Attached files

file filename
EX-32.2 - EXHIBIT 32.2 CERTIFICATION OF BRIAN B. BIRD PURSUANT TO SECTION 906 - NORTHWESTERN CORPexhibit322certification10k.htm
EX-32.1 - EXHIBIT 32.1 CERTIFICATION OF ROBERT C. ROWE PURSUANT TO SECTION 906 - NORTHWESTERN CORPexhibit321certification10k.htm
EX-31.2 - EXHIBIT 31.2 CERTIFICATION OF CHIEF FINANCIAL OFFICER - NORTHWESTERN CORPexhibit312certification10k.htm
EX-31.1 - EXHIBIT 31.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - NORTHWESTERN CORPexhibit311certification10k.htm
EX-23.1 - EXHIBIT 23.1 AUDITOR CONSENT - NORTHWESTERN CORPexhibit231consent10k2017.htm
EX-21 - EXHIBIT 21 SUBSIDIARIES 10-K 2017 - NORTHWESTERN CORPexhibit21subsidiaries10k20.htm
EX-12.. - EXHIBIT 12.1 EARNINGS TO FIXED CHARGES 2017 - NORTHWESTERN CORPexhibit121earningstofixedc.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
x
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017

OR
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: 1-10499
logoa10.jpg
NORTHWESTERN CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
 
46-0172280
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
3010 W. 69th Street, Sioux Falls, South Dakota
 
57108
(Address of principal executive offices)
 
(Zip Code)

Registrant’s telephone number, including area code: 605-978-2900

Securities registered pursuant to Section 12(b) of the Act:
(Title of each class)
 
(Name of each exchange on which registered)
Common Stock, $0.01 par value
 
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x 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 Act. Yes o No x
 
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 x No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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 shorter period that the registrant was required to submit and post such files). Yes x 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 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. o

 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer x
 Accelerated Filer o
Non-accelerated Filer o
Smaller Reporting Company o
Emerging Growth Company o
 
 
(Do not check if smaller reporting company)

 
 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. Yes o  No o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o  No x
 
The aggregate market value of the voting and non-voting common stock held by nonaffiliates of the registrant was $2,957,686,000 computed using the last sales price of $61.02 per share of the registrant’s common stock on June 30, 2017, the last business day of the registrant’s most recently completed second fiscal quarter.
 
As of February 9, 2018, 49,397,196 shares of the registrant’s common stock, par value $0.01 per share, were outstanding.

Documents Incorporated by Reference
Certain sections of our Proxy Statement for the 2018 Annual Meeting of Shareholders
are incorporated by reference into Part III of this Form 10-K






INDEX
 
PAGE
 
Part I
 
 
 
 
 
Part II
 
 
 
 
 
Part III
 
 
 
 
 
Part IV
 
Form 10-K Summary



2



SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

On one or more occasions, we may make statements in this Annual Report on Form 10-K regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference in this Annual Report, relating to management's current expectations of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

Words or phrases such as “anticipates," “may," “will," “should," “believes," “estimates," “expects," “intends," “plans," “predicts," “projects," “targets," “will likely result," “will continue" or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that we will achieve our projections. Factors that may cause such differences include, but are not limited to:

adverse determinations by regulators, as well as potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, could have a material effect on our liquidity, results of operations and financial condition;
changes in availability of trade credit, creditworthiness of counterparties, usage, commodity prices, fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, may reduce revenues or may increase operating costs, each of which could adversely affect our liquidity and results of operations;
unscheduled generation outages or forced reductions in output, maintenance or repairs, which may reduce revenues and increase cost of sales or may require additional capital expenditures or other increased operating costs; and
adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories.

We have attempted to identify, in context, certain of the factors that we believe may cause actual future experience and results to differ materially from our current expectation regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the uncertainties described under the caption “Risk Factors” which is part of the disclosure included in Part I, Item 1A of this Annual Report on Form 10-K.

From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. We believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable. However, any or all of the forward-looking statements in this Annual Report on Form 10-K, our reports on Forms 10-Q and 8-K, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions, which turn out to be inaccurate, or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Annual Report on Form 10-K, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of any of our forward-looking statements in this Annual Report on Form 10-K or other public communications as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. However, your attention is directed to any further disclosures made on related subjects in our subsequent reports filed with the Securities and Exchange Commission (SEC) on Forms 10-K, 10-Q and 8-K and Proxy Statements on Schedule 14A.

Unless the context requires otherwise, references to “we,” “us,” “our,” “NorthWestern Corporation,” “NorthWestern Energy,” and “NorthWestern” refer specifically to NorthWestern Corporation and its subsidiaries.


3



GLOSSARY

Accounting Standards Codification (ASC) - The single source of authoritative nongovernmental GAAP, which supersedes all existing accounting standards.

Allowance for Funds Used During Construction (AFUDC) - A regulatory accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in the property accounts and included in income.

Base-Load - The minimum amount of electric power or natural gas delivered or required over a given period of time at a steady rate. The minimum continuous load or demand in a power system over a given period of time usually is not temperature sensitive.

Base-Load Capacity - The generating equipment normally operated to serve loads on an around-the-clock basis.

Capacity - The amount represents the maximum output of electricity a generator can produce and is related to peak demand. We must maintain a level of available capacity sufficient to meet peak demand with a sufficient reserve.

COD - commercial operating date.

Commercial Customers - consists primarily of main street businesses, shopping malls, grocery stores, gas stations, bars and restaurants, professional offices, hospitals and medical offices, motels, and hotels.

Cushion Gas - The natural gas required in a gas storage reservoir to maintain a pressure sufficient to permit recovery of stored gas.

DGGS - The Dave Gates Generating Station at Mill Creek, a 150 MW natural gas fired facility, which provides up to 105 MW of regulation service.

Environmental Protection Agency (EPA) - A Federal agency charged with protecting the environment.

Federal Energy Regulatory Commission (FERC) - The Federal agency that has jurisdiction over interstate electricity sales, wholesale electric rates, hydroelectric licensing, natural gas transmission and related services pricing, oil pipeline rates and gas pipeline certification.

Franchise - A special privilege conferred by a unit of state or local government on an individual or corporation to occupy and use the public ways and streets for benefit to the public at large. Local distribution companies typically have franchises for utility service granted by state or local governments.

GAAP - Accounting principles generally accepted in the United States of America.

Hedging - Entering into transactions to manage various types of risk (e.g. commodity risk).

Industrial Customers - consists primarily of manufacturing and processing businesses that turn raw materials into products.

Lignite Coal - The lowest rank of coal, often referred to as brown coal, used almost exclusively as fuel for steam-electric power generation. It has high inherent moisture content, sometimes as high as 45 percent. The heat content of lignite ranges from 9 to 17 million Btu per ton on a moist, mineral-matter-free basis.

Midcontinent Independent System Operator (MISO) - MISO is a nonprofit organization created in compliance with FERC as a regional transmission organization, to improve the flow of electricity in the regional marketplace and to enhance electric reliability. Additionally, MISO is responsible for managing the energy markets, managing transmission constraints, managing the day-ahead, real-time and financial transmission rights markets and managing the ancillary market.

Midwest Reliability Organization (MRO) - MRO is one of eight regional electric reliability councils under NERC.

Montana Public Service Commission (MPSC) - The state agency that regulates public utilities doing business in Montana.

Nameplate Capacity - the intended full-load sustained output of a generating facility. Nameplate capacity is the number registered with authorities for classifying the power output of a power station usually expressed in megawatts (MW).


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Nebraska Public Service Commission (NPSC) - The state agency that regulates public utilities doing business in Nebraska.

North American Electric Reliability Corporation (NERC) - NERC oversees eight regional reliability entities and encompasses all of the interconnected power systems of the contiguous United States. NERC's major responsibilities include developing standards for power system operation, monitoring and enforcing compliance with those standards, assessing resource adequacy, and providing educational and training resources as part of an accreditation program to ensure power system operators remain qualified and proficient.

Open Access - Non-discriminatory, fully equal access to transportation or transmission services offered by a pipeline or electric utility.

Open Access Transmission Tariff (OATT) -The OATT, which is established by the FERC, defines the terms and conditions of point-to-point and network integration transmission services offered by us, and requires that transmission owners provide open, non-discriminatory access on their transmission system to transmission customers.

Peak Load - A measure of the maximum amount of energy delivered at a point in time.

Qualifying Facility (QF) - As defined under the Public Utility Regulatory Policies Act of 1978 (PURPA), a QF sells power to a regulated utility at a price agreed to by the parties or determined by a public service commission that is intended to be equal to that which the utility would otherwise pay if it were to generate its own power or buy power from another source.

Regulation Services - FERC jurisdictional services that ensure reliability and support the transmission of electricity from generation sites to customer loads. Such services are also referred to as ancillary services and include regulating reserves, load balancing and voltage support.

Securities and Exchange Commission (SEC) - The U.S. agency charged with protecting investors, maintaining fair, orderly and efficient markets and facilitating capital formation.

South Dakota Public Utilities Commission (SDPUC) - The state agency that regulates public utilities doing business in South Dakota.

Southwest Power Pool (SPP) - A nonprofit organization created in compliance with FERC as a regional transmission organization to ensure reliable supplies of power, adequate transmission infrastructure, and a competitive wholesale electricity marketplace. SPP also serves as a regional electric reliability entity under NERC.

Tariffs - A collection of the rate schedules and service rules authorized by a federal or state commission. It lists the rates a regulated entity will charge to provide service to its customers as well as the terms and conditions that it will follow in providing service.

Tolling Contract - An arrangement whereby a party moves fuel to a power generator and receives kilowatt hours (kWh) in return for a pre-established fee.

Transmission - The flow of electricity from generating stations over high voltage lines to substations. The electricity then flows from the substations into a distribution network.

Western Area Power Administration (WAPA) - A federal power-marketing administration and electric transmission agency established by Congress.

Western Electricity Coordination Council (WECC) - WECC is one of eight regional electric reliability councils under NERC.


5



Measurements:

Billion Cubic Feet (Bcf) - A unit used to measure large quantities of gas, approximately equal to 1 trillion Btu.

British Thermal Unit (Btu) - a basic unit used to measure natural gas; the amount of natural gas needed to raise the temperature of one pound of water by one degree Fahrenheit.

Degree-Day - A measure of the coldness / warmness of the weather experienced, based on the extent to which the daily mean temperature falls below or above a reference temperature.

Dekatherm - A measurement of natural gas; ten therms or one million Btu.

Kilovolt (kV) - A unit of electrical power equal to one thousand volts.

Megawatt (MW) - A unit of electrical power equal to one million watts or one thousand kilowatts.

Megawatt Hour (MWH) - One million watt-hours of electric energy. A unit of electrical energy which equals one megawatt of power used for one hour.


6



Part I

ITEM 1.  BUSINESS

OVERVIEW
 
NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and / or natural gas to approximately 718,300 customers in Montana, South Dakota and Nebraska. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have generated and distributed electricity and distributed natural gas in Montana since 2002.

We operate our business in the following reporting segments:
 
Electric operations;
 
Natural gas operations;
 
All other, which primarily consists of unallocated corporate costs.

serviceterritorymap2017a02.jpg


We seek to deliver value to our customers by providing high reliability and customer service, an environmentally sustainable generation mix and a typical residential customer bill that is below the national average benchmark.



