2016 Annual Report Basin Electric Power Cooperative by Basin Electric

B A S I N E L E C T R I C P O W E R C O O P E R AT I V E

STRONG

UNITED 2016 ANNUAL REPORT

CONTRIBUTORS Contributors Editor:Andrea AndreaBlowers Blowers Editor: (ablowers@bepc.com) (ablowers@bepc.com)

INFORMATION REQUESTS Basin Electric Power Cooperative Communications Communications & Administration 1717 East Interstate Avenue Bismarck, ND 58503-0564 Phone: 701.223.0441 www.basinelectric.com

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GraphicDesigner: Designer: Graphic NicolePerreault Perreault Nicole Photographers: Photographer: ChelsyCiavarella Ciavarella Chelsy & Greg DeSaye This 2016 Annual Report was written, compiled, and produced by the employees of Basin Electric Power Cooperative and its subsidiaries.

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CONTENTS AT A GLANCE

MEMBERSHIP

OPERATIONAL EXCELLENCE

MEMBER SUPPORT GROWTH

COMMITMENT TO COOPERATIVE WORKFORCE

FINANCIAL INFORMATION

FIVE-YEAR CONSOLIDATED FINANCIAL SUMMARY 39

INDEPENDENT AUDITORSâ&#x20AC;&#x2122; REPORT 40

CONSOLIDATED BALANCE SHEETS 4 1

CONSOLIDATED STATEMENTS OF OPERATIONS 42

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) 43

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY 43

CONSOLIDATED STATEMENTS OF CASH FLOWS 44

FINANCIAL STABILITY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 45 2016 ANNUAL REPORT

PRESIDENT

GENERAL MANAGER MESSAGE

STRONG C

Wayne Peltier

Paul Sukut

BASIN ELECTRIC POWER COOPERATIVE

UNITED

hallenges and difficult situations are not new for Basin Electric. Our history is full of ups and downs, milestones, pivotal decisions, and triumph over challenges. Woven throughout are themes of perseverance and loyalty by the cooperative’s members, employees, leaders, and friends. Together, through it all, we, as a cooperative family, have remained strong and united – undivided by challenges. In 2016, there were more than a few. We faced challenges like the Clean Power Plan, which as written in the final rule, is a dramatic shift from the proposed rule. We put a lot of effort into fighting the rule legally, legislatively, and in the states we serve because of its potential to impact our end consumers. On the positive side, the rule provided focus for our work toward advancing clean coal technologies, and as such Basin Electric finalized a lease and operating agreement with the Wyoming Integrated Test Center at Dry Fork Station; and pursued opportunities with technology like the Allam Cycle, which potentially would gasify lignite coal to produce synthetic natural gas. We showed our resiliency through the mild weather, which created a compounding financial deficiency with the drastic and sudden drop in commodity prices resulting in margin shortfalls. The cooperative also experienced an influx of wind into the region. Wind offered at extremely low prices in the Southwest Power Pool market overwhelmed coal-based generation resulting in a need to back down coal plants, and for a short time, forced the cooperative to respond with an economic shutdown of Leland Olds Station Unit 1. All together these events spurred a difficult decision by the board of directors to implement a 7-mill rate increase across the membership. The directors scrutinized all possible scenarios and financial models to ensure they could reach the most astute conclusion. In the end, the rate increase was approved under the condition the cooperative continue its austerity program. And it has continued. Employees exceeded expectations watching every dollar and considering more efficient ways of doing their work and managing assets. We recognize it hasn’t been easy, but the employees are committed and diligent

because they know they work for our members. All the Gasification Company’s Great Plains Synfuels Plant, conefforts combined ensured Basin Electric was able struction also continued on the development of to close the year in a financially the new urea processing facility. The facilstable position. ity is 65 percent complete, though Our decision For the last three years, the it’s been an uphill project. From to raise rates carried sigboard and staff have been Mother Nature’s demolition of nificant weight. Long before the engaged in strategic planthe storage building in July rate increase was decided, we directed ning. From this comes an to other challenges causBasin Electric staff to enter into an austerity annual cooperative plan. ing unexpected delays, the program. They did, and they surpassed our It’s our compass ensuring overall cost of the project expectations. And, when we passed the rate employees and members and anticipated completion increase, we directed staff to continue the know where we are, where date have shifted. program into the foreseeable future. we’re headed, and why we’re Even with those setbacks, - Wayne Peltier doing what we’re doing. the Synfuels Plant will still be President Our focus centers on four key in a good position to help keep areas: operational excellence, member the cooperative strong with its support and growth, commitment to cooperative, and ever-growing portfolio of diverse products. commitment to workforce. In all of these areas, we must We’re also working to ensure we maintain a statake into account the external forces that shape our ble, engaged workforce. Staff pursued a number of direction: a carbon-constrained future, commodity risk, efforts during the year to further connect employees and emerging technologies. All of our efforts incorpowith the cooperative business model and the cooperarate continuous improvement with an emphasis on tive’s membership. Those efforts include the People. safety through the Our Power, Power. Purpose. series, Building Co-op ConMy Safety process. nections, and a new program called For the last three Our nine-state service area EmPOWER, focused on youth in our years, we’ve been engaged in is a broad footprint, and one that communities. strategic planning. Out of this comes requires due diligence to ensure With all we faced in 2016, an annual cooperative plan, so all our we can continue to reliably the year could have left us employees and members understand serve a growing membership. feeling defeated. But, having where we are, where we’re headed, and This has required substantial a greater purpose and driven why we’re doing what we’re doing. investments, but the Bakken to consistently fight for what’s - Paul Sukut region has stabilized with needed best for our members, we are CEO & General Manager transmission infrastructure and hopeful that the co-op way will trangas-peaking capacity. scend the challenges that threaten Throughout the year, we continued to divide us. We are not defeated. We conversations with Minnkota Power Cooperative about are hopeful. We are empowered. We are united. potential Class A membership, and we welcomed MonWe are all in this together, and we couldn’t be more tana distribution co-ops Fergus Electric and Tongue honored to serve you. River as Class C members through Members 1st Electric Cooperative, a new Class A generation and transmission cooperative formed by PRECorp; and Mid-Yellowstone as a Class C member through Upper Missouri. At Dakota WAYNE PELTIER PAUL SUKUT President CEO & General Manager 2016 ANNUAL REPORT

AT A GLANCE

BOARD OF DIRECTORS 11 DISTRICTS

Dakota Valley Electric Cooperative members Jayson and April Corell and their kids Bryson and Miya.

CEO & GENERAL MANAGER

RESOLUTIONS COMMITTEE

DIRECTORS

Les Mehlhaff, District 1 David Meschke, District 2 Mark Brehm, District 3 Louis C. Reed, District 4 Jack Finnerty, District 5 Melanie Roe, District 6 Richard Schneider, District 7 David Sigloh, District 8 Dean Hummel, District 9 Philip Habeck, District 10 Donald Feldman, District 11 Mike McQuistion, Board Rep. 4

BASIN ELECTRIC POWER COOPERATIVE

3 MILLION MEMBER CONSUMERS

141 MEMBER

BYLAW REVIEW COMMITTEE

CO-OPS

GENERAL MANAGERS DIRECTORS Thomas Boyko, District 1 Curt Dieren, District 2 Tom Meland, District 3 Matthew Washburn, District 4 Mike McInnes, District 5 Doug Hardy, District 6 Vic Simmons, District 7 Claire Vigesaa, District 8 Kevin Mikkelsen, District 9 Mike Easley, District 10 Ken Kuyper, District 11

James Ryken, District 1 Aryln Zylstra, District 2 Mark Brehm, District 3 Louis C. Reed, District 4 Melanie Roe, District 6 Richard Schneider, District 7 David Sigloh, District 8 Tim Velde & Casey Wells, District 9 Reuben Ritthaler, District 10 Donald Feldman, District 11

A BASIN ELECTRIC POWER COOPERATIVE SUBSIDIARY

A DAKOTA COAL COMPANY SUBSIDIARY

2,300 EMPLOYEES

A DIVISION OF DAKOTA COAL COMPANY

SUBSIDIARIES

STATE SERVICE TERRITORY

. PRAIRIEWINDS SD 1, INC.

PRAIRIEWINDS ND 1, INC.

PRAIRIEWINDS SD 1, INC.

A BASIN ELECTRIC POWER COOPERATIVE SUBSIDIARY

PRAIRIEWINDS SD 1, INC.

3.4%

3.0%

OIL/DIESEL/ UNSPECIFIED JET FUEL

A DAKOTA GASIFICAITON COMPANY SUBSIDIARY

EXTERNAL DIRECTORS

17.0%

2,300+

NATURAL GAS

MILES HIGH-VOLTAGE TRANSMISSION

0.7%

RECOVERED ENERGY

20.1%

6,031 MW MAXIMUM WINTER GENERATION CAPACITY END OF YEAR 2016

WIND

ALAN KLEIN Dakota Gas director since 2013. Retired partner of Eide Bailly LLP.

JIM GERINGER Dakota Gas director since 2012. Governor of Wyoming 1995-2003.

49.6% COAL

1.0% 5.2%

NUCLEAR

HYDRO

2016 ANNUAL REPORT

DISTRICTS

DIRECTORS

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 District 9 members, which Basin Electric serves directly. In addition, the directors serve on the boards for subsidiaries Dakota Gas/Souris Valley Pipeline Ltd., Dakota Coal Company/Montana Limestone Company, Basin Cooperative Services, PrairieWinds ND 1 Inc., and PrairieWinds SD 1 Inc.

UPPER MISSOURI POWER COOPERATIVE SIDNEY, MT | District 8

ALLEN THIESSEN Basin Electric director since 2012 and electric cooperative board member since 1986. Serves on the PrairieWinds boards and as treasurer on Dakota Gas/Souris Valley Pipeline Ltd. boards. 1 Burke-Divide Electric Cooperative 2 Goldenwest Electric Cooperative 3 Lower Yellowstone Rural Electric Association

4 McCone Electric Cooperative 5 McKenzie Electric Cooperative 6 Mid-Yellowstone Electric Cooperative

7 Mountrail-Williams Electric Cooperative 8 Roughrider Electric Cooperative 9 Sheridan Electric Cooperative

10 Slope Electric Cooperative 11 Southeast Electric Cooperative

CENTRAL MONTANA ELECTRIC POWER COOPERATIVE

RUSHMORE ELECTRIC POWER COOPERATIVE

GREAT FALLS, MT | District 6

RAPID CITY, SD | District 7

ROBERTA ROHRER

MIKE MCQUISTION

Basin Electric director since 2004 and electric cooperative board member since 1979. Serves on PrairieWinds boards and as chairman of Dakota Coal/Montana Limestone boards.

Basin Electric director since 2013 and electric cooperative board member since 1996. Serves on PrairieWinds boards and as treasurer on Dakota Coal/Montana Limestone boards.

1 Big Flat Electric Cooperative 2 Hill County Electric Cooperative 3 Marias River Electric Cooperative

1 2 3 4

* McCone Electric Cooperative

4 5 6 7

NorVal Electric Cooperative Park Electric Cooperative Sun River Electric Cooperative Yellowstone Valley Electric Cooperative

Black Hills Electric Cooperative Butte Electric Cooperative Cam Wal Electric Cooperative Cherry-Todd Electric Cooperative

5 6 7 8

Lacreek Electric Association Moreau-Grand Electric Cooperative West Central Electric Cooperative West River Electric Association

TRI-STATE GENERATION & TRANSMISSION ASSOCIATION WESTMINSTER, CO | District 5

LEO BREKEL Basin Electric director since 2014 and electric cooperative board member since 1995. 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 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 La Plata Electric Association 17 Midwest Electric

Niobrara Electric Association Northern Rio Arriba Electric Cooperative Northwest Rural Public Power District Otero County Electric Cooperative Panhandle Rural Electric Membership Association 27 Poudre Valley Rural Electric Association Cooperative Corporation 28 Roosevelt Public Power District 18 Mora-San Miguel Electric Cooperative 29 San Isabel Electric Association 19 Morgan County Rural Electric Association 30 San Luis Valley Rural Electric Cooperative 20 Mountain Parks Electric 31 San Miguel Power Association 21 Mountain View Electric Association 32 Sangre de Cristo Electric Association 22 23 24 25 26

33 Sierra Electric Cooperative 34 Socorro Electric Cooperative 35 Southeast Colorado Power Association 36 Southwestern Electric Cooperative 37 Springer Electric Cooperative 38 United Power 39 Wheat Belt Public Power District 40 Wheatland Rural Electric Association 41 White River Electric Association 42 Wyrulec Company 43 Y-W Electric Association

* Cooperatives that buy power from two districts are identified by their number in their voting district. 6

BASIN ELECTRIC POWER COOPERATIVE

EAST RIVER ELECTRIC POWER COOPERATIVE MADISON, SD | District 1

KERMIT PEARSON | Vice President Basin Electric director since 1997 and electric cooperative board member since 1981. Serves on Dakota Gas/Souris Valley Pipeline Ltd. and PrairieWinds boards. 1 Agralite Electric Cooperative 2 Bon Homme Yankton Electric

8 Dakota Energy Cooperative 9 Douglas Electric Cooperative 10 FEM Electric Association 11 H-D Electric Cooperative 12 Kingsbury Electric Cooperative 13 Lake Region Electric Association 14 Lyon-Lincoln Electric Cooperative

Association Central Electric Cooperative Charles Mix Electric Association City of Elk Point, SD Clay-Union Electric Corporation Codington-Clark Electric Cooperative

3 4 5 5 6 7

15 Meeker Cooperative Light

& Power Association 16 Northern Electric Cooperative 17 Oahe Electric Cooperative 18 Redwood Electric Cooperative 19 Renville-Sibley Cooperative Power Association Sioux Valley Energy

20 South Central Electric Association 21 Southeastern Electric Cooperative 22 Traverse Electric Cooperative 23 Union County Electric Cooperative 24 Whetstone Valley Electric

Cooperative

CENTRAL POWER ELECTRIC COOPERATIVE

NORTHWEST IOWA POWER COOPERATIVE

MINOT, ND | District 3

LE MARS, IA | District 4

TROY PRESSER

DON APPLEGATE

Basin Electric director since 2015 and electric cooperative board member since 2007. Serves on Dakota Coal/Montana Limestone and PrairieWinds boards.

