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Basin Electric will provide cost-effective wholesale energy along with products and services that support and unite rural America.

Information requests:

Basin Electric Power Cooperative

Communications & Administration 1717 East Interstate Avenue, Bismarck, ND 58503-0564 Phone: 701.223.0441 • www.basinelectric.com


The seven cooperative principles are the bricks in Basin Electric’s foundation. The cooperative was created by its members to meet the energy needs of its members, today and always.

Contents Our generation owned and operated 2 Voluntary and open membership 3 At a glance 6 From our president and general manager 8 Democratic member control 10 Our boards of directors 10 Our management 12 Cooperation among cooperatives 14 Autonomy and independence 18 Education, training and information 24 Concern for community 28 Members’ economic participation 34 Five-year Financial Summary 39 , Independent Auditors Report 40 Consolidated Balance Sheets 41 Consolidated Statements of Operations 42 Consolidated Statements of Comprehensive Income (Loss) 43 Consolidated Statements of Changes in Equity 43 Consolidated Statements of Cash Flows 44 Notes to Consolidated Financial Statements 45

Baseload

Peaking

A Antelope Valley Station

I Culbertson Generation Station

Beulah, ND

2 units Coal 900 MW

Culbertson, MT

B Dry Fork Station Gillette, WY

1 unit Coal 386 MW

Spencer, IA

1 unit Natural gas/oil 80 MW

Basin Electric owns 50% of the plant. It is operated by Corn Belt Power Cooperative, Humboldt, IA.

C Laramie River Station 3 units

Natural gas 95 MW

J Earl F. Wisdom Station Unit 2

Basin Electric has a 92.9% ownership share.

Wheatland, WY

1 unit

K Groton Generation Station

Coal 1,710 MW

2 units Natural gas 196 MW

Basin Electric has a 42.27% ownership share.

Groton, SD

D Leland Olds Station

L Lonesome Creek Station

Stanton, ND

2 units

Coal

Watford City, ND

666 MW

1 unit

Natural gas 45 MW

M Pioneer Generation Station Williston, ND

Intermediate

Unit 2 declared commercial Feb. 1, 2014. Unit 3 declared commercial March 1, 2014.

E Deer Creek Station Elkton, SD

1 unit

Natural gas 300 MW

N Spirit Mound Station Vermillion, SD

2 units Oil 120 MW

O Wyoming Distributed Generation

Renewable F Chamberlain, SD

3 units Natural gas 135 MW

2 turbines Wind 2.6 MW nameplate

Hartzog, Arvada and Barber Creek, WY

9 units Natural gas 54 MW

G Minot, ND This 2013 Annual Report was written, compiled and produced by the employees of Basin Electric Power Cooperative and its subsidiaries. Editor: Andrea Blowers (ablowers@bepc.com) Graphic designer: Julie Ness Photographer: Steve Crane

82 turbines Wind 122.6 MW nameplate

Basin Electric operates the projects and has 100% ownership through PrairieWinds ND 1 Inc.

The 2014 Basin Electric annual meeting of the membership is scheduled for Nov. 5 and 6 in Bismarck, ND.

Committed peaking project

H White Lake, SD

L Lonesome Creek Station Phase 2

Equal Employment Opportunity Employer M/F/D/V

Basin Electric operates the project and has 92.6% ownership through PrairieWinds SD 1 Inc.

Annual meeting:

BASIN ELECTRIC POWER COOPERATIVE BASIN ELECTRIC POWER COOPERATIVE | 3

108 turbines Wind

162 MW nameplate

Watford City, ND

2 units Natural gas 90 MW

2015 expected completion.

BASIN ELECTRIC POWER COOPERATIVE | 2


Cooperatives are voluntary organizations, open to all people able to use its services and willing to accept the responsibilities of membership, without gender, social, racial, political or religious discrimination.

District 1

Kermit Pearson

East River Electric Power Co­opera­tive

Madison, SD

1 Agralite Electric Co­opera­tive 2 Bon Homme Yankton Electric Association 3 Central Electric Co­opera­tive 4 Charles Mix Electric Association City of Elk Point, SD 5 Clay-Union Electric Corporation 6 Codington-Clark Electric Co­opera­tive 7 Dakota Energy Co­opera­tive 8 Douglas Electric Co­opera­tive 9 FEM Electric Association 10 H-D Electric Co­opera­tive 11 Kingsbury Electric Co­opera­tive 12 Lake Region Electric Association 13 Lyon-Lincoln Electric Co­opera­tive 14 Meeker Co­opera­tive Light & Power Association 15 Northern Electric Co­opera­tive 16 Oahe Electric Co­opera­tive 17 Redwood Electric Co­opera­tive 18 Renville-Sibley Co­opera­tive Power Association Sioux Valley Energy 19 South Central Electric Association 20 Southeastern Electric Co­opera­tive 21 Traverse Electric Co­opera­tive 22 Union County Electric Co­opera­tive 23 Whetstone Valley Electric Co­opera­tive District 2 Gary Drost L & O Power Co­opera­tive

Rock Rapids, IA

1 Federated Rural Electric Association 2 Lyon Rural Electric Co­opera­tive 3 Osceola Electric Co­opera­tive 4 Sioux Valley Energy

District 3

Central Power Electric Co­opera­tive

Arden Fuher

1 Capital Electric Co­opera­tive 2 Dakota Valley Electric Co­opera­tive 3 McLean Electric Co­opera­tive 4 North Central Electric Co­opera­tive 5 Northern Plains Electric Co­opera­tive 6 Verendrye Electric Co­opera­tive 3 | 2013 ANNUAL REPORT

Minot, ND

District 4

Don Applegate

Northwest Iowa Power Co­opera­tive

Le Mars, IA

1 Harrison County Rural Electric Co­opera­tive 2 Iowa Lakes Electric Co­opera­tive 3 Nishnabotna Valley Rural Electric Co­opera­tive 4 North West Rural Electric Co­opera­tive Western Iowa Municipal Electric Association 5 Western Iowa Power Co­opera­tive 6 Woodbury County Rural Electric Co­opera­tive

District 5 

Tri-State G&T Association

Marshall Collins Denver, CO

1 Big Horn Rural Electric Company 2 Carbon Power & Light 3 Central New Mexico Electric Co­opera­tive 4 Chimney Rock Public Power District 5 Columbus Electric Co­opera­tive 6 Continental Divide Electric Cooperative 7 Delta-Montrose Electric Association 8 Empire Electric Association 9 Garland Light & Power Company 10 Gunnison County Electric Association 11 High Plains Power 12 High West Energy 13 Highline Electric Association 14 Jemez Mountains Electric Co­opera­tive 15 K.C. Electric Association 16 Kit Carson Electric Co­opera­tive 17 La Plata Electric Association 18 Midwest Electric Co­opera­tive Corporation 19 Morgan County Rural Electric Association 20 Mountain Parks Electric 21 Mountain View Electric Association 22 Niobrara Electric Association 23 Northern Rio Arriba Electric Co­opera­tive 24 Northwest Rural Public Power District 25 Otero County Electric Cooperative 26 Panhandle Rural Electric Membership Association 27 Poudre Valley Rural Electric Association 28 Roosevelt Public Power District 29 San Isabel Electric Association 30 San Luis Valley Rural Electric Co­opera­tive

31 32 33 34 35 36 37 38 39 40 41 42 43

San Miguel Power Association Sangre de Cristo Electric Association Sierra Electric Co­opera­tive Socorro Electric Cooperative Southeast Colorado Power Association Southwestern Electric Cooperative Springer Electric Co­opera­tive United Power Wheat Belt Public Power District Wheatland Rural Electric Association White River Electric Association Wyrulec Company Y-W Electric Association

District 6

Central Montana Electric Power Co­opera­tive

Roberta Rohrer Great Falls, MT

1 Big Flat Electric Co­opera­tive 2 Hill County Electric Co­opera­tive 3 Marias River Electric Co­opera­tive McCone Electric Co­opera­tive 4 NorVal Electric Co­opera­tive 5 Park Electric Co­opera­tive 6 Sun River Electric Co­opera­tive 7 Yellowstone Valley Electric Co­opera­tive

District 7

Mike McQuistion

Rushmore Electric Power Co­opera­tive

Rapid City, SD

1 Black Hills Electric Co­opera­tive 2 Butte Electric Co­opera­tive 3 Cam Wal Electric Co­opera­tive 4 Cherry-Todd Electric Co­opera­tive 5 Lacreek Electric Association 6 Moreau-Grand Electric Co­opera­tive 7 West Central Electric Co­opera­tive 8 West River Electric Association

Cooperatives that buy power from two districts are  identified by number in their voting district.

District 8

Upper Missouri Power Co­opera­tive

Allen Thiessen

Sidney, MT

1 Burke-Divide Electric Co­opera­tive 2 Goldenwest Electric Co­opera­tive 3 Lower Yellowstone Rural Electric Association 4 McCone Electric Co­opera­tive 5 McKenzie Electric Co­opera­tive 6 Mountrail-Williams Electric Co­opera­tive 7 Roughrider Electric Co­opera­tive 8 Sheridan Electric Co­opera­tive 9 Slope Electric Co­opera­tive 10 Southeast Electric Co­opera­tive

District 9

Wayne Peltier

1 Crow Wing Power 2 Grand Electric Co­opera­tive 3 KEM Electric Co­opera­tive 4 Minnesota Valley Co­opera­tive Light & Power Association 5 Minnesota Valley Electric Co­opera­tive 6 Mor-Gran-Sou Electric Co­opera­tive 7 Rosebud Electric Co­opera­tive 8 Wright-Hennepin Co­opera­tive Electric Association Class D Members

A Flathead Electric Co­opera­tive Wyoming Municipal Power Agency

District 10

Paul Baker

District 11

Charles Gilbert

Powder River Energy Corporation Sundance, Wyoming

Corn Belt Power Cooperative

Humboldt, IA

1 Boone Valley Electric Co­opera­tive 2 Butler County Rural Electric Co­opera­tive 3 Calhoun Rural Electric Co­opera­tive 4 Franklin Rural Electric Co­opera­tive 5 Grundy County Rural Electric Co­opera­tive Iowa Lakes Electric Cooperative 6 Midland Power Co­opera­tive 7 Prairie Energy Co­opera­tive 8 Raccoon Valley Electric Co­opera­tive North Iowa Municipal Electric Co­opera­tive Association


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A

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K O H

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BASIN ELECTRIC POWER COOPERATIVE | 5


Incorporated in

137

1961

2.85 million

MEMBER

consumers 2,100 miles transmission

MEMBER

s y s tem s more than

of high-voltage

9-state

service territory from the Canadian to Mexican borders

more than

consumer ...owned

not...for...profit generation and transmission

cooperative

2,000 employees

5,200 megawatts more than

electricity 6 | 2013 ANNUAL REPORT

9.5% coal 5 15.3% natural gas 14.3% renewable 6.0% hydro power 3.4% oil, diesel, jet fuel 1.5% nuclear


Our subsidiaries Dakota Gasification Company

• For-profit subsidiary of Basin Electric since 1988 and operates the Great Plains Synfuels Plant • Owns near Beulah, ND pipeline quality synthetic natural gas, fertiliz• Produces ers, carbon dioxide, crude cresylic acid, krypton/xenon gases, phenol, naphtha and tar oil

Souris Valley Pipeline Ltd.

• For-profit subsidiary of Dakota Gasification Company a daily average of more than 155-million • Transports standard cubic feet of carbon dioxide for enhanced oil

PrairieWinds SD 1 Inc.

• For-profit subsidiary of Basin Electric since 2008 • Owns a wind project near White Lake, SD Basin Cooperative Services

• Not-for-profit subsidiary of Basin Electric since 1981 resources and services for electric • Acquires plant generation Basin Telecommunications Inc.

• For-profit subsidiary of Basin Electric since 1995 a variety of managed hosting and security services • Markets under the name BTInet to Basin Electric members, indi-

recovery in Canada

Dakota Coal Company

• For-profit subsidiary of Basin Electric since 1988 and markets lignite coal from the Freedom Mine • Finances near Beulah, ND, which is owned and operated by The

viduals, small businesses and large corporations around the world

Coteau Properties Company

procurement and rail delivery of Powder River • Coordinates Basin coal to Laramie River Station, Dry Fork Station and Leland Olds Station

a lime plant near Frannie, WY, managed through a • Owns division called Wyoming Lime Producers since 1992

Montana Limestone Company

• For-profit subsidiary of Dakota Coal Company • Operates a limestone quarry since 2002 • Owns and operates a fine grind plant near Warren, MT 50% share of the Bighorn Limestone Company, • Owns which owns the surface and limestone reserves that Montana Limestone Company mines

PrairieWinds ND 1 Inc.

• For-profit subsidiary of Basin Electric since 2008 • Owns wind projects near Minot, ND

Basin Elect

ric Power C ooperative Headquarte Bismarck, N rs orth Dakot a

BASIN ELECTRIC POWER COOPERATIVE | 7


“ We do this because at the end of our power lines are people. ‚ That s who we work for. .  

T

o have a strong foundation, a business must be built on sound principles. Basin Electric was built on the seven cooperative principles. These principles aren’t just words, they’re not abstract concepts, they’re standards by which we define our actions. They include voluntary and open membership; democratic member control; members’ economic participation; autonomy and independence; education, training and information; cooperation among cooperatives; and concern for community. Though time, challenges and opportunities have molded us into the cooperative we are today, the principles we were founded on have not changed. Our principles have ensured that Basin Electric will continue to be a formidable force and a model of cooperative business in the region and nation well into the future. That’s because we work first and foremost for our members. Our members have laid every brick in our foundation, and today, we are 137 members and 2.8 million consumers strong. Together we strive to master the balance between risk, innovation and our obligation to provide reliable, low-cost power to our members. As we look to the future, we will continue to focus our work on maintaining that balance. In navigating the growth in our membership, the environmental regulatory challenges and the opportunities in a regional transmission organization (RTO), we act deliberately. We do this because at the end of our power lines are people. That’s who we work for. Our 8 | 2013 ANNUAL REPORT

members are people first and community focused. It’s also who we are. No level of success means anything if we do not make each and every individual’s safety and well-being our first priority. Day in and day out, we’ve got dedicated employees who work to provide reliable and affordable power, and we appreciate that they’ve made their own well-being a vital part of everything they do. We’ve always had a strong safety record. Our numbers consistently fall below industry average. But, work accidents still happen and they can translate into injuries. Until we have zero incidents, we have more work to do. To address this, Basin Electric employees are actively working to shift from a safety program to a safety culture. Working with Caterpillar Safety Services, we’ve conducted safety surveys, supervisor training, and have developed key messages and initiatives. Our top goal is to have a more empowered, aware and safe workforce. We need a focused workforce to work safely as well as tackle the challenges we’re facing, one of which is the Environmental Protection Agency’s (EPA) pressure on coal. The EPA’s regulations continue to thread through the cooperative’s day-to-day operations. The most recent example is its final ruling on Wyoming’s state implementation plan for regional haze. This action could cost Basin Electric and in turn our members hundreds of millions of dollars in emission control upgrades to the Laramie River Station for negligible difference in visibility,


“ Thank you for your part in building our foundation and , for what you ll do in helping to build our future.      

Wayne Peltier

which is what the regional haze program was created to address. Additionally, our members’ load demands are continuing to grow at a rapid pace, particularly in the Bakken region of northwest North Dakota and eastern Montana. We’re addressing this by working to firm up our transmission, build additional generation, and evaluate purchased power opportunities from the market. We’ve also elected to move towards an RTO, the Southwest Power Pool. We’ve been working closely with the membership and our Integrated System partners, Heartland Consumers Power District and the Western Area Power Administration. While the move is a shift from how we’ve historically operated, we believe Basin Electric can hold true to its principles and effectively operate in this new environment. We’ve always prided ourselves on being an innovator in the industry. We take measured risks and recognize when change is necessary.

Paul Sukut

That’s exactly how we’ve managed Dakota Gasification Company’s Great Plains Synfuels Plant. It’s brought incredible value to the membership, and it’s one of the reasons Basin Electric has some of the lowest rates of any G&T in the nation. The plant is truly a model of ingenuity and resourcefulness, and that continues with the approved addition of a urea plant. Our people are also models of ingenuity and resourcefulness. Give them a goal and they’ll find a way to achieve it. This attribute is especially important as we evaluate our internal processes through two initiatives, the Balanced Scorecard and a Point of View document. Both will help us work smarter, more efficiently and prudently prepare for the future.

competition for the best and brightest is much more arduous, we’re confident our recruitment program will help us successfully fill the vacated positions and orient our new employees to who we are and what we do. Workforce may turnover. New opportunities and challenges will surface. External agencies will continue to pressure us. The fact is we are still a cooperative. Our foundation is strong. We are built on principles and so long as we hold true to those principles, our cooperative bonds will only grow stronger. Thank you for your part in building our foundation and for what you’ll do in helping to build our future.

That includes having a workforce in transition. In 2013, many employees who dedicated 30, 35 and 40 years to the cooperative elected to retire. Their retirements are well-deserved and we wish them all the best.

Wayne Peltier, president

It’s difficult to see them go, but it opens doors for a new workforce. Though

Paul Sukut, interim CEO and general manager

BASIN ELECTRIC POWER COOPERATIVE | 9


Cooperatives are democratic organizations controlled by members – those who buy the goods or use the services of the cooperative – who actively participate in setting policies and making decisions.

Our boards of directors

E

ach Basin Electric director represents one of 11 membership districts. They also serve on their local distribution system board and their respective intermediate generation and transmission system board, with the exception of Districts 9 and 10. Basin Electric serves Districts 9 and 10 members directly. In addition to the Basin Electric board, the directors serve on the boards for subsidiaries Basin Cooperative Services, Basin Telecommunications Inc., PrairieWinds ND 1 Inc. and PrairieWinds SD 1 Inc.

2.85 million member-consumers

Districts 1-8 & 11

District 9

District 10

9 G&Ts, 9 board seats

1 board seat

1 board seat

Basin Electric Power Cooperative

Basin Electric board of directors

Kermit Pearson

Gary Drost

Arden Fuher

Don Applegate

Marshall Collins

Basin Electric director - vice president Dakota Gas director District 1, East River Electric Power Cooperative; electric cooperative board member since 1981; B.S. in animal science and agricultural education, South Dakota State University; farmer/rancher raising small grains and purebred Gelbvieh cattle

Basin Electric director - secretary/treasurer Dakota Gas director District 2, L & O Power Cooperative; electric cooperative board member since 1987; retired U.S. Navy Reserve; farmer raising corn, soybeans, beef cattle and hogs

Basin Electric director Dakota Gas director - vice chairman District 3, Central Power Electric Cooperative; electric cooperative board member since 1986; B.S. in economics and M.A. in school administration, both from North Dakota State University; retired small grains farmer; former high school math instructor and former high school principal

Basin Electric director Dakota Gas director - chairman District 4, Northwest Iowa Power Cooperative; electric cooperative director since 1966; past director National Rural Utilities Cooperative Finance Corporation; farmer raising corn and soybeans

Basin Electric director Dakota Coal director - treasurer District 5, Tri-State Generation and Transmission Association; electric cooperative director since 2008; realtor and retired rancher

Board member since 1997

Board member since 1999

Board member since 2012

10 | 2013 ANNUAL REPORT

Board member since 1997

Board member since 2013


Dakota Gasification Company external directors

Thomas Owens

Jim Geringer

Alan Klein

Dakota Gas director since 2001; retired University of North Dakota professor/ chairman of the Chemical Engineering Department; senior engineer, Exxon Production Research Company 1967-68 and 1973-74; B.S. in chemical engineering, University of North Dakota; M.S. and Ph.D. in chemical engineering, Iowa State University

Dakota Gas director since 2012; current director of policy at the Environmental Systems Research Institute; governor of Wyoming 1995-2003; served in the Wyoming Legislature 1982-1995; worked at the Missouri Basin Power Project’s Laramie River Station 1977-1979; served in the U.S. Air Force for 10 years and continued in reserve service for 12 years; B.S. in mechanical engineering, Kansas State University

Dakota Gas director since 2013; retired partner of Eide Bailly LLP; former partner-in-charge of Bismarck, ND, office; certified public accountant, served as a first lieutenant in the military for two years; B.S.B.A. in accounting and M.S. in accounting, both from University of North Dakota

Roberta Rohrer

Mike McQuistion

Allen Thiessen

Wayne Peltier

Paul Baker

Charles Gilbert

Basin Electric director - assistant secretary Dakota Coal director - chairman District 6, Central Montana Electric Power Cooperative; electric cooperative board member since 1979; farmer/cattle rancher

Basin Electric director Dakota Coal director District 7, Rushmore Electric Power Cooperative; electric cooperative board member since 1996; rancher

Basin Electric director Dakota Gas director - treasurer District 8, Upper Missouri Power Cooperative; electric cooperative board member since 1986; studied agriculture at Montana State University; partner in Town & County Repair in Lambert, MT; school bus contractor

Basin Electric director - president Dakota Coal director District 9; electric cooperative board member since 1999; studied mechanical drafting at Willmar (MN) Junior College; served in the U.S. Air Force and the South Dakota Air National Guard; farmer raising corn and soybeans and owner of P&K Fabricating near Cottonwood, MN

Basin Electric director Dakota Coal director District 10, Powder River Energy Corporation; electric cooperative board member since 1994; cattle rancher