7



        typicalbill.jpg
Environmental Stewardship

We strive to balance statutory requirements to provide cost-effective, reliable and stably priced energy with being good stewards of natural resources, with a diligent focus on sustainability. We own a mix of clean and carbon-free energy resources balanced with traditional energy sources that help us deliver affordable and reliable electricity to our customers 24/7. Our policies support both the role of cost-effective energy efficiency and the potential value of low or carbon-free resources as part of our diverse supply portfolio. In 2017, approximately 56% of our retail needs originated from carbon-free resources.



            a2017electricgenerationa01.jpg

8



ELECTRIC OPERATIONS

Montana

Our regulated electric utility business in Montana includes generation, transmission and distribution. Our service territory covers approximately 107,600 square miles, representing approximately 73% of Montana's land area, and includes a 2016 census estimated population of approximately 913,900. During 2017, we delivered electricity to approximately 369,100 customers in 208 communities and their surrounding rural areas, 11 rural electric cooperatives and, in Wyoming, to the Yellowstone National Park. In 2017, by category, residential, commercial, industrial, and other sales accounted for approximately 42%, 48%, 6%, and 4%, respectively, of our Montana retail electric utility revenue. We also transmit electricity for nonregulated entities owning generation, and utilities, cooperatives, and power marketers serving the Montana electricity market. Our total control area peak demand was approximately 1,803 MWs on July 13, 2017. Our control area average demand for 2017 was approximately 1,276 MWs per hour, with total energy delivered of more than 11.1 million MWHs.
 
Our Montana electric transmission and distribution network consists of approximately 24,660 miles of overhead and underground transmission and distribution lines and 385 transmission and distribution substations. Our transmission system is directly interconnected with Avista Corporation; Idaho Power Company; PacifiCorp; the Bonneville Power Administration; WAPA; and Montana Alberta Tie Ltd. Such interconnections, coupled with transmission line capacity made available under agreements with some of the above entities, permit the interchange, purchase, and sale of power among all major electric systems in the west interconnecting with the winter-peaking northern and summer-peaking southern regions of the western power system. We provide wholesale transmission service and firm and non-firm transmission services for eligible transmission customers. Our 500 kV transmission system, which is jointly owned, along with our 230 kV and 161 kV facilities, form the key assets of our Montana transmission system. Lower voltage systems, which range from 50 kV to 115 kV, provide for local area service needs.

Energy Sources and Resource Planning

Resource planning is an important function necessary to meet our future energy needs. We filed a biennial Electric Supply Resource Procurement Plan (resource plan) with the MPSC during 2016, which guides resource acquisition activities. We have significant generation capacity deficits and negative reserve margins, and our 2016 resource plan identified price and reliability risks to our customers if we rely solely upon market purchases to address these capacity needs. In addition to our responsibility to meet peak demand, national reliability standards effective July 2016 require us to have even greater dispatchable generation capacity available and be capable of increasing or decreasing output to address the irregular nature of intermittent generation such as wind or solar. We expect to file our next resource plan in late 2018.

The following charts depict the makeup of our current Montana portfolio. Hydro generation is by far our largest and most important resource, as it is reliable, dramatically lowers the portfolio's carbon intensity, and reduces economic risks associated with future carbon costs.
        
mt2017electricgen.jpg
Our annual retail electric supply load requirements averaged approximately 760 MWs, with a peak load of approximately 1,200 MWs, and are supplied by owned and contracted resources and market purchases with multiple counterparties. Owned generation resources supplied approximately 60% of our retail load requirements for 2017. We expect that approximately 60% of our retail obligations will be met by owned generation in 2018 as well. In addition, QFs provide a total of 393 MWs of

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nameplate capacity, including 87 MWs of capacity from waste petroleum coke and waste coal, 273 MWs of capacity from wind, 16 MWs of capacity from hydro, and 17 MWs of capacity from solar projects, located in Montana. We have several other long and medium-term power purchase agreements including contracts for 135 MWs of wind generation and 21 MWs of seasonal base-load hydro supply. For 2018, including both owned and contracted resources, we have resources to provide over 90% of the energy requirements necessary to meet our forecasted retail load requirements.

Generation Facilities

        montanagenerationfacilities.jpg
    
Details of these generating facilities are described in the following tables.

Hydro Facilities
COD
River
Source
FERC
License
Expiration
Net
Capacity
(MW) (1)
Black Eagle
1927
Missouri
2040
21
Cochrane
1958
Missouri
2040
69
Hauser
1911
Missouri
2040
19
Holter
1918
Missouri
2040
48
Madison
1906
Madison
2040
8
Morony
1930
Missouri
2040
48
Mystic
1925
West Rosebud Creek
2050
12
Rainbow
1910/2013
Missouri
2040
60
Ryan
1915
Missouri
2040
63
Thompson Falls
1915
Clark Fork
2025
94
 Total
 
 
 
442
(1) The Hebgen facility (0 MW net capacity) is excluded from the figures above. These are run-of-river dams except for Mystic, which is storage generation.
Other Facilities
 
Fuel Source
 
Namplate Capacity (MW)
 
Ownership
Interest
 
Owned
Capacity (MW)
Colstrip Unit 4, located near Colstrip in southeastern Montana
 
Sub-bituminous coal
 
740
 
30%
 
222
Dave Gates Generating Station, located near Anaconda, Montana
 
Natural Gas
 
150
 
100%
 
150
Spion Kop Wind, located in Judith Basin County in Montana
 
Wind
 
40
 
100%
 
40

Colstrip Unit 4 provides base-load supply and is operated by Talen Montana, LLC (Talen). Talen has a 30% ownership interest in Colstrip Unit 3. We have a risk sharing agreement with Talen regarding the operation of Colstrip Units 3 and 4, in which each party receives 15% of the respective combined output and is responsible for 15% of the respective operating and

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construction costs, regardless of whether a particular cost is specified to Colstrip Unit 3 or 4. However, each party is responsible for its own fuel-related costs. Colstrip Unit 4 is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through 2019.

DGGS typically provides regulation service, intra-hour balancing, and contingency reserves. DGGS also provided approximately 7 MWs of retail base-load requirements in 2017.

The capacity of Spion Kop represents the nameplate MW, which varies from actual energy expected to be generated as wind resources are highly dependent upon weather conditions.

Renewable portfolio standards (RPS) enacted in Montana currently require that 15% of our annual electric supply portfolio be derived from eligible sources, including resources such as wind, biomass, solar, and small hydroelectric. Eligible resources used to serve our load generate renewable energy credits (RECs). Any RECs in excess of the annual requirements for a given year are carried forward for up to two years to meet future RPS needs. Our owned hydro generation assets are not eligible resources under the RPS. Given contracts under negotiation and our portfolio resources, we expect to meet the Montana RPS requirements through the 2040s. The penalty for not meeting the RPS is up to $10 per MWH for each REC short of the requirement.

As a subset of the total RPS requirement, we were required to acquire, as of December 31, 2017, approximately 65 MW of community renewable energy projects (CREP), if cost effective. Since 2008, we have undertaken competitive solicitations to acquire this particular resource but have only contracted for 25 MW. We filed waivers for 2012 through 2016, as we have not been able to contract with projects that meet the required qualifications. The MPSC granted waivers for 2012 through 2014, and the waiver requests for 2015 and 2016 are still pending. We expect to file a waiver request for 2017. If the requested waivers are not granted, we may be liable for penalties. We believe the statutory penalty for failure to acquire sufficient energy does not apply to the acquisition of CREP resources. If the MPSC imposes a penalty, the amount of the penalty would depend on how the MPSC calculates the energy that a CREP would have produced. 

South Dakota

Our South Dakota electric utility business operates as a vertically integrated generation, transmission and distribution utility. We have the exclusive right to serve an area in South Dakota comprised of 25 counties with a combined 2010 census population of approximately 226,200. We provide retail electricity to more than 63,600 customers in 110 communities in South Dakota. In 2017, by category, residential, commercial and other sales accounted for approximately 39%, 59%, and 2%, respectively, of our South Dakota retail electric utility revenue. Peak demand was approximately 330 MWs, the average load was approximately 186 MWs, and 1.63 million MWHs were supplied during the year ended December 31, 2017.
 
Our transmission and distribution network in South Dakota consists of approximately 3,560 miles of overhead and underground transmission and distribution lines as well as 126 substations. We have interconnection with the transmission facilities of Otter Tail Power Company; Montana-Dakota Utilities Co.; Xcel Energy Inc.; and WAPA. We have emergency interconnections with the transmission facilities of East River Electric Cooperative, Inc. and West Central Electric Cooperative.
 
Energy Sources and Resource Planning

We have a resource plan that includes estimates of customer usage and programs to provide for the economic, reliable and timely supply of energy. We continue to update our load forecast to identify the future electric energy needs of our customers, and we evaluate additional generating capacity requirements on an ongoing basis. We use market purchases and peaking generation to provide peak supply in excess of our base-load capacity. We have an agreement with Missouri River Energy Services to supply firm capacity of 35 MW in 2018. We are a member of the SPP, which is a regional transmission organization that operates an organized energy market in the Central United States. As a market participant in SPP, we buy and sell wholesale energy and reserves in both day-ahead and real-time markets through the operation of a single, consolidated SPP balancing authority. We and other SPP members submit into the SPP market both offers to sell our generation and bids to purchase power to serve our load. SPP optimizes next-day and real-time generation dispatch across the region and provides participants with greater access to economic energy.

Our sources of energy by type during 2017 were as follows:




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sd2017electricgen.jpg

Generation Facilities                                

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Details of our generating facilities are described further in the following chart:

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Generation Facilities
 
Fuel Source
 
Nameplate Capacity (MW)
 
Ownership
Interest
 
Owned
Capacity (MW)
Big Stone Plant, located near Big Stone City in northeastern South Dakota
 
Sub-bituminous coal
 
475
 
23.4%
 
111
Coyote I Electric Generating Station, located near Beulah, North Dakota
 
Lignite coal
 
427
 
10.0%
 
43
Neal Electric Generating Unit No. 4, located near Sioux City, Iowa
 
Sub-bituminous coal
 
644
 
8.7%
 
56
Aberdeen Generating Unit, located near Aberdeen, South Dakota
 
Natural gas
 
52
 
100.0%
 
52
Beethoven Wind Project, located near Tripp, South Dakota
 
Wind
 
80
 
100.0%
 
80
Miscellaneous combustion turbine units and small diesel units (used only during peak periods)
 
Combination of fuel oil and natural gas
 
 
 
100.0%
 
98
Total Capacity
 
 
 
 
 
 
 
440

Our electric supply portfolio includes facilities that we own jointly with unaffiliated parties. Each of the jointly owned plants is subject to a joint management structure, and we are not the operator of any of these plants. Based upon our ownership interest, we are entitled to a proportionate share of the capacity of our jointly owned plants and are responsible for a proportionate share of the operating costs. Additional resources in our supply portfolio include several wholly owned peaking units and three wind projects. The Beethoven wind project is an 80 MW nameplate facility. Actual output varies as wind generation resources are highly dependent upon weather conditions. We also purchase the output of two wind projects, one of which is a QF, under power purchase agreements.

The fuel for our jointly owned base-load generating plants is provided through supply contracts of various lengths with several coal companies. Coyote is a mine-mouth generating facility. Neal #4 and Big Stone receive their fuel supply via rail. The average delivered cost by type of fuel burned varies between generation facilities due to differences in transportation costs and owner purchasing power for coal supply. Changes in our fuel costs are passed on to customers through the operation of the fuel adjustment clause in our South Dakota tariffs.
 
South Dakota has a voluntary renewable and recycled energy objective, which provides that 10% of all electricity sold at retail within South Dakota be obtained from renewable and recycled energy sources. In 2017, approximately 29% of South Dakota retail needs originated from renewable resources. In 2018, we expect to continue to receive approximately the same level of generation from renewable resources. We may sell company-generated RECs, with proceeds benefiting our customers. We also do not purchase all of the RECs associated with contracted wind generation. Accordingly, not all of the energy from these resources delivered to retail customers qualifies as renewable or recycled under this voluntary standard.