Basin Electric director since 1997 and electric cooperative board member since 1966. Serves on PrairieWinds boards and as chairman of Dakota Gas/Souris Valley Pipeline Ltd. 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

MEMBERS 1ST POWER COOPERATIVE SUNDANCE, WY | District 10

1 Harrison County Rural

Electric Cooperative 2 Iowa Lakes Electric Cooperative 3 Nishnabotna Valley Rural Electric Cooperative 4 North West Rural Electric Cooperative

55 Western Iowa Municipal Electric

Association (Anthon, Aurelia, Hinton, Manning, Mapleton, and Onawa) 6 Western Iowa Power Cooperative 7 Woodbury County Rural Electric Cooperative

PAUL BAKER Basin Electric director since 2013 and electric cooperative board member since 1994. Serves on PrairieWinds boards and as vice chairman of Dakota Coal/Montana Limestone boards. 1 Fergus Electric Cooperative 2 Powder River Energy Corporation

3 Tongue River Electric Cooperative

L&0 POWER COOPERATIVE ROCK RAPIDS, IA | District 2

HUMBOLT, IA | District 11

CHARLIE GILBERT Basin Electric director since 2009 and electric cooperative board member since 1997. Serves on PrairieWinds boards and as vice chairman on Dakota Gas/Souris Valley Pipeline Ltd. boards. 1 Boone Valley Electric Cooperative 2 Butler County Rural Electric

GARY DROST

Secretary/Treasurer Basin Electric director since 1999 and electric cooperative board member since 1987. Serves on Dakota Gas/Souris Valley Pipeline Ltd. and PrairieWinds boards. 1 Federated Rural Electric Association 2 Lyon Rural Electric Cooperative

CORN BELT POWER COOPERATIVE

3 Osceola Electric Cooperative 4 Sioux Valley Energy

Cooperative

3 Calhoun Rural Electric Cooperative 4 Franklin Rural Electric Cooperative 5 Grundy County Rural Electric

Cooperative Iowa Lakes Electric Cooperative

6 7 8 99

Midland Power Cooperative Prairie Energy Cooperative Raccoon Valley Electric Cooperative North Iowa Municipal Electric Cooperative Association (Algona, Alta, Bancroft, Coon Rapids, Graettinger, Grundy Center, Laurens, Milford, New Hampton, Spencer Sumner, Webster City, West Bend)

2016 ANNUAL REPORT

MEMBERSHIP Basin 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 3 million consumers in parts of North Dakota, South Dakota, Wyoming, Colorado, Minnesota, Iowa, Nebraska, Montana, and New Mexico.

3 2

7 3

1 9

7 5

22 42 28

40 2

23 26

37 18

3 34 25

8 3

6 5 9

9 9

79 6

DISTRICT 9 WAYNE PELTIER

5 5 49 5

6 5 4

32 30

3 9

21 10

12 3

1 11

16 17

11 2

2 6

6 3

President Basin Electric director since 2008 and electric cooperative board member since 1999. Serves on Dakota Coal/Montana Limestone boards and chairman of PrairieWinds boards. 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 Flathead Electric Cooperative

2016 ANNUAL REPORT

The Davidson family – grandpa David, daughter Nikki, and grandkids Caden and Bella – own land near Tioga, ND, with two transmissions lines, a 230-kilovolt line and a 345-kilovolt line, running through it.

BASIN ELECTRIC POWER COOPERATIVE

When you do look at the long-term performance of DGC (Dakota Gas), it’s been a net positive for Basin Electric. - Tom Boyko

We’ve seen growth. The new growth comes at a higher cost today than it did in the past. The higher costs are the result of EPA rules, regulations. Those types of things are driving our costs more today than ever. - Brad Schardin General Manager, Southeastern Electric Cooperative

That diversity we have among our membership is strength. It’s a luxury we have; to go through some storms we’d otherwise not make it through. - Doug Hardy General Manager, Central Montana Electric Power Cooperative

CEO and General Manager, East River Electric Power Cooperative

Mid-Yellowstone is one of the smaller co-ops in Montana and to have a firm, solid power supplier and support is worth its weight in gold to the membership. - Jason Brothen Manager, Mid-Yellowstone Electric Cooperative

BASIN ELECTRIC POWER COOPERATIVE

FACILITIES

SUBSIDIARIES OPERATIONAL EXCELLENCE

OPERATIONAL OPERATIONAL EXCELLENCE

asin Electric’s focus on excellence is exemplified in its safety and operational milestones. Milestones are achieved each year because employees are focused on continuously improving in all areas of operation, with safety at top of mind. Providing employees with the tools and training helps to ensure they focus on doing things right.

GENERATION

Employees and contractors worked through a 10-week maintenance outage at the Antelope Valley Station in the spring.

The entire cooperative fleet consists of four baseload coal-fired power plants, one intermediate natural gas combined-cycle, several peaking power plants that run on natural gas and oil, and wind generation. Each resource has intrinsically unique operational requirements and challenges, and the baseload units fueled by coal have been the object of significant scrutiny in recent years. Even so, the facilities consistently operate within 100 percent environmental compliance. There is no question coal is a reliable and inexpensive fuel, and Basin Electric remains committed to the Dakota Coal Company coal operations as well as the operations that support the cooperative’s baseload coal fleet, including Montana Limestone Company and Wyoming Lime Producers. Supplying Dakota Coal is The Coteau Properties Company’s Freedom Mine, which provides coal to Leland Olds Station, Antelope Valley Station, and the Great Plains Synfuels Plant. The team at Coteau works to ensure the lowest possible cost fuel to the cooperative’s facilities. In 2016, the mine’s efforts to keep costs down included an innovative dragline maintenance project the team developed, which saved millions of dollars in repair costs and time. This year Wyoming Lime Producers, a division of Dakota Coal, was able to extend the partnership it has with the operator Pete Lien & Sons another 10 years. In August, Wyoming Lime reached 3 million tons of lime produced. The lime facility and Montana Limestone Company quarry both achieved safety milestones during the year.

Optimizing coal facilities Coal, lime, and limestone are vital to the reliability of Basin Electric’s baseload resources. During the year, several of the baseload units operated close to 95 percent availability. Basin Electric’s triennial maintenance outage schedule

BASIN ELECTRIC POWER COOPERATIVE

L EXCELLENCE ensures these facilities are maintained to run safely and efficiently while keeping the cost of these outages as low as possible. Every baseload facility except Leland Olds Station had an outage during the year. In addition, several projects were under way or completed at each of the facilities. At Antelope Valley Station, Unit 2 had a 10-week maintenance outage in the spring. Some of the work included installing a separated over-fire air system; low NOx (nitrogen oxides) burners; and switching the startup fuel from fuel oil to natural gas. Crews also completed installation of mercury control technology as well as adding six new monitoring wells to comply with the Coal Combustion Residuals Rule. In June, Unit 2 turned 30 years old. At Leland Olds Station, the facility opened the year celebrating 50 years in operation on Jan. 10. Some of the work completed at the facility included commissioning of the SNCR (selective non-catalytic reduction) technology for regional haze compliance and the temporary bottom ash dewatering project. A permanent solution is under construction. Employees at the facility achieved 3 million man-hours without a lost-time accident. The Laramie River Station units are running well. Unit 2 had a six-week maintenance outage, which included change out of the air heater baskets. The Coal Focus Team worked to improve the safety and operation of the coal handling system, and crews began construction on the SCR (selective catalytic reduction) system for Unit 1.

Employees work in an environment where they may be working at heights of 600 feet, with equipment that operates at temperatures of 1,008 degrees and pressures in the 2,400-2,500 psi range, and inclement weather. They have to take all sorts of different things into consideration to do their jobs, and that’s on an everyday basis. We can never take safety for granted.. - John Jacobs Senior Vice President of Operations

Re-imagine CO2

Basin Electric and the Wyoming Municipal Power Agency finalized a lease and operating agreement with the Wyoming Integrated Test Center (ITC) to facilitate the next generation of clean carbon technology. The agreement allows the ITC to be built and operated at the Dry Fork Station. The ITC will use 20 MW of actual coal-based flue gas from the facility. Along with testing capture technologies, Gov. Matt Mead additional research will use flue gas and turn it into a marketable commodity. Pre-construction engineering and design work started in 2015, and some equipment installation took place during the facility’s outage in 2016. As Wyoming Gov. Matt Mead says, he “can’t wait to see what great minds come up with to re-imagine CO2. The innovations will be breathtaking and make a profound difference in the future of coal.” In July, a total of 47 entries from seven countries applied to contend for the $20 million NRG COSIA Carbon XPRIZE. An advisory board of nine leading experts in the fields of chemical and biological engineering, energy and sustainability, and public policy, are advising the Carbon XPRIZE. The board narrowed the field of contenders to 15 teams and, in early 2017, the final five teams will be selected. Each of the five teams will be awarded a $2.5 million prize and after a two-year test period, the board will award the winner a $7.5 million prize. In addition, Basin Electric is reviewing potential technology providers to use the large test center to evaluate clean coal alternatives using between five and 18 MW of flue gas at Dry Fork Station. That organization will be chosen in 2017. The ITC is slated to be the second in the United States, and will be one of the few research and testing facilities at an operating coal-based power plant. It’s scheduled to be complete in the summer of 2017. 2016 ANNUAL REPORT

OPERATIONAL EXCELLENCE

Dry Fork Station also had an outage in March and April, the plantâ&#x20AC;&#x2122;s first major outage since beginning operation in 2011. In addition to a number of electrical and instrumentation projects, flash tank modifications were completed and crews installed a permanent retractable maintenance deck in the boiler. They also installed the guillotine damper for the Wyoming Integrated Test Center.

megawatts of wind and natural gas generation. The development of these resources was simultaneous because of the intermittency of wind and the need to supplement that using a more stable fuel source, natural gas, that has the ability to start up quickly. The distributed generation fleet will include more than 2,500 megawatts (MW) of wind and peaking resources during the first quarter of 2017. HRSG enclosure at Deer Creek Station. Diverse resource mix Within the distributed As the cooperative worked to generation operations, Deer help create a path forward for these Creek Station ran more than expected and other coal resources, it also worked to during the year and, due to the number of diversify its generation fleet by adding hundreds of run hours on the gas turbine of the combine cycle, a

POLLUTION CONTROL COSTS Facility (dollars in thousands) Antelope Valley Station

Capital Costs Life-to-Date $ 390,956.1

2016 Operations & Maintenance, Depreciation & Interest $

35,738.1

Culbertson Generation Station

Deer Creek Station

Dry Fork Station

Groton Generation Station

4,543.0

270.9

Laramie River Station (Basin Electric only)

198,365.8

11,142.6

Leland Olds Station

452,132.4

43,141.2

Lonesome Creek Station

13,830.1

822.0

Pioneer Generation Station

13,377.1

782.0

Spirit Mound Station

Subtotal: Basin Electric

Dakota Coal/Montana Limestone Company

Dakota Gasification Company

Subtotal: Subsidiaries Total: Basin Electric & subsidiaries

4,818.9

263.2

28,584.8

2,165.2

310,963.0

26,590.3

99.8

0.5

1,417,671.0

120,916.0

26,948.7

2,981.7

199,488.8

44,766.9

226,437.5

47,748.6

$ 1,644,108.5

168,664.6

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.

BASIN ELECTRIC POWER COOPERATIVE

major outage and inspection was undertaken. Work to enclose the HRSG (heat recovery system generator) continued during the year to increase reliability. The cooperative’s peaking facilities operated well during the year and exceeded the budgeted megawatt hours of operation, in part because of low

natural gas prices. Basin Electric’s Lonesome Creek Unit 2 ran for 45 days straight in July and August. PrairieWinds subsidiaries’ wind resources also operated well and experienced about 97 percent availability. Crews completed blade repairs and preventative maintenance during the year.

ELECTRIC OPERATING HIGHLIGHTS Energy Sales (in millions of megawatt hours)

2016

2015

% change

23.0

22.7

1.3

5.9

6.9

(14.5)

28.9

29.6

Wyoming sub-bituminous

7.9

8.5

(7.1)

North Dakota lignite

8.2

8.5

(3.5)

16.1

17.0

4.1

4.0

To Class A and Class D members To others Total

(2.4)

Coal Consumed (in millions of tons)

Total Forced-outage rate (five-year average)

(5.3) 0.2

DAKOTA GASIFICATION COMPANY OPERATING HIGHLIGHTS Revenue (in millions) Synthetic gas sales Byproduct, coproduct and other sales Interest and other income Total Synthetic gas sold (dekatherms in millions) Coal consumed (tons in millions)

2016

2015

% change

$ 126.6

$ 187.6

(32.5)

185.5

274.2

(32.3)

2.7

6.2

(56.5)

$ 314.8

$ 468.0

(32.7)

56.3

56.4

(0.2)

6.0

6.1

(1.6)

DAKOTA COAL COMPANY OPERATING HIGHLIGHTS Revenue (in millions)

Coal Sales Lime Sales Limestone sales Interest and other income Total

2016

2015

% change

$ 205.4

$ 218.0

(5.8)

14.1

14.3

(1.4)

6.8

5.9

15.3

2.7

3.9

(30.8)

$ 229.0

$ 242.1

(5.4)

14.1

14.4

(2.1)

142.9

155.0

(7.8)

Sales (in tons) Coal (in millions) Lime (in thousands)

2016 ANNUAL REPORT

POWER RE OPERATIONAL EXCELLENCE

OWNED As of spring 2017

OPERATED

ANTELOPE VALLEY STATION Beulah, ND • 900 MW • 2 units

LELAND OLDS STATION Stanton, ND • 666 MW • 2 units

DRY FORK STATION Gillette, WY • 385 MW • 1 unit

LARAMIE RIVER STATION Wheatland, WY • 1,710 MW • 3 units

Basin Electric has a 92.9-percent ownership share.

Basin Electric has a 42.27-percent ownership share.

COAL BASELOAD GAS INTERMEDIATE GAS PEAKING OIL PEAKING WIND 16

BASIN ELECTRIC POWER COOPERATIVE

DEER CREEK STATION Elkton, SD • 300 MW • 1 Unit

ESOURCES CULBERTSON GENERATION STATION Culbertson, MT 95 MW • 1 unit

LONESOME CREEK STATION Watford City, ND 225 MW • 5 units

EARL F. WISDOM STATION UNIT 2 Spencer, IA 80 MW • 1 unit

GROTON GENERATION STATION Groton, SD 196 MW • 2 units

PIONEER GENERATION STATION Williston, ND 247 MW • 15 units

SPIRIT MOUND STATION Vermillion, SD 120 MW • 2 units

Basin Electric has a 50-percent ownership share. It’s operated by Corn Belt Power Cooperative.

Minot, ND • 122.6 MW

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

White Lake, SD • 162 MW

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

WYOMING DISTRIBUTED GENERATION Hartzog, Arvada, and Barber Creek, WY 54 MW • 9 units

Chamberlain, SD • 2.6 MW

2016 ANNUAL REPORT

OPERATIONAL EXCELLENCE

TRANSMISSION

Though member growth has slowed, the transmission planning team was still actively engaged in studies Basin Electric’s transmission team works to provide and strategy development. The slowdown in growth safe, secure, and reliable power to the co-op members, allowed time to complete needed transmission projects no matter the weather or time of day. in western North Dakota. Twice a year, linemen participate in live line training. Spring training is conducted on wood poles, and fall Grid reliability and regulations training on steel towers. The training focuses on safety Adhering to transmission grid regulations and ensurexercises, like self-rescue, cart-rescue and tower rescue ing reliability, the North American Electrical Reliability of an incapacitated co-worker. Corporation (NERC) sets and enforces standards In addition to updates and repairs, Transthat address the reliable operation of the mission System Maintenance electric grid on two fronts: operations crews tackled several projects We approached and planning, and cyber and physduring the year. (load growth in the Bakken) in ical security. At the Antelope Valley phases involving generation, transmisBasin Electric has assets Station 345-kilovolt (kV) sion, and the market. … The transmission was in two NERC regions: WECC switchyard substation, built in segments, which was part of risk miti(Western Electricity Coordithey installed new protecgation in case the growth slowed down, which nating Council) for western tive relaying and control it has, so we’re evaluating that. system operations, and MRO equipment for the Ante- Mike Risan (Midwest Reliability Organilope Valley to Charlie Creek Senior Vice President of Transmission zation) for eastern system 345-kV line. The new equipoperations. ment is also being installed at The MRO region conducts the Charlie Creek substation. quarterly guided self-certifications. The transmission team also The WECC region performs the traditional sixsupported the cooperative’s transyear audit, with Basin Electric’s last audit occurring in 2015. mission system build-out by commissioning and placing By the end of 2016, Basin Electric compliance staff and into service Roundup, Patent Gate, and Kummer Ridge west-side member cooperatives completed the mitiga345/115 kV substations. tion plan for the issues identified in the 2015 WECC audit. The telecommunication staff completed the installaStarting in 2017, Basin Electric and member coopertion of new microwave radios and associated equipment at atives will implement a new NERC Compliance Program 61 sites in North Dakota and South Dakota in the spring.