Basin Electric director Dakota Coal director - vice chairman District 11, Corn Belt Power Cooperative; electric cooperative director since 1997; B.S.in agricultural business, Iowa State University; retired farmer

Board member since 2004

Board member since 2013

Board member since 2012

Board member since 2008

BASIN ELECTRIC POWER COOPERATIVE | 11

Board member since 2013

Board member since 2009


Our management

Paul Sukut

Claire Olson

Mike Eggl

Matt Greek

Interim CEO and general manager; employed with Basin Electric since 1983; experience in the energy industry since 1979; B.A. in business administration and political science, Jamestown (ND) College; M.S. in accounting and tax, University of North Dakota; Certified Public Accountant; Chartered Global Management Accountant

Senior vice president and General Counsel; employed with Basin Electric and the utility industry since 1975; B.S. in education, Minot (ND) State University; J.D., University of North Dakota

Senior vice president of Communications and Administration; employed with Basin Electric since 2002; experience in government relations & communications since 1994; B.A. in history; M.P.A. in public administration, University of North Dakota

Senior vice president of Engineering & Construction; employed with Basin Electric since May 2013; extensive managerial experience and in the utility industry for 35 years; B.S. in mechanical engineering, Bradley University in Peoria, IL; registered Professional Engineer

Board of Directors

Paul Sukut Interim CEO and General Manager

Claire Olson

Mike Eggl

Matt Greek

Steve Johnson

Senior vice president and General Counsel

Senior vice president of Com­ munications & Administration

Senior vice president  of Engineering & Construction

Interim senior vice president of Financial Services and CFO

Ellen Holt

Mark Kinzler

Shawn Deisz

Vice president of Human Resources

Vice president and CIO

Vice president and Controller

12 | 2013 ANNUAL REPORT


Steve Johnson

Mike Risan

Robert Bartosh

Dave Sauer

Interim senior vice president of Financial Services and chief financial officer; employed with Basin Electric and the utility industry since 1982; B.S. in accounting and business administration and M.S. in management, University of Mary in Bismarck, ND; Certified Public Accountant; Chartered Global Management Accountant

Senior vice president of Transmission; employed with Basin Electric and the utility industry since 1978; B.S. in electrical and electronics engineering, North Dakota State University; M.B.A., University of North Dakota; registered Professional Engineer

Senior vice president and chief operating officer of Dakota Coal Company and Montana Limestone Company; employed with Basin Electric since 1978; experience in fuel supply development since 1975; B.S. in civil engineering, Michigan Technological University; graduate work, Southern Illinois University; registered Professional Engineer

Senior vice president and chief operating officer of Dakota Gasification Company; employed with Basin Electric since 1989; former manager of the Great Plains Synfuels Plant; B.S. in mechanical engineering, North Dakota State University

John Jacobs

Dave Raatz

Ken Rutter

Vice president of Operations

Vice president of Cooperative Planning

Vice president of Marketing & Asset Management

Mike Risan Senior vice president of Transmission

Robert Bartosh Senior vice president and COO of Dakota Coal Company and Montana Limestone Company

Dave Sauer Senior vice president and COO of Dakota ­Gasification Company

Bryan Keller

Bob Fagerstrom

Steven Liebelt

Vice president of Transmission System Maintenance

Vice president of Strategic Studies

Vice president of Marketing & Sales, Dakota Gas

BASIN ELECTRIC POWER COOPERATIVE | 13


Cooperatives serve their members most effectively and strengthen the cooperative movement by working together through local, regional, national and international structures.

B

asin Electric and its members are a family, and as a family they work together toward common goals. The members provide guidance and support for Basin Electric, and Basin Electric provides reliable service for each member’s unique load obligations. As energy needs continue to grow throughout the cooperative, members help guide the decisions on how best to fulfill those needs. When external pressures threaten the cooperative’s ability to provide low-cost power to end consumers, Basin Electric calls on a strong and widespread grassroots network to confront the issues. In 2013, Basin Electric’s cooperative family grew. In February, the board of directors approved Class C membership for three New Mexico distribution cooperatives: Otero County Electric Cooperative, Cloudcroft, NM; Southwestern Electric Cooperative, Clayton, NM; and Socorro Electric Cooperative, Socorro, NM. All three are members of Tri-State Generation and Transmission Association. Then on June 1, Yellowstone Valley Electric Cooperative joined Basin Electric as a Class C member through Central Montana Electric Power Cooperative. Not only has Basin Electric grown in the number of cooperatives it serves, the members have grown in their power obligations to member-consumers. Their needs center on a steady strengthening of the economy and oil and gas development in the Williston Basin in western North Dakota and eastern Montana. One of the most telling signs of continued and aggressive growth in the system is the

14 | 2013 ANNUAL REPORT

member billing peak. Basin Electric’s system hit a new all-time member billing peak three times in 2013. In December, the system hit a new all-time member billing peak of 3,340 megawatts (MW). Just four months prior to that in August, it hit a peak of 3,063 MW, and the year opened in January with an all-time member billing peak of 3,012 MW. The member load forecast updates completed in April predict the cooperative will see more than 1,600 MW of load growth from 2012 through 2025. About two-thirds of that is Williston Basin area growth, which includes all residential, commercial, pipelines and associated services necessary to support the area. However, Basin Electric’s membership is diverse in geography. From the Canadian border to the Mexican border, there’s growth beyond oil and gas. Members are also seeing a slow and steady climb in transportation, manufacturing, housing, farming, ranching, rural residential and small commercial. While economic conditions are still slow to rebound along the U.S. coasts, many members throughout Basin Electric’s service area have been able to maintain growing economies. However, there are pockets within the membership that are not experiencing growth. While one co-op is growing, another co-op may not be, and over time those circumstances change. The strength of the Basin Electric family is the diversity of its members and how they join together to work for the benefit of all. That’s true on all fronts. Basin Electric and its members are inextricably connected to


Cooperatives help one another in good times and in tough times. When storms destroy transmission structures and systems, neighboring co-ops consistently offer help to ensure power is restored quickly. In 2013, a number of Basin Electric member co-ops experienced , the brunt of Mother Nature s destructive rages, including Basin Electric Class C member West River Electric Association in South Dakota. Photo credit: West River Electric BASIN ELECTRIC POWER COOPERATIVE | 15


peak demand growth anticipated from more than

2012-2025

1,600 megawatts

4systems

NEW MEMBER

Hit an all-time

high billing peak of

3,340 megawatts

16 | 2013 ANNUAL REPORT


each other, neighboring entities and the external environment. The external environment has continued to challenge the cooperative. The most predominant concern for Basin Electric has been the U.S. Environmental Protection Agency’s push regarding regional haze regulations. While the state of North Dakota prevailed in retaining its implementation plan for adhering to the Clean Air Act’s regional haze proposals, Wyoming is engrossed in a similar battle. On May 23, the EPA issued a re-proposed federal implementation plan (FIP), which would require additional expensive emission control technology at Laramie River Station. Approval of the re-proposed FIP would cost Basin Electric and the other members of the Missouri Basin Power Project hundreds of millions of dollars to install selective catalytic reduction (SCR) technology on each of the three units at Laramie River. The cooperative grassroots network was called into action and put up a good fight. The network includes member co-ops, impacted utilities, elected officials and many other stakeholders. Unfortunately, on Jan. 10, 2014, the EPA released its final action in the case rejecting the state’s plan in favor of setting a strict nitrogen oxides (NOX) emissions limit, which can only be achieved using SCR technology in addition to the over-fire air and low-NOX burners on all three units at Laramie River. Basin Electric has argued the more than $750 million price tag for SCR technology is not the most prudent choice for no discernable difference in visibility. In response to the ruling, the cooperative is examining several potential courses of action. In addition, Basin Electric has been working with its members, other cooperatives, utilities and state leaders to offer a reasonable solution regarding EPA’s proposed greenhouse gas standards for fossil fuel-based power plants and petroleum refineries, acknowledged in Section 111(d) of the Clean Air Act. The

proposed rule for 111(d) is not expected to be released until June 2014, but Basin Electric has fully engaged in listening sessions and offered input on its potential impact. EPA has already proposed a rule to regulate greenhouse gases from new power plants, represented in Section 111(b). On other fronts, Basin Electric continues making progress meeting Federal Energy Regulatory Commission (FERC) requirements to collectively plan systems and cost allocation methodologies on a regional basis. Through its participation in WestConnect and Mid-Continent Area Power Pool, the cooperative’s goal has been to ensure members are not inappropriately assigned the costs of transmission additions that primarily benefit others. FERC had also designated the North American Electric Reliability Corporation to enforce standards addressing the reliable operation of the electric grid. To meet these critical infrastructure protection (CIP) standards, Basin Electric has taken a team approach focusing on both cyber security and physical security issues. The CIP standards, including sabotage reporting, identification of critical cyber assets, security management, physical access and disaster recovery, are developed with input from industry and ultimately approved by FERC. These regulations and standards being created and enforced by EPA and FERC are only a sample of what Basin Electric and its members have faced in recent years. There are many other external pressures and factors that have and will continue to influence the operation and delivery of power within the Basin Electric system. But, Basin Electric, like other cooperatives, navigates through them by working in cooperation. With its grassroots structure, cooperatives make incredible things happen when they band together and collectively decide to get things done.

BASIN ELECTRIC POWER COOPERATIVE | 17


Cooperatives are autonomous, self-help organizations controlled by members. If the co-op enters into agreements with other organizations or raises capital from external sources, it is done so based on terms that ensure democratic control by the members and maintains , the cooperative s autonomy.

B

asin Electric is governed by its members and for its members. Its deep-rooted self-reliance has ensured it can maintain a stable energy resource portfolio and transmission network. The cooperative currently has 5,289 MW of generation capacity from a fleet fueled by coal, gas, oil, nuclear, heat recovery and wind and it maintains more than 2,100 miles of transmission. With such significant growth expected within the system, the membership continued to take steps again in 2013 to add to its resource mix. The cooperative’s financial forecast shows it will be investing more than $1.2 billion in generation and transmission assets with the greatest portion of that to be spent in the next five years. Two new facilities, Pioneer Generation Station and Lonesome Creek Station, began operating in 2013. Each unit at the plant sites is a 45-MW natural gas-fired peaking station in western North Dakota. Pioneer Unit 1 started commercial operation Sept. 4, 2013, Unit 2 started Feb. 1, 2014, and Unit 3 on March 1, 2014. The plant is located northwest of Williston. Lonesome Creek Unit 1 began commercial operation Dec. 1, 2013, and is located west of Watford City. In July 2012, the board of directors approved two additional units at Lonesome Creek. Lonesome Creek units 2 and 3 are expected to be completed in early 2015. In addition to the peaking resources, in June, Basin Electric issued a request for proposal

18 | 2013 ANNUAL REPORT

seeking power supply proposals for baseload, intermediate and peaking resources on both a short- and long-term basis. Of the proposals received, Basin Electric entered into contracts for 376 MW of wind opportunity from three different projects in North Dakota and South Dakota. The first two power purchase agreements for 278 megawatts of wind in North Dakota were signed on Nov. 6. The developer is Infinity Wind Power out of Santa Barbara, CA. The two projects are the Sunflower Wind Project, which will be a 106-megawatt project to be located near Hebron, ND, and the Antelope Hills Wind Project, which will be a 172-megawatt project to be located near Golden Valley, ND. Both are planned to be operational by the end of 2015. The third wind contract was signed Dec. 20 for an additional 98 MW of capacity. The power purchase agreement is associated with the development of the Campbell County Wind Farm to be constructed in South Dakota. It is co-owned by Fagen Inc. of Granite Falls, MN, and the principals of Dakota Plains Energy, Aberdeen, SD. It’s also planned to be operational by the end of 2015. Having adequate resources is only part of the planning puzzle. Transmission infrastructure is just as important as the megawatts produced. The biggest transmission project on the cooperative’s docket is the Antelope Valley Station to Neset 345-kilovolt (kV) line. The line will run approximately 200 miles from Antelope Valley Station near Beulah, ND, connect to substations near Grassy Butte and Williston,


Gerald and JoAnn DeFoe live south of Watford City, ND, in the heart of the oil and gas development in western North Dakota. They’re members of Basin Electric Class C member McKenzie Electric Cooperative. BASIN ELECTRIC POWER COOPERATIVE | 19


2013 transmission System Joint Ownership

Total Basin Basin Circuit Electric Electric Miles Owned Maintained

Integrated System

Basin Electric, Western Area Power Administration, Heartland Consumers Power District

Common Use Missouri Basin Power Project

9,447

1,554

1,518

262

Basin Electric, Black Hills Power, Powder River Energy Corporation

910

279

346

0

Basin Electric, Tri-State G&T, Wyoming Municipal Power Agency, Missouri River Energy Services, Heartland, Lincoln Electric System

681

288

301

0

47

88

0

Total Basin Electric miles

2,168

2,253

262

Other

Basin Electric Planned

Electric operating highlights Energy Sales (in millions of megawatt hours)

2013

To Class A and Class D members To others Total

20.4 18.7 9.1 6.2 7.2 (13.9) 26.6 25.9 2.7

Coal Consumed (in millions of tons)

2013

Wyoming sub-bituminous North Dakota lignite Total Forced-outage rate (five-year average)

2012

2012

Kenaston Tap Station Blaisdell 115-kV additions

Charlie Creek transformer

North Dakota 20 | 2013 ANNUAL REPORT

% change

9.3 8.9 8.4 7.8 17.7 16.7 4.09% 4.21%

Transmission additions and substations completed in 2013

% change

Leland Olds Station transformer

4.5 7.7 6.0 (2.9)


and end at the Neset 345-kV substation near Tioga, ND. Public Service Commission hearings on the line were held in September. Construction is scheduled to begin in 2014.

Part of this principle, however, means the cooperative is open to evaluating how external organizations could benefit the cooperative’s overall strategy.

Additional transmission analysis indicates the need for another 345-kV line in western North Dakota to assist with demand. The proposed line would run from Killdeer to Alexander.

For more than 10 years, Basin Electric, the membership, and its Integrated System (IS) partners Western Area Power Administration and Heartland Consumers Power District have carefully examined the possibility of joining a regional transmission organization (RTO). RTOs are a product of FERC Orders and are meant to provide non-discriminatory access to transmission across systems.

New transmission is important, but ensuring reliable delivery means the cooperative’s existing transmission lines meet high standards as well. Though the year’s weather was one of extremes, Basin Electric’s system experienced only minor storm damage. This enabled the cooperative’s Transmission System Maintenance staff to focus on maintenance, warehouse organization and support for new construction. This included construction of 115-kV ties lines to Pioneer and Lonesome Creek, and substation crews commissioned and assisted with the energization of the high-voltage equipment at the new power plants. Transmission System Maintenance supported the design, construction and commissioning of several new substations and substation expansions, including Kenaston, Charlie Creek and Laramie River Station 345-kV substations. Crews also installed new protective relaying for both 345-kV lines at Groton 345/115-kV substation. System reliability is being enhanced through an upgrade of the cooperative’s microwave system. New equipment is being installed at 56 sites in North Dakota and South Dakota to provide the additional bandwidth required by new generating and transmission system facilities. The new system will have six times the bandwidth of the existing system. Basin Electric’s ability to construct and maintain a stable resource portfolio and transmission network for its members epitomizes the principle of autonomy and independence.

After significant evaluation between three options, joining MISO, joining SPP or remaining independent, Basin Electric concluded that there is an overall positive economic benefit for IS parties to join SPP, and the cooperative was more philosophically aligned with SPP. The board approved a resolution at its April meeting authorizing Basin Electric staff to begin discussions, negotiations and contract development with SPP. However, Basin Electric was not pursuing membership without Western and Heartland. As a federal organization, Western was required to participate in a public process before making an RTO decision. On Nov. 1, Western published its formal recommendations to pursue negotiations with SPP. After a 45-day comment period and evaluation of comments received, on Jan. 10, 2014, Western reported it would also pursue formal negotiations for membership with SPP. Basin Electric and its members will continue to meet internally and with SPP to finalize the terms of the integration. The cooperative is targeting to have details worked out by spring 2014 so all parties can execute SPP membership agreements by that time. As the cooperative moves into this new operating environment, it’s doing so mindful of its mission and the principles from which it was

BASIN ELECTRIC POWER COOPERATIVE | 21


Dakota Gas products created. There will be changes, however. One of which is not solely related to RTO membership, but one of the group’s functions will be to manage Basin Electric within the RTO environment. Basin Electric’s Marketing & Asset Management Department was created to better manage the cooperative’s assets. Though Basin Electric and Western’s partnership goes back to the beginning of Basin Electric, the environment surrounding their shared IS system has become more and more constrained from the market and the cooperative’s obligations and generation assets are of such a size that it must be managed hour by hour. Rather than have the cooperative’s assets managed by Western, Western has been supportive of Basin Electric taking over managing it all from within the cooperative. The first step in this is the implementation of Basin Electric’s real time trading desk for west side operations, which will begin in February 2014. With a central office able to manage its fuel and power commodities, the changes in the prices of each commodity can actually be used to bring new value to the cooperative. The Marketing & Asset Management group provides another level of independence Basin Electric has not fully utilized before. It’s an opportunity to recognize more clearly the cooperative’s strengths and to prepare for the realities of the future.

Beyond natural gas, the gasification process yields valuable products, which Dakota Gas markets. Following are the 2013 production of each commodity and examples of end use.

Natural gas

Ammonium sulfate

Anhydrous ammonia

36.7

83,432

233,649 tons

fuel

DakSul® fertilizer

million dekatherms

tons

agricultural fertilizer

Carbon dioxide

47.3

billion standard cubic feet (salable)

enhanced oil recovery

Supporting the cooperative

B

asin Electric’s subsidiaries have been formed throughout its existence with a primary mission: support the cooperative and its members. Each is vital to the cooperative’s success.

Dakota Gasification Company

B

asin Electric’s largest subsidiary, Dakota Gasification Company, which owns and operates the Great Plains Synfuels Plant, had a year of transition, activity and milestones. In recent years, the board and management have brought renewed focus to the viability and profitability of the plant. Two initiatives that have served Dakota Gas well are the $5-a-dekatherm program, which is a mission to keep synthetic natural gas production costs at no more than $5 a dekatherm; and the Responsible Care® certification, which ensures safety and environmental stewardship at the facility. The activity at the Synfuels Plant was at its highest in the spring. For only the second time in its history, the plant went black, meaning everything was shut down. Five major projects and about 7,000 individual tasks were completed, including the tie-in of the clean cooling water system, which was the primary reason for the black plant because all systems are tied to the unit. In February, the tar oil stripper unit started up. With this addition, the rail load out was expanded to allow more shipments more quickly. The

22 | 2013 ANNUAL REPORT

expansion has provided four additional load stations increasing the product shipment from three cars a day to 12 cars a day. The addition of tar oil brought the total product count at the Synfuels Plant to 10, which includes natural gas. However, that number will increase yet again. Throughout the year, the board of directors and membership spent considerable time discussing potential additions to the plant – urea and diesel emission fluid (DEF). Urea is produced using anhydrous ammonia and carbon dioxide. It’s used as a solid nitrogen fertilizer and costs less to handle, store and transport than other nitrogen-based fertilizers. DEF is used to reduce NOX emissions in diesel engines as mandated by the federal government on all new diesel engines. The project was approved Jan. 27, 2014, and is projected to cost approximately $402 million. Since inception, Dakota Gas has invested approximately $665 million in plant additions and improvements and product development. For its product, carbon dioxide, the Synfuels Plant marked a milestone in February. The plant delivered its 25-millionth metric ton of carbon dioxide to the Canadian oil fields for enhanced oil recovery.

Dakota Coal Company

D

akota Gas and another subsidiary Dakota Coal Company also reached milestone anniversaries in 2013. Basin Electric created both 25 years ago in 1988. Dakota Gas was created to own and operate the Synfuels Plant and Dakota


Crude cresylic acid

26.3

million

pounds

wire enamel coatings, pesticides, vitamin E, antioxidants, dyes, solvents, insecticides, semi­conductors, electronic chips, alkylphenols, resins

Krypton/ xenon gases

Liquid nitrogen

3.6

gallons (salable)

million

liters

halogen headlights and light bulbs, lasers, window insulation

Coal was created to provide financing and ownership of certain mining rights. The Coteau Properties Company Freedom Mine supplies fuel for the Synfuels Plant, Antelope Valley Station and Leland Olds Station. In 2013, the mine neared the completion of a major reclamation project. Inside the Freedom Mine, the coal handling facilities were upgraded after 30 years of delivering more than 400 million tons of lignite. The upgrade allows the mine to reduce coal fines for customers like the Synfuels Plant in addition to lowering the cost of producing coal at the Freedom Mine. Dakota Coal also has a division, Wyoming Lime Producers, and another subsidiary, Montana Limestone Company. Wyoming Lime celebrated its 20-year anniversary of lime production and production of its 2.5 millionth ton of lime. Though Wyoming Lime’s objective is supporting Basin Electric’s facilities, it has also found additional markets in the Williston Basin. The same is true for Montana Limestone. Customers in the Williston Basin are using the powdered limestone to neutralize drill cuttings. With a growing market for smaller limestone

67,569

coolant, refrigerant, preservative

Naphtha

Phenol

Tar oil

7.7 million

20.3 million

13.5

feedstock for benzene, toluene, and xylenes, gasoline additives, paint thinners, solvents

polycarbonate products, oral analgesics, household cleansers, automotive parts, oriented strand board, plywood, counter tops, exterior siding, insulation

gallons

product, Montana Limestone is installing a pin mill crusher to help efficiency and produce more saleable limestone. In 2013, Wyoming Lime and Montana Limestone reached notable safety achievements. Both have had four years without a lost time accident, and on Dec. 16 Montana Limestone’s fine grind plant and rail load out facility achieved 10 years without a lost time accident.