We are a transmission-owning member in the SPP. Each year, we review all new or modified South Dakota transmission assets and transfer functional control of assets that qualify under the SPP Tariff to the SPP. To date, we have transferred control of over 330 line miles of 115 kV facilities and over 97 line miles of 69 kV facilities. All of our SPP controlled facilities reside in the Upper Missouri Zone (UMZ), which is also known as Zone 19 in the regional transmission organization. The Coyote, Big Stone, and Neal power plants, which we jointly own, are connected directly to the MISO system. Our ownership rights in the transmission lines from these plants to our distribution system allow us to move the power to our customers. Marketing activities in SPP are handled for us by a third-party provider acting as our agent. Along with operating the transmission system, SPP also coordinates transmission planning for all members of the organization.
 

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NATURAL GAS OPERATIONS

Montana

Our regulated natural gas utility business in Montana includes production, storage, transmission and distribution. During 2017, we distributed natural gas to approximately 196,700 customers in 118 Montana communities over a system that consists of approximately 5,187 miles of underground distribution pipelines. We also serve several smaller distribution companies that provide service to approximately 37,000 customers. We transmit natural gas in Montana from production receipt points and storage facilities to distribution points and other nonaffiliated transmission systems. We transported natural gas volumes of approximately 42.9 Bcf during the year ended December 31, 2017.
 
Our natural gas transmission system consists of more than 2,100 miles of pipeline, which vary in diameter from two inches to 24 inches, and serve more than 140 city gate stations. We have connections in Montana with four major, unaffiliated transmission systems: Williston Basin Interstate Pipeline, NOVA Gas Transmission Ltd., Colorado Interstate Gas, and Spur Energy. Eight compressor sites provide more than 34,000 horsepower, capable of moving more than 335,000 dekatherms per day. In addition, we own and operate two transmission pipelines through our subsidiaries, Canadian-Montana Pipe Line Corporation and Havre Pipeline Company, LLC.
  
Natural gas is used primarily for residential and commercial heating, and for fuel for two electric generating facilities. The demand for natural gas largely depends upon weather conditions. Our Montana retail natural gas supply requirements for the year ended December 31, 2017, were approximately 20.8 Bcf. Our Montana natural gas supply requirements for electric generation fuel for the year ended December 31, 2017, were approximately 3.9 Bcf. We have contracted with several major producers and marketers with varying contract durations to provide the anticipated supply to meet ongoing requirements. Our natural gas supply requirements are fulfilled through third-party fixed-term purchase contracts, short-term market purchases and owned production. Our portfolio approach to natural gas supply is intended to enable us to maintain a diversified supply of natural gas sufficient to meet our supply requirements. We benefit from direct access to suppliers in significant natural gas producing regions in the United States, primarily the Rockies (Colorado), Montana, and Alberta, Canada.

Owned Production and Storage

Since 2010, we have acquired gas production and gathering system assets as a part of an overall strategy to provide rate stability and customer value: as we own these assets, which are regulated, our customers are protected from potential price spikes in the market. As of December 31, 2017, these owned reserves totaled approximately 55.9 Bcf and are estimated to provide approximately 4.5 Bcf in 2018, or about 22 percent of our expected annual retail natural gas load in Montana. In addition, we own and operate three working natural gas storage fields in Montana with aggregate working gas capacity of approximately 17.75 Bcf and maximum aggregate daily deliverability of approximately 195,000 dekatherms.

South Dakota and Nebraska

We provide natural gas to approximately 88,900 customers in 59 South Dakota communities and three Nebraska communities. We have approximately 2,416 miles of underground distribution pipelines and 55 miles of transmission pipeline in South Dakota and Nebraska. In South Dakota, we also transport natural gas for eight gas-marketing firms and three large end-user accounts. In Nebraska, we transport natural gas for four gas-marketing firms and one end-user account. We delivered approximately 27.4 Bcf of third-party transportation volume on our South Dakota distribution system and approximately 3.3 Bcf of third-party transportation volume on our Nebraska distribution system during 2017.
 
Our South Dakota natural gas supply requirements for the year ended December 31, 2017, were approximately 5.6 Bcf. We contract with a third party under an asset management agreement to manage transportation and storage of supply to minimize cost and price volatility to our customers. In Nebraska, our natural gas supply requirements for the year ended December 31, 2017, were approximately 4.1 Bcf. We contract with a third party under an asset management agreement that includes pipeline capacity, supply, and asset optimization activities. To supplement firm gas supplies in South Dakota and Nebraska, we contract for firm natural gas storage services to meet the heating season and peak day requirements of our customers.

Municipal Natural Gas Franchise Agreements
 
We have municipal franchises to provide natural gas service in the communities we serve. The terms of the franchises vary by community. Our Montana franchises typically have a fixed 10-year term and continue for an additional 10-year term unless and until canceled, with 5 years notice. The maximum term permitted under Nebraska law for these franchises is 25 years while

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the maximum term permitted under South Dakota law is 20 years. Our policy generally is to seek renewal or extension of a franchise in the last year of its term. We continue to serve those customers while we obtain formal renewals. During the next five years, five of our Montana franchises are scheduled to reach the end of their fixed term, which account for approximately 39,000 or 20 percent of our Montana natural gas customers. Eight of our South Dakota franchises and one franchise in Nebraska, which account for approximately 18,550 or 21% of our South Dakota and Nebraska natural gas customers, are scheduled to reach the end of their fixed term during the next five years. We do not anticipate termination of any of these franchises.
REGULATION

Base rates are the rates that are intended to allow us the opportunity to collect from our customers total revenues (revenue requirements) equal to our cost of providing delivery and rate-based supply services, plus a reasonable rate of return on invested capital. We have both electric and natural gas base rates and cost recovery clauses. We may ask the respective regulatory commission to increase base rates from time to time. Rate increases are normally granted based on historical data and those increases may not always keep pace with increasing costs. For more information on current regulatory matters, see Note 3 - Regulatory Matters, to the Consolidated Financial Statements.

The following is a summary of our rate base and authorized rates of return in each jurisdiction:

Jurisdiction and Service
 
Implementation Date
 
Authorized Rate Base (millions) (1)
 
Estimated Rate Base (millions) (2)
 
Authorized Overall Rate of Return
 
Authorized Return on Equity
 
Authorized Equity Level
Montana electric delivery (3)
 
July 2011
 
$632.5
 
$1,163.4
 
7.92%
 
10.25%
 
48%
Montana - DGGS (3)
 
January 2011
 
172.7
 
122.5
 
8.16%
 
10.25%
 
50%
Montana - Colstrip Unit 4
 
January 2009
 
400.4
 
298.7
 
8.25%
 
10.00%
 
50%
Montana Spion Kop
 
December 2012
 
69.8
 
47.1
 
7.00%
 
10.00%
 
48%
Montana hydro assets
 
November 2014
 
841.8
 
783.4
 
6.91%
 
9.80%
 
48%
Montana natural gas delivery and production
 
September 2017
 
430.2
 
435.2
 
6.96%
 
9.55%
 
46.79%
South Dakota electric (4)
 
December 2015
 
557.3
 
577.6
 
7.24%
 
n/a
 
n/a
South Dakota natural gas (4)
 
December 2011
 
65.9
 
63.0
 
7.80%
 
n/a
 
n/a
Nebraska natural gas (4)
 
December 2007
 
24.3
 
27.5
 
8.49%
 
10.40%
 
n/a
 
 
 
 
$3,194.9
 
$3,518.4
 
 
 
 
 
 
(1)    Rate base reflects amounts on which we are authorized to earn a return.
(2)    Rate base amounts are estimated as of December 31, 2017.
(3)
The FERC regulated portion of Montana electric transmission and DGGS are included as revenue credits to our MPSC jurisdictional customers. Therefore, we do not separately reflect FERC authorized rate base or authorized returns.
(4)    For those items marked as "n/a," the respective settlement and/or order was not specific as to these terms.

MPSC Regulation

Our Montana operations are subject to the jurisdiction of the MPSC with respect to rates, terms and conditions of service, accounting records, electric service territorial issues and other aspects of our operations, including when we issue, assume, or guarantee securities in Montana, or when we create liens on our regulated Montana properties. We have an obligation to provide service to our customers with an opportunity to earn a regulated rate of return.

Electric Supply Tracker - In April 2017, the Montana legislature passed House Bill 193 (HB 193), amending the statute that provided for mandatory recovery of our prudently incurred electric supply costs effective July 1, 2017. The revised statute gives the MPSC discretion whether to approve an electric supply cost adjustment mechanism. The MPSC initiated a process to develop a replacement electric supply cost adjustment mechanism, and in response, in July 2017, we filed a proposed electric Power Cost and Credit Adjustment Mechanism (PCCAM). A hearing is scheduled to begin May 31, 2018.

Natural Gas Supply Tracker - Rates for our Montana natural gas supply are set by the MPSC. Certain supply rates are adjusted on a monthly basis for volumes and costs during each July to June 12-month tracking period. Annually, supply rates

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are adjusted to include any differences in the previous tracking year's actual to estimated information for recovery during the subsequent tracking year. We submit an annual natural gas tracker filings for the actual 12-month period ended June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our natural gas energy supply procurement activities were prudent. If the MPSC subsequently determines that a procurement activity was imprudent, then it may disallow such costs.

Montana Property Tax Tracker - We file an annual property tax tracker (including other state/local taxes and fees) with the MPSC for an automatic rate adjustment, which reflects the incremental property taxes since our last base rate filing adjusted for the associated income tax benefit.
 
SDPUC Regulation

Our South Dakota operations are subject to SDPUC jurisdiction with respect to rates, terms and conditions of service, accounting records, electric service territorial issues and other aspects of our electric and natural gas operations. Our retail electric rates, approved by the SDPUC, provide several options for residential, commercial and industrial customers, including dual-fuel, interruptible, special all-electric heating, and other special rates. Our retail natural gas tariffs include gas transportation rates for transportation through our distribution systems by customers and natural gas marketers from the interstate pipelines at which our systems take delivery to the end-user. Such transporting customers nominate the amount of natural gas to be delivered daily. Daily, we monitor usage for these customers and balance it against their respective supply agreements.
 
An electric adjustment clause provides for quarterly adjustment based on differences in the delivered cost of energy, delivered cost of fuel, ad valorem taxes paid and commission-approved fuel incentives. The adjustment goes into effect upon filing, and is deemed approved within 10 days after the information filing unless the SDPUC staff requests changes during that period. A purchased gas adjustment provision in our natural gas rate schedules permits the monthly adjustment of charges to customers to reflect increases or decreases in purchased gas, gas transportation and ad valorem taxes.
 
NPSC Regulation
 
Our Nebraska natural gas rates and terms and conditions of service for residential and smaller commercial customers are regulated by the NPSC. High volume customers are not subject to such regulation, but can file complaints if they allege discriminatory treatment. Under the Nebraska State Natural Gas Regulation Act, a regulated natural gas utility may propose a change in rates to its regulated customers, if it files an application for a rate increase with the NPSC and with the communities in which it serves customers. The utility may negotiate with those communities for a settlement with regard to the rate change if the affected communities representing more than 50% of the affected ratepayers agree to direct negotiations, or it may proceed to have the NPSC review the filing and make a determination. Our tariffs have been accepted by the NPSC, and the NPSC has adopted certain rules governing the terms and conditions of service of regulated natural gas utilities. Our retail natural gas tariffs provide residential, general service and commercial and industrial options, as well as firm and interruptible transportation service. A purchased gas adjustment clause provides for adjustments based on changes in gas supply and interstate pipeline transportation costs.
 