TRANSMISSION System

Joint Ownership

Southwest Power Pool

Basin Electric Maintained 1,709

Common Use

Basin Electric, Black Hills Power, Powder River Energy Corporation

279

346

Missouri Basin Power Project

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

288

301

43 2,356

84 2,440

Other Total Basin Electric Miles

Basin Electric Owned 1,746

BASIN ELECTRIC POWER COOPERATIVE

MRO WECC

to intervene and protest. In October 2016, a settlement was reached with the intervening parties. The settlement means Basin Electric receives an annual revenue requirement for transmission cost reimbursement that’s about the same as the cooperative initially filed. After a full year of membership in SPP, staff is confident Basin Electric’s membership made the right decision in joining the RTO for its east-side operations. For its west-side operations, over the last two years, Basin Electric and a number of neighboring utilities, including Class A member Tri-State and Western Area Power Administration, have been exploring similar RTO options to improve efficiencies and derive value on behalf of the membership. The group is called Mountain West Transmission Group. Additional work to explore potential west-side RTO participation will be ongoing through 2017 and beyond.

designed to clarify the roles and responsibilities assigned to Basin Electric and member co-ops for the identified member-owned Bulk Electric System (BES) facilities and equipment. Additionally, Version 5 of the NERC critical infrastructure protection (CIP) standards went into effect July 1. It applies to secur ing cyber assets that support the Within CIP 5, Basin BES. Version 5 of the CIP stanElectric identified 13 mediumdards impact Basin Electric in The establishment of a impact facilities and 180 low-impact many ways. Physical secuwest-side RTO presence cerfacilities. For the medium-impact rity is another element of tainly poses challenges, but facilities, Basin Electric must impleCIP standards Basin Electhe benefits have the potenment all of the CIP 5 standards and tric must comply with and tional to outweigh them. For requirements. This new version of at the beginning of the example, as wind and other CIP standards is very significant to year staff enhanced securenewable energy sources Basin Electric. The transition requires rity at substations identified continue to expand generaa tremendous amount of crossas medium impact. tion, the RTO ensures the loads cooperative coordination. can benefit from generation addi-

MARKETS

Regional transmission participation

In 2016, Basin Electric completed its first full year of operation in the Southwest Power Pool (SPP) regional transmission organization (RTO). As a member of SPP, Basin Electric operates its system on a broader basis and now recovers eastern interconnection transmission costs through SPP, which is regulated by the Federal Energy Regulatory Commission (FERC). Basin Electric engaged in the process in May 2015, filing a formulary rate to recover transmission costs effective Oct. 1, 2015. The filing prompted some SPP parties

tions while minimizing the impact of transmission and congestion. Regarding Basin Electric’s membership in SPP, the generation facilities responded very well to the dispatch signals from the market, and the market itself performed as expected. The cooperative is capturing positive financial benefit from being a member of SPP versus being outside the market – even in a commodity down cycle paired with a long period of mild weather. While national natural gas production and inventories remained high, loads were below average due to the mild temperatures. 2016 ANNUAL REPORT

OPERATIONAL EXCELLENCE

Wind energy in the market

for hedging; scheduling; and load management, workAdditionally, SPP added a lot of wind generation. ing directly with the membership to manage load in the During late winter/early spring, with loads down, at one most efficient way possible. point wind generation accounted for 49.5 percent of SPP’s During the year, Basin Electric also took a fresh look energy resources in the market. at its load management program as one of a number Given the amount of must-run coal baseload generof continuous improvement options to add more value ation and the gas peaking generation running to the membership. to regulate the wind generation, a glut of We completed our energy saturated the market, so prices Dakota Gas commodities first year in SPP, one year in the became very soft, resulting in lower As a commodity production organization and with books. We believe it was the right values for the cooperative’s generdepressed prices across commodity markets throughout decision for Basin Electric and our memation in the marketplace. Likewise, the year, staff remained focused on finding new ways bership, and we are realizing benefits in the it resulted in lower replacement or to help stabilize revenue and expenses. They looked at marketplace, true economic benepurchased power cost for loads. management of rail agreements and fuel surcharges, fits as a result of joining. As Basin Electric migrated through achieving price certainty for ammonia sales and man- Ken Rutter the low-price environment, units aging the pipeline capacity the cooperative owns to Senior Vice President of Marketing & Asset responded appropriately by backmove natural gas produced by Dakota Gas. Management ing down so Basin Electric’s members The unique operating structure of the Synfuels could realize fuel savings and lower Plant affords Dakota Gas some flexibility to choose the purchased power costs. most cost-effective product to produce at any given The cooperative’s mine-mouth coal plants have a distime. In the spring, ammonia sales were strong, and tinct advantage over other coal plants in the country that were within the top three years in terms of overall ammopay very high coal transportation costs. This benefit nia with more than 100,000 tons sold. Staff was able will continue to help the plants experience to work around operational challenges to Basin high capacity factors well into the future. ensure product was available. Electric is still in a Dakota Gas commodity staff unique situation of being Peaking resources meets daily to determine the dayone of the few generation and Basin Electric’s gas peaking ahead commodity values and transmission co-ops experiencplants offer a unique benefit. Iniproduction levels. The informaing growth, and the co-op remains tially, they were added for reliability tion allows them to adjust the focused on transmission service within growing load pockets, and production plan. and grid reliability for the with the new 345-kV transmission A significant project in 2016 entire system. line, capacity factors were expected involved continuous improvement, to drop. The ability to get inexpensive gas specifically relating to transportain the north made those peaking resources ecotion. From pipelines to trucks and trains, nomical in the marketplace. employees strive to choose the most cost-effective The cooperative continues to monitor all its offers in transportation option. A cross-departmental team the marketplace, as well as restructuring them to ensure reviewed ideas and identified several savings opporBasin Electric is capturing sufficient margins from the martunities that Basin Electric and Dakota Gas will continue ket to operate the generating units. to benefit from in the future. To do that, the cooperative runs models for load and The group’s efforts to bring more value to Dakota wind forecasting; price forecasting to help the day-ahead Gas through new customers continued by adding new and real-time traders; congestion forecasting; performance tar oil and natural gas customers. 20

BASIN ELECTRIC POWER COOPERATIVE

SERVICE

INNOVATION MEMBER SUPPORT

GROWTH

MEMBER SUPPO MEMBER SUPPORT

GROWTH

asin Electric was created to provide low-cost, reliable electricity to its members. It’s a focused mission, and one that has endured for more than five decades. While distributed generation and self-supply have become options, the economics and risks they carry are rarely better than what the cooperative can do with economies of scale and a united front.

PROJECTS

Clyde Moch is the operation maintenance supervisor at the Lonesome Creek Station. Lonesome Creek is adding two units, 90 MW, to Basin Electric’s resource portfolio in 2017.

BASIN ELECTRIC POWER COOPERATIVE

To ensure its mission continues, Basin Electric’s engineering and construction, planning and right of way, and environmental services teams were busy in 2016 with several generation, transmission, and process projects. Construction wrapped up on Phase III of Pioneer Generation and Lonesome Creek stations, two natural gas peaking plants in northwestern North Dakota. Phase III of the Pioneer Generation Station project near Williston, ND, added 112 MW of peaking capacity using 12 natural gas-based Wärtsilä reciprocating engines. These engines are a first for Basin Electric. They began commercial operation in January 2017. At Lonesome Creek Station near Watford City, ND, commercial operation of Units 4 and 5 began in spring 2017. The additional units at Lonesome Creek employ General Electric LM 6000 combustion turbine generators. A third unit is permitted for future installation. Construction continues on the 200-mile Antelope Valley to Neset transmission project to improve reliability in western North Dakota and eastern Montana. Work is under way on the final phase of the project, a 65-mile 345/115-kV line with Class C member Mountrail-Williams Electric Cooperative. Crews also completed foundation work and setting structural steel as part of the new 345-kV Tande substation, located near Tioga, ND. The contractor worked through the winter and plans to complete the substation by October 2017. Modification to the 345-kV Neset substation will complete construction on the Antelope Valley to Neset project in October 2017. Additional transmission construction includes the North Killdeer Loop project. Phase I is approximately 60 miles of 345-kV transmission line and three substations that will deliver power into Class C member McKenzie Electric Cooperative’s service territory.

ORT

GROWTH

Five transformers in four weeks

In June and July, five transformers for the North Killdeer Loop project were delivered: two each to the Patent Gate and Kummer Ridge substations, and one to the Roundup substation. It took transportation contractors four weeks to deliver all five transformers – one by one – from Dickinson, ND, to their appropriate site, using a 31-axle semi-truck. Due to the heavy gross weight, contractors used a push-pull concept for delivery, which alleviated stress on the truck pulling cargo and ensured adequate power to climb the steep grades on the route.

The final portion of Phase I, the Patent Gate to Kummer Ridge transmission line and Kummer Ridge substation, was energized Sept. 27. These substations tie directly into member co-op systems and have spare bays for future member growth. There are also a number of member construction projects on the distribution system.

Sustained winds at nearly 80 miles per hour collapsed the steel frame of the approximately 150,000-square foot building. The steel frame was about 80 percent complete and siding was about 10 percent complete before it was destroyed. Fortunately, the winds did not damage the process construction areas, allowing construction there to continue as soon as power was restored. Dakota Gas Additionally, contractor issues perpetuated delays diversification At Dakota Gas’ Great and increases in the cost Plains Synfuels Plant, of the project further construction is about challenged the project. 65 percent complete However, Basin Electric on the urea production has taken over as genfacility project, which will eral contractor and a new Though the project has experienced setbacks, the ultimately produce 1,100 contractor was secured construction of the urea facility at the Great tons of urea daily, with for piping work. Plains Synfuels Plant is about 65 percent the ability to shift from urea Even with the delays and complete and on track for completion in 2018. production to produce diesel added costs, the project still exhaust fluid (DEF) and sell liquemaintains a positive rate of return fied carbon dioxide (CO2). based on current projections. The projWork continues on the project on parallel ect is slated for completion in early 2018. construction paths. The process areas, logistics and The urea plant is one of a number of capital investcommon facilities are all being constructed at the same ments at Dakota Gas. Since Basin Electric purchased time. Much of the foundation, structural steel and equipthe plant in 1988, Dakota Gas has made capital improvement setting has been completed as have the new power ments totaling $820 million through 2016. These efforts supply and control room. include projects to increase plant production, such as Unfortunately, the project faced challenges. The gasifier utilization and process unit debottlenecking, as partially complete urea storage building was destroyed well as product diversification projects like carbon dioxby strong winds at the construction site in early July. ide, phenol, cresylic acid, fertilizers, and krypton/xenon.

2016 ANNUAL REPORT

MEMBER SUPPORT

GROWTH

Maintaining regulatory compliance

Technology development

While all of the projects under construction within In addition to the ITC at Dry Fork Station, Basin ElecBasin Electric support a growing membership and innotric is working to assist in the development of some vative opportunities, there are a number of projects innovative technologies that could help preserve the that address changing environmental role of fossil fuels in a carbon-constrained world. Among regulations. them are a potential CO2 sequestration project with the Much of our time In January, the board approved Energy and Environmental Research Center (EERC) and goes to support existing assets, the SCR (selective catalytic reducthe Allam Cycle. but projects are where we come tion) project for Unit 1 at Laramie The vision for the Allam Cycle consists of gasifying together and do most of our work with othRiver Station. Installing the SCR lignite coal to produce synthetic natuers in the organization. … Our work is a lot like required the bulk warehouse to ral gas, which would then be used a relay race. We spend a lot of time either getBasin Electric be targeted for demolition as along with oxygen and CO2 to drive ting a baton or giving a baton after executing formed the Horizons moving it was not cost-effective. a turbine generator, all without a portion of a project. Committee to monitor Construction of a new 300-foot increasing the cost of produc- Matt Greek and disseminate inforSenior Vice President by 180-foot bulk warehouse was ing electricity. Basin Electric of Engineering & mation regarding new completed during the year. and ALLETE have committed to Construction technologies. The SCR technology is a contributing matching funds and process where an ammonia-based in-kind services to support the work. reagent is sprayed into flue gas, converting nitrogen oxides Joining Basin Electric’s Horizons Team into nitrogen and water, which is then released through the in looking to a carbon-constrained future is the Enviair heater, scrubber, and emissions stack. The equipment is ronmental Regulatory Activities Committee, formed by scheduled to be operational in 2019. the cooperative during the year. The cross-deEmission control technology that cappartmental team’s purpose is to monitor, tures mercury was installed at other review and evaluate all current and In September, facilities including both units at proposed environmental regulaBasin Electric worked with the the Antelope Valley Station, all tory activities that may impact Lignite Energy Council and ALLETE three units at the Laramie River the cooperative. Energy to take a North Dakota delegation Station, and both units at the of state legislators and energy industry repLeland Olds Station. CapturA benefit to resentatives to Texas to study the Allam Cycle. ing mercury emissions involves the cooperative The demonstration site in Texas could be folinjecting activated carbon, The common thread is lowed by a large demonstration project in which is a reagent that reacts consistent long-term viability. North Dakota tied to Dakota Gas, which with the mercury emissions proThe Synfuels Plant is an examwould run on either natural gas or duced from coal combustion. ple of that. On average, Dakota gasified coal. Additionally, construction was Gas provides about $90 million in complete in 2016 on the Leland Olds Stabenefits to Basin Electric annually. Econtion SNCR project. omies of scale between the electric operations of the cooperative, and the Dakota Gas byproduct operations have provided financial stability and benefits over the While Basin Electric tackles projects, the cooperative years to both sides of the business. The cooperative has looks ahead to opportunities for advanced coal technoloreduced coal costs, among many other benefits, because gies, recognizing that innovation is critical to the long-term of how the coal is shared between Antelope Valley, Leland viability of the cooperative and its subsidiaries. Olds, and the Synfuels Plant.

OPPORTUNITIES

BASIN ELECTRIC POWER COOPERATIVE

The ongoing analysis of Dakota Gas’ Great Plains Synfuels Plant continues to show that the plant provides an annual benefit of about $90 million to the membership. The operation of the plant also contributes to the energy economy of the state and region. Following is the 2016 production of each commodity and examples of its end use. In addition, the percentage of revenue attributed to each product is noted.

