 11,243$ 196,773 $ (152) $ 258,030 $ 206,907 $ 237 $ 12,196 $ 11,243 $ 685,234*Project recorded on a liquidation basis The accompanying notes are an integral part of these combined financial statements 51 Energy Northwest Notes To Financial Statements Note 1 -Summary Of Operations and Significant Accounting Policies Energy Northwest, a municipal corporation and joint operating agency of the State of Washington, was organized in 1957 to finance, acquire, construct and operate facilities for the generation and transmission of electric power.Membership consists of 23 public utility districts and five municipalities.

AlL members own and operate electric systems within the State of Washington.

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

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

Participants in Energy Northwest's net-billed business units consist of public utilities and rural electric cooperatives located in the western United States who have entered into net-billing agreements with Energy Northwest and BPA for participation in one or more of Energy Northwest's business units. BPA is obligated by law to establish rates for electric power which wilt recover the cost of electric energy acquired from Energy Northwest and other sources, as well as BPA's other costs (see Note 6).Energy Northwest operates the Columbia Generating Station (Columbia), a 1,150-MWe (Design Electric Rating, net) generating plant completed in 1984. Energy Northwest has obtained all permits and licenses required to operate Columbia, including a Nuclear Regulatory Commission (NRC) operating license that expires in December 2023.On January 19, 2010 Energy Northwest submitted an application to the NRC to renew the license for an additional 20 years, thus continuing operations until 2043.The estimated duration of the license renewal process is 20 to 24 months from acceptance of the application.

Costs to date for Columbia relicensing are $18.7 million and are shown as deferred charges in the balance sheet.Energy Northwest also operates the Packwood Lake Hydroelectric Project (Packwood), a 27.5-MWe generating plant completed in 1964. Packwood has been operating under a 50-year license issued by the Federal Energy Regulatory Commission (FERC), which expired on Feb.28, 2010. Energy Northwest submitted the Final License Application (FLA) for renewal of the operating license to FERC on Feb. 22, 2008. On March 4, 2010, FERC issued a one-year extension, or until the issuance of a new license for the project or other disposition under the Federal Power Act, whichever comes first. FERC is awaiting issuance of the National Oceanic and Atmospheric Administration's (NOAA) Biological Opinion (BO), after which FERC wil[complete the final license renewal documentation for Packwood.

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

The Packwood participants are obligated to pay annual costs of Packwood including debt service, whether or not Packwood is operable, until the outstanding bonds are paid or provisions are made for bond retirement, in accordance with the requirements of bond resolution.

The participants also share Packwood revenue.In October 2008, Packwood entered into a new Power Sales Agreement with Snohomish PUD to purchase the entire project output (see Note 6). This contract was extended in the fall of 2010 and wilt continue until the fall of 2011. The Packwood participants will then assume 52 Energy rN4c thwest 2011 Anonki R epor the responsibility to purchase their respective shares in the fall of 2011, or they can re-assign their shares to other participants.

Nuclear Project No. 1, a 1,250-MWe plant, was placed in extended construction delay status in 1982, when it was 65 percent complete.

Nuclear Project No. 3, a 1,240-MWe plant, was placed in extended construction delay status in 1983, when it was 75 percent complete.

On May 13, 1994, Energy Northwest's Board of Directors adopted resolutions terminating Nuclear Projects Nos. 1 and 3. All funding requirements remain as net-billed obligations of Nuclear Projects Nos. 1 and 3. Energy Northwest wholly owns Nuclear Project No. 1. Energy Northwest is no longer responsible for site restoration costs for Nuclear Project No. 3. (See Note 13)The Business Development Fund was established in April 1997 to pursue and develop new energy related business opportunities.

There are four main business lines associated with this business unit: General Services and Facilities, Generation, Professional Services, and Business Unit Support.Nine Canyon was established in January 2001 for the purpose of exploring and establishing a wind energy project. Phase I of the project was completed in FY 2003 and Phase II was completed in FY 2004. Phase I and II combined capacity is approximately 63.7 MWe. Phase III was completed in FY 2008 adding an additional 14 wind turbines to the Nine Canyon Wind Project and adding an aggregate capacity of 32.2 MWe. The total number of turbines at Nine Canyon is 63 and the total capacity is 95.9 MWe.The Internal Service Fund was established in May 1957.It is currently used to account for the central procurement of certain common goods and services for the business units on a cost reimbursement basis.Energy Northwest's fiscal year begins on July 1 and ends on June 30. In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through November 30, 2011, the date the financial statements were issued.The following is a summary of the significant accounting policies: a) Basis of Accounting and Presentation:

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

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

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

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

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

Depreciation relating 53 to capital assets is charged to the appropriate business units based upon assets held by each project.Liabilities of the Internal Service Fund represent accrued payroll, vacation pay, employee benefits, and common accounts payable which have been charged directly or indirectly to business units and will be funded by the business units when paid. Net amounts owed to, or from, Energy Northwest business units are recorded as Current Liabilities-Due to other business units, or as Current Assets-Due from other business units on the Internal Service Fund Balance Sheet.The Combined Total column on the financial statements is for presentation only as each Energy Northwest business unit is financed and accounted for separately from all other current and future business units. The FY 2011 Combined Total includes eliminations for transactions between business units as required in GASB Statement No. 34, "Basic Financial Statements and Management's Discussion and Analysis for State and Local Governments." Pursuant to GASB Statement No. 20, "Accounting and Financial Reporting for Proprietary Funds and Other Governmental Entities That Use Proprietary Fund Accounting," Energy Northwest has elected to apply all FASB standards, except for those that conflict with, or contradict, GASB pronouncements.

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

b) Utility Plant and Depreciation:

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

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

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

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

Interest expense, termination expenses and asset disposition costs for Nuclear Projects Nos. 1 and 3 have been charged to operations.

c) Allowance for Funds Used During Construction (AFUDC): For financing not related to a Capital Facility, Energy Northwest analyzes the gross interest expense relating to the cost of the bond sale, taking into account interest earnings and draws for purchase or construction reimbursements for the purpose of analyzing impact to the recording of capitalized interest.

However, if estimated costs are more than inconsequential, an adjustment is made to allocate capitalized interest to the appropriate plant account.Interest costs capitalized for FY 2011 totaled $0.6 million and related to Columbia.

54 [11,~ N, , , wst 2011 Ar/d) Nuclear Fuel: Energy Northwest has various agreements for uranium concentrates, conversion, and enrichment to provide for short-term enriched uranium product and Long-term enrichment services.

These contracts do not obligate Energy Northwest to purchase fuel components in excess of the requirements of operations.

Alt expenditures related to the initial purchase of nuclear fuel for Columbia, including interest, were capitalized and carried at cost. When the fuel is placed in the reactor; the fuel cost is amortized to operating expense on the basis of quantity of heat produced for generation of electric energy. Accumulated nuclear fuel amortization (the amortization of the cost of nuclear fuel assemblies in the reactor used in the production of energy and in the fuel pool for less than six months per FERC guidelines) is $53.5 million as of June 30, 2011. Fees for disposal of fuel in the reactor are expensed as part of the fuel cost.Energy Northwest has a contract with the U.S.Department of Energy (DOE) that requires the DOE to accept title and dispose of spent nuclear fuel (reference to the term "spent fuel" is due to DOE contract and current court proceedings. "Used fuel" is the preferred term by Energy Northwest).

