2015 Annual Report Web

2015 ANNUAL REPORT

Doug Roethlisberger lives with his family, including his son, Case, south of Huff, ND, on Mor-Gran-Sou Electric Cooperative lines.

The Roethlisbergers run a small grain farm, growing corn and wheat. Doug also works for 3C Construction, a company owned by three co-ops, Roughrider Electric, Slope Electric and Mor-Gran-Sou Electric. 3C Construction does work on power lines, underground and overhead power, and storm repair.

TABLE OF CONTENTS 2 PRESIDENT AND GENERAL MANAGER MESSAGE 4 AT A GLANCE 4 GENERATION PORTFOLIO 5 SEVEN SUBSIDIARIES 7-9 MEMBERSHIP MAP, DISTRICTS & DIRECTORS 10 DAKOTA GAS DIRECTORS 10 COOPERATIVE MANAGEMENT 11 SENIOR MANAGEMENT 13 OPERATIONAL EXCELLENCE 20-21 OWNED OR OPERATED POWER RESOURCES 27 DAKOTA GAS PRODUCTS 28 CLEAN POWER PLAN 29 SUPPORTING MEMBER GROWTH 35 COMMITMENT TO COOPERATIVE & WORKFORCE 41 COMMITMENT TO COMMUNITY 45 FINANCIAL STABILITY 49 FIVE-YEAR CONSOLIDATED FINANCIAL SUMMARY 50 INDEPENDENT AUDITORS’ REPORT 51 CONSOLIDATED BALANCE SHEETS 52 CONSOLIDATED STATEMENTS OF OPERATIONS 53 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) 53 CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY 54 CONSOLIDATED STATEMENTS OF CASH FLOWS 55-81 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ANNUAL MEETING INFORMATION REQUESTS BASIN ELECTRIC POWER COOPERATIVE Communications & Administration 1717 East Interstate Avenue Bismarck, ND 58503-0564 Phone: 701.223.0441 www.basinelectric.com Editor: Andrea Blowers (ablowers@bepc.com) Graphic Designer: Nicole Perreault Photographers: Chelsy Ciavarella & Greg DeSaye

The 2016 Basin Electric Annual Meeting of the Membership is scheduled for Nov. 9 and 10 in Bismarck, ND.

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This 2015 Annual Report was written, compiled and produced by the employees of Basin Electric Power Cooperative and its subsidiaries.

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Equal Employment Opportunity Employer M/F/D/V

2015 ANNUAL REPORT 1

PRESIDENT & GENERAL MANAGER MESSAGE

PEOPLE. POWER. PURPOSE.

T

hree simple words, yet they embody all of what Basin Electric is – how it came to be, what it is today and what it will be in the future.

No matter what Basin Electric and its membership face – be it poorly considered regulations, commodity price fluctuations, growing loads or an evolution in the way we do business, having a specific and clearly defined purpose – our members – ensures these issues will never cloud our judgment.

This year, Basin Electric’s board refocused its commitment to that purpose. In reviewing our Statement of Ideals and Objectives, our mission statement, our board policies and our long-term structure, the board and staff worked to clearly define the course for Basin Electric. In the end, we decided three external elements would guide us in setting the plan: living in a carbon-constrained world; dealing with rapidly evolving technology, particularly in the form of distributed generation; and mitigating the risks of commodity prices.

It’s imperative that we are all on the same page about who we are and where we’re going, and we believe we’re on the right track.

In a year like 2015, where Basin Electric marked a number of defining milestones and evolutions in the way we operate, having a clear path and transparent goals have never been more important.

OUR MISSION Basin Electric Power Cooperative provides reliable, low-cost wholesale power, along with value-added products and services to support and unite rural America. We are a member-owned, democratically controlled organization focused on professional excellence, social responsibility, a culture of safety and excellent member service.

2 BASIN ELECTRIC POWER COOPERATIVE

INITIA T

OPPOR TUN ITI

ES

E C TIVE

OPPO R T UN ITI

In October, we completed our integration into Southwest Power Pool (SPP) after years of study and evaluation with our membership. This pivotal move changes our relationship with the Western Area Power Administration Upper Great Plains Region (Western), and although Western will no longer dispatch our power, our relationship remains strong. While this was a complicated and challenging move for all parties, we were guided by doing the right thing for our membership.

We also made the pivotal decision to buy out of the Rural Utilities Service (RUS). Though our support for RUS and the valuable role it plays in rural America remains as strong as ever, a number of factors weighed into our decision, and buying out of RUS was prudent for Basin Electric.

It was a positive experience. As the finance team met with investors to procure debt previously held by RUS, the cooperative’s long-term wholesale power supply contracts with members and its favorable creditworthiness played vital roles in raising $1.5 billion, nearly double the original goal of $800 million: the largest generation and transmission cooperative U.S. private placement transaction to date.

Additionally, we’re pleased with how the Our Power, My Safety initiative is continuing to grow across the cooperative’s facilities. Employees are truly our greatest resource and we’re fully supportive of a continuous improvement process that puts our people first.

Unfortunately, the year wasn’t all positive. The Environmental Protection Agency (EPA) threw a mighty blow in August when the agency announced its final Clean Power Plan rule, which limits carbon dioxide (CO2) emissions from existing stationary power sources. The differences between the proposed rule and the final rule are preposterous, and eight of the 12 states hit the hardest are in our service territory. Quite simply, this rule is a threat to our members.

S RISK

BJ

S IES

O

CO-OP PLAN

RISKS

S RISK

V

OPPOR T U NI T

Through its Cooperative Plan, Basin Electric has expanded its efforts to communicate and train toward the cooperative’s key mission. Efforts are being made to maintain a focus on Basin Electric’s planning process to ensure all employees know the cooperative’s mission and their important role in making it a success.

ES IV

ES LU A

CO-OP PLAN

OPPOR TU NI T IES

ES

S RISK

In response, we’ve begun working through the legal process, but we fully anticipate this fight will carry on for a number of years on all fronts – legally, legislatively and publically. Our legal efforts are paying off. In February 2016, the Supreme Court granted a Stay of the rule, which halts implementation of the rule until litigation is concluded.

It’s a challenge, but we’ve faced them before and there will be others in the future. As long as we remain true to our values, our mission and our guiding force – our members – Basin Electric will continue to be a strong, stable cooperative for many, many years.

MILESTONES RUS BUYOUT A number of factors weighed into Basin Electric’s decision to buy out of the Rural Utilities Service.

SPP INTEGRATION In October 2015, Basin Electric integrated into Southwest Power Pool, a regional transmission organization.

BNSF SETTLEMENT In May, Western Fuels Association and Basin Electric, as the operating agent for the six participants of the Missouri Basin Power Project, reached a settlement with BNSF Railway on a rate case dating back to 2004.

WAYNE PELTIER President

PAUL SUKUT CEO and General Manager

2015 ANNUAL REPORT 3

AT A GLANCE NOT-FOR-PROFIT · MEMBER-OWNED · GENERATION AND TRANSMISSION COOPERATIVE

2,100+MILES

2,300

EMPLOYEES

OR RP ATE O

D

INC

HIGH-VOLTAGE TRANSMISSION

2.9

138

MILLION MEMBER CONSUMERS

CO-OP MEMBERS

9

STATE SERVICE TERRITORY

GENERATION PORTFOLIO Basin Electric’s Resource Portfolio consists of generation in megawatts (winter ratings) from owned facilities and purchased power contracts longer than three years. The renewables percentage includes wind, recovered energy generation and flaregas totals.

OIL

3.2% 180.8 MW

NATURAL GAS

18.4% 1,026.5 MW

TOTAL 5,594 MW

RECOVERED ENGERY 0.8%

44 MW

COAL

MAXIMUM WINTER

56.4% 3,154.1 MW

CAPABILITY IN MEGAWATTS End of year 2015

WIND 14.5%

810.7 MW

NUCLEAR 1.1% 4 BASIN ELECTRIC POWER COOPERATIVE

62.2 MW

HYDRO 5.6%

315.7 MW

SEVEN SUBSIDIARIES DAKOTA GASIFICATION COMPANY

DAKOTA COAL COMPANY

• For-profit subsidiary since 1988

• For-profit subsidiary since 1988

• Owns and operates the Great Plains Synfuels Plant near Beulah, ND

• Finances and markets lignite coal from the Freedom Mine near Beulah, ND, which is owned and operated

by The Coteau Properties Company

• Produces pipeline-quality synthetic natural gas, fertilizers, carbon dioxide, crude cresylic acid, krypton/ xenon gases, phenol, naphtha and tar oil

SOURIS VALLEY PIPELINE LIMITED

• Coordinates procurement and transportation of Powder River Basin Coal to Laramie River Station, Dry Fork Station and Leland Olds Station • Owns a lime plant near Frannie, WY, managed through a division called Wyoming Lime Producers since 1992

MONTANA LIMESTONE COMPANY

• For-profit subsidiary of Dakota Gasification Company since 1997 • Capable of transporting a daily average of 155 million standard cubic feet of carbon dioxide for enhanced oil recovery in Canada

BASIN COOPERATIVE SERVICES • Not-for-profit subsidiary since 1981

• Acquires resources and services for electric plant generation

PRAIRIEWINDS ND 1, INC.

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

PRAIRIEWINDS SD 1, INC.

• For-profit subsidiary since 2008

• For-profit subsidiary since 2008

• Owns wind projects (123 MW) near Minot, ND

• Owns a wind project (150 MW) near White Lake, SD

2015 ANNUAL REPORT 5

Sean Keller, Basin Electric lineman-journeyman stationed in the Transmission System Maintenance shop in Gillette, WY. Basin Electric operates Transmission System Maintenance shops in 11 locations in North Dakota, South Dakota, Wyoming and Nebraska.

DISTRICT 6

DISTRICT 3

Central Montana Electric Power Co­operative ROBERTA ROHRER Great Falls, MT

Central Power Electric Co­operative TROY PRESSER Minot, ND

Basin Electric director since 2004 and 1 Big Flat Electric Co­opera­tive electric cooperative board member 2 Hill County Electric Co­opera­tive since 1979 3 Marias River Electric Co­opera­tive Farmer/cattle rancher McCone Electric Co­opera­tive 4 NorVal Electric Co­opera­tive 5 Park Electric Co­opera­tive 6 Sun River Electric Co­opera­tive 7 Yellowstone Valley Electric Serves on PrairieWinds boards and as chairman of Dakota Coal/Montana Limestone boards Co­opera­tive

Basin Electric director since 2015 and electric cooperative board member since 2007 Rancher

Serves on Dakota Coal/Montana Limestone and PrairieWinds boards

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

DISTRICT 8 Upper Missouri Power Co­operative ALLEN THIESSEN Sidney, MT

Basin Electric director since 2012 and 1 Burke-Divide Electric Co­opera­tive electric cooperative board member 2 Goldenwest Electric Co­opera­tive since 1986 3 Lower Yellowstone Rural Electric Association Studied agriculture at Montana State University 4 McCone Electric Co­opera­tive 5 McKenzie Electric Co­opera­tive Partner in Town & Country Repair 6 Mountrail-Williams Electric Co­opera­tive Serves on the PrairieWinds boards and as treasurer on 7 Roughrider Electric Co­opera­tive Dakota Gas board 8 Sheridan Electric Co­opera­tive 9 Slope Electric Co­opera­tive 10 Southeast Electric Co­opera­tive

DISTRICT 10 Powder River Energy Corporation PAUL BAKER Sundance, WY

Basin Electric director since 2013 and electric cooperative board member since 1994 Cattle rancher

Serves on PrairieWinds boards and as vice chairman of Dakota Coal/Montana Limestone boards

DISTRICT 5

Tri-State Generation & Transmission Association LEO BREKEL Westminster, CO

Basin Electric director since 2014 and electric cooperative board member since 1995 Retired physical plant director at Northeastern Junior College Farmer Serves on Dakota Coal/Montana Limestone and PrairieWinds boards

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

7 BASIN ELECTRIC POWER COOPERATIVE

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 Mora-San Miguel Electric Cooperative 20 Morgan County Rural Electric Association 21 Mountain Parks Electric 22 Mountain View Electric Association 23 Niobrara Electric Association 24 Northern Rio Arriba Electric Co­opera­tive 25 Northwest Rural Public Power District 26 Otero County Electric Cooperative

27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44

Panhandle Rural Electric Membership Association Poudre Valley Rural Electric Association Roosevelt Public Power District San Isabel Electric Association San Luis Valley Rural Electric Co­opera­tive 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

MEMBERSHIP MAP

B

asin Electric’s member systems’ service territories span 540,000 square miles from the Canadian to the Mexican borders. Our members constitute a vital network of generation, transmission and distribution systems that deliver electricity to 2.9 million consumers in parts of North Dakota, South Dakota, Wyoming, Colorado, Minnesota, Iowa, Nebraska, Montana and New Mexico.

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3 1

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2

10 2

1 9

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District 10

8 5

43 29

22

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4

4 8 3 5

6

27

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3

44 15

DISTRICT 9 WAYNE PELTIER

32 31 17 16

38

Basin Electric director since 2008 and electric cooperative board member since 1999

36

30

Studied mechanical drafting at Willmar Junior College and served in the U.S. Air Force and the South Dakota Air National Guard

37

Farmer and owner of P&K Fabricating

14

19

President Serves on Dakota Coal/Montana Limestone boards and chairman of PrairieWinds boards

6 3 35

34

4

20

33

24

5

13

22 10

2

1

3

18

28 39

7

4

1 2

20

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4

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8

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13

40

12 21

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25

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42

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14

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11 3

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41

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1 11

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15

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1

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26

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

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

2 5

DISTRICTS & DIRECTORS

E

ach Basin Electric director represents one of 11 membership districts. They also serve on local distribution system boards and intermediate generation and transmission system boards, with the exception of Districts 9 and 10, which Basin Electric serves directly. In addition, the directors serve on the boards for subsidiaries Dakota Gas/Souris Valley Pipeline Limited, Dakota Coal Company/Montana Limestone Company, Basin Cooperative Services, PrairieWinds ND 1, Inc. and PrairieWinds SD 1, Inc.

DISTRICT 1

DISTRICT 11

East River Electric Power Co­operative KERMIT PEARSON Madison, SD

Basin Electric director since 1997 and electric cooperative board member since 1981 B.S. in animal science and agricultural education, South Dakota State University Vice President

Farmer/rancher

Serves on Dakota Gas and PrairieWinds boards

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

DISTRICT 7

Rushmore Electric Power Cooperative MIKE MCQUISTION Rapid City, SD

Corn Belt Power Cooperative CHARLES GILBERT Humbolt, IA

10 11 12 13 14 15 16 17 18 19 20 21 22 23

H-D Electric Co­opera­tive Kingsbury Electric Co­opera­tive Lake Region Electric Association Lyon-Lincoln Electric Co­opera­tive Meeker Co­opera­tive Light & Power Association Northern Electric Co­opera­tive Oahe Electric Co­opera­tive Redwood Electric Co­opera­tive Renville-Sibley Co­opera­tive Power Association Sioux Valley Energy South Central Electric Association Southeastern Electric Co­opera­tive Traverse Electric Co­opera­tive Union County Electric Co­opera­tive Whetstone Valley Electric Co­opera­tive

Basin Electric director since 2009 and electric cooperative director since 1997 B.S. in agricultural business, Iowa State University Retired farmer

Serves on PrairieWinds boards and as vice chairman on Dakota Gas board

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

DISTRICT 4

Northwest Iowa Power Cooperative DON APPLEGATE Le Mars, IA

DISTRICT 2

L & O Power Cooperative GARY DROST Rock Rapids, IA

Basin Electric director since 2013 and electric cooperative board member since 1996

Basin Electric director since 1997 and electric cooperative board member since 1966

Basin Electric director since 1999 and electric cooperative board member since 1987

Rancher

Past director, National Rural Utilities Cooperative Finance Corporation

Retired U.S. Navy Reserve and lineman electrician certification

Farmer Secretary/Treasurer Serves on PrairieWinds boards and as treasurer on Dakota Coal/Montana Limestone boards

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

Serves on PrairieWinds boards and as chairman of Dakota Gas board

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

Farmer

Serves on Dakota Gas board and PrairieWinds boards

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

2015 ANNUAL REPORT 9

DAKOTA GAS DIRECTORS JIM GERINGER

ALAN KLEIN

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 19771979; 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

THOMAS OWENS 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 *Owens retired from the Dakota Gas board in December 2015.

COOPERATIVE MANAGEMENT MEMBERSHIP BOARD OF DIRECTORS PAUL SUKUT 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 General Manager

RESOLUTIONS COMMITTEE Director District 1 Les Mehlhaff District 2 David Meschke District 3 Troy Presser District 4 Louis C. Reed District 5 Jack Finnerty District 6 Melanie Roe District 7 Richard Schneider District 8 David Sigloh District 9 Dean Hummel District 10 Philip Habeck District 11 Donald Feldman Board Rep. Paul Baker 10 BASIN ELECTRIC POWER COOPERATIVE

BYLAW REVIEW COMMITTEE Director James Ryken Aryln Zylstra Mark Brehm Louis C. Reed Rick Gordon Patti Murphy Dick Schneider David Sigloh Tim Velde & Timothy Young Reuben Ritthaler Donald Feldman

General Manager District 1 Thomas Boyko District 2 Curt Dieren District 3 Tom Meland District 4 Kent Pauling District 5 Mike McInnes District 6 Doug Hardy District 7 Vic Simmons District 8 Claire Vigesaa District 9 Reed Metzger District 10 Mike Easley District 11 Ken Kuyper

SENIOR MANAGEMENT DAVE SAUER

MATT GREEK Senior vice president and COO of Dakota Gas; employed with Basin Electric since 1989; former plant manager of the Great Plains Synfuels Plant; B.S. in mechanical engineering, North Dakota State University

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

MARK FOSS

DIANE PAUL

Senior vice president of Communications & Administration; employed with Basin Electric since 2002; 22 years experience in government relations and communications; B.A. in history; M.P.A., University of North Dakota

JOHN JACOBS Senior vice president and General Counsel; employed with Basin Electric since 1978; B.A. English, University of North Dakota; J.D. University of North Dakota School of Law

Senior vice president of Human Resources; employed with Basin Electric since 1979; extensive experience in Human Resources; B.S. business administration, University of Mary

Senior vice president of Operations; employed with Basin Electric since 1979; served as plant manager at Antelope Valley Station 1999-2014; B.S. in civil engineering, North Dakota State University

STEVE JOHNSON Senior vice president of Financial Services and CFO; employed with Basin Electric and the utility industry since 1982; B.S. in accounting and business administration: M.S. in management, University of Mary; Certified Public Accountant; Chartered Global Management Accountant

MIKE RISAN

ROBERT BARTOSH Senior vice president and COO of Dakota Coal Company and Montana Limestone Company; employed with Basin Electric since 1988; B.S. in civil engineering, Michigan Technological University; graduate work, Southern Illinois University; registered Professional Engineer

VICE PRESIDENTS Vice president of Cooperative Planning Dave Raatz

*Bartosh retires May 6, 2016, and Dakota Coal Company responsibilities will move to the Operations Department.

