Edgar Filing: MDU RESOURCES GROUP INC

Wdesk | 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____________ to ______________

Commission file number 1-3480

MDU RESOURCES GROUP, INC.

(Exact name of registrant as specified in its charter)



Delaware		41-0423660
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1200 West Century Avenue

P.O. Box 5650

Bismarck, North Dakota 58506-5650

(Address of principal executive offices)

(Zip Code)

(701) 530-1000

(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class		Name of each exchange on which registered
Common Stock, par value $1.00		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Preferred Stock, par value $100

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No o.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No ý.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o.

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act (Check one):



Large accelerated filer ý	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No ý.

State the aggregate market value of the voting common stock held by nonaffiliates of the registrant as of June 30, 2015: $3,805,857,581.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of February 11, 2016: 195,265,744 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's 2016 Proxy Statement are incorporated by reference in Part III, Items 10, 11, 12, 13 and 14 of this Report.

Contents



Part I

Forward-Looking Statements		6

Items 1 and 2 Business and Properties		6
	General	6
	Electric	7
	Natural Gas Distribution	11
	Pipeline and Midstream	13
	Construction Materials and Contracting	14
	Construction Services	17
	Refining	17
	Discontinued Operations	18

Item 1A	Risk Factors	18

Item 1B	Unresolved Staff Comments	24

Item 3	Legal Proceedings	24

Item 4	Mine Safety Disclosures	24

Part II

Item 5	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25

Item 6	Selected Financial Data	26

Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	28

Item 7A	Quantitative and Qualitative Disclosures About Market Risk	47

Item 8	Financial Statements and Supplementary Data	48

Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	106

Item 9A	Controls and Procedures	106

Item 9B	Other Information	106

Part III

Item 10	Directors, Executive Officers and Corporate Governance	107

Item 11	Executive Compensation	107

Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	107

Item 13	Certain Relationships and Related Transactions, and Director Independence	107

Item 14	Principal Accountant Fees and Services	107

Part IV

Item 15	Exhibits and Financial Statement Schedules	108

Signatures		115

Exhibits

2 MDU Resources Group, Inc. Form 10-K

Definitions



The following abbreviations and acronyms used in this Form 10-K are defined below:
Abbreviation or Acronym
AFUDC	Allowance for funds used during construction
Army Corps	U.S. Army Corps of Engineers
ASC	FASB Accounting Standards Codification
ATBs	Atmospheric tower bottoms
BART	Best available retrofit technology
Bbl	Barrel
Bcf	Billion cubic feet
Bicent	Bicent Power LLC
Big Stone Station	475-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent ownership)
BOE	One barrel of oil equivalent - determined using the ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf of natural gas
Bombard Mechanical	Bombard Mechanical, LLC, an indirect wholly owned subsidiary of MDU Construction Services
BPD	Barrels per day
Brazilian Transmission Lines	Company's former investment in companies owning three electric transmission lines
Btu	British thermal unit
Calumet	Calumet Specialty Products Partners, L.P.
Cascade	Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
CEM	Colorado Energy Management, LLC, a former direct wholly owned subsidiary of Centennial Resources (sold in the third quarter of 2007)
Centennial	Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
Centennial Capital	Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
Centennial Resources	Centennial Energy Resources LLC, a direct wholly owned subsidiary of Centennial
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act
Clean Air Act	Federal Clean Air Act
Clean Water Act	Federal Clean Water Act
Colorado Court of Appeals	Court of Appeals, State of Colorado
Colorado State District Court	Colorado Thirteenth Judicial District Court, Yuma County
Company	MDU Resources Group, Inc.
Coyote Creek	Coyote Creek Mining Company, LLC, a subsidiary of The North American Coal Corporation
Coyote Station	427-MW coal-fired electric generating facility near Beulah, North Dakota (25 percent ownership)
Dakota Prairie Refinery	20,000-barrel-per-day diesel topping plant built by Dakota Prairie Refining in southwestern North Dakota
Dakota Prairie Refining	Dakota Prairie Refining, LLC, a limited liability company jointly owned by WBI Energy and Calumet
D.C. Circuit Court	United States Court of Appeals for the District of Columbia Circuit
dk	Decatherm
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
EBITDA	Earnings before interest, taxes, depreciation, depletion and amortization
EIN	Employer Identification Number
EPA	United States Environmental Protection Agency
ERISA	Employee Retirement Income Security Act of 1974
ESA	Endangered Species Act
ESCP	Erosion and Sediment Control Plan
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fidelity	Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings (previously referred to as the Company's exploration and production segment)
FIP	Funding improvement plan
GAAP	Accounting principles generally accepted in the United States of America

MDU Resources Group, Inc. Form 10-K 3

Definitions



GHG	Greenhouse gas
Great Plains	Great Plains Natural Gas Co., a public utility division of the Company
GVTC	Generation Verification Test Capacity
IBEW	International Brotherhood of Electrical Workers
ICWU	International Chemical Workers Union
IFRS	International Financial Reporting Standards
Intermountain	Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
IPUC	Idaho Public Utilities Commission
Item 8	Financial Statements and Supplementary Data
JTL	JTL Group, Inc., an indirect wholly owned subsidiary of Knife River
Knife River	Knife River Corporation, a direct wholly owned subsidiary of Centennial
Knife River - Northwest	Knife River Corporation - Northwest, an indirect wholly owned subsidiary of Knife River
K-Plan	Company's 401(k) Retirement Plan
kW	Kilowatts
kWh	Kilowatt-hour
LTM	LTM, Incorporated, an indirect wholly owned subsidiary of Knife River
LWG	Lower Willamette Group
MBbls	Thousands of barrels
MBOE	Thousands of BOE
Mcf	Thousand cubic feet
MD&A	Management's Discussion and Analysis of Financial Condition and Results of Operations
Mdk	Thousand decatherms
MDU Construction Services	MDU Construction Services Group, Inc., a direct wholly owned subsidiary of Centennial
MDU Energy Capital	MDU Energy Capital, LLC, a direct wholly owned subsidiary of the Company
MEPP	Multiemployer pension plan
MISO	Midcontinent Independent System Operator, Inc.
MMBOE	Millions of BOE
MMBtu	Million Btu
MMcf	Million cubic feet
MMdk	Million decatherms
MNPUC	Minnesota Public Utilities Commission
Montana-Dakota	Montana-Dakota Utilities Co., a public utility division of the Company
Montana DEQ	Montana Department of Environmental Quality
Montana First Judicial District Court	Montana First Judicial District Court, Lewis and Clark County
Montana Seventeenth Judicial District Court	Montana Seventeenth Judicial District Court, Phillips County
MPPAA	Multiemployer Pension Plan Amendments Act of 1980
MTPSC	Montana Public Service Commission
MW	Megawatt
NDPSC	North Dakota Public Service Commission
Nevada State District Court	District Court Clark County, Nevada
NGL	Natural gas liquids
Notice of Civil Penalty	Notice of Civil Penalty Assessment and Order
Oil	Includes crude oil and condensate
Omimex	Omimex Canada, Ltd.
OPUC	Oregon Public Utility Commission
Oregon DEQ	Oregon State Department of Environmental Quality
PCBs	Polychlorinated biphenyls
Proxy Statement	Company's 2016 Proxy Statement
PRP	Potentially Responsible Party
PUD	Proved undeveloped
RCRA	Resource Conservation and Recovery Act

4 MDU Resources Group, Inc. Form 10-K

Definitions



RIN	Renewable Identification Number
ROD	Record of Decision
RP	Rehabilitation plan
SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
SEC Defined Prices	The average price of oil and natural gas during the applicable 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions
Securities Act	Securities Act of 1933, as amended
Securities Act Industry Guide 7	Description of Property by Issuers Engaged or to be Engaged in Significant Mining Operations
Sheridan System	A separate electric system owned by Montana-Dakota
South Dakota DENR	South Dakota Department of Environment and Natural Resources
SourceGas	SourceGas Distribution LLC
Stock Purchase Plan	Company's Dividend Reinvestment and Direct Stock Purchase Plan
UA	United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada
United States District Court for the District of Montana	United States District Court for the District of Montana, Great Falls Division
United States Supreme Court	Supreme Court of the United States
VIE	Variable interest entity
Washington DOE	Washington State Department of Ecology
WBI Energy	WBI Energy, Inc., an indirect wholly owned subsidiary of WBI Holdings
WBI Energy Midstream	WBI Energy Midstream, LLC, an indirect wholly owned subsidiary of WBI Holdings
WBI Energy Transmission	WBI Energy Transmission, Inc., an indirect wholly owned subsidiary of WBI Holdings
WBI Holdings	WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
WUTC	Washington Utilities and Transportation Commission
Wygen III	100-MW coal-fired electric generating facility near Gillette, Wyoming (25 percent ownership)
WYPSC	Wyoming Public Service Commission
ZRCs	Zonal resource credits - a MW of demand equivalent assigned to generators by MISO for meeting system reliability requirements

MDU Resources Group, Inc. Form 10-K 5

Part I

Forward-Looking Statements

This Form 10-K contains forward-looking statements within the meaning of Section 21E of the Exchange Act. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words "anticipates," "estimates," "expects," "intends," "plans," "predicts" and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - MD&A - Prospective Information.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management's examination of historical operating trends, data contained in the Company's records and other data available from third parties. Nonetheless, the Company's expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.

Items 1 and 2. Business and Properties

General

The Company is a diversified natural resource company, which was incorporated under the laws of the state of Delaware in 1924. Its principal executive offices are at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 530-1000.

Montana-Dakota, through the electric and natural gas distribution segments, generates, transmits and distributes electricity and distributes natural gas in Montana, North Dakota, South Dakota and Wyoming. Cascade distributes natural gas in Oregon and Washington. Intermountain distributes natural gas in Idaho. Great Plains distributes natural gas in western Minnesota and southeastern North Dakota. These operations also supply related value-added services.

The Company, through its wholly owned subsidiary, Centennial, owns WBI Holdings, Knife River, MDU Construction Services, Centennial Resources and Centennial Capital. WBI Holdings is comprised of the pipeline and midstream segment; Dakota Prairie Refinery, which is reflected in the refining segment; and Fidelity, the Company's exploration and production business. For more information on Dakota Prairie Refinery, see Item 8 - Note 17. Knife River is the construction materials and contracting segment, MDU Construction Services is the construction services segment, and Centennial Resources and Centennial Capital are both reflected in the Other category.

In the second quarter of 2015, the Company announced its plan to market Fidelity and exit that line of business. In the third and fourth quarters of 2015 and the first quarter of 2016, the Company entered into purchase and sale agreements to sell the vast majority of Fidelity's assets. Therefore, Fidelity's results are reflected in discontinued operations, other than certain general and administrative costs and interest expense which are reflected in the Other category. For more information on the Company's business segments and discontinued operations, see Item 8 - Notes 2 and 13.

As of December 31, 2015, the Company had 8,689 employees with 149 employed at MDU Resources Group, Inc., 1,027 at Montana-Dakota, 34 at Great Plains, 317 at Cascade, 239 at Intermountain, 530 at WBI Holdings, 2,945 at Knife River and 3,448 at MDU Construction Services. The number of employees at certain Company operations fluctuates during the year depending upon the number and size of construction projects. The Company considers its relations with employees to be satisfactory.

The following information regarding the number of employees represented by labor contracts is as of December 31, 2015.

At Montana-Dakota and WBI Energy Transmission, 354 and 76 employees, respectively, are represented by the IBEW. Labor contracts with such employees are in effect through April 30, 2018, and March 31, 2018, respectively.

6 MDU Resources Group, Inc. Form 10-K

Part I

At Cascade, 179 employees are represented by the ICWU. The labor contract with the field operations group is effective through April 1, 2018.

At Intermountain, 126 employees are represented by the UA. Labor contracts with such employees are in effect through September 30, 2016.

Knife River operates under 43 labor contracts that represent 455 of its construction materials employees. Knife River is in negotiations on four of its labor contracts.

MDU Construction Services has 155 labor contracts representing the majority of its employees.

The majority of the labor contracts contain provisions that prohibit work stoppages or strikes and provide for binding arbitration dispute resolution in the event of an extended disagreement.

The Company's principal properties, which are of varying ages and are of different construction types, are generally in good condition, are well maintained and are generally suitable and adequate for the purposes for which they are used.

The financial results and data applicable to each of the Company's business segments, as well as their financing requirements, are set forth in Item 7 - MD&A and Item 8 - Note 13 and Supplementary Financial Information.

The operations of the Company and certain of its subsidiaries are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations and state hazard communication standards. The Company believes that it is in substantial compliance with these regulations, except as to what may be ultimately determined with regard to items discussed in Environmental matters in Item 8 - Note 17. There are no pending CERCLA actions for any of the Company's properties, other than the Portland, Oregon, Harbor Superfund Site and the Bremerton Gasworks Superfund Site.

The Company produces GHG emissions primarily from its fossil fuel electric generating facilities, as well as from natural gas pipeline and storage systems, operations of equipment and fleet vehicles, and refining activities. GHG emissions also result from customer use of natural gas for heating and other uses. As interest in reductions in GHG emissions has grown, the Company has developed renewable generation with lower or no GHG emissions. Governmental legislative and regulatory initiatives regarding environmental and energy policy are continuously evolving and could negatively impact the Company's operations and financial results. Until legislation and regulation are finalized, the impact of these measures cannot be accurately predicted. The Company will continue to monitor legislative and regulatory activity related to environmental and energy policy initiatives. Disclosure regarding specific environmental matters applicable to each of the Company's businesses is set forth under each business description later. In addition, for a discussion of the Company's risks related to environmental laws and regulations, see Item 1A - Risk Factors.