FERC Regulation
 
We are subject to FERC's jurisdiction and regulations with respect to rates for electric transmission service in interstate commerce and electricity sold at wholesale rates, hydro licensing and operations, the issuance of certain securities, incurrence of certain long-term debt, and compliance with mandatory reliability regulations, among other things. Under FERC's open access transmission policy promulgated in Order No. 888, as owners of transmission facilities, we are required to provide open access to our transmission facilities under filed tariffs at cost-based rates. In addition, we are required to comply with FERC's Standards of Conduct for Transmission Providers.
 
Our Montana wholesale transmission customers, such as cooperatives, are served under our OATT, which is on file with FERC. The OATT also defines the terms, conditions and rates of our Montana transmission service, including ancillary services. Our South Dakota transmission operations are in the SPP and the majority of transmission service is provided under the SPP OATT. We maintain an OATT in South Dakota to provide discrete transmission service to a small number of transmission customers.
  
Our natural gas transportation pipelines are generally not subject to FERC's jurisdiction, although we are subject to state regulation. We conduct limited interstate transportation in Montana and South Dakota that is subject to FERC jurisdiction, but

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FERC has allowed the MPSC and SDPUC to set the rates for this interstate service. We have capacity agreements in South Dakota and Nebraska with interstate pipelines that are also subject to FERC jurisdiction.

Our hydroelectric generating facilities are licensed by the FERC. In connection with the relicensing of these generating facilities, applicable law permits the FERC to issue a new license to the existing licensee or to a new licensee, and alternatively allows the U.S. government to take over the facility. If the existing licensee is not relicensed, it is compensated for its net investment in the facility, not to exceed the fair value of the property taken, plus reasonable severance damages to other property affected by the lack of relicensing.
 
Reliability Standards - We must comply with the standards and requirements that apply to the NERC functions for which we have registered in both the MRO for our South Dakota operations and the WECC for our Montana operations. WECC and the MRO have responsibility for monitoring and enforcing compliance with the FERC approved mandatory Reliability Standards within their respective regions. Additional reliability standards continue to be developed and will be adopted in the future. We expect that the existing reliability standards will change often as a result of modifications, guidance and clarification following industry implementation and ongoing audits and enforcement.

SEASONALITY AND CYCLICALITY
 
Our electric and gas utility businesses are seasonal businesses, and weather patterns can have a material impact on operating performance. Because natural gas is used primarily for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Demand for electricity is often greater in the summer and winter months for cooling and heating, respectively. Accordingly, our operations have historically generated less revenue and income when weather conditions are milder in the winter and cooler in the summer. These weather patterns could adversely affect our results of operations, financial condition and liquidity.

ENVIRONMENTAL

The operation of electric generating, transmission and distribution facilities, and gas gathering, storage, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are issued, we assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.

We strive to comply with all environmental regulations applicable to our operations. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, what effect future laws or regulations may have on our operations. The EPA is in the process of proposing and finalizing a number of environmental regulations that will directly affect the electric industry over the coming years. These initiatives cover all sources - air, water and waste. For more information on environmental regulations and contingencies and related capital expenditures, see Note 18 - Commitments and Contingencies, to the Consolidated Financial Statements.

CORPORATE INFORMATION AND WEBSITE

We were incorporated in Delaware in November 1923. Our Internet address is http://www.northwesternenergy.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments, along with our annual report to shareholders and other information related to us, are available, free of charge, on our Internet website as soon as reasonably practicable after we electronically file those documents with, or otherwise furnish them to, the SEC. This information is available in print to any shareholder who requests it. Requests should be directed to: Investor Relations, NorthWestern Corporation, 3010 W. 69th Street, Sioux Falls, South Dakota 57108 and our telephone number is (605) 978-2900. References to our website in this report are provided as a convenience and do not constitute, and should not be viewed as, an incorporation by reference of the information contained on, or available through, the website. Therefore, such information should not be considered part of this report.

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EMPLOYEES

As of December 31, 2017, we had 1,557 employees. Of these, 1,233 employees were in Montana and 324 were in South Dakota or Nebraska. Of our Montana employees, 459 were covered by seven collective bargaining agreements involving five unions. Six of these agreements were renegotiated in 2016 with terms that will expire in 2020. One of these agreements was renegotiated in 2017 with a term that will expire in 2021. Of our South Dakota and Nebraska employees, 194 were covered by a collective bargaining agreement that was renegotiated in 2016 with a term that expires at the end of 2019. We consider our relations with employees to be good.

Executive Officer
 
Current Title and Prior Employment
 
Age on Feb. 9, 2018
Robert C. Rowe
 
President, Chief Executive Officer and Director since August 2008. Prior to joining NorthWestern, Mr. Rowe was a co-founder and senior partner at Balhoff, Rowe & Williams, LLC, a specialized national professional services firm providing financial and regulatory advice to clients in the telecommunications and energy industries (January 2005-August, 2008); and served as Chairman and Commissioner of the Montana Public Service Commission (1993–2004).
 
62
 
 
 
 
 
Brian B. Bird
 
Vice President and Chief Financial Officer since December 2003. Prior to joining NorthWestern, Mr. Bird was Chief Financial Officer and Principal of Insight Energy, Inc., a Chicago-based independent power generation development company (2002-2003). Previously, he was Vice President and Treasurer of NRG Energy, Inc., in Minneapolis, MN (1997-2002). Mr. Bird serves on the board of directors of a NorthWestern subsidiary.
 
55
 
 
 
 
 
Michael R. Cashell
 
Vice President - Transmission since May 2011; formerly Chief Transmission Officer since November 2007; formerly Director Transmission Marketing and Business Planning since 2003. Mr. Cashell serves on the board of directors of a NorthWestern subsidiary.
 
55
 
 
 
 
 
Heather H. Grahame
 
Vice President - General Counsel and Regulatory and Federal Government Affairs since January 2018; formerly Vice President and General Counsel since August 2010. Prior to joining NorthWestern, Ms. Grahame was a partner in the law firm of Dorsey & Whitney, LLP, where she co-chaired its Telecommunications practice (1999-2010).
 
62
 
 
 
 
 
John D. Hines
 
Vice President - Supply and Montana Government Affairs since January 2018; formerly Vice President - Supply since May 2011; formerly Chief Energy Supply Officer since January 2008; formerly Director - Energy Supply Planning since 2006. Previously, Mr. Hines served as the Montana representative to the Northwest Power and Conservation Council (2003-2006).
 
59
 
 
 
 
 
Crystal D. Lail
 
Vice President and Controller since October 2015; formerly Assistant Controller since February 2008 and, prior to that an SEC Reporting Manager. Prior to joining NorthWestern, Ms. Lail was an auditor for KPMG LLP.
 
39
 
 
 
 
 
Curtis T. Pohl
 
Vice President - Distribution since May 2011; formerly Vice President-Retail Operations since September 2005; Vice President-Distribution Operations since August 2003; formerly Vice President-South Dakota/Nebraska Operations since June 2002; formerly Vice President-Engineering and Construction since June 1999. Mr. Pohl serves on the board of directors of a NorthWestern subsidiary.
 
53
 
 
 
 
 
Bobbi L. Schroeppel
 
Vice President, Customer Care, Communications and Human Resources since May 2009, formerly Vice President-Customer Care and Communications since September 2005; formerly Vice President-Customer Care since June 2002; formerly Director-Staff Activities and Corporate Strategy since August 2001; formerly Director-Corporate Strategy since June 2000.
 
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Officers are elected annually by, and hold office at the pleasure of the Board of Directors (Board), and do not serve a “term of office” as such.


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ITEM 1A.  RISK FACTORS -

You should carefully consider the risk factors described below, as well as all other information available to you, before making an investment in our common stock or other securities.
 
We are subject to potential unfavorable state and federal regulatory outcomes. To the extent our incurred costs are deemed imprudent by the applicable regulatory commissions or certain regulatory mechanisms are not available, we may not recover some of our costs, which could adversely impact our results of operations and liquidity.

Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. We provide service at rates established by several regulatory commissions. These rates are generally set based on an analysis of our costs incurred in a historical test year. In addition, each regulatory commission sets rates based in part upon their acceptance of an allocated share of total utility costs. When commissions adopt different methods to calculate inter-jurisdictional cost allocations, some costs may not be recovered. Thus, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs. In addition to rate cases, our cost tracking mechanisms are a significant component of how we recover our costs. Historically, our wholesale costs for electricity and natural gas supply were recovered through various pass-through cost tracking mechanisms in each of the states we serve.

Montana

We have received several unfavorable regulatory rulings in Montana, including:

In January 2018, the MPSC issued an order in our 2017 property tax tracker filing reducing our recovery of Montana property taxes between general rate filings by applying an alternate allocation methodology. This results in a lower property tax allocation to our Montana electric retail customers and a higher property tax allocation to FERC transmission customers (we do not have a property tax tracker for FERC jurisdictional purposes).

In 2017, the MPSC revised our QF tariff for standard QF rates for small QFs (3 MW or less) to establish a maximum contract length of 15 years and substantially lowering the rate for future QF contracts. In this order, the MPSC also applied the 15-year contract term to our future owned and contracted electric supply resources. As a result, we terminated our competitive solicitation process to determine the lowest-cost / least-risk approach for addressing our intermittent capacity and reserve margin needs in Montana. This order may have a significant impact on our approach to meet our portfolio needs. We continue to evaluate the impact of this decision.

In 2016, the MPSC disallowed replacement power costs from a 2013 outage at Colstrip Unit 4 requested in our electric tracker filings. We appealed the MPSC’s decision regarding the disallowance of Colstrip Unit 4 costs in Montana District Court, arguing that these decisions were arbitrary and capricious, and violated Montana law.

In October 2015, the MPSC issued an order eliminating the lost revenue adjustment mechanism. This mechanism was established in 2005 as a component of an approved energy efficiency program, by which we recovered on an after-the-fact basis our fixed costs that would otherwise have been collected in the kWh sales lost due to energy efficiency programs through our supply tracker. Recovery of lost revenues was terminated, prospectively, effective December 1, 2015.

In October 2013, the MPSC concluded that costs associated with a 2012 outage at DGGS were imprudently incurred, and disallowed recovery.

We have two significant dockets currently in process with the MPSC. The MPSC advocated revising the statute that provided for mandatory recovery of our prudently incurred electric supply costs, and in April 2017, the Montana legislature passed HB 193, amending the statute. In July 2017, we filed a proposed electric PCCAM. Following the submission of intervenor testimony, the MPSC identified additional issues and established a revised procedural schedule with a hearing scheduled to begin May 31, 2018. We cannot guarantee how the MPSC may apply the statute in establishing a revised mechanism. To the extent our energy supply costs are deemed imprudent by the applicable state regulatory commissions, or the passage of HB 193 reduces our recovery or the timeliness of cash flows, the revised mechanism could adversely impact our

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results of operations and cash flows. The MPSC also established a docket regarding the impact of the Tax Cuts and Jobs Act and we expect to submit a filing regarding the customer benefit during the first quarter of 2018. We cannot predict how the MPSC may address this filing.

FERC & Other Regulation

In our regulatory filings related to DGGS, we proposed an allocation of approximately 80% of costs to retail customers subject to the MPSC's jurisdiction and approximately 20% allocated to wholesale customers subject to FERC's jurisdiction. In March 2012, the MPSC's final order approved using our proposed cost allocation methodology, but requires us to complete a study of the relative contribution of retail and wholesale customers to regulation capacity needs. The results of this study may be used in determining future cost allocations between retail and wholesale customers. However, there is no assurance that both the MPSC and FERC will agree on the results of this study, which could result in an inability to fully recover our costs in a future electric general rate filing.