KEN RUTTER 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

Mark Kinzler

Vice president and Chief Information Officer

Shawn Deisz

Vice president and Controller

Jon Klein

Vice president of Procurement

Bryan Keller

Vice president of Transmission System Maintenance

Susan Sorensen

Vice president and Treasurer

Steven Liebelt

Vice president of Marketing and Sales, Dakota Gas

Senior vice president of Marketing & Asset Management; employed with Basin Electric since 2012; 13 years experience in energy trading and risk management; B.S. mechanical engineering, Purdue University, M.B.A., Washington University

2015 ANNUAL REPORT 11

Three very large pieces of equipment arrived at their final destination as part of the urea facility construction project at Dakota Gas’ Great Plains Synfuels Plant. The high pressure scrubber, high pressure stripper and pool reactor arrived at the Synfuels Plant site via rail after traveling thousands of miles from Austria.

12 BASIN ELECTRIC POWER COOPERATIVE

OPERATIONAL EXCELLENCE 2015 ANNUAL REPORT 13

OPERATIONAL EXCELLENCE

O

perational excellence is about more than Basin Electric’s physical assets. It’s the cooperative’s employees, its focus on safety and a commitment to low-cost, reliable electricity. It’s about ensuring Basin Electric’s generation and transmission resources are operated and maintained to ensure the members receive the highest quality service.

It requires fuel supply, reliable transportation, emissions controls, well-planned and executed maintenance activities, equipment updates, full environmental and regulatory compliance, effective and consistent employee training and a strong understanding of energy market participation.

The cooperative’s current generation fleet consists of four baseload coal-fired power plants, one intermediate natural gas combined-cycle plant, several peaking power plants that run on natural gas and oil and wind generation.

Since 2005, Basin Electric’s wind generation portfolio has grown by more than 800 megawatts complemented by as much natural gas peaking generation. Each of these resources comes with different challenges with regard to operation and maintenance.

In 2000, Basin Electric’s capacity portfolio was 85 percent coal. Today, though the Dry Fork Station was added in 2011 as well as the resources of Class A member, Corn Belt Power, the percentage of the cooperative’s coal resources is just over half its total resource capacity.

In the past, operations employees With its generation asset mix would have the opportunity and time to expanding, Basin Electric must continue train in a job for years before moving into the next job classification. In some to adapt, train and develop the best cases, those years have turned into workforce possible. The focus over months, making valuable and appropriate the last year has been in providtraining essential. It not only ensures our ing opportunities for employees to employees can perform their jobs, but broaden their skills. Training that perform them while keeping safety as priority number engages employees and helps them one. We’re continually improving. feel empowered in their jobs means JOHN JACOBS, employees won’t just come to work to senior vice president of Operations do a job, they’ll come to work with a deeper connection to the cooperative and its members, and a desire to find greater efficiencies and ways to improve operations.

Employees are the cooperative’s greatest resource.

Basin Electric seeks to provide the most effective training and resources possible to ensure employees can perform at their highest potential.

14 BASIN ELECTRIC POWER COOPERATIVE

In April, the Lignite Energy Council honored the Leland Olds Station with the Safety Excellence Award for achieving a zero-accident rate, tied for the lowest overall accident rate in the lignite industry in 2014. In recognition of their safety achievements, the North Dakota Safety Council (NDSC) awarded employees at Lonesome Creek Station, Pioneer Generation Station, PrairieWinds ND and Headquarters with an award for exemplary safety performance. The NDSC also honored the Freedom Mine the Mine Safety Merit Award. The award is given to companies showing an incidence rate equal to or less than the national average for their mine type.

GENERATION Like its employees, each of Basin Electric’s generation facilities is unique with different requirements for operation, which, in this world of one-size-fits-all regulation, can challenge their efficiencies.

The legacy units have been in operation for 30 to 50 years and they continue to operate reliably and at a very low cost. Fuel for the North Dakota units is supplied from The Coteau Properties Company Freedom Mine by Basin Electric’s subsidiary Dakota Coal Company. The baseload coal units in North Dakota and Wyoming also use lime and limestone from Dakota Coal’s division, Wyoming Lime Producers, and its subsidiary Montana Limestone Company.

Whether it’s lignite coal for Leland Olds Station, Antelope Valley Station or Dakota Gas, or lime and limestone for wet and dry scrubbers at the facilities, Dakota Coal provides and ensures Basin Electric’s baseload facilities have the necessary quantity and quality of fuel and products to be among the cleanest, most economical and reliable energy producers in the nation.

It was another successful year with regard to safety.

In September, Wyoming Lime Producers achieved six years without a lost-time accident. The same month,

Montana Limestone’s quarry marked one year without a lost-time accident, and in November, the Freedom Mine marked two years without a lost-time accident.

In December, Montana Limestone’s fine grind plant/rail load out achieved 12 years without a lost-time accident.

The Wyoming Lime Producers’ Frannie Lime Plant, a limestone processing facility The Dry Fork Mine, which provides near Frannie, WY, not only excels coal to the Dry Fork Station, Laramie in safety, but also production.

River Station and Leland Olds Station, The plant converts limestone achieved milestones in 2015. For five to high-quality lime through a years running, coal from the Dry Fork heat transfer process called Mine supplied to the Dry Fork Station calcination. The cooled lime is was the lowest cost coal in the country. then crushed to meet customer The second milestone achieved at Dry handling requirements and loaded Fork Mine happened in April when the onto railcars or trucks for delivery 100 millionth ton of coal was shipped. to Basin Electric’s coal-based Coincidentally, that ton was delivered energy facilities for use in stack to Leland Olds Station. emission scrubbers and water treatment facilities. Lime also has other regional industrial and environmental uses.

In addition to its safety achievement, Wyoming Lime Producers broke an all-time lime production record through

2015 ANNUAL REPORT 15

OPERATIONAL EXCELLENCE

The capability to crush or grind and separate different sizes of limestone opens up additional market opportunities. For example, crushed limestone goes to customers like Leland Olds Station for the scrubber, but new customers that use limestone to seal asphalt need a finer grind, and certain sizes of limestone are sold as chicken grit and other animal feed applications. The finest size of limestone goes to the rock dust market, to be used in underground coal mines to minimize the risk of coal dust explosions. The limestone rock dust is mixed with water to make a slurry, and then sprayed on the underground mine walls.

2014 by safely producing 157,289 tons of lime during the year. The record of 150,832 tons was previously set in 2008.

At Montana Limestone’s fine grind plant, a new pin mill was completed this year and commissioned in mid-September.

The new pin mill was needed because the customer base shifted and fine limestone is in higher demand. The pin mill balances the plant’s output and thus its efficiency. Also, a new transformer was installed In May, Western Fuels Association and Basin to meet the electrical load Electric, as the operating agent for the six parrequirements of the pin ticipants of the Missouri Basin Power Project, mill system. reached a settlement with BNSF Railway on a rate Because of the high case dating back to 2004. The legal dispute with demand for product at BNSF involved coal shipping rates for the LaraBasin Electric’s facilities mie River Station located near Wheatland, WY. and other customers, The details of the settlement agreement are product transportation is confidential, but the parties are satisfied with more important than ever. the outcome. The settlement marks the end of Though the limethe dispute and assures a continued partnership stone, lime and coal between all parties. operations have had challenges in the past with transportation, BNSF Railway has worked with the cooperative over the last year to ensure consistency in product deliveries. As a result, Basin Electric’s facilities were able to maintain appropriate inventories. Also, going

16 BASIN ELECTRIC POWER COOPERATIVE

into winter, BNSF offered enhanced service. Instead of running two crews, they ran three crews for a few months at no additional charge.

In addition to improvements in rail deliveries, improvements were made at the Freedom Mine. The mine’s first dragline, Sakakawea, which has been running since 1983, had its boom and mast retired, and a new boom and mast lifted into place.

Beginning in April, crews worked to assemble the new boom and mast on a site developed for that purpose. On Sept. 15, the boom was lifted and pinned on the dragline.

It was back in operation by the end of the month.

The mine continues reclamation activities and staff have been reviewing the Stream Protection Rule proposed by the Office of Surface Mining Reclamation and Enforcement. It requires surface and underground coal mining companies to establish pre-mining surface and groundwater conditions, then return the land to those conditions post-mining.

Several of Basin Electric’s baseload facilities operated at or above 100 percent of budgeted generation. That level of reliability doesn’t happen by accident. The cooperative’s triennial maintenance outage schedule ensures its facilities are provided the care and attention needed so they can run safely and efficiently.

In addition, Basin Electric consistently maintains full environmental compliance. As the chart shows, more of the cooperative’s operations budget is spent meeting, and in most cases exceeding, environmental compliance standards.

Work was completed in the spring for new mercury emissions removal equipment at Leland Olds, Antelope Valley and Laramie River. The equipment is used to comply with the EPA’s Mercury & Air Toxics Standard (MATS) rule, which required coal-based power plants to capture and remove determined levels of mercury emissions from flue gas. They are using amended silicates and activated carbon to remove mercury. These materials are injected into the flue gas after it leaves the boiler and before it enters the scrubber. The use of amended silicates does not raise the fire risk in the baghouse as too much activated carbon does.

In June, the U.S. Supreme Court ruled in a 5-4 decision that the EPA did not properly consider compliance costs in crafting the MATS rule and remanded it back to the D.C. Circuit Court of Appeals to assess how the agency could fix the regulations. The D.C. Circuit issued a ruling in December that allows EPA to enforce the rule as it fixes the flaws in the regulatory program identified by a Supreme Court ruling.

At Dry Fork Station, there was no need to install the mercury control equipment because it was installed as part of the original construction plan. Dry Fork has been

Basin Electric and Dakota Coal Company fared better than most of the other utilities in the country. We had a good year.

The BNSF really stepped up for us. First of all, our inventory levels at Leland Olds Station, which was a major concern for us, have been brought up to levels they are supposed to be with help from BNSF and they’ve stayed there. Secondly, our limestone campaign from Warren, Montana, to Leland Olds Station finished well ahead of schedule, as did our PRB, the Dry Fork coal to Leland Olds Station. That also finished well ahead of schedule, so it was a great year.

JOE LEINGANG,

director of fuel and transportation, Dakota Coal

in compliance with the strict standards for about a year.

Leland Olds has been in compliance since April and Laramie River and Antelope Valley since June.

Another EPA rule which impacts the Leland Olds Station is the Coal Combustion Residual rule finalized in April. Due to the age, construction and proximity of its ash pond to the Missouri River, Leland Olds closed the pond in mid-October to comply with this rule. An engineering

POLLUTION CONTROL COSTS

2015 Operations & Maintenance,

Capital Cost Depreciation Facility (dollars in thousands) Life-to-Date

& Interest Antelope Valley Station $ 369,340.8 $ 31,044.8 Culbertson Generation Station 4,818.9 309.4 Deer Creek Station 28,584.8 2,145.4 Dry Fork Station 318,621.5 30,901.7 Groton Generation Station 4,543.0 358.1 Laramie River Station (Basin Electric only) 13,773.9 921.7 Leland Olds Station 440,999.3 41,911.1 Lonesome Creek Station 197,403.3 13,456.8 Pioneer Generation Station 13,377.1 905.2 Spirit Mound Station 99.8 0.6 Subtotal: Basin Electric 1,391,562.4 121,954.8 Dakota Coal/Montana Limestone Company 26,942.0 2,839.5 Dakota Gasification Company 199,078.7 56,517.3 Subtotal: Subsidiaries

226,020.7 59,356.8 Total: Basin Electric & subsidiaries $ 1,617,583.1 $ 181,311.6 Dry Fork Station, Deer Creek Station, Pioneer Generation Station and Lonesome Creek Station amounts are estimated; finalized amounts will be available after the capital costs have been unitized.

2015 ANNUAL REPORT 17

OPERATIONAL EXCELLENCE

ELECTRIC OPERATING HIGHLIGHTS Energy Sales (in millions of megawatt hours) To Class A and Class D members To others Total Coal Consumed (in millions of tons) Wyoming sub-bituminous North Dakota lignite Total Forced-outage rate (five-year average)

firm familiar with large scale dewatering designed a temporary system. The same firm is working on preliminary designs and estimates for a permanent system as well as requirements for the pond closure.

These activities are expected to take place over the next two years.

As Basin Electric works to comply with federal regulations, one EPA rule stood out in 2015 targeting coal-based generation facilities. The Clean Power Plan is the final rule of Section 111(d) of the Clean Air Act with greenhouse gas emission reduction requirements for

SAFETY

Z

E

R O

18 BASIN ELECTRIC POWER COOPERATIVE

S E N T

I N

2015 2014 % change 8.5 8.2 3.7 8.5 7.9 7.6 17.0 16.1 5.6 4.0% 3.3% 21.2

existing coal-based facilities. The rule challenges the reliability and affordability of Basin Electric’s baseload generation fleet. (See page 28 to read more.)

Basin Electric’s generation fleet will always be the workhorses of the cooperative, but none of it would be possible without a workforce committed to safety. In 2014, the Our Power, My Safety initiative began rolling out at all of Basin Electric’s facilities. Safety is one of the cooperative’s core values. Our Power, My Safety is a process of safety improvement over time with employees in all areas of the cooperative as the drivers.

OUR POWER, MY SAFETY

I D

OUR POWE

MY R,

2015 2014 % change 22.7 22.1 2.7 6.9 6.2 11.3 29.6 28.3 4.6

C

Basin Electric has continued to work on the Our Power, My Safety process. Continuous improvement team #1 fully implemented the first initiative at all facilities and continuous improvement team #2 continues their implementation process. In 2015, the cooperative celebrated the one-year mark since launching the culture-changing process. From veteran employees to new employees, the Our Power, My Safety process is bringing out the best in the cooperative’s workforce.

DAKOTA GASIFICATION COMPANY OPERATING HIGHLIGHTS Revenue (in millions) 2015 2014 % change Synthetic gas sales $ 187.6 $ 276.9 (32.2) Byproduct, coproduct and other sales 274.2 305.9 (10.4) Interest and other income

6.2 4.3 44.2 Total $ 468.0 $ 587.1 (20.3) Synthetic gas sold (dekatherms in millions) Coal consumed (tons in millions)

56.4 6.1

56.7 5.9

(0.5) 3.4

DAKOTA COAL COMPANY OPERATING HIGHLIGHTS Revenue (in millions) 2015 2014 % change Coal sales $ 218.0 $ 214.7 1.5 Lime sales 14.3 13.9 2.9 Limestone sales 5.9 5.8 1.7 Interest and other

3.9

5.7 (31.6) Total $ 242.1 $ 240.1 0.8 Sales (in tons) 2015 2014 Coal (in millions) 14.4 14.3 Lime (in thousands) 155.0 160.3

% change 0.7 (3.3)

2015 ANNUAL REPORT 19

OPERATIONAL EXCELLENCE

OWNED OR OPERATED POWER RESOURCES ANTELOPE VALLEY STATION Location: Beulah, ND Capacity: 900 MW Fuel: Coal Purpose: Baseload Units: 2

DRY FORK STATION

Location: Stanton, ND Capacity: 666 MW Fuel: Coal Purpose: Baseload Units: 2

LARAMIE RIVER STATION

Location: Gillette, WY Capacity: 386 MW Fuel: Coal Purpose: Baseload Unit: 1

Location: Wheatland, WY Capacity: 1,710 MW Fuel: Coal Purpose: Baseload Units: 3

Basin Electric has a 92.9 -percent ownership share.

Basin Electric has a 42.27 -percent ownership share.

DEER CREEK STATION

CULBERTSON GENERATION STATION

Location: Elkton, SD Capacity: 300 MW Fuel: Natural Gas Purpose: Intermediate Unit: 1

Location: Culbertson, MT Capacity: 95 MW Fuel: Natural Gas Purpose: Peaking Unit: 1

EARL F. WISDOM STATION UNIT 2

GROTON GENERATION STATION

Location: Spencer, IA Capacity: 80 MW Fuel: Natural Gas/Oil Purpose: Peaking Unit: 1 Basin Electric has a 50-percent ownership share. It’s operated

by Corn Belt Power Cooperative.

20 BASIN ELECTRIC POWER COOPERATIVE

LELAND OLDS STATION

Location: Groton, SD Capacity: 196 MW Fuel: Natural Gas Purpose: Peaking Units: 2

LONESOME CREEK STATION

WIND GENERATION

Location: Watford City, ND Capacity: 135 MW Fuel: Natural Gas Purpose: Peaking Units: 3

PIONEER GENERATION STATION Location: Williston, ND Capacity: 135 MW Fuel: Natural Gas Purpose: Peaking Units: 3

SPIRIT MOUND STATION Location: Vermillion, SD Capacity: 120 MW Fuel: Oil Purpose: Peaking Units: 2

Location: Chamberlain, SD Nameplate: 2.6 MW Fuel: Wind Purpose: Renewable Turbines: 2

Location: Minot, ND Nameplate: 122.6 MW Fuel: Wind Purpose: Renewable Turbines: 82

Location: White Lake, SD Nameplate: 162 MW Fuel: Wind Purpose: Renewable Turbines: 108

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

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

COMMITTED PROJECTS LONESOME CREEK STATION PHASE III Location: Watford City, ND Capacity: 90 MW Fuel: Natural Gas Purpose: Peaking Units: 2 2016 expected completion.

WYOMING DISTRIBUTED GENERATION Locations: Hartzog, Arvada

and Barber

Creek, WY Capacity: 54 MW Fuel: Natural Gas Purpose: Peaking Units: 9

PIONEER GENERATION STATION PHASE III Location: Williston, ND Capacity: 112 MW Fuel: Natural Gas Purpose: Peaking Units: 12 2016 expected completion.

2015 ANNUAL REPORT 21

OPERATIONAL EXCELLENCE

Basin Electric line crews take live line training, in which the line workers do self-rescues and conductor cart rescues on live 345-kV transmission lines.

Linemen also practice the rescue of an incapacitated co-worker, as well as hot stick procedures on different types of steel towers.

TRANSMISSION Whether serving as the boots on the ground working to keep the lines safe and secure, or on the planning team, members of the Transmission Department are vitally important in getting safe, secure and reliable electricity to members.