This annual report on Form 10-K, the Company's quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge through the Company's Web site as soon as reasonably practicable after the Company has electronically filed such reports with, or furnished such reports to, the SEC. The Company's Web site address is www.mdu.com. The information available on the Company's Web site is not part of this annual report on Form 10-K.

Electric

General Montana-Dakota provides electric service at retail, serving more than 142,000 residential, commercial, industrial and municipal customers in 177 communities and adjacent rural areas as of December 31, 2015. The principal properties owned by Montana-Dakota for use in its electric operations include interests in 13 electric generating facilities and three small portable diesel generators, as further described under System Supply, System Demand and Competition, approximately 3,100 and 5,000 miles of transmission and distribution lines, respectively, and 73 transmission and 318 distribution substations. Montana-Dakota has obtained and holds, or is in the process of renewing, valid and existing franchises authorizing it to conduct its electric operations in all of the municipalities it serves where such franchises are required. Montana-Dakota intends to protect its service area and seek renewal of all expiring franchises. At December 31, 2015, Montana-Dakota's net electric plant investment was $1.3 billion.

The percentage of Montana-Dakota's 2015 retail electric utility operating revenues by jurisdiction is as follows: North Dakota - 65 percent; Montana - 21 percent; Wyoming - 9 percent; and South Dakota - 5 percent. Retail electric rates, service, accounting and certain security issuances are subject to regulation by the NDPSC, MTPSC, SDPUC and WYPSC. The interstate transmission and wholesale electric power operations of Montana-Dakota also are subject to regulation by the FERC under provisions of the Federal Power Act, as are interconnections with other utilities and power generators, the issuance of securities, accounting and other matters.

MDU Resources Group, Inc. Form 10-K 7

Part I

Through MISO, Montana-Dakota has access to wholesale energy, ancillary services and capacity markets for its integrated system. MISO is a regional transmission organization responsible for operational control of the transmission systems of its members. MISO provides security center operations, tariff administration and operates day-ahead and real-time energy markets, ancillary services and capacity markets. As a member of MISO, Montana-Dakota's generation is sold into the MISO energy market and its energy needs are purchased from that market.

System Supply, System Demand and Competition Through an interconnected electric system, Montana-Dakota serves markets in portions of western North Dakota, including Bismarck, Mandan, Dickinson, Williston and Watford City; eastern Montana, including Sidney, Glendive and Miles City; and northern South Dakota, including Mobridge. The maximum electric peak demand experienced to date attributable to Montana-Dakota's sales to retail customers on the interconnected system was 611,542 kW in August 2015. Montana-Dakota's latest forecast for its interconnected system indicates that its annual peak will continue to occur during the summer and the sales growth rate through 2020 will approximate three percent annually. The interconnected system consists of 12 electric generating facilities and three small portable diesel generators, which have an aggregate nameplate rating attributable to Montana-Dakota's interest of 704,143 kW and total net ZRCs of 513.2 in 2015. ZRCs are a MW of demand equivalent measure and are allocated to individual generators to meet planning reserve margin requirements within MISO. For 2015, Montana-Dakota's total ZRCs, including its firm purchase power contracts, were 547.3. Montana-Dakota's planning reserve margin requirement within MISO was 547.3 for 2015. Montana-Dakota's interconnected system electric generating capability includes four steam-turbine generating units using coal for fuel, three combustion turbine peaking stations, three wind electric generating facilities, a reciprocating internal combustion engine, a heat recovery electric generating facility and three small portable diesel generators.

In December 2015, construction was completed on a wind farm consisting of 43 wind turbines totaling 107.5 MW of electric generation. On December 30, 2015, Montana-Dakota purchased the wind farm from Thunder Spirit Wind, LLC, at a total cost of approximately $214 million including purchase price, internal costs and AFUDC with approximately $55 million already funded in 2014. The project began commercial operation in the fourth quarter of 2015. The generation interconnects at Montana-Dakota's substation near Hettinger, North Dakota. Montana-Dakota completed construction and commissioning of an 18.7 MW reciprocating internal combustion engine electric generation project at the existing Lewis & Clark generating facility in Sidney, Montana in December of 2015. Additional energy will be purchased as needed, or if more economical, from the MISO market. In 2015, Montana-Dakota purchased approximately 47 percent of its net kWh needs for its interconnected system through the MISO market.

Through the Sheridan System, Montana-Dakota serves Sheridan, Wyoming, and neighboring communities. The maximum peak demand experienced to date attributable to Montana-Dakota sales to retail customers on that system was approximately 61,501 kW in July 2012. Montana-Dakota has a power supply contract with Black Hills Power, Inc. to purchase up to 49,000 kW of capacity annually through December 31, 2016. Wygen III serves a portion of the needs of its Sheridan-area customers.

8 MDU Resources Group, Inc. Form 10-K

Part I

The following table sets forth details applicable to the Company's electric generating stations:



Generating Station	Type	Nameplate Rating (kW)	2015 ZRCs	(a)	2015 Net Generation (kWh in thousands)
Interconnected System:
North Dakota:
Coyote (b)	Steam	103,647	92.7		481,995
Heskett	Steam	86,000	87.2		500,630
Heskett	Combustion Turbine	89,038	70.8		1,211
Glen Ullin	Heat Recovery	7,500	3.4		38,248
Cedar Hills	Wind	19,500	4.5		57,147
Diesel Units	Oil	5,475	3.6		9
Thunder Spirit	Wind	107,500	(c)		11,174
South Dakota:
Big Stone (b)	Steam	94,111	98.8		303,844
Montana:
Lewis & Clark	Steam	44,000	52.1		222,192
Lewis & Clark	Reciprocating Internal Combustion Engine	18,700	(c)		96
Glendive	Combustion Turbine	75,522	73.2		1,212
Miles City	Combustion Turbine	23,150	21.4		443
Diamond Willow	Wind	30,000	5.5		89,144
		704,143	513.2		1,707,345
Sheridan System:
Wyoming:
Wygen III (b)	Steam	28,000	N/A		190,815
		732,143	513.2		1,898,160


(a)	Interconnected system only. MISO requires generators to obtain their summer capability through the GVTC. The GVTC is then converted to ZRCs by applying each generator's forced outage factor against its GVTC. Wind generator's ZRCs are calculated based on a wind capacity study performed annually by MISO. ZRCs are used to meet supply obligations within MISO.


(b)	Reflects Montana-Dakota's ownership interest.


(c)	Pending accreditation.

Virtually all of the current fuel requirements of the Coyote, Heskett and Lewis & Clark stations are met with coal supplied by subsidiaries of Westmoreland Coal Company under contracts that expire in May 2016, December 2021 and December 2017, respectively. The Coyote Station coal supply agreement provides for the purchase of coal necessary to supply the coal requirements of the Coyote Station or 30,000 tons per week, whichever may be the greater quantity at contracted pricing. The Heskett and Lewis & Clark coal supply agreements provide for the purchase of coal necessary to supply the coal requirements of these stations at contracted pricing. Montana-Dakota estimates the Heskett and Lewis & Clark coal requirement to be in the range of 450,000 to 550,000 tons and 250,000 to 350,000 tons per contract year, respectively.

The owners of Coyote Station, including Montana-Dakota, have a contract with Coyote Creek for coal supply to the Coyote Station beginning May 2016 until December 2040. Montana-Dakota estimates the Coyote Station coal supply agreement to be approximately 2.5 million tons per contract year. For more information, see Item 8 - Note 17.

The owners of Big Stone Station, including Montana-Dakota, have coal supply agreements, which meet a portion of the Big Stone Station's fuel requirements, for the purchase of 500,000 tons in 2016 from Peabody Coalsales, LLC and 750,000 in 2016 and 2017 from Alpha Coal Sales Co., LLC both at contracted pricing. The remainder of the Big Stone Station fuel requirements will be secured through separate future contracts.

Montana-Dakota has a coal supply agreement with Wyodak Resources Development Corp., to supply the coal requirements of Wygen III at contracted pricing through June 1, 2060. Montana-Dakota estimates the maximum annual coal consumption of the facility to be 585,000 tons.

MDU Resources Group, Inc. Form 10-K 9

Part I

The average cost of coal purchased, including freight, at Montana-Dakota's electric generating stations (including the Big Stone, Coyote and Wygen III stations) was as follows:



Years ended December 31,	2015		2014		2013
Average cost of coal per MMBtu	$	1.75	$	1.74	$	1.73
Average cost of coal per ton	$	25.41	$	25.11	$	25.32

Montana-Dakota expects that it has secured adequate capacity available through existing baseload generating stations, renewable generation, turbine peaking stations, demand reduction programs and firm contracts to meet the peak customer demand requirements of its customers through mid-2017. Future capacity that is needed to replace contracts and meet system growth requirements is expected to be met by constructing new generation resources, or acquiring additional capacity through power purchase contracts or the MISO capacity auction. For more information regarding potential power generation projects, see Item 7 - MD&A - Prospective Information - Electric and natural gas distribution.

Montana-Dakota has major interconnections with its neighboring utilities and considers these interconnections adequate for coordinated planning, emergency assistance, exchange of capacity and energy and power supply reliability.

Montana-Dakota is subject to competition in varying degrees, in certain areas, from rural electric cooperatives, on-site generators, co-generators and municipally owned systems. In addition, competition in varying degrees exists between electricity and alternative forms of energy such as natural gas.

Regulatory Matters and Revenues Subject to Refund In North Dakota, Montana-Dakota reflects monthly increases or decreases in fuel and purchased power costs (including demand charges) and is deferring those electric fuel and purchased power costs that are greater or less than amounts presently being recovered through its existing rate schedules. In Montana, a monthly Fuel and Purchased Power Tracking Adjustment mechanism allows Montana-Dakota to reflect 90 percent of the increases or decreases in fuel and purchased power costs (including demand charges) and Montana-Dakota is deferring 90 percent of costs that are greater or less than amounts presently being recovered through its existing rate schedules. A fuel adjustment clause contained in South Dakota jurisdictional electric rate schedules allows Montana-Dakota to reflect monthly increases or decreases in fuel and purchased power costs (excluding demand charges). In Wyoming, an annual Electric Power Supply Cost Adjustment mechanism allows Montana-Dakota to reflect increases or decreases in purchased power costs (including demand charges but excluding increases or decreases from base coal price) related to power supply and Montana-Dakota is deferring costs that are greater or less than amounts presently being recovered through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments which are filed annually. For more information, see Item 8 - Note 4.

In North Dakota, Montana-Dakota recovers in rates the costs associated with environmental upgrades at Big Stone Station and Lewis & Clark Station. Montana-Dakota will maintain a tracker account until all costs are recovered or until the associated costs are reflected in base rates as a part of a general rate case.

In North Dakota, Montana-Dakota has the ability to recover the costs associated with new generation through a rider mechanism. Montana-Dakota will utilize this rider mechanism for new generation until such time as the costs and investment are included in base rates. For the Thunder Spirit Wind project, Montana-Dakota implemented a renewable resource cost adjustment rider. Montana-Dakota also has in place in North Dakota a transmission tracker to recover transmission costs from its regional transmission operator, MISO. The tracking mechanism has an annual true-up.

For more information on regulatory matters, see Item 8 - Note 16.

Environmental Matters Montana-Dakota's electric operations are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations; and state hazard communication standards. Montana-Dakota believes it is in substantial compliance with these regulations.

Montana-Dakota's electric generating facilities have Title V Operating Permits, under the Clean Air Act, issued by the states in which they operate. Each of these permits has a five-year life. Near the expiration of these permits, renewal applications are submitted. Permits continue in force beyond the expiration date, provided the application for renewal is submitted by the required date, usually six months prior to expiration. The Title V Operating Permit renewal application for Big Stone Station was submitted timely to the South Dakota DENR in November 2013. Big Stone Station continues to operate under conditions of the Title V Operating Permit issued by the South Dakota DENR in June 2009. It is expected that a final renewed permit will be issued in 2016 with the completion of the BART air quality control system. Wygen III is allowed to operate under the facility's construction permit until the Title V Operating Permit is issued by the Wyoming

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Department of Environmental Quality. The Title V Operating Permit application for Wygen III was submitted timely in January 2011, with the permit expected to be issued in 2016. The Title V Operating Permit renewal application for Lewis & Clark Station was submitted timely in February 2014 to the Montana DEQ and the permit was issued July 2015. The Title V Operating Permit renewal application for Heskett Station was submitted timely in August 2014 to the North Dakota Department of Health and the permit was issued July 2015. The Title V Operating Permits for the Miles City and Glendive stations expire in August 2016, and the renewal applications are expected to be submitted to the Montana DEQ in early 2016.

State water discharge permits issued under the requirements of the Clean Water Act are maintained for power production facilities on the Yellowstone and Missouri rivers. These permits also have five-year lives. Montana-Dakota renews these permits as necessary prior to expiration. Other permits held by these facilities may include an initial siting permit, which is typically a one-time, preconstruction permit issued by the state; state permits to dispose of combustion by-products; state authorizations to withdraw water for operations; and Army Corps permits to construct water intake structures. Montana-Dakota's Army Corps permits grant one-time permission to construct and do not require renewal. Other permit terms vary and the permits are renewed as necessary.