Although the courts have ruled that DOE had the obligation to accept title to spent nuclear fuel by January 31, 1998, currently, there is no known date established when DOE will fufill this legal obligation and begin accepting spent nuclear fuel. Energy Northwest was awarded Final Judgment and received damages in the amount of $48,702,551 (See Note 13).The current period operating expense for Columbia includes a $6.8 million charge from DOE for future spent fuel storage and disposal in accordance with the Nuclear Waste Policy Act of 1982.Energy Northwest has completed the Independent Spent Fuel Storage Installation (ISFSI) project, which is a temporary dry cask storage until the DOE completes its plan for a national repository.

ISFSI will store the spent fuel in commercially available dry storage casks on a concrete pad at the Columbia site. No casks were issued from the cask inventory account in FY 2011.Spent fuel is transferred from the spent fuel pool to the ISFSI periodically to allow for future refuelings.

Current period costs include $29.1 million for nuclear fuel and SI .7 million for dry cask storage costs.e) Asset Retirement Obligation:

Energy Northwest has adopted ASC 410, "Asset Retirement and Environmental Obligations".

This standard requires Energy Northwest to recognize the fair value of a liability associated with the retirement of a long-lived asset, such as: Columbia Generating Station, Nuclear Project No. 1, and Nine Canyon, in the period in which it is incurred. (See Note 11)f) Decommissioning and Site Restoration:

Energy Northwest established decommissioning and site restoration funds for Columbia and monies are being deposited each year in accordance with an established funding plan. (See Note 12)g) Derivative Instruments:

In June, 2008, GASB issued Statement No. 53,"Accounting and Financial Reporting for Derivative Instruments." Statement No. 53 provides a comprehensive framework for the measurement, recognition and disclosure of derivative instrument transactions for the purpose of enhancing the usefulness and comparability of derivative instrument information reported by state and local governments.(See Note 14) 55 h) Restricted Assets: In accordance with bond resolutions, related agreements and laws, separate restricted accounts have been established.

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

i) Cash and Investments:

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

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

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

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

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

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

The amounts due to each business unit are reflected in the Due To/From other business unit's account. Other receivables specific to each business unit are recorded in the residing business unit.1) Materials and Supplies: Materials and supplies are valued at cost using the weighted average cost method.m) Long-Term Liabilities:

These consist of obligations related to bonds payable and the associated premiums/discounts and gains/losses. Other noncurrent liabilities for Columbia relate to the dry cask storage activity.

56 Energy Northwest 2011 Annual Report Long-Term Liability activity for the year ended June 30, 2011 was as follows: 1 Long-Term Liabilities (dollars in thousands)

Beginning Balance Columbia Generating Station Revenue bonds payable $ 2 Unamortized (discount)/premium on bonds -net Unamortized gain/(Iloss) on bond refundings Other noncurrent liabilities Current portion$ 2 Nuclear Project No.1 Revenue bonds payable $Unamortized (discount)/premium on bonds -net Unamortized gain/floss) on bond refundings Current portion$Nuclear Project No.3 Revenue bonds payable $Unamortized (discount)I/premium on bonds- net Unamortized gain/(loss) on bond refundings Current portion Nine Canyon Wind Project Revenue bonds payable $Unamortized (discount)Ipremium on bonds- net Current portion$n) Debt Premium, Discount and Expense: Original issue and reacquired bond premiums, discounts and expenses relating to the bonds are amortized over the terms of the respective bond issues using the bonds outstanding method which approximates the effective interest method. In accordance with GASB Statement No. 23, "Accounting and Financial Reporting for Refundings of Debt ,327,455 $78,202 (8,232)12,373 Increases 501,570 $30,637 (12,005)1,655 Decreases 341,670 16,184 4,736 Ending Balance$ 2,487,355 92,655 (15,501)14,028 140,790 140,745 45 ,550,588 $ 521,857 $ 503,335 $ 2,578,582 ,739,835 $ -$ 166,030 $ 1,573,805 71,488 30 15,877 55,641 (12,292) (237) 5,418 (7,111)75,505 166,030 75,505 166,030 ,874,536 $ 165,823 $ 262,830 $ 1,788,365 ,637,715 $ 92,285 $ 234,520 $ 1,495,480 47,646 12,797 7,013 53,430 (4,235) (948) 3,959 (1,224)44,050 129,435 44,050 129,435 ,725,176 $ 233,569 $ 289,542 $ 1,677,121 140,765 $ 4,260 $ 136,505 4,633 478 4,155 3,965 4,260 3,965 4,260 149,363 $ 4,260 $ 8,703 $ 144,920 Reported by Proprietary Activities," losses on debt refundings have been deferred and amortized as a component of interest expense over the shorter of the remaining life of the old or new debt. The Balance Sheet includes the original deferred amount less recognized amortization expense and is included as a reduction to the new debt.

57 o) Revenue Recognition:

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

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

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

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

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

Nine Canyon did not record a receivable for FY 2011 REPI funding as no funds are anticipated to be disbursed to Energy Northwest under this program. The payment stream from Nine Canyon participants and the anticipated REPI receipts were projected to cover the total costs over the purchase agreement.

Permanent shortfalls in REPI funding for the Nine Canyon project led to a revised rate plan to incorporate the impact of this shortfall over the life of the project. The rate schedule for the Nine Canyon participants covers total project costs occurring in FY 2011 and projections out to the 2030 proposed end date.q) Compensated Absences: Employees earn leave in accordance with length of service. Energy Northwest accrues the cost of personal leave in the year when earned. The liability for unpaid leave benefits and related payroll taxes was $19.9 million at June 30, 2011 and is recorded as a current liability.

r) Use of Estimates:

The preparation of Energy Northwest financial statements in conformity with GAAP requires management to make estimates and assumptions that directly affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from these estimates.

Certain incurred expenses and revenues are allocated to the business units based on specific allocation methods that management considers to be reasonable.

58 Energy Northwest 2011 Annual Report Note 2 -Utility Plant Utility plant activity for the year ended June 30, 2011 was as follows: , Utility Plant Activity (dollars in thousands)

Beginning Balance Increases Decreases Ending Balance Columbia Generating Station Generation 3,588,450 59,536 (85,987) 3,561,999 Decommissioning 32,469 -32,469 Construction Work-in-Progress 146,030 99,046 (59,275) 185,801 Accumulated Depreciation and Decommissioning (2,391,614)

(81,818) 102,875 (2,370,557)

Utility Plant, net 1,375,335 76,764 (42,387) 1,409,712 Packwood Lake Hydroelectric Project Generation 13,647 (22) 13,625 Accumulated Depreciation (12,668) (48) -(12,716)Utility Plant, net $ 979 $ (48) $ (22) $ 909 Business Development General 2,399 255 (589) 2,065 Construction Work-in-Progress Accumulated Depreciation (742) (120) (862)Utility Plant, net 1,657 135 (589) 1,203 Nine Canyon Wind Project Generation 133,666 265 (345) 133,586 Decommissioning 861 --861 Construction Work-in-Progress

-213 (213)Accumulated Depreciation and Decommissioning (33,771) (6,801) -(40,572)Utility Plant, net 100,756 (6,323) (558) 93,875 Internal Service Fund General 46,914 2,481 (434) 48,961 Construction Work-in-Progress 591 -(591)Accumulated Depreciation (40,999) (2,293) 8,201 (35,091)Utility Plant, net 6,506 188 7,176 13,870* Does not include Nuclear Fuel Amount of $267 million, net of amortization.