$90 MILLION

ANNUAL BENEFIT

CRUDE CRESYLIC ACID 21.8 million pounds

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

AMMONIUM SULFATE 137.5 thousand tons

PHENOL

Dak Sul 45® fertilizer

26.9 million pounds

NAPHTHA

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

8.9 million gallons

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

2.2%

TAR OIL 1.7% 0.5%

halogen headlights and light bulbs, lasers, window insulation

CARBON DIOXIDE

fuel

10.5%

fuel

3.3 million liters

40.1 million dekatherms

3.1%

28.9 million gallons (salable)

KRYPTON XENON GASES

NATURAL GAS

2.4%

8.7%

31.6 billion standard cubic feet (salable) 0.0%

2016 TOTAL

$312.1

40.5%

IN MILLIONS

enchanced oil recovery

LIQUID NITROGEN

29.5%

109.2 thousand gallons

0.9%

coolant, refrigerant, preservative

ANHYDROUS AMMONIA 205.9 thousand tons

OTHER

agricultural fertilizer 2016 ANNUAL REPORT

MEMBER SUPPORT

GROWTH

In 2016, the Synfuels Plant had a half-plant Staff at the plant continue to mitigate risk by enhancing outage to allow staff to complete needed programs such as pipeline reliability and maintenance. maintenance including repairs on the The pipeline integrity program monitors nearly solvent distillation overhead separa250 miles of pipeline. Pipeline internal gauges, known tor in the phenol recovery unit; as as pigs, are used to collect important data. With new well as work on the Riley boilers technology, the plant has gone from running several and ammonia plant. pigs a year to capture data, to one. The continued focus for Austerity and fiscal responsibility are also comDakota Gas is investigatponents of risk mitigation, and employees have ing opportunities to further participated fully in the cost-cutting process. They diversify its products to mitiare active in reviewing daily processes, procedures, gate risk. and actions to identify ways to save dollars, and they The Revenue Generaare committed to continue cutting costs, minimize tion and Diversification team expenses, increase revenues, and improve efficiency. at Dakota Gas pursued and evalAll of these efforts have translated into a continuous Claude O’Berry, Dakota Gasification uated opportunities to upgrade improvement initiative in 2017. Company pipeline superintendent, existing products. The team remains The Synfuels Plant is linked by design to Antelope works to maintain the integrity of the carbon dioxide pipeline. focused on the goals set forth in the coopValley and the Freedom Mine sharing services, coal, erative plan. These include a process to further water, and power supply. Dakota Gas is also linked reduce the plant’s environmental footprint, diverwith the membership, having paid $230 million in sify revenue, enhance safety, and improve compliance dividends to Basin Electric over the years. programs. These dividends have helped keep Examples include installation the mill rate low when electric Dakota Gas was of a mercury emissions control sysrates at utilities across the actually able to beat our revised tem; improved efficiencies in the nation steadily increased. budget in every controllable cost cateammonia plant; minimized prodgory in 2016. We’re very proud of the people uct freight costs by implementing at Dakota Gas for doing that. In all areas they suggestions from the Logistics Understanding all came in under budget, so we very much Continuous Improvement team; and responding to appreciate the efforts by the employees. and an enhanced safety culture the needs of the mem- Dave Sauer through a new Management of bership also helps. Senior Vice President & Change process. When the cooperative’s COO of Dakota Gas Aligning Dakota Gas’ safety, 2016 load forecast was health, security, and environmental complete in January, efforts is the Responsible Care® cerit showed power needs tification. Every three years the plant is across the membership were audited by a third party. In late 2016, the facility received projected to increase 1,360 MW from 2015 to 2035. notification it was recertified. That’s growth of 1.4 percent annually. At the close of Mechanical integrity and continuous improvement the year and into 2017, an updated forecast projected programs all play a part in achieving success within the about 1,145 MW of growth or 1.1 percent annually program. Responsible Care focuses on measuring risk. across the membership.

PLANNING

BASIN ELECTRIC POWER COOPERATIVE

Serving the membership

Basin Electric has four different regions to plan The member load forecast is the main tool for transfor: Midcontinent ISO (MISO), SPP, Montana, and the Colmission and power supply planning. It’s fundamental to orado/Wyoming area. Each region essentially requires financial forecasting and used to establish rate compoevaluation and balance of generation with load. nents. The load forecast shows the magnitude of each In Colorado and Wyoming, there is excess genmember’s load growth or decline proeration primarily due to reduced coal-bed jected over 20 years. It’s reviewed methane extraction and reduced Several of Basin and approved by each member coal mining load levels. In Electric’s members have system and then presented to Montana, power purasked about incorporating Basin Electric directors each chase agreements were solar as a resource option. The year for approval. Through executed through 2025 cooperative is considering how the process, Basin Electric to supplement the power to best incorporate both small and load forecasting staff works deliveries into the region large solar into our generation fleet, and with the membership and from eastern interconnecwe continue to work with the membership as we reviews the granular details: tion resources. develop a solar resource strategy. meter counts for each load In MISO, Basin Electric Dave Raatz classification, rural residential has resource obligations and Senior Vice President of versus seasonal residential, street power purchase agreements in Cooperative Planning lights and irrigation accounts, small place to meet MISO load obligaand large commercial usage, and timelines tions through 2022. In SPP, the for new large loads coming online. cooperative evaluated power purchase and new reIn 2016, staff expanded the efforts to evaluate the source economics. dynamics across the membership. Cooperative Planning started a supplemental annual load forecasting process Additional renewable generation to capture a broader view of member load levels. It only Through the resource planning process, the cooperconsiders the big drivers that can affect electricity sales ative evaluated the possibility of entering into additional quickly, but supplements the more detailed process. The wind power purchase agreements. In October, the board evaluation is now completed three times per year. authorized execution of a PPA for 200 MW of additional Cooperative Planning is also looking at loads that wind generation with NextEra Energy Resources called could potentially be lost or economically supplied by other the Burke Wind Project, with the option to expand this sources through market purchases or self-generation, purchase before October 2017 to 300 MW. It will be comcalled loads at risk. The ultimate objective is to keep memmercial in late 2019. With the new wind PPA contract ber rates low. execution, Basin Electric expands its wind portfolio to Power purchase agreements (PPA) are one tool the 1,600 or 1,700 MW by the end of 2019. cooperative uses to do so. In February, Basin Electric As the year closed, three wind projects for which issued a Request for Proposal, or RFP, for power supply Basin Electric signed PPAs began commercial operaproposals within both the eastern and western intertion. The Sunflower Wind Project, declared commercial connections. Through this process, 85 proposals were Dec. 22 and located near Hebron, ND, has a maximum received totaling more than 9,000 MW of power supcapacity of 104 MW; and Brady Wind I Energy Center ply, with 1,900 MW short-listed for detailed review and and Brady Wind II Energy Center, located adjacent to evaluation. one another near New England, ND, are composed of

2016 ANNUAL REPORT

MEMBER SUPPORT

GROWTH

174 turbines with a maximum capacity of 300 MW. These projects are also owned by NextEra Energy Resources. The projects were declared commercial Nov. 21 and Dec. 27, respectively, and added 404 MW of capacity to the cooperative’s portfolio.

Rate increase in 2016 One of the most challenging decisions in 2016 was the board’s approval of an intra-year Class A member rate increase of approximately 7 mills effective Aug. 1. The drivers impacting it were lower-than-anticipated member sales; reduced revenue from non-member sales; added costs to operate PURPA was generation facilities; generation enacted in 1978 in part and transmission investments; to require utilities to buy power and reduced revenue support from qualifying facilities. If a qualifyfrom non-electric or subsidiary ing facility is developed, such as hydro, businesses. wind, or solar, the utility has an obligaThe new 2016 demand tion to buy it at its avoided cost. This and energy rate components obligation trumps Basin Electric’s were held constant into 2017, all-requirement power supply conand the average Class A rate for tracts with its members. 2017 is estimated to be 64.2 mills per kilowatt-hour. Changes to other rates include modification of the solar purchase rate. Starting Jan. 1, 2017, the rate was renamed the Renewable Resource Pass-through Rate. It continues to allow Basin Electric to purchase the net generation from solar, wind, hydro, or biomass generation projects, up to 150 kilowatts (kW) in size, from consumer- or member-owned projects at Basin Electric’s avoided cost. Several members asked about incorporating solar energy as a resource option, so Basin Electric is considering how to best incorporate both small and large solar resources into its generation fleet. Through 2016, the cooperative helped with the development of small solar projects located within member distribution systems primarily in Iowa, South Dakota, and Minnesota through financial incentives. Basin Electric’s goal is to maintain the lowest cost of power possible for the collective membership, and the membership took steps to help meet that goal, through 28

BASIN ELECTRIC POWER COOPERATIVE

assignments of Public Utility Regulatory Policies Act (PURPA) obligations for projects 150 kilowatt (kW) or more to Basin Electric.

New members Basin Electric has grown in the number of distribution cooperative members. At the start of 2016, three new member cooperatives were slated to join Basin Electric beginning Oct. 1, 2017. However, over the course of the year, the parties agreed to move the date to Jan. 1, 2017. In Montana, Class A member Upper Missouri welcomed Mid-Yellowstone Electric. Fergus Electric and Tongue River Electric became members of a new cooperative called Members 1st Power Cooperative, which will be represented in District 10. PRECorp, which was previously represented as a Class A member in District 10 became a Class C member of Members 1st Power Cooperative. Further due diligence also continued in 2016, with the possible addition of Minnkota Power Cooperative, headquartered in Grand Forks, ND, as a Class A member. Work continues to reach a conceptual agreement and an evaluation of the economics.

Mid-Yellowstone Fergus

Members 1st Power Cooperative

Tongue River PRECorp

PEOPLE FACILITIES

COMMUNITIES SUBSIDIARIES COMMITMENT TO COOPERATIVE OPERATIONALWORKFORCE EXCELLENCE

COMMITMENT COOPERATIVE COMMITMENT TO COOPERATIVE

WORKFORCE

asin Electric has long known the nation is moving toward a carbon-constrained future, and the cooperative has been engaged in all levels of energy politics to ensure its members’ interests are represented. A significant dilemma for utilities in recent years is the U.S. Environmental Protection Agency’s (EPA) Clean Power Plan (CPP). Though the final rule was overwhelming, it followed the path already paved by numerous other regulations for future energy generation. Basin Electric remains at the forefront of this issue and others to ensure the cooperative, its membership, and employees are poised for the future.

GOVERNMENT

Basin Electric employees (from left) Kevin Solie and Darrell Schulz plant a replacement tree on private land near PrairieWinds 1 south of Minot, ND.

BASIN ELECTRIC POWER COOPERATIVE

As written, the CPP presents challenges for electric generators and communities. Of the 13 states hit the hardest by it, eight are in Basin Electric’s service territory. Compounding the problem is the required two-thirds compliance by 2022. As proposed, the CPP gave Basin Electric no credit for recent investments in natural gas generation or renewable resources, nor Basin Electric’s carbon sequestration efforts through Dakota Gas. On Jan. 21, 2016, the D.C. Circuit Court denied all of the petitions and motions for stay of the CPP and implemented an expedited briefing schedule. Basin Electric joined with about 60 utilities to file a motion to stay with the U.S. Supreme Court. And, in February, the U.S. Supreme Court, in an unprecedented move stayed the rule, halting implementation until litigation is complete. Briefings followed and initially a three-judge panel was slated to hear oral arguments. But, in another first, the D.C. Circuit Court of Appeals scheduled oral arguments to be heard before the entire court. Oral arguments were held Sept. 27, 2016, and the Supreme Court has not yet made a decision. However, President Donald Trump signed an executive order March 28, 2017, directing the EPA to review the CPP and other greenhouse gas regulations for the power sector. The action is a positive step forward in the cooperative’s efforts to seek time and flexibility in the development of a carbon management plan.

TO WORKFORCE Stream Protection Rule overturned

In May, at the invitation of U.S. Sen. John Hoeven (R-ND) (far right), Janice Schneider (far left), assistant secretary for Land and Minerals Management with the Department of the Interior, visited the The Coteau Properties Company Freedom Mine operations. Staff took her into the field and showed her the direct impacts the Stream Protection Rule would have on the Freedom Mine. Also pictured in the foreground is U.S. Sen. Heidi Heitkamp (D-ND) (center). In December, the rule became final threatening detrimental impacts on mining operations. However, in January 2017, Congress overturned the rule on repeal.

When the Basin Electric is actively The team completed its work in final rule came out seeking solutions that reduce 2016, but the initiative continin 2015, it increased the carbon its carbon footprint while keepues to develop and grow at dioxide reductions by 400 percent. ing coal as part of its energy each facility. CI #2 focused … It had the potential of costing Basin portfolio, preserving both on improving safety meetElectric billions of dollars and really comreliability and cost competiings and communications pletely reconfiguring how we do business. tiveness of the cooperative’s and was implemented at - Mark Foss energy supply. all facilities. Each facilSenior Vice President Additionally, Basin Electric ity is now building and & General Counsel has been engaged in further improving the quality of developing its political and their meetings. community support for the last CI #3 is developing with a several years. focus on education about OPMS. That In 2016, this included a numinitiative rolls out in 2017. The CI #4 team ber of senate letters supporting repeal of the CPP; and began at the close of 2016 and the focus is Montana the development of the Energy States Coalition that has safety metrics. Limestone Company was recognized by the attorneys general from states coming together to evalWith full support from Basin Electric’s Mine Safety and Health uate regulations. senior leadership, employees work hard and Administration with a cerare fully committed to improving Basin Electificate of achievement tric’s safety culture. in Safety for 2015. Safety continues to have the highest value Efforts to strengthen the Leland Olds Stathroughout the cooperative. Basin Electric’s employee base coincide with tion’s First Response Our Power, My Safety (OPMS) process efforts to strengthen ties to the Team was honored with established continuous improvement members. It’s important employNorth Dakota Safety Council’s rd (CI) initiatives to engage employees ees understand the members are Lifesaver Award at the NDSC 43 annual Safety & Health Conferin the effort of improving everyone’s the foundation of the cooperative. ence for saving the life of a safety, both at work and home. To further this, Basin Electric truck driver in cardiac CI #1 focused on improved work area launched the Building Cooperative arrest. inspections at every Basin Electric facility. Connections program with the goal of

COOPERATIVE

2016 ANNUAL REPORT

COMMITMENT TO COOPERATIVE

WORKFORCE

Building Cooperative Connections

Participating in the first Building Cooperative Connections were (from left) Lori Leier, Basin Electric tax analyst II; Aaron Eide, lineman with Lower Yellowstone Rural Electric Association; and Raymond Bell, cooperative member.

A few Basin Electric employees spent time at Class C member Lower Yellowstone to learn about the business from their point of view. Employees learned what the Lower Yellowstone employees deal with on a daily basis. They also had the opportunity to interact with a member who farms near Sidney, MT. Then, the Lower Yellowstone team visited Basin Electric to learn what happens at a generation and transmission cooperative and how decisions are made.