Montana-Dakota's electric operations are conditionally exempt small-quantity hazardous waste generators and subject only to minimum regulation under the RCRA. Montana-Dakota routinely handles PCBs from its electric operations in accordance with federal requirements. PCB storage areas are registered with the EPA as required.

Montana-Dakota incurred $46.0 million of environmental capital expenditures in 2015, largely for the installation of a BART air quality control system at the Big Stone Station. Environmental capital expenditures are estimated to be $14.8 million, $4.1 million and $2.8 million in 2016, 2017 and 2018, respectively. Projects for 2016 through 2018 include sulfur-dioxide, nitrogen oxide and mercury and non-mercury metals emission control equipment installation and anticipated costs for coal ash disposal at electric generating stations. Montana-Dakota's capital and operational expenditures could also be affected in a variety of ways by future air emission regulations and coal ash management requirements, including the Clean Power Plan rule published by the EPA in October 2015. Montana-Dakota is evaluating the Clean Power Plan, which requires existing fossil fuel-fired electric generation facilities to reduce carbon dioxide emissions. It is unknown at this time what each state will require for emissions limits or reductions from each of Montana-Dakota's owned and jointly owned fossil fuel-fired electric generating units. Compliance costs will become clearer as final state plans are completed and submitted to the EPA by September 2018. On February 9, 2016, the United States Supreme Court granted an application for a stay of the Clean Power Plan pending disposition of the applicants' petition for review in the D.C. Circuit Court and disposition of the applicants' petition for a writ of certiorari if such a writ is sought. Montana-Dakota has not included estimates for capital expenditures in 2016 through 2018 for the potential compliance requirements of the Clean Power Plan.

Natural Gas Distribution

General The Company's natural gas distribution operations consist of Montana-Dakota, Great Plains, Cascade and Intermountain, which sell natural gas at retail, serving over 906,000 residential, commercial and industrial customers in 334 communities and adjacent rural areas across eight states as of December 31, 2015, and provide natural gas transportation services to certain customers on the Company's systems. These services are provided through distribution systems aggregating approximately 19,100 miles. The natural gas distribution operations have obtained and hold, or are in the process of renewing, valid and existing franchises authorizing them to conduct their natural gas operations in all of the municipalities they serve where such franchises are required. These operations intend to protect their service areas and seek renewal of all expiring franchises. At December 31, 2015, the natural gas distribution operations' net natural gas distribution plant investment was $1.3 billion.

The percentage of the natural gas distribution operations' 2015 natural gas utility operating sales revenues by jurisdiction is as follows: Idaho - 32 percent; Washington - 26 percent; North Dakota - 15 percent; Montana - 8 percent; Oregon - 8 percent; South Dakota - 6 percent; Minnesota - 3 percent; and Wyoming - 2 percent. The natural gas distribution operations are subject to regulation by the IPUC, MNPUC, MTPSC, NDPSC, OPUC, SDPUC, WUTC and WYPSC regarding retail rates, service, accounting and certain security issuances.

System Supply, System Demand and Competition The natural gas distribution operations serve retail natural gas markets, consisting principally of residential and firm commercial space and water heating users, in portions of Idaho, including Boise, Nampa, Twin Falls, Pocatello and Idaho Falls; western Minnesota, including Fergus Falls, Marshall and Crookston; eastern Montana, including Billings, Glendive and Miles City; North Dakota, including Bismarck, Mandan, Dickinson, Wahpeton, Williston, Watford City, Minot and Jamestown; central and eastern Oregon, including Bend, Pendleton, Ontario and Baker City; western and north-central South Dakota, including Rapid City, Pierre, Spearfish and Mobridge; western, southeastern and south-central Washington, including Bellingham, Bremerton, Longview, Aberdeen, Wenatchee/Moses Lake, Mount Vernon, Tri-Cities, Walla Walla and Yakima; and northern Wyoming, including Sheridan and Lovell. These markets are highly seasonal and sales volumes depend largely on the weather, the effects of which are mitigated in certain jurisdictions by a weather normalization mechanism discussed in Regulatory Matters. In addition to the residential and commercial sales, the utilities transport natural gas for larger commercial and industrial customers who purchase their own supply of natural gas.

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Competition in varying degrees exists between natural gas and other fuels and forms of energy. The natural gas distribution operations have established various natural gas transportation service rates for their distribution businesses to retain interruptible commercial and industrial loads. These services have enhanced the natural gas distribution operations' competitive posture with alternative fuels, although certain customers have bypassed the distribution systems by directly accessing transmission pipelines within close proximity. These bypasses did not have a material effect on results of operations.

The natural gas distribution operations and various distribution transportation customers obtain their system requirements directly from producers, processors and marketers. The Company's purchased natural gas is supplied by a portfolio of contracts specifying market-based pricing and is transported under transportation agreements with WBI Energy Transmission, Northern Border Pipeline Company, Northwest Pipeline GP, Northern Natural Gas, Gas Transmission Northwest LLC, Northwestern Energy, Viking Gas Transmission Company, Westcoast Energy Inc., Ruby Pipeline LLC, Foothills Pipe Lines Ltd. and NOVA Gas Transmission Ltd. The natural gas distribution operations have contracts for storage services to provide gas supply during the winter heating season and to meet peak day demand with various storage providers, including WBI Energy Transmission, Questar Pipeline Company, Northwest Pipeline GP and Northern Natural Gas. In addition, certain of the operations have entered into natural gas supply management agreements with various parties. Demand for natural gas, which is a widely traded commodity, has historically been sensitive to seasonal heating and industrial load requirements as well as changes in market price. The natural gas distribution operations believe that, based on current and projected domestic and regional supplies of natural gas and the pipeline transmission network currently available through their suppliers and pipeline service providers, supplies are adequate to meet their system natural gas requirements for the next decade.

Regulatory Matters The natural gas distribution operations' retail natural gas rate schedules contain clauses permitting adjustments in rates based upon changes in natural gas commodity, transportation and storage costs. Current tariffs allow for recovery or refunds of under- or over-recovered gas costs through rate adjustments which are filed annually.

Montana-Dakota's North Dakota and South Dakota natural gas tariffs contain weather normalization mechanisms applicable to certain firm customers that adjust the distribution delivery charge revenues to reflect weather fluctuations during the November 1 through May 1 billing periods.

On December 28, 2015, the OPUC approved an extension of Cascade's decoupling mechanism until January 1, 2020, with an agreement that Cascade would initiate a review of the mechanism by September 30, 2019. Cascade also has an earnings sharing mechanism with respect to its Oregon jurisdictional operations as required by the OPUC.

For more information on regulatory matters, see Item 8 - Note 16.

Environmental Matters The natural gas distribution operations are subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations. The natural gas distribution operations believe they are in substantial compliance with those regulations.

The Company's natural gas distribution operations are conditionally exempt small-quantity hazardous waste generators and subject only to minimum regulation under the RCRA. Certain locations of the natural gas distribution operations routinely handle PCBs from their natural gas operations in accordance with federal requirements. PCB storage areas are registered with the EPA as required. Capital and operational expenditures for natural gas distribution operations could be affected in a variety of ways by potential new GHG legislation or regulation. In particular, such legislation or regulation would likely increase capital expenditures for energy efficiency and conservation programs and operational costs associated with GHG emissions compliance. Natural gas distribution operations expect to recover the operational and capital expenditures for GHG regulatory compliance in rates consistent with the recovery of other reasonable costs of complying with environmental laws and regulations.

The natural gas distribution operations did not incur any material environmental expenditures in 2015. Except as to what may be ultimately determined with regard to the issues described later, the natural gas distribution operations do not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2018.

Montana-Dakota has had an economic interest in four historic manufactured gas plants and Great Plains has had an economic interest in one historic manufactured gas plant within their service territories. Montana-Dakota is investigating a former manufactured gas plant in Montana and is planning an investigation of a former manufactured gas plant in North Dakota. Montana-Dakota will seek recovery in its natural gas rates charged to customers for any remediation costs incurred for these sites. None of the remaining former manufactured gas plant sites of Montana-Dakota or Great Plains are being actively investigated. Cascade has had an economic interest in nine former manufactured gas plants within its service territory. Cascade has been involved in the investigation and remediation of three manufactured gas plants in Washington and Oregon. See Item 8 - Note 17 for a further discussion of these three manufactured gas plants. To the extent these claims are not covered by insurance, Cascade will seek recovery through the OPUC and WUTC of remediation costs in its natural gas rates charged to customers.

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Part I

Pipeline and Midstream

General WBI Energy owns and operates both regulated and nonregulated businesses. The regulated business of this segment, WBI Energy Transmission, owns and operates approximately 4,000 miles of transmission, gathering and storage lines in Montana, North Dakota, South Dakota and Wyoming. Three underground storage fields in Montana and Wyoming provide storage services to local distribution companies, producers, natural gas marketers and others, and serve to enhance system deliverability. Its system is strategically located near five natural gas producing basins, making natural gas supplies available to its transportation and storage customers. The system has 13 interconnecting points with other pipeline facilities allowing for the receipt and/or delivery of natural gas to and from other regions of the country and from Canada. Under the Natural Gas Act, as amended, WBI Energy Transmission is subject to the jurisdiction of the FERC regarding certificate, rate, service and accounting matters, and at December 31, 2015, its net plant investment was $363.4 million.

The nonregulated business of this segment owns and operates gathering facilities in Montana and Wyoming. In 2015, the Company sold its gathering facilities in Colorado. It also owns a 50 percent undivided interest in the Pronghorn assets located in western North Dakota, which include a natural gas processing plant, both oil and gas gathering pipelines, an oil storage terminal and an oil pipeline. In total, facilities include approximately 800 miles of operated field gathering lines, some of which interconnect with WBI Energy's regulated pipeline system. The nonregulated business provides natural gas and oil gathering services, natural gas processing and a variety of other energy-related services, including cathodic protection, water hauling, contract compression operations, measurement services, and energy efficiency product sales and installation services to large end-users.

A majority of its pipeline and midstream business is transacted in the northern Great Plains and Rocky Mountain regions of the United States.

For information regarding natural gas gathering operations litigation, see Item 8 - Note 17.

System Supply, System Demand and Competition Natural gas supplies emanate from traditional and nontraditional production activities in the region and from off-system supply sources. While certain traditional regional supply sources are in various stages of decline, incremental supply from nontraditional sources have been developed which has helped support WBI Energy Transmission's supply needs. This includes new natural gas supply associated with the continued development of the Bakken area in Montana and North Dakota. In addition, off-system supply sources are available through the Company's interconnections with other pipeline systems. WBI Energy Transmission expects to facilitate the movement of these supplies by making available its transportation and storage services. WBI Energy Transmission will continue to look for opportunities to increase transportation, gathering and storage services through system expansion and/or other pipeline interconnections or enhancements that could provide substantial future benefits.

WBI Energy Transmission's underground natural gas storage facilities have a certificated storage capacity of approximately 353 Bcf, including 193 Bcf of working gas capacity, 85 Bcf of cushion gas and 75 Bcf of native gas. These storage facilities enable customers to purchase natural gas at more uniform daily volumes throughout the year and meet winter peak requirements.

WBI Energy Transmission competes with several pipelines for its customers' transportation, storage and gathering business and at times may discount rates in an effort to retain market share. However, the strategic location of its system near five natural gas producing basins and the availability of underground storage and gathering services, along with interconnections with other pipelines, serve to enhance its competitive position.

Although certain of WBI Energy Transmission's firm customers, including its largest firm customer Montana-Dakota, serve relatively secure residential and commercial end-users, they generally all have some price-sensitive end-users that could switch to alternate fuels.

WBI Energy Transmission transports substantially all of Montana-Dakota's natural gas, primarily utilizing firm transportation agreements, which for 2015 represented 43 percent of WBI Energy Transmission's subscribed firm transportation contract demand. The majority of the firm transportation agreements with Montana-Dakota expire in June 2017. In addition, Montana-Dakota has contracts with WBI Energy Transmission to provide firm storage services to facilitate meeting Montana-Dakota's winter peak requirements expiring in July 2035.

The nonregulated business competes with several midstream companies for existing customers, the expansion of its systems and the installation of new systems. Its strong position in the fields in which it operates, its focus on customer service and the variety of services it offers, along with its interconnection with various other pipelines, serve to enhance its competitive position.

Environmental Matters The pipeline and midstream operations are generally subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations. The Company believes it is in substantial compliance with those regulations.

Ongoing operations are subject to the Clean Air Act, the Clean Water Act, the RCRA and other state and federal regulations. Administration of many provisions of these laws has been delegated to the states where WBI Energy and its subsidiaries operate. Permit terms vary and all

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permits carry operational compliance conditions. Some permits require annual renewal, some have terms ranging from one to five years and others have no expiration date. Permits are renewed and modified, as necessary, based on defined permit expiration dates, operational demand and/or regulatory changes.

Detailed environmental assessments and/or environmental impact statements as required by the National Environmental Policy Act are included in the FERC's environmental review process for both the construction and abandonment of WBI Energy Transmission's natural gas transmission pipelines, compressor stations and storage facilities.

The pipeline and midstream operations did not incur any material environmental expenditures in 2015 and do not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2018.