Reclassifications took place in FY 2011 for various plant and accumulated depreciation accounts.

Corrections were a result of legacy adjustments made in the asset records that tracked historical changes. Changes reported for each business unit were: Plant Accumulated Depreciation Columbia Generating Station (1,336) 34,273 Packwood Lake Hydroelectric Project (22)Business Development (589) (13)Nine Canyon Wind Project (2)Internal Service Fund 1,870 7,741 Total Legacy Adjustments (77) 41,999 59 Note 3 -Deposits And Investments As of June 30, 2011, Energy Northwest had the following unrealized gains and Losses:-Available-For-Sale-Investments (dollars in thousands)

Amortized Cost Unrealized Gains Unrealized Losses Fair Value (1) (2)Columbia Generating Station $ 136,627 $ 178 $Packwood Lake Hydroelectric Project Nuclear Project No. 1 121,110 -Nuclear Project No. 3 159,434 2 Business Development Fund 4,736 1 -Internal Service Fund 26,132 52 (4)Nine Canyon Wind Project 12,718 4 (1)(I) 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

$21.56 million have a maturity beyond 1 year with the longest maturity being March 8th, 20131$136,805 121,110 159,436 4,737 26,180 12,721 Interest rate risk: In accordance with its investment policy, Energy Northwest manages its exposure to declines in fair values by limiting investments to those with maturities designated in specific bond resolutions.

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

This investment policy is more restrictive than the state law.Concentration of credit risk: Energy Northwest investment policy does not specifically address concentration of credit risk. An individual authorized security or obligation can receive up to 100 percent of the authorized investment amount; there are no individual concentration limits.Custodial credit risk, Deposits:

For a deposit, this is the risk that in the event of bank failure, Energy Northwest's deposits may not be returned to it. Energy Northwest's interest bearing accounts and certificates of deposits are covered up to $250,000 by Federal Depository Insurance Corporation (FDIC) while non-interest bearing deposits are entirely covered by FDIC and if necessary, all interest and non-interest bearing deposits are covered by collateral held in multiple financial institution collateral pool administered by the Washington State Treasurer's Local Government Investment Pool (LGIP). Under state law, public depositories under the PDPC may be assessed on a prorated basis if the pool's collateral is insufficient to cover a loss. As a result, deposits covered by collateral held in the multiple financial institution collateral pool are considered to be insured. State law requires deposits may only be made with institutions that are approved by the PDPC.

60 Fnerg'y Nwht%' i , 01 Ann~ual Repori Note 4 -Others Deferred Charges And Deferred Credits Other deferred charges of $18.7 million and $3.7 million relate to the Columbia and Packwood relicensing effort, respectively.

Business Development deferred charge of$0.1 million relates to derivative power options. (See Note 14) Other deferred credits of $0.2 million consist of turbine elevator purchases for Nine Canyon that will be completed in FY 2013.Note 5 -Long-Term Debt Each Energy Northwest business unit is financed separately.

The resolutions of Energy Northwest authorizing issuance of revenue bonds for each business unit provide that such bonds are payable from the revenues of that business unit. All bonds issued under Resolutions Nos. 769, 775 and 640 for Nuclear Projects Nos. 1, 3 and Columbia, respectively, have the same priority of payment within the business unit (the "Prior Lien Bonds"). All bonds issued under Resolutions Nos. 835, 838 and 1042 (the"Electric Revenue Bonds") for Nuclear Projects Nos. 1, 3 and Columbia, respectively, are subordinate to the Prior Lien Bonds and have the same subordinated priority of payment within the business unit. Nine Canyon's bonds were authorized by the following resolutions:

Resolution No. 1214 (2001 Bonds), Resolution No. 1299 (2003 Bonds), Resolution No. 1376 (2005 Bonds) and Resolution No.1482 (2006 Bonds).During the year ended June 30, 2011, Energy Northwest issued, for Columbia, the Series 2010-D, 2011-B, and 2011 -C Bonds. The Series 2011 -A Bonds were issued for Nuclear Project 3 and Columbia.

The Series 2010-D, 2011-A, 2011 -B, and 2011-C Bonds issued for Nuclear Project No. 3 and Columbia are fixed rate bonds with a weighted average coupon interest rate ranging from 3.55 percent to 5.70 percent. These transactions resulted in a net loss for accounting purposes of $11.71 million.According to GASB No. 23, "Accounting and Financial Reporting for Refundings of Debt Reported by Proprietary Activities," gains and losses on the refundings are deferred and amortized over the remaining life of the old debt or the new debt, whichever is shorter.The Series 2010-D Bonds issued for Columbia are taxable fixed-rate Build America Bonds to finance costs of acquiring fuel and to finance a portion of the costs planned to be incurred during fiscal years 2011, 2012 and 2013 for certain capital improvements.

The Series 2011-A Bonds issued for Nuclear Project No. 3 and Columbia are tax exempt fixed-rate bonds that refunded certain Electric Revenue Bonds.The Series 2011-B Bonds issued for Columbia are taxable fixed-rate bonds that refunded certain Electric Revenue Bonds and are to finance a portion of the cost of certain capital improvements.

The Series 2011-C Bonds issued for Columbia are taxable fixed-rate bonds to finance costs of operating Columbia.

61 The Bond Proceeds, Weighted Average Coupon Interest Rates, Net Accounting Loss, and Total Defeased Bonds for 2010-D, 201 IA, 201 IB, and 2011-C are presented in the following tables: Bond Proceeds (dollars in millions)2010D 2011A 20118 2011C Total CGS $ 155.81 $ 341.84 $ 29.92 $ 4.60 $ 532.17 Project 3 -10508 -105.08 Total $ 155.81 $ 446.92 $ 29.92 $ 4.60 $ 637.25 Weighted Average Coupon Interest Rate for Refunded Bonds (dollars in millions)2011A 2011B Total 5.38% 5.23%Weighted Average Coupon Interest Rate for New Bonds (dollars in millions)2010D 2011A 2 Total 5.70% 4.91% 4 Net Accounting Loss (Gain) ($ in millions)2010D 2011A 2011B CGS $ -$ (4.72) $ (6.27) $Project 3 (0.72)Total $ -$ (5.44) $ (6.27) $Total Defeased (dollars in millions)2010D 2011A 2011B CGS $ -$ 343.95 $ 4.37 $Project 3 105.10 -Total $ -$ 449.05 $ 4.37 $011B.92%2011C 2011C-$$Energy Northwest did not issue or refund any bonds 2011C associated with Packwood or Nine Canyon for FY 2011.3.55%° In prior fiscal years, Energy Northwest also defeased certain revenue bonds by placing the net proceeds from the refunding bonds in irrevocable trusts to provide for all Total required future debt service payments on the refunded (10.99) bonds until their dates of redemption.

Accordingly, the (0.72) trust account assets and liability for the defeased bonds (11.71)are not included in the financial statements in accordance with GASB statements No. 7 and 23. Including the FY 2011 Total defeasements, $33.6 million, $9.5 million, and $88.0 348.32 million of defeased bonds were not called or had not 105.10 matured at June 30, 2011, for Nuclear Projects Nos. 1 and 453.42 3, and Columbia respectively.