The planning team helps identify what is needed, where and by when. They are actively engaged in studies and developing a strategy to meet the power delivery needs of the membership.

Basin Electric is in a unique situation. It’s one of the few generation and transmission co-ops experiencing growth. Current generation and transmission projects are being built to serve all 2.9 million member-consumers.

Basin Electric has been enhancing the transmission system in North Dakota to meet members’ needs. The two

transmission projects under construction include the Antelope Valley Station to Neset 345-kilovolt (kV) project and the North Killdeer Loop project. (Read more about these projects in Supporting Growth & Innovation.) Despite the decrease in oil prices and slowdown in oil activity, planning studies show the transmission projects are needed.

The year included intense work in regard to system regulation.

The North American Electrical Reliability Corporation (NERC) sets and enforces standards that address the reliable operation of the electric grid on two fronts: operations and planning, and cyber and physical security.

Basin Electric has assets in two NERC regions: WECC, which is the Western Electricity Coordinating Council for its western system operations, and MRO, which is the Midwest

The Distributed Generation division grew another with the addition of two combustion turbines at the Lonesome Creek Station.

90 MW

22 BASIN ELECTRIC POWER COOPERATIVE

In North Dakota and South Dakota, 62 microwave sites have been upgraded with new microwave radios and associated equipment. The upgrade provides the additional bandwidth required by new generating and transmission system facilities. Transmission System Maintenance (TSM) line crews and mechanic-operators relocated the two Leland Olds Station 345-kilovolt (kV) tie lines into new line terminals at the Antelope Valley Station 345-kV switchyard in support of new construction.

The crews completed line modifications to connect the new Dry Creek Substation to the New Underwood 230-kV line at the Rapid City DC Tie. Crews also installed new transmission line structures near Williston and Dawson, ND, which were required by highway construction projects.

TSM’s substation crews installed and commissioned new equipment related to the additions at Antelope Valley and Charlie Creek 345-kV substations for the two new 345-kV transmission lines. During the Laramie River Station Unit #1 maintenance outage, TSM engineers and substation crews upgraded the protective relays, communications and control systems for the three east side MBPP 345-kV transmission lines.

Reliability Organization for its eastern system operations.

Throughout the year, staff prepared for NERC compliance audits, which are conducted every six years. Because Basin Electric has assets in both the WECC and MRO, the cooperative has two audits. Preliminary audit results indicated Basin Electric did not have any issues with the critical infrastructure protection standards, commonly called CIP standards. Several potential violations were identified on the operations and planning side.

Basin Electric compliance staff and west-side member cooperatives will be working together with WECC enforcement

staff to complete a mitigation plan to resolve the identified issues. This process typically takes one to two years to complete.

The other significant aspect about NERC standards is the implementation of a physical security standard and version 5 of the CIP standards, which goes into effect July 1, 2016. This new version of CIP standards is very significant to Basin Electric. Under the version 5 CIP standards, Basin Electric will transition from not having any critical cyber assets to having a moderate level of critical cyber assets. This is a big transition that requires a tremendous amount of cross-cooperative coordination.

TRANSMISSION

System Joint Ownership Southwest Power Pool Common Use

Missouri Basin Power Project

Other

Total Circuit Miles

Southwest Power Pool Members Basin Electric, Black Hills Power, Powder River Energy Corporation 910 Basin Electric, Tri-State G&T, Wyoming Municipal Power Agency, Missouri River Energy Services, Heartland, Lincoln Electric System 681

Total Basin Electric Miles

Basin Basin Electric Electric Owned Maintained

Basin Electric Planned

1,575

1,618

263

279

346

0

288 43

301 84

0 0

2,185

2,349

263

2015 ANNUAL REPORT 23

OPERATIONAL EXCELLENCE

Cybersecurity exercises are a great way to prepare for a crisis and to assess procedures. In November, Basin Electric participated in GridEx III, a grid exercise for incident response involving players across North America. GridEx III is meant to simulate a widespread event with rolling blackouts, and provides crisis preparation.

TRANSMISSION HIGHLIGHTS Transmission additions and substations completed in 2015

North Dakota Judson

New 230/345 kV

Charlie Creek 345 kV Additions

AVS

345 kV Additions

South Dakota

Completed in 2014

24 BASIN ELECTRIC POWER COOPERATIVE

Dry Creek

New 115/230 kV

Completed Under construction

Version 5 of the CIP standards will impact Basin Electric in many ways, right down to the employee level. Certain Basin Electric employees who have access to the Bulk Electric System, or BES, will be required to successfully complete and maintain a current background check. Aside from a background check, employees will also need to have quarterly exposure to security awareness information and annual security training, specific to each employee’s role.

Physical security is another element of the CIP standards that requires Basin Electric compliance. In response, the cooperative is enhancing security to its substations. That includes fixed cameras as well as pan, tilt and zoom cameras for tracking activity within the substations. Control buildings will also receive fixed cameras, as well as other security equipment.

The overall goal is to improve Basin Electric’s operations, planning and cybersecurity activities while promoting a strong culture of compliance.

Basin Electric’s real time desk manages and markets west side electricity operations for Basin Electric, and also Basin Electric’s exposures on the Eastern Interconnect in Midcontinent ISO (MISO) and Southwest Power Pool. Basin Electric’s short-term (18 months out) power and natural gas desks manage the market exposures for baseload generation, wind projects, gas peaking units, member and non-member loads, transmission and regional transmission organization offers and bids. The short-term desk manages the financial derivative transactions for Dakota Gas’ natural gas and tar oil exposures. Marketing includes management of the sales of Dakota Gas’ products.

MARKETING One of Basin Electric’s historical events of 2015 was the transition to membership in a regional transmission organization. Following many years of work and months of preparation, Basin Electric is a transmission-owning member in the Southwest Power Pool (SPP).

The actual “go live” took place at midnight Oct. 1, and the transition went rather smoothly.

One of the key factors through all of it was the development of strong communication between the marketing group and plant operators at all facilities. In late August and early September, the plant communication process was rolled out with the plant operators. As with all areas of the integration, training was so important.

The effectiveness of communication between the power plants and marketing determines the cooperative’s effectiveness in the market. It’s key.

While the cooperative is operating in a new arena, Basin Electric will always retain control of how it serves its loads and the operation of its assets. There are simply new rules in day-to-day activities in the integrated marketplace. The cooperative now has access to a

broad marketplace, which allows it to capture new value for members through lower purchased power costs and new ways to capture non-member sales.

In a seemingly very short amount of time, Basin Electric was able to get all its market operations under one roof. That includes co-locating Basin Electric’s and its subsidiary Dakota Gas’ commodity marketing Basin Electric has continued a long-standing functions to manage the relationship with North Iowa Municipal Electric collective obligations Cooperative Association or NIMECA. NIMECA and assets hour by serves 13 municipal electric utilities. NIMECA hour from one central has shared interests in generation resources location. In 2015, the that Basin Electric manages, which provides team took steps to efficiencies for all. better integrate the marketing functions.

The commodities the cooperative produces can experience significant price swings. These swings can lead to challenges.

2015 ANNUAL REPORT 25

OPERATIONAL EXCELLENCE

Anhydrous ammonia is one of the largest coproducts from a revenue standpoint. In the spring, about 90,000 tons of anhydrous ammonia was sold out of the plant. A normal spring yields from 60,000 to 70,000 tons during the April-May timeframe.

For many years Basin Electric was a partner in the Integrated System. As of Oct. 1, the cooperative is part of the Southwest Power Pool. The transition is a historic milestone for Basin Electric. In the past the cooperative planned its transmission system with the IS partners, the Western Area Power Administration and Heartland Consumers Power District. As a member of SPP, Basin Electric now plans the system on a broader basis as part of the SPP planning process. Of course, Basin Electric’s relationship with Western, which extends back five decades, won’t end here. It’s evolving to something new. Basin Electric is grateful for all the work Western did, and the transition to SPP couldn’t have taken place without them.

Southwest Power Pool

In a challenging atmosphere, the cooperative is finding new ways to help stabilize revenue and expenses by looking at how rail agreements and fuel surcharges are managed, how to get price certainty for ammonia sales and how to manage the pipeline capacity Dakota Gas owns to move natural gas.

There is great diversity in the cooperative family.

By collectively looking at the commodities within the whole cooperative, including subsidiaries, Basin Electric is able to manage, maximize and hedge its resources to create added value and mitigate risk.

Creating one central market location and full integration in SPP are helping Basin Electric do that.

The cooperative is now able to get power where it’s needed, when it’s needed as well as help monetize excess energy.

Achieving operational excellence is a commitment.

SPP INTEGRATION TIMELINE

July 16, 2014 – Basin Electric’s board authorizes co-op to join SPP

26 BASIN ELECTRIC POWER COOPERATIVE

Aug. 1, 2014 – SPP FERC filing

July 2014-September 2015 – Integration activities

May 2015-July 2015 – Market trials in SPP

October 1, 2015 – “Go live” in SPP

A LEGACY OF INNOVATION AND VALUE Dakota Gas’ Great Plains Synfuels Plant remains a valuable longterm asset for Basin Electric’s members. The ongoing analysis continues to show that Dakota Gas provides a yearly benefit of approximately $78 million to the membership. In addition, the operation of the plant contributes to the energy economy of the state and region.

Since Basin Electric purchased the facility in 1988, the Dakota Gas board, management and staff have diversified the plant’s commodity mix nearly fourfold.

Following is the 2015 production of each commodity and examples of their end use. In addition, the percentage of revenue attributed to each product is noted.

NATURAL GAS

1988 TOTAL

98%

nitrogen & anhydrous ammonia

2%

OTHER

22.3

37.9

million pounds

PHENOL

million dekatherms

1.9% polycarbonate products, oral analgesics,

NATURAL GAS

40.6% fuel

household cleansers, automotive parts, oriented strand board, plywood, counter tops, exterior siding, insulation

2015 TOTAL

22.6

$461.8

million pounds

CRUDE CRESYLIC ACID

2.6% wire enamel coatings, pesticides,

OTHER

0.4%

IN MILLIONS

vitamin E, antioxidants, dyes, solvents, insecticides, semi­conductors, electronic chips, alkylphenols, resins

292.9

118.3 thousand tons

thousand tons

ANHYDROUS AMMONIA

AMMONIUM SULFATE

7.1% Dak Sul 45® fertilizer

3.2

4.7 million gallons

NAPHTHA

1.3% blend stock for benzene, toluene and xylenes, gasoline additives, paint thinners, solvents

105.1

million liters

KRYPTON/ XENON GASES

0.4%

halogen headlights and light bulbs, lasers, window insulation

28.7

million gallons (salable)

TAR OIL

5.4% fuel

28.7% agricultural fertilizer

thousand gallons

LIQUID NITROGEN

0.0% coolant, refrigerant, preservative 41.4

billion standard cubic feet (salable)

CARBON DIOXIDE

11.6% enhanced oil recovery

2015 ANNUAL REPORT 27

OPERATIONAL EXCELLENCE

CLEAN POWER PLAN Final %

MT

47%

ND

(21%)

44% (19%)

45% (11%)

SD

WY

(Proposed %)

48% (35%)

40% (41%)

41% (34%)

MN

WI

Clean Power Plan, if not improved, will (26%) 44% NE (33%) have significant impacts 40% (35%) 37% 44% on electric cooperative 41% IL (21%) CO (23%) (18%) KS KY MO members.

40% TN (40%) Basin Electric, along with a number of other utilities and organizations across the country, is challenging the rule.

The driving force is the well-being of the cooperative’s members. They will ultimately pay for compliance with this rule.

Financially, Basin Electric In August 2015, the EPA released the Clean Power estimates having to spend about Plan, its final rule to address carbon dioxide (CO2) emissions $5.3 billion to comply. These billions of dollars would for existing coal-based power generation facilities. only cover adding new generation and the impacts of The rule, which seeks to reduce greenhouse gas the rule on operations of existing facilities. This does emissions by nearly a third in only 15 years, prescribes not include the expense of additional electric or gas more than three times the reductions required by the infrastructure to support new generation. proposed rule and is plagued by unintended consequences, unproven assumptions and extreme complexity. EPA’s CHALLENGE On Nov. 5, 2015, Basin Electric joined many others in filing a Motion to Stay the EPA’s Clean Power Plan with the D.C. Circuit Court of Appeals in Washington, D.C. A Stay is a request to halt implementation of the Clean Power Plan until litigation has concluded.

The D.C. Circuit Court denied the Stay on Jan. 21, 2016.

In response to the ruling, Basin Electric filed a request for an immediate Stay of the rule to the U.S. Supreme Court on Jan. 26, 2016.

On Feb. 9, 2016, the U.S. Supreme Court granted the Stay by a vote of 5-4. The Stay halts implementation of the rule until litigation is concluded and postpones all compliance dates.

On Feb. 9, 2016, the U.S. Supreme Court granted Basin Electric’s Motion to Oral arguments on the rule’s legality are set for Stay the Clean Power Plan by a vote of 5-4. The Stay halts implementation June 2, 2016, in front of the D.C. Circuit Court of Appeals, of the rule until litigation is concluded and postpones all compliance dates. with the final decision likely to be made by the U.S. Supreme Court.

28 BASIN ELECTRIC POWER COOPERATIVE

40%

42% (16%)

IA

SUPPORTING MEMBER GROWTH 2015 ANNUAL REPORT 29

SUPPORTING MEMBER GROWTH

M

any forces joined together to enable Basin Electric and its membership to continue to grow and evolve in the face of regulatory and power supply challenges.

In January 2015, Basin Electric’s system hit a new all-time member billing peak of 3,598 megawatts, 40 megawatts higher than the previous year’s member billing peak, which occurred in January 2014. There wasn’t a prolonged cold spell throughout the entire membership area, so the year-over-year load growth does not seem as significant as the growth from years previously. Over the last five years, Basin Electric’s member billing peak increased by about 900 megawatts. The fact that Basin Electric’s system continues to peak year after year shows that growth continues throughout the membership.

In February, Basin Electric’s board of directors approved the cooperative’s 2015 load forecast, which showed that even with lower oil prices, growth is expected to continue.

The updated forecast predicted member requirements to increase by approximately 875 megawatts over the next five years and between 2,220 megawatts and 2,700 megawatts over the forecast period of 2015-2035. The load forecast is a significant input into Basin Electric’s planning processes for power supply, transmission, financial forecasting and rates.

CONSTRUCTION

Basin Electric is building a high-voltage transmission line, approximately 200 miles long, to run from Antelope Valley Station near Beulah, ND, connect to substations along the way, and end at the Neset 345-kV substation near Tioga, ND. An addition to the project, the North Killdeer Loop, adds another 60 miles of line and three substations.

30 BASIN ELECTRIC POWER COOPERATIVE

To meet this expected membership load growth, Basin Electric purchased power from the market and the cooperative is expanding its generation fleet.

Construction continues on Phase III of Pioneer Generation Station and Lonesome One new technology Creek Station, two natural gas peaking that Basin Electric is supporting plants in northwestern North Dakota. research and development of is Phase III of the Pioneer Generation Station the Allam Cycle. The Allam Cycle project will consist of 112 megawatts (MW) is a new thermodynamic cycle to produce electricity and it uses of additional peaking capacity provided by CO2 as a working fluid rather 12 natural gas-based reciprocating engines. than water, which is used in our Two steel stacks were constructed on the coal-fired power plants. It has an advantage site and the reciprocating engines were of being more efficient and also capturing moved into place. Commercial operation CO2, but to develop another technology is targeted for the fall of 2016. doesn’t come without challenges that we are working through to provide a pathway for At Lonesome Creek Station, the Unit utilizing our coal in the future.

4 stack and part of the selective catalytic reduction system, was put in place in JIM SHELDON, September. Commercial operation of units senior research and development engineer 4 & 5 at Lonesome Creek Station are also

The high pressure scrubber, high pressure stripper and pool reactor were lifted from railcars and set at the urea plant construction site. One vessel was lifted each day from Dec. 6 through Dec. 8. The equipment was initially loaded onto a barge on the Danube River in October and traveled to the Port of Antwerp, Belgium. From Belgium, the equipment was sent to the Port of Houston, TX, where it was loaded onto railcars.

targeted for the fall of 2016. A third unit, Unit 6, has been permitted for future installation.

On the transmission side, construction continues to move forward with the Antelope Valley Station to Neset project. This new 345-kV transmission line in North Dakota will be approximately 200 miles in length.

It’s on track to be completed by the end of 2017. The project reached a few milestones during the year. The section of line from Antelope Valley to Charlie Creek was energized in early fall, and the line from Charlie Creek to Judson was energized late in the year. The Antelope Valley Station and Charlie Creek substations are scheduled for final completion

by May 2016, at which time the full reliability benefits of the Antelope Valley Station to Judson project will be realized.

As the Antelope Valley to Judson section was being completed, construction started on Phase I of the North Killdeer Loop project. This project, which includes 60 miles of 345-kV transmission line and three substations, is being pursued due to load growth projected in North Dakota’s McKenzie County in the 2016 timeframe and beyond.

Phase I of the North Killdeer Loop project is scheduled to be completed by the end of 2016. Phase II of the North Killdeer Loop project and the Judson to Neset section of the Antelope Valley Station to Neset project are scheduled for completion by the end of 2017.

At Dakota Gas’ Great Plains Synfuels Plant, construction on the urea production facility continues on schedule for commercial operation in the second quarter of 2017.

Most of the equipment needed to complete the facility has also arrived at the plant. The core process equipment consisting of a separation vessel, scrubber and pool reactor arrived at the plant from Austria in late November.

When complete, 1,100 tons of urea will be produced daily, with the ability to shift urea production to produce diesel exhaust fluid and sell liquefied CO2.

In the fall, Dry Fork Station was chosen Workforce numbers are projected as the site for an Integrated Test Center to increase and peak at 750 workers project competition. Companies who in 2016. choose to participate and are selected At Laramie River Station, staff by the Test Center committee will have is working on a project needed an opportunity to develop their techto meet the EPA’s Regional Haze nology at Dry Fork Station and use flue requirements. gas to create carbon products. The X In early 2014, the EPA issued Prize Foundation is also participating. a partial federal implementation The competitor with the highest value plan on Wyoming’s state plan that product will win the cash prize. requires Laramie River Station to install Selective Catalytic Reduction (SCR) nitrogen oxides (NOx) controls on all three units by March 2019. These SCRs are in addition to the low-NOx burners and over-fire air required by Wyoming’s state plan.