Construction Materials and Contracting

General Knife River operates construction materials and contracting businesses headquartered in Alaska, California, Hawaii, Idaho, Iowa, Minnesota, Montana, North Dakota, Oregon, Texas, Washington and Wyoming. These operations mine, process and sell construction aggregates (crushed stone, sand and gravel); produce and sell asphalt mix and supply ready-mixed concrete for use in most types of construction, including roads, freeways and bridges, as well as homes, schools, shopping centers, office buildings and industrial parks. Although not common to all locations, other products include the sale of cement, liquid asphalt for various commercial and roadway applications, various finished concrete products and other building materials and related contracting services.

For information regarding construction materials litigation, see Item 8 - Note 17.

The construction materials business had approximately $491 million in backlog at December 31, 2015, compared to $438 million at December 31, 2014. The Company anticipates that a significant amount of the current backlog will be completed during 2016.

Competition Knife River's construction materials products are marketed under highly competitive conditions. Price is the principal competitive force to which these products are subject, with service, quality, delivery time and proximity to the customer also being significant factors. The number and size of competitors varies in each of Knife River's principal market areas and product lines.

The demand for construction materials products is significantly influenced by the cyclical nature of the construction industry in general. In addition, construction materials activity in certain locations may be seasonal in nature due to the effects of weather. The key economic factors affecting product demand are changes in the level of local, state and federal governmental spending, general economic conditions within the market area that influence both the commercial and residential sectors, and prevailing interest rates.

Knife River is not dependent on any single customer or group of customers for sales of its products and services, the loss of which would have a material adverse effect on its construction materials businesses.

Reserve Information Aggregate reserve estimates are calculated based on the best available data. This data is collected from drill holes and other subsurface investigations, as well as investigations of surface features such as mine high walls and other exposures of the aggregate reserves. Mine plans, production history and geologic data also are utilized to estimate reserve quantities. Most acquisitions are made of mature businesses with established reserves, as distinguished from exploratory-type properties.

Estimates are based on analyses of the data described above by experienced internal mining engineers, operating personnel and geologists. Property setbacks and other regulatory restrictions and limitations are identified to determine the total area available for mining. Data described previously are used to calculate the thickness of aggregate materials to be recovered. Topography associated with alluvial sand and gravel deposits is typically flat and volumes of these materials are calculated by applying the thickness of the resource over the areas available for mining. Volumes are then converted to tons by using an appropriate conversion factor. Typically, 1.5 tons per cubic yard in the ground is used for sand and gravel deposits.

Topography associated with the hard rock reserves is typically much more diverse. Therefore, using available data, a final topography map is created and computer software is utilized to compute the volumes between the existing and final topographies. Volumes are then converted to tons by using an appropriate conversion factor. Typically, 2 tons per cubic yard in the ground is used for hard rock quarries.

Estimated reserves are probable reserves as defined in Securities Act Industry Guide 7. Remaining reserves are based on estimates of volumes that can be economically extracted and sold to meet current market and product applications. The reserve estimates include only salable tonnage and thus exclude waste materials that are generated in the crushing and processing phases of the operation. Approximately 955 million tons of the 1.0 billion tons of aggregate reserves are permitted reserves. The remaining reserves are on properties that are expected to be permitted for mining under current regulatory requirements. The data used to calculate the remaining reserves may require revisions in the future to account for changes in customer requirements and unknown geological occurrences. The years remaining

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were calculated by dividing remaining reserves by the three-year average sales from 2013 through 2015. Actual useful lives of these reserves will be subject to, among other things, fluctuations in customer demand, customer specifications, geological conditions and changes in mining plans.

The following table sets forth details applicable to the Company's aggregate reserves under ownership or lease as of December 31, 2015, and sales for the years ended December 31, 2015, 2014 and 2013:



	Number of Sites (Crushed Stone)		Number of Sites (Sand & Gravel)		Tons Sold (000's)			Estimated Reserves (000's tons)	Lease Expiration	Reserve Life (years)
Production Area	owned	leased	owned	leased	2015	2014	2013	Estimated Reserves (000's tons)	Lease Expiration	Reserve Life (years)
Anchorage, AK	—	—	1	—	1,837	1,665	1,074	17,315	N/A	11
Hawaii	—	6	—	—	1,892	1,840	1,672	53,992	2017-2064	30
Northern CA	—	—	9	1	1,580	1,340	1,525	52,204	2018	35
Southern CA	—	2	—	—	118	147	241	91,846	2035	Over 100
Portland, OR	1	3	5	3	3,562	3,244	3,343	225,148	2025-2055	67
Eugene, OR	3	4	4	—	819	928	825	155,566	2016-2046	Over 100
Central OR/WA/ID	1	1	5	4	1,493	1,254	1,045	113,867	2020-2077	90
Southwest OR	5	5	12	5	1,872	1,624	1,465	93,592	2017-2053	57
Central MT	—	—	1	2	1,383	1,260	1,236	26,094	2023-2027	20
Northwest MT	—	—	7	2	1,423	1,486	1,242	63,140	2016-2020	46
Wyoming	—	—	1	1	888	952	983	9,731	2019	10
Central MN	—	1	38	12	2,556	1,674	1,578	55,091	2016-2028	28
Northern MN	2	—	14	5	595	491	349	25,330	2016-2017	53
ND/SD	—	—	3	19	1,959	2,377	1,862	27,453	2016-2031	13
Texas	1	2	1	—	1,138	903	672	12,144	2022	13
Sales from other sources					3,844	4,642	5,601
					26,959	25,827	24,713	1,022,513

The 1.0 billion tons of estimated aggregate reserves at December 31, 2015, are comprised of 476 million tons that are owned and 547 million tons that are leased. Approximately 31 percent of the tons under lease have lease expiration dates of 20 years or more. The weighted average years remaining on all leases containing estimated probable aggregate reserves is approximately 22 years, including options for renewal that are at Knife River's discretion. Based on a three-year average of sales from 2013 through 2015 of leased reserves, the average time necessary to produce remaining aggregate reserves from such leases is approximately 61 years. Some sites have leases that expire prior to the exhaustion of the estimated reserves. The estimated reserve life assumes, based on Knife River's experience, that leases will be renewed to allow sufficient time to fully recover these reserves.

The changes in Knife River's aggregate reserves for the years ended December 31 were as follows:



	2015		2014		2013
			(000's of tons)
Aggregate reserves:
Beginning of year	1,061,156		1,083,376		1,088,236
Acquisitions	7,406		12,343		22,682
Sales volumes*	(23,115	)	(21,185	)	(19,112	)
Other**	(22,934	)	(13,378	)	(8,430	)
End of year	1,022,513		1,061,156		1,083,376


*	Excludes sales from other sources.


**	Includes property sales, revisions of previous estimates and expiring leases.

Environmental Matters Knife River's construction materials and contracting operations are subject to regulation customary for such operations, including federal, state and local environmental compliance and reclamation regulations. Except as to the issues described later, Knife River believes it is in substantial compliance with these regulations. Individual permits applicable to Knife River's various operations are managed largely by local operations, particularly as they relate to application, modification, renewal, compliance and reporting procedures.

Knife River's asphalt and ready-mixed concrete manufacturing plants and aggregate processing plants are subject to Clean Air Act and Clean Water Act requirements for controlling air emissions and water discharges. Some mining and construction activities also are subject to these

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laws. In most of the states where Knife River operates, these regulatory programs have been delegated to state and local regulatory authorities. Knife River's facilities also are subject to the RCRA as it applies to the management of hazardous wastes and underground storage tank systems. These programs also have generally been delegated to the state and local authorities in the states where Knife River operates. Knife River's facilities must comply with requirements for managing wastes and underground storage tank systems.

Some Knife River activities are directly regulated by federal agencies. For example, certain in-water mining operations are subject to provisions of the Clean Water Act that are administered by the Army Corps. Knife River operates several such operations, including gravel bar skimming and dredging operations, and Knife River has the associated permits as required. The expiration dates of these permits vary, with five years generally being the longest term.

Knife River's operations also are occasionally subject to the ESA. For example, land use regulations often require environmental studies, including wildlife studies, before a permit may be granted for a new or expanded mining facility or an asphalt or concrete plant. If endangered species or their habitats are identified, ESA requirements for protection, mitigation or avoidance apply. Endangered species protection requirements are usually included as part of land use permit conditions. Typical conditions include avoidance, setbacks, restrictions on operations during certain times of the breeding or rearing season, and construction or purchase of mitigation habitat. Knife River's operations also are subject to state and federal cultural resources protection laws when new areas are disturbed for mining operations or processing plants. Land use permit applications generally require that areas proposed for mining or other surface disturbances be surveyed for cultural resources. If any are identified, they must be protected or managed in accordance with regulatory agency requirements.

The most comprehensive environmental permit requirements are usually associated with new mining operations, although requirements vary widely from state to state and even within states. In some areas, land use regulations and associated permitting requirements are minimal. However, some states and local jurisdictions have very demanding requirements for permitting new mines. Environmental impact reports are sometimes required before a mining permit application can even be considered for approval. These reports can take up to several years to complete. The report can include projected impacts of the proposed project on air and water quality, wildlife, noise levels, traffic, scenic vistas and other environmental factors. The reports generally include suggested actions to mitigate the projected adverse impacts.

Provisions for public hearings and public comments are usually included in land use permit application review procedures in the counties where Knife River operates. After taking into account environmental, mine plan and reclamation information provided by the permittee as well as comments from the public and other regulatory agencies, the local authority approves or denies the permit application. Denial is rare, but land use permits often include conditions that must be addressed by the permittee. Conditions may include property line setbacks, reclamation requirements, environmental monitoring and reporting, operating hour restrictions, financial guarantees for reclamation, and other requirements intended to protect the environment or address concerns submitted by the public or other regulatory agencies.

Knife River has been successful in obtaining mining and other land use permit approvals so sufficient permitted reserves are available to support its operations. For mining operations, this often requires considerable advanced planning to ensure sufficient time is available to complete the permitting process before the newly permitted aggregate reserve is needed to support Knife River's operations.

Knife River's Gascoyne surface coal mine last produced coal in 1995 but continues to be subject to reclamation requirements of the Surface Mining Control and Reclamation Act, as well as the North Dakota Surface Mining Act. Portions of the Gascoyne Mine remain under reclamation bond until the 10-year revegetation liability period has expired. A portion of the original permit has been released from bond and additional areas are currently in the process of having the bond released. Knife River's intention is to request bond release as soon as it is deemed possible.

Knife River did not incur any material environmental expenditures in 2015 and, except as to what may be ultimately determined with regard to the issues described later, Knife River does not expect to incur any material expenditures related to environmental compliance with current laws and regulations through 2018.

In December 2000, Knife River - Northwest was named by the EPA as a PRP in connection with the cleanup of a commercial property site, acquired by Knife River - Northwest in 1999, and part of the Portland, Oregon, Harbor Superfund Site. For more information, see Item 8 - Note 17.

In October 2015, the Oregon DEQ issued a Notice of Civil Penalty to LTM asserting violations of Oregon water quality statues and rules at a site in Coos County. For more information, see Item 8 - Note 17.

Mine Safety The Dodd-Frank Act requires disclosure of certain mine safety information. For more information, see Item 4 - Mine Safety Disclosures.

16 MDU Resources Group, Inc. Form 10-K

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Construction Services

General MDU Construction Services provides utility construction services specializing in constructing and maintaining electric and communication lines, gas pipelines, fire suppression systems, and external lighting and traffic signalization. This segment also provides utility excavation and inside electrical and mechanical services, and manufactures and distributes transmission line construction equipment and other supplies. These services are provided to utilities and large manufacturing, commercial, industrial, institutional and government customers.

For information regarding construction services litigation, see Item 8 - Note 17.

Construction and maintenance crews are active year round. However, activity in certain locations may be seasonal in nature due to the effects of weather.

MDU Construction Services operates a fleet of owned and leased trucks and trailers, support vehicles and specialty construction equipment, such as backhoes, excavators, trenchers, generators, boring machines and cranes. In addition, as of December 31, 2015, MDU Construction Services owned or leased facilities in 17 states. This space is used for offices, equipment yards, warehousing, storage and vehicle shops.

MDU Construction Services' backlog is comprised of the uncompleted portion of services to be performed under job-specific contracts. The backlog at December 31, 2015, was approximately $493 million compared to $305 million at December 31, 2014. MDU Construction Services expects to complete a significant amount of this backlog during 2016. Due to the nature of its contractual arrangements, in many instances MDU Construction Services' customers are not committed to the specific volumes of services to be purchased under a contract, but rather MDU Construction Services is committed to perform these services if and to the extent requested by the customer. Therefore, there can be no assurance as to the customers' requirements during a particular period or that such estimates at any point in time are predictive of future revenues.

MDU Construction Services works with the National Electrical Contractors Association, the IBEW and other trade associations on hiring and recruiting a qualified workforce.

Competition MDU Construction Services operates in a highly competitive business environment. Most of MDU Construction Services' work is obtained on the basis of competitive bids or by negotiation of either cost-plus or fixed-price contracts. The workforce and equipment are highly mobile, providing greater flexibility in the size and location of MDU Construction Services' market area. Competition is based primarily on price and reputation for quality, safety and reliability. The size and location of the services provided, as well as the state of the economy, will be factors in the number of competitors that MDU Construction Services will encounter on any particular project. MDU Construction Services believes that the diversification of the services it provides, the markets it serves throughout the United States and the management of its workforce will enable it to effectively operate in this competitive environment.

Utilities and independent contractors represent the largest customer base for this segment. Accordingly, utility and subcontract work accounts for a significant portion of the work performed by MDU Construction Services and the amount of construction contracts is dependent to a certain extent on the level and timing of maintenance and construction programs undertaken by customers. MDU Construction Services relies on repeat customers and strives to maintain successful long-term relationships with these customers.