PrairieWinds

T

he cooperative’s PrairieWinds subsidiary facilities in North Dakota and South Dakota attribute their year without injury to attention and training, and the technicians dedicate themselves to ensuring the turbines perform at their best. It’s working. Having the turbines available at a moment’s notice means they’re producing electricity whenever the wind blows. That translates into higher generation percentages than most wind facilities, even when the facilities shut down for migratory birds like whooping cranes, which is what happened at the Crow Lake Wind Project in South Dakota in April.

pounds

million gallons (salable)

fuel

Because of their commitment to responsible operation, over the course of about a month, the turbines were shut down whenever the cranes were spotted. To protect the endangered species, each technician is trained to spot whooping cranes, and the cooperative hires biologists to spend the migratory season on site to watch for cranes.

BTInet

R

esponsible operation is threaded throughout all business units within the cooperative, including BTInet. The data storage, firewall services and server hosting subsidiary was started in 1995 to provide services to member cooperatives. What started as a long distance telephone plan has evolved and expanded with technology. As part of its evolution, BTInet and Basin Electric’s information services and telecommunications group restructured over the last year. The new structure has given the group more depth of coverage for their customers. Though its primary focus is on member cooperatives, BTInet also provides technology services to tech companies and a host of other businesses.

Dakota Gasification Company operating highlights

Dakota Coal Company operating highlights

Revenue (in millions)

Coal sales $ 226.3 $ 225.1 0.5 Lime sales 13.1 13.2 (0.8) Limestone sales 5.3 5.1 3.9 Interest and other 4.6 4.1 12.2 Total $ 249.3 $ 247.5 0.7

Revenue (in millions)

2013 2012 % change

Synthetic gas sales $ 203.9 $ 252.4 Byproduct, coproduct and other sales 292.4 295.3 Interest and other income 3.9 3.4 Total $ 500.2 $ 551.1

(19.2) (1.0) 14.7 (9.2)

Synthetic gas sold (dekatherms in millions) 45.3 50.7 (10.7) Coal consumed (tons in millions) 5.6 6.1 (8.2)

Sales (in tons)

2013 2012 % change

2013

2012

Coal (in millions) 13.8 13.1 Lime (in thousands) 152.7 150.4

BASIN ELECTRIC POWER COOPERATIVE | 23

% change

5.3 1.5


Cooperatives provide education and training for members, elected representatives, managers and employees so they can contribute effectively to the development of their cooperative. Members also inform the general public about the nature and benefits of cooperatives.

B

asin Electric has always put a high priority on its members as well as it employees. These people are the heartbeat of the cooperative. Having welltrained and knowledgeable employees means electricity is most economically and efficiently delivered to members. Beyond that, the cooperative wants employees who care about what they’re doing, not only for themselves, but also those around them. A workforce that considers its well-being and that of its fellow employees can never be overrated. Though Basin Electric’s safety records have consistently been better than average, better than average is not how the cooperative wants its employees to think about its safety program. During the year, Basin Electric refocused its efforts to ensure employees put safety above everything else. To do that, Caterpillar (CAT) Safety Services was called on to assist the cooperative with implementing its Zero-Incident Performance Process. The idea is to evolve the cooperative’s safety program from incident reaction to

Safety DART: days away, restricted or transferred TCIR: total case incident rate Industry

Basin Electric overall 3

2.7

2.8

2

1.2

1

1.5

0 TCIR

24 | 2013 ANNUAL REPORT

DART

culture creation. That began with a survey of employees at all facilities during the summer to gather safety perceptions from co-op employees. Basin Electric’s senior leadership team reviewed the survey results with CAT Safety professionals in September and determined the main areas of focus: supervisor development, communication and off-the-job safety. The Safety Steering Team and each Continuous Improvement Team assigned to these areas are working to develop new or better ways of doing things. The new processes will be piloted and rolled out across the cooperative business units. Moving to a safety culture is just one of a number of transitions employees are working through. Another is the baby boomer retirement boom. In 2013, 179 experienced, knowledgeable 20-, 30- and 40-year employees welcomed retirement. Two factors made 2013 the perfect year to retire: employees were at retirement age, and low discount rates on the cooperative’s defined benefit retirement plan made lump sum distributions very attractive. Having anticipated the start of the baby boomer retirements, the business units within the cooperative and human resources had already begun succession planning to identify redundancies in critical areas and strengthen cross-training. Knowledge transfer has been a key component of the succession process. Nevertheless, it’s been more difficult in recent years to attract skilled individuals into these


Basin Electric, its employees and members understand the importance of being present and involved in their communities. Employees like Jeremy Severson (left), electrical engineer III, who demonstrates his commitment to the cooperative principles wearing one of the Touchstone Energy速 puppets during the Mandan (ND) Independence Day Parade. BASIN ELECTRIC POWER COOPERATIVE | 25


Sharing electric & cooperative knowledge Story Behind the Switch

B

asin Brittany and Electric Eric made their debuts at schools across Basin Electric’s service territory Kim Kranz (c enter), demon stration coor in 2013. They’re part of nator, travel dis across Basin Electric’s serv territory to Basin Electric’s 30-year-old ice present the 45-minute pr ogram. school-based electricity education program, the Story Behind The Switch. The two new characters helped tell the story of electricity safety, generation and its incredible value to elementary kids from North Dakota to New Mexico. As part of the program’s facelift, it has new graphics, a 45-inch flat screen television and a PowerPoint slideshow. What hasn’t changed: the plasma ball, a highlight of the demonstration; and the Van de Graff generator, also a favorite.

Efficiency & Technology Display Program

W

ith a change of focus in recent years, a program that once centered on promoting electric technologies has expanded to also promote energy efficiency and conservation through innovative technologies.

Approaching its 20-year birthday, the Efficiency and Technology Display Program offers an opportunity to experience firsthand technologies that can help members get more value out of their energy dollar. The program is a service to member cooperatives and annually reaches about 70 events including annual meetings; home, farm and ranch shows; state and county fairs; schools; and state capitols and local government events.

ram coordian (right), prog Michael Riedm e capitols events at stat nator, attends with leglk ta bership to across the mem t energy ou ab rs aff membe islators and st conservation. efficiency and

26 | 2013 ANNUAL REPORT


open positions. There’s simply more competition in the region. That hasn’t stopped Basin Electric from continuing to be the employer of choice. It’s simply a matter of knowing what employees need and want. To do that, Basin Electric consistently examines everything from its recruitment program to its benefit structure. Anticipating more retirements in the next few years, human resources has already begun hiring early to fill positions that will open as long-time employees leave. Part of that is Basin Electric’s long-time commitment to partnering with colleges and universities to grow and harvest new employees. Foundationally, Basin Electric wants employees who meet two criteria – a passion for their work and the knowledge and commitment to the way cooperatives conduct business. Having a strong team points back to the reason Basin Electric was created – to serve its members. The members want to know their cooperative is sound and balanced. A knowledgeable team will ensure that happens. In 2013, the cooperative took that a step further initiating two strategic processes – Balanced Scorecard and Point of View. Both will provide data to help Basin Electric strategically position itself for what the future may hold. In the early part of the year, Basin Electric staff began Phase I development of the Balanced Scorecard, which is a management tool that helps individuals and departments see how they’re contributing to Basin Electric overall. In Phase 1 various areas of the organization identified operational metrics important to their functions and responsibilities.

The scorecard process will continue throughout 2014 with final implementation set for 2015. The process is involved and complex. The objective is to insure Basin Electric is at its best; and to develop a useful tool to monitor and improve each area over the long-term. Working smarter, more efficiently, and most of all, being prepared is only prudent. The second initiative is the Point of View. The Point of View is meant to broaden the knowledge of key issues external to Basin Electric and its membership that could impact the industry and/or the cooperative. Working with the membership, the cooperative has identified six topics for further investigation – fuel choice, security, technology, the changing member, politics and regulations, and economics. Each topic will be analyzed and the results are expected to be communicated back to the board, senior staff and the membership in the summer of 2014. Trackable measurement and recognizing external influences are important pieces of a strategic plan. As Basin Electric prepares once again to define that plan in 2014, it’s also reevaluating its vision and mission statements to ensure they express what the cooperative’s present purpose is (mission) and what it wants to achieve over time (vision). Simply put: the mission and vision statements and Point of View help develop a strategic plan, and the scorecard helps implement and measure performance so Basin Electric can continue to succeed at what it was created to do – serve its members.

Accolades

B

asin Electric received two awards for being one of the best workplaces in the Bismarck-Mandan community. The Bismarck-Mandan Young Professionals Network awarded Basin Electric as one of the “top 10 Young Professional workplaces” in 2013. Basin Electric was recognized as the “Best Large Company to Work For” with 75-plus employees by The Bismarck Tribune’s Best of the Best – Readers’ Choice 2013 list. BASIN ELECTRIC POWER COOPERATIVE | 27


While focusing on member needs, cooperatives work for the sustainable development of communities through policies and programs accepted by the members.

C

ommunity for Basin Electric is the mortar in its foundation. It’s how members and employees feel connected. It’s people helping people, organizations and charities providing life-changing, sometimes life-saving services. It’s a desire to be good stewards of the land, air and water. Of all the principles defining cooperatives, this one sets Basin Electric apart from other businesses. The cooperative’s story is deeper than simply providing electricity to members, it’s about the people themselves and what they need – whether its help fixing up a house, money for college, assistance in serving meals to the homeless. Basin Electric and its employees give time and resources consistently, year-round with the hope of helping their communities be better. Each year, Basin Electric and its subsidiaries give $1.3 million to charitable projects, events and organizations. More than a third of that is set aside as member matching funds. The cooperative’s Charitable Giving Program is broken down into four categories: community development and enrichment; education and youth development; health and human services; and cultural and fine arts. The cooperative also has major fundraising campaigns throughout the year for larger local and national organizations. In 2013, Basin Electric supported three major campaigns – United Way, St. Baldrick’s and Give More to Moore.

28 | 2013 ANNUAL REPORT

Our people

B

asin Electric recognizes its employees want to help the communities where they live and work. Employees are Basin Electric’s ambassadors. They’re the boots on the ground impression the communities have of the cooperative. Basin Electric isn’t just trying to appear to care about its communities, its doing what it can to ensure there’s enough food and shelter for all, and that every child has the tools and opportunities they need to succeed. Youth and education is vital for community sustainability. Basin Electric invests in proper tools and resources to help keep kids in school, help them go on to college and prepare them to be leaders in their communities. Each year, the cooperative awards $1,000 scholarships to more than 180 students in its communities. Scholarships are awarded to children of member cooperative consumers, member cooperative employees and Basin Electric and subsidiary employees. Since the program’s inception in 1991, Basin Electric has given more than $3.75 million to more than 3,800 students. In addition to scholarships, Basin Electric provides assistance through dollars and training opportunities to schools to help educate the future workforce. One example: the cooperative takes students from Bismarck State College to work at its plant facilities to help them fulfill their required two-week internships. The benefit is two-fold: students gain experience and Basin Electric gets to meet potential new employees.


Basin Electric employee Darrell Schulz helps plant a replacement tree on private land near the PrairieWinds site south of Minot, ND. Approximately 989 trees and 345 shrubs were removed during construction of the 115.5-megawatt wind project. However, Basin Electric staff planted replacement trees and shrubs on a two-for one-basis, so in total, approximately 3,100 trees and shrubs were planted in place of those removed. BASIN ELECTRIC POWER COOPERATIVE | 29


Charitable contributions 2013 distribution Health & human services

18%

Education & youth development

24%

Cultural & arts

8%

Community development & enrichment

50%

United Way

$210,000

Basin Electri ’ cs y ar Pumpkin Patc team helped Papa’s ch Za s, ee av sh d an rs h rebuild, re he Two young brot furbish and refresh its ch eiand, shaved on W en Aid d aritable ope an ) ft Weiand (le ’s team Cut the Unite ration durin k ric ld Ba . St – d e g Way’s Day of . es the Brave the Shav inn C Th a aring. Mi e ort of honore pp su in r ue nq Co to

+$1,000,000

Brave the Shave St. Baldrick’s events

in 6 YEARS

30 | 2013 ANNUAL REPORT


Basin Electric’s financial support cannot be ignored. In 2013, the cooperative gave more than $113,000 to colleges and institutions in its communities. One recent example is the donation Basin Electric made toward construction of a Student Campus Center at the University of Mary in Bismarck, ND. The new center is meant to bring together diverse services for students, faculty, staff and guests and provide a more easily accessible location for the bookstore and multi-use spaces. Basin Electric proudly supports education. It’s also proud to employ and support members of the United States Armed Forces. The cooperative strives to go above and beyond what the law requires for employees and their families at home and while deployed. Nearly 10 percent of the cooperative’s workforce is veteran or active military and, in fact, Basin Electric emphasizes the recruitment of veterans and current military service members.

Our communities

B

asin Electric takes care of its own. In one way or another, that commitment touches every person in its communities and beyond. In appreciation for the constant support they receives, Basin Electric and its employees give back through various philanthropic activities and charitable contributions. One organization, which has been stamped with Basin Electric involvement for many years, is United Way. In true form, the cooperative’s United Way committee organized several events and fundraisers leading up to the employee giving campaign. The employee campaign again surpassed its goal of $100,000 and, in total, Basin Electric and employees gave $210,000 to support United Way agencies in their communities. On Jan. 31, 2014, Missouri Slope Areawide United Way recognized Basin Electric as the top corporate contributor to the 2013 campaign.

Another campaign dear to Basin Electric and its employees is the Brave the Shave – St. Baldrick’s event held each year at various locations within the cooperative family and beyond. In its sixth year, Basin Electric’s community outreach and participation hit a new high. With a goal to surpass $1 million in total for all of its six years, participants, who raise money and shave their heads or cut their hair to help fund pediatric cancer research and fellowships, raised $333,809 and surpassed the $1 million goal by more than $85,000. Some of the events held in 2013 were a Guns N’ Hoses event, featuring police officers and firefighters vying to see who could raise more; an event at the Brookings (SD) Fire Station with employees from Deer Creek Station and South Dakota State University’s Sigma Lambda Chi Construction Management Honor Society; and a Sanford Health St. Baldrick’s event. St. Baldrick’s Foundation recognized the dedication Basin Electric puts forth each year to organize the events and, in 2013, awarded Sanford Medical Center with a grant for $44,700 named after the cooperative. It’s called the Basin Electric Power Cooperative St. Baldrick’s Infrastructure Grant and will be used for additional education for nursing staff caring for oncology patients. Basin Electric also jumps in to help after a natural disaster strikes. When the EF5 tornado killed 24 people, injured 387 and destroyed an estimated 1,150 homes in Moore, OK, in May, Basin Electric jumped right in with a desire and a plan to help. In collaboration with the Touchstone Energy® Oklahoma Relief Fund, Basin Electric launched an effort to assist Oklahoma cooperative members affected by the deadly tornado. Employees paid at least $130 to wear jeans to work all summer. In total, employees raised more than $16,000. In addition, Basin Electric purchased cases of dry socks, sunscreen and bug spray for the linemen working to restore power.

BASIN ELECTRIC POWER COOPERATIVE | 31


Snapshots of generosity Day of Caring s ral manager, help rim CEO and gene one Soup Kitchen. te in t, ku Su ul Pa St l at Ruth Meiers’ serve a noon mea

Basin Electric’s Rebuilding Togethe r team helped a couple in Mandan, ND.

E

ach year, employees join hundreds of others in their communities to assist with renewing and revitalizing human service agencies and schools that cannot afford to do it on their own. In addition to working at Papa’s Pumpkin Patch, employees in Hazen and Beulah had an opportunity for the first time in 2013 to participate in a Day of Caring in their community. Volunteers from Dakota Gasification Company helped repair and stain a large wheelchair access ramp, install new carpeting and other tasks at Mercer County Women’s and Action Resource Center.

Ruth Meiers Stone Soup Kitchen

B

asin Electric employees serve lunch at Ruth Meiers the third Wednesday of each month. Five to 7 employees are given two hours to volunteer with meal preparation and service for homeless and low-income individuals in the Bismarck‑Mandan (ND) community.

h Dakota ites at the Nort All of the graves placed on ry had a wreath Veteran’s Cemete esite of Senior Adminisgrav it, including the h’s father. Michelle Weidric nt ta sis As ive at tr

Basin Electric staff co nstructed the large puppet-sized Touchstone Energy® human connec tion icons to accompany th e cooperative’s 4 th of July float.

Rebuilding Together

O

n April 27, the cooperative’s Rebuilding Together team members upgraded a Mandan (ND) couple’s bathroom to make it wheelchair accessible.

Sanford Health Great American Bike Race

B

asin Electric’s Basin Power Pedalers biked 82.26 miles and raised more than $5,000 for equipment and services for families of those diagnosed with cerebral palsy and similar disabilities.

Wreaths Across America

B

asin Electric gives $1,500 each year, enough to supply 100 wreaths at the North Dakota Veterans Cemetery for the Wreaths Across America campaign. Wreaths Across America coordinates wreath laying ceremonies at veterans’ cemeteries across the country. This was the first year there were enough donations to put a wreath on every one of the more than 5,000 gravesites at the North Dakota cemetery.

Community connections 4th of July Parade

N

early 140 cooperative employees and family members proudly walked alongside Touchstone Energy’s® Mandan Independence Day Parade float. The float featured three tiers in the form of a pyramid. The bottom tier represented Basin Electric, the middle tier represented Basin Electric’s member distribution cooperatives and the top tier represented individual member-owners. The float was voted best in the “Theme” category for its well-executed theme of cooperative philosophy.

32 | 2013 ANNUAL REPORT

Touchstone Energy® Co-op Connections

B

asin Electric launched a reinvigorated Co-op Connections Card discount program as a benefit to all employees and local and national businesses. As part of the economic fiber of its communities, Basin Electric’s Co-op Connections encourages employees to shop locally and support their local communities, and it provides free advertising for smaller businesses and a measurable way to attract new and repeat customers.


Our environment

B

asin Electric uses natural resources to generate the electricity its members need, so the cooperative has first-hand understanding of how vital and valuable these resources are. Waste is not an option. In fact, employees are charged with finding ways to be more efficient and use less. Cooperatives seek to keep costs down because conservation keeps the cost of electricity low for members and, ultimately, the folks at the end of the line. At its plant facilities, Basin Electric and its subsidiaries have a lot to boast about. They’re all 100 percent environmentally compliant with systems in place to ensure that continues. Through 2013, Basin Electric invested nearly $1.3 billion in power plant emissions control technology. More than $100 million was spent in 2013 to operate and maintain those controls. One of those is the Leland Olds Station scrubber addition. Two wet limestone scrubbers, which remove sulfur dioxide, were installed on both units at the plant and began operating in 2013. According to reports, the scrubbers have been producing at better than design performance. They were added to comply with the U.S. Environmental Protection Agency’s regional haze rule and will extend the longevity of the plant. Other projects at the cooperative’s Antelope Valley Station are being completed also in response to environmental regulations. The first is the construction of a 3-mile natural gas pipeline from the Great Plains Synfuels Plant to Antelope Valley. The purpose is to provide igniter fuel for the station to be used during periods of start-up, shut down and malfunction. The switch will ensure more efficient plant operations during those times.

Basin Electric is family first, organization second. It was created to serve its members by working hard and doing the right thing.

The second project at Antelope Valley is the separated over-fire air (SOFA) project, which is being implemented to reduce NOX emissions by more than 55 percent. Both projects will be complete and tied in during Antelope Valley’s planned spring 2014 outage. One project that wrapped up in 2013 was the replacement of trees at the PrairieWinds ND project near Minot. Before Basin Electric built the wind farm, the cooperative made a commitment to plant two trees for every one removed during construction. An inventory was kept of all the trees taken out and, in the fall, employees finished planting

the last 100 of about 3,000 trees. In total, about 15 percent more trees were planted than the original commitment required. Many of the replacement trees, which included cottonwood, hackberry, chokecherry, green ash, conifers and pine trees, will actually provide better food and shelter for wildlife than the ones removed. It’s part of the cooperative’s long-standing commitment to reclamation practices. Keeping the environment clean is among the cooperative’s top priorities. It all comes back to why the cooperative exists – people. Basin Electric is family first, organization second. It was created to serve its members by working hard and doing the right thing. There are challenges ahead; that is certain. But they’ve never stopped Basin Electric before. The strength of the cooperative is in its foundation – its members, its principles and its desire to serve. The cooperative always finds a way to do great things and it always will.