62 Energy Noithwest 2011 Anrmal Repoit Outstanding Long-Term Debt As Of June 30, 2011 (dollars In thousands)

Outstanding principal on revenue and refunding bonds for the various business units as of June 30, 2011, and future debt service requirements for these bonds are presented in the following tables: Columbia Revenue and Refunding Bonds Nuclear Project No. 1 Refunding Revenue Bonds Serial or Term Maturities Serial or Term Coupon Rate (%) Maturities Series Coupon Rate (%)Amount Series Amount 1992A 1994A 2002A 2002B 2003A 2003F 2004A 2004B 2004C 2005A 2005C 2006A 2006B 2006C 2006D 2007A 2007B 2007D 2008A 2008B 2008C 2008D 2009A 20098 2009C 2010B 2010C 2010D 2011A 20118 2011C 6.30 5.40 5.20-5.75 5.35-6.00 5.50 5.00-5.25 5.25 5.50 5.25 5.00 4.52-4.74 5.00 5.23 5.00 5.80 5.00 5.07-5.33 5.00 5.00-5.25 5.95 5.00-5.25 5.00 3.00-5.00 4.59-6.80 4.25-5.00 3.75-4.25 4.52-5.12 5.61-5.71 3.00-5.00 4.19-5.19 3.55 7-1 -2012 7-1 -2012 7-1-17/2018 7-1-2018 7-1 -12/2015 7-1-12/2018 7-1-17/2018 7-1 -2013 7-1-12/2018 7-1-1512018 7-1-12/2015 7-1 -20/2024 7-1-2011 7-1 -2012024 7-1 -2023 7-1-1312018 7-1-12/2021 7-1 -21/2024 7-1-14/2018 7-1-2012021 7-1-2112024 7-1 -2012 7-1-14/2018 7-1-14/2024 7-1 -20/2024 7-1 -20/2024 7-1 -20/2024 7-1 -23/2024 7-1-13/2023 7-1-19/2024 7-1-2019$ 50,000 100,200 157,260 63,140 103,845 27,015 129,260 12,715 17,230 114,985 55,945 434,210 45 62,200 3,425 77,575 10,665 35,080 110,935 12,025 37,240 74,950 116,425 18,515 69,170 16,005 75,770 155,805 311,245 29,920 4,600 19898 2001A 2002A 2002B 2003A 2004A 20048 2005A 2006A 2007A 20078 2007C 2008A 2008D 2009A 20098 2010A 20108 7.125 4.50-5.50 5.50-5.75 6.00 5.50 5.25 5.50 5.00 5.00 5.00 5.07-5.10 5.00 5.00-5.25 5.00 3.25-5.00 4.59 2.00-5.00 2.00 7-1-2016 7-1 -2011 7-1-13/2017 7-1-2017 7-1-13/2017 7-1-2013 7-1-2013 7-1-13/2015 7-1-11/2017 7-1-1312017 7-1-12/2013 7-1 -1 3/2017 7-1-13/2017 7-1-11/2017 7-1-14/2015 7-1-2014 7-1-11/2017 7-1-2011$ 41,070 73,010 248,485 101,950 241,455 62,485 1,135 72,175 206,575 51,730 6,740 219,020 230,535 62,085 48,905 515 71,150 815 Revenue bonds payable $ 1,739,835 Estimated fair value at June 30, 2011 $ 1,920,469 (B)(B) The estimated fair value shown has been reported to meet the disclosure requirements of the Accounting Standards Codification (ASC) 820 and does not purport to represent the amounts at which these obligations would be settled.Revenue bonds payable $ 2,487,400 Estimated fair value at June 30, 2011 $ 2,746,735 (B)(B) The estimated fair value shown has been reported to meet the disclosure requirements of the Accounting Standards Codification (ASC) 820 and does not purport to represent the amounts at which these obligations would be settled.

Ilo Taiorý 63 Nuclear Project No.3 Refunding Revenue Bonds Nine Canyon Wind Project Revenue and Refunding Bonds Series 1989A 1989B 1993C 2001A 2002B 2003A 2004A 20048 2005A 2006A 2007A 2007B 2007C 2008A 2008D 2009A 2009B 2010A 2010B 2011A Coupon Rate (%)(A)(A)7.125 (A)5.50 6.00 5.50 5.25 5.50 5.00 5.00 4.50-5.00 5.07 5.00 5.25 5.00 5.00-5.25 4.59 5.00 5.00 4.00-5.00 Serial or Term Maturities 7-1-1112014 7-1-1112014 7-1 -2016 7-1-13/2018 7-1-2011 7-01-2016 7-1-11/2017 7-1-14/2016 7-1 -2013 7-1-13/2015 7-1-16/2018 7-1-13/2018 7-1 -2012 7-1 -1 2/2018 7-1-2018 7-1-11/2017 7-1-14/2018 7-1 -2014 7-1-1612018 7-1 -2016 7-1 -2018 Amount$ 6,065 18,719 76,145 94,864 23,963 34,190 75,360 241,915 83,835 1,515 129,265 39,445 84,465 1,725 61,085 13,790 50,615 116,055 970 279,980 29,865 92,285 Series 2003 2005 2006 Coupon Rate (%)3.75-5.00 4.50-5.00 4.50-5.00 Serial or Term Maturities 7-1-11/2023 7-1-11/2023 7-1-11/2030 Amount 16,680 54,755 69,330 Revenue bonds payable $ 140,765 Estimated fair value at June 30, 2010 $ 146,424 (B)(B The estimated fair value shown has been reported to meet the disclosure requirements of the Accounting Standards Codification (ASC) 820 and does not purport to represent the amounts at which these obligations would be settled.Total bonds payable $ 5,992,915 Estimated fair value at June 30, 2011 $ 6,620,190 Compound interest bonds accretion 163,663 Revenue bonds payable $ 1,624,915 Estimated fair value at June 30, 2011 $ 1,806,562 (R)(A) Compound Interest Bonds (B) The estimated fair value shown has been reported to meet the disclosure requirements of the Accounting Standards Codification (ASC) 820 and does not purport to represent the amounts at which these obligations would be settled.

64 Energy Northwest 2011 An~nual, Rpcort Debt Service Requirements As Of June 30, 2011 (Dollars In Thousands)

Columbia Generating Station Nuclear Project No. 1 Fiscal Year 6/30/2011 Balance* $2012 2013 2014 2015-2017 2018-2022 2023-2024 Principal 45 $266,810 40,785 83,410 418,545 1,056,405 621,400 2,487,400

$Interest 62,801 $127,605 113,153 111,201 295,122 313,167 50,201 1,073,250

$Total 62,846 394,415 153,938 194,611 713,667 1,369,572 671,601 3,560,650 Fiscal Year 6/30/2011 Balance* $2012 2013 2014 2015 2016 2017 Principal 166,030 $56,030 276,250 368,040 191,970 326,980 354,535 1,739,835

$Interest 45,568 $82,769 80,079 65,788 46,787 37,197 19,373 377,561 $Total 211,598 138,799 356,329 433,828 238,757 364,177 373,908 2,117,396$$* Principal and Interest due July 1, 2011.Nuclear Project No. 3.Principal and Interest due July 1, 2011.Nine Canyon Wind Project Fiscal Year 6/30/2011 Balance $2012 2013 2014 2015 2016 2017 2018 Adjustment

• • Principal 103,514 $69,132 131,875 124,704 151,885 264,213 211,232 404,696 163,664 Interest 64,997 $95,934 100,433 92,367 64,116 58,814 43,694 29,230 Total 168,511 165,066 232,308 217,071 216,001 323,027 254,926 433,926 Fiscal Year 6/30/2011 Balance* $2012 2013 2014-2017 2018-2021 2022-2025 2026-2029 2030$Principal 4,260 $4,575 6,930 31,310 37,835 30,460 19,855 Interest 3,387 $6,570 6,351 21,873 15,445 7,827 3,305 249 65,007 $Total 7,647 11,145 13,281 53,183 53,280 38,287 23,160 5,789 205,772 5,540 140,765 $(163,664).Principal and Interest due July 1, 2011.$ 1,624,915 S 385,921 $ 2,010,836 Principal and Interest due July 1, 2011.-Adjustment for Compound Interest Bonds accretion; Compound Interest Bonds are reflected at their face amount less discount on the balance sheet Note 6 -Net Billing Security -Nuclear Projects Nos. I and 3 and Columbia The participants have purchased all of the capability of Nuclear Projects Nos. 1 and 3 and Columbia.