Environmental Matters MDU Construction Services' operations are subject to regulation customary for the industry, including federal, state and local environmental compliance. MDU Construction Services believes it is in substantial compliance with these regulations.

The nature of MDU Construction Services' operations is such that few, if any, environmental permits are required. Operational convenience supports the use of petroleum storage tanks in several locations, which are permitted under state programs authorized by the EPA. MDU Construction Services has no ongoing remediation related to releases from petroleum storage tanks. MDU Construction Services' operations are conditionally exempt small-quantity waste generators, subject to minimal regulation under the RCRA. Federal permits for specific construction and maintenance jobs that may require these permits are typically obtained by the hiring entity, and not by MDU Construction Services.

MDU Construction Services did not incur any material environmental expenditures in 2015 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2018.

Refining

General WBI Energy, in conjunction with Calumet, formed Dakota Prairie Refining, to develop, build and operate Dakota Prairie Refinery. The refinery is designed as a 20,000-barrel-per-day facility located in the Bakken region in Stark County in western North Dakota.

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Construction of the refinery was completed in March 2015 and the refinery began commercial operations in May 2015. The refinery processes Bakken crude oil into diesel, naphtha, ATBs and other by-products.

System Supply, System Demand and Competition Bakken crude oil is supplied to the refinery via a pipeline interconnect with the Belle Fourche Pipeline and a portion is trucked to the refinery from wells near the refinery. Crude oil contracts are generally secured on a month-to-month basis. Dakota Prairie Refining believes that adequate supplies of crude oil will continue to be available; however, more challenging to secure due to the slowdown in drilling activity in the Bakken region.

The refinery sells diesel fuel at the refinery rack to diesel wholesalers. Naphtha is railed to Canada and sold to third parties primarily for use as a diluent for tar sands production. ATBs are railed and sold to other facilities for further processing.

Dakota Prairie Refining's competitors include a number of large, integrated refiners with greater flexibility in responding to or absorbing market changes. Dakota Prairie Refining obtains all of its crude oil from third-party sources and competes with other purchasers in the local market area for these supplies. The availability and cost of crude oil, as well as the demand for and prices of the products the refining operations produce, are heavily influenced by global, as well as regional, supply and demand dynamics. Major competitors for the sale of Dakota Prairie Refining's refined products include other refineries both in the state and in the surrounding states that produce similar products.

Environmental Matters Refinery operations are subject to numerous federal, state and local laws regulating the discharge of substances into the environment or otherwise relating to the protection of the environment. Permits are required under these laws for the operation of refineries, pipelines and related refining operations facilities, and these permits are subject to revocation, modification and renewal. Compliance with applicable environmental laws, regulations and permits will continue to have an impact on refining operations, results of operations, and capital requirements. Dakota Prairie Refining believes that its current operations are in substantial compliance with applicable federal, state and local environmental laws, regulations and permits.

Dakota Prairie Refining's operations and many of the products it manufactures are subject to certain requirements of the Clean Air Act as well as related state and local laws and regulations. The EPA has the authority under the Clean Air Act to modify the formulation of the refined transportation fuel products Dakota Prairie Refining manufactures in order to limit the emissions associated with their final use. In addition, in 2014, the EPA published a proposed rule that proposes amendments to refinery standards already in effect: the National Emission Standards for Hazardous Air Pollutants from Petroleum. The proposed rule would also amend emission requirements under the existing Petroleum Refinery New Source Performance Standard. The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 prescribe certain percentages of renewable fuels (e.g., ethanol and biofuels) that, where required by the Renewable Fuel Standard, must be blended into the refining operations' produced diesel or that requirement may be satisfied by purchasing RINs. For more information on RINs, see Item 8 - Note 6. Dakota Prairie Refining's operations are also subject to the Clean Water Act, the Federal Safe Drinking Water Act and comparable state and local requirements. The Clean Water Act, the Federal Safe Drinking Water Act and analogous laws prohibit any discharge into surface waters, ground waters, injection wells and publicly owned treatment works except in conformance with legal authorization, such as pre-treatment permits and National Pollutant Discharge Elimination System permits, issued by federal, state and local governmental agencies. National Pollutant Discharge Elimination System permits and analogous water discharge permits are valid for a maximum of five years and must be renewed.

Compliance with current and future environmental regulations is not expected to require material capital expenditures through 2018.

Discontinued Operations

General Discontinued operations includes the results of Fidelity other than certain general and administrative costs and interest expense. In the third and fourth quarters of 2015 and the first quarter of 2016, the Company entered into purchase and sale agreements to sell the vast majority of Fidelity's assets, comprising greater than 93 percent of total production for 2014. The completion of the majority of these sales occurred in the fourth quarter of 2015 and the Company continues to market the remaining assets of Fidelity. For more information on discontinued operations, see Item 8 - Note 2 and Supplementary Financial Information.

For information regarding litigation from discontinued operations, see Item 8 - Note 17.

Item 1A. Risk Factors

The Company's business and financial results are subject to a number of risks and uncertainties, including those set forth below and in other documents that it files with the SEC. The factors and the other matters discussed herein are important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in the forward-looking statements included elsewhere in this document.

18 MDU Resources Group, Inc. Form 10-K

Part I

Economic Risks

The Company's pipeline and midstream and refining businesses are dependent on factors, including commodity prices and commodity price basis differentials/crack spreads, that are subject to various external influences that cannot be controlled.

These factors include: fluctuations in oil, NGL and natural gas production and prices; fluctuations in commodity price basis differentials/crack spreads; domestic and foreign supplies of oil, NGL and natural gas; political and economic conditions in oil producing countries; actions of the Organization of Petroleum Exporting Countries; and other risks incidental to the development and operations of oil and natural gas processing plants, pipeline systems and the refinery. Continued prolonged depressed prices for oil, NGL and natural gas could impede the growth of our pipeline and midstream business, and could negatively affect the results of operations, cash flows and asset values of the Company's pipeline and midstream and refining businesses.

The regulatory approval, permitting, construction, startup and/or operation of power generation facilities may involve unanticipated events or delays that could negatively impact the Company's business and its results of operations and cash flows.

The construction, startup and operation of power generation facilities involve many risks, which may include: delays; breakdown or failure of equipment; inability to obtain required governmental permits and approvals; inability to complete financing; inability to negotiate acceptable equipment acquisition, construction, fuel supply, off-take, transmission, transportation or other material agreements; changes in markets and market prices for power; cost increases and overruns; the risk of performance below expected levels of output or efficiency; and the inability to obtain full cost recovery in regulated rates. Such unanticipated events could negatively impact the Company's business, its results of operations and cash flows.

The operation of Dakota Prairie Refinery may involve events that could negatively impact the Company's business, its results of operations, cash flows and asset values.

The operation of Dakota Prairie Refinery involves many risks, which may include: breakdown or failure of the equipment and systems; inability to operate within environmental permit parameters; inability to produce refined products to required specifications; inability to obtain crude oil supply; inability to effectively manage distribution channels; changes in markets and market prices for crude oil and refined products; operating cost increases; and the inability of Dakota Prairie Refinery to fund its operations from its operating cash flows, by obtaining third-party financing or through capital contributions from Calumet or WBI Energy; as well as the risk of performance below expected levels of output or efficiency. Such events, as well as continued operating losses at Dakota Prairie Refinery, could negatively impact the Company's business, its results of operations, cash flows and asset values.

Economic volatility, including volatility in North Dakota's Bakken region, affects the Company's operations, as well as the demand for its products and services and the value of its investments and investment returns including its pension and other postretirement benefit plans, and may have a negative impact on the Company's future revenues and cash flows.

The global demand and price volatility for natural resources, interest rate changes, governmental budget constraints and the ongoing threat of terrorism can create volatility in the financial markets. Unfavorable economic conditions can negatively affect the level of public and private expenditures on projects and the timing of these projects which, in turn, can negatively affect the demand for the Company's products and services, primarily at the Company's construction businesses. The level of demand for construction products and services could be adversely impacted by the economic conditions in the industries the Company serves, as well as in the economy in general. State and federal budget issues may negatively affect the funding available for infrastructure spending. The ability of the Company's electric and natural gas distribution businesses to grow service territory and customer base is affected by the economic environments of the markets served. This economic volatility could have a material adverse effect on the Company's results of operations, cash flows and asset values.

Changing market conditions could negatively affect the market value of assets held in the Company's pension and other postretirement benefit plans and may increase the amount and accelerate the timing of required funding contributions.

The Company relies on financing sources and capital markets. Access to these markets may be adversely affected by factors beyond the Company's control. If the Company is unable to obtain economic financing in the future, the Company's ability to execute its business plans, make capital expenditures or pursue acquisitions that the Company may otherwise rely on for future growth could be impaired. As a result, the market value of the Company's common stock may be adversely affected. If the Company issues a substantial amount of common stock it could have a dilutive effect on its existing shareholders.

The Company relies on access to short-term borrowings, including the issuance of commercial paper, long-term capital markets and asset sales as sources of liquidity for capital requirements not satisfied by its cash flow from operations. If the Company is not able to access capital at competitive rates, the ability to implement its business plans may be adversely affected. Market disruptions or a downgrade of the

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Part I

Company's credit ratings may increase the cost of borrowing or adversely affect its ability to access one or more financial markets. Such disruptions could include:


•	A severe prolonged economic downturn


•	The bankruptcy of unrelated industry leaders in the same line of business


•	Deterioration in capital market conditions


•	Turmoil in the financial services industry


•	Volatility in commodity prices


•	Terrorist attacks


•	Cyber attacks

Economic turmoil, market disruptions and volatility in the securities trading markets, as well as other factors including changes in the Company's results of operations, financial position and prospects, may adversely affect the market price of the Company's common stock.

The Company currently has a shelf registration statement on file with the SEC, under which the Company may issue and sell any combination of common stock and debt securities. The issuance of a substantial amount of the Company's common stock, whether sold pursuant to the registration statement, issued in connection with an acquisition or otherwise, or the perception that such an issuance could occur, may adversely affect the market price of the Company's common stock.

The Company is exposed to credit risk and the risk of loss resulting from the nonpayment and/or nonperformance by the Company's customers and counterparties.

If the Company's customers or counterparties were to experience financial difficulties or file for bankruptcy, the Company could experience difficulty in collecting receivables. The nonpayment and/or nonperformance by the Company's customers and counterparties could have a negative impact on the Company's results of operations and cash flows.

The backlogs at the Company's construction materials and contracting and construction services businesses are subject to delay or cancellation and may not be realized.

Backlog consists of the uncompleted portion of services to be performed under job-specific contracts. Contracts are subject to delay, default or cancellation and the contracts in the Company's backlog are subject to changes in the scope of services to be provided as well as adjustments to the costs relating to the applicable contracts. Backlog may also be affected by project delays or cancellations resulting from weather conditions, external market factors and economic factors beyond the Company's control. Accordingly, there is no assurance that backlog will be realized.

Environmental and Regulatory Risks

The Company's operations are subject to environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the Company to environmental liabilities.

The Company is subject to environmental laws and regulations affecting many aspects of its operations, including air quality, water quality, waste management and other environmental considerations. These laws and regulations can increase capital, operating and other costs, cause delays as a result of litigation and administrative proceedings, and create compliance, remediation, containment, monitoring and reporting obligations, particularly relating to electric generation operations and oil and natural gas processing. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Although the Company strives to comply with all applicable environmental laws and regulations, public and private entities and private individuals may interpret the Company's legal or regulatory requirements differently and seek injunctive relief or other remedies against the Company. The Company cannot predict the outcome (financial or operational) of any such litigation or administrative proceedings.

Existing environmental laws and regulations may be revised and new laws and regulations seeking to protect the environment may be adopted or become applicable to the Company. These laws and regulations could require the Company to limit the use or output of certain facilities, restrict the use of certain fuels, retire and replace certain facilities, install pollution controls, remediate environmental impacts, remove or reduce environmental hazards, or forego or limit the development of resources. Revised or new laws and regulations that increase compliance costs or restrict operations, particularly if costs are not fully recoverable from customers, could have a material adverse effect on the Company's results of operations and cash flows.

On April 17, 2015, the EPA published a final rule, under the RCRA, for coal combustion residuals that regulates coal ash as a solid waste and not a hazardous waste. The rule requires ground water and location restriction evaluations be conducted by October 2017 at ash

20 MDU Resources Group, Inc. Form 10-K

Part I

impoundments and landfills not located at coal mines. In 2015, one ash impoundment at Lewis & Clark Station was replaced with a new concrete basin. Additional site and groundwater analyses may identify the need to upgrade or close additional impoundments or the Company may need to install replacement ash management systems. The cost of replacement ash impoundments or landfills may be material. If these costs are not fully recoverable from customers, they could have a material adverse effect on the Company's results of operations and cash flows.

On August 15, 2014, the EPA published a final rule under Section 316(b) of the Clean Water Act, establishing requirements for water intake structures at existing steam electric generating facilities. The purpose of the rule is to reduce impingement and entrainment of fish and other aquatic organisms at cooling water intake structures. The majority of the Company's electric generating facilities are either not subject to the rule or have completed studies that project compliance expenditures are not material. The Lewis & Clark Station will complete a study that will be submitted to the Montana DEQ by July 31, 2019, to be used in determining any required controls. It is unknown at this time what controls may be required or if compliance costs will be material. The installation schedule for any required controls would be established with the permitting agency after the study is completed.