2013 pollution control costs (in thousands) Capital cost Facility life-to-date

Antelope Valley Station $ 340,046.5 Culbertson Generation Station 4,818.9 Deer Creek Station 28,429.8 Dry Fork Station 296,319.7 Groton Generation Station 4,543.3 Laramie River Station (Basin only) 183,952.8 Leland Olds Station 434,390.1 Lonesome Creek Station 3,026.9 Pioneer Generation Station 3,014.8 Spirit Mound Station 99.8 Subtotal: Basin Electric 1,298,642.6 Dakota Coal/Montana Limestone Company 26,948.7 Dakota Gasification Company 141,703.3 Subtotal: Subsidiaries 168,652.0 Subtotal: Basin Electric & subsidiaries $ 1,467,294.6

Operations & maintenance, depreciation & interest

$

33,938.3 303.9 2,097.8 23,975.0 289.9 15,388.6 24,913.7 7.6 40.5 0.6 100,955.9 2,935.4 50,478.1 53,413.5 $ 154,369.4

The Dry Fork Station, Deer Creek Station, Pioneer Generation Station and Lonesome Creek Station amounts are estimated; final amounts will be available after the capital costs have been assigned to specific property units.

BASIN ELECTRIC POWER COOPERATIVE | 33


Members contribute to, and democratically control, the capital of the cooperative. This benefits members in proportion to the business they conduct with the cooperative rather than on the capital  invested.

B

asin Electric is a not-for-profit organization, which means the cooperative’s operating budget is established to cover the actual costs of running and maintaining its system.

and the National Rural Utilities Cooperative Finance Corporation (CFC), single investor and leveraged leases, internally generated funds and investments from the membership through the Member Investment Program.

The cooperative’s vast system serves 2.85 million member-consumers. And, according to the cooperative’s load forecast, that number is growing. To meet the growing demand, Basin Electric will be investing approximately $1.2 billion in generation and transmission infrastructure over the next 10 years, with 90 percent of that to be expended in the first five years. To secure that amount of capital, Basin Electric actively seeks opportunities from multiple lending institutions such as private and public debt markets and the U.S. Department of Agriculture’s (USDA) Rural Utilities Service (RUS).

Basin Electric continues to be able to readily secure financing because of its well-run and valuable generating resources, strong financial condition, financial flexibility, member support including long-term power sale contracts through the life of the obligations, competitive member power rates and sound management policies.

Current long- and short-term financing resources include private placements, tax-exempt and taxable bonds, bank lines of credit, loans from the Farm Credit System

2013 financing activities In 2013, Basin Electric did not complete any long-term financing. However, on March 18, 2013, Basin Electric extended the maturity date on a $130-million revolving credit facility used to back-stop the cooperative’s tax-exempt commercial paper program. The maturity date on the facility with the National Rural Utilities CFC was extended from Nov. 18, 2013, to March 18, 2018.

Consolidated financial highlights For the years ended Dec. 31 (in millions)

2013

2012

Total utility and nonutility revenue $ 2,066.1 $ 1,954.6 Total expenses 2,020.2 1,834.0 Net margin and earnings $ 45.9 $ 120.6 As of Dec. 31 (in millions)

Net electric plant and nonutility property Total assets Long-term debt Equity

34 | 2013 ANNUAL REPORT

2013

2012

$ 4,764.5 $ 6,089.8 $ 3,371.2 $ 1,273.9

$ 4,612.1 $ 6,061.6 $ 3,632.7 $ 1,101.2

% change

5.7 10.2 (6.6) % change

3.3 0.5 (7.2) 15.7


Basin Electric was created by its members for its members. Through its distribution cooperatives, Basin Electric works to provide reliable, low-cost power for each member at the end of the line; members like Andrew Holle of Northern Lights Dairy in St. Anthony, ND. Northern Lights Dairy is a member of Basin Electric Class A member Mor-Gran-Sou Electric Cooperative. BASIN ELECTRIC POWER COOPERATIVE | 35


Consolidated gross revenue Before intercompany eliminations In millions of dollars - for the year ended Dec. 31, 2013

Basin Electric

$1,379.2 Dakota Coal

$249.3 Other

$36.6

Dakota Gas

$500.2

Basin Electric consolidated capitalization* As of Dec. 31, 2013

Equity and deferred taxes

Federal Financing Bank ( FFB )

25.9%

27.4%

Financial institutions

Public debt

21.9% * Rating agency methodology 36 | 2013 ANNUAL REPORT

Leases

4%

20.8%


On Nov. 6, 2013, the cooperative also extended the maturity date on a $400-million revolving credit facility from Nov. 6, 2017, to Nov. 6, 2018. This facility serves as an additional source of liquidity. Basin Electric’s financial strength and flexibility is rooted in integrity, an important part of the electric cooperative business model. Electric rates – The 2013 average Class A member rate was 54.3 mills per kilowatt-hour. In August, Basin Electric’s board approved the Class A member rate package for 2014 to meet the member revenue requirement of $1.152 billion. The average Class A rate will be 53.8 mills per kilowatt-hour beginning Jan. 1, 2014. Senior secured bond ratings – Fitch Ratings affirmed the cooperative’s senior secured A+ rating, Standard & Poor’s Rating Services affirmed the cooperative’s A rating and Moody’s Investors Service affirmed the cooperative’s A1 rating. All include a stable outlook. Short-term ratings – Basin Electric’s short-term ratings are F1 from Fitch Ratings, A1 from Standard & Poor’s Rating Services

and P-1 from Moody’s Investors Service. Basin Electric uses short-term commercial paper as a source of bridge financing until it can secure long-term financing. Strong business model – An indication of Basin Electric’s financial strength lies in the number of firms that contact the cooperative with lending offers. This is attributable to the strength of the cooperative business model and the effective leadership of the board of directors and management.

Operating results Consolidated results – Basin Electric’s financial statements are consolidated with those of its subsidiaries. For the year ended Dec. 31, 2013, the consolidated net margin and earnings was $45.9 million. This is $74.7 million less than the 2012 consolidated net margin and earnings of $120.6 million. Electric – Basin Electric’s total utility operating revenue for 2013 was $1.3 billion, an increase of $140.9 million from 2012. Revenue from member systems totaled $1.1 billion in 2013, an increase of $159.4 million from 2012. Revenue from non-member sales totaled $218.9 million,

Total electric sales to member systems and others

Consolidated net margin & earnings In millions of dollars - for the years ended

In millions of megawatt hours

120.6

120

98.3

30

20

50

45.9

40

20.8 15.0

22.5 16.5

6.0

6.4

7.2

26.6 20.4

15 10

30 20

5

8.8

10 0

5.8

6.2 20 13

20 13

20 12

20 11

20 10

20 09

0

20 09

60

65.4

25.9 18.7

23.5 17.1

20 12

25

80

20 11

90

20 10

100

70

Members

Others

110

BASIN ELECTRIC POWER COOPERATIVE | 37


Member Investment Program In millions of dollars - at year end 165

158.4

150 135 120

112.3

101.8

105 90

75.7

75

56.8

60 45 30 15

20 13

20 12

20 11

20 09

20 10

0

Average interest rate on utility debt As of Dec. 31 - in percent 5 4

4.30

3.96

4.07 3.50

3.97

3 2 1

20 13

20 12

20 11

20 10

20 09

0

Margin disposition In millions of dollars - for the years ended Bill credits 110 100

Allocated to members

103.1

90 80 70 60

57.4

55.2

50

45.9

40

42.6

30 20 10

20 13

20 12

20 11

20 10

20 09

0

a decrease of $17.8 million from 2012. Total utility operating expenses plus interest and other charges before income taxes for 2013 were $1.3 billion, which is $134.8 million greater than in 2012. Basin Electric’s utility margin before income taxes, combined with Basin Cooperative Services’ net operating results, yielded a combined margin of $57.4 million to be allocated to members.

Award: In October, the National Cooperative Bank ranked Basin Electric as the top electric cooperative in their annual Co-op

Subsidiary earnings – Dakota Gas incurred a net loss of $11.0 million during 2013. Dakota Gas did not declare or pay any dividends to Basin Electric in 2013; however, since 2007, Dakota Gas has paid $198.5 million in dividends to Basin Electric.

100 list, which sites the

Financial position

increase of $172.8 million from 2012. In 2013, the board of directors voted to treat unrealized gains and losses associated with Basin Electric’s hedging activity as regulatory items. This action resulted in the reclassification of $55.2 million of unrealized losses from the equity section to the deferred charges section of the balance sheet, contributing to the increase in the equity position. At the end of 2013, equity represented 27.1 percent of Basin Electric’s total capitalization on its balance sheet. Basin Electric has an equity-to-asset ratio of 20.9 percent.

Assets – The total assets of Basin Electric and its subsidiaries as of Dec. 31, 2013, were $6.1 billion, an increase of more than $28.1 million from a year earlier. Cash position – The consolidated cash balance, including restricted cash, as of Dec. 31, 2013, was $364.9 million. Basin Electric also had $226.0 million deposited in a cushion of credit account at the U.S. Treasury, which is reflected on the balance sheet as a reduction of long-term debt. Member Investment Program – Basin Electric’s Member Investment Program ended the year with $158.4 million. The program offers members an additional investment source and a competitive rate of return while providing Basin Electric with an additional source of capital. Debt – As of Dec. 31, 2013, Basin Electric had approximately $4.1 billion of debt outstanding including Member Investment Program obligations, at a weighted average interest rate of 4.0 percent. Equity position – At year-end 2013, Basin Electric had total equity of $1.3 billion, an 38 | 2013 ANNUAL REPORT

top revenue-generating cooperatives in the country.

Capital credit allocations and retirements – In March 2013, Basin Electric allocated $42.6 million to its patrons. Since 1966 Basin Electric has allocated more than $770.2 million in capital credits to its members. Basin Electric returned no capital credits to its members in 2013, but has retired $219.6 million over the history of the cooperative. Return of cash to members – Since 2000, Basin Electric has returned nearly $600.2 million to the membership through patronage capital retirements, bill credits and power cost adjustments.


Five-year Consolidated Financial Summary

Basin Electric Power Cooperative and Subsidiaries

Five-year Consolidated Financial Summary For the years ended December 31, (dollars in thousands)

2013 2012 2011 2010 2009 Utility operations: Operating revenue: Sales of electricity for resale $ 1,325,737 $ 1,184,132 $ 1,028,832 $ 945,282 $ 843,690 Other electric revenue 12,072 12,812 8,219 8,454 10,260 Total utility operating revenue 1,337,809 1,196,944 1,037,051 953,736 853,950 Operating expenses: Operation 905,289 807,629 779,575 747,406 644,311 Maintenance 124,436 130,081 130,909 103,640 91,160 Depreciation and amortization 131,421 108,328 69,058 56,004 49,285 Taxes other than income 2,908 2,255 2,802 2,248 3,027 Total utility operating expenses 1,164,054 1,048,293 982,344 909,298 787,783 Interest and other charges: Interest on long-term debt 149,669 130,719 58,010 56,893 47,112 Other 8,044 7,933 10,307 7,106 9,129 Total interest and other charges 157,713 138,652 68,317 63,999 56,241 Operating margin (deficit) 16,042 9,999 (13,610) (19,561) 9,926 Nonoperating margin: Interest and other income 34,267 29,646 30,978 23,765 20,591 Patronage allocations from other cooperatives 7,133 2,988 1,816 2,224 988 Total nonoperating margin 41,400 32,634 32,794 25,989 21,579 Utility margin before income taxes 57,442 42,633 19,184 6,428 31,505 Nonutility earnings (loss) before income taxes (16,854) 82,529 77,754 32,192 43,716 Provision for (benefit from) income taxes (5,359) 4,606 (1,349) 29,843 9,777 Net margin and earnings $ 45,947 $ 120,556 $ 98,287 $ 8,777 $ 65,444 Electric sales information: Electric energy sales (in thousands of MWh) Members 20,382 18,715 17,156 16,523 14,973 Others 6,171 7,183 6,361 6,015 5,808 Total 26,553 25,898 23,517 22,538 20,781

› BASIN ELECTRIC POWER COOPERATIVE | 39


Independent Auditors' Report

Deloitte & Touche LLP 50 South Sixth Street Suite 2800 Minneapolis, MN 55402-1538 USA

INDEPENDENT AUDITORS’ REPORT To the Board of Directors and Members of Basin Electric Power Cooperative Bismarck, North Dakota

Tel: +1 612 397 4000 Fax: +1 612 397 4450 www.deloitte.com

We have audited the accompanying consolidated financial statements of Basin Electric Power Cooperative (a North Dakota cooperative corporation) and its subsidiaries (the "Cooperative"), which comprise the consolidated balance sheets as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows, for the years then ended, and the related notes to the consolidated financial statements. Management's Responsibility for the Consolidated Financial Statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. Auditors' Responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Cooperative's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Cooperative's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Cooperative and its subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

March 12, 2014

Member of Deloitte Touche Tohmatsu

40 | 2013 ANNUAL REPORT


Consolidated Financial Statements Basin Electric Power Cooperative and Subsidiaries

Consolidated Balance Sheets as of December 31, (dollars in thousands)

ASSETS 2013 2012

Electric plant: In service $ 5,348,845 $ 4,748,011 Property held under capital leases 48,831 40,586 Construction work in progress 132,227 499,153 Total electric plant 5,529,903 5,287,750 Less: accumulated provision for depreciation and amortization (1,785,934) (1,666,811) 3,743,969 3,620,939 Nonutility property: Property, plant and equipment 1,640,981 1,462,918 Construction work in progress 16,749 97,715 Total nonutility property 1,657,730 1,560,633 Less: accumulated provision for depreciation and depletion (637,215) (569,452) 1,020,515 991,181 Other property, investments and deferred charges: Mine related assets (Note 5) 129,782 121,322 Investments in associated companies 35,683 31,495 Other investments 65,354 73,709 Special funds 53,190 62,704 Deferred charges (Note 6) 191,760 146,155 475,769 435,385 Current assets: Cash and cash equivalents 123,410 128,914 Restricted cash and investments (Note 2) 30,000 10,125 Short-term investments 211,505 347,723 Customer accounts receivable 137,057 100,530

Other receivables, net of allowance for uncollectibles

88,465

83,118

Coal stock, materials and supplies (Note 2) 185,056 172,235 Prepayments and other current assets 74,015 171,469 849,508 1,014,114 $ 6,089,761 $ 6,061,619

EQUITY AND LIABILITIES 2013 2012

Capitalization: Equity: Memberships $ 21 $ 21 Patronage capital 546,711 514,851 Retained earnings of subsidiaries 406,947 417,246 Other equity (Note 7) 302,058 277,672 Accumulated other comprehensive income (loss) 15,692 (110,204) 1,271,429 1,099,586 Noncontrolling interest 2,506 1,588 1,273,935 1,101,174 Long-term debt, net of current portion (Note 8) 3,371,200 3,632,724 Capital lease obligations, net of current portion (Note 3) 58,041 47,250 4,703,176 4,781,148 Deferred credits, taxes and other liabilities (Note 11) 537,646 612,127 Commitments and contingencies (Notes 3 and 12) Current liabilities: Current portion of long-term debt (Note 8) 130,016 39,983 Current portion of capital lease obligations (Note 3) 3,113 2,256 Accounts payable 155,872 139,776 Notes payable – affiliates 157,183 111,416 Notes payable (Note 12) 309,879 279,894 Taxes and other current liabilities 92,876 95,019 848,939 668,344 $ 6,089,761 $ 6,061,619 The accompanying notes are an integral part of these consolidated financial statements.

BASIN ELECTRIC POWER COOPERATIVE | 41

›


Consolidated Financial Statements Basin Electric Power Cooperative and Subsidiaries

Consolidated Statements of Operations for the years ended December 31, (dollars in thousands)

2013

2012

Utility operations: Operating revenue: Sales of electricity for resale: Members $ 1,106,804 $ 947,391 Others 218,933 236,741 1,325,737 1,184,132 Other electric revenue 12,072 12,812 1,337,809 1,196,944 Operating expenses: Operation 905,289 807,629 Maintenance 124,436 130,081 Depreciation and amortization 131,421 108,328 Taxes other than income 2,908 2,255 1,164,054 1,048,293 Interest and other charges: Interest on long-term debt 149,669 130,719 Other 8,044 7,933 157,713 138,652 Operating margin 16,042 9,999 Nonoperating margin: Interest and other income 34,267 29,646 Patronage allocations from other cooperatives 7,133 2,988 41,400 32,634 Utility margin before income taxes 57,442 42,633 Nonutility operations: Operating revenue: Synthetic gas 203,945 252,347 Byproducts, coproduct and other 349,692 354,720 Lignite coal 130,047 115,334 683,684 722,401 Operating expenses (includes $17,671 and $16,511 of net income attributed to noncontrolling interest) 703,818 642,458 Operating income (loss)

(20,134)

79,943

Interest and other income

3,280

2,586

Nonutility earnings (loss) before income taxes

(16,854)

82,529

Margin and earnings before income taxes

40,588

125,162

Provision for (benefit from) income taxes

(5,359)

4,606

Net margin and earnings

$ 45,947 $ 120,556

The accompanying notes are an integral part of these consolidated financial statements.

42 | 2013 ANNUAL REPORT


Consolidated Financial Statements Basin Electric Power Cooperative and Subsidiaries

Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, (dollars in thousands) 2013 2012 Net margin and earnings $ 45,947 $ 120,556 Other comprehensive income (loss): Adjustment to post employment liability of $36,189, (net of tax of $(889)) and $(2,597), (net of tax of $(987)) 36,189 (2,597) Unrealized gain on securities of $5,758, (net of tax of $2,405) and $2,360, (net of tax of $1,152) 5,758 2,360 Unrealized gain (loss) on cash flow hedges of $17,731, (net of tax of $2,329) and unrealized loss of $(1,877), (net of tax of $2,940) and reclassification adjustment of $(702), (net of tax of $7,377) and $(1,062), (net of tax of $(6,405)) reclassified into earnings 17,029 (2,939) Change in accounting treatment on cash flow hedges for Basin Electric 66,920 Total other comprehensive income (loss) 125,896 (3,176) Comprehensive income $ 171,843 $ 117,380

Consolidated Statements of Changes in Equity for the years ended December 31, 2013 and 2012 (dollars in thousands) Retained Patronage Earnings of Other Memberships Capital Subsidiaries Equity

Accumulated Other Comprehensive Income (Loss) Noncontrolling (Note 7) Interest Total

Balance, December 31, 2011

$ (107,028) $ 3,589 $ 985,795

$

21 $ 474,307 $ 363,880 $ 251,026

Comprehensive income (loss) - 67,190 53,366 - (3,176) - 117,380 Transfers to other equity - (26,646) - 26,646 - - Noncontrolling interest in net margin and earnings - - - - - 16,511 16,511 Dividends paid by noncontrolling interest - - - - - (18,512) (18,512) Balance, December 31, 2012

21 514,851 417,246 277,672 (110,204) 1,588 1,101,174

Comprehensive income (loss) - 56,246 (10,299) - 125,896 - 171,843 Transfers to other equity - (24,386) - 24,386 - - Noncontrolling interest in net margin and earnings - - - - - 17,671 17,671 Dividends paid by noncontrolling interest - - - - - (16,753) (16,753) Balance, December 31, 2013 $ 21 $ 546,711 $ 406,947 $ 302,058 $ 15,692 $ 2,506 $ 1,273,935 The accompanying notes are an integral part of these consolidated financial statements.

› BASIN ELECTRIC POWER COOPERATIVE | 43


Consolidated Financial Statements Basin Electric Power Cooperative and Subsidiaries

Consolidated Statements of Cash Flows for the years ended December 31, (dollars in thousands)

2013

Operating activities: Net margin and earnings $ 45,947 $ Adjustments to reconcile net margin and earnings to net cash from operating activities: Depreciation and amortization of property, plant and equipment 205,256 Increase (decrease) in reserves (22,634) Other amortization 58,875 Patronage capital and other (8,397) Deferred income taxes (2,257) Other, including regulatory revenue deferral 19,207 Income attributable to noncontrolling interest 17,671 Changes in other operating elements: Customer accounts receivable (36,527) Other receivables (6,668) Coal stock, materials and supplies (15,395) Prepayments and other current assets 24,185 Accounts payable 22,079 Taxes and other current liabilities 5,222 Net cash provided by operating activities 306,564 Investing activities: Acquisition of electric plant (246,091) Acquisition of nonutility property (101,105) Purchase of investments (473,221) Sale of investments 594,514 Purchase of other assets (26,345) Net cash used in investing activities (252,248)

2012

120,556 184,966 17,575 16,035 (4,295) 1,706 16,511 (22,912) 77,697 (1,441) (49,999) 20,307 (22,527) 354,179 (215,576) (96,001) (405,513) 154,763 (29,493) (591,820)

Financing activities: Loan advances 38,644 592,433 Principal payments of long-term debt (142,077) (141,062) Purchase of funds held by U.S. Treasury (10,956) (45,175) Sale of funds held by U.S. Treasury - 137,607 Payment of debt issue costs (849) (1,808) Proceeds of notes payable - affiliates 991,846 908,585 Payments of notes payable - affiliates (946,079) (872,916) Proceeds of notes payable 1,139,790 3,074,591 Payments of notes payable (1,109,805) (3,464,558) Payments under capital lease obligations (3,581) (2,352) Dividends paid to noncontrolling interest (16,753) (18,512) Net cash provided by (used in) financing activities (59,820) 166,833 Net decrease in cash and cash equivalents (5,504) (70,808) Cash and cash equivalents, beginning of year 128,914 199,722 Cash and cash equivalents, end of year $ 123,410 $ 128,914 Supplemental disclosure of cash flow information: Cash paid for interest, net of amounts capitalized $ 164,710 $ 162,717 Cash paid (refunded) for income taxes $ (1,226) $ 1,573 Non-cash investing and financing activity: Acquisition of electric plant and nonutility property through short-term financing $ 22,462 $ Acquisition of electric plant and nonutility property through capital lease $ 15,200 $ The accompanying notes are an integral part of these consolidated financial statements.