2015 ANNUAL REPORT 31

SUPPORTING MEMBER GROWTH

The federal plan MONTANA River Electric is headquartered would cost Basin Electric in Ashland, MT. Basin Electric approximately $363 power deliveries under all Fergus million and the Missouri three contracts will begin Basin Power Project more in October 2017. than $750 million collectively The addition of these Mid Yellowstone Tongue to bring Laramie River Station three Montana member River into compliance. In September cooperatives will increase th 2014, the 10 Circuit Court of the Basin Electric power Appeals granted a Motion to Stay the supply obligation by slightly more than 52 MW. ruling, effectively granting Basin Electric’s and PacifiCorp’s During the year, the 2016 Class A member rate request that the compliance deadline for EPA’s federal structure was modified to include a demand and energy implementation plan be extended for the duration of the stay. contract extension credit associated with a depreciable life extension of the cooperative’s power plants, made possible PLANNING by extension of the member wholesale power contracts In the face of regulatory challenges such as these, through 2075. This contract extension credit amounts to a Basin Electric continues looking for ways to work better discount of $37.4 million in 2016 and equates to roughly a and collaborate with both members and non-members.

1.5-mill discount to the member rate.

Basin Electric accepted Basin Electric and its membership are reviewing the rate membership for three structure, load management operations, and an expansion of its cooperatives in Montana. support of solar generation development in the memberships’ Basin Electric Class A service territories over the next nine months, with the ultimate member Upper Missouri goal of supporting membership growth.

In July, Basin Electric directors passed a resPower Cooperative has With growth comes continued commitment and service olution to authorize further due diligence accepted Mid-Yellowstone to the membership. Basin Electric offers 24-hour dispatch regarding the possible addition of another Electric Cooperative’s formal services for 70 distribution cooperatives and their residential Class A member to the Basin Electric family. request for member-ship. and commercial customers across the Midwest. The cooperThat potential new member is Minnkota Power Mid-Yellowstone is headative also offers a wide range of alarm monitoring services.

Cooperative, a generation and transmission quartered in Hysham, MT. As Basin Electric develops plans to meet members’ cooperative headquartered in Grand Forks, Fergus Electric Coopenergy needs, all options to help keep member rates low ND. Minnkota’s total projected load in 2017 erative and Tongue River are considered. A new load forecast developed in early is 876 MW of peak demand. There is no timeElectric Cooperative also 2016 led to another request for proposal, or RFP, for power. frame associated with the board resolution. took action to become Basin Electric is also evaluating if it is economical to build Class C members of Class A additional generation. member Powder River Energy Corporation in Wyoming. Fergus Based upon previous power supply planning analysis, Electric is headquartered in Lewistown, MT, and Tongue the cooperative secured resources or developed strategies

Basin Electric is considering participating in the joint development of a large combined cycle facility of about 900 MW. The cooperative is looking at about 300 MW of combined cycle generation in the MISO system to serve its MISO obligations. With the economies of scale, participating in joint ownership of a larger facility is much more economical for the cooperative.

32 BASIN ELECTRIC POWER COOPERATIVE

to meet the forecasted membership load growth into the year 2020 in Montana, through 2022 in MISO and into 2024 in SPP. There is no current need for additional generation in the Colorado/Wyoming area well into the future.

Options being considered to address member growth are the construction of Montana peaking generation, possibly by 2020, and a combined cycle power plant within SPP by 2024. Basin Electric is also evaluating a joint-ownership structure for a potential combined cycle power plant in the MISO system. Next steps for the project include finalization of definitive agreements related to the arrangement and potential full commitment to the project’s development in 2016.

Membership in SPP enables Basin Electric to do business with more entities as the cooperative looks to either build new generation or execute power purchase agreements or PPAs. PPAs are another tool to help keep rates low. There are times Basin Electric can enter into short-term PPAs at a cost less than construction of new generation facilities such as a combined cycle or peaking plant, and buy time to monitor load growth and market conditions before building generation resources. In May, directors authorized staff to execute PPAs of up to an additional 425 MW. The agreements are strategically placed across SPP, Montana and MISO. Basin Electric continues the development of new renewable generation sources. The cooperative’s renewable generating portfolio, which includes waste heat, will total more than 1,400 MW by the end of 2016.

Uncertain oil and gas prices and the Clean Power Plan make it impossible to accurately predict the future. But with the help of external consultants, collaboration with the membership and continued hard work and innovative thinking, Basin Electric continues to strive to keep rates as low as possible.

Gov. Matt Mead, Wyoming, Mike Easley, CEO of Powder River Energy and chairman of the Wyoming Infrastructure Authority, and Paul Sukut, CEO and general manager of Basin Electric, announced Dry Fork Station as the site for the Integrated Test Center on Oct. 8.

SUPPORT Basin Electric’s subsidiary, Dakota Gas, plays a key role in that process. The unique Great Plains Synfuels Plant with its diverse commodity structure and endless opportunity for innovation has long been a significant financial support for the cooperative.

When Basin Electric purchased Dakota Gas in 1988, only two percent of the revenue was from products other than natural gas. (See page 27.) By 2017, approximately 75 percent of Dakota Gas’ revenue is projected to be from additional products. Product diversification to increase sources of revenue is key in securing the Synfuels Plant’s operation into the future.

Dakota Gas, with Basin Electric’s support, expanded to nine additional products today, with three new products – urea, diesel exhaust fluid and liquefied carbon dioxide (CO2) set to be ready for sale by spring 2017.

Innovation provided the unique scrubbing system that uses ammonia as a reagent to capture sulfur dioxide and produce the ammonium sulfate granular fertilizer Dak Sul 45® sold to the agricultural community.

BASIN ELECTRIC ENTERED INTO

750 MW

ECONOMICALLY PRICED PURCHASED POWER AGREEMENTS.

2015 ANNUAL REPORT 33

SUPPORTING MEMBER GROWTH

Another innovative project is the CO2 project. More than 30 million tons of CO2 has been captured and transported to the Canadian oil fields for enhanced oil recovery.

Innovation isn’t simply adding products, but also increasing efficiency and availability of the plant. The clean cooling water project has lengthened the duration between maintenance outages to two years. This year, for the first time in its 31 years of operation, the Synfuels Plant was able to eliminate a maintenance turnaround and avoid associated maintenance costs and production downtime.

Another area staff is working to improve efficiencies is in the ammonia plant. A study OUR VISION Working together safely and efficiently to was conducted this year with deliver quality products for long-term a consultant who provided an extensive review of the anhydrous success. ammonia plant operation. The OUR MISSION study indicated the Synfuels Dakota Gasification Company converts lignite Plant was running the outlet of coal into diverse revenue streams in a safe, one of the heaters at a warmer profitable, and environmentally responsible temperature than necessary. By manner, providing long-term value and stability lowering the temperature, they to the cooperative and our community. were able to realize an immediate

34 BASIN ELECTRIC POWER COOPERATIVE

five percent increase in ammonia plant efficiency.

This was one of a number of significant projects completed during the year.

With the focus on innovation and diversification, and keeping cooperative principles in mind, staff at the Synfuels Plant spent time this year developing a new strategic plan. A committee that included members of the management team and a cross section of experienced and new employees discussed and evaluated the future of the plant.

The results include a new mission statement, vision statement, values and strategic themes.

The urea facility is an example of a project that follows the thought behind this plan. It will develop three additional products, which will increase the revenue stream and more safely move the plant’s products to market, while providing urea fertilizer to benefit members and rural America.

In 1988, when Basin Electric’s membership voted to purchase the Synfuels Plant, the cooperative realized a $37 million per year benefit. Today, that benefit is estimated to be $78 million a year.

We are committed to continuing on a path to further diversify operations to position the facility for a bright future with an increasing benefit to the membership.

COMMITMENT TO COOPERATIVE & WORKFORCE 2015 ANNUAL REPORT 35

COMMITMENT TO COOPERATIVE & WORKFORCE

I

n the last few years, Basin Electric focused on the fundamentals of an organization committed to the cooperative principles. That means building a stronger workforce; growing the cooperative model through strong linkages with the membership; becoming a shining example of the co-op model within the communities in which Basin Electric serves, and to do this all in the light of building a better Basin Electric.

It began with the board on governance. The board directed staff to take a comprehensive look at the policies and practices of everyday business. It’s an important process on a few different levels. Policies need to be clear and concise, establishing the broad priorities from the board.

This helps staff clearly see what the board wants and provides a roadmap for how to get there. Solid governance helps ensure the cooperative is successful.

At the same time, staff worked to increase focus on issues of importance to the employees and deliver those messages in an easy to find, understandable format.

WORKFORCE

As a warehouseperson at Leland Olds Station, Dusty Simmons’ job duties change weekly. The rotations include unloading new freight, cataloging new and stocked inventory, delivering freight to employees, and shipping materials; providing customer service at the warehouse window; and two weeks floating between the two areas.

36 BASIN ELECTRIC POWER COOPERATIVE

As Basin Electric made strides in governance, significant progress was also made in strengthening the cooperative’s workforce.

Basin Electric continues to vie for the best in the workforce. Over the last five years there’s been a significant transition within the cooperative, and due to a competitive environment for recruiting and retaining employees, along with many retirements, more than 850 employees have transitioned out of Basin I’m so proud to work for Electric’s workforce. This highlights the Basin Electric, and I know our employees would say the same. need for the cooperative to work on Working for a cooperative can recruitment, orientation and training, be considered a bit of a calling retention and communication.

– knowing you are working for Improving communication began member-owners to meet needs with changes made at the board level and and make the community a better a more intentional and in depth dialogue place to live, is a good feeling. with the employees and membership.

DIANE PAUL, CEO and General Manager Paul Sukut senior vice president of Human Resources furthered that commitment by consistently communicating with employees through weekly staff updates. He also made in-person visits to all cooperative facilities multiple times during the year to speak directly with employees regarding the issues facing the cooperative as well as answer questions. To enhance

If stationed abroad, Basin Electric offers benefits like supplementing military pay for employees while they are deployed, continuing benefits during deployment, providing cell phones and laptops to deployed employees and granting extra leave after they return from deployment. The cooperative also provides an “open door” for family members to raise concerns that develop while their loved one is deployed.

Dr. Kaspari does everything you’d expect when you go to a medical appointment. What he doesn’t do is charge a co-payment. That’s an immediate savings of at least $25 for a Basin Electric employee.

that effort, Human Resources staff visited the facilities with a goal of re-establishing relationships with supervisors and managers.

Changes were made in recruitment and the cooperative revised its orientation program. Instead of a stack of papers, new employees now participate in a program that spans the first several months of their career at Basin Electric.

That effort rolls into training and employee development.

The cooperative is currently in the process of advancing a robust learning and development training program and doing so in new ways.

Basin Electric takes the role of supporting all employees very seriously, and does so by working to keep employees healthy in direct ways. Having every Basin Electric employee healthy and ready for work each day is vital to the cooperative’s success.

In 2007, Basin Electric expanded the role of Dr. Thomas Kaspari, the on site physician at Dakota Gas, from that of a

PEOPLE. POWER. PURPOSE. SERIES IN 2016 Beginning in 2016, Basin Electric’s learning & development division started a new live stream, interactive learning series called People. Power. Purpose. The series informs employees about topics relating to Basin Electric, the cooperative business model, challenges facing the cooperative and more right from their location or desk.

2015 ANNUAL REPORT 37

COMMITMENT TO COOPERATIVE & WORKFORCE

When Basin Electric employees struggle to find child care, it affects everything. The cooperative wanted to be a part of finding a solution to help fill that void in our communities. Basin Electric teamed up with the Missouri Valley Family YMCA and local hospitals in Bismarck to announce a child care partnership. This is a unique, first-of-its-kind partnership for the YMCA to expand its quality child care services.

part-time industrial medicine role to a full-time doctor who visits all facilities on a rotational basis. Having access to an on-site physician is a time- and money-saving reality for the cooperative and workforce. In a matter of 15 minutes, they can visit with Dr. Kaspari about their medical needs versus spending a few hours in a clinic and the associated costs.

On a monthly basis, Dr. Kaspari sees an average of more than 400 employees across all of our facilities.

The cooperative employs 203 military veterans and 46 active military members. The employees in military service who voluntarily sacrifice so much, deserve consistent and continuous support. Basin Electric takes great strides to support employee-soldiers at home and abroad.

Child care is an ongoing challenge and Basin Electric attempted to address it in the past, but it’s been difficult.

When employees struggle to find child care, it affects

Basin Electric was named a Go Healthy worksite by the Go Bismarck-Mandan Healthy Community Coalition.

38 BASIN ELECTRIC POWER COOPERATIVE

everything and Basin Electric wanted to be a part of finding a solution to help fill that void in its communities.

Building an in-house child care facility was discussed, but the issues of space, expertise and cost were daunting.

To overcome some of those obstacles, Basin Electric teamed up with the Missouri Valley Family YMCA and local hospitals in Bismarck to announce a child care partnership.

It’s a unique, first-of-its-kind partnership for the YMCA to expand its quality child care services. The new facility opened Feb. 1, 2016.

The next challenge is finding a solution in the Beulah-Hazen, ND, area and Wheatland, WY. The cooperative has more than 1,000 employees working near those small communities. Further, the resources for child care are scarce. Creativity and diligence will be vital to help solve this issue in those rural areas.

The cooperative’s efforts to make life better for all employees and community have been recognized.

• The Bismarck-Mandan Young Professionals Network named Basin Electric one of the top 10 places to work, based on employment strategy, benefits and workplace development.

The Story Behind the Switch kits include retractable banners, table skirts, teacher workbooks, stickers, a PowerPoint presentation, an energy efficiency booklet and demonstration equipment. Equipping Class A members with this turnkey tool is a good way to foster relationships with members and share their co-op story.

• The Bismarck Tribune, through a reader poll, recognized Basin Electric as the Best Large Company to Work For, of those workplaces with 75 employees or more.

• Right-of-Way earned an international award – the International Right of Way Association’s Employer of the Year Award. That award is given to workplaces that promote leadership, education and personal growth opportunities. This is the second time Basin Electric received this award.

COOPERATIVE A solid employee base provides the foundation to strengthen ties with Basin Electric’s membership. The long-term contracts with members serve the financial underpinning of a great organization. They represent a relationship based on a common goal.

To help directly connect employees with the members, staff is developing a cooperative internship program, with the premise of having Basin Electric employees spend a few days at a member cooperative, Class A or Class C, to learn about the business from their point of view. On the flip side, the program will give distribution cooperative

employees the chance to work at Basin Electric for a few days to see what happens at the generation and transmission level. The program is currently in development, but providing an opportunity for employees to “walk in the members’ shoes” will help them better understand the impact of the work they do each day.

The connection between employees and members is vital. That connection directly translates to the communities where they live and work. As challenges arise, it’s cooperatives like Basin Electric that step up to help find a solution.

EDUCATION Care for kids in the cooperative’s communities is one part of helping to nurture future generations. Another is education. Working with young people in schools is something Basin Electric has a long tradition in.

The Story Behind the Switch is one of the cooperative’s most successful, long-standing programs. It’s been in existence for more than 30 years and teaches students to be safe around electricity, how electricity is generated and how electricity gets to homes. Each year, the one-

2015 ANNUAL REPORT 39

COMMITMENT TO COOPERATIVE & WORKFORCE

Three goals exist for the expansion to Basin Electric’s Headquarters building.

The first is to get all employees under one roof. The second goal is to build an addition that can accommodate growth and needs into the future. Lastly, the cooperative is striving to provide a working environment that matches employees’ needs in terms of effective work style, lighting, technology and collaborative elements.

hour program is presented to more than 12,000 fifth graders across Basin Electric’s nine-state member region, and it was recently produced digitally to allow even more members to extend the important message to kids and adults throughout the cooperative’s membership and beyond.

This digital format can be shared online through social media, a Basin Electric donates more than 180 vital channel to engage scholarships every year for children of with the next generation Basin Electric members and employof co-op members. Addiees. The cooperative has given scholarships tionally, the popularity of worth nearly $4 million since the program’s Story Behind the Switch inception in 1991. prompted the creation of the train the trainer pilot program, where staff from Basin Electric’s Class A members learn to deliver the Story Behind the Switch presentation. Basin Electric pays for the cost of the turnkey kits, customized to its Class A members.

$4 MILLION

40 BASIN ELECTRIC POWER COOPERATIVE

EXPAND It’s an exciting time at Basin Electric. The membership has grown and evolved as has the cooperative’s workforce.

Supporting this process required more than additional generation and transmission, it required new resources and employees to best meet the members’ needs. As a result, the amount of space at Headquarters is insufficient, with little room for collaborative space, conference rooms and new employees. Currently, Basin Electric has more than 550 employees in Bismarck working at four different locations.

For many years, Basin Electric was prudent in responding to space needs at Headquarters. In early 2015, the Basin Electric board took a practical approach to addressing the need for more space and, after much review and analysis, approved an expansion to the Headquarters building in August. The addition will include 91,000 square feet to the existing building’s west entrance.

The new working environment will help increase employee engagement, enable formal and informal interactions and collaboration, and enhance the transfer and exchange of knowledge in the workplace. The completion date for the project is summer 2017.

COMMITMENT TO COMMUNITY 2015 ANNUAL REPORT 41

COMMITMENT TO COMMUNITY

C

Basin’s Backyard Garden is an employee-driven initiative to grow vegetables and herbs on Basin Electric’s property. Employees volunteer to plant, maintain and harvest the garden throughout the growing season. It provides employees an opportunity to broaden their network within Basin Electric as well as grow fresh vegetables for local food pantries for those in need. Molly Anderson and Ashtyn Wald are part of the Highland Acres Elementary 1st grade class that helped plant the garden.

42 BASIN ELECTRIC POWER COOPERATIVE

ommunity is people. It’s their health and well-being, their quality of life and opportunities.

When it comes to community, Basin Electric and its employees place high priority on ensuring every need is addressed.

In fact, employees demonstrate year after year their deep commitment to their communities. One example continues to be Brave the Shave. Employees, businesses and citizens stepped up in a big way once again in 2015 raising money to help families battling childhood cancer.

During the campaign, more than $440,000 was raised and more than 360 people braved the shave. Money raised went to St. Baldrick’s Foundation to fund childhood cancer research and fellowships.

What started in 2008 as an internal charitable initiative has grown to a region-wide event where local businesses and Basin Electric’s facilities in various states come together to help children and families in their fight against cancer.

In eight years, more than $1.9 million has been raised by communities in the region.

Basin Electric is also helping Bismarck-Mandan at-risk youth. For the past 10 years, the cooperative has supported Charles Hall Youth Services in its efforts to help at-risk youth make a successful transition from a troubled adolescence to mature adulthood.

Some of Basin Electric’s other charitable efforts are home grown – right between the beans and the cabbage in Basin’s Backyard Garden.