PEOPLE

providing employees with first-hand experience of what it is like to work at a distribution cooperative and on the An informed and engaged workforce is a strong flip side, what it is like to work at a generation and transworkforce, and the cooperative’s best asset. Mainmission cooperative. taining the competitive edge in employee recruitment Administratively, staff reviewed governance and and retention was a focus in 2016. A bubble of board policies. Basin Electric’s board engaged in the employee retirements is again approaching, so staff process while staff worked to simplify and streamline is working to prepare. the structure of policies and proceThis proactive approach includes dures across the cooperative. interacting with potential employThe expansion of the ees long before they enter the In the last three years, Headquarters building conworkforce through college our average employee age tinues with three goals. The career fairs, employee has gone from 48 to 43 years and our averfirst, to get all employparticipation in school age tenure has also dropped from 17 to 12 years ees under one roof. More STEM (science, techat Basin Electric and Dakota Gas. And, 63 percent of than 550 employees in nology, engineering, our employees are new to their position since 2014. Bismarck are spread out and math) program In the next 10 years, 750 employees will reach noramong four different locaactivities, and science mal retirement age, with 169 being supervisors. tions. Second, to build an center programs. - Diane Paul addition to accommodate Basin Electric also Senior Vice President of growth and needs into the works with local colHuman Resources future, and third, to proleges in the region, to vide an environment that pair their students with matches employees’ needs internship opportunities within with technology and collabothe cooperative. Each year, Basin Elecrative design. tric employs approximately 70 interns, and also offers The new working environment will increase a summer work program for sons and daughters of employee engagement, enable formal and informal employees, designed to assist supervisors with suminteraction, and enhance communication in the workmer workloads while giving students exposure to place. Headquarters West is expected to be complete cooperative jobs and culture. These positions include September 2017. laborers, clerical, technical, and professional positions.

BASIN ELECTRIC POWER COOPERATIVE

Basin Electric is helping students gain experience of continual learning with a curriculum and structure in advance of completing their degrees through newly that expands employee orientation from two days to an signed apprenticeship agreements. The cooperative 18- to 24-month program. partnered with Bismarck State College’s (BSC) An employee continuous learning series, called National Energy Center of Excellence to People. Power. Purpose., evolved throughcreate apprenticeship programs out the year. Live stream learning at the Antelope Valley and sessions are held monthly and proLeland Olds stations. The vide foundational knowledge programs were developed of departments and issues for three trades: instruthe cooperative is tackling. mentation and control Another program technician, mechanical rolling out in early 2017 is maintenance technician, BE Leaders. It’s a program and laboratory technifor employees to prepare The cooperative saves up to cian. In addition, the for future leadership roles. cooperative partnered Through the developa year by providing employees and with BSC and signed a ment and implementation their dependents the benefit of mechanical maintenance of these programs, staff was seeing an onsite physician. apprenticeship agreemindful of the cooperative’s ausment for the Laramie terity program. In consideration, special River Station. efforts to review and bid employee benefit It’s been When a new employee is programs were pursued, and staff identified cost savings hired, an improved orientation by further utilizing the cooperative’s contracted physician. since Basin Electric last program incorporating the Medical services staff began offering care to dependents updated and signed an cooperative’s history helps of employees in addition to the care they are providing to apprenticeship set the foundation for a career employees at a cost savings to Basin Electric. agreement.

$5 MILLION

16 YEARS

People. Power. Purpose.

A wide spectrum of topics were featured including change management; government regulations relating to the Clean Power Plan; workplace violence and situational awareness; cooperative management and communication; financial services and capital projects; austerity and cyber security; malware security; the trading floor at Headquarters; NERC compliance education and awareness; Dry Fork Station; ethics and business; the Great Plains Synfuels Plant; and a senior management recap of 2016 achievements.

Tom Stalcup, Dry Fork Station plant manager, provides a tour of the plant during one of the People. Power. Purpose. series presentations.

2016 ANNUAL REPORT

COMMITMENT TO COOPERATIVE

WORKFORCE

COMMUNITY EMPLOYEE COMMITMENT IN SCHOLARSHIPS

MILITARY

OLARSH I CH

4.4 MILLION

SCHOLARSHIP PROGRAM 25TH YEAR

ACTIVE MILITARY MEMBERS

MORE THAN

4,350 COLLEGE STUDENTS AWARDED

FOR MEMBER MATCHING DONATIONS

278 $405,000

DONATIONS

EMPLOYEE SERVICE

CAMPBELL COUNTY’S 3 RD ANNUAL HELPING HANDS DAY IN WYOMING MERCER COUNTY BACKPACK PROGRAM

ENSURING PAY IS WHOLE WHILE DEPLOYED Provide time off for temporary employees who serve. Time off for military members to be part of honor guards.

$2.6 MILLION SINCE 2008

1,000 LBS.

GROWN AND DONATED IN 2016 WILTON FIRE DEPARTMENT TRUCK DONATION

MISSOURI SLOPE AREAWIDE BACKPACK PROGRAM 800 BAGS FILLED DONATED

$20,000

50 EMPLOYEES 34

BASIN ELECTRIC POWER COOPERATIVE

CAMP

BASIN’S BACKYARD GARDEN

DAY OF CARING AT PAPA’S PUMPKIN PATCH

CLEANED 4.5 MILES OF HIGHWAY DITCHES

MILITARY VETERANS

CALLED TO SERVE: TECHNOLOGY TO STAY IN TOUCH

CHARITABLE GIVING PROGRAM

1/3 =

190

LUNCHEON

DONATED BY EMPLOYEES TO FIGHT HUNGER

REVENUE

EXPENSES FINANCIAL STABILITY

FINANCIAL FINANCIAL STABILITY

ven before 2015 ended, it was clear commodity prices in energy and agriculture were in a lengthy downward trend. Then, a combination of negative events hit the cooperative in rapid succession and extremely mild weather spread across the membership. The combination is rare and unexpected. When electricity sales are budgeted conservatively with normalized weather and the entirety of the cooperative’s service area experiences well above normal temperatures in the winter months and cooler than normal temperatures along with abundant precipitation during the summer, the impact on the bottom line can be significant. In response, the cooperative revised budgets, and initiated a task force to update the current state, develop a plan for moving forward and implement change. The team investigated every possible opportunity to cut costs and save money. They included expense reductions, a freeze on hiring new employees, delays in filling open positions, and the optimization of plant operations to name a few. It was undoubtedly a lengthy and extremely involved process,

CONSOLIDATED NET MARGIN & EARNINGS

TOTAL ELECTRIC SALES TO MEMBER SYSTEMS AND OTHERS

In millions of dollars – for the years ended

In millions of megawatt hours

150 120 90 60 120.6 30 0

but employees committed to the austerity measures put in place, and the board made a tough decision to implement an intra-year rate increase of 7 mills beginning Aug. 1, 2016, and into 2017. With the changes, the cooperative is in a strong financial position moving forward. A few other financial events took significant effort in 2016. First, the high-speed wind gusts in early July leveled the storage building for the Dakota Gasification Company Great Plains Synfuels Plant urea project. The insurance coverage for the urea project includes a deductible for property damage of $250,000 for each loss. Given the severity of the damage, the cooperative is collecting under that policy. As the Synfuels Plant works through its challenges, it’s worth reiterating how intricately connected the business, facilities, and operations are with the whole of the cooperative. The gasification plant cannot be considered a facility or resource that stands on its own. The annual benefit to Basin Electric of operating the Synfuels Plant is projected to provide an average yearly benefit to the membership of about $90 million during the 2017-2026 timeframe, which

2012

45.9

49.7

2013

2014

BASIN ELECTRIC POWER COOPERATIVE

8.1 2015

54.6 2016

30 25 20 15 10 5 0

28.3 6.2

29.6

7.2

26.6 6.2

6.9

28.9 5.9

18.7

20.4

22.1

22.7

23.0

25.9

8.1 2012

2013 2014 Members

2015 2016 Others

L STABILITY 2016 FINANCING ACTIVITIES

is the equivalent of about three and three-quarter mills. In addition, the operation of the Synfuels Plant contributes to the economy Electric rates – Beginning Jan. 1, 2016, the average Class A rate of the state and region. was 59.2 mills per kilowatt-hour before a depreciation credit, and Another large project Financial Services and others were 57.2 mills per kilowatt-hour net through July 2016. In June 2016, the involved with during the year was the material inventory process at board approved an intra-year rate increase of an average 7 mills per the Laramie River Station. The objective was to consolkilowatt-hour beginning August 2016 through the year. The 2016 idate materials from across multiple average Class A member rate was 60.5 mills per kilostorage locations at Laramie River watt hour. In August 2016, Basin Electric’s board We are stronger Station and improve the inventory approved the Class A member rate package because we continually process and increase efficiency prior for 2017 to meet the member revenue evaluate our processes and look for to the warehouse demolition. requirement of $1.58 billion. Beginning alternatives and efficiencies. We’re stronger In the last 10 years of its Jan. 1, 2017, the average Class A rate because we recognize we’re smarter when we 55-year history, Basin Electric will be 64.2 mills per kilowatt-hour. work together, and we’re stronger because we’ve has grown its total consoliSenior Secured Bond ratings – been able to weather the challenges and come out dated assets from $2.9 billion Fitch Ratings downgraded its A+ rating the other side with opportunities to continuously in 2006 to over $7.3 billion – to an A with an outlook change from improve our processes. an increase of over two and a stable to negative. Though Standard -Steve Johnson half times. & Poor’s affirmed its A rating of Basin Senior Vice President of

Financing these investElectric, the agency also changed its Financial Services & CFO ments takes a strong financial outlook for the cooperative from stable condition and associated credit to negative. While Moody’s gave Basin Electric worthiness. And, the foundation a stable outlook, they downgraded the cooperaof the cooperative’s strength is the tive two notches, from A-1 to A-3. commitment shown by members through the extension of Short-term ratings – Basin Electric’s short-term ratings are F1 wholesale power contracts. from Fitch Ratings, A-1 from Standard & Poor’s Rating Services and The strength of the cooperative today and well into the future P-2 from Moody’s Investors Service. Basin Electric uses short-term foundationally stands on sticking together – uniting and supportcommercial paper as a source of bridge financing until it can secure ing each other when challenges arise. long-term financing.

MARGIN DISPOSITION

AVERAGE INTEREST RATE ON UTILITY DEBT

In millions of dollars – theMargin years Disposition ended

As of Dec. 31 – in percent

150

120

90 60 30 0

42.6

57.4

52.0

77.6 28.2 49.4 8.1

140.8

2012 2013 2014 2015 2016 Allocated to members Bill credits

3 2

4.07

3.97

3.83

1 0

4.21

8.1 2012

2013

2014

2015

2016

2016 ANNUAL REPORT

FINANCIAL STABILITY

MEMBER INVESTMENT PROGRAM

EQUITY & DEFERRED TAXES 21.9%

In millions of dollars – at year end

200 150 100 50 0

112.3

158.4

165.2

173.8

180.2

BASIN ELECTRIC CONSOLIDATED CAPITALIZATION As of Dec. 31, 2016

8.1 2012

2013

2014

2015

DEBT 73.1%

2016

OPERATING RESULTS Consolidated results – Basin Electric’s financial statements are consolidated with those of its subsidiaries. For the year ended Dec. 31, 2016, the consolidated net margin and earnings was $54.6 million. This is $46.5 million more than the 2015 consolidated net margin and earnings of $8.1 million. Electric – Basin Electric’s total utility operating revenue for 2016 was $1.6 billion, an increase of $116.0 million from 2015. Revenue from member systems totaled $1.4 billion in 2016, an increase of $189.3 million from 2015. Revenue from non-member sales totaled $139 million, a decrease of $77.9 million from 2015. Total utility operating expenses plus interest and other charges before income taxes for 2016 were $1.5 billion, which is $24.6 million more than in 2015. Basin Electric’s utility margin before income taxes, combined with Basin Cooperative Services’ net operating results, yielded a combined margin of $140.8 million to be allocated to members. Subsidiary earnings – Dakota Gas had a net loss of $94.1 million during 2016. Dakota Gas did not declare or pay any dividends to Basin Electric in 2016; 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, 2016, were $7.3 billion, an increase of more than $229.6 million from a year earlier. Cash position – The consolidated cash balance, including restricted cash, as of Dec. 31, 2016, was $237.6 million. Member Investment Program – Basin Electric’s Member Investment Program ended the year with $180.8 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. 38

BASIN ELECTRIC POWER COOPERATIVE

LEASES 5.0%

BASIN ELECTRIC $1,600.6

CONSOLIDATED GROSS REVENUE TOTAL $2,183.1 In millions of dollars For the year ended Dec. 31, 2016

DAKOTA COAL $229.0 OTHER $38.7 DAKOTA GAS $314.8

Debt – As of Dec. 31, 2016, Basin Electric had approximately $5.0 billion of debt outstanding including Member Investment Program obligations, at a weighted average interest rate of 4.05 percent. Equity position – At year-end 2016, Basin Electric had total equity of $1.3 billion, an increase of $42.1 million from 2015. At the end of 2016, equity represented 24.1 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 2016, Basin Electric allocated $49.4 million to its patrons. Since 1966 Basin Electric allocated more than $871.6 million in capital credits to its members. Basin Electric retired $224.6 million over the history of the cooperative. Return of cash to members – Since 2000, Basin Electric 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)

2016

2015

2014

2013

2012

$ 1,531,257

$ 1,419,862

$ 1,459,155

$ 1,325,737

$ 1,184,132

30,321

25,755

22,346

12,072

12,812

1,561,578

1,445,617

1,481,501

1,337,809

1,196,944

1,001,114

948,317

987,388

905,289

807,629

Maintenance

149,357

160,348

163,433

124,436

130,081

Depreciation and amortization

125,287

154,151

148,028

131,421

108,328

2,762

2,773

2,959

2,908

2,255

1,278,520

1,265,589

1,301,808

1,164,054

1,048,293

Interest on long-term debt

167,192

156,903

155,679

149,669

130,719

Other

14,088

12,716

8,338

8,044

7,933

Total interest and other charges

181,280

169,619

164,017

157,713

138,652

Operating margin

101,778

10,409

15,676

16,042

9,999

35,039

34,894

32,614

34,267

29,646

Utility operations:

Operating revenue:

Sales of electricity for resale Other electric revenue Total utility operating revenue

Operating expenses:

Operation

Taxes other than income Total utility operating expenses

Interest and other charges:

Nonoperating margin:

Interest and other income Patronage allocations from other cooperatives

3,979

4,105

3,777

7,133

2,988

39,018

38,999

36,391

41,400

32,634

Utility margin before income taxes

140,796

49,408

52,067

57,442

42,633

Nonutility earnings (loss) before income taxes

(153,150)

(57,614)

(1,575)

(16,854)

82,529

(66,921)

(16,281)

811

(5,359)

4,606

$ 54,567

$ 8,075

$ 49,681

$ 45,947

$ 120,556

23,000

22,664

22,074

20,382

18,715

Total nonoperating margin

Provision for (benefit from) income taxes

Net margin and earnings Electric sales information: Electric energy sales (in thousands of MWh) Members Others

Total

5,899

6,890

6,251

6,171

7,183

28,899

29,554

28,325

26,553

25,898

2016 ANNUAL REPORT

INDEPENDENT AUDITORS’ REPORT

Deloitte & Touche LLP

Suite 2800 50 South Sixth Street 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, 2016 and 2015, 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 Company’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 Company’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Cooperative and its subsidiaries as of December 31, 2016 and 2015, 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, 2017

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)

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 (Note 2) 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 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 loss (Note 7) Noncontrolling interest

Long-term debt, net of current portion (Notes 2 and 8) Capital lease obligations, net of current portion (Note 3)

Deferred credits, taxes and other liabilities (Note 11)