44 | 2013 ANNUAL REPORT

28,241 -


Consolidated Financial Statements Basin Electric Power Cooperative and Subsidiaries

Notes to Consolidated Financial Statements (dollars in thousands)

1. Organization Basin Electric Power Cooperative (Basin Electric) is an electric generation and transmission cooperative corporation, organized and existing under the laws of the State of North Dakota. It serves member electric service needs in a nine-state region of North Dakota, South Dakota, Montana, Wyoming, New Mexico, Colorado, Nebraska, Minnesota and Iowa. Basin Electric’s power supply resources are composed of its own generating facilities and contractual power purchase arrangements. It delivers power and energy over its own transmission facilities and through contractual arrangements with other power supply entities in the region, primarily the Western Area Power Administration. Basin Electric’s accounting records are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission as adopted and interpreted by the Rural Utilities Service (RUS). The rates charged to its members for electric service are established by Basin Electric’s Board of Directors and require concurrence from the RUS. Basin Electric has five wholly owned for-profit subsidiaries, Dakota Gasification Company (Dakota Gas), Dakota Coal Company (Dakota Coal), Basin Telecommunications, Inc. (BTI), PrairieWinds ND 1, Inc. (PrairieWinds ND), and PrairieWinds SD 1, Inc. (PrairieWinds SD) and one wholly owned not-for-profit subsidiary, Basin Cooperative Services (BCS). Dakota Gas has a wholly owned for-profit subsidiary, Souris Valley Pipeline Limited (SVPL). Dakota Coal has a wholly owned for-profit subsidiary, Montana Limestone Company (MLC). Dakota Gas owns and operates the Great Plains Synfuels Plant (Synfuels Plant) which converts lignite coal into pipeline-quality synthetic gas and anhydrous ammonia as a coproduct, as well as a number of byproducts including carbon dioxide (CO2), and is located adjacent to Basin Electric’s Antelope Valley Station (AVS) electric generating plant. These plants share certain facilities, and coal and water supplies. Basin Electric also supplies the Synfuels Plant with electric capacity and energy, and Dakota Gas supplies Basin Electric’s Groton and Culbertson peaking stations with synthetic gas. SVPL owns and operates a CO2 pipeline in Saskatchewan, Canada. Dakota Coal purchases lignite coal from the Freedom Mine, a coal mine in North Dakota that is owned and operated by The Coteau Properties Company (Coteau), a wholly owned subsidiary of The North American Coal Corporation (NACoal). Coteau is a variable interest entity of Dakota Coal. Pursuant to the coal purchase agreement, Dakota Coal is obligated to provide financing for and has certain rights with respect to the operation of the coal mine. The lignite coal is used in Basin Electric’s Leland Olds Station (LOS), AVS, and Dakota Gas’ Synfuels Plant. Dakota Coal coordinates procurement and rail delivery of Powder River Basin coal to the Laramie River Station (LRS), the Dry Fork Station (DFS) and LOS. Dakota Coal also owns a lime plant that sells lime to AVS, the Missouri Basin Power Project (MBPP) and others. MLC operates a limestone quarry and owns and operates a fine grind plant, both in Montana, and sells limestone to Dakota Coal’s lime plant, LOS and others. BTI provides internet access and hosting services. PrairieWinds ND owns wind projects near Minot, North Dakota. PrairieWinds SD owns a wind project near White Lake, South Dakota. BCS provides certain nonutility property management services to Basin Electric. Basin Electric is a 42.27 percent owner of the MBPP and acts as the operating agent for the 1,710 megawatt LRS generating plant in Wyoming, associated transmission facilities and the Grayrocks Dam and Reservoir. Basin Electric is a 92.9 percent owner of the DFS generating plant in Wyoming and acts as the operating agent for the 386 megawatt plant.

2. Significant Accounting Policies PRINCIPLES OF CONSOLIDATION–The consolidated financial statements include the accounts of Basin Electric, its wholly owned subsidiaries and its variable interest entity, Coteau. All intercompany investments, debt, and receivable and payable accounts have been eliminated in consolidation. Charges from BCS, BTI, Dakota Gas, Dakota Coal, MLC, Coteau, PrairieWinds ND and PrairieWinds SD to Basin Electric and charges from Basin Electric to BCS, BTI, Dakota Gas, Dakota Coal, MLC, Coteau, PrairieWinds ND and PrairieWinds SD are not eliminated as Basin Electric includes the results of these activities in the determination of rates charged to its members. USE OF ESTIMATES–The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting period. Estimates are used for items such as plant depreciable lives, actuarially determined benefit costs, valuation of derivatives, asset retirement obligations, and provision for (benefit from) income taxes. Ultimate results could differ from those estimates. CASH AND CASH EQUIVALENTS–Basin Electric considers all investments purchased with an original maturity of three months or less to be cash equivalents. The fair value of cash equivalents approximates their carrying values due to their short-term maturity.

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Consolidated Financial Statements

RESTRICTED CASH AND INVESTMENTS–Cash and investments, and funds held in escrow, by trustee, by the U.S. Treasury and by a financial institution at December 31 were restricted for the following purposes: 2013 2012 Cash and investments: MBPP operating funds $ 20,000 $ 10,125 Revenue deferral 10,000 $ 30,000 $ 10,125 Funds held by the U.S. Treasury: RUS/Federal Financing Bank (FFB) debt service payments $ 226,003 $ 215,047 Funds held by U.S. Bank, trustee: Campbell County, Wyoming solid waste facilities revenue bonds - 3,654 $ 226,003 $ 218,701 INVESTMENTS–Basin Electric classifies its investments as either available-for-sale or held-to-maturity. The cost of securities sold is based on the specific identification method. Available-for-sale securities are included in Short-term investments, Mine related assets, Other investments and trustee-held funds included in Long-term debt. The cost, unrealized holding gains and losses, and fair value of available-for-sale securities were as follows: December 31, 2013 Gross Unrealized Holding Cost Gains Losses

Fair Value

Cost

December 31, 2012 Gross Unrealized Holding Gains Losses

Fair Value

U.S. Government obligations $ 181,588 $ 50 $ 217 $ 181,421 $ 347,517 $ 107 $ 1 $ 347,624 Equity securities 45,003 14,673 - 59,676 43,778 6,235 - 50,013 Corporate commercial paper 29,985 - - 29,985 - - - $ 256,576 $ 14,723 $ 217 $ 271,082 $ 391,295 $ 6,342 $ 1 $ 397,637 During 2013 and 2012, sales proceeds on securities classified as available-for-sale were $601,308 and $141,577. The fair value of available-for-sale debt securities at December 31, 2013, which all have contracted maturity dates of one year or less is $211,406. Held-to-maturity securities are included in Cash equivalents, Short-term investments, Other investments and trustee-held funds included in Long-term debt. The cost, unrealized holding gains and losses, and fair value of held-to-maturity securities were as follows:

Cost

December 31, 2013 Gross Unrealized Holding Gains Losses

Fair Value

Cost

December 31, 2012 Gross Unrealized Holding Gains Losses

U.S. Government obligations $ - $ - $ - $ - $ 44,991 $ Corporate bonds 69,993 - - 69,993 31,996 $ 69,993 $ - $ - $ 69,993 $ 76,987 $

- $ - - $

Fair Value

- $ 44,991 - 31,996 - $ 76,987

The fair value of held-to-maturity debt securities at December 31, 2013, which all have contracted maturity dates of one year or less is $69,993. Investment securities, in general, are exposed to various risks, such as interest rate, credit and overall volatility. Due to such risks, it is reasonably possible that changes in the values of investment securities will occur in the near term and that such changes could materially affect amounts reported in the financial statements. Management regularly monitors the difference between the cost and fair market values of its investments. If any of Basin Electric’s investments experience a decline in value that is believed to be other than temporary, a loss is recognized in Interest and other income in the Consolidated Statements of Operations. Included in Other investments is the cash surrender value of life insurance policies of $10,128 and $10,860, as of December 31, 2013 and 2012.

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Consolidated Financial Statements

COAL STOCK, MATERIALS AND SUPPLIES–Byproducts, coproducts, and limestone inventories are stated at the lower of average cost or market prices, and fuel stock, and materials and supplies inventories are stated at average cost, which approximates market. Inventories were as follows at December 31: 2013 2012 Materials and supplies $ 137,075 $ 119,763 Coal and fuel oil 19,998 41,607 Byproducts, coproducts and limestone inventory 7,226 4,092 Ammonia 16,814 3,757 Ammonium sulfate 2,541 741 Process inventory 1,402 2,275 $ 185,056 $ 172,235 PATRONAGE CAPITAL AND RETAINED EARNINGS OF SUBSIDIARIES–At the discretion of Basin Electric’s Board of Directors, utility margins are allocated to members on a patronage basis or may be offset in whole or in part against current or prior losses. Certain other margins may also be set aside as other equity for improvements, new construction, depreciation and contingencies as determined by the Board of Directors under the Basin Electric Indenture. Basin Electric may not retire patronage capital if, after the distribution, an event of default would exist or Basin Electric’s equity would be less than 20 percent of total long-term debt and equity. Cumulative patronage capital retired at December 31, 2013 was $219,626. REVENUE RECOGNITION–Revenue from electric energy is recognized when delivered. Synthetic gas revenue is recognized upon delivery or when tendered in accordance with contract requirements. Byproduct and coproduct revenue are generally recognized upon delivery. Coal, lime, limestone, internet access and hosting service revenue are recognized upon delivery. ELECTRIC PLANT AND NONUTILITY PROPERTY–Electric plant and nonutility property are stated at cost, including contract work, direct labor and materials, allocable overheads and allowance for funds used during construction. Interest charged and capitalized to construction during 2013 and 2012 totaled $12,465 and $24,223. Repairs and maintenance are charged to operations as incurred. When electric plant is retired, sold, or otherwise disposed of, the original cost plus the cost of removal less salvage value is charged to accumulated depreciation and the corresponding gain or loss is amortized over the remaining life of the plant. When nonutility property is retired or sold, the cost and the related accumulated depreciation are eliminated and any gain or loss is reflected in nonutility operations. DEPRECIATION AND AMORTIZATION–Electric plant is depreciated using the straight-line method based on the estimated useful lives of the various classes of property. The annual depreciation provision as a percent of average depreciable electric plant in service was approximately 2.34 and 2.13 percent in 2013 and 2012. Annual electric plant depreciation expense totaled $130,664 and $107,821 for 2013 and 2012. Nonutility property is depreciated using the straight-line method based on the estimated useful lives of the individual assets, with plant and pipeline depreciated over 20 years and equipment depreciated over useful lives ranging from 3 to 15 years or the units-of-production method based on estimated recoverable tonnage. Annual nonutility depreciation expense totaled $74,592 and $77,145 for 2013 and 2012. Accelerated and straight-line depreciation methods are used for income tax reporting purposes. RECOVERABILITY OF LONG-LIVED ASSETS–Basin Electric accounts for the impairment or disposal of long-lived assets in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 360, Property, Plant, and Equipment, which requires long-lived assets, such as property and equipment, to be evaluated for impairment whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. An impairment loss is recognized when estimated undiscounted cash flows expected to result from the use of the asset plus net proceeds expected from disposition of the asset (if any) are less than the carrying value of the asset. When an impairment loss is recognized, the carrying amount of the asset is reduced to its estimated fair value based on quoted market prices or other valuation techniques. To date, management has determined that no impairment of these assets exists. REGULATORY ASSETS AND LIABILITIES–Basin Electric is subject to the provisions of ASC 980, Regulated Operations. Regulatory assets represent probable future revenue to Basin Electric associated with certain costs which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenue associated with amounts that are to be credited to customers through the ratemaking process (Notes 6 and 11). Basin Electric has entered into various swaps and option arrangements to limit its exposure to

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Consolidated Financial Statements

fluctuation in interest rates and natural gas prices. Under ASC 980, changes in fair value of all hedge arrangements, to the extent they are recoverable through future rates, are deferred and recorded in regulatory accounts. Regulatory assets and liabilities were as follows at December 31: 2013 2012 Regulatory assets included in: Deferred charges $ 173,741 $ 123,369 Mine related assets 27,226 27,743 200,967 151,112 Regulatory liabilities included in: Deferred credits, taxes and other liabilities (19,380) (4,988) Net regulatory assets $ 181,587 $ 146,124 As of December 31, 2013, Basin Electric’s regulatory assets are reflected in rates charged to customers over periods ranging from 3 to 30 years. If all or a separable portion of Basin Electric’s operations no longer are subject to the provisions of ASC 980, a write-off of related regulatory assets would be required, unless some form of transition recovery (refund) continues through rates established and collected for Basin Electric’s remaining regulated operations. In addition, Basin Electric would be required to determine any impairment to the carrying costs of deregulated plant and inventory assets. DERIVATIVE FINANCIAL INSTRUMENTS–The Risk Management Steering Committee (RMSC) Policy contains a framework that defines risk parameters, delineates management responsibility and establishes organizational relationships. The RMSC Policy requires reporting these risk management activities to the Dakota Gas Board of Directors. Dakota Gas entered into derivative financial instruments for the purpose of hedging the risk of market fluctuation in natural gas prices. These financial instruments effectively fix the price of synthetic natural gas between $3.55 and $7.00 per dekatherm for a portion of the forecasted sales (10% to 76% on a monthly basis) through December 2016. These financial instruments attempt to provide for sales prices in excess of Dakota Gas’ average before tax cost of production and are held only to hedge the risk of natural gas price movements. Any changes in cash flows from the hedged sales are offset by corresponding changes in the cash flows from the derivatives. Dakota Gas and its counterparties have various obligations to post collateral with each other to partially backstop their synthetic gas hedging activity based upon fluctuations in the price of natural gas. Certain financial instruments valued at $16,619 and $41,592, at December 31, 2013 and 2012, meet the criteria for hedge accounting under ASC 815, Derivatives and Hedging, and as a result, unrealized gains or losses on the instruments were recognized in equity in Accumulated other comprehensive income and will subsequently be reclassified to synthetic gas revenue in the Consolidated Statement of Operations when the hedged sales are recorded. Dakota Gas evaluates and quantifies any hedge ineffectiveness on a quarterly basis, and Dakota Gas’ natural gas cash flow hedges had no ineffectiveness in 2013 or 2012. In the December 31, 2013 Consolidated Balance Sheets, the fair value of the current portion of these financial instruments was included in Prepaid pension and other and the noncurrent portion was included in Patronage from affiliates, prepaid pension, and other. Financial instruments valued at $1,381 and $0, at December 31, 2013 and 2012, did not meet the criteria for hedge accounting under ASC 815, and as a result, changes in market value of these instruments were recognized on the Consolidated Statement of Operations as synthetic gas revenue. In 2013, Dakota Gas also entered into derivative financial instruments for the purpose of hedging the risk of market fluctuation in tar oil prices. These financial instruments effectively fix the price of tar oil between $91.65 and $94.10 per barrel for 100% of tar oil sales until June 2014. These financial instruments will attempt to provide for sales prices in excess of Dakota Gas’ average before tax cost of production and will be held only to hedge the risk of tar oil price movements, not for speculation. Any changes in cash flows from the hedged sales will be offset by corresponding changes in the cash flows from the derivatives. None of the financial instruments, valued at $267 and $0, at December 31, 2013 and 2012, meet the criteria for hedge accounting under ASC 815, and as a result, all changes in market value of the instruments are recognized in Byproducts, coproduct and other revenue on the Consolidated Statement of Operations. Basin Electric entered into various interest-rate swap agreements to reduce the impact of changes in interest rates on certain of its variable rate long-term bonds. There were four interest rate swaps outstanding at December 31, 2013 that effectively change the interest rate on $100,000 of Basin Electric’s variable rate bonds due in 2032 to a fixed rate of 6.18 percent, the interest rate on $50,000 of Basin Electric’s variable rate bonds due in 2032 to a fixed rate of 4.95 percent, and the interest rate on $50,000 of Basin Electric’s variable rate bonds due in 2030 to a fixed rate of 5.33 percent. In October of 2013, Basin Electric’s Board of Directors took action to defer accumulated and future changes in the fair value of these swaps as a regulatory item to be recovered through rates in the future. Only current settlements of these interest rate swaps are included in earnings, which resulted in charges to interest expense for the years ended December 31, 2013 and 2012 of $10,936 and $10,833. The change in fair value for the year ended December 31, 2013 resulted in a deferred gain of $43,991. At December 31, 2013 and 2012, the fair 48 | 2013 ANNUAL REPORT


Consolidated Financial Statements

value of the obligation related to the interest rate swap agreements of $56,190 and $100,181 were included in Deferred credits, taxes and other liabilities on the Consolidated Balance Sheets. A regulatory deferred asset, which represents the amount to be recovered through future rates, is included in Deferred charges on the Consolidated Balance Sheets (Note 6). Beginning in November 2013, Basin Electric entered into a series of floating-to-fixed swap agreements for natural gas to manage the variable price risk associated with the forecasted natural gas exposure through 2016. In October 2013, Basin Electric’s Board of Directors established a policy to defer changes in fair value as a regulatory item to be recovered in future rates. At December 31, 2013, the fair value of the asset related to certain natural gas agreements was included in Prepayments and other current assets ($8,819) and in other current assets ($9,229) on the Consolidated Balance Sheets. At December 31, 2013, the fair value of the liability related to other natural gas agreements of $2,809 was included in Taxes and other current liabilities on the Consolidated Balance Sheets. A regulatory deferred liability, which represents the amount to be returned through future rates, is included in Deferred credits, taxes and other liabilities on the Consolidated Balance Sheets (Note11). Basin Electric and Dakota Gas are exposed to credit risk loss in the event of nonperformance by the counterparties to their derivative financial instruments. However, Basin Electric and Dakota Gas do not anticipate nonperformance by the counterparties as all counterparties’ credit ratings are in compliance with Basin Electric’s and Dakota Gas’ risk policy requirements. Basin Electric and Dakota Gas also enter into contracts for the purchase and sale of various commodities for use in its business operations. ASC 815 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from ASC 815 as normal purchases or normal sales. Basin Electric and Dakota Gas evaluate all of their contracts when such contracts are entered into to determine if they are derivatives and, if so, whether they qualify to meet the normal exception requirements under ASC 815. In July 2010, the President of the United States signed into law comprehensive financial reform legislation under the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank). This financial reform legislation includes a provision that requires over-the-counter derivative transactions to be executed through an exchange or centrally cleared. Such clearing requirements would result in a significant change from Basin Electric’s and Dakota Gas’ current practice of bilateral transactions and negotiated credit terms. In July 2012, the Commodity Futures Trading Commission (CFTC) issued a final rule providing for an exemption to such clearing requirements as outlined in the legislation for end users that enter into hedges to mitigate commercial risk. Basin Electric and Dakota Gas expect to qualify under the end user exemption. At the same time, the legislation includes provisions under which the CFTC may impose collateral requirements for transactions, including those that are used to hedge commercial risk. In addition, although the CFTC's proposed rules would not impose specific margin requirements on end users, the CFTC's proposed regulations would require swap dealers and major swap participants to have credit support arrangements with their end user counterparties. Also, to the extent that Basin Electric and Dakota Gas counterparties are banking entities, proposed rules issued by banking regulators would require the banking entities to calculate credit exposure limits for end user counterparties and collect margin when the credit exposure exceeds the limit. At this time, management does not anticipate any material impact to our risk management strategy. ASSETS AND LIABILITIES MEASURED AT FAIR VALUE–ASC 820, Fair Value Measurements, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The standard applies to reported balances that are required or permitted to be measured at fair value. ASC 820 emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Therefore, a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. As a basis for considering market participant assumptions in fair value measurements, ASC 820 establishes a fair value hierarchy that distinguishes between market participant assumptions based on market data obtained from sources independent of the reporting entity (observable inputs that are classified within Levels 1 and 2 of the hierarchy) and the reporting entity’s own assumptions about market participant assumptions (unobservable inputs classified within Level 3 of the hierarchy). Level 1 inputs utilize observable market data in active markets for identical assets or liabilities. Level 2 inputs consist of observable market data, other than that included in Level 1, that is either directly or indirectly observable. Level 3 inputs consist of unobservable market data which are typically based on an entity’s own assumptions of what a market participant would use in pricing an asset or liability as there is little, if any, related market activity. In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. Basin Electric’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset or liability.