Now in its second year, the garden That caring philosophy volunteers have donated more than that Basin and the members 1,000 pounds of vegetables to local have … most of the members have had that rural sense of food pantries. At the beginning of the everyone works together … year, students from Highland Acres and I think Basin models that Elementary School in Bismarck helped same philosophy by allowing plant the garden, and mid-summer, its employees to take part in preschoolers with New Discovery these events.

Montessori Center visited to learn DUSTIN ERHARDT, about gardening. cyber security/compliance specialist III, The garden has provided a connregarding the iCan Bike Camp volunteer opportunity ection to one of the area’s newest cooperatives, the BisMan Community Food Co-op. In 2015, Basin Electric provided the organizers with $50,000 in preferred equity to help them reach their goal of $900,000 – the amount needed to open a cooperative grocery store. At the end of September, the food co-op

Eight hundred fifty charities received monetary donations from Basin Electric in 2015. The Missouri Slope Areawide United Way honored Basin Electric as the top corporate contributor.

reached their goal. They plan to open in spring 2016. It’s another example of co-ops helping co-ops.

The United Way chapters throughout Basin Electric’s service area also receive strong support from the cooperative and its employees. For two years in a row, Basin Electric was honored by the Missouri Slope Areawide United Way as the top corporate contributor to its fundraising campaign.

Employee pledges, combined with Basin Electric’s 100 percent match and various fundraisers at the facilities, totaled more than $240,000 in 2015.

In addition to monetary support, employees support the United Way with people power. For more than a decade, Headquarters employees have volunteered their time during United Way’s Day of Caring.

This year, which marked the 16th annual Day of Caring, more than 30 volunteers from Basin Electric braved the 100-degree temperature and helped at Papa’s Pumpkin Patch. The Pumpkin Patch has always focused on families, education and fun. Since 1983, Papa’s has given more than $500,000 to local charities with help from generous volunteers.

In addition to employees’ dollars and time, Basin Electric’s Charitable Giving Program offers direct financial impact to the rural communities it serves. Each year, one-third of the charitable giving budget is set aside for member matching donations. In 2015, for the first time, Basin Electric distributed 100 percent of the budget for member matches. Fifty-four co-ops from eight states in

Cory Bittner (right) shaved his head in honor of his daughter, Grace (left), a Brave the Shave honoree, during the 2015 flagship event at the Missouri Valley Family YMCA in Bismarck.

1,900 $1.9 MILLION

VOLUNTEERS HAVE SHAVED THEIR HEADS

46

NUMBER OF LOCAL CHILDREN HONORED

2015 ANNUAL REPORT 43

COMMITMENT TO COMMUNITY

Nearly 100 employees are part of the BE Involved Committee, which is a Basin Electric volunteer team dedicated to helping employees find ways to give back to their communities.

the cooperative’s service area participated in the program to help Basin Electric distribute more than $480,000 to their communities.

As members work to support the priorities of their communities, Basin Electric is right there beside them helping to make the projects successful.

Some of Basin Electric’s largest contributions in 2015 went toward medical centers in rural communities. The cooperative dedicated $250,000 over five years – with the support of Class C member Roughrider Electric Cooperative – to the renovation of the Sakakawea Medical Center in Hazen, ND, an area where Basin Electric employs more than 1,000 people.

Basin Electric also made a member matching contribution with Slope Electric Cooperative for West River Health Services – $100,000 over five years.

These are just a few examples of the many ways Basin Electric, its employees and members are directly impacting the health, well-being, quality of life and opportunities within their communities.

People helping people. It’s quite simply the essence of cooperatives.

500 VOLUNTEER HOURS

BETWEEN ICAN BIKE CAMP, UNITED WAY DAY OF CARING AND REBUILDING TOGETHER. 44 BASIN ELECTRIC POWER COOPERATIVE

Electric cooperative representatives present $200,000 to West River Health Services. (From left) Ted Uecker, West River Health Services Foundation; Steve Wagner, Slope Electric Cooperative director; and Jen Holen, Basin Electric supervisor of community and employee engagement.

LARGEST PRIVATE PLACEMENT TRANSACTION IN 2015

BISMARCK SPRINGFIELD 11 10 BOSTON 9 NEW YORK 1 5 CHICAGO 8 PHILADELPHIA

MILWAUKEE 2

CHARLOTTE

7

NEWPORT

3 BEACH

DALLAS 4

ATLANTA 6

SAN ANTONIO 12

BASIN ELECTRIC BORROWED

$1.5 BILLION

RUS BUYOUT

TO PARTIALLY FUND PROJECTS

$1.2 BILLION $300 MILLION

Four Basin Electric employees embarked on a five-day investor roadshow to deliver the Basin Electric story in an effort to raise the capital needed to buy out of the Rural Utility Service. The roadshow spanned coast-to-coast and border-to-border with stops in 12 cities and meetings with more than twice that many potential investors. The trip culminated with an immensely successful transaction with over $1.9 billion in initial offers from private placement investors. The transaction was the largest private placement ever for a generation and transmission cooperative.

FINANCIAL STABILITY 2015 ANNUAL REPORT 45

FINANCIAL STABILITY

CONSOLIDATED NET MARGIN & EARNINGS

150 120 90

2015 FINANCING ACTIVITIES

In millions of dollars - for the years ended

120.6 98.3

60

0

49.7

45.9

30

8.1 2011

2012

2013

2014

2015

TOTAL ELECTRIC SALES TO MEMBER SYSTEMS AND OTHERS In millions of megawatt hours

30 25

23.5

20

6.4

15

17.1

25.9 7.2 18.7

28.3 6.2

26.6 6.2 20.4

22.1

2013

2014

29.6 6.9 22.7

10 5 0

2011

2012

2015

Others

Members MARGIN DISPOSITION

In millions of dollars – for the years ended

80 70 60 50 40 30 20 10 0

7.2

55.2 18.0

57.4 42.6

37.2

2011

6.2

2012 2013 Allocated to members

46 BASIN ELECTRIC POWER COOPERATIVE

6.2

77.6 28.2

52.0

49.4

2014 2015 Bill credits

B

asin Electric’s financial strength comes in many forms.

It comes in the form of 30 investors working with Basin Electric during the Rural Utilities Service buyout.

It comes in the form of the urea project financing for Dakota Gas’ Great Plains Synfuels Plant, especially in the midst of dropping commodity prices.

It comes in the form of strong bond ratings from the three major rating agencies.

From a financial standpoint, 2015 was an historic year for Basin Electric and all of the change and activity was done with the best interest of the membership as top priority. Basin Electric works on behalf of its members to best serve them.

The most significant financial activity in 2015 was the cooperative’s efforts to buy out of the Rural Utilities Service (RUS). The driver of that decision was the National Environmental Policy Act (NEPA) rules proposed by the U.S. Department of Agriculture Rural Development office. The rules would have greatly impacted Basin Electric’s ability to conduct and transact business with RUS in a timely manner.

In a private placement transaction that spanned several weeks in preparation and numerous investor presentations that took the finance team across the U.S., Basin Electric received $1.9 billion in initial offers. Ultimately, Basin Electric borrowed $1.5 billion given the attractive interest rates the cooperative was offered. To complete the RUS buyout, Basin Electric needed $1.2 billion, so the $300 million differential was used to partially fund projects currently under construction.

The transaction was significant for multiple reasons.

It was the largest private placement transaction involving a generation and transmission cooperative. It was the largest U.S. private placement transaction across all sectors in 2015.

It was the third largest U.S. private placement transaction ever to date. Also, Basin Electric is now working with its first foreign investor, South Korea’s Dongbu Insurance. The cooperative’s transaction was the first globally marketed G&T transaction, and the first U.S. private placement marketed to an Asian investor.

While, there were 30 investors in the RUS buyout, Basin Electric relied heavily on one of its cooperative allies, the National Rural Utilities Cooperative Finance Corporation (CFC). CFC was the largest investor at $227 million.

While the NEPA rules appear to be a bit less onerous than initially anticipated, other challenges such as the potential impact of the EPA’s Clean Power Plan, confirm that buying out of RUS was the right decision.

Another financial feat in 2015 was the financing of the urea project at Dakota Gas. In May, Dakota Gas closed on a private placement to fund the bulk of the investment required for the plant. The private placement is comprised of $475 million of secured long-term debt provided by a group of four investors. Once again, the cooperative relied on its cooperative allies. In this transaction, CoBank and some of its affiliated farm credit system members were the largest investors at $200 million.

Individually, these private placement transactions are extremely significant, and they were only possible because of Basin Electric’s strong financial condition and associated credit-worthiness. These attributes are bolstered by the financial strength of the entire membership, and membership’s respective wholesale power contract extensions.

It was a good year for Basin Electric. The accomplishments of the finance team exemplify their commitment to the mission of Basin Electric. The cooperative is in sound financial condition to meet the needs of its membership now and well into the future.

Basin Electric’s financial strength and flexibility is rooted in integrity, an important part of the electric cooperative business model.

Electric rates – The 2015 average Class A member rate was 53.7 mills per kilowatt hour. In August, Basin Electric’s board approved the Class A member rate package for 2016 to meet the member revenue requirement of $1.45 billion.

Beginning Jan. 1, 2016, the average Class A rate will be 59.2 mills per kilowatt-hour before a depreciation credit, and 57.7 mills per kilowatt-hour net.

The rate structure was modified to include a demand and energy credit associated with the depreciation extension to the members that have signed wholesale power contracts through 2075.

Senior Secured Bond ratings – Fitch Ratings affirmed the cooperative’s senior secured A+ rating and Moody’s Investors Service affirmed the cooperative’s A1 rating. Standard & Poor’s rating of the cooperative is A. Fitch and Standard & Poor’s ratings include a stable outlook. Moody’s changed its ratings outlook from stable to negative siting a deterioration in the consolidated operating performance of the cooperative as the reason for its action.

Short-term ratings – Basin Electric’s short-term ratings are F1 from Fitch Ratings, A-1 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, 2015, the consolidated net margin and earnings was $8.1 million. This is $41.6 million less than the 2014 consolidated net margin and earnings of $49.7 million.

CONSOLIDATED GROSS REVENUE Before intercompany eliminations For the year ended Dec. 31, 2015

BASIN ELECTRIC

$1,484.6

In millions of dollars

DAKOTA COAL

$242.1 OTHER

$37.6

Total $2,231.2

DAKOTA GAS

$466.9

BASIN ELECTRIC CONSOLIDATED CAPITALIZATION As of Dec. 31, 2015

LEASES

%

6.2%

EQUITY AND DEFERRED TAXES

22.6%

DEBT

71.2% 2015 ANNUAL REPORT 47

FINANCIAL STABILITY

CONSOLIDATED FINANCIAL HIGHLIGHTS For the years ended Dec. 31 (in millions) 2015 2014 Total utility and nonutility revenue $ 2,133.0 $ 2,288.8 Total expenses 2,124.9 2,239.1 Net margin and earnings $ 8.1 $ 49.7

% change (6.8) (5.1) (83.7)

As of Dec. 31 (in millions) Net electric plant and nonutility property Total assets Long-term debt Equity

% change 9.2 10.9 27.5 (0.2)

2015 $ 5,488.6 $ 7,132.5 $ 4,024.0 $ 1,304.1

Electric – Basin Electric’s total utility operating revenue for 2015 was $1.4 billion, a decrease of $35.9 million from 2014. Revenue from member systems totaled $1.2 billion in 2015, an increase of $7.8 million from 2014. Revenue from non-member sales totaled $216.9 million, a decrease of $47.1 million from 2014. Total utility operating expenses plus interest and other charges before income taxes for 2015 were $1.4 billion, which is $30.6 million less than in 2014. Basin Electric’s utility margin before income taxes, combined with Basin Cooperative Services’ net operating results, yielded a combined margin of $49.4 million to be allocated to members.

MEMBER INVESTMENT PROGRAM In millions of dollars – at year end

200 150

158.4

100 50 0

165.2

173.8

112.3 75.7 8.1

2011

2012

2013

2014

2015

AVERAGE INTEREST RATE ON UTILITY DEBT As of Dec. 31 – in percent

5 4 3

3.49

4.07

3.97

3.83

2012

2013

2014

4.21

2 1 0

2011

48 BASIN ELECTRIC POWER COOPERATIVE

2015

2014 $ 5,024.2 $ 6,431.8 $ 3,155.7 $ 1,307.3

Subsidiary earnings – Dakota Gas had a net loss of $31.1 million during 2015. Dakota Gas did not declare or pay any dividends to Basin Electric in 2015; however, since 2007, Dakota Gas has paid $198.5 million in dividends to Basin Electric.

FINANCIAL POSITION Assets – The total assets of Basin Electric and its subsidiaries as of Dec. 31, 2015, were $7.1 billion, an increase of more than $700.7 million from a year earlier.

Cash position – The consolidated cash balance, including restricted cash, as of Dec. 31, 2015, was $490.0 million.

Member Investment Program – Basin Electric’s Member Investment Program ended the year with $173.8 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, 2015, Basin Electric had approximately $4.1 billion of debt outstanding including Member Investment Program obligations, at a weighted average interest rate of 4.2 percent.

Equity position – At year-end 2015, Basin Electric had total equity of $1.3 billion, a decrease of $3.2 million from 2014. At the end of 2015, equity represented 23.7 percent of Basin Electric’s total capitalization on its balance sheet.

Basin Electric has an equity-to-asset ratio of 18.3 percent.

Capital credit allocations and retirements – In March 2015, Basin Electric allocated $52.0 million to its patrons. Since 1966 Basin Electric has allocated more than $871.6 million in capital credits to its members. Basin Electric has retired $224.6 million over the history of the cooperative.

Return of cash to members – Since 2000, Basin Electric has returned nearly $633.4 million to the membership through patronage capital retirements, bill credits and power cost adjustments.

BASIN ELECTRIC POWER COOPERATIVE AND SUBSIDIARIES

FIVE-YEAR CONSOLIDATED FINANCIAL SUMMARY for the years ended December 31, (dollars in thousands)

2015

2014

2013

2012

2011

Utility operations: Operating revenue: Sales of electricity for resale Other electric revenue Total utility operating revenue

$ 1,419,862 $ 1,459,155 $ 1,325,737 $ 1,184,132 $ 1,028,832 25,755 22,346 12,072 12,812 8,219 1,445,617 1,481,501 1,337,809 1,196,944 1,037,051

Operating expenses: Operation Maintenance Depreciation and amortization Taxes other than income Total utility operating expenses

948,317 160,348 154,151 2,773 1,265,589

987,388 163,433 148,028 2,959 1,301,808

905,289 124,436 131,421 2,908 1,164,054

807,629 130,081 108,328 2,255 1,048,293

779,575 130,909 69,058 2,802 982,344

Interest and other charges: Interest on long-term debt Other Total interest and other charges Operating margin (deficit)

156,903 12,716 169,619 10,409

155,679 8,338 164,017 15,676

149,669 8,044 157,713 16,042

130,719 7,933 138,652 9,999

58,010 10,307 68,317 (13,610)

Nonoperating margin: Interest and other income Patronage allocations from other cooperatives Total nonoperating margin Utility margin before income taxes

34,894 4,105 38,999 49,408

32,614 3,777 36,391 52,067

34,267 7,133 41,400 57,442

29,646 2,988 32,634 42,633

30,978 1,816 32,794 19,184

Nonutility earnings (loss) before income taxes

(57,614)

(1,575)

(16,854)

82,529

77,754

Provision for (benefit from) income taxes

(16,281)

811

(5,359)

4,606

(1,349)

Net margin and earnings

$ 8,075 $ 49,681 $ 45,947 $ 120,556 $

98,287

Electric sales information: Electric energy sales (in thousands of MWh) Members Others Total

22,664 22,074 20,382 18,715 6,890 6,251 6,171 7,183 29,554 28,325 26,553 25,898

17,156 6,361 23,517

2015 ANNUAL REPORT 49

INDEPENDENT AUDITORS’ REPORT

Deloitte & Touche LLP

50 South Sixth Street, Suite 2800 Minneapolis, MN 55402-1538 USA

INDEPENDENT AUDITORS’ REPORT

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

To the Board of Directors and Members of Basin Electric Power Cooperative Bismarck, North Dakota 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, 2015 and 2014, 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 as of December 31, 2015 and 2014, 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 15, 2016

50 BASIN ELECTRIC POWER COOPERATIVE

Member of Deloitte Touche Tohmatsu

CONSOLIDATED FINANCIAL STATEMENTS

BASIN ELECTRIC POWER COOPERATIVE AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS for the years ended December 31, (dollars in thousands)

2015 Assets Electric plant: In service Property held under capital leases Construction work in progress Total electric plant Less: accumulated provision for depreciation and amortization Nonutility property: Property, plant and equipment Construction work in progress Total nonutility property Less: accumulated provision for depreciation and depletion Other property, investments and deferred charges: Mine related assets (Note 5) Investments in associated companies Other investments Special funds Deferred charges (Note 6) Current assets: Cash and cash equivalents Restricted cash and investments (Note 2) Short-term investments Customer accounts receivable Other receivables, net of allowance for uncollectibles Coal stock, materials and supplies (Note 2) Prepayments and other current assets Capitalization and Liabilities Capitalization: Equity: Memberships Patronage capital Retained earnings of subsidiaries Other equity (Note 7) Accumulated other comprehensive income (loss) (Note 7) Noncontrolling interest Long-term debt, net of current portion (Note 8) Capital lease obligations, net of current portion (Note 3) Deferred credits, taxes and other liabilities (Note 11)

2014

$ 5,700,875 181,425 514,678 6,396,978 (2,067,813) 4,329,165

$ 5,508,363 195,518 212,799 5,916,680 (1,928,890) 3,987,790

1,727,705 194,273 1,921,978 (762,520) 1,159,458

1,664,627

65,295 1,729,922 (693,484) 1,036,438

146,289 37,904 55,335 45,195 347,910 632,633

127,557

42,907

55,877 44,341 235,964 506,646

171,204 318,685 100 120,098 85,151 201,011 114,959 1,011,208 $ 7,132,464

286,775 34,000 51,362 129,465 93,518 187,592 118,220 900,932 $ 6,431,806

$ 21 638,363 374,078 296,031 (6,553) 1,301,940 2,192 1,304,132

$ 21 591,803 409,072 299,522 4,489 1,304,907 2,416 1,307,323

4,023,978 179,886 5,507,996 541,840

3,155,726 198,719 4,661,768 595,165

41,469 5,404 230,866 169,655 544,758 90,476 1,082,628 $ 7,132,464

188,920 4,914 210,983 161,395 514,820

93,841 1,174,873 $ 6,431,806

Commitments and contingencies (Notes 3 and 12) Current liabilities: Current portion of long-term debt (Note 8) Current portion of capital lease obligations (Note 3) Accounts payable Notes payable – affiliates Notes payable (Note 12) Taxes and other current liabilities