2016

2015

$ 6,055,327 118,623 419,035 6,592,985 (2,165,237) 4,427,748

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

1,764,715 518,216 2,282,931 (820,618) 1,462,313

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

146,471 42,365 140,429 46,422 306,213 681,900

146,289 37,904 55,335 45,195 325,206 609,929

214,708 22,830 100 163,336 99,959 197,330 69,183 767,446 $ 7,339,407

171,204 318,685 100 120,098 85,151 201,011 114,959 1,011,208 $ 7,109,760

$ 21 795,648 277,897 289,494 (17,899) 1,345,161 1,027 1,346,188

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

4,133,002 116,185 5,595,375 507,867

4,001,274 179,886 5,485,292 541,840

50,846 3,342 204,313 178,197 679,516 119,951 1,236,165 $ 7,339,407

41,469 5,404 230,866 169,655 544,758 90,476 1,082,628 $ 7,109,760

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 â&#x20AC;&#x201C; affiliates Notes payable (Note 12) Taxes and other current liabilities

2016 ANNUAL REPORT

CONSOLIDATED FINANCIAL STATEMENTS

Basin Electric Power Cooperative and Subsidiaries

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

2016

2015

$ 1,392,252 139,005 1,531,257 30,321 1,561,578

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

1,001,114 149,357 125,287 2,762 1,278,520

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

167,192 14,088 181,280 101,778

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

35,039 3,979 39,018

34,894 4,105 38,999

140,796

49,408

126,546 246,952 114,397 487,895

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

644,888

705,994

(156,993)

(62,587)

3,843

4,973

Nonutility loss before income taxes

(153,150)

(57,614)

Margin and loss before income taxes

(12,354)

(8,206)

Benefit from income taxes

(66,921)

(16,281)

$ 8,075

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

Operating expenses (includes $15,217 and $17,976 of net income attributed to noncontrolling interest)

Operating loss

Interest and other income

Net margin and earnings

BASIN ELECTRIC POWER COOPERATIVE

54,567

CONSOLIDATED FINANCIAL STATEMENTS

Basin Electric Power Cooperative and Subsidiaries

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

2016 Net margin and earnings

2015

$ 54,567

8,075

Other comprehensive income (loss): Adjustment to post employment liability of $5,669, (net of tax of $586) and $(1,818), (net of tax of $(171)) Unrealized gain (loss) on securities of $3,201, (net of tax of $1,517) and $(915), (net of tax of $(442)) Unrealized gain (loss) on cash flow hedges of $(11,900), (net of tax of $(6,408)) and $135, (net of tax of $73) and reclassification adjustment of $(8,316), (net of tax of $(4,179)) and $(8,444), (net of tax of $(4,546)) reclassified into earnings

(20,216)

(8,309)

(11,346)

(11,042)

43,221

Total other comprehensive loss

Comprehensive income (loss)

(1,818) (915)

5,669 3,201

(2,967)

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY for the years ended December 31, 2016 and 2015 (dollars in thousands)

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 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, 2016

Other Equity $ 299,522

Accumulated Other Comprehensive Income (Loss) (Note 7) $ 4,489

Noncontrolling Interest $ 2,416

Total $ 1,307,323

(34,994) -

(3,491) -

(11,042) -

(2,967) -

638,363

374,078

296,031

(6,553)

150,748 6,537 -

(96,181) -

(6,537) -

(11,346) -

Patronage Capital $ 591,803

Retained Earnings of Subsidiaries $ 409,072

43,069 3,491 -

Memberships $ 21

$ 21

$ 795,648

$ 277,897

$ 289,494

$ (17,899)

17,976 (18,200) 2,192 15,217 (16,382) $ 1,027

17,976 (18,200) 1,304,132 43,221 15,217 (16,382) $ 1,346,188

2016 ANNUAL REPORT

CONSOLIDATED FINANCIAL STATEMENTS

Basin Electric Power Cooperative and Subsidiaries

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

2016

2015

$ 54,567

$ 8,075

185,626 15,585 36,943 (5,929) (57,309) 15,217

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

(43,238) (14,261) 3,681 (39,406) (6,378) 12,591 157,689

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

(303,177) (362,231) (25,938) 320,585 (2,950) (373,711)

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

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 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

187,636 (46,858) (194) 1,393,996 (1,386,256) 2,968,055 (2,833,298) (7,173) (16,382) 259,526 43,504 171,204 $ 214,708

1,907,124 (1,423,483) (6,225) 243,742 (130,304) 1,289,454 (1,281,194) 2,834,407 (2,804,469) (23,426) (18,200) 587,426 (115,571) 286,775 $ 171,204

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

$ 163,323 $ (261)

$ 168,583 $ (2,472)

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

$ (20,175) $ -

$ 17,642 $ 5,083

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 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

BASIN ELECTRIC POWER COOPERATIVE

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 a ccordance 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). 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 various Basin Electric peaking stations and AVS 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.

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 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. RESTRICTED CASH AND INVESTMENTS–Cash and investments, and funds held in escrow, by trustee, and by a financial institution at December 31 were restricted for the following purposes: 2016

2015

Cash and investments:

MBPP operating funds Unadvanced funds held in escrow by U.S. Bank as trustee for Dakota Gas

Other investments: Funds held in trust for an asset retirement obligation by Bank of Montreal as trustee for SVPL

$ 22,830 -

$ 22,453 296,232

$ 22,830

$ 318,685

$ 2,190

$ 2,106

2016 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 on the Consolidated Balance Sheets. The cost, unrealized holding gains and losses, and fair value of available-for-sale securities were as follows: December 31, 2016

Cost Equity securities Guaranteed investment certificates Canadian government bonds Corporate commercial paper

$ 49,482 744 1,460 100 $ 51,786

Gross Unrealized Holding Gains Losses $ 17,453 $ 14 $ 17,453 $ 14

December 31, 2015 Fair Value $ 66,935 744 1,446 100 $ 69,225

Cost $ 47,730 1,131 956 100 $ 49,917

Gross Unrealized Holding Losses Gains $ 14,735 $ 627 5 14 $ 14,754 $ 627

Fair Value $ 61,838 1,136 970 100 $ 64,044

During 2016 and 2015, sales proceeds on securities classified as available-for-sale were $10,960 and $100,102. The fair value of available-for-sale debt securities by contracted maturity date at December 31, 2016 was as follows: 2016 $ 67,626 Due through one year Due after one year through five years 1,298 Due after five years 301 $ 69,225 Held-to-maturity securities are included in Cash and 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:

Cost Money market Corporate commercial paper

$ 185,027 33,800 $ 218,827

December 31, 2016 Gross Unrealized Holding Gains Losses $ $ $ - $ -

Fair Value $ 185,027 33,800 $ 218,827

Cost $ 185,027 33,800 $ 218,827

December 31, 2015 Gross Unrealized Holding Losses Gains $ - $ $ - $ -

Fair Value $ 134,004 349,621 $ 483,625

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 $6,781 and $7,166, as of December 31, 2016 and 2015. COAL STOCK, MATERIALS AND SUPPLIES–Byproducts, coproduct, 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:

Materials and supplies Coal and fuel oil Byproducts, coproducts and limestone inventory Ammonia Ammonium sulfate Process inventory

2016

2015

$ 141,371 35,954 11,432 7,099 942 532 $ 197,330

$ 142,350 31,203 11,884 12,515 2,915 144 $ 201,011

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, 2016 was $224,626.

BASIN ELECTRIC POWER COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2016 and 2015 totaled $38,908 and $13,043. 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 1.80 and 2.51 percent in 2016 and 2015. Annual electric plant depreciation expense totaled $120,372 and $150,752 for 2016 and 2015. Nonutility property is depreciated using a straight-line method over a remaining estimated useful life of 30 years, except for certain byproduct assets which are depreciated over a remaining estimated useful life of 15 years. Annual nonutility depreciation expense totaled $65,254 and $79,332 for 2016 and 2015. 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: 2016 Regulatory assets included in: Deferred charges Mine related assets

$ 300,972 22,593 323,565

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

(24,888) $

298,677

2015 $ 319,360 24,086 343,446

(31,991) $ 311,455

As of December 31, 2016, 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 Boards of Directors of Basin Electric and its wholly-owned subsidiaries, Dakota Gas and Dakota Coal (said Boards of Directors being collectively referred to herein as the Board), adopted Board Policy 02B Cooperative Commodity Risk Management, dated October 13, 2015 (Policy). The Policy refers to Basin Electric, Dakota Gas, and Dakota Coal collectively as Affiliated Companies. The Policy provides a risk management framework and direction to staff engaged in the purchase, sale, optimization, control, accounting, and settlement of commodity transactions affecting each of the Affiliated Companies. This Commodity Risk Management Manual (Manual) fulfills the requirement of the Policy that the Risk Management Steering Committee (RMSC) adopt a written commodity risk management manual. The RMSC adopted the Manual, dated August 15, 2016. This Manual is designed to establish the commodity risk management and internal control framework under which the Affiliated Companies may engage in commodity transacting and hedging activities. This Manual governs contemplated commodity transactions, as well as, the management, tracking, and reporting of risks related to the commodity transacting portfolio. The Affiliated Companies’ commodity transacting program was developed to hedge inherent market risks associated with the business. In offsetting market risk, the Affiliated Companies are exposed to other forms of incremental risk such as credit or liquidity risk. 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 $2.55 and $4.00 per dekatherm for a portion of the forecasted sales (6% to 63% on a monthly basis) through December 2018. These derivative financial instruments attempt to provide for sales prices in excess of Dakota Gas’s 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. 2016 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Certain financial instruments valued at ($9,917) and $18,939, at December 31, 2016 and 2015, 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 Accumulated other comprehensive loss 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’s natural gas cash flow hedges had no ineffectiveness in 2016 or 2015. Derivative financial instruments valued at ($15,809) and $3,627, at December 31, 2016 and 2015, 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, 2016 Consolidated Balance Sheets, the fair value of the current portion of these derivative financial instruments, $1,467, was included in Prepayments and other current assets, the current liability portion, ($25,277), was included in Taxes and other current liabilities and the noncurrent portion, ($1,916) was included in Deferred credits, taxes and other liabilities. 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 of the liability, ($129), was included in Taxes and other current liabilities and the noncurrent portion of the liability, ($414), was included in Deferred credits, taxes and other liabilities. 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 $30.30 and $47.75 per barrel for a portion of the forecasted sales (16% to 67% on a monthly basis) through December 2018. These derivative financial instruments attempt to provide for sales prices in excess of Dakota Gas’s 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 ($6,523) and $1,029, at December 31, 2016 and 2015, meet the criteria for hedge accounting under ASC 815, and as a result, unrealized gains or losses on the instruments were recognized in Accumulated other comprehensive loss and will subsequently be reclassified to Byproducts, coproduct and other revenue in the Consolidated Statements of Operations when the underlying sales are recorded. Dakota Gas evaluates and quantifies any hedge ineffectiveness on a quarterly basis, and Dakota Gas’s tar oil cash flow hedges had no ineffectiveness in 2016 or 2015. Derivative financial instruments valued at $72 and $12,386, at December 31, 2016 and 2015, 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, 2016 Consolidated Balance Sheets, the fair value of the current liability portion of these derivative financial instruments, ($4,510), was included in Taxes and other current liabilities and the noncurrent portion, ($1,941), was included in Deferred credits, taxes and other liabilities. 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. 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. Derivative financial instruments, valued at $974 and ($1,288), at December 31, 2016 and 2015, did not 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, 2016 Consolidated Balance Sheets, the fair value of the current portion of these derivative financial instruments, $644, was included in Prepayments and other current assets and the noncurrent portion, $330, was included in Other investments. 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. In 2016, Dakota Gas also entered into derivative financial instruments for the purpose of mitigating the risk of market fluctuation in diesel prices paid to transport products. Derivative financial instruments, valued at $440, at December 31, 2016, did not 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, 2016 Consolidated Balance Sheets, the fair value of the current portion of these derivative financial instruments, $326 was included in Prepayments and other current assets and the noncurrent portion, $114, was included in Other investments. 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 six interest rate swaps outstanding at December 31, 2016 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, the interest rate on $50,000 of Basin Electric’s variable rate bonds due in 2030 to a fixed rate of 5.33 percent, the interest rate on $50,000 of Basin Electric’s variable rate bonds due in 2046 to a fixed rate of 2.255 percent, and the interest rate on $50,000 of Basin Electric’s variable rate bonds due in 2046 to a fixed rate of 2.295 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, 2016 and 2015 of $10,341 and $10,933. The change in fair value for the year ended December 31, 2016 resulted in a deferred gain of $9,786. At December 31, 2016 and 2015, the fair value of the obligation related to the interest rate swap agreements of $81,771 and $91,557 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 ($938) and ($6,198) at December 31, 2016 and 2015, for natural gas, power and diesel to manage the variable price risk associated with the forecasted commodity exposure through 2021. In the December 31, 2016 Consolidated Balance Sheets, the fair value of the current portion of the assets related to these derivative financial instruments, $3,065, was included in Prepayments and other current assets and the noncurrent portion, $390, was included in Other investments. At December 31, 2016, the fair value of the current portion of the liability related to Basin Electric’s derivative financial instruments was included in Taxes and other current liabilities ($474) and the noncurrent portion was included in Deferred credits, taxes and other liabilities ($3,919) on the Consolidated Balance Sheets. A regulatory deferred asset, which represents the amount to be recovered through future rates, was included in Deferred charges on the Consolidated Balance Sheets. In the December 31, 2015 Consolidated Balance Sheets, 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 POWER COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In 2016, Dakota Coal also entered into derivative financial instruments for the purpose of mitigating the risk of market fluctuation in the diesel cost component of the coal costs paid to Coteau. These derivative financial instruments effectively fix the price paid for diesel between $1.56 and $1.75 per gallon for a portion of the forecasted purchases (17% to 61% on a monthly basis) through December 2019. These derivative financial instruments attempt to mitigate the risk of price movement in the diesel cost component of coal costs. Certain derivative financial instruments valued at $812 at December 31, 2016 meet the criteria for hedge accounting under ASC 815, and as a result, unrealized gains or losses on the instruments were recognized in Accumulated other comprehensive loss and will subsequently be reclassified to Operating expenses in the Consolidated Statements of Operations when the underlying purchases are recorded. Dakota Coal evaluates and quantifies any hedge ineffectiveness on a quarterly basis, and Dakota Coal’s diesel cash flow hedges had no ineffectiveness in 2016. In the December 31, 2016 Consolidated Balance Sheets, the fair value of the current portion of these derivative financial instruments, $277, was included in Prepayments and other current assets and the noncurrent portion, $535, was included in Other investments. Basin Electric, Dakota Gas and Dakota Coal are exposed to credit risk loss in the event of nonperformance by the counterparties to their derivative financial instruments. However, Basin Electric, Dakota Gas and Dakota Coal do not anticipate nonperformance by the counterparties as all counterparties’ credit ratings are in compliance with Basin Electric’s, Dakota Gas’, and Dakota Coal’s risk policy requirements included in the Manual. ASSETS AND LIABILITIES MEASURED AT FAIR VALUE–ASC 820, Fair Value Measurements, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The standard applies to reported balances that are required or permitted to be measured at fair value. ASC 820 emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Therefore, a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. As a basis for considering market participant assumptions in fair value measurements, ASC 820 establishes a fair value hierarchy that distinguishes between market participant assumptions based on market data obtained from sources independent of the reporting entity (observable inputs that are classified within Levels 1 and 2 of the hierarchy) and the reporting entity’s own assumptions about market participant assumptions (unobservable inputs classified within Level 3 of the hierarchy). Level 1 inputs utilize observable market data in active markets for identical assets or liabilities. Level 2 inputs consist of observable market data, other than that included in Level 1, that is either directly or indirectly observable. Level 3 inputs consist of unobservable market data which are typically based on an entity’s own assumptions of what a market participant would use in pricing an asset or liability as there is little, if any, related market activity. In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. Basin Electric’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset or liability. On December 31, 2016, Basin Electric had money market accounts, commercial paper, U.S. government obligations and equity securities included in Short-term investments, Mine related assets and Other investments, 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, Basin Electric had money market accounts, commercial paper, U.S. government obligations, guaranteed investment certificates and equity securities included in Short-term investments, Mine related assets and Other investments, recorded at a fair value, using quoted prices in active markets for identical assets as the fair value measurement (Level 1). On December 31, 2016, Basin Electric recorded derivative financial instruments including commodity contracts, interest rate swaps, and guaranteed investment certificates 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. The fair value for the guaranteed investment certificates is determined by the insurance company by discounting the related cash flows based on current yields of similar instruments with comparable durations considering the creditworthiness of the issuer. On December 31, 2015, 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. On December 31, 2016, Basin Electric recorded a Dakota Gas tar oil contract at fair value using significant unobservable inputs as the fair value measurement (Level 3). The valuation of this contract involved management’s judgment. The fair value for the commodity contract was determined by comparing the difference between the net present value of the cash flows for the contract at their initial price and the current market price based on volatility curves as of December 31, 2016. 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.