Initiatives to reduce GHG emissions could adversely impact the Company's operations.

Concern that GHG emissions are contributing to global climate change has led to international, federal and state legislative and regulatory proposals to reduce or mitigate the effects of GHG emissions. On October 23, 2015, the EPA published the final rule establishing carbon dioxide emission limits for new, reconstructed and modified coal-fired steam electric generating units. In this same rule, the EPA established carbon dioxide emission limits for new and reconstructed base load and non-base load stationary combustion turbines. At this time, the EPA has determined not to establish emission limits for modified stationary combustion turbines and has withdrawn the proposed rule emission standards for modified stationary combustion turbines. New coal-fired generating units must comply with an emission standard of 1,400 pounds of carbon dioxide per MW hour gross, equivalent to a super critical pulverized coal unit capturing about 20 percent of its carbon dioxide emissions. Unless carbon capture and storage technology becomes available and cost effective, no new coal-fired electric generating facilities are projected to be constructed. Limits for reconstructed and modified coal-fired generating units may preclude reconstruction or modification depending on the facility. New and reconstructed base load stationary natural gas-fired combustion turbines must comply with an emission standard of 1,000 pounds of carbon dioxide per MW hour gross which should be achievable, but could limit operating at higher load levels, depending on the unit. For newly constructed and reconstructed non-base load (peaking) natural gas-fired stationary combustion turbines, the EPA has established a heat input-based emission standard of 120 pounds of carbon dioxide per MMBtu.

On October 23, 2015, the EPA published the final Clean Power Plan rule which requires existing fossil fuel-fired electric generation facilities to reduce carbon dioxide emissions. By September 6, 2016, states must either submit to the EPA a request for an extension to submit a final state plan by September 6, 2018, or submit a final plan. The state plan must demonstrate how emissions reductions will be achieved and include emission limits in the form of an annual emission cap or an emission rate that will be applied to each individual fossil fuel-fired electric generating facility starting in 2022. Emissions limits become more stringent from 2022 to 2030, with the 2030 emission limits applying thereafter. It is unknown at this time what each state will require for emissions limits or reductions from each of Montana-Dakota's owned and jointly owned fossil fuel-fired electric generating units. Compliance costs will become clearer as final state plans are completed and submitted to the EPA by September 6, 2018. On February 9, 2016, the United States Supreme Court granted an application for a stay of the Clean Power Plan pending disposition of the applicants' petition for review in the D.C. Circuit Court and disposition of the applicants' petition for a writ of certiorari if such a writ is sought.

The Company’s primary GHG emission is carbon dioxide from fossil fuels combustion at Montana-Dakota's electric generating facilities, particularly its coal-fired facilities. Approximately 50 percent of Montana-Dakota's owned generating capacity and approximately 90 percent of the electricity it generated in 2015 was from coal-fired facilities.

On January 14, 2015, President Obama announced a goal to reduce methane emissions from the oil and natural gas industry by 40 to 45 percent below 2012 levels by 2025. On September 18, 2015, the EPA published a proposed rule on standards for methane and GHG emissions from new and modified sources within the oil and natural gas industry, with a final rule expected in 2016. The rule, as proposed, would require emission reductions and work practices for sources such as gathering and boosting stations, and transmission and storage compressor stations. The president will continue to evaluate further methods of methane reduction including additional leak detection controls and emission reporting, enhanced venting and flaring requirements for sources on public lands, and upgrades to existing natural gas transmission and distribution infrastructure. It is unknown at this time how the Company will be impacted or if compliance costs will be material.

On January 6, 2016, the Washington DOE issued the proposed Clean Air Rule, a rule requiring reductions of carbon dioxide emissions from various industries, including carbon dioxide emissions resulting from the combustion of natural gas supplied to end-use customers by natural gas distribution companies, such as Cascade. The rule requires reductions in carbon dioxide emissions resulting from the

MDU Resources Group, Inc. Form 10-K 21

Part I

combustion of natural gas Cascade supplies to the majority of its customers. In 2017, the rule requires Cascade to hold carbon dioxide emissions to a baseline, equal to the average emissions in 2012 to 2016. Beginning in 2018, annual carbon dioxide emissions would be reduced by an additional one and two-thirds percent of the baseline from the previous year's emissions. Washington DOE proposes compliance to be achieved through emissions credit purchases using existing trading markets or by funding end-use energy efficiency projects that would reduce natural gas usage, increasing the operating costs for Cascade. If Cascade could not receive timely and full recovery of compliance costs from its customers, such costs could adversely impact the results of its operations.

There also may be new treaties, legislation or regulations to reduce GHG emissions that could affect Montana-Dakota's electric utility operations by requiring additional energy conservation efforts or renewable energy sources, as well as other mandates that could significantly increase capital expenditures and operating costs. If Montana-Dakota does not receive timely and full recovery of GHG emission compliance costs from its customers, then such costs could adversely impact the results of its operations.

In addition to Montana-Dakota's electric generation operations, the GHG emissions from the Company's other operations are monitored, analyzed and reported as required by applicable laws and regulations. The Company monitors GHG regulations and the potential for GHG regulations to impact operations.

Due to the uncertain availability of technologies to control GHG emissions and the unknown obligations that potential GHG emission legislation or regulations may create, the Company cannot determine the potential financial impact on its operations.

The Company is subject to government regulations that may delay and/or have a negative impact on its business and its results of operations and cash flows. Statutory and regulatory requirements also may limit another party's ability to acquire the Company or impose conditions on an acquisition of or by the Company.

The Company is subject to regulation or governmental actions by federal, state and local regulatory agencies with respect to, among other things, allowed rates of return and recovery of investment and cost, financing, rate structures, health care coverage and cost, taxes, franchises and recovery of purchased power and purchased gas costs. These governmental regulations significantly influence the Company's operating environment and may affect its ability to recover costs from its customers. The Company is unable to predict the impact on operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on the Company's results of operations and cash flows. Approval from a number of federal and state regulatory agencies would need to be obtained by any potential acquirer of the Company as well as for acquisitions by the Company. The approval process could be lengthy and the outcome uncertain.

Other Risks

Weather conditions can adversely affect the Company's operations, and revenues and cash flows.

The Company's results of operations can be affected by changes in the weather. Weather conditions influence the demand for electricity and natural gas, affect the price of energy commodities, affect the ability to perform services at the construction materials and contracting and construction services businesses and affect ongoing operation and maintenance and construction activities for the pipeline and midstream and refining businesses. In addition, severe weather can be destructive, causing outages, and/or property damage, which could require additional costs to be incurred. As a result, adverse weather conditions could negatively affect the Company's results of operations, financial position and cash flows.

Competition exists in all of the Company's businesses.

All of the Company's businesses are subject to competition. Construction services' competition is based primarily on price and reputation for quality, safety and reliability. Construction materials products are marketed under highly competitive conditions and are subject to such competitive forces as price, service, delivery time and proximity to the customer. The electric utility and natural gas industries also are experiencing increased competitive pressures as a result of consumer demands, technological advances and other factors. The pipeline and midstream business competes with several pipelines for access to natural gas supplies and gathering, transportation and storage business. The refining business competes with larger and more diverse refineries that may be better positioned to withstand volatile industry and pricing conditions. Competition could negatively affect the Company's results of operations, financial position and cash flows.

The Company could be subject to limitations on its ability to pay dividends.

The Company depends on earnings from its divisions and dividends from its subsidiaries to pay dividends on its common stock. Regulatory, contractual and legal limitations, as well as capital requirements and the Company's financial performance or cash flows, could limit the earnings of the Company's divisions and subsidiaries which, in turn, could restrict the Company's ability to pay dividends on its common stock and adversely affect the Company's stock price.

22 MDU Resources Group, Inc. Form 10-K

Part I

Cost increases related to obligations under MEPPs could have a material negative effect on the Company's results of operations and cash flows.

Various operating subsidiaries of the Company participate in approximately 85 MEPPs for employees represented by certain unions. The Company is required to make contributions to these plans in amounts established under numerous collective bargaining agreements between the operating subsidiaries and those unions.

The Company may be obligated to increase its contributions to underfunded plans that are classified as being in endangered, seriously endangered or critical status as defined by the Pension Protection Act of 2006. Plans classified as being in one of these statuses are required to adopt RPs or FIPs to improve their funded status through increased contributions, reduced benefits or a combination of the two. Based on available information, the Company believes that approximately 40 percent of the MEPPs to which it contributes are currently in endangered, seriously endangered or critical status.

The Company may also be required to increase its contributions to MEPPs where the other participating employers in such plans withdraw from the plan and are not able to contribute an amount sufficient to fund the unfunded liabilities associated with their participants in the plans. The amount and timing of any increase in the Company's required contributions to MEPPs may also depend upon one or more of the following factors including the outcome of collective bargaining, actions taken by trustees who manage the plans, actions taken by the plans' other participating employers, the industry for which contributions are made, future determinations that additional plans reach endangered, seriously endangered or critical status, government regulations and the actual return on assets held in the plans, among others. The Company may experience increased operating expenses as a result of the required contributions to MEPPs, which may have a material adverse effect on the Company's results of operations, financial position or cash flows.

In addition, pursuant to ERISA, as amended by MPPAA, the Company could incur a partial or complete withdrawal liability upon withdrawing from a plan, exiting a market in which it does business with a union workforce or upon termination of a plan to the extent these plans are underfunded.

On September 24, 2014, Knife River provided notice to the plan administrator of one of the MEPPs to which it is a participating employer that it was withdrawing from that plan effective October 26, 2014. The plan administrator will determine Knife River’s withdrawal liability, which the Company currently estimates at approximately $16.4 million (approximately $9.8 million after tax). The assessed withdrawal liability for this plan may be significantly different from the current estimate.

The Company's operations may be negatively impacted by cyber attacks or acts of terrorism.

The Company operates in industries that require continual operation of sophisticated information technology systems and network infrastructure. While the Company has developed procedures and processes that are designed to strengthen and protect these systems, they may be vulnerable to failures or unauthorized access due to hacking, theft, sabotage, viruses, acts of terrorism, acts of war or other causes. If the technology systems were to fail or be breached and these systems were not recovered in a timely manner, the Company's operational systems and infrastructure, such as the Company's electric generation, transmission and distribution facilities and its oil and natural gas processing facilities, storage and pipeline systems, may be unable to fulfill critical business functions, including an inability to produce or distribute some part of our energy services and other products and the provision of service to customers. Such disruption could result in decreased revenues and/or significant remediation costs which could have a material adverse effect on the Company's results of operations, financial position and cash flows. Additionally, because generation, transmission systems and gas pipelines are part of an interconnected system with other operators, a disruption elsewhere in the system could negatively impact the Company's business.

The Company's business requires access to sensitive customer, employee, shareholder and Company data in the ordinary course of business. Despite the Company's implementation of security measures, a failure or breach of a security system could compromise sensitive and confidential information and data. Such an event could result in negative publicity and reputational harm, remediation costs and possible legal claims and fines which could adversely affect the Company's financial results, notwithstanding the purchase of cyber risk insurance. The Company's third-party service providers that perform critical business functions or have access to sensitive and confidential information and data may also be vulnerable to security breaches and other risks that could have an adverse effect on the Company.

While the Company has completed the sale of the majority of Fidelity's assets and is currently marketing the remaining assets of Fidelity, there is no assurance that a sale of the remaining marketed assets will be successful, and Fidelity may continue to be subject to potential liabilities relating to the sold assets arising from events prior to sale.

As part of the Company’s corporate strategy, it sold the majority of its Fidelity assets, and is currently marketing the remaining assets and will exit that line of business. Such a disposition of the remaining assets is subject to various risks, including: the purchase and sale agreements may be terminated prior to closing as a result of the due diligence process or due to inability of the purchasers to obtain financing; suitable purchasers may not be available or willing to purchase the remaining assets on terms and conditions acceptable to the

MDU Resources Group, Inc. Form 10-K 23

Part I

Company; the agreements pursuant to which the Company divests the assets may contain continuing indemnification obligations; the Company may incur costs in connection with the marketing and sale of the assets; there could be tax consequences dependent on the nature of the sale; and the Company may be required to record additional fair value impairment charges that could have an adverse effect on the Company’s financial condition. Fidelity will also continue to be subject to potential liabilities, either directly or through indemnification of buyers, for potential liabilities relating to the sold assets arising from events prior to sale.

Other factors that could impact the Company's businesses.

The following are other factors that should be considered for a better understanding of the financial condition of the Company. These other factors may impact the Company's financial results in future periods.


•	Acquisition, disposal and impairments of assets or facilities


•	Changes in operation, performance and construction of plant facilities or other assets


•	Changes in present or prospective generation


•	The ability to obtain adequate and timely cost recovery for the Company's regulated operations through regulatory proceedings


•	The availability of economic expansion or development opportunities


•	Population growth rates and demographic patterns


•	Market demand for, available supplies of, and/or costs of, energy- and construction-related products and services


•	The cyclical nature of large construction projects at certain operations


•	Changes in tax rates or policies


•	Unanticipated project delays or changes in project costs, including related energy costs


•	Unanticipated changes in operating expenses or capital expenditures


•	Labor negotiations or disputes


•	Inability of contract counterparties to meet their contractual obligations


•	Changes in accounting principles and/or the application of such principles to the Company


•	Changes in technology


•	Changes in legal or regulatory proceedings


•	The ability to effectively integrate the operations and the internal controls of acquired companies


•	The ability to attract and retain skilled labor and key personnel


•	Increases in employee and retiree benefit costs and funding requirements

Item 1B. Unresolved Staff Comments

The Company has no unresolved comments with the SEC.