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

Under the net-bitting agreements for each of the business units, participants are obligated to pay Energy Northwest a pro-rata share of the total annual costs of the respective projects, including debt service on bonds relating to each business unit. BPA is then obligated to reduce amounts from participants under BPA power sales agreements by the same amount. The net-billing agreements provide that participants and BPA are obligated to make such payments whether or not the projects are completed, operable or operating and notwithstanding the suspension, interruption, interference, reduction or curtailment of the projects' output.

65 On May 13, 1994, Energy Northwest's Board of Directors adopted resolutions terminating Nuclear Projects Nos.1 and 3. The Nuclear Projects Nos. 1 and 3 project agreements and the net-billing agreements, except for certain sections which relate only to billing processes and accrued liabilities and obligations under the net-billing agreements, ended upon termination of the projects.Energy Northwest entered into an agreement with BPA to provide for continuation of the present budget approval, billing and payment processes.

With respect to Nuclear Project No. 3, the ownership agreement among Energy Northwest and private companies was terminated in FY 1999. (See Note 13)Security -Packwood Lake Hydroelectric Project The Packwood participants and Snohomish PUD have a Power Sales agreement that became effective in October 2008. Under the agreement, Snohomish PUD purchases all of the output directly.

The power purchase agreement (PPA) provides a predetermined rate for all firm delivery, per the contract schedule and the Mid-Columbia (Mid-C)based rate for all firm deliveries above firm, or secondary power. Packwood is obligated to supply a specified amount of power. If power production does not supply the required amount of power, Packwood is required to provide any shortfall by purchasing power on the open market which resulted in $17k of purchased power in FY 2011. Conversely, if there is excess capacity per the PPA with Snohomish PUD, Packwood sells the excess on the open market for additional revenues to be included as part of the PPA with the Packwood participants.

The Packwood participants are obligated to pay annual costs of the project including debt service, whether or not Packwood is operable, until the outstanding bonds are paid or provisions are made for bond retirement, in accordance with the requirements of the bond resolution.

The Packwood participants also share project revenue to the extent that the amounts exceed project costs.Note 7 -Pension Plans Substantially all Energy Northwest full-time and qualifying part-time employees participate in one of the following statewide retirement systems administered by the Washington State Department of Retirement Systems, under cost-sharing multiple-employer public employee defined benefit and defined contribution retirement plans. The Department of Retirement Systems (DRS), a department within the primary government of the State of Washington, issues a publicly available comprehensive annual financial report (CAFR) that includes financial statements and required supplementary information for each plan. The DRS CAFR may be obtained by writing to: Department of Retirement Systems, Communications Unit, P.O. Box 48380, Olympia, WA 98504-8380; or it may be downloaded from the DRS website at www.drs.wa.gov. The following disclosures are made pursuant to GASB Statements No. 27, Accounting for Pensions by State and Local Government Employers and No. 50, Pension Disclosures, an Amendment of GASB Statements No. 25 and No. 27.Any information obtained from the DRS is the responsibility of the State of Washington.

PricewaterhouseCoopers LLP (PwC), independent auditors for Energy Northwest, has not audited or examined any of the information available from the DRS; accordingly, PwC does not express an opinion or any other form of assurance with respect thereto.Public Employees' Retirement System (PERS)Plans 1, 2, and 3 PERS is a cost-sharing multiple-employer retirement system comprised of three separate plans for membership purposes:

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

Membership in the system includes:

elected officials; state employees; employees of the Supreme, Appeals, and Superior courts (other than judges currently in a judicial retirement system); employees of legislative committees; community and technical colleges, college and university 66 Energy Northwest 2011 Annual Report employees not participating in national higher education retirement programs; judges of district and municipal courts; and employees of local governments.

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

An employee is reported in Plan 2 until a choice is made. Employees who fail to choose within 90 days default to PERS Plan 3.Notwithstanding, PERS Plan 2 and Plan 3 members may opt out of plan membership if terminally ill, with less than five years to live.PERS Plan 1 and Plan 2 defined benefit retirement benefits are financed from a combination of investment earnings and employer and employee contributions.

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

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

If a survivor option is chosen, the benefit is further reduced. A cost-of living allowance (COLA) is granted at age 66 based upon years of service times the COLA amount, which is increased 3 percent annually.

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

To offset the cost of this annual adjustment, the benefit is reduced.PERS Plan 1 provides duty and non-duty disability benefits.

Duty disability retirement benefits for disablement prior to the age of 60 consist of a temporary life annuity payable to the age of 60. The allowance amount is $350 a month, or two-thirds of the monthly AFC, whichever is less. The benefit is reduced by any workers'compensation benefit and is payable as long as the member remains disabled or until the member attains the age of 60. A member with five years of covered employment is eligible for non-duty disability retirement.

Prior to the age of 55, the allowance amount is 2 percent of the AFC for each year of service reduced by 2 percent for each year that the member's age is less than 55. The total benefit is limited to 60 percent of the AFC and is actuarially reduced to reflect the choice of a survivor option. A cost-of living allowance is granted at age 66 based upon years of service times the COLA amount (based on the consumer Price Index), capped at 3 percent annually.

To offset the cost of this annual adjustment, the benefit is reduced.PERS Plan 1 members can receive credit for military service while actively serving in the military, if such credit makes them eligible to retire. Members can also purchase up to 24 months of service credit lost because of an on-the-job injury.PERS Plan 2 members are vested after the completion of five years of eligible service. Plan 2 members are eligible for normal retirement at the age of 65 with five years of service. The monthly benefit is 2 percent of the AFC per year of service. (AFC is the monthly average of the 60 consecutive highest-paid service months.)PERS Plan 2 members who have at least 20 years of service credit and are 55 years of age or older are eligible for early retirement with a reduced benefit. The benefit is reduced by an early retirement factor (ERF) that varies according to age, for each year before age 65.

67 PERS Plan 2 members who have 30 or more years of service credit and are at least 55 years old can retire under one of two provisions: " With a benefit that is reduced by 3 percent for each year before age 65." With a benefit that has a smaller (or no) reduction (depending on age) that imposes stricter return-to-work rules.PERS Plan 2 retirement benefits are also actuarially reduced to reflect the choice, if made, of a survivor option.There is no cap on years of service credit; and a cost-of-living allowance is granted (based on the Consumer Price Index), capped at 3 percent annually.The surviving spouse or eligible child or children of a PERS Plan 2 member who dies after leaving eligible employment having earned ten years of service credit may request a refund of the member's accumulated contributions.