2016 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes assets and liabilities measured at fair value on a recurring basis as of December 31, 2016, aggregated by the level in the fair value hierarchy within which those measurements fall: Fair Value Measurements Using

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

Fair Value

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

Significant Other Observable Inputs (Level 2)

Significant Unobservable Inputs (Level 3)

$ 744 185,127 33,800 1,446 33,809 8,863 18,947 5,316 288,052 8,036 (225,594) $ 70,494

$ 185,127 33,800 1,446 33,809 8,863 18,947 5,316 287,308 (218,927) $ 68,381

$ 744 744 8,036 (6,667) $ 2,113

$ $ -

$ 81,771 39,940 (32,165) $ 89,546

$ $ -

$ 81,771 38,924 (31,149) $ 89,546

$ 1,016 (1,016) $ -

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 Measurements Using

BASIN ELECTRIC POWER COOPERATIVE

Fair Value

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

Significant Other Observable Inputs (Level 2)

Significant Unobservable Inputs (Level 3)

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

$ 1,136 134,004 349,721 970 30,206 7,918 18,466 5,248 547,669 (187,493) $ 360,176

$ 32,947 (32,248) $ 699

$ $ -

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

$ $ -

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

$ $ -

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 year ended December 31, 2016, there was a transfer of $744 between Level 1 and Level 2 based on additional information available on the fair value of guaranteed investment certificates. For the year ended December 31, 2015, 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, 2016 through March 15, 2017, 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 2016 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. 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 believes the adoption of this new guidance will not have a material 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. 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. In August 2016, the FASB issued new accounting guidance for classification of certain cash receipts and cash payments on the statement of cash flows. The new guidance increases transparency and comparability among organizations by specific guidance on eight issues. The new guidance will be effective for Basin Electric in 2019. Early adoption of the accounting guidance is permitted and must be applied using a retrospective transition method. Management believes the adoption of this new guidance will not have a material impact on our consolidated financial statements and disclosures. In November 2016, the FASB issued new accounting guidance for classification of restricted cash on the statement of cash flows. The new guidance reduces diversity in practice by providing specific guidance on the presentation of restricted cash and restricted cash equivalents in the statement of cash flows. The new guidance will be effective for Basin Electric in 2019. Early adoption of the accounting guidance is permitted and must be applied using a retrospective transition method. Management believes the adoption of this new guidance will not have a material impact on our consolidated financial statements and disclosures. ACCOUNTING STANDARD UPDATES ADOPTED–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 was effective for Basin Electric beginning in 2016, and required that unamortized debt issue costs of $22,704 as of December 31, 2015 previously reported as a component of Deferred Charges be presented as a deduction from Long-term debt, net of current portion on the Consolidated Balance Sheets.

2016 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2017 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, 2016 included various substation and mining equipment with an original cost of $134,098. 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. Minimum future lease payments under capital leases as of December 31, 2016 for each of the next five years and in the aggregate are: Year 2017 2018 2019 2020 2021 Thereafter Total minimum lease payments Less: Amount representing interest Present value of net minimum lease payments

Amount $ 8,574 7,775 7,198 7,084 7,837 190,251 228,719 109,192 $ 119,527

Interest rates on capitalized leases vary from 2.29 percent to 5.14 percent and are imputed based on the lessor’s implicit rate of return. LEASING ARRANGEMENTS AS LESSEE–Basin Electric leases certain electric plant facilities, mining and related equipment and other operational assets under noncancelable operating leases with initial terms up to 30 years. Minimum future lease payments under noncancelable operating leases for each of the next five years and in aggregate are: Year 2017 2018 2019 2020 2021 Thereafter Total

Amount $ 28,953 19,507 18,455 17,852 3,227 23,438 $ 111,432

Rental payments charged to expense were $46,484 and $56,146 in 2016 and 2015.

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

2016

2015

$ 778,694

$ 757,516

(505,649) $ 273,045

(496,016) $ 261,500

Basin Electric’s share of MBPP operating expenses was $116,736 and $140,930 for 2016 and 2015, 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.

BASIN ELECTRIC POWER COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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: Prepaid coal royalties Mine closing fund investments Interest on coal royalties Notes receivable and mine financing costs Other

2016

2015

$ 32,635 90,797 17,266 446 5,327 $ 146,471

$ 34,692 85,992 18,353 1,520 5,732 $ 146,289

Coteau notes receivable with NACoal of $387 and $1,446 at December 31, 2016 and 2015 included above bear interest rates varying from 0.66 percent to 0.75 percent.

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 Refinancing fees Regulatory deferred pension expense Unrealized loss on interest rate swaps Unrealized loss on natural gas swaps Other

2016

2015

61,264 135,692 6,155 80,806 938 21,358 $ 306,213

$ 51,944 141,865 11,306 90,591 6,199 23,301 $ 325,206

Interest on coal royalties and other costs deferred under ASC 980, totaling $22,593 and $24,086 at December 31, 2016 and 2015, are included in Mine related assets on the Consolidated Balance Sheets.

7. EQUITY ACCUMULATED OTHER COMPREHENSIVE LOSS–The following table includes the changes in the balances of the components of Accumulated other comprehensive loss, net of tax, on the Consolidated Balance Sheets:

Balance, December 31, 2014 Comprehensive loss Balance, December 31, 2015 Comprehensive income (loss) Balance, December 31, 2016

Post Employment Benefit Plans $ (22,491) (1,818) (24,309) 5,669 $ (18,640)

Unrealized Gain (Loss) on Securities $ 9,768 (915) 8,853 3,201 $ 12,054

Unrealized Gain (Loss) on Cash Flow Hedges $ 17,212 (8,309) 8,903 (20,216) $ (11,313)

Total $ 4,489 (11,042) (6,553) (11,346) $ (17,899)

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, 2016, $8,976 of net income tax benefit was closed into Other equity.

2016 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. LONG-TERM DEBT 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% 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 1, 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 2.249% Basin Electric Power Cooperative, First Mortgage Obligations, MetLife 2008 Series A Note Number 2 due May 2032, variable interest at 2.339% Basin Electric Power Cooperative, First Mortgage Obligations, MetLife 2008 Series A Note Number 3 due May 2032, variable interest at 2.356% Basin Electric Power Cooperative, First Mortgage Obligations, MetLife 2008 Series A Note Number 4 due May 2032, variable interest at 2.371% Basin Electric Power Cooperative, First Mortgage Obligations, New York Life 2008 Series B Note, due June 2029, variable interest at 2.264% Basin Electric Power Cooperative, First Mortgage Obligations, John Hancock 2008 Series C Note, due June 2031, variable interest at 2.264% 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,2011 Series A Notes, due in semi-annual installments through October 2031, interest at 4.00% Basin Electric Power Cooperative, First Mortgage Obligations, 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 2017 to December 2018, 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% 54

BASIN ELECTRIC POWER COOPERATIVE

December 31, 2016

December 31, 2015

$ 200,000

283,741

288,327

10,833

100,000

110,000

23,569

25,615

150,000

45,000

13,750

15,000

9,000

9,750

50,000

110,000

115,000

30,000

32,500

100,000

229,230

100,000

93,513

95,281

2,629

4,117

250,000

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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% Basin Electric Power Cooperative, First Mortgage Obligations,2016 CoBank Note due in semi-annual installments through April 2046, interest at 4.48% Basin Electric Power Cooperative, First Mortgage Obligations,2016 CFC Note due in quarterly installments through April 2046, interest at 3.74% 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, 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 TT and UU, due in monthly installments through July 2021, interest from 2.48% 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% Equipment notes, Series III, JJJ and KKK due in monthly installments through May 2026, interest from 2.77% to 3.28% 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 2045, interest at 4.01% Other Less: Current portion Unamortized debt issue costs

December 31, 2016

December 31, 2015

$ 285,000

40,000

925,000

98,333

74,370 2,080 34

2,600 235

5,194

7,716

7,077

9,688

1,960

2,894

1,843

2,398

4,872

5,540

2,157

2,571

3,472 54,330

4,002 58,081

10,189

50,000

200,000

225,000 18,534 4,204,877

225,000 19,069 4,065,447

(50,846) (21,029) $ 4,133,002

(41,469) (22,704) $ 4,001,274

The estimated fair value of debt at December 31, 2016 and 2015 was $4,425,874 and $4,001,528, 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, 2016 are as follows: Long -term debt

2017 $ 50,846

2018 $ 66,416

2019 $ 97,278

2020 $ 97,123

2021 $ 94,464

All of Basin Electric’s long-term debt is secured under the Amended and Restated Indenture dated as of May 5, 2015 (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. 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’ longterm 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. 2016 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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:

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

2016 $ 900 872 2,034 $ 3,806

2015 $ 900 $ 900

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 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 Electricâ&#x20AC;&#x2122;s Benefit from income taxes were as follows for the years ended December 31: Current tax benefit Deferred tax benefit Benefit from income taxes

2016 $ (9,612) (57,309) $ (66,921)

2015 $

(548) (15,733) $ (16,281)

The tax effect of significant temporary differences representing deferred tax assets and liabilities were as follows at December 31: 2016

2015

Deferred tax liabilities: Depreciation and property RUS refinancing expense Direct financing leases Other deferred tax liabilities Unrealized gains Total deferred tax liability

$ 397,714 38,173 36,301 14,755 486,943

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

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 Unrealized losses Total deferred tax assets Net deferred tax liability Current deferred tax (asset) liability Noncurrent deferred tax liability

(58,706) (20,596) (30,905) (7,901) (139,298) (54,863) (20,913) (5,716) (338,898) 148,045 (9,336) $ 157,381

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

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.

BASIN ELECTRIC POWER COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Income taxes differ from the 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 Other, net Change in regulatory asset associated with deferred taxes net of patron net operating loss Other State income taxes Total Benefit from income taxes

2016 $ (4,324)

2015 $ (2,872)

(49,269) (1,357)

(17,284) (1,264)

(9,986) (611) (1,374) $ (66,921)

(274) 5,362 51 $ (16,281)

Basin Electric had available federal and state research tax credit carryforwards of approximately $19,637 and alternative minimum tax credit carryforwards of approximately $11,268 at December 31, 2016. The research tax credits expire in varying amounts from 2019 through 2037. Basin Electric has a consolidated net operating loss carryforward as of December 31, 2016 of $156,752. The net operating loss expires in varying amounts from 2035 through 2037. Basin Electric has a patron federal net operating loss carryforward of approximately $397,995. The patron net operating loss expires in varying amounts from 2028 through 2037. It is more likely than not that deferred tax assets will be recognized before their expiration. Basin Electric 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.

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 2016 and 2015 funding was $1,998 and $1,598. Coteau funds postretirement medical benefits through a Voluntary Employees Beneficiary Association (VEBA) trust. Coteau did not make any cash contributions to the VEBA in 2016 and 2015. Coteau also maintains health care and life insurance plans which provide benefits to eligible retired employees. Net periodic postretirement benefit expense for the years ended December 31 includes the following components: Basin Electric and Subsidiaries 2016 2015 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 loss: Net loss (gain) arising during the period Amortization of prior service credit Amortization of gain (loss) Total recognized in Other comprehensive loss

$ 3,099 1,798 (456) (53) $ 4,388

$ 2,620 1,547 (456) (40) $ 3,671

4,328 456 53 $ 4,837

(2,326) 456 40 (1,830)

Coteau 2016

2015

$ 311 540 (69) (137) 679 $ 1,324

$ 330 466 (145) (257) 435 $ 829

$ (4,742) 137 (679) $ (5,284)

1,883 257 (435) $ 1,705

2016 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Assumptions used to determine net periodic postretirement benefit expense were as follows for the years ended December 31: Basin Electric and Subsidiaries 2016 2015 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

4.22% N/A 7.10% 4.50% 2038

Coteau

3.82% N/A 7.41% 4.50% 2027

2016

2015

3.40% 5.75% 7.25% 5.00% 2025

3.25% 6.00% 6.75% 5.00% 2022

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 2016 2015

Coteau 2016

2015

Change in accumulated postretirement benefit liability: Balance at January 1 Service cost Interest cost Actuarial loss (gain) Assumption changes Benefit payments Plan participantsâ&#x20AC;&#x2122; 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 participantsâ&#x20AC;&#x2122; contributions Benefit payments Fair value of plan assets at end of year 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 loss: Prior service credit (cost) Actuarial gain (loss) Accumulated other comprehensive loss

$ 39,832 3,099 1,798 3,511 818 (4,821) 2,823 $ 47,060

$ 39,589 2,620 1,547 1,430 (3,756) (4,502) 2,904 $ 39,832

$ 16,104 311 540 (4,819) (624) $ 11,512

$ 14,461 330 466 1,698 (851) $ 16,104

1,998 2,823 (4,821) -

1,598 2,904 (4,502) -

1,720 (8) (1,004) 708

2,862 (39) (1,103) 1,720

$ 47,060 $ 47,060

$ 39,832 $ 39,832

$ 11,512 708 $ 10,804

$ 16,104 1,720 $ 14,384

2,683 44,377 $ 47,060

2,287 37,545 $ 39,832

298 10,506 $ 10,804

14,384 $ 14,384

(468) 3,055 2,587

(13) 7,437 7,424

(4) (348) (352)

133 (5,769) $ (5,636)

For Basin Electric and subsidiaries, as of December 31, 2016, $389 of the prior service credit and $55 of the actuarial gain will, through amortization, be recorded as components of net periodic postretirement benefit expense in 2017. For Coteau, as of December 31, 2016, $7 of the prior service cost and $0 of the actuarial loss will, through amortization, be recorded as components of net periodic postretirement benefit expense in 2017.