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Consolidated Financial Statements

On December 31, 2013 and 2012, Basin Electric had money market accounts, commercial paper, U.S. government obligations, and equity securities included in Short-term investments, Mine related assets, Other investments and trustee-held funds included in Long-term debt, recorded at a fair value, using quoted prices in active markets for identical assets as the fair value measurement (Level 1). On December 31, 2013 and 2012, Basin Electric recorded derivative financial instruments including commodity contracts and interest rate swaps using significant other observable inputs as the fair value measurement (Level 2). The fair value for commodity contracts is determined by comparing the difference between the net present value of the cash flows for the commodity contracts at their initial price and the current market price. The initial price is quoted in the commodity contract and the current market price is corroborated by observable market data. The fair value for interest rate swap contracts is determined by comparing the difference between the net present value of the cash flows for the swaps at their initial fixed rate and the current market fixed rate. The initial fixed rate is quoted in the swap agreement and the current market fixed rate is corroborated by observable market data. Basin Electric continuously monitors the creditworthiness of the counterparties to its derivative contracts and assesses the counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of Basin Electric’s own credit risk when determining the fair value of derivative assets and liabilities, the impact of considering credit risk was immaterial to the fair value of derivative assets and liabilities presented in the Consolidated Balance Sheets. The following table summarizes assets and liabilities measured at fair value on a recurring basis as of December 31, 2013, aggregated by the level in the fair value hierarchy within which those measurements fall:

Fair Value Measurements Using

Quoted Prices in Active Markets for Identical Assets and Fair Liabilities Value (Level 1)

Significant Other Observable Inputs (Level 2)

Significant Unobservable Inputs (Level 3)

Assets: Investments: US Government Treasury Bills and Notes $ 181,421 $ 181,421 $ Corporate Commercial Paper 99,978 99,978 Institutional Index Fund 30,239 30,239 500 Index Fund 11,120 11,120 Total Bond Market Index Fund 13,371 13,371 Intermediate-Term Treasury Fund 4,946 4,946 341,075 341,075 Derivative financial instruments 18,810 - Less amounts classified as current assets (288,580) (281,399) $ 71,305 $ 59,676 $

- - - - - - - 18,810 (7,182) 11,628

$ $

-

Liabilities: Interest rate swaps $ Derivative financial instruments Less amounts classified as current liabilities $

(56,190) $ (2,851) 2,851 (56,190) $

-

50 | 2013 ANNUAL REPORT

(56,190) $ (2,851) 2,851 (56,190) $

- $ - - - $


Consolidated Financial Statements The following table summarizes assets and liabilities measured at fair value on a recurring basis as of December 31, 2012, aggregated by the level in the fair value hierarchy within which those measurements fall:

Fair Value Measurements Using

Quoted Prices in Active Markets for Identical Assets and Fair Liabilities Value (Level 1)

Significant Other Observable Inputs (Level 2)

Assets: Investments: US Government Treasury Bills and Notes $ 392,615 $ 392,615 $ Corporate Commercial Paper 31,996 31,996 Institutional Index Fund 22,848 22,848 500 Index Fund 8,403 8,403 Total Bond Market Index Fund 13,663 13,663 Intermediate-Term Treasury Fund 5,099 5,099 474,624 474,624 Derivative financial instruments 41,592 - Less amounts classified as current assets (448,349) (424,611) $ 67,867 $ 50,013 $ Liabilities: Interest rate swaps

$ (100,181)

$

-

Significant Unobservable Inputs (Level 3)

- - - - - - - 41,592 (23,738) 17,854

$ $

-

$ (100,181)

$

-

Basin Electric evaluates the significance of transfers between levels based on the nature of the financial instrument and size of the transfer relative to total assets. For the years ended December 31, 2013 and 2012, there were no transfers between levels. SUBSEQUENT EVENTS–Basin Electric considered events for recognition or disclosure in the consolidated financial statements that occurred subsequent to December 31, 2013 through March 12, 2014, the date the consolidated financial statements were available for issuance. Management is not aware of any material subsequent events that would require recognition or disclosure in the 2013 consolidated financial statements. RECENTLY ISSUED ACCOUNTING STANDARD UPDATES–In February 2013, the FASB issued an update to ASC 220, Comprehensive Income, to improve the reporting of reclassifications out of accumulated other comprehensive income by requiring an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In general, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income. The amendments are effective prospectively for reporting periods beginning after December 15, 2013. Early adoption is permitted. Management does not expect adoption of the required amendments to have a significant impact on Basin Electric’s financial position or results of operations. In July 2013, the FASB issued an update to ASC 740, Income Taxes, to provide guidance for consistent financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. For nonpublic entities, the amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2014. Early adoption is permitted. Management does not expect adoption of the required amendments to have a significant impact on Basin Electric’s financial position or results of operations.

3. Leases CAPITAL LEASES–Basin Electric, Dakota Gas, and Dakota Coal are the lessees of certain substation, mining equipment, and railcars under capital leases expiring from 2014 to 2050. The assets and liabilities under capital leases are recorded at the lesser of the present value of the minimum lease payments or the fair value of the asset. Property under capital leases as of December 31, 2013 included various substation and mining equipment with an original cost of $69,341. The assets are amortized over the lesser of their related lease terms or their estimated productive lives. Certain of the mining equipment under capital leases are subleased to Coteau, recorded as direct financing leases and eliminated in consolidation.

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Consolidated Financial Statements

Minimum future lease payments under capital leases as of December 31, 2013 for each of the next five years and in the aggregate are: Year Amount 2014 $ 5,567 2015 5,398 2016 5,797 2017 4,314 2018 3,536 Thereafter 78,149 Total minimum lease payments 102,761 Less: Amount representing interest 41,607 Present value of net minimum lease payments $ 61,154 Interest rates on capitalized leases vary from 2.29 percent to 5.14 percent and are imputed based on the lessor’s implicit rate of return. LEASING ARRANGEMENTS AS LESSEE–Basin Electric leases certain electric plant facilities, mining and related equipment and other operational assets under noncancelable operating leases with initial terms up to 30 years. Minimum future lease payments under noncancelable operating leases for each of the next five years and in aggregate are:

Year Amount 2014 $ 49,359 2015 49,216 2016 23,939 2017 22,519 2018 21,716 Thereafter 107,947 Total $ 274,696

Rental payments charged to expense were $66,646 and $60,709 in 2013 and 2012.

4. Jointly Owned Facilities Basin Electric’s investment in the MBPP electric plant was as follows at December 31: 2013 2012 Electric plant $ 736,884 $ 719,171 Less accumulated provision for depreciation and amortization (478,089) (472,487) $ 258,795 $ 246,684 Basin Electric’s share of MBPP operating expenses was $117,505 and $121,122 for 2013 and 2012, and is reflected in utility operating expenses. Each of the members in MBPP are responsible for arranging their own financing for their ownership interest in MBPP.

5. Mine Related Assets Assets associated with the properties that supply coal for AVS, LOS and Dakota Gas’ Synfuels Plant are classified as Mine related assets and were as follows at December 31: 2013 2012 Prepaid coal royalties $ 38,430 $ 39,971 Mine closing fund investments 59,677 50,013 Interest on coal royalties 20,253 20,720 Notes receivable and mine financing costs 4,449 3,595 Other 6,973 7,023 $ 129,782 $ 121,322 Coteau notes receivable with NACoal of $4,347 and $3,477 at December 31, 2013 and 2012 included above bear interest rates varying from .21 percent to .32 percent. 52 | 2013 ANNUAL REPORT


Consolidated Financial Statements 6. Deferred Charges Deferred charges are recovered through amortization into service rates charged by Basin Electric to customers over periods ranging from 3 to 30 years or as tax timing differences reverse and were as follows at December 31: 2013 2012 Regulatory asset related to deferred income taxes $ 63,539 $ 66,296 Debt issuance and refinancing fees 46,045 50,555 Regulatory deferred pension expense 9,440 10,788 Unrealized loss on interest rate swaps 55,225 Other 17,511 18,516 $ 191,760 $ 146,155 Interest on coal royalties and other costs deferred under ASC 980, totaling $27,226 and $27,743 at December 31, 2013 and 2012, are included in Mine related assets in the Consolidated Balance Sheets.

7. Equity ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)–The following table includes the changes in the balances of the components of Accumulated other comprehensive income (loss) on the Consolidated Balance Sheets: Post Unrealized Unrealized Loss Employment Gain on on Cashflow Benefit Plan Securities Hedges Total Balance, December 31, 2011 $ (39,569) $ 1,783 $ (69,242) $ (107,028) Comprehensive income (loss) (2,597) 2,360 (2,939) (3,176) Balance, December 31, 2012 (42,166) 4,143 (72,181) (110,204) Comprehensive income 36,189 5,758 83,949 125,896 Balance, December 31, 2013 $ (5,977) $ 9,901 $ 11,768 $ 15,692

OTHER EQUITY–From November 1981 through August 1983, Basin Electric sold approximately $894,000 of electric plant under sale and leaseback agreements in exchange for $310,000 in cash and $584,000 in notes. Annual lease payments are equal to the payments the purchaser is required to make on its notes to Basin Electric. The sale and lease transactions have not been recognized for financial reporting purposes, as such transactions were entered into solely for tax purposes under the Economic Recovery Tax Act of 1981 and the Tax Equity and Fiscal Responsibility Act of 1982 and do not affect Basin Electric’s rights with respect to the property. The $310,000, net of expenses of $28,000, was reserved in Other equity. Beginning in March 2001, Basin Electric allocated its before tax margin to members and recorded the provision for (benefit from) income taxes in Other equity. As of December 31, 2013, $20,377 of income tax expense was closed into Other equity.

8. Long-term Debt

December 31,

December 31,

2013 2012 RUS guaranteed mortgage notes payable to the FFB, due in quarterly installments through 2033, interest from 1.764% to 7.939% $ 1,455,025 $ 1,534,753 Less funds held by the U.S. Treasury (226,003) (215,047) Basin Electric Power Cooperative, First Mortgage Bonds, 2006 Series A due June 2041, interest at 6.127% 200,000 200,000 Basin Electric Power Cooperative, First Mortgage Obligations, CoBank 2007 Series Notes 1and 2 due in quarterly installments through September 2042, interest at 4.02%, 4.37%, 5.92%, 6.24%, 6.27% and 6.59% 297,418 299,501 Basin Electric Power Cooperative, First Mortgage Obligations, 2009 Series B Notes due in semi-annual installments through October 2016, interest at 4.00% 32,500 32,500 Basin Electric Power Cooperative, First Mortgage Obligations, 2009 Series C Notes due in semi-annual installments through October 2027, interest at 4.89% 100,000 100,000

› BASIN ELECTRIC POWER COOPERATIVE | 53


Consolidated Financial Statements

December 31,

December 31,

2013 2012

Basin Electric Power Cooperative, First Mortgage Obligations, 2009 Series D Notes due in semi-annual installments through April 2040, interest at 5.59% Basin Electric Power Cooperative, Wyoming Infrastructure Authority Note due in semi-annual maturities through September 15, 2025, interest at 4.84% Campbell County Wyoming Solid Waste Facilities Revenue Bonds 2009 Series A due in semi-annual installments through July 2039, interest at 5.75% Less funds held by trustee Basin Electric Power Cooperative, First Mortgage Obligations, CoBank 2005 Series A Note due December 2028, interest at 5.85% Basin Electric Power Cooperative, First Mortgage Obligations, CoBank 2005 Series B Note due May 2030, interest at 5.85% Basin Electric Power Cooperative, First Mortgage Note, Wells Fargo Note Number 1 due in annual installments through June 2027, interest at 5.395% Basin Electric Power Cooperative, First Mortgage Obligations, Wells Fargo Note Number 2 due in annual installments through December 2028, interest at 4.745% Basin Electric Power Cooperative, First Mortgage Obligations, MetLife 2008 Series A Note Number 1 due June 2030, variable interest at 1.76935% Basin Electric Power Cooperative, First Mortgage Obligations, MetLife 2008 Series A Note Number 2 due May 2032, variable interest at 1.764% Basin Electric Power Cooperative, First Mortgage Obligations, MetLife 2008 Series A Note Number 3 due May 2032, variable interest at 1.767% Basin Electric Power Cooperative, First Mortgage Obligations, MetLife 2008 Series A Note Number 4 due May 2032, variable interest at 1.76785% Basin Electric Power Cooperative, First Mortgage Obligations, New York Life 2008 Series B Note, due June 2029, variable interest at 1.77060% Basin Electric Power Cooperative, First Mortgage Obligations, John Hancock 2008 Series C Note, due June 2031, variable interest at 1.76935% Basin Electric Power Cooperative, First Mortgage Obligations, Prudential 2008 Series D Note, due in semi-annual installments through October 2038, interest at 5.93% Basin Electric Power Cooperative, First Mortgage Obligations, 2008 Series E Note, due in semi-annual installments through December 2028, interest at 7.69% Basin Electric Power Cooperative, First Mortgage Obligations, 2008 Series F Note, due in serial maturities through December 2038, interest at 8.20% Basin Electric Power Cooperative, First Mortgage Obligations, 2010 South Dakota Investment Fund Limited Partnership 3 Note, due in serial maturities in March through October 2015, interest at 2.50% Basin Electric Power Cooperative, First Mortgage Obligations, 2011 Series A Notes, due in semi-annual installments through October 2031, interest at 4.00% Basin Electric Power Cooperative, First Mortgage Obligations, 2011 Series B Notes, due in semi-annual installments through October 2049, interest at 5.10% Basin Electric Power Cooperative, First Mortgage Obligations, 2012 Series A Notes, due in semi-annual installments through November 2044, interest at 4.067% Basin Electric Power Cooperative, notes payable to affiliates, bullet maturities ranging from February 2014 to September 2015, interest at 1.5% Equipment notes, Series R and S, due in monthly installments through December 2020, interest from 5.37% to 6.26% Equipment notes, Series W and X, due in monthly installments through February 2017, interest from 5.65% to 5.70% Equipment notes, Series EE, due in monthly installments through December 2013, interest at 6.00% Equipment notes, Series FF, GG, HH and II, due in monthly installments through July 2020, interest from 4.98% to 6.03% Equipment notes, Series KK, LL and MM, due in monthly installments through November 2020, interest from 5.16% to 5.76% 54 | 2013 ANNUAL REPORT

110,000

110,000

29,426

31,199

150,000 -

150,000 (3,654)

45,000

45,000

45,000

45,000

17,500

18,750

11,250

12,000

50,000

50,000

50,000

50,000

50,000

50,000

50,000

50,000

50,000

50,000

50,000

50,000

125,000

130,000

37,500

40,000

100,000

100,000

105,000

105,000

229,230

240,240

100,000

100,000

98,610

100,000

1,254

-

4,079

5,478

1,105 -

1,866 286

13,117

15,840

14,909

17,520


Consolidated Financial Statements

December 31,

December 31,

2013 2012

Equipment notes, Series NN, OO and PP, due in monthly installments through July 2020, interest from 2.18% to 3.42% 4,840 5,823 Equipment notes, Series QQ, RR, SS, TT and UU, due in monthly installments through July 2021, interest from 1.86% to 2.61% 3,651 4,325 Equipment notes, Series VV, WW and XX, due in monthly installments through November 2020, interest from 2.26% to 3.08% 6,876 Equipment notes, Series AAA, BBB and CCC, due in monthly installments through September 2022, interest from 2.62% to 3.49% 3,400 Equipment notes due in semi-annual installments through November 2044, interest at 4.10% 65,140 68,461 Other 20,389 21,463 3,501,216 3,616,304 Less current portion: FFB debt (90,378) (102,071) Funds held by the U.S. Treasury - 158,474 Debt, other than FFB (39,638) (39,983) $ 3,371,200 $ 3,632,724 In 2013, the current portion of FFB debt and funds held by the U.S. Treasury are included in Long-term debt on the Consolidated Balance Sheets. In 2012, the current portion of FFB debt and funds held by the U.S. Treasury are included in Prepayments and other current assets on the Consolidated Balance Sheets. The estimated fair value of debt, net of funds held by the U.S. Treasury and trustees, at December 31, 2013 and 2012 was $3,704,393 and $4,098,735, based on cash flows discounted at interest rates for similar issues or at the current rates offered to Basin Electric for debt of comparable maturities. The scheduled maturities of long-term debt and projected use of funds held by the U.S. Treasury for the next five years at December 31, 2013 are as follows: 2014 2015 2016 2017 2018 Long-term debt $ 130,016 $ 224,100 $ 95,706 $ 105,632 $ 113,046 Funds held by the U.S. Treasury - - (116,983) (109,020) $ 130,016 $ 224,100 $ (21,277) $ (3,388) $ 113,046 All of Basin Electric’s long-term debt is secured under an Indenture dated as of January 1, 1998 (the “Indenture”), between Basin Electric and U.S. Bank National Association, as trustee. Pursuant to the Indenture, Basin Electric created a first lien on substantially all of its tangible and certain of its intangible assets in favor of the Indenture trustee to secure certain long-term debt on a pro-rata basis. The FFB mortgage notes are guaranteed by RUS and are also collateralized by the Indenture. Basin Electric’s debt agreements contain various restrictive covenants which, among other matters, require Basin Electric to maintain a defined margins for interest ratio. All of Dakota Coal’s long-term debt is secured under the Third Amended and Restated Indenture of Trust and Security Agreement dated as of January 1, 1994 between Dakota Coal and Wells Fargo Bank, N.A., formerly known as Norwest Bank Minnesota, National Association, as trustee.

9. Income Taxes Basin Electric is a nonexempt cooperative subject to federal and state income taxation, but as a cooperative is allowed to exclude from income margins allocated as patronage capital. Basin Electric and its subsidiaries (the Consolidated Group) file a consolidated income tax return and have entered into tax-sharing agreements. Income taxes are allocated among members of the Consolidated Group based on a systematic, rational and consistent method under which such taxes approximate the amount that would have been computed on a separate company basis, subject to limitations on the Consolidated Group. In accordance with the provisions of ASC 740, Income Taxes, Basin Electric records a liability for unrecognized tax benefits. Unrecognized tax benefits are tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such BASIN ELECTRIC POWER COOPERATIVE | 55


Consolidated Financial Statements

deductibility. Basin Electric recognizes interest and penalties related to unrecognized tax benefits in the respective interest and penalties expense accounts and not in the Provision for (benefit from) income taxes. Because of the impact of deferred income tax accounting, other than for interest and penalties, the disallowance of the shorter deductibility period would not affect the effective income tax rate by any significant amount but would accelerate the cash payments to the taxing authority to an earlier tax period. Management has determined that uncertain tax positions as of December 31, 2013 are not material to the results of operations or to the financial position and a reserve is not necessary. There are no amounts of unrecognized tax benefits that are expected to significantly change within the next 12 months. The components of Basin Electric’s Provision for (benefit from) income taxes were as follows for the years ended December 31: Current tax expense $ Deferred tax expense (benefit) Provision for (benefit from) income taxes $

2013 2012 (3,102) $ 2,900 (2,257) 1,706 (5,359) $ 4,606

The tax effect of significant temporary differences representing deferred tax assets and liabilities were as follows at December 31: Deferred tax liabilities: Depreciation and property $ Direct financing leases Prepaid pension expense Other deferred tax liabilities Unrealized gains Total deferred tax liability Deferred tax assets: Tax benefit transfer leases Deferred credits Tax credits available Mine related Patronage loss carryforward Other deferred tax assets Total deferred tax assets Net deferred tax liability Current deferred tax liability Noncurrent deferred tax liability $

2013 410,496 $ 33,502 7,529 32,976 10,681 495,184

2012 407,799 30,274 12,456 23,463 24,693 498,685

(65,077) (65,242) (31,794) (28,828) (35,136) (30,005) (6,019) (7,236) (96,099) (95,529) (27,469) (26,831) (261,594) (253,671) 233,590 245,014 5,604 11,727 227,986 $ 233,287

Deferred taxes have been provided for temporary income tax differences associated with utility operations with an offsetting amount recorded as a regulatory asset as such amounts are expected to be recovered through rates charged to members at such time as the Board of Directors, in its capacity as regulator, deems appropriate. Income taxes differ from the Provision for (benefit from) income taxes computed using the statutory rate for the years ended December 31 as follows: Computed income tax at statutory rate $ Permanent differences: Patronage capital allocated Domestic production activities deduction Other, net Change in regulatory asset associated with deferred taxes net of patron net operating loss Other State income taxes Total provision for (benefit from) income taxes $ 56 | 2013 ANNUAL REPORT

2013 2012 14,206 $ 43,806 (20,089) - (470) (408) 1,362 40 (5,359) $

(14,904) (1,219) (1,324) (23,886) 1,763 370 4,606


Consolidated Financial Statements Basin Electric had available federal and state research tax credit carryforwards of approximately $16 million and alternative minimum tax credit carryforwards of approximately $19 million at December 31, 2013. The research tax credits expire in varying amounts from 2014 through 2033. Basin Electric has a patron federal net operating loss carryforward of approximately $275 million. The patron net operating loss expires in varying amounts from 2028 through 2033. It is more likely than not that deferred tax assets will be recognized before their expiration. TANGIBLE PROPERTY REGULATIONS–In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with amounts paid to acquire, produce, or improve tangible property. The regulations have the effect of a change in law and as a result the impact should be taken into account in the period of adoption. In general, such regulations apply to tax years beginning on or after January 1, 2014, with early adoption permitted. Procedural guidance is expected in early 2014 to facilitate implementation. We expect that implementation of most, if not all, of the provisions of the final regulations will occur in 2014. Analysis performed to date indicates no material impact to our financial statements.