Effective July 22, 2007, said refund (adjusted as needed for specified legal reductions) is increased from 100 percent to 200 percent of the accumulated contributions if the member's death occurs in the uniformed service to the United States while participating in Operation Enduring Freedom or Persian Gulf, Operation Iraqi Freedom.PERS Plan 3 has a dual benefit structure.

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

The defined benefit portion provides a monthly benefit that is 1 percent of the AFC per year of service. (AFC is the monthly average of the 60 consecutive highest-paid service months.)Effective June 7, 2006, PERS Plan 3 members are vested in the defined benefit portion of their plan after ten years of service; or after five years of service, if twelve months of that service are earned after age 44; or after five service credit years earned in PERS Plan 2 prior to June 1, 2003.Plan 3 members are immediately vested in the defined contribution portion of their plan.Vested Plan 3 members are eligible for normal retirement at age 65, or they may retire early with the following conditions and benefits: " If they have at least ten service credit years and are 55 years old, the benefit is reduced by an ERF that varies with age, for each year before age 65." If they have 30 service credit years and are at least 55 years old, they have the choice of a benefit that is reduced by 3% for each year before age 65; or a benefit with a smaller (or no) reduction factor (depending on age) that imposes stricter return-to-work rules.PERS Plan 3 defined benefit retirement benefits are also actuarially reduced to reflect the choice, if made, of a survivor option. There is no cap on years of service credit and Plan 3 provides the same cost-of-living allowance as Plan 2.PERS Plan 3 defined contribution retirement benefits are solely dependent upon the results of investment activities.

The defined contribution portion can be distributed in accordance with an option selected by the member, either as a lump sum or pursuant to other options authorized by the Director of the Department of Retirement Systems.PERS Plan 2 and Plan 3 provide disability benefits.There is no minimum amount of service credit required for eligibility.

The Plan 2 monthly benefit amount is 2% of the AFC per year of service. For Plan 3, the monthly benefit amount is 1% of the AFC per year of service.These disability benefit amounts are actuarially reduced for each year that the member's age is less than 65, and to reflect the choice of a survivor option. There is no cap on years of service credit, and a cost-of-living allowance is granted (based on the Consumer Price Index) capped at 3%annually.PERS Plan 2 and Plan 3 members may have up to ten years of interruptive military service credit; five years at no cost and five years that may be purchased by paying the required contributions.

Effective July 24, 2005, a member who becomes totally incapacitated for continued employment while serving the uniformed services, or a surviving spouse or eligible children, may apply for interruptive military service credit. Additionally, PERS Plan 2 and Plan 3 members can also purchase up to 24 months of 68, service credit lost because of an on-the-job injury.PERS members may also purchase up to five years of additional service credit once eligible for retirement.

This credit can only be purchased at the time of retirement and can be used only to provide the member with a monthly annuity that is paid in addition to the member's retirement benefit.Beneficiaries of a PERS Plan 2 or Plan 3 member with ten years of service who is killed in the course of employment receive retirement benefits without actuarial reduction, if the member was not at normal retirement age at death.This provision applies to any member killed in the course of employment, on or after June 10, 2004, if found eligible by the Department of Labor and Industries.

A one-time duty-related death benefit is provided to the estate (or duly designated nominee) of a PERS member who dies in the line of service as a result of injuries sustained in the course of employment, or if the death resulted from an occupational disease or infection that arose naturally and proximately out of said member's covered employment, if found eligible by the Department of Labor and Industries.

The defined contribution portion can be distributed in accordance with an option selected by the member, either as a lump sum or pursuant to other options authorized by the Employee Retirement Benefits Board.There are 1,189 participating employees in PERS.Membership in PERS consisted of the following as of the latest actuarial valuation date for the plans of June 30, 2009: contribution rate for Plan 3 are developed by the Office of the State Actuary to fully fund Plan 2 and the defined benefit portion of Plan 3. All employers are required to contribute at the level established by the Legislature.

Under PERS Plan 3, employer contributions finance the defined benefit portion of the plan, and member contributions finance the defined contribution portion.The Director of the Department of Retirement Systems sets Plan 3 employee contribution rates. Six rate options are available ranging from 5 to 15 percent; two of the options are graduated rates dependent on the employee's age. As a result of the implementation of the Judicial Benefit Multiplier Program in January 2007, a second tier of employer and employee rates was developed to fund, along with investment earnings, the increased retirement benefits of those justices and judges that participate in the program. The methods used to determine the contribution requirements are established under state statute in accordance with chapters 41.40 and 41.45 RCW.The required contribution rates expressed as a percentage of current-year covered payroll, as of December 31, 2010, are as follows: Employer*Employee PERS Plan 1 5.31%**6.00%**-*PERS Plan 2 5.31 3.90%****PERS Plan 3 5.31%***Retirees and Beneficiaries Receiving Benefits Terminated Plan Members Entitled to But Not Yet Receiving Benefits Active Plan Members Vested Active Plan Members Non-vested 74,857 28,074 105,339 53,896 The employer rates include the employer administrative expense fee currently set at 0.16 percent.The employer rate for state elected officials is 7.89 percent for Plan 1 and 5.31 percent for Plan 2 and Plan 3.Plan 3 defined benefit portion only.The employee rate for state elected officials is 7.50 percent for Plan I and 3.90 percent for Plan 2.Variable from 5.0 percent minimum to 15.0 percent maximum based on rate selected by the PERS 3 member.Both Energy Northwest and the employees made the required contributions.

Energy Northwest's required contributions for the years ending June 30 were as follows: Total 262,166 Funding Policy Each biennium, the state Pension Funding Council adopts Plan 1 employer contribution rates, Plan 2 employer and employee contribution rates, and Plan 3 employer contribution rates. Employee contribution rates for Plan 1 are established by statute at 6 percent for state agencies and local government unit employees, and at 7.5 percent for state government elected officials.

The employer and employee contribution rates for Plan 2 and the employer 2011 2010 2009$$$PERS Plan 1 184,863 $214,117 $244,531 $PERS Plan 2 7,921,762

$7,238,997

$6,774,304

$PERS Plan 3 4,281,077 3,971,410 2,964,075 69 Note 8 -Deferred Compensation Plans Energy Northwest provides a 401(k) Deferred Compensation Plan (401(k) Plan), and a 457 Deferred Compensation Plan. Both plans are defined contribution plans that were established to provide a means for investing savings by employees for retirement purposes.All permanent, full-time employees are eligible to enroll in the plans. Participants are immediately vested in their contributions and direct the investment of their contribution.

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

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

During FY 2011 Energy Northwest contributed

$2.9 million in employer matching funds.Note 9 -Other Employment Benefits-Post-Employment In addition to the pension benefits available through PERS, Energy Northwest offers post-employment life insurance benefits to retirees who are eligible to receive pensions under PERS Plan 1, Plan 2, and Plan 3. There are 83 retirees that remain participants in the insurance program. In 1994, Energy Northwest's Executive Board approved provisions which continued the life insurance benefit to retirees at 25 percent of the premium for employees who retire prior to January 1, 1995, and charged the full 100 percent premium to employees who retired after December 31, 1994. The life insurance benefit is equal to the employee's annual rate of salary at retirement for non-bargaining employees retiring prior to January 1, 1995.The life insurance benefit has a maximum limit of $10,000 for retirees after December 31, 1994. The cost of coverage for retirees remained unchanged for FY 2011 and was $2.82 per $1,000 of coverage.