2015 ANNUAL REPORT 51

CONSOLIDATED FINANCIAL STATEMENTS

BASIN ELECTRIC POWER COOPERATIVE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS for the years ended December 31, (dollars in thousands)

2015 Utility operations: Operating revenue: Sales of electricity for resale: Members Others Other electric revenue Operating expenses: Operation Maintenance Depreciation and amortization Taxes other than income Interest and other charges: Interest on long-term debt Other Operating margin Nonoperating margin: Interest and other income Patronage allocations from other cooperatives Utility margin before income taxes Nonutility operations: Operating revenue: Synthetic gas Byproducts, coproduct and other Lignite coal

$ 1,202,947 216,915 1,419,862 25,755 1,445,617

$ 1,195,095 264,060 1,459,155

22,346 1,481,501

948,317 160,348 154,151

2,773 1,265,589

987,388 163,433 148,028

2,959 1,301,808

156,903 12,716 169,619 10,409

155,679 8,338 164,017 15,676

34,894 4,105 38,999

32,614 3,777 36,391

49,408

52,067

187,564 333,813 122,030 643,407

276,922 368,820 121,516 767,258

Operating expenses (includes $17,976 and $17,903 of net income attributed to noncontrolling interest)

705,994

Operating loss

Margin and earnings (loss) before income taxes

772,527

(62,587)

(5,269)

4,973

3,694

(57,614)

(1,575)

(8,206)

50,492

Interest and other income Nonutility loss before income taxes

2014

Provision for (benefit from) income taxes

(16,281)

811

Net margin and earnings

$ 8,075

$ 49,681

52 BASIN ELECTRIC POWER COOPERATIVE

CONSOLIDATED FINANCIAL STATEMENTS

BASIN ELECTRIC POWER COOPERATIVE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) for the years ended December 31, (dollars in thousands)

2015 2014 $ 8,075 $ 49,681

Net margin and earnings Other comprehensive income (loss): Adjustment to post employment liability of $(1,818), (net of tax of $(171)) and $(16,514), (net of tax of $(963)) Unrealized gain (loss) on securities of $(915), (net of tax of $(442)) and $(133), (net of tax of $476) Unrealized gain (loss) on cash flow hedges of $135, (net of tax of $73) and $(4,177), (net of tax of $(3,177)) and reclassification adjustment of $(8,444), (net of tax of $(4,546)) and $9,621, (net of tax of $7,318) reclassified into earnings

(1,818) (16,514) (915) (133) (8,309) 5,444

Total other comprehensive loss

(11,042) (11,203)

Comprehensive income (loss)

$

(2,967) $

38,478

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY for the years ended December 31, 2015 and 2014 (dollars in thousands)

Balance, December 31, 2013

Memberships $ 21

Patronage Capital $ 546,711

Retained Earnings of Subsidiaries $ 406,947

Other Equity $ 302,058

Accumulated Other Comprehensive Income (Loss) (Note 7) $ 15,692

-

48,718 1,374 (5,000) -

963 1,162

(1,374) (1,162)

(11,203) -

-

-

-

-

-

17,903

17,903

-

-

-

-

-

(17,993)

(17,993)

21

591,803

409,072

299,522

4,489

2,416

1,307,323

-

43,069 3,491 -

(34,994) -

(3,491) -

(11,042) -

-

(2,967) -

-

-

-

-

-

17,976

17,976

-

-

-

-

-

(18,200)

(18,200)

$ 21

$ 638,363

$ 374,078

$ 296,031

$ 2,192

$ 1,304,132

Comprehensive income (loss) Transfers to other equity Retirement of patronage capital Merger with BTI Noncontrolling interest in net margin and earnings Dividends paid to noncontrolling interest Balance, December 31, 2014 Comprehensive income (loss) Transfers to other equity Retirement of patronage capital Noncontrolling interest in net margin and earnings Dividends paid to noncontrolling interest Balance, December 31, 2015

$ (6,553)

Noncontrolling Interest $ 2,506

Total $ 1,273,935

-

38,478 (5,000) -

2015 ANNUAL REPORT 53

CONSOLIDATED FINANCIAL STATEMENTS.

BASIN ELECTRIC POWER COOPERATIVE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS for the years ended December 31, (dollars in thousands)

2015 Operating activities: Net margin and earnings Adjustments to reconcile net margin and earnings to net cash from operating activities: Depreciation and amortization of property, plant and equipment Increase (decrease) in reserves Other amortization Patronage capital and other Deferred income taxes Other, including regulatory revenue deferral Income attributable to noncontrolling interest Changes in other operating elements: Customer accounts receivable Other receivables Coal stock, materials and supplies Prepayments and other current assets Accounts payable Taxes and other current liabilities Net cash provided by operating activities

2014

$ 8,075

$ 49,681

230,084 (36,195) 16,737 (7,296) (15,733) 7,884 17,976

221,165 22,621 3,858 (6,289) 544 5,000 17,903

9,367 9,395 (13,436) 297 2,242 1,073 230,470

7,592 (5,553) (3,079) (32,423) 33,094 (5,278) 308,836

Investing activities: Acquisition of electric plant Acquisition of nonutility property Purchase of investments Sale of investments Purchase of other assets Net cash used in investing activities

(477,838) (174,300) (370,439) 117,060 (27,950) (933,467)

(205,424) (89,161) (297,401) 455,306 (21,916) (158,596)

Financing activities: Loan advances Principal payments of long-term debt Purchase of funds held by U.S. Treasury Sale of funds held by U.S. Treasury Payment of debt issue costs Retirement of patronage capital Proceeds of notes payable - affiliates Payments of notes payable - affiliates Proceeds of notes payable Payments of notes payable Payments under capital lease obligations Dividends paid to noncontrolling interest Net cash provided by financing activities Net increase (decrease) in cash and cash equivalents Cash and cash equivalents, beginning of year Cash and cash equivalents, end of year

1,907,124 19,161 (1,423,483) (165,814) (6,225) (11,514) 243,742 (130,304) (1,724) - (5,000) 1,289,454 1,238,102 (1,281,194) (1,231,320) 2,834,407 1,154,631 (2,804,469) (949,690) (23,426) (15,714) (18,200) (17,993) 587,426 13,125 (115,571) 163,365 286,775 123,410 $ 171,204 $ 286,775

Supplemental disclosure of cash flow information: Cash paid for interest, net of amounts capitalized Cash paid (refunded) for income taxes

$ 168,583 $ 164,817 $ (2,472) $ 2,228

Non-cash investing and financing activity: Acquisition of electric plant and nonutility property through short-term financing Acquisition of electric plant and nonutility property through capital lease

$ 17,642 $ 5,083

54 BASIN ELECTRIC POWER COOPERATIVE

$ 22,326 $ 158,223

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

BASIN ELECTRIC POWER COOPERATIVE AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS for the years ended December 31, (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. The rates charged to its members for electric service are established by Basin Electric’s Board of Directors.

Basin Electric has four wholly owned for-profit subsidiaries, Dakota Gasification Company (Dakota Gas), Dakota Coal Company (Dakota Coal), 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). Another wholly owned for-profit subsidiary, Basin Telecommunications, Inc. (BTI), was merged with Basin Electric on December 31, 2014. 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. 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, Dakota Gas, Dakota Coal, MLC, Coteau, PrairieWinds ND and PrairieWinds SD to Basin Electric and charges from Basin Electric to BCS, 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 (Note 13).

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.

2015 ANNUAL REPORT 55

NOTES TO 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: Cash and investments: MBPP operating funds Revenue deferral Unadvanced funds held in escrow by U.S. Bank as trustee for Dakota Gas

2015

2014

$ 22,453 $ 19,000 15,000 296,232 $ 318,685 $ 34,000

Funds held by the U.S. Treasury: RUS/Federal Financing Bank (FFB) debt service payments

$ - $ 237,517

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 and Other investments.

The cost, unrealized holding gains and losses, and fair value of available-for-sale securities were as follows:

Cost $ Equity securities 47,730 Guaranteed investment certificates 1,131 Canadian government bonds 956 100 Corporate commercial paper $ 49,917

U.S. Government obligations

December 31, 2015 Gross Unrealized Holding Fair Gains Losses Value Cost $ - $ - $ - $ 24,983 14,735 627 61,838 47,730 5 1,136 14 970 100 26,839 $ 14,754 $ 627 $ 64,044 $ 99,552

December 31, 2014 Gross Unrealized Holding Fair Gains Losses Value $ 16 $ - $ 24,999 14,832 62,562 577 26,262 $ 14,848 $ 577 $ 113,823

During 2015 and 2014, sales proceeds on securities classified as available-for-sale were $100,102 and $430,072.

All available-for-sale debt securities have contracted maturity dates of one year or less.

Held-to-maturity securities are included in Cash equivalents and Restricted cash and investments. The cost, unrealized holding gains and losses, and fair value of held-to-maturity securities were as follows:

Money market Corporate commercial paper

December 31, 2015 Gross Unrealized Holding Fair Cost Cost Gains Losses Value $ 134,004 $ - $ - $ 134,004 $ 349,621 349,621 137,183 $ 483,625 $ - $ - $ 483,625 $ 137,183

December 31, 2014 Gross Unrealized Holding Fair Gains Losses Value $ - $ - $ 137,183 $ - $ - $ 137,183

All held-to-maturity securities have contracted maturity dates of three months or less.

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 $7,166 and $8,135, as of December 31, 2015 and 2014.

56 BASIN ELECTRIC POWER COOPERATIVE

NOTES TO 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: 2015 2014 Materials and supplies $ 142,350 $ 140,944 Coal and fuel oil 31,203 33,251 Byproducts, coproducts and limestone inventory 11,884 7,189 Ammonia 12,515 2,716 Ammonium sulfate 2,915 1,407 144 2,085 Process inventory $ 201,011 $ 187,592 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, 2015 was $224,626.

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 and limestone 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 2015 and 2014 totaled $13,043 and $5,920. 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 2.51 and 2.49 percent in 2015 and 2014. Annual electric plant depreciation expense totaled $150,752 and $143,535 for 2015 and 2014.

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 $79,332 and $77,630 for 2015 and 2014.

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 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:

2015 ANNUAL REPORT 57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Regulatory assets included in: Deferred charges Mine related assets Regulatory liabilities included in: Deferred credits, taxes and other liabilities Net regulatory assets

2015 2014 $ 319,360 $ 220,119 24,086 25,526 343,446 245,645

(31,991)

(23,927)

$ 311,455 $ 221,718

As of December 31, 2015, 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 Policy contains a framework that defines risk parameters, delineates management responsibility and establishes organizational relationships. The Risk Management Policy requires reporting these risk management activities to the Basin Electric and Dakota Gas Boards of Directors.

Dakota Gas’ Risk Management Policy contains a framework that defines risk parameters, delineates management responsibility and establishes organizational relationships. The Risk Management 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 mitigating the risk of market fluctuation in natural gas prices. These derivative financial instruments effectively fix the price of synthetic natural gas between $3.15 and $4.90 per dekatherm for a portion of the forecasted sales (5% to 48% on a monthly basis) through March 2018. These derivative financial instruments attempt to provide for sales prices in excess of Dakota Gas’ average before tax cost of production and are only to mitigate the risk of natural gas price movements. Any changes in cash flows from the underlying 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 derivative activity based upon fluctuations in the price of natural gas.

Certain financial instruments valued at $18,939 and $29,511, at December 31, 2015 and 2014, 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 Statements 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 2015 or 2014. Derivative financial instruments valued at $3,627 and $(81), at December 31, 2015 and 2014, 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 Statements of Operations as synthetic gas revenue. In the December 31, 2015 Consolidated Balance Sheets, the fair value of the current portion of these derivative financial instruments, $19,382, was included in Prepayments and other current assets, and the noncurrent portion, $100, was included in Other investments, the current portion, ($129), was included in Taxes and other current liabilities and the noncurrent portion, ($414), was included in Deferred credits, taxes and other liabilities.

In 2015 and 2014, Dakota Gas also entered into derivative financial instruments for the purpose of mitigating the risk of market fluctuation in tar oil prices. These derivative financial instruments effectively fix the price of tar oil between $45.00 and $63.00 per barrel for a portion of the forecasted sales (24% to 67% on a monthly basis) through June 2017. These derivative financial instruments attempt to provide for sales prices in excess of Dakota Gas’ average before tax cost of production and are held only to mitigate the risk of tar oil price movements.

Certain derivative financial instruments valued at $1,029 and $0, at December 31, 2015 and 2014, meet the criteria for hedge accounting under ASC 815, 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 Byproducts, coproduct and other revenue in the Consolidated Statements of Operations when the underlying

58 BASIN ELECTRIC POWER COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2015 or 2014. Derivative financial instruments valued at $12,386 and $11,490, at December 31, 2015 and 2014, 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 Statements of Operations as Byproducts, coproduct and other revenue. In the December 31, 2015 Consolidated Balance Sheets, the fair value of the current portion of these derivative financial instruments, $12,816, was included in Prepayments and other current assets and the noncurrent portion, $599, was included in Other investments.

In 2015, Dakota Gas also entered into derivative financial instruments for the purpose of mitigating the risk of market fluctuation in electricity prices paid at the plant. None of the electricity derivative financial instruments, valued at $(1,288), at December 31, 2015, meet the criteria for hedge accounting under ASC 815, and as a result, all changes in market value on the instruments are recognized in Nonutility Operating expenses on the Consolidated Statements of Operations. In the December 31, 2015 Consolidated Balance Sheets, the fair value of the current portion of these derivative financial instruments, $50, was included in Prepayments and other current assets and the current liability portion, ($1,338), was included in Taxes and other current liabilities.

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, 2015 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, 2015 and 2014 of $10,933 and $11,022. The change in fair value for the year ended December 31, 2015 resulted in a deferred loss of $985. At December 31, 2015 and 2014, the fair value of the obligation related to the interest rate swap agreements of $91,557 and $90,571 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).

Basin Electric entered into a series of floating-to-fixed swap agreements valued at ($6,198) and ($5,098) at December 31, 2015 and 2014, 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, 2015, the fair value of the liability related to Basin Electric’s natural gas swap agreements was included in Deferred credits, taxes and other liabilities ($5,668) and Taxes and other current liabilities ($530) 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).

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.

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

2015 ANNUAL REPORT 59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

At December 31, 2015 and 2014, 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, 2015 and 2014, 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, 2015, aggregated by the level in the fair value hierarchy within which those measurements fall:

Fair Value Assets: Investments: Guaranteed investment certificates Money market Corporate commercial paper Canadian government bonds Institutional Index Fund 500 Index Fund Total Bond Market Index Fund Intermediate-Term Treasury Fund Derivative financial instruments Less amounts classified as current assets

60 BASIN ELECTRIC POWER COOPERATIVE

Fair Value Measurements Using Quoted Prices in Significant Other Active Markets Observable Significant for Identical Inputs Unobservable Assets and Liabilities (Level 2) Inputs

$ 1,136 $ 1,136 $ - $ 134,004 134,004 349,721 349,721 970 970 30,206 30,206 7,918 7,918 18,466 18,466 5,248 5,248 547,669 547,669 32,947 32,947 (219,741) (187,493) (32,248) $ 360,875 $ 360,176 $ 699 $ -

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Fair Value Measurements Using Significant Quoted Prices in Other Active Markets Observable for Identical Significant Inputs Assets and Unobservable Liabilities (Level 2) Inputs

$ 91,557 $ - $ 91,557 $ 8,080 8,080 (1,998) (1,998) $ 97,639 $ - $ 97,639 $ -

The following table summarizes assets and liabilities measured at fair value on a recurring basis as of December 31, 2014, aggregated by the level in the fair value hierarchy within which those measurements fall:

Fair Value Assets: Investments: US Government Treasury Bills and Notes Corporate commercial paper Institutional Index Fund 500 Index Fund Total Bond Market Index Fund Intermediate-Term Treasury Fund Derivative financial instruments Less amounts classified as current assets Liabilities: Interest rate swaps Derivative financial instruments Less amounts classified as current liabilities

Fair Value Measurements Using Quoted Prices in Significant Other Active Markets Observable Significant for Identical Inputs Assets and Unobservable Liabilities (Level 2) Inputs

$ 24,999 $ 24,999 $ - $ 163,445 163,445 29,797 29,797 9,209 9,209 18,391 18,391 5,165 5,165 251,006 251,006 41,001 41,001 (222,799) (188,444) (34,555) $ 69,208 $ 62,562 $ 6,646 $ $ 90,627 $ - $ 90,627 $ 4,573 4,573 (4,573) (4,573) $ 90,627 $ - $ 90,627 $ -

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, 2015 and 2014, 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, 2015 through March 15, 2016, 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 2015 consolidated financial statements.

RECENTLY ISSUED ACCOUNTING STANDARD UPDATES–In May 2014, the FASB issued accounting guidance on the recognition of revenue from contracts with customers, which will supersede nearly all existing revenue recognition guidance under GAAP. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. In August 2015, the FASB issued accounting guidance deferring the effective date by one year. The new guidance will be effective for Basin Electric in 2019. Early adoption is permitted and must be applied retrospectively using one of two prescribed methods. Management is currently evaluating the impact of adoption of this new guidance on our consolidated financial statements and disclosures.

2015 ANNUAL REPORT 61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In April 2015, the FASB issued accounting guidance on simplifying the presentation of debt issuance costs. This update requires that debt issuance costs related to a recognized debt obligation be presented in the balance sheet as a direct deduction from the carrying amount of the debt. The recognition and measurement guidance for debt issuance costs are not affected by the new guidance. The new guidance will be effective for Basin Electric in 2016. Early adoption is permitted and must be applied retrospectively. Management believes the adoption of this new guidance will not have a material impact on our consolidated financial statements and disclosures.

In July 2015, the FASB issued accounting guidance on simplifying the measurement of inventory. This update applies to entities that measure inventory using first-in, first-out (FIFO) or average cost. It requires that inventory be measured at the lower of cost or net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The new guidance will be effective for Basin Electric in 2017. Early adoption is permitted and must be applied prospectively. Management is currently evaluating the impact of adoption of this new guidance on our consolidated financial statements and disclosures.