10. Employee Benefit Plans POSTRETIREMENT BENEFITS–Employees of Basin Electric, Dakota Gas, and MLC retiring at or after attaining age 55 and completing five years of service may elect to continue medical and dental benefits by paying premiums to Basin Electric, Dakota Gas or MLC for participating in the current employee plan, subject to deductible, coinsurance and copayment provisions. Eligible dependents of retired employees continue to receive benefits after the death of the former employee, with certain limitations. Participation in Basin Electric’s, Dakota Gas’ or MLC’s medical plan can continue until the retiree or spouse becomes eligible for Medicare. Once a retiree becomes eligible for Medicare, the spouse may continue under each of the plans until the spouse becomes eligible for Medicare. Basin Electric, Dakota Gas, and MLC reserve the right to change or terminate these benefits at any time. Basin Electric and Dakota Gas fund postretirement medical benefits from general funds, and in 2013 and 2012 funding was $1,979 and $1,079. Coteau funds postretirement medical benefits through a Voluntary Employees Beneficiary Association (VEBA) trust. Coteau did not make any cash contributions to the VEBA in 2013 and 2012. Coteau also maintains health care and life insurance plans which provide benefits to eligible retired employees. Net periodic postretirement benefit expense for the years ended December 31 includes the following components: Basin Electric and Subsidiaries Coteau 2013 2012 2013 2012

Service cost – benefits attributed to service during the year $ 1,665 $ Interest cost on accumulated postretirement benefit liability 1,172 Return on plan assets - Amortization of prior service credit (989) Amortization of unrecognized loss (gain) (348) Net periodic postretirement benefit expense 1,500 Other changes recognized in Accumulated other comprehensive loss: Net loss (gain) arising during the period (7,625) Amortization of prior service credit 989 Amortization of gain (loss) 348 Total recognized in Accumulated other comprehensive income (loss) (6,288) Total recognized in net periodic benefit expense and Accumulated other comprehensive income (loss) $ (4,788) $

1,946 $ 1,593 - (1,129) (19) 2,391

374 $ 411 (216) (257) 472 784

362 488 (256) (257) 445 782

(8,188) 1,129 19

(3) 257 (472)

449 257 (445)

(7,040)

(218)

261

(4,649)

566

$

$

1,043

› BASIN ELECTRIC POWER COOPERATIVE | 57


Consolidated Financial Statements

Assumptions used to determine net periodic postretirement benefit expense were as follows for the years ended December 31: Basin Electric and Subsidiaries Coteau 2013 2012 2013 2012

Weighted-average discount rates Expected long-term rate of return on plan assets Health care cost trend rate assumed Ultimate health care cost trend Year that the rate reaches the ultimate trend rate

3.79% N/A 8.24% 4.50% 2027

4.46% N/A 8.66% 4.50% 2027

3.05% 6.00% 7.00% 5.00% 2021

3.90% 6.50% 7.50% 5.00% 2018

The following sets forth the changes in accumulated postretirement benefit liability and plan assets during the year, and reconciles the funded status of the plans to the accrued liability which is included in Deferred credits, taxes and other liabilities on the Consolidated Balance Sheets, as of December 31: Basin Electric and Subsidiaries Coteau 2013 2012 2013 2012

Change in accumulated postretirement benefit liability: Balance at January 1 $ 37,561 $ 43,289 $ Service cost 1,665 1,946 Interest cost 1,172 1,593 Actuarial loss (gain) (5,420) (5,535) Assumption changes (2,205) (2,653) Benefit payments (4,047) (2,949) Retiree contributions 2,068 1,870 Balance at December 31 $ 30,794 $ 37,561 $ Change in plan assets: Fair value of plan assets at beginning of year $ - $ - $ Actual return on plan assets - - Employer contributions 1,979 1,079 Plan participants’ contributions 2,068 1,870 Benefit payments (4,047) (2,949) Fair value of plan assets at end of year $ - $ - $ As of December 31, the funded status of the plan was: Accumulated postretirement benefit liability $ 30,794 $ 37,561 $ Fair value of plan assets - - Funded status at end of year $ 30,794 $ 37,561 $ As of December 31, the following amounts were recognized in the balance sheets and in Accumulated other comprehensive income (loss): Current liabilities $ 1,616 $ 1,599 $ Noncurrent liabilities 29,178 35,962 Net amount recognized in balance sheet $ 30,794 $ 37,561 $ Amounts not yet reflected in net periodic postretirement benefit expense and included in Accumulated other comprehensive income (loss): Prior service credit $ 4,159 $ 5,147 $ Actuarial gain (loss) 9,228 1,952 Accumulated other comprehensive income (loss) $ 13,387 $ 7,099 $

58 | 2013 ANNUAL REPORT

13,444 $ 374 411 383 - (828) - 13,784 $

12,460 362 488 493 (359) 13,444

3,938 $ 602 - - (1,059) 3,481 $

4,253 301 (616) 3,938

13,784 $ 3,481 10,303 $

13,444 3,938 9,506

- $ 10,303 10,303 $

9,506 9,506

647 $ (4,367) (3,720) $

905 (4,842) (3,937)


Consolidated Financial Statements

For Basin Electric and subsidiaries, as of December 31, 2013, $851 of the prior service credit and $457 of the actuarial gain will, through amortization, be recorded as components of net periodic postretirement benefit expense in 2014. For Coteau, as of December 31, 2013, $257 of the prior service credit and $427 of the actuarial loss will, through amortization, be recorded as components of net periodic postretirement benefit expense in 2014. Assumptions used in accounting for the postretirement benefit plans obligation were as follows for the years ended December 31: Basin Electric and Subsidiaries Coteau 2013 2012 2013 2012

Weighted-average discount rates Initial health care cost trend Ultimate health care cost trend rate Year that the rate reaches the ultimate trend rate

4.57% 7.82% 4.50% 2027

3.79% 8.24% 4.50% 2027

3.85% 7.00% 5.00% 2021

3.05% 7.00% 5.00% 2021

Changes in the assumed health care cost trend rates would impact the accumulated postretirement benefit liability and the net periodic postretirement benefit expense for 2013 as follows:

Accumulated postretirement benefit liability Net periodic postretirement benefit expense

Basin Electric and Subsidiaries Coteau 1% Increase 1% Decrease 1% Increase 1% Decrease

$ $

2,872 384

$ $

(2,891) (359)

$ $

951 64

$ $

(866) (64)

Postretirement benefit plan weighted average asset allocations were as follows: Coteau 2013 2012 Equity securities 67.7% 59.6% Debt securities 29.9% 38.6% Other 2.4% 1.8% Basin Electric and its subsidiaries and Coteau expect to make contributions of $1,616 and $0 in 2014 to their postretirement medical plans. The following are the expected future benefits to be paid:

Basin Electric and Subsidiaries Coteau

2014 2015 2016 2017 2018 2019-2023

$ $ $ $ $ $

1,616 1,744 1,892 2,016 2,456 16,891

$ $ $ $ $ $

801 969 1,062 1,165 1,305 7,525

DEFINED BENEFIT PLANS–Pension benefits for substantially all Basin Electric and Dakota Gas employees are provided through participation in the National Rural Electric Cooperative Association (NRECA) Retirement Security Plan (RS Plan) which is a defined benefit pension plan qualified under Section 401 and tax-exempt under Section 501(a) of the Internal Revenue code. It is a multiemployer plan under the accounting standards. A unique characteristic of a multiemployer plan compared to a single employer plan is that all plan assets are available to pay benefits of any plan participant. Separate asset accounts are not maintained for participating employers. This means that assets contributed by one employer may be used to provide benefits to employees of other participating employers. Basin Electric and Dakota Gas contributions to the RS Plan in 2013 and in 2012 represented less than 5 percent of the total contributions made to the plan by all participating employers. Pension costs charged to expense during 2013 and 2012 were $41,533 and $38,463. There have been no BASIN ELECTRIC POWER COOPERATIVE | 59

›


Consolidated Financial Statements

significant changes that affect the comparability of 2013 and 2012 contributions. Through 2011, Dakota Gas prefunded $66,674 to the pension plan to meet required contributions for pension funding in future years. The remaining balance of the prepaid pension fund as of December 31, 2013 and 2012 was $22,816 and $37,111. Interest on the remaining balance is earned monthly and recorded in Interest and other income in the Consolidated Statement of Operations. In the RS Plan, a “zone status” determination is not required, and therefore not determined, under the Pension Protection Act (PPA) of 2006. In addition, the accumulated benefit obligations and plan assets are not determined or allocated separately by individual employer. In total, the RS Plan was between 65 percent and 80 percent funded at January 1, 2013 and 2012 based on the PPA funding target and PPA actuarial value of assets on those dates. Because the provisions of the PPA do not apply to the RS Plan, funding improvement plans and surcharges are not applicable. Future contribution requirements are determined each year as part of the actuarial valuation of the plan and may change as a result of plan experience. BCS’s former United Mine Workers of America employees are covered under a defined benefit plan which is funded by BCS. Plan assets are invested in common stocks, long-term corporate bonds and money market funds. BCS uses a December 31 measurement date. Substantially all of Coteau’s salaried employees hired prior to January 1, 2000, participate in NACoal’s Salaried Employees Pension Plan (the NACoal Plan), a noncontributory defined benefit plan sponsored by NACoal. Benefits under the defined benefit pension plan are based on years of service and average compensation during certain periods. During 2013, Coteau amended the Combined Defined Benefit Plan to freeze pension benefits for all employees effective as of the close of business on December 31, 2013. Employees whose benefits were frozen will receive retirement benefits under defined contribution retirement plans. As a result of this amendment, Coteau remeasured the Combined Plan and recorded a $632 pre-tax curtailment loss. Net periodic pension expense for the years ended December 31 includes the following components: BCS Coteau 2013 2012 2013 2012

Service cost $ - $ Interest cost 168 Return on plan assets (242) Curtailment charge - Amortization of prior service cost - Amortization of actuarial loss 117 Net periodic pension expense 43 Other changes recognized in Accumulated other comprehensive income (loss): Prior service cost arising during period - Net income (loss) arising during the period (333) Amortization of prior service cost - Amortization of actuarial loss (117) Recognition of curtailment credit - Total recognized in Accumulated other comprehensive income (loss) (450) Total recognized in net periodic pension expense and Accumulated other comprehensive income (loss) $ (407) $

- $ 192 (226) - - 107 73

2,176 $ 3,900 (5,082) 632 197 2,205 4,028

2,382 4,058 (4,366) 324 2,596 4,994

- 211 - (108) -

(156) (30,872) (197) (2,205) (632)

7,033 (324) (2,596) -

103

(34,062)

4,113

176

(30,034)

9,107

$

$

The assumptions used to determine net periodic pension expense were as follows for the years ended December 31: 2013

Weighted average discount rate Expected long-term return on plan assets

3.34% 7.00%

BCS Coteau 2012 2013

3.92% 7.00%

3.90%/4.70%* 7.75%

2012

4.55% 8.25%

* A discount rate of 3.90% was used for the period January 1, 2013 through July 31, 2013. A discount rate of 4.70% was used for the period August 1, 2013 through December 2013, and was also used to calculate the new prior service (credit) that resulted from the elimination of future cost-of-living adjustments which was recognized immediately as a result of the curtailment. 60 | 2013 ANNUAL REPORT


Consolidated Financial Statements

The expected long-term rate of return on NACoal Plan assets reflects management’s expectations of long-term rates of return on funds invested to provide for benefits included in the projected benefit obligations. NACoal has established the expected long-term rate of return assumption for NACoal Plan assets by considering historical rates of return over a period of time that is consistent with the long-term nature of the underlying obligations of the NACoal Plan. The historical rates of return for each of the asset classes used by NACoal to determine its estimated rate of return assumption were based upon the rates of return earned by investments in the equivalent benchmark market indices for each of the asset classes. The NACoal Plan maintains an investment policy that, among other things, establishes a portfolio asset allocation methodology with percentage allocation bands for individual asset classes. The investment policy further divides investments in equity securities among U.S. and non-U.S. companies. The investment policy provides that investments are reallocated between asset classes as balances exceed or fall below the appropriate allocation bands. The following sets forth the changes in the pension benefit obligation and plan assets allocated based on the actuary’s analysis as of December 31: BCS Coteau 2013 2012 2013 2012

Change in pension benefit obligation: Projected benefit obligation at beginning of year $ 5,214 $ 5,096 $ Service cost - - Interest cost 168 192 Actuarial loss (gain) (336) 327 Benefits payments (397) (401) Plan amendments - - Curtailment - - Projected pension benefit obligation at end of year $ 4,649 $ 5,214 $ Change in plan assets: Fair value of plan assets at beginning of year $ 3,528 $ 3,274 $ Actual return on plan assets 239 343 Employer contribution 268 312 Benefits payments (397) (401) Inter-company transfers - - Fair value of plan assets at end of year $ 3,638 $ 3,528 $ As of December 31, the funded status of the plan was as follows: Projected pension obligation $ 4,649 $ 5,214 $ Fair value of plan assets 3,638 3,528 Funded status at end of year $ 1,011 $ 1,686 $ Amounts recognized in the balance sheets consist of: Current liabilities $ - $ - $ Noncurrent liabilities 1,011 1,686 Net amount recognized $ 1,011 $ 1,686 $ Amounts not yet reflected in net periodic pension expense and included in Accumulated other comprehensive income (loss): Prior service cost $ - $ - $ Actuarial loss 1,911 2,361 Accumulated other comprehensive income $ 1,911 $ 2,361 $

101,173 $ 87,979 2,176 2,382 3,900 4,058 (13,515) 9,011 (2,575) (2,257) (156) (10,650) 80,353 $ 101,173 62,012 $ 11,904 4,774 (2,575) (115) 76,000 $

49,819 6,482 8,106 (2,257) (138) 62,012

80,353 $ 101,173 76,000 62,012 4,353 $ 39,161 29 $ 4,324 4,353 $

29 39,132 39,161

379 $ 2,545 2,924 $

1,364 35,622 36,986

The projected pension benefit obligation included in the table above represents the actuarial present value of benefits attributable to employee service rendered to date, including the effects of estimated future pay increases. The accumulated pension benefit obligation also reflects the actuarial present value of benefits attributable to employee service rendered to date, but does not include the effects of estimated future pay increases. As of December 31, 2013, $4 of the Coteau actuarial gain and $19 of the prior service cost will, through amortization, be recorded as components of net periodic pension expense in 2014.

› BASIN ELECTRIC POWER COOPERATIVE | 61


Consolidated Financial Statements

As of December 31, 2013, $95 of the BCS actuarial loss will, through amortization, be recorded as a component of net periodic pension expense in 2014. Assumptions used to account for the pension benefit obligation were as follows for the years ended December 31: 2013

Weighted average discount rate Rate of increase in compensation levels

BCS Coteau 2012 2013

4.23% N/A

3.34% N/A

4.75% N/A

2012

3.90% 3.75%

The following is the actual and target allocation percentages for the NACoal Plan assets at the measurement date:

2013 Actual Allocation Target Allocation Range

U.S. equity securities Non-U.S. equity securities Fixed income securities Money market

53.6% 13.0% 32.9% 0.5%

41.0% – 62.0% 10.0% – 16.0% 30.0% – 40.0% 0.0% – 10.0%

The following is the actual and target allocation percentages for the BCS Plan assets at the measurement date:

2013 Actual Allocation Target Allocation

Equity securities Fixed income securities Other

44.8% 37% 52.1% 60% 3.1% 3%

BCS Plan assets are invested with a trust that is responsible for maintaining an appropriate investment ratio in common stocks, long-term corporate bonds and money market funds. In 2014, BCS expects to make contributions of $274 and Coteau expects to make zero contributions in 2014. The following are the expected future benefit payments for the BCS Plan and the NACoal Plan:

BCS Coteau

2014 2015 2016 2017 2018 2019-2023

$ 390 $ 2,876 $ 379 $ 3,199 $ 368 $ 3,514 $ 357 $ 3,815 $ 347 $ 4,094 $ 1,581 $ 25,404

DEFINED CONTRIBUTION PLANS–Basin Electric, Dakota Gas and MLC have qualified tax deferred savings plans for eligible employees. Eligible participants of the tax deferred savings plans may make pre-tax and post-tax contributions, as defined, with Basin Electric, Dakota Gas and MLC matching various percentages of the participants’ annual compensation. Contributions to these plans by Basin Electric, Dakota Gas, and MLC were $8,567 and $8,137 for 2013 and 2012. For employees hired after December 31, 1999, Coteau established a defined contribution plan which requires Coteau to make retirement contributions based on a formula using age and salary as components of the calculation. Employees are vested at a rate of 20 percent for each year of service and are 100 percent vested after five years of employment. Coteau recorded contribution expense of approximately $1,182 and $1,022 related to this plan in 2013 and 2012. Substantially all of Coteau’s salaried employees also participate in a defined contribution plan sponsored by NACoal. Employee contributions are matched by Coteau up to a limit of 5 percent of the employee’s salary. Coteau’s contributions to this plan were approximately $2,009 and $1,876 in 2013 and 2012. Under the provisions of the lignite sales agreement between Dakota Coal and Coteau, retirement related costs will be recovered as a cost of coal as tonnage is sold. 62 | 2013 ANNUAL REPORT


Consolidated Financial Statements

11. Deferred Credits, Taxes and Other Liabilities Deferred credits, taxes and other liabilities were as follows at December 31: 2013 2012 Non-current deferred income tax liability, net $ 227,986 $ 233,287 Asset retirement obligations and other reserves 122,966 122,922 Pension and benefit obligations 63,863 104,615 Long-term hedge liability 56,190 100,181 MBPP operating advances 29,207 20,000 Deferred gain on sale of electric plant 4,666 7,000 Unearned revenue 5,123 6,361 Regulatory deferred post-retirement obligation 8,927 4,988 Regulatory deferred revenue 10,000 Regulatory deferred unrealized gains on hedging 453 Other 8,265 12,773 $ 537,646 $ 612,127

12. Commitments and Contingencies POWER PURCHASE COMMITMENTS–Basin Electric entered into various power purchase contracts from one to 25 years. The estimated commitments under these contracts as of December 31, 2013 were $277,907 in 2014, $269,659 in 2015, $311,061 in 2016, $312,416 in 2017, $297,618 in 2018, and $4,005,710 thereafter. Amounts purchased under the contracts totaled $236,147 in 2013 and $211,504 in 2012. Basin Electric entered into various power purchase agreements with its Class A member, Corn Belt Power Cooperative (Corn Belt), under which Basin Electric buys substantially all of the output from Corn Belt’s generation resources at cost, which approximates market, through December 2050. Basin Electric also entered into a transmission lease agreement with Corn Belt which expires in December 2050. ASC 810, Consolidation, requires that certain of Corn Belt’s generation assets and liabilities associated with the power purchase agreements be consolidated in Basin Electric’s balance sheet. At December 31, 2013 and 2012, the assets and liabilities of Corn Belt included in the Consolidated Balance Sheets totaled $14,472 and $17,633. Basin Electric accounts for the costs associated with these assets and liabilities as operation, maintenance, interest and depreciation expense, rather than purchased power expense. CONSTRUCTION CONTRACT COMMITMENTS–Basin Electric is constructing two 45-megawatt natural gas-fired peaking stations in northwest North Dakota and multiple transmission projects. Dakota Gas is constructing capital projects for operational improvements. Various outstanding contractual construction commitments for Basin Electric and its subsidiaries totaled $173,200 as of December 31, 2013. Coteau has outstanding equipment purchase commitments of $281 as of December 31, 2013. INVENTORY PURCHASE COMMITMENTS–Coteau entered into various diesel fuel contracts through January 2014. The estimated commitments under these purchase contracts as of December 31, 2013 were $20,409. MINE CLOSING COSTS AND COAL PURCHASE COMMITMENTS–Under the terms of the Coteau Lignite Sales Agreement (Agreement) between Dakota Coal and Coteau, Dakota Coal is obligated to purchase all of its lignite requirements from Coteau, and Coteau is obligated to sell and deliver the required coal to Dakota Coal from contractually defined dedicated coal reserves. The coal purchase price includes all costs incurred by Coteau for development and operation of the dedicated coal reserves and may include costs to be incurred in connection with the mine closing. During 2013 and 2012, Dakota Coal paid $208,475 and $198,392 to Coteau for coal purchased under the lignite sales agreement. As a result of applying ASC 810, Consolidation, Coteau is consolidated with Dakota Coal and coal purchases from Coteau are eliminated within the consolidated financial statements. Under certain federal and state regulations, Coteau is required to reclaim land disturbed as a result of mining. Reclamation of disturbed land is a continuous process throughout the term of the Agreement. Costs of ongoing reclamation are charged to expense in the period incurred and are being recovered as a cost of coal as tonnage is sold to Dakota Coal. Costs to complete reclamation after mining has been completed in a specific mine area are reimbursed under the Agreement as costs of reclamation are actually incurred.