We must also comply with established reliability standards and requirements, which apply to the NERC functions in both the MRO for our South Dakota operations and WECC for our Montana operations. The FERC, NERC, or a regional reliability organization may assess penalties against any responsible entity that violates their rules, regulations or standards. Violations may be discovered through various means, including self-certification, self-reporting, compliance investigations, audits, periodic data submissions, exception reporting, and complaints. Penalties for the most severe violations can reach as high as approximately $1.2 million per violation, per day. If a serious reliability incident or other incidence of noncompliance did occur, it could have a material adverse effect on our operating and financial results.

We are also subject to changing federal and state laws and regulations. Congress and state legislatures may enact legislation that adversely affects our operations and financial results.

We are subject to existing, and potential future, federal and state legislation. In the planning and management of our operations, we must address the effects of legislation within a regulatory framework. Federal and state laws can significantly impact our operations, whether it is new or revised statutes directly affecting the electric and gas industry, or other issues such as taxes.

In addition, new or revised statutes can also materially affect our operations through impacting existing regulations or requiring new regulations. These changes are ongoing, and we cannot predict the future course of changes or the ultimate effect that this changing environment will have on us. Changes in laws, and the resulting regulations and tariffs and how they are implemented and interpreted, may have a material adverse effect on our financial condition, results of operations and cash flows.

Our ability to invest in additional generation is impacted by PURPA, which requires electric utilities, with few exceptions, to purchase energy and capacity from independent power producers that are QFs. Our requirements to procure power from these sources could impact our ability to make generation investments depending upon the number and size of QF contracts we ultimately enter into. The cost to procure power from these QFs may not be a cost effective resource for customers, or the type of generation resource needed, resulting in increased supply costs.

On June 22, 2016, the Securing America’s Future Energy: Protecting our Infrastructure of Pipelines and Enhancing Safety Act (SAFE PIPES Act), was signed into law. The law prioritized the Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA) completion of outstanding regulations and proposed regulations to safety standards for natural gas transmission and gathering pipelines. The long-anticipated proposal could impose significant regulatory requirements for additional miles of natural gas pipeline, including pipelines constructed prior to 1970, which were previously exempt from PHMSA regulations related to pressure testing. It would also create a new "Moderate Consequence Area" category to expand safety protocols to pipelines in moderately populated areas. The rule also would codify the Integrity Verification Process (IVP) which is a process that will require companies to have reliable, traceable, verifiable, and complete records for pipelines in certain areas. The rule would establish a deadline for IVP completion that we will be required to meet. Costs incurred to comply with the proposed regulations may be material.

We are subject to extensive and changing environmental laws and regulations and potential environmental liabilities, which could have a material adverse effect on our liquidity and results of operations.

We are subject to extensive laws and regulations imposed by federal, state, and local government authorities in the ordinary course of operations with regard to the environment, including environmental laws and regulations relating to air and water quality, protection of natural resources, migratory birds and other wildlife, solid waste disposal, coal ash and other

20



environmental considerations. We believe that we are in compliance with environmental regulatory requirements; however, possible future developments, such as more stringent environmental laws and regulations, and the timing of future enforcement proceedings that may be taken by environmental authorities, could affect our costs and the manner in which we conduct our business and could require us to make substantial additional capital expenditures or abandon certain projects.

In October 2015, the EPA published standards for states to implement to control greenhouse gas (GHG) emissions from existing electric generating units. These standards are referred to as the Clean Power Plan (CPP). We, along with a number of states and other parties, filed lawsuits against the EPA standards. The EPA proposed to repeal the CPP in October 2017, and in December 2017, issued an Advance Notice of Proposed Rulemaking (ANPR), soliciting information on systems of emission reduction that comply with EPA’s interpretation of the Clean Air Act, for a possible replacement of the CPP. In light of the proposed repeal, and the ANPR, the future of the CPP regulations and associated guidance is uncertain. However, if the CPP is not repealed, survives the pending legal challenges and is implemented as written or if a replacement to the CPP is adopted with similar requirements, it could result in significant additional compliance costs that would affect our future results of operations and financial position if such costs are not recovered through regulated rates. Due to the pending litigation, the proposed repeal of the CPP, the ANPR, and the uncertainties in the state approaches, the ultimate timing and impact of the CPP or other GHG regulations on our operations cannot be determined with certainty at this time. Complying with the CO2 emission performance standards, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of our jointly owned facilities or for individual owners to participate in their proportionate ownership of the coal-fired generating units. This could lead to significant impacts to customer rates for recovery of plant improvements and / or closure related costs and costs to procure replacement power. In addition, these changes could impact system reliability due to changes in generation sources.

Many of these environmental laws and regulations provide for substantial civil and criminal fines for noncompliance which, if imposed, could result in material costs or liabilities. In addition, there is a risk of environmental damages claims from private parties or government entities. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair, upgrade or expansion of our facilities to meet future requirements and obligations under environmental laws.

To the extent that costs exceed our estimated environmental liabilities, or we are not successful in recovering remediation costs or costs to comply with the proposed or any future changes in rules or regulations, our results of operations and financial position could be adversely affected.

Weather and weather patterns, including normal seasonal and quarterly fluctuations of weather, as well as extreme weather events that might be associated with climate change, could adversely affect our results of operations and liquidity.

Our electric and natural gas utility business is seasonal, and weather patterns can have a material impact on our financial performance. Demand for electricity and natural gas is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenue and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters or cool summers could adversely affect our results of operations and financial position. In addition, exceptionally hot summer weather or unusually cold winter weather could add significantly to working capital needs to fund higher than normal supply purchases to meet customer demand for electricity and natural gas. Our sensitivity to weather volatility is significant due to the absence of regulatory mechanisms, such as those authorizing revenue decoupling, lost margin recovery, and other innovative rate designs.

Severe weather impacts, including but not limited to, thunderstorms, high winds, wildfires, tornadoes and snow or ice storms can disrupt energy generation, transmission and distribution. We derive a significant portion of our energy supply from hydroelectric facilities, and the availability of water can significantly affect operations. Higher temperatures may decrease the Montana snowpack and impact the timing of run-off and may require us to purchase replacement power. Dry conditions also increase the threat of wildfires, which could threaten our communities and electric distribution and transmission lines and facilities. In addition, wildfires alleged to have been caused by our system could expose us to substantial property damage and other claims. Any damage caused as a result of wildfires could negatively impact our financial condition, results of operations or cash flows.

There is also a concern that the physical risks of climate change could include changes in weather conditions, such as changes in the amount or type of precipitation and extreme weather events. Climate change and the costs that may be associated with its impacts have the potential to affect our business in many ways, including increasing the cost incurred in

21



providing electricity and natural gas, impacting the demand for and consumption of electricity and natural gas (due to change in both costs and weather patterns), and affecting the economic health of the regions in which we operate. Extreme weather conditions creating high energy demand on our own and/or other systems may raise market prices as we buy short-term energy to serve our own system. To the extent the frequency of extreme weather events increase, this could increase our cost of providing service. In addition, we may not recover all costs related to mitigating these physical and financial risks.

Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions or response to price increases. We are also impacted by market conditions outside of our service territories related to demand for transmission capacity and wholesale electric pricing.

Our revenues, results of operations and financial condition are impacted by customer growth and usage, which can be impacted by a number of factors, including the voluntary reduction of consumption of electricity and natural gas by our customers in response to increases in prices and demand-side management programs, economic conditions impacting decreases in their disposable income, and the use of distributed generation resources or other emerging technologies for electricity. Advances in distributed generation technologies that produce power, including fuel cells, micro-turbines, wind turbines and solar cells, may reduce the cost of alternative methods of producing power to a level competitive with central power station electric production. Customer-owned generation itself reduces the amount of electricity purchased from utilities and may have the effect of increasing rates generally and increasing rates for customers who do not own generation, unless retail rates are designed to share the costs of the distribution grid across all customers that benefit from their use. Such developments could affect the price of energy, could affect energy deliveries as customer-owned generation becomes more cost-effective, could require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy. 

Decreasing use per customer (driven, for example, by appliance and lighting efficiency) and the availability of cost-effective distributed generation, both put downward pressure on load growth. Our resource plan includes an expected load growth assumption of 0.8 percent annually, which reflects low customer and usage increases, offset in part by these efficiency measures. Reductions in usage, attributable to various factors could materially affect our results of operations, financial position, and cash flows through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.

Demand for our Montana transmission capacity fluctuates with regional demand, fuel prices and weather related conditions. The levels of wholesale sales depend on the wholesale market price, market participants, transmission availability and the availability of generation, among other factors. Declines in wholesale market price, availability of generation, transmission constraints in the wholesale markets, or low wholesale demand could reduce wholesale sales. These events could adversely affect our results of operations, financial position and cash flows.

Cyber and physical attacks, threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may affect our operations in unpredictable ways and could adversely affect our liquidity and results of operations.

We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber (such as hacking and viruses) and physical security breaches and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities are deemed critical infrastructure and provide the framework for our service infrastructure. These assets and the information technology systems on which they depend could be direct targets of, or indirectly affected by, cyber attacks and other disruptive activities, including cyber attacks and other disruptive activities on third party facilities that are interconnected to us through the regional transmission grid or natural gas pipeline infrastructure. Any significant interruption of these assets or systems could prevent us from fulfilling our critical business functions including delivering energy to our customers, and sensitive, confidential and other data could be compromised.

We rely on information technology networks and systems to operate our critical infrastructure, engage in asset management activities, and process, transmit and store electronic information including customer and employee information. Further, our infrastructure, networks and systems are interconnected to external networks and neighboring critical infrastructure systems. Security breaches could lead to system disruptions, generating facility shutdowns or unauthorized disclosure of confidential information. Cyber or physical attacks, terrorist acts, or disruptive activities could harm our business by limiting our ability to generate, purchase or transmit power and by delaying the development and construction of new facilities and capital improvements to existing facilities.

22




In addition, our information systems and those of our third-party vendors contain confidential information, including information about customers and employees. A data breach involving theft, improper disclosure, or other unauthorized access to or acquisition of confidential information could subject us to penalties for violation of applicable privacy laws, claims by third parties, and enforcement actions by government agencies. It could also reduce the value of proprietary information, and harm our reputation.

Security threats continue to evolve and adapt. We and our third-party vendors have been subject to, and will likely continue to be subject to, attempts to gain unauthorized access to systems, or confidential data, or to disrupt operations. None of these attempts has individually or in aggregate resulted in a security incident with a material impact on our financial condition or results of operations. Despite implementation of security and control measures, there can be no assurance that we will be able to prevent the unauthorized access of our systems and data, or the disruption of our operations, either of which could have a material impact.

These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure assets, and could adversely affect our operations by contributing to the disruption of supplies and markets for electricity, natural gas, oil and other fuels. These events could also impair our ability to raise capital by contributing to financial instability and reduced economic activity.

Our electric and natural gas transmission and distribution operations involve numerous activities that may result in accidents, wildfires, and other operating risks and costs that are unique to our industry.

Inherent in our electric and natural gas operations are a variety of hazards and operating risks, such as fires, electric contacts, leaks, explosions, catastrophic failures and mechanical problems. These risks could cause a loss of human life, significant damage to property, loss of customer load, environmental pollution, impairment of our operations, and substantial financial losses to us and others. Fires alleged to have been caused by our system could also expose us to significant damage claims on theories such as strict liability, negligence, gross negligence, trespass, inverse condemnation, and others. The risk of wildfires is exacerbated in forested areas where beetle infestations have caused a significant increase in the quantity of standing dead and dying timber, increasing the risk that such trees may fall from either inside or outside our right-of-way into a powerline igniting a fire. For our natural gas lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks potentially is greater. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

Our owned and jointly owned electric generating facilities are subject to risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, increased power purchase costs and the inability to recover our investment.