Employees who retired prior to January 1, 1995, contribute

$.58 per $1,000 of coverage while Energy Northwest pays the remainder; retirees after December 31, 1994, pay 100 percent of the cost coverage.Premiums are paid to the insurer on a current period basis.At the time each employee retired, Energy Northwest accrued an estimated liability for the actuarial value of the future premium. Energy Northwest revises the liability for the actuarial value of estimated future premiums, net of retiree contributions.

The total liability recorded at June 30, 2011, was $0.6 million for these benefits.During FY 2011, pension costs for Energy Northwest employees and post-employment life insurance benefit costs for retirees were calculated and allocated to each business unit based on direct labor dollars. This allocation basis resulted in the following percentages by business unit for FY 2011 for this and other allocated costs; Columbia at 94 percent; Business Development at 4 percent; and Project 1, Nine Canyon, Packwood and Project 3 receiving the residual amount of 2 percent.Note 10 -Insurance Nuclear Licensing and Insurance Energy Northwest is a licensee of the Nuclear Regulatory Commission and is subject to routine licensing and user fees, to retrospective premiums for nuclear liability insurance, and to license modification, suspension, or revocation or civil penalties in the event of violations of various regulatory and license requirements.

Federal taw under the Price Anderson Act currently limits public liability claims from a nuclear incident.As of June 30, 2011, the current limit was $12.6 billion and is subject to change to account for the effects of inflation and changes in the number of Licensed reactors.As required by law, Energy Northwest has purchased the maximum commercial insurance available of $375 million, which is the primary layer of protection.

The remaining balance is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the United States results in claims that exceed the individual licensee's primary insurance layer. The current maximum deferred premium for each nuclear incident is $117.5 million per reactor, but not more than $17.5 million per reactor may be charged in any one year for each incident.Nuclear property damage and decontamination liability 70 Energy Northwest 2011I Annual Repoft insurance requirements are met through a combination of commercial nuclear insurance policies purchased by Energy Northwest and BPA. The total amount of insurance purchased is currently

$2.8 billion. The deductible for this coverage is $5.0 million per occurrence.

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

Upon initial recognition of the AROs that are measurable, the probability weighted future cash flows for the associated retirement costs are discounted using a credit-adjusted-risk-free rate, and are recognized as both a liability and as an increase in the capitalized carrying amount of the related long-lived assets. Capitalized asset retirement costs are depreciated over the life of the related asset with accretion of the ARO liability classified as an operating expense on the statement of operations and Net Assets each period. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss if the actual costs differ from the recorded amount. However, with regard to the net-billed projects, BPA is obligated to provide for the entire cost of decommissioning and site restoration; therefore, any gain or loss recognized upon settlement of the ARO results in an adjustment to either the billings in excess of costs (liability) or costs in excess of billings (asset), as appropriate, as no net revenue or loss is recognized, and no equity is accumulated for the net-billed projects.Energy Northwest has identified legal obligations to retire generating plant assets at the following business units: Columbia, Nuclear Project No. 1 and Nine Canyon.Decommissioning and site restoration requirements for Columbia and Nuclear Project No. 1 are governed by the NRC regulations and site certification agreements between Energy Northwest and the State of Washington and regulations adopted by the Washington Energy Facility Site Evaluation Council (EFSEC) and a lease agreement with the DOE. (See Notes 1 and 13) Additionally, there are separate lease agreements for land located at Nine Canyon.Leases at these locations are considered operating leases and expenses were $38.3k for Columbia, S35.Ok for Nuclear Project No. 1 and $641.6k for the Nine Canyon project.As of June 30, 2011, Columbia has a capital decommissioning net asset value of $16.6 million and an accumulated liability of $129.7 million for the generating plant, and for the ISFSI a net asset value of $1.1 million and an accumulated liability of $1.9 million.Restoration costs incurred in FY 2011 of $0.2 million combined with the current year accretion expense of$0.8 million and downward revision in future restoration estimates of $0.1 million resulted in the small increase to the ARO of $0.5 million. Nuclear Project No. 1 has a capital decommissioning net asset value of zero and an accumulated liability of $15.8 million.Under the current agreement, Nine Canyon has the obligation to remove the generation facilities upon expiration of the lease agreement if requested by the lessors. The Nine Canyon Wind Project recorded the related original ARO in FY 2003 for Phase I and II. Phase III began commercial operation in FY 2008 and the original ARO was adjusted to reflect the change in scenario for the retirement obligation, with current lease agreements of 71 reflecting a 2030 expiration date. As of June 30, 2011, Nine Canyon has a capital decommissioning net asset value of$0.6 million and an accumulated liability of $1.2 million.Packwood's obligation has not been calculated because the time frame and extent of the obligation was considered under this statement as indeterminate.

As a result, no reasonable estimate of the ARO obligation can be made.An ARO will be required to be recorded if circumstances change. Management believes that these assets wilt be used in utility operations for the foreseeable future.The following table describes the changes to Energy Northwest's ARO liabilities for the year ended June 30, 2011: Asset Retirement Obligation (dollars in millions)Columbia Generating Station Balance At June 30, 2010 Current year accretion expense ARO at June 30,2011 ISFSI Balance At June 30, 2010 Current year accretion expense ARO at June 30, 2011 Nuclear Project No. 1 Balance At June 30, 2010 Less: Restoration costs incurred Current year accretion expense Revision in future restoration estimates ARO at June 30,2011 Nine Canyon Wind Project Balance At June 30, 2010 Current year accretion expense ARO at June 30,2011$ 123.22 6.44$ 129.66$ 1.85 0.09$ 1.94 15.30 (0.16)0.79 (0.09)$ 15.84$ 1.14 0.05$ 1.19 Note 12 -Decommissioning And Site Restoration The NRC has issued rules to provide guidance to licensees of operating nuclear plants on decommissioning the plants at the end of each plant's operating life (See Note 11 for Columbia ARC). In September 1998, the NRC approved and published its "Final Rule on Financial Assurance Requirements for Decommissioning Power Reactors." As provided in this rule, each power reactor licensee is required to report to the NRC the status of its decommissioning funding for each reactor or share of a reactor it owns. This reporting requirement began on March 31, 1999, and reports are required every two years thereafter.

Energy Northwest submitted its most recent report to the NRC in March 2011.Energy Northwest's current estimate of Columbia's decommissioning costs in FY 2011 dollars is $463.5 million (Columbia

-$459.7 million and ISFSI -$3.8 million).

This estimate, which is updated biannually, is based on the NRC minimum amount required to demonstrate reasonable financial assurance for a boiling water reactor with the power level of Columbia.Site restoration requirements for Columbia are governed by the site certification agreements between Energy Northwest and the State of Washington and by regulations adopted by the EFSEC. Energy Northwest submitted a site restoration plan for Columbia that was approved by the EFSEC on June 12, 1995. Energy Northwest's current estimate of Columbia's site restoration costs is $96.4 million in constant dollars (based on the 2011 study) and is updated biannually along with the decommissioning estimate.