Item 3. Legal Proceedings

For information regarding legal proceedings, see Item 8 - Note 17, which is incorporated herein by reference.

Item 4. Mine Safety Disclosures

For information regarding mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K, see Exhibit 95 to this Form 10-K, which is incorporated herein by reference.

24 MDU Resources Group, Inc. Form 10-K

Part II

Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The Company's common stock is listed on the New York Stock Exchange under the symbol "MDU." The price range of the Company's common stock as reported by The Wall Street Journal composite tape during 2015 and 2014 and dividends declared thereon were as follows:



	Common Stock Price (High)		Common Stock Price (Low)		Common Stock Dividends Declared Per Share
2015
First quarter		$24.51		$20.01		$.1825
Second quarter	23.12		19.22		.1825
Third quarter	19.73		16.15		.1825
Fourth quarter	19.66		16.26		.1875
						$.7350
2014
First quarter		$35.10		$29.62		$.1775
Second quarter	36.05		32.45		.1775
Third quarter	35.41		27.35		.1775
Fourth quarter	28.51		21.33		.1825
						$.7150

As of December 31, 2015, the Company's common stock was held by approximately 12,900 stockholders of record.

The Company depends on earnings from its divisions and dividends from its subsidiaries to pay dividends on common stock. The declaration and payment of dividends is at the sole discretion of the board of directors, subject to limitations imposed by the Company's credit agreements, federal and state laws, and applicable regulatory limitations. For more information on factors that may limit the Company's ability to pay dividends, see Item 8 - Note 10.

The following table includes information with respect to the Company's purchase of equity securities:

ISSUER PURCHASES OF EQUITY SECURITIES



Period	(a) Total Number of Shares (or Units) Purchased (1)	(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (2)	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (2)
October 1 through October 31, 2015	—
November 1 through November 30, 2015	54,351		$18.21
December 1 through December 31, 2015	3,830	16.97
Total	58,181


(1)	Represents shares of common stock purchased on the open market in connection with annual stock grants made to the Company's non-employee directors and for those directors who elected to receive additional shares of common stock in lieu of a portion of their cash retainer.


(2)	Not applicable. The Company does not currently have in place any publicly announced plans or programs to purchase equity securities.

MDU Resources Group, Inc. Form 10-K 25

Part II

Item 6. Selected Financial Data



	2015			2014			2013			2012			2011			2010
Selected Financial Data
Operating revenues (000's):
Electric	$	280,615		$	277,874		$	257,260		$	236,895		$	225,468		$	211,544
Natural gas distribution	817,419			921,986			851,945			754,848			907,400			892,708
Pipeline and midstream	156,236			157,365			144,571			142,610			152,972			175,961
Construction materials and contracting	1,904,282			1,765,330			1,712,137			1,617,425			1,510,010			1,445,148
Construction services	926,427			1,119,529			1,039,839			938,558			854,389			789,100
Refining	178,262			—			—			—			—			—
Other	9,191			9,364			9,620			10,370			11,446			7,727
Intersegment eliminations	(80,883		)	(136,632		)	(95,201		)	(74,595		)	(68,482		)	(49,125		)
	$	4,191,549		$	4,114,816		$	3,920,171		$	3,626,111		$	3,593,203		$	3,473,063
Operating income (loss) (000's):
Electric	$	57,955		$	61,331		$	54,274		$	49,852		$	49,096		$	48,296
Natural gas distribution	53,810			65,633			78,829			67,579			82,856			75,697
Pipeline and midstream	29,988			46,713			20,896			49,139			45,365			46,310
Construction materials and contracting	146,026			86,462			93,629			57,864			51,092			63,045
Construction services	43,376			82,309			85,246			66,531			39,144			33,352
Refining	(68,860		)	(9,097		)	(850		)	—			—			—
Other	(5,700		)	(4,028		)	(4,146		)	(5,325		)	(7,079		)	(10,854		)
Intersegment eliminations	(2,462		)	(9,900		)	(7,176		)	—			—			—
	$	254,133		$	319,423		$	320,702		$	285,640		$	260,474		$	255,846
Earnings (loss) on common stock (000's):
Electric	$	35,914		$	36,731		$	34,837		$	30,634		$	29,258		$	28,908
Natural gas distribution	23,607			30,484			37,656			29,409			38,398			36,944
Pipeline and midstream	13,250			24,666			7,701			26,588			23,082			23,208
Construction materials and contracting	89,096			51,510			50,946			32,420			26,430			29,609
Construction services	23,762			54,432			52,213			38,429			21,627			17,982
Refining	(22,457		)	(2,038		)	(72		)	—			—			—
Other	(12,376		)	(7,317		)	(10,605		)	(7,209		)	(5,918		)	8,508
Intersegment eliminations	(1,531		)	(6,095		)	(4,307		)	—			—			—
Earnings on common stock before income (loss) from discontinued operations	149,265			182,373			168,369			150,271			132,877			145,159
Income (loss) from discontinued operations, net of tax*	(772,385		)	115,175			109,879			(151,710		)	79,464			94,815
	$	(623,120	)	$	297,548		$	278,248		$	(1,439	)	$	212,341		$	239,974
Earnings (loss) per common share before discontinued operations - diluted	$	.77		$	.95		$	.89		$	.80		$	.70		$	.77
Discontinued operations, net of tax	(3.97		)	.60			.58			(.81		)	.42			.50
	$	(3.20	)	$	1.55		$	1.47		$	(.01	)	$	1.12		$	1.27
Common Stock Statistics
Weighted average common shares outstanding -diluted (000's)	194,986			192,587			189,693			188,826			188,905			188,229
Dividends declared per common share	$	.7350		$	.7150		$	.6950		$	.6750		$	.6550		$	.6350
Book value per common share	$	12.83		$	16.66		$	15.01		$	13.95		$	14.62		$	14.22
Market price per common share (year end)	$	18.32		$	23.50		$	30.55		$	21.24		$	21.46		$	20.27
Market price ratios:
Dividend payout**	95		%	75		%	78		%	84		%	94		%	82		%
Yield	4.1		%	3.1		%	2.3		%	3.2		%	3.1		%	3.2		%
Market value as a percent of book value	142.8		%	141.1		%	203.5		%	152.3		%	146.8		%	142.5		%


*	Reflects oil and natural gas properties noncash write-downs of $315.3 million (after tax) and $246.8 million (after tax) in 2015 and 2012, respectively, and fair value impairments of assets held for sale of $475.4 million (after tax) in 2015.


**	Based on continuing operations.

26 MDU Resources Group, Inc. Form 10-K

Part II

Item 6. Selected Financial Data (continued)



	2015			2014			2013			2012			2011			2010
General
Total assets (000's)	$	6,627,608		$	7,832,408		$	7,073,447		$	6,708,666		$	6,583,597		$	6,310,976
Total long-term debt (000's)	$	1,871,232		$	2,093,830		$	1,853,112		$	1,743,000		$	1,422,207		$	1,503,813
Capitalization ratios:
Common equity	57		%	61		%	60		%	60		%	66		%	64		%
Total debt	43			39			40			40			34			36
	100		%	100		%	100		%	100		%	100		%	100		%
Electric
Retail sales (thousand kWh)	3,316,017			3,308,358			3,173,086			2,996,528			2,878,852			2,785,710
Electric system summer and firm purchase contract ZRCs (Interconnected system)	547.3			584.0			583.5			552.8			572.8			553.3
Electric system peak demand obligation, including firm purchase contracts, planning reserve margin requirement (Interconnected system)	547.3			522.4			508.3			550.7			524.2			529.5
Demand peak - kW (Interconnected system)	611,542			582,083			573,587			573,587			535,761			525,643
Electricity produced (thousand kWh)	1,898,160			2,519,938			2,430,001			2,299,686			2,488,337			2,472,288
Electricity purchased (thousand kWh)	1,658,002			1,010,422			971,261			870,516			645,567			521,156
Average cost of fuel and purchased power per kWh	$	.024		$	.025		$	.025		$	.023		$	.021		$	.021
Natural Gas Distribution
Sales (Mdk)	95,559			104,297			108,260			93,810			103,237			95,480
Transportation (Mdk)	154,225			145,941			149,490			132,010			124,227			135,823
Degree days (% of normal)
Montana-Dakota/Great Plains	88		%	103		%	105		%	84		%	101		%	98		%
Cascade	83		%	89		%	98		%	96		%	103		%	96		%
Intermountain	89		%	95		%	110		%	91		%	107		%	100		%
Pipeline and Midstream
Transportation (Mdk)	290,494			233,483			178,598			137,720			113,217			140,528
Gathering (Mdk)	33,441			38,372			40,737			47,084			66,500			77,154
Customer natural gas storage balance (Mdk)	16,600			14,885			26,693			43,731			36,021			58,784
Construction Materials and Contracting
Sales (000's):
Aggregates (tons)	26,959			25,827			24,713			23,285			24,736			23,349
Asphalt (tons)	6,705			6,070			6,228			5,988			6,709			6,279
Ready-mixed concrete (cubic yards)	3,592			3,460			3,223			3,157			2,864			2,764
Aggregate reserves (000's tons)	1,022,513			1,061,156			1,083,376			1,088,236			1,088,833			1,107,396
Refining
Refined product sales (MBbls)
Diesel fuel	1,072			*			*			*			*			*
Naphtha	996			*			*			*			*			*
ATBs and other	884			*			*			*			*			*
Total refined product sales	2,952			*			*			*			*			*


*	Dakota Prairie Refinery began commercial operation in 2015.

MDU Resources Group, Inc. Form 10-K 27

Part II

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

Overview

The Company's strategy is to apply its expertise in energy and transportation infrastructure industries to increase market share, increase profitability and enhance shareholder value through:


•	Organic growth as well as a continued disciplined approach to the acquisition of well-managed companies and properties


•	The elimination of system-wide cost redundancies through increased focus on integration of operations and standardization and consolidation of various support services and functions across companies within the organization


•	The development of projects that are accretive to earnings per share and return on invested capital


•	Divestiture of certain assets to fund capital growth projects throughout the Company

The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial paper facilities, revolving credit facilities, the issuance from time to time of debt and equity securities and asset sales. For more information on the Company's net capital expenditures, see Liquidity and Capital Commitments.

The key strategies for each of the Company's business segments and certain related business challenges are summarized below. For a summary of the Company's businesses, see Item 8 - Note 13.

Key Strategies and Challenges

Electric and Natural Gas Distribution

Strategy Provide safe and reliable competitively priced energy and related services to customers. The electric and natural gas distribution segments continually seek opportunities to retain, grow and expand their customer base through extensions of existing operations, including building and upgrading electric generation and transmission and natural gas systems, and through selected acquisitions of companies and properties at prices that will provide stable cash flows and an opportunity for the Company to earn a competitive return on investment.

Challenges Both segments are subject to extensive regulation in the state jurisdictions where they conduct operations with respect to costs and timely recovery and permitted returns on investment as well as subject to certain operational, system integrity and environmental regulations. These regulations can require substantial investment to upgrade facilities. The ability of these segments to grow through acquisitions is subject to significant competition. In addition, the ability of both segments to grow service territory and customer base is affected by the economic environment of the markets served and competition from other energy providers and fuels. The construction of any new electric generating facilities, transmission lines and other service facilities is subject to increasing cost and lead time, extensive permitting procedures, and federal and state legislative and regulatory initiatives, which will necessitate increases in electric energy prices. Legislative and regulatory initiatives to increase renewable energy resources and reduce GHG emissions could impact the price and demand for electricity and natural gas.

Pipeline and Midstream

Strategy Utilize the segment's existing expertise in energy infrastructure and related services to increase market share and profitability through optimization of existing operations, internal growth, and investments in and acquisitions of energy-related assets and companies both in its current operating areas and beyond its northern Rockies base. Incremental and new growth opportunities include: access to new energy sources for storage, gathering and transportation services; expansion of existing gathering and transmission facilities; incremental expansion of pipeline capacity; expansion of the pipeline and midstream business to include liquid pipelines and processing activities; and expansion of related energy services.

Challenges Challenges for this segment include: energy price volatility; tight basis differentials; environmental and regulatory requirements; recruitment and retention of a skilled workforce; and competition from other pipeline and midstream companies.

Construction Materials and Contracting

Strategy Focus on high-growth strategic markets located near major transportation corridors and desirable mid-sized metropolitan areas; strengthen long-term, strategic aggregate reserve position through purchase and/or lease opportunities; enhance profitability through cost containment, margin discipline and vertical integration of the segment's operations; develop and recruit talented employees; and continue growth through organic and acquisition opportunities. Vertical integration allows the segment to manage operations from aggregate mining to final lay-down of concrete and asphalt, with control of and access to permitted aggregate reserves being significant. A key element of the Company's long-term strategy for this business is to further expand its market presence in the higher-margin materials business (rock, sand, gravel, liquid asphalt, asphalt concrete, ready-mixed concrete and related products), complementing and expanding on the Company's expertise.