Operation of electric generating facilities involves risks, which can adversely affect energy output and efficiency levels. Operational risks include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error, catastrophic events such as fires, explosions, floods, and intentional acts of destruction or other similar occurrences affecting the electric generating facilities; and operational changes necessitated by environmental legislation, litigation or regulation. The loss of a major electric generating facility would require us to find other sources of supply or ancillary services, if available, and expose us to higher purchased power costs. In early July 2013, following the return to service from a scheduled maintenance outage, Colstrip Unit 4 tripped off-line and incurred damage to its stator and rotor. Colstrip Unit 4 returned to service in early 2014. As discussed above, we were not able to fully recover our costs for the purchase of replacement power while Colstrip Unit 4 was out of service.

Our investment in generating facilities is a long-lived asset. An early retirement of a unit before the end of the current estimated useful life or change in classification as held for use could have a material adverse impact on our results of operations. The timing of a change in estimated useful life may be dependent upon events out of our control. The costs associated with a retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs and environmental remediation costs, could be material and we have no assurance of recovery of these costs from customers.

As part of the settlement of litigation brought by the Sierra Club and the Montana Environmental Information Center against the owners and operator of Colstrip, the owners of Units 1 and 2 agreed to shut down these units no later than July 2022. We do not have ownership in Units 1 and 2, and decisions regarding these units, including their shut down, were made by

23



their respective owners. However, the six owners of Colstrip currently share the operating costs pursuant to the terms of an operating agreement among the owners of Units 3 and 4 and a common facilities agreement among the owners of all four units. When Units 1 and 2 discontinue operation, we anticipate incurring incremental operating costs with respect to our interest in Unit 4 and expect to experience a negative impact on our transmission revenue due to less energy available to transmit across our transmission lines. This reduction would be incorporated in our next general electric rate filing after the closure of Units 1 and 2, resulting in lower revenue credits to certain customers. In addition, the remaining life on our investment in Colstrip Unit 4 is through 2042. Recovery of costs associated with the shut-down of the facility prior to the end of the useful life would be subject to MPSC approval.


Colstrip Units 3 and 4 are supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through 2019. These contracts are necessary for the long-term operation of the facility. Negotiation of a new coal supply contract anticipates environmental reviews and permitting, and we cannot predict when or if those permits will be granted. If a new coal supply contract is not in place, we could continue under the current arrangement for several years if the mining company agrees, however the extraction costs would increase.

We also rely on a limited number of suppliers of coal for our electric generation, making us vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity and operational issues and/or increased prices for coal transportation from a sole supplier.

We must meet certain credit quality standards. If we are unable to maintain investment grade credit ratings, our liquidity, access to capital and operations could be materially adversely affected.

A downgrade of our credit ratings to less than investment grade could adversely affect our liquidity. Certain of our credit agreements and other credit arrangements with counterparties require us to provide collateral in the form of letters of credit or cash to support our obligations if we fall below investment grade. Also, a downgrade below investment grade could hinder our ability to raise capital on favorable terms, including through the commercial paper markets. Higher interest rates on short-term borrowings with variable interest rates or on incremental commercial paper issuances could also have an adverse effect on our results of operations.

Our plans for future expansion through the acquisition of assets including natural gas reserves, capital improvements to current assets, generation investments, and transmission grid expansion involve substantial risks.

Acquisitions include a number of risks, including but not limited to, regulatory approval, additional costs, the assumption of material liabilities, the diversion of management’s attention from daily operations to the integration of the acquisition, difficulties in assimilation and retention of employees, and securing adequate capital to support the transaction. The regulatory process in which rates are determined may not result in rates that produce full recovery of our investments, or a reasonable rate of return. Uncertainties also exist in assessing the value, risks, profitability, and liabilities associated with certain businesses or assets and there is a possibility that anticipated operating and financial synergies expected to result from an acquisition do not develop. The failure to successfully integrate future acquisitions that we may choose to undertake could have an adverse effect on our financial condition and results of operations.

Our business strategy also includes significant investment in capital improvements and additions to modernize existing infrastructure, generation investments and transmission capacity expansion. The completion of generation and natural gas investments and transmission projects are subject to many construction and development risks, including, but not limited to, risks related to permitting, financing, regulatory recovery, escalating costs of materials and labor, meeting construction budgets and schedules, and environmental compliance. In addition, these capital projects may require a significant amount of capital expenditures. We cannot provide certainty that adequate external financing will be available to support such projects. Additionally, borrowings incurred to finance construction may adversely impact our leverage, which could increase our cost of capital.

Poor investment performance of plan assets of our defined benefit pension and post-retirement benefit plans, in addition to other factors impacting these costs, could unfavorably impact our results of operations and liquidity.

Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors. Assumptions related to future costs, return on investments and interest rates have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock

24



market performance and changes in governmental regulations. Without sustained growth in the plan assets over time and depending upon interest rate changes as well as other factors noted above, the costs of such plans reflected in our results of operations and financial position and cash funding obligations may change significantly from projections.

Our obligation to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWH could expose us to material commodity price risk if certain QFs under contract with us do not perform during a time of high commodity prices, as we are required to make up the difference. In addition, we are subject to price escalation risk with one of our largest QF contracts.

As part of a stipulation in 2002 with the MPSC and other parties, we agreed to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWH through June 2029. The annual minimum energy requirement is achievable under normal QF operations, including normal periods of planned and forced outages. However, to the extent the supplied QF power for any year does not reach the minimum quantity set forth in the settlement, we are obligated to purchase the difference from other sources. The anticipated source for any QF shortfall is the wholesale market, which would subject us to commodity price risk if the cost of replacement power is higher than contracted QF rates.

In addition, we are subject to price escalation risk with one of our largest QF contracts due to variable contract terms. In estimating our QF liability, we have estimated an annual escalation rate of three percent over the remaining term of the contract (through June 2024). To the extent the annual escalation rate exceeds three percent, our results of operations, cash flows and financial position could be adversely affected.


ITEM 1B.  UNRESOLVED STAFF COMMENTS

None

ITEM 2.  PROPERTIES

Our corporate support office is owned by us and located at 3010 West 69th Street, Sioux Falls, South Dakota 57108. Our operational support office for our Montana operations is owned by us and located at 11 East Park Street, Butte, Montana 59701. In addition, our operational support office for our South Dakota and Nebraska operations is owned by us and located at 600 Market Street West, Huron, South Dakota 57350. While we do lease some facilities, substantially all of our Montana, South Dakota and Nebraska facilities are owned by us.

Substantially all of our Montana electric and natural gas assets are subject to the lien of our Montana First Mortgage Bond indenture. Substantially all of our South Dakota and Nebraska electric and natural gas assets are subject to the lien of our South Dakota Mortgage Bond indenture. For further information regarding our operating properties, including generation and transmission, see the descriptions included in Item 1.

ITEM 3.  LEGAL PROCEEDINGS

We discuss details of our legal proceedings in Note 18 - Commitments and Contingencies, to the Consolidated Financial Statements. Some of this information is about costs or potential costs that may be material to our financial results.



25



Part II



ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock, which is traded under the ticker symbol NWE, is listed on the New York Stock Exchange (NYSE). As of February 9, 2018, there were approximately 1,020 common stockholders of record.

Dividends

We pay dividends on our common stock after our Board declares them. The Board reviews the dividend quarterly and establishes the dividend rate based upon such factors as our earnings, financial condition, capital requirements, debt covenant requirements and/or other relevant conditions. Although we expect to continue to declare and pay cash dividends with a targeted long-term dividend payout ratio of 60 - 70 percent of earnings per share, we cannot assure that dividends will be paid in the future or that, if paid, the dividends will be paid in the same amount as during 2017. Quarterly dividends were declared and paid on our common stock during 2017 and 2016 as set forth in the table below.

QUARTERLY COMMON STOCK PRICE RANGES AND DIVIDENDS

 
Prices
 
 
 
High
 
Low
 
Cash Dividends Paid
2017-
 
 
 
 
 
Fourth Quarter
$64.47
 
$56.44
 
$0.525
Third Quarter
61.80
 
56.87
 
0.525
Second Quarter
63.86
 
58.16
 
0.525
First Quarter
59.41
 
55.65
 
0.525
2016-
 
 
 
 
 
Fourth Quarter
$59.13
 
$53.85
 
$0.50
Third Quarter
63.75
 
56.18
 
0.50
Second Quarter
63.30
 
55.34
 
0.50
First Quarter
62.22
 
52.16
 
0.50

On February 9, 2018, the last reported sale price on the NYSE for our common stock was $52.13.




26




ITEM 6.  SELECTED FINANCIAL DATA

The following selected financial data has been derived from our Consolidated Financial Statements and should be read in conjunction with the Consolidated Financial Statements and notes thereto and with “Management's Discussion and Analysis of Financial Condition and Results of Operations" and other financial data included elsewhere in this report. The historical results are not necessarily indicative of results to be expected for any future period.

FIVE-YEAR FINANCIAL SUMMARY

 
Year Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
Financial Results (in thousands, except per share data)
 
 
 
 
 
 
 
 
 
Operating revenues
$
1,305,652

 
$
1,257,247

 
$
1,214,299

 
$
1,204,863

 
$
1,154,519

Net income
162,703

 
164,172

 
151,209

 
120,686

 
93,983

Basic earnings per share
$3.35
 
$3.40
 
$3.20
 
$3.01
 
$2.46
Diluted earnings per share
3.34
 
3.39
 
3.17
 
2.99
 
2.46
Dividends declared per common share
2.10
 
2.00
 
1.92
 
1.60
 
1.52
Financial Position
 
 
 
 
 
 
 
 
 
Total assets
$
5,420,917

 
$
5,499,321

 
$
5,264,695

 
$
4,960,902

 
$
3,701,645

Total debt, including capital leases and short-term borrowings
2,137,318

 
2,120,474

 
2,026,219

 
1,946,790

 
1,313,989

Ratio of earnings to fixed charges
2.8
 
2.6
 
2.9
 
2.3
 
2.5



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ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with “Item 6 Selected Financial Data" and our Consolidated Financial Statements and related notes contained elsewhere in this Annual Report on Form 10-K. For additional information related to our segments, see Note 19 - Segment and Related Information, to the Consolidated Financial Statements, which is included in Item 8 herein. For information regarding our revenues, net income and assets, see our Consolidated Financial Statements included in Item 8.

OVERVIEW

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 718,300 customers in Montana, South Dakota and Nebraska. As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2017, 2016 and 2015. Following is a brief overview of significant developments for 2017, and a discussion of our strategy.

SIGNIFICANT DEVELOPMENTS IN 2017
 
Ÿ
Operating income increased approximately $15.5 million due to an improvement in gross margin driven by favorable weather, and to a lesser extent, by customer growth, offset in part by an increase in property and other taxes.
 
 
 
 
 
 
 
Ÿ
Favorable operating income was offset by the inclusion in our 2016 results of a $17.0 million tax benefit as part of a tax accounting change related to costs to repair generation property, resulting in a $1.5 million decrease in net income.
 
 
 
 
 
 
Ÿ
Successfully accessed the capital markets:
 
 
 
 
 
 
 
Ÿ
Received proceeds of approximately $53.7 million after commissions and other fees from the sale of 888,938 common shares under our Equity Distribution Agreement; and
 
 
 
 
 
 
 
Ÿ
Refinanced $250 million of Montana First Mortgage Bonds, reducing the fixed interest rate from 6.34% to 4.03% and extending the maturity from 2019 to 2047.
 