In August 2015, the FASB issued accounting guidance on the application of the Normal Purchases and Normal Sales scope exception to certain electricity contracts within Nodal Energy Markets. This guidance specifies that the use of locational marginal pricing by an independent system operator does not constitute net settlement of a contract for the purchase or sale of electricity on a forward basis that necessitates transmission through, or delivery to a location within, a nodal energy market, even in scenarios in which legal title to the associated electricity is conveyed to the independent system operator during transmission. Consequently, the use of locational marginal pricing by the independent system operator does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. If the physical delivery criterion is met, along with all of the other criteria of the normal purchases and normal sales scope exception, an entity may elect to designate that contract as a normal purchase or normal sale. The new guidance was effective upon issuance. Management determined the adoption of this new guidance had no impact on our consolidated financial statements and disclosures.

In November 2015, the FASB issued accounting guidance on balance sheet classification of deferred income taxes. To simplify the presentation of deferred income taxes, the accounting guidance requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The new guidance will be effective for Basin Electric in 2018. Early adoption is permitted and may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. Management believes the adoption of this new guidance will not have a material impact on our consolidated financial statements and disclosures (Note 9).

In January 2016, the FASB issued accounting guidance on recognition and measurement of financial assets and financial liabilities. The new guidance improves certain aspects of recognition, measurement, presentation and disclosure of financial instruments. The new guidance will be effective for Basin Electric in 2018. Early adoption of certain provisions of the accounting guidance is permitted as of the beginning of the fiscal year of adoption, however, early adoption of the remaining provisions of this accounting guidance is not permitted. Management is currently evaluating the impact of adoption of this new guidance on our consolidated financial statements and disclosures.

In February 2016, the FASB issued new accounting guidance for leases. The new guidance increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.

The new guidance will be effective for Basin Electric in 2020. Early adoption of the accounting guidance is permitted and must be applied using a modified retrospective approach. Management is currently evaluating the impact of adoption of this new guidance on our consolidated financial statements and disclosures.

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 2016 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, 2015 included various substation and mining equipment with an original cost of $201,704. 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.

62 BASIN ELECTRIC POWER COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Minimum future lease payments under capital leases as of December 31, 2015 for each of the next five years and in the aggregate are : Year 2016 2017 2018 2019 2020 Thereafter Total minimum lease payments Less: Amount representing interest Present value of net minimum lease payments

Amount $ 13,555 12,074 11,275 10,711 10,583 303,075 361,273 175,983 $ 185,290

Interest rates on capitalized leases vary from 2.29 percent to 4.97 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 2016 $ 20,715 2017 19,389 2018 17,822 2019 17,210 2020 17,048 66,569 Thereafter Total $ 158,753 Rental payments charged to expense were $56,146 and $65,279 in 2015 and 2014.

4. JOINTLY OWNED FACILITIES Basin Electric’s investment in the MBPP electric plant was as follows at December 31: Electric plant Less accumulated provision for depreciation and amortization

2015 $ 757,516

2014 $ 758,836

(496,016) (490,027) $ 261,500 $ 268,809

Basin Electric’s share of MBPP operating expenses was $140,930 and $130,794 for 2015 and 2014, 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: 2015 2014 Prepaid coal royalties $ 34,692 $ 36,574 Mine closing fund investments 85,992 62,562 Interest on coal royalties 18,353 19,363 Notes receivable and mine financing costs 1,520 2,895 Other 5,732 6,163 $ 146,289 $ 127,557 Coteau notes receivable with NACoal of $1,446 and $2,807 at December 31, 2015 and 2014 included above bear interest rates varying from 0.25 percent to 0.55 percent.

2015 ANNUAL REPORT 63

NOTES TO 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: Regulatory asset related to deferred income taxes Debt issuance and refinancing fees Regulatory deferred pension expense Unrealized loss on interest rate swaps Unrealized loss on natural gas swaps Other

2015 2014 $ 51,944 $ 59,787 164,569 42,256 11,306 13,425 90,591 89,606 6,199 5,098 23,301 25,792 $ 347,910 $ 235,964

Interest on coal royalties and other costs deferred under ASC 980, totaling $24,086 and $25,526 at December 31, 2015 and 2014, 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), net of tax, on the Consolidated Balance Sheets:

Balance, December 31, 2013 Comprehensive income (loss) Balance, December 31, 2014 Comprehensive loss Balance, December 31, 2015

Unrealized Gain Post Employment Unrealized Loss (Loss) on Cash Benefit Plans on Securities Flow Hedges Total $ (5,977) $ 9,901 $ 11,768 $ 15,692 (16,514) (133) 5,444 (11,203) (22,491) 9,768 17,212 4,489 (1,818) (915) (8,309) (11,042) $ (24,309) $ 8,853 $ 8,903 $ (6,553)

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, 2015, $15,513 of net income tax benefit was closed into Other equity.

RUS guaranteed mortgage notes payable to the FFB, due in quarterly installments through 2033, interest from 1.764% to 7.630% Less funds held by the U.S. Treasury Basin Electric Power Cooperative, First Mortgage Bonds, 2006 Series A due June 2041, interest at 6.127% 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% Basin Electric Power Cooperative, First Mortgage Obligations, 2009 Series B Notes due in semi-annual installments through October 2016, interest at 4.00%

64 BASIN ELECTRIC POWER COOPERATIVE

December 31, 2015

December 31, 2014

$ - $ 1,379,013 (237,517) 200,000

200,000

288,327

294,292

10,833

21,667

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Basin Electric Power Cooperative, First Mortgage Obligations, 2009 Series C Notes due in semi-annual installments through October 2027, interest at 4.89% 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% 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 1.8931% Basin Electric Power Cooperative, First Mortgage Obligations, MetLife 2008 Series A Note Number 2 due May 2032, variable interest at 2.013% Basin Electric Power Cooperative, First Mortgage Obligations, MetLife 2008 Series A Note Number 3 due May 2032, variable interest at 2.0219% Basin Electric Power Cooperative, First Mortgage Obligations, MetLife 2008 Series A Note Number 4 due May 2032, variable interest at 1.8686% Basin Electric Power Cooperative, First Mortgage Obligations, New York Life 2008 Series B Note, due June 2029, variable interest at 1.9005% Basin Electric Power Cooperative, First Mortgage Obligations, John Hancock 2008 Series C Note, due June 2031, variable interest at 1.9170% 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 January 2016 to December 2017, interest at 1.5% Basin Electric Power Cooperative, First Mortgage Obligations, 2015 Series A Notes due in semi-annual installments through June 2027, interest at 3.74% Basin Electric Power Cooperative, First Mortgage Obligations, 2015 Series B Notes due in semi-annual installments through June 2034, interest at 4.10% Basin Electric Power Cooperative, First Mortgage Obligations, 2015 Series BK Notes due in semi-annual installments through June 2034, interest at 4.10% Basin Electric Power Cooperative, First Mortgage Obligations, 2015 Series C Notes due in semi-annual installments through June 2044, interest at 4.74%

December 31, 2015

December 31, 2014

100,000

100,000

110,000

110,000

25,615

27,566

150,000

150,000

45,000

45,000

45,000

45,000

15,000

16,250

9,750

10,500

50,000

50,000

50,000

50,000

50,000

50,000

50,000

50,000

50,000

50,000

50,000

50,000

115,000

120,000

32,500

35,000

100,000

100,000

-

70,000

229,230

229,230

100,000

100,000

95,281

96,979

4,117

3,824

250,000

-

285,000

-

40,000

-

925,000

2015 ANNUAL REPORT 65

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Equipment notes, Series S, due in monthly installments through December 2020, interest at 6.26% Equipment notes, Series X, due in monthly installments through February 2017, interest at 5.70% Equipment notes, Series HH and II, due in monthly installments through July 2020, interest from 5.66% to 6.03% Equipment notes, Series KK, LL and MM, due in monthly installments through November 2020, interest from 5.16% to 5.76% Equipment notes, Series NN and PP, due in monthly installments through July 2020, interest from 2.97% to 3.42% Equipment notes, Series RR, SS, TT and UU, due in monthly installments through July 2021, interest from 1.98% to 2.61% Equipment notes, Series VV, WW and XX, due in monthly installments through November 2024, interest from 2.26% to 3.08% Equipment notes, Series AAA, BBB and CCC, due in monthly installments through September 2022, interest from 2.62% to 3.49% Equipment notes, Series DDD, EEE, FFF, GGG and HHH, due in monthly installments through December 2025, interest from 2.58% to 3.68% Equipment notes due in semi-annual installments through April 2032, interest at 4.10% Dakota Gasification Company, Senior Secured Notes, 2015 Series A Notes due in semi-annual installments through May 2030, interest at 3.66% Dakota Gasification Company, Senior Secured Notes, 2015 Series B Notes due in semi-annual installments through May 2035, interest at 4.33% Dakota Gasification Company, Senior Secured Notes, 2015 Series C Notes due in semi-annual installments through May 2040, interest at 4.01% Other Less current portion: FFB debt Debt, other than FFB

December 31, 2015

December 31, 2014

2,600

3,120

235

436

7,716

10,395

9,688

12,299

2,894

3,857

2,398

2,976

5,540

6,208

2,571

2,986

4,002

4,532

58,081

61,682

50,000

-

200,000

-

225,000 19,069 4,065,447

19,351 3,344,646

(76,136) (41,469) (112,784) $ 4,023,978 $ 3,155,726

The estimated fair value of debt, net of funds held by the U.S. Treasury, at December 31, 2015 and 2014 was $4,001,528 and $3,682,573, 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 for the next five years at December 31, 2015 are as follows:

Long -term debt

2016 2017 2018 2019 2020 $ 41,469 $ 44,494 $ 58,700 $ 90,192 $ 90,036

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.

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.

66 BASIN ELECTRIC POWER COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All of Dakota Gas’ long-term debt is secured under an Indenture dated as of May 1, 2015 between Dakota Gas and U.S. Bank, N.A., as trustee.

Dakota Gas’ long-term debt is also backed by an unsecured Guarantee dated as of May 8, 2015 by Basin Electric, its parent, in favor of U.S. Bank 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. A reconciliation of the beginning and ending amount of the liability for unrecognized tax benefits is as follows: 2015 $ 900 $ 900

Balance at January 1 Addition for tax positions of current period Balance at December 31

Basin Electric recognizes interest and penalties related to unrecognized tax benefits (if any) in the respective interest and penalties expense accounts and not in the Provision for (benefit from) income taxes. 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 (benefit) Deferred tax expense (benefit) Provision for (benefit from) income taxes

2015 2014 $ (548) $ 267 (15,733) 544 $ (16,281) $ 811

The tax effect of significant temporary differences representing deferred tax assets and liabilities were as follows at December 31: 2015 Deferred tax liabilities: Depreciation and property RUS refinancing expense 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 Net operating loss carryforward Other deferred tax assets Total deferred tax assets Net deferred tax liability Current deferred tax liability Noncurrent deferred tax liability

$ 385,870 39,962 36,256 23,147 10,362 495,597

$

(61,983) (18,910) (42,045) (6,549) (120,464) (21,465) (18,191) (289,607) 205,990 11,774 194,216

2014 $ 418,775 28,887 3,193 22,209 14,938 488,002

(64,043) (33,614) (40,737) (5,574) (92,358) (1,239) (16,126) (253,691) 234,311 13,357 $ 220,954

2015 ANNUAL REPORT 67

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

2015 2014 $ (2,872) $ 17,672 (17,284) (1,264)

(18,195) 541 (2,856)

(274) (996) 5,362 4,369 51 276 $ (16,281) $ 811

Basin Electric had available federal and state research tax credit carryforwards of approximately $20,964 and alternative minimum tax credit carryforwards of approximately $21,081 at December 31, 2015. The research tax credits expire in varying amounts from 2019 through 2036. Basin Electric has a consolidated net operating loss carryforward as of December 31, 2015 of $61,300. The net operating loss expires in varying amounts from 2035 through 2036. Basin Electric has a patron federal net operating loss carryforward of approximately $344,200. The patron net operating loss expires in varying amounts from 2028 through 2036. It is more likely than not that deferred tax assets will be recognized before their expiration.

Basin Electric has completed examinations by the Internal Revenue Service (IRS) through 2010. Management does not believe future settlements with the IRS will be material to Basin Electric’s financial position.

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. Implementation of the provisions of the final regulations was completed in 2015 with no material impact to our consolidated 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, Dakota Gas and MLC fund postretirement medical benefits from general funds, and in 2015 and 2014 funding was $1,598 and $1,469.

Coteau funds postretirement medical benefits through a Voluntary Employees Beneficiary Association (VEBA) trust. Coteau did not make any cash contributions to the VEBA in 2015 and 2014.

Coteau also maintains health care and life insurance plans which provide benefits to eligible retired employees.

68 BASIN ELECTRIC POWER COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net periodic postretirement benefit expense for the years ended December 31 includes the following components:

Service cost – benefits attributed to service during the year Interest cost on accumulated postretirement benefit liability Return on plan assets Amortization of prior service credit Amortization of unrecognized loss (gain) Net periodic postretirement benefit expense Other changes recognized in Other comprehensive income (loss): Prior service cost arising during the period Net loss (gain) arising during the period Amortization of prior service credit Amortization of gain (loss) Total recognized in Other comprehensive income (loss)

Basin Electric and Subsidiaries Coteau 2015 2014 2015 2014 $ 2,620 $ 1,863 $ 330 $ 343 1,547 1,558 466 529 (145) (185) (456) (618) (257) (257) (40) (332) 435 427 $ 3,671 $ 2,471 $ 829 $ 857 $ - $ 3,098 $ - $ (2,326) 3,745 1,883 382 456 618 257 257 40 332 (435) (427) $ (1,830) $ 7,793 $ 1,705 $ 212

Assumptions used to determine net periodic postretirement benefit expense were as follows for the years ended December 31: Basin Electric and Subsidiaries 2015 2014 3.82% 4.57% N/A N/A 7.41% 7.82% 4.50% 4.50% 2027 2027

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

Coteau 2015 2014 3.25% 3.85% 6.00% 6.00% 6.75% 7.00% 5.00% 5.00% 2021 2021

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 2015 2014

Coteau 2015

2014

Change in accumulated postretirement benefit liability: Balance at January 1 Service cost Interest cost Actuarial loss Plan amendments Assumption changes Benefit payments Plan participants’ contributions Balance at December 31 Change in plan assets: Fair value of plan assets at beginning of year Actual return on plan assets Employer contributions Plan participants’ contributions Benefit payments Fair value of plan assets at end of year

$ 39,589 $ 30,794 $ 14,461 $ 13,784 2,620 1,863 330 343 1,547 1,558 466 529 1,430 734 1,698 403 3,098 (3,756) 3,011 (4,502) (4,243) (851) (598) 2,904 2,774 $ 39,832 $ 39,589 $ 16,104 $ 14,461

$

$

- $ - $ 2,862 $ (39) 1,598 1,469 2,904 2,774 (4,502) (4,243) (1,103) - $ - $ 1,720 $

3,481 206 (825) 2,862

2015 ANNUAL REPORT 69

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Basin Electric and Subsidiaries 2015 2014 As of December 31, the funded status of the plan was: Accumulated postretirement benefit liability Fair value of plan assets Funded status at end of year Amounts recognized in the balance sheets consist of: Current liabilities Noncurrent liabilities Net amount recognized in balance sheet Amounts not yet reflected in net periodic postretirement benefit expense and included in Accumulated other comprehensive income (loss): Prior service credit (cost) Actuarial gain (loss) Accumulated other comprehensive income (loss)

Coteau 2015

2014

$ 39,832 $ 39,589 $ 16,104 $ 14,461 1,720 2,862 $ 39,832 $ 39,589 $ 14,384 $ 11,599

$

2,287 $ 1,879 $ - $ 37,545 37,710 14,384 11,599 $ 39,832 $ 39,589 $ 14,384 $ 11,599

$ $

(13) $ 7,437 7,424 $

443 $ 133 $ 390 5,151 (5,769) (4,322) 5,594 $ (5,636) $ (3,932)

The Basin Electric plan was amended effective January 1, 2014 to eliminate deductibles and coinsurance for prescription drugs for certain groups.

For Basin Electric and subsidiaries, as of December 31, 2015, $456 of the prior service credit and $258 of the actuarial gain will, through amortization, be recorded as components of net periodic postretirement benefit expense in 2016.

For Coteau, as of December 31, 2015, $137 of the prior service credit and $679 of the actuarial loss will, through amortization, be recorded as components of net periodic postretirement benefit expense in 2016.

Assumptions used in accounting for the postretirement benefit plans obligation were as follows for the years ended December 31:

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

Basin Electric and Subsidiaries 2015 2014 4.22% 3.82% 7.10% 7.41% 4.50% 4.50% 2038 2027

Coteau 2015 2014 3.40% 3.25% 7.25% 6.75% 5.00% 5.00% 2024 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 2015 as follows: Basin Electric and Subsidiaries Coteau 1% Increase 1% Decrease 1% Increase 1% Decrease Accumulated postretirement benefit liability $ 3,796 $ (3,553) $ 1,009 $ (954) Net periodic postretirement benefit expense $ 618 $ (543) $ 56 $ (53) Postretirement benefit plan weighted average asset allocations were as follows:

Equity securities Debt securities Other

70 BASIN ELECTRIC POWER COOPERATIVE

Coteau 2015 2014 81.0% 72.1% 14.7% 24.9% 4.3% 3.0% 100.0% 100.0%

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Basin Electric and its subsidiaries and Coteau expect to make contributions of $2,287 and $0 in 2016 to their postretirement medical plans.

The following are the expected future benefits to be paid:

2016 2017 2018 2019 2020 2021-2025

Basin Electric and Subsidiaries $ 2,287 $ 2,469 $ 2,718 $ 2,767 $ 3,152 $ 15,969

Coteau $ 1,055 $ 1,200 $ 1,409 $ 1,572 $ 1,687 $ 8,738

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 2015 and in 2014 represented less than 5 percent of the total contributions made to the plan by all participating employers. Pension costs charged to expense during 2015 and 2014 were $43,084 and $39,225. There have been no significant changes that affect the comparability of 2015 and 2014 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, 2015 and 2014 was $0 and $10,682.

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 over 80 percent funded at January 1, 2015 and 2014 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.

Certain of Basin Electric’s employees participate in an Executive Benefit Restoration (EBR) Plan established in October 2015. The EBR Plan is a noncontributory defined benefit plan sponsored by Basin Electric. Benefits under the EBR plan are based on the difference between amounts without IRS qualified pension plan limits on compensation and benefits and those with such limits as determined under the provisions of the NRECA RS Plan.