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Consolidated Financial Statements

Coteau accounts for its asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations, which provides accounting requirements for retirement obligations associated with tangible long-lived assets and requires that an asset’s retirement cost be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Coteau’s annual costs related to amortization of the asset and accretion of the liability totaled $4,333 in 2013 and $11,921 in 2012. Coteau made payments of $7,529 and $7,437 in 2013 and 2012 for costs of reclamation that were incurred. Dakota Coal has established designated funds for mine closing costs. The Agreement includes provisions whereby, upon expiration of the agreement, Dakota Coal has the option to purchase the outstanding common stock of Coteau for its book value from NACoal. Dakota Coal may exercise this option only if Coteau has not exercised its right to extend the Agreement. NACoal has the option to require Dakota Coal to purchase the outstanding stock of Coteau for its book value in the event all of the plants Dakota Coal presently sells lignite coal to are closed or if lignite coal may no longer be legally mined in North Dakota and Dakota Coal exercises its right to terminate the Agreement with Coteau. COAL PURCHASE AND FINANCING COMMITMENTS–Basin Electric, on behalf of the MBPP, has executed an agreement with Western Fuels Association, Inc. (Western Fuels) requiring coal purchases of approximately 6,700,000 tons per year through 2034, with an option to extend the contract with approval by both parties. The average price of coal under this agreement during 2013 and 2012 was approximately $19.73 and $19.12 per ton. Basin Electric executed an agreement with Western Fuels requiring coal purchases of approximately 1,800,000 tons per year beginning in 2011 through the life of the DFS, with an option to extend the contract with approval by both parties. Coal purchased under this agreement is used at the DFS. The average price of coal purchased under this agreement during 2013 and 2012 was approximately $11.14 and $10.56 per ton. The MBPP provides financing to Western Fuels and Western Fuels-Wyoming, Inc. (WFW), a wholly owned subsidiary of Western Fuels for mine development costs associated with coal deliveries to LRS. Basin Electric provides financing to Western Fuels and WFW for mine development costs associated with coal deliveries to DFS. Notes receivable from Western Fuels and WFW as of December 31, 2013 and 2012 are as follows: Issue Interest Original Date Term Rate Loan Value Borrower Purpose 04-01-03 10 years 4.25% $ 11,347 Western Fuels Mine development-LRS Basin share $ 01-31-07 7 years 4.60% 4,777 WFW Equipment purchase- LRS Basin share 09-24-08 15 years 4.50% 1,522 WFW Shop expansion- LRS Basin share 09-24-09 7 years 5.50% 526 WFW Equipment purchase- LRS Basin share 07-23-10 7 years 5.25% 412 WFW Equipment purchase- LRS Basin share 12-15-10 32 years 5.15% 20,457 WFW Coal conveyance equipment-DFS 05-03-11 7 years 5.61% 109 WFW Mine capital spares- LRS Basin share 05-03-11 7 years 5.61% 180 WFW Mine capital spares-DFS 05-03-11 5 years 4.97% 183 WFW Mine inventory spares-LRS Basin share 05-03-11 5 years 4.97% 302 WFW Mine inventory spares-DFS 12-30-11 7 years 4.35% 257 WFW Mine capital spares-DFS 12-30-11 5 years 3.85% 445 WFW Mine inventory spares-DFS Less current portion $

2013 2012 - $ 222 - 739 - 1,293 - 288 - 270 20,231 20,518 77 91 127 151 183 183 302 302 195 228 445 445 21,560 24,730 (376) (1,480) 21,184 $ 23,250

The estimated fair value of these notes receivable at December 31, 2013 and 2012 was $25,787 and $33,508, respectively, based on the future cash flows discounted using the yield on a treasury note with a similar maturity. COAL SALES & PURCHASE COMMITMENT–In 2013, Basin Electric entered into agreements with three, unrelated companies to supply “refined coal” to AVS, LOS and LRS. The refined coal is produced by chemically treating lignite or sub-bituminous coal to produce a fuel stock which reduces air emissions during combustion of the treated coal. Basin Electric sells untreated coal to the refined coal supplier and then purchases refined coal from the supplier after it was been refined. The supplier pays Basin Electric for rent and services provided by Basin Electric in connection with supplier’s production of refined coal. The estimated net benefit to Basin Electric for the refined coal projects through 2014 exceeds $14

64 | 2013 ANNUAL REPORT


Consolidated Financial Statements

million per year. The refined coal suppliers own the coal treatment facilities, which were installed on the AVS, LOS and LRS plant sites and pay all associated operating costs. The refined coal suppliers qualify for certain federal tax credits for each ton of refined coal sold to Basin Electric with the reasonable expectation that it will be used for the purpose of producing steam and results in required emission reductions. Basin Electric has an option to purchase the coal treatment facilities (or similar assets) at each plant site after the eligible federal tax credit period ends in 2021. The agreements between the refined coal suppliers and Basin Electric allow for either party to terminate the agreement at any time, which would require the removal of the equipment at the refined coal supplier’s cost. ASSET RETIREMENT OBLIGATIONS–An asset retirement obligation is the result of legal or contractual obligations associated with the retirement of a tangible long-lived asset that results from the acquisition, construction, or development and/or the normal operation of a long-lived asset. Basin Electric and Coteau determine these obligations based on an estimated asset retirement cost adjusted for inflation and projected to the estimated settlement dates, and discounted using a credit-adjusted risk-free interest rate. A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation included in Deferred credits, taxes and other liabilities on the Consolidated Balance Sheets is as follows: Balance, January 1 $ Liabilities settled during the period Accretion expense Additions Balance, December 31 $

2013 2012 72,612 $ 47,074 (7,536) (7,572) 3,901 3,863 1,023 29,247 70,000 $ 72,612

RECLAMATION GUARANTEES–Basin Electric provides guarantees of certain reclamation obligations of Coteau. These guarantees cover the reclamation of mined areas as required by the State of North Dakota’s Public Service Commission (PSC). The bonds are released by the PSC after a period of time (generally ten years after final reclamation is completed) when it has been determined that the mined area has been returned to its original condition. As of December 31, 2013, the aggregated value of these guarantees is $107,100. Basin Electric provides guarantees of certain reclamation obligations of WFW. Those guarantees cover the reclamation of mined areas as approved by the Wyoming Department of Environmental Quality (WDEQ) under its self-bonding program. The bonds are released by the WDEQ after a period of time (generally ten years after final reclamation is completed) when it has been determined that the mined area has been returned to its approved post-mining use. As of December 31, 2013, the aggregated value of these guarantees is $18,300. DISMANTLEMENT COSTS–The county zoning permit requires Dakota Gas to dismantle the Synfuels Plant at such time that operations or other alternative uses approved by the Board of County Commissioners are terminated. Although Dakota Gas presently intends to operate the Synfuels Plant indefinitely, in accordance with ASC 410, Asset Retirement and Environmental Obligations, Dakota Gas accrues an obligation for the eventual dismantlement and discontinuation of use of the Synfuels Plant. LINES OF CREDIT–Basin Electric has entered into lines of credit as follows: Lender Maturity National Rural Utilities Cooperative Finance Corporation 03-18-18 Syndicate of Eleven Banks 12-31-16 Syndicate of Twelve Banks 11-06-18

Total Availability $ 130,000 $ 500,000 $ 400,000

Outstanding Advances as of December 31, 2013 $ 129,925 $ 179,954 $ -

As of December 31, 2013, the effective interest rate of the outstanding advances is .0144%. LEASE INDEMNIFICATIONS–In general, under the terms of Basin Electric’s sale and leaseback agreements discussed in Note 7, the lessors are indemnified should certain disqualifying events occur resulting in the recapture of tax credits, accelerated cost recovery deductions and interest deductions. Management believes that if indemnification occurs, there will not be a material adverse effect on Basin Electric’s financial position, results of operations or cash flows. CO2 SALES COMMITMENTS–Dakota Gas has three contracts involving commitments for the sale of CO2. Two of these contracts are to sell and deliver CO2 from the Synfuels Plant to oil fields located near Weyburn, Saskatchewan. The initial Weyburn agreement is for a 15-year term ending in 2016, which may be extended by the buyer with at least 120 days prior written notice for up to ten one-year renewals . Either party has the right at any time during the term of the agreement to cancel the obligation to purchase or deliver CO2 by giving 12 months prior written

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Consolidated Financial Statements

notice and paying a termination value of $130,000. This termination amount is effective until June 2015 and the buyer can extend this date for one-year renewals by giving 120 days prior written notice. If the buyer, over the course of a contract year, fails to take an average stated volume, Dakota Gas has the right to terminate this agreement 30 days following such contract year unless the buyer provides written notice to extend the agreement and pays Dakota Gas a penalty fee for each month the average stated volume was not taken. Dakota Gas entered into a second Weyburn agreement which required payment of a certain portion of Dakota Gas’ additional capital requirements, reducing Dakota Gas’ capitalized equipment cost. This sales agreement terminated in February 2012, and Dakota Gas paid the buyer a prescribed amount of $8,196 as partial reimbursement of the capital contribution previously paid. In August 2012, a replacement agreement was entered into between Dakota Gas and the counterparty. This agreement has a term of five years, may be extended by either party for up to five one-year renewals and may be terminated at any time by either party with 180 days prior written notice. The third CO2 agreement is to sell and deliver CO2 from the Synfuels Plant to oil fields located near Midale, Saskatchewan for a 20-year period ending in 2025, and required that this buyer pay a certain portion of Dakota Gas’ additional capital requirements up front, reducing Dakota Gas’ capitalized equipment cost. This buyer can terminate this agreement without penalty by giving 120 days prior written notice. If the initial Weyburn agreement is terminated, Dakota Gas has the right to terminate this Midale agreement by giving the buyer 120 days prior written notice. BURLINGTON NORTHERN SANTA FE RAILWAY COMPANY (BNSF)–On October 19, 2004, Western Fuels and Basin Electric filed a complaint with the Surface Transportation Board (STB) alleging that the BNSF rates for the movement of coal from the Powder River Basin to the LRS are unreasonably high and asked the STB to set reasonable rates. On February 18, 2009, the STB issued a decision providing significant rate relief for LRS coal deliveries. After further post decision deliberations, the STB concluded that the tariff for deliveries to LRS should be reduced by 48% and that reparation should be received for overcharges paid during October 2004 through March 2009. On November 18, 2009, Western Fuels received $119,958 from BNSF which was transferred to the participants of the MBPP. Basin Electric’s share was $51,196 and is recorded as a liability reserve for unearned revenue, included in deferred credits, taxes and other liabilities on the Consolidated Balance Sheets, until a decision is made on an appeal made by BNSF to the U.S. Court of Appeals for the D.C. Circuit (the Court). On May 11, 2010, the Court decided two of the three issues in favor of Western Fuels/Basin Electric. On the third issue, the Court remanded the decision back to the STB directing the STB to explain in greater detail why their methodology for allocating variable costs did not double count certain revenue. On January 31, 2011, after receiving comments on the remanded issue from BNSF, the STB re-opened the record. Western Fuels/Basin Electric responded to the BNSF comments on March 18, 2011. On June 15, 2012, the STB provided the detailed recommendation on their allocation and affirmed their earlier decision. On July 23, 2012, BNSF appealed the decision to the Court. On January 31, 2014, the DC Circuit remanded the case back to the STB noting that the Board, under the previous remand, should have also considered whether to apply alternative ATC to the allocation or provided a reasonable explanation for STB actions. CLIMATE CHANGE–There are efforts underway in the United States to regulate greenhouse gas emissions through regulatory changes and litigation through the courts. Basin Electric is currently unable to predict with any degree of certainty when (or if) a comprehensive regulatory scheme for greenhouse gases will be in place. Since a significant portion of Basin Electric’s generating assets are coal based, greenhouse gas regulation may have a significant impact on future costs. ENVIRONMENTAL PROTECTION AGENCY (EPA) SECTION 114(a)-LRS–Basin Electric received a Section 114(a) letter dated September 28, 2011, from the EPA requesting information about capital additions at the LRS. Responsive documents were submitted to EPA on December 2, 2011. On January 16, 2012, EPA requested additional information within 30 days on 25 of the capital projects. Basin Electric provided those documents on April 16, 2012. By letter dated February 6, 2013, EPA requested additional information regarding non-capitalized projects of $100,000 or more. On April 11, 2013, Basin Electric submitted a portion of the updated information. A second portion was submitted by April 15, 2013 and the third portion was submitted May 23, 2013. Basin Electric will continue to respond to these requests as the law requires, and will respond appropriately when any additional steps are required. NORTH DAKOTA BART–The Clean Air Act’s Regional Haze Program requires each state to adopt a State Implementation Plan (SIP) that includes requiring certain existing major sources of visibility impairing pollutants to install Best Available Retrofit Technology (BART) to control emissions of such pollutants. The LOS Unit 2 was subject to the BART review. On November 29, 2010, the EPA notified the North Dakota Health Department (NDHD) that it intended to propose a Federal Implementation Plan (FIP) because a portion of North Dakota’s SIP is inadequate. The letter noted that the proposed nitrogen oxide (NOx) controls for LOS Unit 2 are inadequate. On February 20, 2011, the EPA notified the NDHD that EPA may also propose additional Reasonable Progress controls in a FIP for a portion of the North Dakota Regional Haze Plan, which includes AVS. The state of North Dakota contested these EPA proposals. 66 | 2013 ANNUAL REPORT


Consolidated Financial Statements

On September 21, 2011, EPA published notice of its proposed rule to partially approve and partially disapprove North Dakota’s SIP. Included in the disapproval was North Dakota’s determination of BART for NOx emissions for LOS Unit 2 and its “reasonable progress” plan for AVS. Basin Electric presented comments at a public hearing in October 2011 and submitted written comments on November 21, 2011. In a final decision issued on March 2, 2012, the EPA approved the North Dakota SIP for the BART at LOS but disapproved the state’s “reasonable progress” plan for AVS. The EPA notice requires each unit at AVS to reduce its NOx emissions by 2018 to not more than 0.17 pounds per million Btu averaged over a rolling 30-day period. Management believes this new emission rate is achievable through modifications to the low NOx burners at AVS. Several parties, including the state of North Dakota, Great River Energy and the National Parks Conservation Club, have filed appeals of EPA’s decision with the Eighth Circuit Court of Appeals. Basin Electric has intervened in the appeal and has filed briefs. The Court heard oral arguments on the issues on May 14, 2013. EPA held a public hearing on May 15, 2013 to take comments on the Petition for Reconsideration of its BART decision regarding LOS and Milton R. Young Station filed by Environmental Groups. On June 17, 2013, Basin Electric also submitted written comments on the reconsideration proposal. On September 23, 2013, the United States Court of Appeals for the Eighth Circuit issued its Opinion in the North Dakota/EPA Regional Haze appeals cases. The Court concluded it was without jurisdiction to hear the Environmental Groups challenges to EPA’s approval of the North Dakota BART determinations for Milton R. Young Station and the Leland Olds Station. The Court found that because the Environmental Groups had filed a Petition for Reconsideration with EPA on this issue which is still under consideration, that the matter was not ready for the Court of Appeals to render its Opinion. WYOMING BART–In June 2006, the WDEQ notified Basin Electric that the LRS was subject to BART requirements. A settlement agreement between Basin Electric and the WDEQ was approved by the Wyoming Environmental Quality Council in November 2010. The terms of the agreement were incorporated into the Wyoming Regional SIP. On June 4, 2012, EPA issued its proposed action regarding the Wyoming Regional Haze SIP. EPA proposed to approve all of the Wyoming SIP except for the NOx BART for certain coal-fired electric generation stations, including LRS. EPA proposed the addition of selective non-catalytic reduction (SNCR) equipment to LRS Units 1, 2 and 3. Written comments were submitted on August 3, 2012. On October 3, 2012, the parties to the Wildearth Guardians v. EPA suit in the U.S. District Court-Colorado signed a Stipulation of Extend Deadlines in a Consent Decree. The deadline for EPA to issue a Notice of Final Rulemaking regarding Wyoming was moved from October 15, 2012, to December 14, 2012 and then to September 22, 2013. EPA requested more time to review new cost and visibility analyses for several of the units subject to review. On May 24, 2013, EPA issued its reproposed NOX BART FIP for LRS of 0.07 lbs/mmBtu on a 30-day rolling average. The emission limit would require selective catalytic reduction (SCR) technology in addition to low NOX burns (LNB) and overfire air (OFA). Public hearings were held in Cheyenne on June 24 and July 17, 2013 and in Casper on July 26, 2013. Basin Electric was represented at all three hearings and presented expert witnesses at the July 26 hearing. Basin Electric submitted lengthy comments to EPA on August 26, 2013, which was the end of the comment period. Per the Consent Decree, EPA had until November 21, 2013 to issue its final action on the Wyoming Regional Haze SIP. EPA was granted an extension under the Consent Decree until January 10, 2014. On January 10, 2014, EPA issued its final FIP on Wyoming Regional Haze SIP. EPA found a NOX BART for LRS to be 0.07 lbs/mmBtu on a 30-day rolling average. Basin Electric is considering its legal and technical options. WILDEARTH GUARDIANS V. EPA–On January 11, 2013, Wildearth Guardians filed with the Tenth Circuit Court of Appeals in Denver, Colorado a Petition to Review EPA’s December 2012 decision to approve a revision to the state of Wyoming’s RHSIP pursuant to Section 309 of the Clean Air Act regulations. The approved RHSIP revision would reduce SO2 emissions by establishing yearly emission milestones and a backstop SO2 trading program. Section 309 is an alternative to Section 308 of the Regional Haze regulations, which requires certain facilities to undergo a BART review for pollutants that could impact mandatory Class 1 areas. Wyoming, Utah and New Mexico on the Colorado Plateau elected to pursue the Section 309 option to control their SO2 emissions affecting Regional Haze. Because the LRS is a BART source which has already undergone BART review for NOx, it could be affected should the court overrule EPA’s approval of Wyoming’s Section 309 RHSIP for SO2. An additional suit, Heal Utah v. EPA, has been filed on the same basis challenging EPA’s approval of the Section 309 revision on Wyoming’s RHSIP. Basin Electric has filed Motions to Intervene in both the Wildearth Guardians and the Heal Utah cases. All briefs were filed prior to November 1, 2013. Oral arguments will be held in March, 2014.

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Consolidated Financial Statements

13. Related Party Transactions Other receivables include $2,584 and $846 at December 31, 2013 and 2012, amounts Basin Electric, as operating agent, has billed to MBPP. Included in special funds is Basin Electric’s advance to MBPP of approximately $12,346 and $8,454 at December 31, 2013 and 2012. CONTRACTUAL COMMITMENTS–Basin Electric provides and receives power, various materials, supplies and services to and from affiliates which are under the following agreements through 2020, except as noted below:

• POWER SUPPLY–Basin Electric provides all electric capacity, energy and transmission service needed to meet Dakota Gas’ Synfuels Plant requirements under an agreement that extends through 2050.

• POWER SALES–PrairieWinds ND and PrairieWinds SD sell electric power to Basin Electric under an agreement that extends through 2034. • SCREENED COAL–Dakota Gas’ Synfuels Plant provides screened coal to Basin Electric under an agreement that extends through 2037. • COAL SUPPLY–Dakota Coal provides all coal requirements of Dakota Gas’ Synfuels Plant and Basin Electric’s AVS. It also supplies a majority of LOS’s coal requirements. This agreement extends through 2037.

• PROJECT ADMINISTRATIVE SERVICES–Basin Electric provides various administrative and financial services to Dakota Gas, Dakota Coal, BTI, PrairieWinds ND and PrairieWinds SD.

• LIME SALES–Dakota Coal provides lime to Basin Electric’s AVS and LRS. • WATER SUPPLY–Basin Electric provides water supply facilities for use by Dakota Gas’ Synfuels Plant. • SALE OF NATURAL GAS–Dakota Gas sells natural gas to Basin Electric for operation of utility peaking plants. • PROJECT SERVICES–Basin Electric provides the use of operational assets to Dakota Gas’ Synfuels Plant. Related party amounts that were not eliminated in consolidation in accordance with ASC 980, Regulated Operations, were billed as follows for the years ended December 31: Power supply from Basin Electric to Dakota Gas Screened coal sales from Dakota Gas to Basin Electric Coal supply sales from Dakota Coal to Basin Electric Power sales from PrairieWinds ND to Basin Electric Power sales from PrairieWinds SD to Basin Electric Administrative services by Basin Electric to Dakota Gas Lime sales from Dakota Coal to Basin Electric Water supply from Basin Electric to Dakota Gas Natural gas sales from Dakota Gas to Basin Electric Administrative services by Basin Electric to Dakota Coal Administrative services by Basin Electric to PrairieWinds ND Administrative services by Basin Electric to PrairieWinds SD Administrative services by Basin Electric to BTI Project services from Basin Electric to Dakota Gas

$ $ $ $ $ $ $ $ $ $ $ $ $ $

2013 2012 63,045 $ 58,707 62,278 $ 70,204 67,755 $ 45,098 14,279 $ 14,625 19,784 $ 21,388 12,806 $ 12,913 10,324 $ 11,166 2,977 $ 3,083 8,393 $ 7,943 2,186 $ 1,992 806 $ 837 1,108 $ 1,042 1,052 $ 1,736 381 $ 457

Various other intercompany management, administrative and financial services were performed, which were not significant.

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Antelope Valley

Station

Dry Fork Station

Freedom Mine

Laramie River Station

one Company

Montana Limest

Spirit Mound Station

Culbertson Generation Station

tion Unit 2 Earl F. Wisdom Generating Sta

Great Plains Synfuels Plant

Leland Olds Station

Pioneer Generation Station

Transmission BASIN ELECTRIC POWER COOPERATIVE | 69 a

Deer Creek Station

Frannie Lime Plant

n

Groton Generation Statio

Lonesome Creek Station

PrairieWinds

Wyoming Distributed Generation



2013 Basin Electric Annual Report