 
HOW WE PERFORMED AGAINST OUR 2016 RESULTS
 
Year-over-Year Change
 
 
 
 
Gross Margin by Segment(1)
 
 
 
Electric
$24.3M
é
3.6
 %
Natural Gas
$14.8M
é
8.3
 %
 
 
 
 
 
 
 
 
Operating Income
$15.5M
é
6.3
 %
 
 
 
 
 
 
 
 
Net Income
$(1.5)M
ê

(0.9
)%
 
 
 
 
 
 
 
 
EPS (Basic)
$(0.05)
ê
(1.5
)%
___________________________

(1) Non-GAAP financial measure. See "non-GAAP Financial Measure" under Results of Operations below.


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SIGNIFICANT TRENDS AND REGULATION

Tax Cuts and Jobs Act

On December 22, 2017, H.R.1 (the Tax Cuts and Jobs Act) was signed into law, which enacts significant changes to U.S. tax and related laws. The primary impact to us is a reduction of the federal corporate income tax rate from 35% to 21% effective January 1, 2018. We revalued our net deferred tax liability as of December 31, 2017 based on the reduction in the overall future tax impact expected to be realized at the lower tax rate. This resulted in a reduction in our net deferred tax liability of approximately $321 million, which was offset in regulatory assets and liabilities.

Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits. The lower statutory tax rate will reduce the impact of these deductions. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.

The revaluation of deferred income taxes reflects our estimate of the impact of the Tax Cuts and Jobs Act. We will continue to evaluate subsequent regulations and interpretations and assumptions made, which could materially change our estimate.

We expect to provide a customer benefit as a result of the Tax Cuts and Jobs Act in each of our jurisdictions. The MPSC and SDPUC initiated dockets regarding the impact and we expect to submit filings in Montana and South Dakota during the first quarter of 2018 with a proposal to address the effects of the lower statutory rate. As the net impact of the lower statutory rate is expected to be passed through to customers, we do not expect the Tax Cuts and Jobs Act to impact our results of operations in 2018. However, we expect a consolidated reduction in our cash flows from operations ranging from $15 million to $20 million in 2018, as a result of the reduction in revenues from customers while we are not a cash taxpayer. We currently estimate that our effective income tax rate will range from 0% to 5% in 2018.

Montana QF Tariff Filing

Under the Public Utility Regulatory Policies Act (PURPA), electric utilities are required, with exceptions, to purchase energy and capacity from independent power producers that are QFs. In May 2016, we filed an application for approval of a revised tariff for standard rates for small QFs (3 MW or less). In November 2017, the MPSC issued an order revising the QF tariff to establish a maximum contract length of 15 years and substantially lowering the rate for future QF contracts. In this order, the MPSC also upheld an initial decision to apply the contract term to our future owned and contracted electric supply resources.

As a result of this order, we terminated our competitive solicitation process for 20-year resources to determine the lowest-cost / least-risk approach for addressing our intermittent capacity and reserve margin needs in Montana. We continue to evaluate the impact of this decision, as we have significant generation capacity deficits and negative reserve margins, and our 2016 resource plan identified price and reliability risks to our customers if we rely solely upon market purchases to address these capacity needs. In addition to our responsibility to meet peak demand, national reliability standards effective July 2016 require us to have even greater dispatchable generation capacity available and be capable of increasing or decreasing output to address the irregular nature of intermittent generation such as wind or solar. We expect to file our next electric supply resource procurement plan in late 2018.

Cost Recovery Mechanisms

Montana House Bill 193 / Electric Tracker - In April 2017, the Montana legislature passed House Bill 193 (HB 193), amending the statute that provided for mandatory recovery of our prudently incurred electric supply costs effective July 1, 2017. The revised statute gives the MPSC discretion whether to approve an electric supply cost adjustment mechanism. The MPSC initiated a process to develop a replacement electric supply cost adjustment mechanism, and in response, in July 2017, we filed a proposed electric PCCAM. Intervenor testimony was filed in November 2017, and in December 2017, the MPSC issued a Notice of Additional Issues stating that the range of options proposed by the parties was not sufficient and directing parties to consider alternatives incorporating risk-sharing features of other utilities in the region.


29



Our July 2017 PCCAM filing is consistent with our understanding of the MPSC's advocacy for HB 193, which referenced the Montana-Dakota Utilities (MDU) adjustment mechanism used in Montana that allows for recovery of 90 percent of the increases or decreases in fuel and purchased energy costs from an established baseline. However, we cannot guarantee how the MPSC may apply the statute in establishing a revised mechanism for us. We filed rebuttal testimony in February 2018, responsive to intervenor testimony and the MPSC's December 2017 Notice of Additional Issues, addressing alternative risk-sharing mechanisms. A hearing is scheduled to begin May 31, 2018. If the MPSC approves a new mechanism, the MPSC may apply the mechanism to variable costs on a retroactive basis to the effective date of HB 193 (July 1, 2017).

FERC Filing - Dave Gates Generating Station at Mill Creek (DGGS)

In May 2016, we received an order from the FERC denying a May 2014 request for rehearing and requiring us to make refunds. The request for rehearing challenged a September 2012 FERC Administrative Law Judge's (ALJ) initial decision regarding cost allocation of DGGS between retail and wholesale customers. The 2012 decision concluded that only a portion of these costs should be allocated to FERC jurisdictional customers. We had cumulative deferred revenue of approximately $27.3 million, consistent with the ALJ's initial decision, which was refunded to wholesale and choice customers in June 2016 in accordance with the FERC order.

In June 2016, we filed a petition for review of the FERC's May 2016 order with the United States Circuit Court of Appeals for the District of Columbia Circuit (D.C. Circuit). A hearing was held on December 1, 2017. We expect a decision in this matter by the end of the second quarter of 2018.
STRATEGY

We operate a fully regulated electric and natural gas utility. We seek to deliver value to our customers by providing high reliability and customer service, an environmentally sustainable generation mix and a typical residential customer bill that is below the national average benchmark. We are focused on delivering long-term shareholder value by continuing to invest in our system including:

Infrastructure investment focused on a stronger and smarter grid to improve the customer experience, while enhancing grid reliability and safety. This includes automation in distribution and substations that enables the use of changing technology.

Integrating supply resources that balance reliability, cost, capacity, and environmental considerations with more predictable long-term commodity prices. Resource planning is an important function necessary to meet our future energy and reserve margin needs. Based on our current analysis, we are considering electric supply capacity investments and expect to continue to pursue opportunities to add to our natural gas reserves portfolio.

We continually look for ways to increase our operating efficiency. Financial discipline is essential to earning our authorized return on invested capital and maintaining a strong balance sheet, stable cash flows, and quality credit ratings.

We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects. See the “Capital Requirements" discussion below for further detail on planned capital expenditures.

Rate cases are necessary to recover the cost of providing safe, reliable service, while contributing to earnings growth and achieving our financial objectives. We typically evaluate the need for electric and natural gas rate changes annually. We plan to file a Montana electric general rate case in 2018, based on a 2017 test year, and expect to complete the evaluation of the need for a rate case for our remaining jurisdictions during the first quarter of 2018.


30



INVESTMENT

Our estimated capital expenditures for the next five years, including our electric and natural gas transmission and distribution infrastructure investment plan, are as follows (in millions):
                

    regulatedutility5tear.jpg

Supply Investments

Our resource plans identify portfolio resource requirements including potential investments. Since 2010, we have acquired gas production and gathering system assets as a part of an overall strategy to provide rate stability and customer value through the addition of regulated assets that are not subject to market forces. As of December 31, 2017, these owned reserves totaled approximately 55.9 Bcf and are estimated to provide approximately 4.5 Bcf in 2018, or about 22 percent of our expected annual retail natural gas load in Montana. We continue to pursue opportunities to secure low cost gas reserves for our customers, with a target of owning 50% of our supply. Our estimated capital expenditure requirements above do not include estimates for incremental natural gas reserve acquisitions, potential peaking generation needs or other investment opportunities that may arise.

As discussed above, due to the MPSC's decision regarding maximum contract length in the QF tariff docket, we terminated our competitive solicitation process to determine the lowest-cost / least-risk approach for addressing our intermittent capacity and reserve margin needs in Montana. We expect to file an electric supply resource procurement plan in Montana in late 2018 and are evaluating our options to address our significant generation capacity deficits and negative reserve margins.

Distribution and Transmission System Investment

As part of our commitment to maintain high level reliability and system performance we continue to evaluate the condition of our distribution and transmission assets to address aging infrastructure through our asset management process. The primary goals of our infrastructure investment are to reverse the trend in aging infrastructure, maintain reliability, proactively manage safety, build capacity into the system, and prepare our network for the adoption of new technologies. We are working on various solutions taking a proactive and pragmatic approach to replace these assets while also evaluating the implementation of additional technologies to prepare the overall system for smart grid applications.




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RESULTS OF OPERATIONS

Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of gross margin by segment.

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Gross Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross Margin (Revenues less Cost of Sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of Gross Margin is intended to supplement investors’ understanding of our operating performance. Gross Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating costs. Our Gross Margin measure may not be comparable to other companies’ Gross Margin measures. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

Factors Affecting Results of Operations

Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.

Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.

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OVERALL CONSOLIDATED RESULTS

Year Ended December 31, 2017 Compared with Year Ended December 31, 2016

 
Year Ended December 31,
 
2017
 
2016
 
Change
 
% Change
 
(in millions)
Operating Revenues
 
 
 
 
 
 
 
Electric
$
1,037.1

 
$
1,011.6

 
$
25.5

 
2.5
%
Natural Gas
268.6

 
245.7

 
22.9

 
9.3

 
$
1,305.7

 
$
1,257.3

 
$
48.4

 
3.8
%

 
Year Ended December 31,
 
2017
 
2016
 
Change
 
% Change
 
(in millions)
Cost of Sales
 
 
 
 
 
 
 
Electric
$
334.0

 
$
332.8

 
$
1.2

 
0.4
%
Natural Gas
76.3

 
68.2

 
8.1

 
11.9

 
$
410.3

 
$
401.0

 
$
9.3

 
2.3
%

 
Year Ended December 31,
 
2017
 
2016
 
Change
 
% Change
 
(in millions)
Gross Margin
 
 
 
 
 
 
 
Electric
$
703.1

 
$
678.8

 
$
24.3

 
3.6
%
Natural Gas
192.3

 
177.5

 
14.8

 
8.3

 
$
895.4

 
$
856.3

 
$
39.1

 
4.6
%

Consolidated gross margin in 2017 was $895.4 million, an increase of $39.1 million, or 4.6%, from gross margin in 2016. Factors that impacted gross margin included:


33



 
Gross Margin 2017 vs. 2016
 
(in millions)
Gross Margin Items Impacting Net Income
 
Electric retail volumes
$
15.7

Natural gas retail volumes
10.5

2016 MPSC disallowance
9.5

Montana natural gas rates
1.8

2016 Hydro generation rates
1.5

South Dakota electric rate increase
1.2

Electric transmission
0.6

Electric QF adjustment
0.4

2016 Lost revenue adjustment mechanism
(14.2
)
Other
3.9

Consolidated Gross Margin Impacting Net Income
30.9

 
 
Gross Margin Items Offset in Operating Expenses and Income Tax Expense
 
Property taxes recovered in trackers
6.7

Operating expenses recovered in trackers
1.5

Change in Items Offset Within Net Income
8.2

Increase in Consolidated Gross Margin
$
39.1


Consolidated gross margin for items impacting net income increased $30.9 million primarily due to the following:

An increase in electric retail volumes due primarily to colder winter and warmer summer weather in our Montana jurisdiction and customer growth, partly offset by cooler summer weather in our South Dakota jurisdiction and milder spring weather overall;
An increase in natural gas retail volumes due primarily to colder winter and spring weather and customer growth, partly offset by warmer summer weather;
The inclusion in our 2016 results of the MPSC disallowance of both replacement power costs from a 2013 outage at Colstrip Unit 4 and portfolio modeling costs;
An increase in our Montana gas rates effective September 1, 2017;
The inclusion in our 2016 results of a reduction in hydro generation rates due to the MPSC order in the hydro compliance filing;
An increase in South Dakota electric rates due to the timing of the change in customer rates in 2016;
Higher demand to transmit energy across our transmission lines due to market conditions and pricing; and
A decrease in QF related supply costs based on actual QF pricing and output.