Net periodic pension expense of Basin Electric associated with the EBR for the year ended December 31 include the following components: 2015 Service cost Interest cost Amortization of prior service cost Net periodic pension expense

$ 7 7 41 $ 55

Other changes recognized in Other comprehensive income: Amortization of prior service cost Amortization of actuarial gain Total recognized in Other comprehensive loss

$ 41 7 $ 48

2015 ANNUAL REPORT 71

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The assumptions used to determine net periodic pension expense were as follows for the years ended December 31: 2015 4.04%

Weighted average discount rate Basin Electric expects to make no contributions in 2016.

At December 31, 2015, Basin Electric expects to pay benefits for the next five years and thereafter as follows: 2016 2017 2018 2019 2020 Thereafter $ - $ 19 $ - $ 918 $ - $ The following sets forth the changes in the pension benefit obligation based on the actuary’s analysis as of December 31: 2015 Change in pension benefit obligation: Projected benefit obligation at October 1 Service cost Interest cost Actuarial gain Projected pension benefit obligation at end of year

$ 686 7 7 (6) $ 694

As of December 31, the funded status of the plan was as follows: Projected benefit obligation Fair value of plan assets Funded status at end of year

$ 694 $ 694

Amounts recognized in the balance sheets consist of: Current liabilities Noncurrent liabilities Net amount recognized

$ 694 $ 694

Amounts not yet reflected in net periodic pension expense and included in Accumulated other comprehensive loss: Prior service cost Actuarial gain Accumulated other comprehensive loss

$ 645 (6) $ 639

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, including the effects of estimated future pay increases.

As of December 31, 2015, $162 of the prior service credit and $0 of the actuarial gain will, through amortization, be recorded as components of net periodic pension expense in 2016.

Assumptions used to account for the pension benefit obligation were as follows for the years ended December 31: Weighted average discount rate Rate of increase in compensation levels

2015 4.04% 1.50%

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.

72 BASIN ELECTRIC POWER COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Effective December 31, 2014, current and former employees of Coteau participating in the Combined Defined Benefit Plan were “spun-off” into the new Coteau Pension Plan.

Net periodic pension expense for the years ended December 31 includes the following components:

Interest cost Return on plan assets Amortization of prior service cost Amortization of actuarial loss (gain) Net periodic pension expense (income)

BCS Coteau 2015 2014 2015 2014 $ 181 $ 188 $ 3,749 $ 3,747 (260) (250) (5,891) (5,371) 19 122 95 450 (4) $ 43 $ 33 $ (1,692) $ (1,609)

Other changes recognized in Other comprehensive income (loss): Prior service cost arising during period Net (gain) loss arising during the period Amortization of actuarial gain (loss) Total recognized in Other comprehensive income (loss)

$ - $ - $ - $ (380) (33) 787 914 14,826 (122) (95) (450) 4 $ (155) $ 692 $ 464 $ 14,450

The assumptions used to determine net periodic pension expense were as follows for the years ended December 31: BCS Coteau 2015 2014 2015 2014 Weighted average discount rate 3.55% 4.23% 3.95% 4.75% Expected long-term return on plan assets 7.00% 7.00% 7.75% 7.75% 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 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 2015 Change in pension benefit obligation: Projected benefit obligation at beginning of year Interest cost Actuarial loss (gain) Benefits payments Plan amendments Projected pension benefit obligation at end of year

Coteau 2014

2015

2014

$

5,295 $ 4,649 $ 96,551 $ 80,353 181 188 3,749 3,747 (270) 853 (5,323) 15,880 (386) (395) (3,216) (2,920) (509) $ 4,820 $ 5,295 $ 91,761 $ 96,551

2015 ANNUAL REPORT 73

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

BCS 2015

Coteau 2014

2015

2014

Change in plan assets: Fair value of plan assets at beginning of year Actual return on plan assets Employer contribution Benefits payments Intercompany transfers Fair value of plan assets at end of year

$ 3,762 $ 3,638 $ 81,886 $ 76,000 24 316 (77) 5,911 324 203 2,194 (386) (395) (3,216) (2,920) (268) 701 $ 3,724 $ 3,762 $ 78,325 $ 81,886

As of December 31, the funded status of the plan was as follows: Projected pension obligation Fair value of plan assets Funded status at end of year

$ 4,820 $ 5,295 $ 91,761 $ 96,551 3,724 3,762 78,325 81,886 $ 1,096 $ 1,533 $ 13,436 $ 14,665

Amounts recognized in the balance sheets consist of: Current liabilities Noncurrent liabilities Net amount recognized

$

- $ - $ - $ 1,096 1,533 13,436 14,665 $ 1,096 $ 1,533 $ 13,436 $ 14,665

Amounts not yet reflected in net periodic pension expense and included in Accumulated other comprehensive income (loss): Actuarial loss

$ 2,448 $ 2,603 $ 17,838 $ 17,375

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, 2015, $229 of the Coteau actuarial loss and $122 of the BCS actuarial loss will, through amortization, be recorded as components of net periodic pension expense in 2016.

Assumptions used to account for the pension benefit obligation were as follows for the years ended December 31: BCS Weighted average discount rate

2015 3.80%

2014 3.55%

Coteau 2015 2014 4.30% 3.95%

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 is the actual and target allocation percentages for the NACoal Plan assets at the measurement date: 2015 Actual Allocation Target Allocation Range U.S. equity securities 52.3% 41.0% – 62.0% Non-U.S. equity securities 12.2% 10.0% – 16.0% Fixed income securities 35.2% 30.0% – 40.0% Money market 0.3%

0.0% – 10.0% 100.0%

74 BASIN ELECTRIC POWER COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following is the actual and target allocation percentages for the BCS Plan assets at the measurement date: 2015 Equity securities Fixed income securities Other

Actual Allocation 41.4% 53.4% 5.2% 100.0%

Target Allocation Range 37.0% 60.0% 3.0% 100.0%

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.

BCS and Coteau expect to make no contributions in 2016 to their defined benefit plans. The following are the expected future benefit payments for the BCS Plan and the Coteau Pension Plan: 2016 2017 2018 2019 2020 2021-2025

BCS $ 378 $ 367 $ 356 $ 346 $ 336 $ 1,536

Coteau $ 3,475 $ 3,789 $ 4,088 $ 4,436 $ 4,771 $ 27,903

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 $10,931 and $9,176 for 2015 and 2014.

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 $2,595 and $99 related to this plan in 2015 and 2014.

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 $2,270 and $2,208 in 2015 and 2014.

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.

11. DEFERRED CREDITS, TAXES AND OTHER LIABILITIES Deferred credits, taxes and other liabilities were as follows at December 31: Non-current deferred income tax liability, net Asset retirement obligations and other reserves Pension and benefit obligations Long-term hedge liability MBPP operating advances Deferred gain on sale of electric plant Unearned revenue Regulatory deferred post-retirement obligation Regulatory deferred revenue Other

2015 2014 $ 194,216 $ 220,954 97,361 129,175 83,904 84,689 97,639 90,627 29,207 29,207 2,333 3,084 3,783 8,927 8,927 22,884 15,000 4,618 10,470 $ 541,840 $ 595,165 2015 ANNUAL REPORT 75

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2015 were $335,513 in 2016, $380,837 in 2017, $407,292 in 2018, $402,387 in 2019, $372,477 in 2020, and $5,365,212 thereafter. Amounts purchased under the contracts totaled $256,346 in 2015 and $275,322 in 2014.

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 Consolidated Balance Sheets. At December 31, 2015 and 2014, the assets and liabilities of Corn Belt included in the Consolidated Balance Sheets totaled $16,123 and $17,053. 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 $515,843 as of December 31, 2015.

Coteau has outstanding equipment commitments of $7,139 as of December 31, 2015.

INVENTORY PURCHASE COMMITMENTS–Coteau entered into various diesel fuel contracts through February 2017. The estimated commitments under these purchase contracts as of December 31, 2015 were $11,566.

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 Freedom Mine closing.

During 2015 and 2014, Dakota Coal paid $211,775 and $212,634 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.

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 $3,123 and $3,126 in 2015 and 2014. Coteau made payments of $311 and $3,970 in 2015 and 2014 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.

76 BASIN ELECTRIC POWER COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2015 and 2014 was approximately $18.54 and $20.06 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 2015 and 2014 was approximately $8.65 and $9.76 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, 2015 and 2014 are as follows: Issue Date 12-15-10 05-03-11 05-03-11 05-03-11 05-03-11 12-30-11 12-30-11 05-16-14 09-19-14 11-10-15

Term 32 years 7 years 7 years 5 years 5 years 7 years 5 years 7 years 7 years 5 years

Interest Rate 5.15% 5.61% 5.61% 4.97% 4.97% 4.35% 3.85% 5.08% 4.99% 4.72%

Original Loan Value 20,457 109 180 183 302 257 445 2,366 6,165 761

Borrower WFW WFW WFW WFW WFW WFW WFW WFW WFW WFW

Purpose Coal conveyance equipment-DFS Mine capital spares- LRS Basin share Mine capital spares-DFS Mine inventory spares-LRS Basin share Mine inventory spares-DFS Mine capital spares-DFS Mine inventory spares-DFS Equipment purchase- LRS Basin share Equipment purchase- LRS Basin share Land Purchase-LRS Basin share Less current portion

2015 2014 $ 19,612 $ 19,929 46 62 76 102 183 183 302 302 123 160 445 445 1,831 2,169 5,603 3,349 752 28,973 26,701 (1,861) (1,134) $ 27,112 $ 25,567

The estimated fair value of these notes receivable at December 31, 2015 and 2014 was $36,907 and $35,405, 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 has 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 2015 exceeds $14,000 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.

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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 Addition for new mine area Other additions Balance, December 31

2015 2014 $ 69,458 $ 70,000 (355) (4,435) 3,880 3,801 15,505 248 92 $ 88,736 $ 69,458

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, 2015, the aggregated value of these guarantees is $131,400.

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, 2015, 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

CFC Syndicate of Eleven Banks Syndicate of Twelve Banks Royal Bank of Canada

Maturity 03-18-18 11-14-19 11-06-18 12-30-17

Total Availability $ 130,000 $ 500,000 $ 400,000 $ 50,000

Outstanding Advances as of December 31, 2015 $ 129,925 $ 364,833 $ $ 50,000

As of December 31, 2015, the effective interest rate of the outstanding advances is 0.477%.

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 two contracts involving commitments for the sale of CO2. One of these contracts is to sell and deliver CO2 from the Synfuels Plant to oil fields located near Weyburn, Saskatchewan. The Weyburn agreement is for a 15-year term ending in April 2016, which may be extended by the buyer with at least 120 days prior written notice for up to ten one-year renewals. The buyer has elected to extend the agreement for one year. 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.

The second 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’

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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.

BNSF RAILWAY COMPANY (BNSF) SETTLEMENT–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 Laramie River Station (LRS) were 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 for the period October 2004 through March 2009. BNSF appealed this STB decision to the D.C. Circuit Court of Appeals (the D.C. Circuit). 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 was recorded as a liability reserve for unearned revenue, included in Deferred credits, taxes and other liabilities on the Consolidated Balance Sheets, until such time as there was a final, non-appealable decision.

On May 11, 2010, the D.C. Circuit decided two of the three issues in favor of Western Fuels/Basin Electric. On the third issue, the D.C. Circuit remanded the decision back to the STB. On January 31, 2011, after receiving comments on the remanded issue from BNSF, the STB re-opened the record. On June 15, 2012, the STB provided the detailed recommendation on their allocation and affirmed its earlier decision. On July 23, 2012, BNSF appealed this STB decision to the D.C. Circuit. On January 31, 2014, the D.C. Circuit remanded the case back to the STB. On January 28, 2015, Western Fuels/Basin Electric and BNSF filed a joint petition with the STB asking the STB to hold the remanded case in abeyance. In this filing, the parties informed the STB that they had reached a preliminary settlement agreement that called for the dismissal of the case. The parties also informed the STB that the preliminary agreement was contingent upon the parties’ development and execution of a rail transportation contract.

The estimated settlement obligation was recorded by the MBPP in December 2014. Basin Electric and BNSF executed the settlement on May 13, 2015.

The LRS rail rate case was finalized in June, 2015, with the STB having upheld $100,000 in cash refunds paid from BNSF to MBPP. The settlement resulted in approximately $530,000 in rail rate reductions for MBPP. CLEAN POWER PLAN–On October 23, 2015, the Environmental Protection Agency (EPA) published the Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units; Final Rule (the Rule). The Rule establishes guidelines for states to develop plans to reduce CO2 emissions from fossil fuel-fired electric generating units. In those states where Basin Electric owns and operates a substantial amount of fossil fuel-fired generation (North Dakota and Wyoming), the required reductions to be achieved by 2030 are substantial (45% and 44%, respectively).

Basin Electric filed a request with the EPA for administrative stay pending judicial review of the Clean Power Plan final rule on October 30, 2015.

No response has been received to date.

Basin Electric also filed with the D.C. Circuit Court of Appeals (D.C. Circuit) a petition for review of the Rule on October 29, 2015 and a motion to stay the Rule on November 5, 2015. The D.C. Circuit consolidated the petitioners for judicial efficiency. The D.C. Circuit denied the consolidated petitioners’ motions to stay the Rule on January 21, 2016. The consolidated petitioners then appealed to the Supreme Court of the United States via emergency petition on January 26, 2016. The Supreme Court granted the petitioners’ request to stay the Rule on February 9, 2016.

Unlike prior EPA Clean Air regulations, the determination of what steps must be taken to comply with the Rule is the responsibility of state environmental agencies and not individual utilities. Thus it is difficult, if not impossible, to provide an accurate forecast of the likely cost of compliance if the Rule survives judicial scrutiny. Subject to that caveat, Basin Electric believes if the Rule is upheld by the courts, these costs would be substantial.

WYOMING BART–The Regional Haze provisions of the Clean Air Act require that facilities that commenced construction between 1962 and 1977 identify and apply Best Available Retrofit Technology (BART) to control sulfur dioxide (SO2) and nitrous oxide (NOX) emissions if their emission rates for those pollutants exceed a certain designated levels. All three LRS units exceed the presumptive levels for NOX under the BART guidelines promulgated by the EPA in 2005. Basin Electric engaged in negotiations with the Wyoming Department of Environmental Quality (DEQ) from 2007 to 2009 relating

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to the NOX emission levels for all three LRS units and the associated emission controls to operate LRS within the designated levels. The DEQ issued its BART determination in 2009. Under the Wyoming State Implementation Plan (SIP), LRS was required to install over-fire air technology to reduce NOX emissions below the presumptive level for Unit 1 in 2009, Unit 2 in 2010 and Unit 3 in 2011 and to also install new “Low-NOX burners” for Unit 1 in 2012, Unit 2 in 2013 and Unit 3 in 2014. These controls were installed at LRS in accordance with the scheduled outlined in the Wyoming SIP. The EPA published its final rule on January 30, 2014, disapproving the Wyoming SIP for NOX controls at LRS. The EPA’s Federal Implementation Plan instead required installation of Selective Catalytic Reduction (SCR) equipment on all three LRS units by March 2019 in order to meet a NOX emission limit of 0.07 pounds per million British thermal units (BTU) on a thirty day rolling average.

On March 31, 2014, Basin Electric filed a Petition for Review with the 10th Circuit Court of Appeals of the EPA’s NOX determination requiring the installation of three SCRs at LRS. The 10th Circuit Court of Appeals granted a stay on September 9, 2014 that extends the time for compliance for the duration of the litigation. This appeal is ongoing. Oral arguments are currently scheduled for the March 2016 term of court, though are not expected to occur until the May term. The cost of one SCR is expected to exceed $300,000.

The EPA did approve Wyoming’s SIP for BART as it applies to LRS SO2 emissions. Environmental groups appealed that approval and a decision was issued in 2014 upholding that part of the Wyoming’s BART determination as it relates to SO2.

ENVIRONMENTAL PROTECTION AGENCY SECTION 114(a)-LRS–In September 2011, Basin Electric received a Section 114(a) letter from the EPA requesting information about certain projects at LRS. Responsive documents were submitted and the EPA responded by requesting additional information on twenty-five specific projects. The EPA subsequently contacted Basin Electric regarding specific work that was performed on the Unit 3 superheater in 2011. Discussions have been conducted with the EPA regarding whether this work constituted ordinary maintenance or constituted capital improvements that required a permit to construct. Basin Electric and the EPA Region 8 Enforcement have conducted discussions and have signed a tolling agreement extending the statute of limitations for the Unit 3 superheater investigation while LRS personnel conduct optimization studies of current operations at LRS Unit 3.

13. RELATED PARTY TRANSACTIONS Other receivables include $2,679 and $2,862 at December 31, 2015 and 2014, for amounts Basin Electric, as operating agent, and its subsidiaries, have billed to MBPP. Included in Special funds in the Consolidated Financial Statements is Basin Electric’s advance to MBPP of approximately $12,346 at December 31, 2015 and 2014.

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. • LIMESTONE SALES–Dakota Coal provides limestone to Basin Electric’s LOS. • 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.

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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: 2015 2014 Power supply from Basin Electric to Dakota Gas $ 63,536 $ 85,724 Power sales from PrairieWinds ND to Basin Electric $ 15,462 $ 16,269 Power sales from PrairieWinds SD to Basin Electric $ 21,863 $ 22,643 Screened coal sales from Dakota Gas to Basin Electric $ 63,489 $ 61,251 Coal supply sales from Dakota Coal to Basin Electric $ 58,457 $ 60,155 Administrative services by Basin Electric to Dakota Gas $ 23,616 $ 17,633 Administrative services by Basin Electric to Dakota Coal $ 2,935 $ 2,295 Administrative services by Basin Electric to PrairieWinds ND $ 903 $ 846 Administrative services by Basin Electric to PrairieWinds SD $ 1,247 $ 1,176 Administrative services by Basin Electric to BTI $ - $ 627 Lime sales from Dakota Coal to Basin Electric $ 12,650 $ 9,956 Limestone sales from Dakota Coal to Basin Electric $ 3,412 $ 3,650 Water supply from Basin Electric to Dakota Gas $ 2,896 $ 3,266 Natural gas sales from Dakota Gas to Basin Electric $ 1,364 $ 627 Project services from Basin Electric to Dakota Gas $ 388 $ 367 Various other intercompany management, administrative and financial services were performed, which were not significant.

This Annual Report contains forward-looking statements. When used in this report, and future reports or communications, either written or oral, such words as “may,” “will,” “expect,” “anticipate,” “continue,” “estimate,” “project,” “believes,” or similar expressions, are intended to identify forward-looking statements. Such statements are based on current expectations and assumptions, and entail various risks and uncertainties that could cause actual results to differ from those expressed in forward-looking statements.

2015 ANNUAL REPORT 81

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