Both decommissioning and site restoration estimates (based on 2011 study) are used as the basis for establishing a funding plan that includes escalation and interest earnings until decommissioning activities occur. Payments to the decommissioning and site restoration funds have been made since January 1985. The fair value of cash and investment securities in the decommissioning and site restoration funds 72 Energy Northwest 2011 AnnuaL Report as of June 30, 2011, totaled approximately

$160.3 million and $25.4 million, respectively.

Since September 1996, these amounts have been held in an irrevocable trust that recognizes asset retirement obligations according to the fair value of the dismantlement and restoration costs of certain Energy Northwest assets. The trustee is a domestic U.S. bank that certifies the funds for use when needed to retire the asset. The trust is funded by BPA ratepayers and managed by BPA in accordance with NRC requirements and site certification agreements; the balances in these external trust funds are not reflected on Energy Northwest's Balance Sheet.Energy Northwest established a decommissioning and site restoration plan for the ISF51 in 1997. Beginning in FY 2003, an annual contribution is made to the Energy Northwest Decommissioning Fund. These contributions are held by Energy Northwest and not held in trust by BPA. The fair market value of cash and investments as of June 30, 2011, is $0.9 million. These contributions wilt occur through FY 2029; cash payments wilt begin for decommissioning and site restoration in FY 2025 with equal installments for five years totaling $2.06 million in constant dollars based on the 1997 study.Note 13 -Commitments And Contingencies Nuclear Project No. I Termination Since the Nuclear Project No.1 termination, Energy Northwest has been planning for the demolition of Nuclear Project No. 1 and restoration of the site, recognizing the fact that there is no market for the sale of the project in its entirety, and to-date no viable alternative use has been found. The final level of demolition and restoration will be in accordance with agreements discussed below under"Nuclear Project No. 1 Site Restoration." Nuclear Project No. 3 Termination In June 1994, the Nuclear Project No. 3 Owners Committee voted unanimously to terminate the project.During 1995, a group from Grays Harbor County, Washington, formed the Satsop Redevelopment Project (SRP). The SRP introduced legislation with the State of Washington under Senate Bill No. 6427, which passed and was signed by the Governor of the State of Washington on March 7, 1996.The legislation enables local governments and Energy Northwest to negotiate an arrangement allowing such local governments to assume an interest in the site on which Nuclear Project No. 3 exists for economic development by transferring ownership of all or a portion of the site to local government entities.

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

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

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

Members formed NoaNet pursuant to an Interlocal Cooperation Agreement for the development and efficient use by the members and others of a communication network in conjunction with BPA.The Business Development Fund has a 7.38 percent interest in NoaNet with a potential mandate of an additional 73 25 percent step-up possible for a maximum 9.23 percent.NoaNet has $14.3 million in network revenue bonds and note payables outstanding, based on their June 30, 2011 unaudited financial statements.

The members are obligated to pay the principal and interest on the bonds when due in the event and to the extent that NoaNet's Gross Revenue (after payment of costs of Maintenance and Operation) is insufficient for this purpose. The maximum principal share (based on step-up potential) that the Business Development Fund could be required to pay is $1.7 million. It is important to note that the Business Development Fund is not obligated to reimburse tosses of NoaNet unless an assessment is made to NoaNet's members based on a two-thirds vote of the membership.

In FY 2011 the Business Development Fund contributed

$63k to NoaNet based on assessments by the NoaNet members.Financial statements for NoaNet may be obtained by writing to: Northwest Open Access Network, NoaNet Headquarters, 5802 Overtook Ave. NE, Tacoma, WA 98422.Any information obtained from NoaNet is the responsibility of NoaNet. PwC has not audited or examined any information available from NoaNet; accordingly, PwC does not express an opinion or any other form of assurance with respect thereto.Other Litigation and Commitments Energy Northwest

v. United States of America filed in U.S.Court of Federal Claims in January 2004 (Cause No. 04-0010C). This is an action for breach of contract and breach of implied covenant of good faith and fair dealing brought by Energy Northwest against the United States (Department of Energy, "DOE") for damages for DOE's failure to meet its legal obligations to accept and dispose of spent nuclear fuel and high-level radioactive waste per the Standard Contract.Energy Northwest's claim was in the amount of $56.8 million. A bench trial was conducted in February 2009. The Court issued its opinion in February 2010, awarding Energy Northwest 100% of its claim. The Government appealed approximately

$10 million of the trial court's decision.The U.S. Court of Appeals for the Federal Circuit issued its decision on April 7, 2011 affirming the trial court's decision in part, reversing in part, and remanding the case to the trial court for further proceedings.

On July 8, 2011, DOE and Energy Northwest filed a Stipulation for Entry of Final Judgment in Favor of Plaintiff Energy Northwest and that same day, the Court of Federal Claims entered Final Judgment in the amount of $48.7 million which was received on August 29, 2011.Energy Northwest vs. United States of America filed in U.S. Court of Federal Claims in July 2011 (Cause No.1:11-cv-00447-EJD).

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

The outcome of the litigation is unknown at this time.Energy Northwest is involved in other various claims, Legal actions and contractual commitments and in certain claims and contracts arising in the normal course of business.

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

In the opinion of management, the outcome of such litigation, claims or commitments will not have a material adverse effect on the financial positions of the business units or Energy Northwest as a whole. The future annual cost of the business units, however, may either be increased or decreased as a result of the outcome of these matters.Energy Northwest experienced a significant delay in the completion of R-20. The planned outage extended past the fiscal year-end and was completed in September of 2011. R-20 was planned for 78 days and lasted 174 days.On October 21, 2011, the contractor for the majority of the condenser work for R-20 filed a claim against Energy Northwest for additional costs incurred in connection with the extended outage in the amount of $50 million. The Company intends to vigorously defend against this claim and cannot reasonably estimate the final outcome; however the potential range of exposure is between zero and $50 million. As of June 30, 2011, an accrual has been made for our best estimate of the potential loss within this range.

74 Energy Northwest 2011 Annual Report Note 14 -Derivative Instruments GASB Statement No. 53, "Accounting and Reporting for Derivative Instruments" was adopted in FY 2010. Energy Northwest's policy is to review and apply as appropriate the normal purchase and normal sales exception under GASB No. 53. Energy Northwest has reviewed various contractual arrangements to determine applicability of this statement.

Purchases and sales of nuclear fuel and components that require physical delivery and are expected to be used and/or sold in the normal course of business are generally considered normal purchases and normal sales. These transactions are excluded under GASB No. 53 and therefore are not required to be recorded at fair value in the financial statements.

Certain contracts for power options were evaluated and the following contract did not meet the exclusion for normal purchase and normal sale: The Business Development Fund had a power sales contract subject to the provisions of GASB No. 53. Call options associated with the contract had a notional amount of 50 MWh. The fair value of the power sales option contract is based on the futures price curve for the Mid-Columbia Intercontinental Exchange for electricity and the Sumas index for natural gas. This contract has an end date of June 2013. Assets associated with the call options are classified on the Balance Sheet as deferred charges (other deferred charges) and are currently valued at $0.1 million.Changes in the fair value of the call options are classified as non-operating revenue and expenses -investment income on the Statements of Revenues, Expenses and Changes in Net Assets.~@0 Current Debt Ratings (Unaudited)

Nine Canyon Rating Phase I & II Phase III Energy Northwest (Long-Term)

Net-Billed Rating Fitch, Inc.Moodys Investors Service, Inc. (Moodys)Standard and Poor's Ratings Services (S & P)AA Aaa AA A-A3 A-A3 A- A

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