28 MDU Resources Group, Inc. Form 10-K

Part II

Challenges Recruitment and retention of key personnel and volatility in the cost of raw materials such as diesel, gasoline, liquid asphalt, cement and steel, are ongoing challenges. This business unit expects to continue cost containment efforts, positioning its operations for the resurgence in the private market, while continuing the emphasis on industrial, energy and public works projects.

Construction Services

Strategy Provide a superior return on investment by: building new and strengthening existing customer relationships; effectively controlling costs; retaining, developing and recruiting talented employees; continue growth through organic and acquisition opportunities; and focusing efforts on projects that will permit higher margins while properly managing risk.

Challenges This segment operates in highly competitive markets with many jobs subject to competitive bidding. Maintenance of effective operational and cost controls, retention of key personnel, managing through downturns in the economy and effective management of working capital are ongoing challenges.

Refining

Strategy Utilize Dakota Prairie Refinery’s prime location in North Dakota’s Bakken region to access crude oil supplies to safely and efficiently produce into refined products. Pursue operational effectiveness to maximize returns and cash flows through efforts such as marketing, cost reductions and refinery performance improvements. Additional opportunities exist in debottlenecking the plant which could increase production volumes.

Challenges Challenges for this market include the narrowing of the differential between the Company’s actual crude oil price and West Texas Intermediate crude oil prices; availability, cost and price volatility of crude oil and refined products; narrowing crack spreads for refined products including diesel, naphtha and ATBs; changes in overall demand for refined products; environmental and regulatory requirements; the potential for increasing price volatility for RINs and competition from other refineries.

For more information on the risks and challenges the Company faces as it pursues its growth strategies and other factors that should be considered for a better understanding of the Company's financial condition, see Item 1A - Risk Factors. For more information on key growth strategies, projections and certain assumptions, see Prospective Information. For information pertinent to various commitments and contingencies, see Item 8 - Notes to Consolidated Financial Statements.

Earnings Overview

The following table summarizes the contribution to consolidated earnings (loss) by each of the Company's businesses.



Years ended December 31,	2015			2014			2013
	(Dollars in millions, where applicable)
Electric	$	35.9		$	36.7		$	34.8
Natural gas distribution	23.6			30.5			37.7
Pipeline and midstream	13.3			24.7			7.7
Construction materials and contracting	89.1			51.5			50.9
Construction services	23.8			54.5			52.2
Refining	(22.5		)	(2.1		)	(.1		)
Other	(12.4		)	(7.2		)	(10.6		)
Intersegment eliminations	(1.5		)	(6.2		)	(4.3		)
Earnings before discontinued operations	149.3			182.4			168.3
Income (loss) from discontinued operations, net of tax	(772.4		)	115.1			109.9
Earnings (loss) on common stock	$	(623.1	)	$	297.5		$	278.2
Earnings (loss) per common share - basic:
Earnings before discontinued operations	$	.77		$	.95		$	.89
Discontinued operations, net of tax	(3.97		)	.60			.58
Earnings (loss) per common share - basic	$	(3.20	)	$	1.55		$	1.47
Earnings (loss) per common share - diluted:
Earnings before discontinued operations	$	.77		$	.95		$	.89
Discontinued operations, net of tax	(3.97		)	.60			.58
Earnings (loss) per common share - diluted	$	(3.20	)	$	1.55		$	1.47

MDU Resources Group, Inc. Form 10-K 29

Part II

2015 compared to 2014 The Company recognized a consolidated loss of $623.1 million in 2015, compared to consolidated earnings of $297.5 million in 2014. This decrease was due to:

•

Discontinued operations which had a fair value impairment of the Company's assets held for sale of $475.4 million (after tax); a $315.3 million after-tax noncash write-down of oil and natural gas properties; lower average realized commodity prices, excluding gain/loss on commodity derivatives; and decreased oil production; partially offset by lower depreciation, depletion and amortization expense and lease operating expense


•	Lower workloads and margins in the Western region and lower equipment rental sales and margins at the construction services business


•	Higher operation and maintenance, largely due to higher rail-related and contract services costs with commencement of operations of Dakota Prairie Refinery occurring in May 2015


•	Impairments of natural gas gathering assets of $10.6 million (after tax) at the pipeline and midstream business


•	Higher depreciation, depletion and amortization expense due to plant additions and lower natural gas sales volumes offset in part by natural gas retail rate increases at the natural gas distribution business

Partially offsetting these decreases were higher earnings on all product lines at the construction materials and contracting business.

2014 compared to 2013 Consolidated earnings for 2014 increased $19.3 million from the prior year. This increase was due to:

•

The absence of the 2013 impairment of coalbed natural gas gathering assets of $9.0 million (after tax), as discussed in Item 8 - Note 1, as well as higher earnings due to increased transportation rates and higher earnings from the Company's interest in the Pronghorn oil and natural gas gathering and processing assets; partially offset by lower storage services earnings at the pipeline and midstream business


•	Other earnings increased resulting from favorable income tax changes, due to the resolution of certain tax matters and higher income tax benefits

Partially offsetting these increases were higher operation and maintenance expense, higher depreciation, depletion and amortization expense and the absence of the 2013 $2.8 million (after tax) gain on the sale of Montana-Dakota's nonregulated appliance service and repair business; partially offset by higher other income and natural gas retail sales margins at the natural gas distribution business.

Financial and Operating Data

Following are key financial and operating data for each of the Company's businesses.

Electric



Years ended December 31,	2015		2014		2013
	(Dollars in millions, where applicable)
Operating revenues	$	280.6	$	277.9	$	257.3
Operating expenses:
Fuel and purchased power	86.2		89.3		83.5
Operation and maintenance	87.7		81.1		76.5
Depreciation, depletion and amortization	37.6		35.0		32.8
Taxes, other than income	11.1		11.1		10.2
	222.6		216.5		203.0
Operating income	58.0		61.4		54.3
Earnings	$	35.9	$	36.7	$	34.8
Retail sales (million kWh)	3,316.0		3,308.4		3,173.1
Average cost of fuel and purchased power per kWh	$	.024	$	.025	$	.025

2015 compared to 2014 Electric earnings decreased $800,000 (2 percent) compared to the prior year due to:


•	Higher operation and maintenance expense, which includes $4.3 million (after tax) largely related to higher contract services, primarily related to a planned outage at an electric generation station, and higher payroll and benefit-related costs


•	Higher depreciation, depletion and amortization expense of $1.6 million (after tax) due to increased property, plant and equipment balances


•	Higher net interest expense, which includes $1.1 million (after tax) due to higher long-term debt

Partially offsetting these decreases were:


•	Increased electric retail sales margins, primarily due to rate recovery of new generation

30 MDU Resources Group, Inc. Form 10-K

Part II


•	Higher other income, which includes $3.5 million (after tax) primarily related to allowance for funds used during construction

2014 compared to 2013 Electric earnings increased $1.9 million (5 percent) compared to the prior year due to increased electric retail sales margins, primarily due to rate recovery on electric environmental upgrades and increased electric sales volumes of 4 percent to all customer classes, due to customer growth.

Partially offsetting the increase were:


•	Higher operation and maintenance expense, which includes $3.5 million (after tax) largely related to higher benefit-related costs and increased contract services


•	Higher net interest expense, which includes $1.8 million (after tax) due to higher long-term debt


•	Higher depreciation, depletion and amortization expense of $1.4 million (after tax) due to increased property, plant and equipment balances

Natural Gas Distribution



Years ended December 31,	2015			2014			2013
	(Dollars in millions, where applicable)
Operating revenues	$	817.4		$	922.0		$	851.9
Operating expenses:
Purchased natural gas sold	499.0			603.2			534.8
Operation and maintenance	153.5			150.2			142.3
Depreciation, depletion and amortization	64.8			54.7			50.0
Taxes, other than income	46.3			48.3			46.0
	763.6			856.4			773.1
Operating income	53.8			65.6			78.8
Earnings	$	23.6		$	30.5		$	37.7
Volumes (MMdk):
Sales	95.6			104.3			108.3
Transportation	154.2			145.9			149.5
Total throughput	249.8			250.2			257.8
Degree days (% of normal)*
Montana-Dakota/Great Plains	88		%	103		%	105		%
Cascade	83		%	89		%	98		%
Intermountain	89		%	95		%	110		%
Average cost of natural gas, including transportation, per dk	$	5.22		$	5.78		$	4.94


*	Degree days are a measure of the daily temperature-related demand for energy for heating.

2015 compared to 2014 The natural gas distribution business experienced a decrease in earnings of $6.9 million (23 percent) compared to the prior year due to:


•	Higher depreciation, depletion and amortization expense of $6.3 million (after tax), largely resulting from increased property, plant and equipment balances


•	Lower natural gas sales margins, primarily lower retail sales volumes of 8 percent to all customer classes due to warmer weather than the prior year, partially offset by approved rate increases effective in 2015 and increased transportation volumes

The pass-through of lower natural gas prices is reflected in the decrease in both sales revenue and purchased natural gas sold in 2015.

2014 compared to 2013 The natural gas distribution business experienced a decrease in earnings of $7.2 million (19 percent) compared to the prior year due to:


•	Higher operation and maintenance expense, which includes $4.8 million (after tax) largely related to higher payroll and benefits-related costs


•	Higher depreciation, depletion and amortization expense of $2.9 million (after tax), primarily resulting from increased property, plant and equipment balances


•	The absence of the 2013 $2.8 million (after tax) gain on the sale of Montana-Dakota's nonregulated appliance service and repair business

MDU Resources Group, Inc. Form 10-K 31

Part II

These decreases were partially offset by:


•	Higher other income, which includes $2.1 million (after tax) largely related to allowance for funds used during construction


•	Higher natural gas retail sales margins, primarily resulting from approved rate increases effective in late 2013, largely offset by lower sales volumes of 4 percent ($4.3 million after tax) in certain jurisdictions due to warmer weather than the prior year

Pipeline and Midstream



Years ended December 31,	2015		2014			2013
	(Dollars in millions)
Operating revenues	$	156.2	$	157.4		$	144.6
Operating expenses:
Purchased natural gas sold	1.2		—			—
Operation and maintenance*	84.8		68.1			81.0
Depreciation, depletion and amortization	28.0		29.8			29.1
Taxes, other than income	12.2		12.8			13.6
	126.2		110.7			123.7
Operating income	30.0		46.7			20.9
Earnings*	$	13.3	$	24.7		$	7.7
Transportation volumes (MMdk)	290.5		233.5			178.6
Natural gas gathering volumes (MMdk)	33.4		38.4			40.7
Customer natural gas storage balance (MMdk):
Beginning of period	14.9		26.7			43.7
Net injection (withdrawal)	1.7		(11.8		)	(17.0		)
End of period	16.6		14.9			26.7

Reflects impairments of natural gas gathering assets of $17.1 million ($10.6 million after tax) in 2015 and coalbed natural gas gathering assets of $14.5 million ($9.0 million after tax) in 2013, as discussed in Item 8 - Note 1; as well as a net benefit of $2.5 million ($1.5 million after tax) in 2013 related to the natural gas gathering operations litigation, largely reflected in operation and maintenance expense, as discussed in Item 8 - Note 17.

2015 compared to 2014 Pipeline and midstream earnings decreased $11.4 million (46 percent) largely due to:


•	Impairment of natural gas gathering assets of $10.6 million (after tax) included in operation and maintenance expense, as discussed in Item 8 - Note 1


•	Lower gathering and processing earnings of $5.2 million (after tax), primarily lower processing prices and natural gas gathering volumes


•	Lower storage services earnings, primarily due to lower interruptible storage withdrawal volumes and lower average balances

Partially offsetting the earnings decrease was higher earnings of $5.7 million (after tax) due to higher transportation revenue, primarily resulting from higher rates due to a rate case settlement effective in May 2014, and increased volumes.

2014 compared to 2013 Pipeline and midstream earnings increased $17.0 million (220 percent) largely due to:


•	Absence of the 2013 impairment of coalbed natural gas gathering assets of $9.0 million (after tax), as discussed in Item 8 - Note 1


•	Higher earnings of $5.6 million (after tax) due to increased transportation rates, primarily due to a rate case settlement, and higher volumes


•	Higher earnings from the Company's interest in the Pronghorn oil and natural gas gathering and processing assets, primarily due to higher volumes


•	Favorable income tax changes, including $1.0 million of higher income tax benefits


•	Lower operation and maintenance expense (excluding the asset impairment, net benefit related to natural gas gathering operations litigation and Pronghorn-related expense), which includes $800,000 (after tax) largely related to legal and abandonment costs offset in part by higher payroll and benefit-related costs

Partially offsetting the earnings increase were:


•	Lower storage services earnings of $3.5 million (after tax), largely due to lower average storage balances and lower rates


•	Absence of the net benefit in 2013 of $1.5 million (after tax) related to the natural gas gathering operations litigation, as discussed in Item 8 - Note 17

32 MDU Resources Group, Inc. Form 10-K

Part II

Construction Materials and Contracting



Years ended December 31,	2015		2014		2013
	(Dollars in millions)
Operating revenues	$	1,904.3	$	1,765.3	$	1,712.1
Operating expenses:
Operation and maintenance*	1,652.3		1,571.5		1,505.2
Depreciation, depletion and amortization	65.9		68.6		74.5
Taxes, other than income	40.1		38.8		38.8
	1,758.3		1,678.9		1,618.5
Operating income	146.0		86.4		93.6
Earnings*	$	89.1	$	51.5	$	50.9
Sales (000's):
Aggregates (tons)	26,959		25,827		24,713
Asphalt (tons)	6,705		6,070