BASIN ELECTRIC POWER COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Assumptions used in accounting for the postretirement benefit plans obligation were as follows for the years ended December 31: Basin Electric and Subsidiaries 2016 2015 Weighted-average discount rates Initial health care cost trend Ultimate health care cost trend rate Year that the rate reaches the ultimate trend rate

4.00% 6.78% 4.50% 2038

4.22% 7.10% 4.50% 2038

Coteau 2016

2015

3.25% 7.00% 5.00% 2025

3.40% 7.25% 5.00% 2025

Changes in the assumed health care cost trend rates would impact the accumulated postretirement benefit liability and the net periodic postretirement benefit expense for 2016 as follows: Basin Electric and Subsidiaries Coteau Accumulated postretirement benefit liability Net periodic postretirement benefit expense

1% Increase

1% Decrease

1% Increase

1% Decrease

$ 4,735 $ 666

$ (4,075) $ (553)

$ 706 $ 60

$ (677) $ (57)

Postretirement benefit plan weighted average asset allocations for Coteau were as follows: Coteau 2016 Equity securities Debt securities Other

59.0% 35.6% 5.4% 100.0%

2015 81.0% 14.7% 4.3% 100.0%

Basin Electric and its subsidiaries and Coteau expect to make contributions of $2,683 and $0 in 2017 to their postretirement medical plans. The following are the expected future benefits to be paid:

2017 2018 2019 2020 2021 2022-2026

Basin Electric and Subsidiaries $ 2,683 $ 3,011 $ 3,143 $ 3,776 $ 3,937 $ 20,704

Coteau $ 1,006 $ 1,071 $ 1,152 $ 1,305 $ 1,239 $ 5,941

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 2016 and in 2015 represented less than 5 percent of the total contributions made to the plan by all participating employers. Pension costs charged to expense during 2016 and 2015 were $46,761 and $43,084. There have been no significant changes that affect the comparability of 2016 and 2015 contributions. 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, 2016 and 2015 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.

2016 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Net periodic pension expense of Basin Electric associated with the EBR for the year ended December 31 include the following components: 2016

2015

Service cost Interest cost Amortization of prior service cost Amortization of loss Adjustment of prior period Net periodic pension expense

$ 32 53 520 7 94 $ 706

$ 7 7 41 -

Other changes recognized in Other comprehensive loss: Amortization of prior service cost Amortization of actuarial loss (gain) Adjustment of prior period Total recognized in Other comprehensive loss

$ 520 299 357 $ 1,176

$ 41 (7) $ 34

$ 55

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

Weighted average discount rate

2016

2015

4.06%

4.04%

Basin Electric expects to make no contributions in 2017. At December 31, 2016, Basin Electric expects to pay benefits for the next five years and thereafter as follows: 2017 $

2018 22

2019 -

1,254

2020 $

2021 -

Thereafter -

The following sets forth the changes in the pension benefit obligation based on the actuaryâ&#x20AC;&#x2122;s analysis as of December 31:

2016

2015

Change in pension benefit obligation: Projected benefit obligation at January 1 and October 1 Adjustment to December 31, 2015 Adjusted projected benefit obligation at January 1 and October 1 Service cost Interest cost Actuarial gain (loss) Benefit payments Projected pension benefit obligation at end of year

$ 694 452 1,146 32 53 292 (470) $ 1,053

$ 686 686 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

$ 1,053 $ 1,053

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

$ 1,053 $ 1,053

$ 694 $ 694

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

$ 483 278 $ 761

BASIN ELECTRIC POWER COOPERATIVE

694 $ 694

645 (6) $ 639

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2016, $162 of the prior service cost and $7 of the actuarial loss will, through amortization, be recorded as components of net periodic pension expense in 2017. 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

2016

2015

3.68% 1.50%

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. 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: BCS

Coteau

2016

2015

2016

2015

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

$ 176 (247) 122 $ 51

$ 181 (260) 122 $ 43

$ 3,872 (5,966) 229 $ (1,865)

$ 3,749 (5,891) 450 $ (1,692)

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

$ (166) (122) $ (288)

$ (1,080) (229) $ (1,309)

(33) (122) $ (155)

914 (450) $ 464

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

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

Coteau

2016

2015

2016

2015

3.80% 7.00%

3.55% 7.00%

4.30% 7.50%

3.95% 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.

2016 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Change in pension benefit obligation: Projected benefit obligation at beginning of year Interest cost Actuarial gain

Benefits payments

Projected pension benefit obligation at end of year

2015

2016

2015

$ 4,820 176 (128)

$ 5,295 181 (270)

$ 91,761 3,872 (1,422)

$ 96,551 3,749 (5,323)

(370)

(386)

(3,464)

(3,216)

4,498

$ 4,820

$ 90,747

$ 91,761

$ 3,724 285 61 (370) $ 3,700

$ 3,762 24 324 (386) $ 3,724

$ 78,325 5,624 (3,464) $ 80,485

4,498 3,700 798

90,747 80,485 10,262

$ 91,761 78,325 $ 13,436

798 798

13,436 13,436

2,160

17,838

Change in plan assets: Fair value of plan assets at beginning of year Actual return on plan assets Employer contribution Benefits payments Inter-company transfers Fair value of plan assets at end of year 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 Amounts recognized in the balance sheets consist of: Current liabilities Noncurrent liabilities Net amount recognized Amounts not yet reflected in net periodic pension expense and included in Accumulated other comprehensive loss: Actuarial loss

Coteau

2016

$ $

4,820 3,724 1,096

1,096 $ 1,096

$ $

10,262 10,262

$ 2,448

16,529

81,886 (77) (3,216) (268) $ 78,325

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, 2016, $182 of the Coteau actuarial loss and $112 of the BCS actuarial loss will, through amortization, be recorded as components of net periodic pension expense in 2017. Assumptions used to account for the pension benefit obligation were as follows for the years ended December 31: BCS

Weighted average discount rate

Coteau

2016

2015

2016

2015

3.66%

3.80%

4.05%

4.30%

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: 2016 Actual Allocation U.S. equity securities Non-U.S. equity securities Fixed income securities Money market

BASIN ELECTRIC POWER COOPERATIVE

46.4% 19.6% 33.6% 0.4% 100.0%

Target Allocation Range 36.0% – 54.0% 16.0% – 24.0% 30.0% – 40.0% 0.0% – 10.0%

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following is the actual and target allocation percentages for the BCS Plan assets at the measurement date: 2016 Actual Allocation Equity securities Fixed income securities Other

43.0% 53.9% 3.1% 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 2017 to their defined benefit plans. the Coteau Pension Plan: BCS 2017 $ 356 2018 $ 346 2019 $ 335 2020 $ 325 2021 $ 316 2022-2026 $ 1,441

The following are the expected future benefit payments for the BCS Plan and Coteau $ $ $ $ $ $

3,591 3,808 4,071 4,408 4,749 27,115

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 $11,238 and $10,931 for 2016 and 2015. 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 $2,593 and $2,595 related to this plan in 2016 and 2015. 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 $2,219 and $2,270 in 2016 and 2015. 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 Unearned revenue Regulatory deferred post-retirement obligation Regulatory deferred revenue Other

2016

2015

$ 157,381 113,580 85,325 89,547 29,207 2,742 1,963 22,884 5,238 $ 507,867

$ 194,216 97,361 83,904 97,639 29,207 3,084 8,927 22,884 4,618 $ 541,840

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, 2016 were $366,674 in 2017, $401,282 in 2018, $378,397 in 2019, $357,653 in 2020, $332,225 in 2021, and $5,141,845 thereafter. Amounts purchased under the contracts totaled $293,101 in 2016 and $256,346 in 2015. 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, 2016 and 2015, the assets 2016 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

and liabilities of Corn Belt included in the Consolidated Balance Sheets totaled $15,268 and $16,123. 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 multiple transmission projects and a building addition to the headquarters in Bismarck. Dakota Gas is constructing a urea plant and capital projects for operational improvements. Various outstanding contractual construction commitments for Basin Electric and its subsidiaries totaled $240,773 as of December 31, 2016. Coteau has outstanding equipment commitments of $6,493 as of December 31, 2016. INVENTORY PURCHASE COMMITMENTS–Coteau entered into various diesel fuel contracts through January 2018. The estimated commitments under these purchase contracts as of December 31, 2016 were $4,184. 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 2016 and 2015, Dakota Coal paid $198,904 and $211,775 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 $3,866 and $3,123 in 2016 and 2015. Coteau made payments of $0 and $311 in 2016 and 2015 for costs of reclamation that were incurred. Dakota Coal has established designated funds for mine closing costs. The Agreement includes provisions whereby, upon expiration of the agreement, Dakota Coal has the option to purchase the outstanding common stock of Coteau for its book value from NACoal. Dakota Coal may exercise this option only if Coteau has not exercised its right to extend the Agreement. NACoal has the option to require Dakota Coal to purchase the outstanding stock of Coteau for its book value in the event all of the plants Dakota Coal presently sells lignite coal to are closed or if lignite coal may no longer be legally mined in North Dakota and Dakota Coal exercises its right to terminate the Agreement with Coteau. COAL PURCHASE AND FINANCING COMMITMENTS–Basin Electric, on behalf of the MBPP, has executed an agreement with Western Fuels Association, Inc. (Western Fuels) requiring coal purchases of approximately 6,700,000 tons per year through 2034, with an option to extend the contract with approval by both parties. The average price of coal under this agreement during 2016 and 2015 was approximately $18.49 and $18.54 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 2016 and 2015 was approximately $10.18 and $8.65 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, 2016 and 2015 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 02-16-16 06-22-16 10-20-16

Term 32 years 7 years 7 years 5 years 5 years 7 years 5 years 7 years 7 years 5 years 7 years 6.83 years 10 years

Interest Rate 5.15% 5.61% 5.61% 4.97% 4.97% 4.35% 3.85% 5.08% 4.99% 4.72% 4.51% 4.4633% 4.7556%

Original Loan Value 20,457 109 180 183 302 257 445 2,366 6,165 761 3,273 3,326 4,675

Borrower WFW WFW WFW 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 Equipment purchase-LRS Basin share Equipment purchase-LRS Basin share Road Relocation Project-LRS Basin share Less current portion

BASIN ELECTRIC POWER COOPERATIVE

2016 $ 19,277 29 48 85 445 1,493 4,819 612 1,983 2,108 1,954 32,853 (2,923) $ 29,930

2015 $ 19,612 46 76 183 302 123 445 1,831 5,603 752 28,973 (1,861) $ 27,112

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The estimated fair value of these notes receivable at December 31, 2016 and 2015 was $32,970 and $36,907, 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 2016 exceeds $15,000 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 longlived asset that results from the acquisition, construction, or development and/or the normal operation of a long-lived asset. Basin Electric and Coteau determine these obligations based on an estimated asset retirement cost adjusted for inflation and projected to the estimated settlement dates, and discounted using a credit-adjusted risk-free interest rate. A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation included in Deferred credits, taxes and other liabilities on the Consolidated Balance Sheets is as follows: 2016 2015 Balance, January 1 Liabilities settled during the period Accretion expense Addition for new mine area Addition for utility obligations Balance, December 31

$ 88,736 (1,143) 4,747 12,627 $ 104,967

$ 69,458 (355) 3,880 15,505 248 $ 88,736

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, 2016, the aggregated value of these guarantees is $146,000. 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, 2016, the aggregated value of these guarantees is $14,700. 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 Ten Banks Syndicate of Eleven 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, 2016 $ 129,925 $ 399,591 $ 100,000 $ 50,000

As of December 31, 2016, the effective interest rate of the outstanding advances is 1.18%. 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 was for a 15-year term ended 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 a second one-year renewal. 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. 2016 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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’ 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–In 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. In 2009, the STB issued a decision providing significant rate relief for LRS coal deliveries and 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. In November 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 final settlement. In early 2015, Western Fuels/Basin Electric and BNSF informed the STB that they had reached a preliminary settlement agreement which 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 in May 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 an administrative stay pending judicial review and a petition for reconsideration of the Rule on October 30, 2015. The EPA denied Basin Electric’s request for administrative stay and petition for reconsideration on January 11, 2017. Basin Electric also filed with the D.C. Circuit Court 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. Oral arguments were held on September 27, 2016. The D.C. Circuit has yet to rule on the merits of the appeal of the Rule. Unlike prior EPA Clean Air Act (CAA) 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. LARAMIE RIVER STATION BART FOR REGIONAL HAZE–The Regional Haze provisions of the CAA 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 certain threshold 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 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 (FIP) 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 (10th Circuit) of the EPA’s NOx determination requiring the installation of three SCRs at LRS. The 10th Circuit granted a stay on September 9, 2014 that extends the time for compliance for the duration of the litigation. This appeal is ongoing. Through the 10th Circuit Mediation Office, Basin Electric and the EPA have negotiated a tentative settlement, published in the Federal Register on December 30, 2016. The technology package includes SCR equipment on Unit 1, operational by July 31, 2019; and selective non-catalytic reduction equipment (SNCR) on Unit 2 and Unit 3, operational by December 31, 2018. The estimated cost of the technology package is $300 million for the SCR and $50 million for the two SNCRs. The settlement is not final until the EPA revises its FIP as it relates to LRS. The settlement is expected to be final in the summer of 2018. Until that time, the EPA could back out for numerous reasons in which case the litigation in the 10th Circuit would resume. 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 confidential discussions and have signed a tolling agreement extending the statute of limitations for the Unit 3 superheater investigation to June 30, 2017. The only way to reduce Unit 3 SO2 emissions to a level that EPA believes is BACT is to install a baghouse, at an estimated cost of $150 million, or a wet scrubber, at an estimated cost of $350 million, as determined by Sargent & Lundy in their BACT evaluation of May, 2015. LRS personnel are conducting optimization studies and computational fluid dynamics modeling of the current system at LRS Unit 3 to determine whether the unit can achieve lower SO2 emissions with the current controls instead of installing a baghouse or wet scrubber. Basin Electric and the EPA have not settled on BACT emission levels for Unit 3. 66

BASIN ELECTRIC POWER COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. RELATED PARTY TRANSACTIONS Other receivables include $1,272 and $2,679 at December 31, 2016 and 2015, for amounts Basin Electric, as operating agent, and its subsidiaries, have billed to MBPP. Included in Special funds on the Consolidated Balance Sheets is Basin Electric’s advance to MBPP of approximately $12,346 at December 31, 2016 and 2015. 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, 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 and AVS. • PROJECT SERVICES–Basin Electric provides the use of operational assets to Dakota Gas’ Synfuels Plant. Related party amounts that were not eliminated in consolidation in accordance with ASC 980, Regulated Operations, were billed as follows for the years ended December 31: Power supply from Basin Electric to Dakota Gas Power sales from PrairieWinds ND to Basin Electric Power sales from PrairieWinds SD to Basin Electric Screened coal sales from Dakota Gas to Basin Electric Coal supply sales from Dakota Coal to Basin Electric Administrative services by Basin Electric to Dakota Gas Administrative services by Basin Electric to Dakota Coal Administrative services by Basin Electric to PrairieWinds ND Administrative services by Basin Electric to PrairieWinds SD Lime sales from Dakota Coal to Basin Electric Limestone sales from Dakota Coal to Basin Electric Water supply from Basin Electric to Dakota Gas Natural gas sales from Dakota Gas to Basin Electric Project services from Basin Electric to Dakota Gas

2016

2015

$ 47,708 $ 15,953 $ 22,394 $ 57,136 $ 58,575 $ 23,513 $ 1,378 $ 1,001 $ 1,306 $ 12,005 $ 4,235 $ 3,664 $ 15,140 $ 360

$ 63,536 $ 15,462 $ 21,863 $ 63,489 $ 58,457 $ 23,616 $ 2,935 $ 903 $ 1,247 $ 12,650 $ 3,412 $ 2,896 $ 1,364 $ 388

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

2016 ANNUAL REPORT

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