These increases were partly offset by the inclusion in our 2016 results of $14.2 million of deferred revenue as a result of a MPSC final order in our tracker filings regarding prior period lost revenues.

The change in consolidated gross margin also includes the following items that had no impact on net income:

An increase in revenues for property taxes included in trackers is offset by increased property tax expense; and
An increase in operating expenses included in our supply trackers is offset by an increase in operating, general and administrative expenses.



34



 
Year Ended December 31,
 
2017
 
2016
 
Change
 
% Change
 
(in millions)
Operating Expenses (excluding cost of sales)
 
 
 
 
 
 
 
Operating, general and administrative
$
305.1

 
$
302.9

 
$
2.2

 
0.7
%
Property and other taxes
162.6

 
148.1

 
14.5

 
9.8

Depreciation and depletion
166.1

 
159.3

 
6.8

 
4.3

 
$
633.8

 
$
610.3

 
$
23.5

 
3.9
%

Consolidated operating, general and administrative expenses were $305.1 million in 2017 as compared with $302.9 million in 2016. Primary components of this change include the following:
 
Operating, General, & Administrative
Expenses 2017 vs. 2016
 
(in millions)
Bad debt expense
$
1.9

Operating expenses recovered in trackers
1.5

Maintenance costs
1.2

Employee benefits and compensation costs
(1.5
)
Insurance reserves
(1.0
)
Other
0.1

Increase in Operating, General & Administrative Expenses
$
2.2


The increase in operating, general and administrative expenses of $2.2 million was primarily due to the following:

Higher bad debt expense due to an increase in revenues as a result of colder winter and warmer summer weather;
Higher operating expenses recovered through our supply trackers; and
Higher maintenance costs at our Dave Gates Generating Station and Colstrip Unit 4.

These increases were offset in part by:

A decrease in employee benefits due primarily to lower pension costs, offset in part by higher medical costs and more time spent by employees on maintenance projects (which are expensed) rather than capital projects; and
A decrease in insurance reserves primarily due to the amount recorded in 2016 related to the Billings, Montana refinery outage.

Property and other taxes were $162.6 million in 2017 as compared with $148.1 million in 2016. This increase was primarily due to plant additions and higher estimated property valuations in Montana. Under Montana law, we are allowed to track the increases in the actual level of state and local taxes and fees and adjust our rates to recover the increase between rate cases less the amount allocated to FERC-jurisdictional customers and net of the associated income tax benefit. In January 2018, the MPSC issued an order in our 2017 filing reducing our recovery of these taxes by approximately $1.7 million by applying an alternate allocation methodology. This results in a lower allocation to our Montana electric retail customers and a higher property tax allocation to FERC transmission customers (we do not have a property tax tracker for FERC jurisdictional purposes).

Depreciation and depletion expense was $166.1 million in 2017 as compared with $159.3 million in 2016. This increase was primarily due to plant additions.

Consolidated operating income in 2017 was $261.4 million, as compared with $245.9 million in 2016. This increase was primarily due to the increase in gross margin as discussed above, offset in part by higher operating expenses.

Consolidated interest expense in 2017 was $92.3 million, as compared with $95.0 million, in 2016. This decrease was primarily due to the refinancing of debt in 2016. See "Liquidity and Capital Resources" for additional information regarding our financing activities. We expect interest expense to decrease by approximately $2 million in 2018 as a result of these refinancing transactions offset by rising interest rates.

35




Consolidated other income in 2017 was $6.9 million as compared with $5.5 million in 2016. This increase was primarily due to higher capitalization of AFUDC.

Consolidated income tax expense in 2017 was $13.4 million as compared with an income tax benefit of $7.6 million in 2016. Our effective tax rate for the twelve months ended December 31, 2017 was 7.6% as compared with (4.9)% for the same period of 2016. During the twelve months ended December 31, 2016, we recorded an income tax benefit of approximately $17.0 million due to the adoption of a tax accounting method change related to the costs to repair generation assets, which allowed us to take a current tax deduction for a significant amount of repair costs that were previously capitalized for tax purposes. Approximately $12.5 million of this deduction related to 2015 and prior tax years. This is reflected in the flow-through repairs deductions line due to the regulatory treatment.

Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits. The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
 
Year Ended December 31,
 
2017
 
2016
Income Before Income Taxes
$176.1
 
 
 
$156.5
 
 
 
 
 
 
 
 
 
 
Income tax calculated at 35% Federal statutory rate
61.6
 
35.0%
 
54.8
 
35.0%
 
 
 
 
 
 
 
 
Permanent or flow through adjustments:
 
 
 
 
 
 
 
State income tax, net of federal provisions
(3.3)
 
(1.9)
 
(3.7)
 
(2.4)
Flow through repairs deductions
(30.5)
 
(17.3)
 
(41.1)
 
(26.3)
Production tax credits
(11.0)
 
(6.3)
 
(10.9)
 
(7.0)
Plant and depreciation of flow through items
(2.2)
 
(1.3)
 
(4.6)
 
(2.9)
Share based compensation
(0.4)
 
(0.2)
 
(1.6)
 
(1.1)
Prior year permanent return to accrual adjustments
(0.6)
 
(0.3)
 
(0.1)
 
(0.1)
Other, net
(0.2)
 
(0.1)
 
(0.4)
 
(0.1)
 
(48.2)
 
(27.4)
 
(62.4)
 
(39.9)
 
 
 
 
 
 
 
 
Income Tax Expense (Benefit)
$13.4
 
7.6%
 
$(7.6)
 
(4.9)%
 
Consolidated net income in 2017 was $162.7 million as compared with $164.2 million in 2016. This decrease was primarily due to the inclusion in our 2016 results of a $17.0 million income tax benefit due to the adoption of a tax accounting method change related to the costs to repair generation assets, and higher operating expenses as discussed above, offset in part by improved gross margin as a result of favorable weather, and to a lesser extent, by customer growth.


36



Year Ended December 31, 2016 Compared with Year Ended December 31, 2015

 
Year Ended December 31,
 
2016
 
2015
 
Change
 
% Change
 
(in millions)
Operating Revenues
 
 
 
 
 
 
 
Electric
$
1,011.6

 
$
944.4

 
$
67.2

 
7.1
 %
Natural Gas
245.7

 
269.9

 
(24.2
)
 
(9.0
)
 
$
1,257.3

 
$
1,214.3

 
$
43.0

 
3.5
 %
 
Year Ended December 31,
 
2016
 
2015
 
Change
 
% Change
 
(in millions)
Cost of Sales
 
 
 
 
 
 
 
Electric
$
332.8

 
$
281.3

 
$
51.5

 
18.3
 %
Natural Gas
68.2

 
91.6

 
(23.4
)
 
(25.5
)
 
$
401.0

 
$
372.9

 
$
28.1

 
7.5
 %
 
Year Ended December 31,
 
2016
 
2015
 
Change
 
% Change
 
(in millions)
Gross Margin
 
 
 
 
 
 
 
Electric
$
678.8

 
$
663.1

 
$
15.7

 
2.4
 %
Natural Gas
177.5

 
178.3

 
(0.8
)
 
(0.4
)
 
$
856.3

 
$
841.4

 
$
14.9

 
1.8
 %

Consolidated gross margin in 2016 was $856.3 million, an increase of $14.9 million, or 1.8%, from gross margin in 2015. Factors that impacted gross margin included:
 
Gross Margin 2016 vs. 2015
 
(in millions)
Gross Margin Items Impacting Net Income
 
South Dakota electric rate increase
$
33.5

Lost revenue adjustment mechanism
7.7

Electric QF adjustment
6.1

Natural gas retail volumes
0.2

MPSC disallowance
(9.5
)
Electric transmission
(3.6
)
Electric retail volumes
(2.0
)
Hydro generation rates
(1.5
)
Natural gas production rates
(1.2
)
Other
(1.5
)
Consolidated Gross Margin Impacting Net Income
28.2

 
 
Gross Margin Items Offset in Operating Expenses and Income Tax Expense
 
Hydro operations - Kerr conveyance
(16.5
)
Production tax credits flowed-through trackers
(8.2
)
Natural gas production gathering fees
(1.1
)
Property taxes recovered in trackers
12.5

Change in Items Offset Within Net Income
(13.3
)
Increase in Consolidated Gross Margin
$
14.9


37




Consolidated gross margin for items impacting net income increased $28.2 million primarily due to the following:

An increase in South Dakota electric rates;
The recognition of $14.2 million of deferred revenue as a result of a MPSC final order in our tracker filings, offset in part by the elimination of the lost revenue adjustment mechanism decreasing the recovery of our fixed costs by approximately $6.5 million;
The inclusion in our 2015 results of an increase in supply costs due to the adjustment of the QF liability based on a review of contract assumptions; and
An increase in our Montana jurisdiction residential and commercial natural gas volumes due to colder late summer and winter weather, and customer growth, offset by warmer winter weather in our South Dakota jurisdiction.

These increases were partly offset by:

An MPSC disallowance of previously incurred replacement power and modeling / planning costs;
Lower demand to transmit energy across our transmission lines due to market conditions and pricing;
A decrease in electric retail volumes due primarily to colder late summer weather in our Montana jurisdiction, along with lower industrial volumes of a large Montana customer, partly offset by warmer spring and summer weather in our South Dakota jurisdiction and customer growth;
A reduction in hydro generation rates due to the MPSC order in the hydro compliance filing; and
A decrease in natural gas production margin due to an $0.8 million decrease in overhead fees and a $0.4 million decrease in interim rates based on actual costs.

The change in consolidated gross margin also includes the following items that had no impact on net income:

A decrease in revenues from the conveyance of the Kerr facility to the Confederated Salish and Kootenai Tribes (CSKT) in September 2015 (offset by reduced operating expenses);
A decrease in revenues for production tax credits primarily associated with the Beethoven wind generation project, which is a reduction in our customers rates (offset by reduced income tax expense);
A decrease in natural gas production gathering fees (offset by reduced operating expenses); and
An increase in revenues for property taxes included in trackers (offset by increased property tax expense).

 
Year Ended December 31,
 
2016
 
2015
 
Change
 
% Change
 
(in millions)
Operating Expenses (excluding cost of sales)
 
 
 
 
 
 
 
Operating, general and administrative
$
302.9

 
$
297.5

 
$
5.4

 
1.8
%
Property and other taxes
148.1

 
133.4

 
14.7

 
11.0

Depreciation and depletion
159.3

 
144.7

 
14.6

 
10.1

 
$
610.3

 
$
575.6

 
$
34.7

 
6.0
%

Consolidated operating, general and administrative expenses were $302.9 million in 2016 as compared with $297.5 million in 2015. Primary components of this change include the following:

38



 
Operating, General, & Administrative
Expenses 2016 vs. 2015
 
(in millions)
Insurance recovery, net
$
20.8

Employee benefit and compensation costs
2.7

Plant operator costs
2.2

Non-employee directors deferred compensation
1.5

Insurance reserves
0.9

Hydro operations - Kerr conveyance
(15.2
)
DSIP expenses
(4.0
)
Natural gas production gathering expense
(1.1
)
Bad debt expense
(1.0
)
Other
(1.4
)
Increase in Operating, General & Administrative Expenses
$
5.4


The increase in operating, general and administrative expenses of $5.4 million was primarily due to the following:

The inclusion in our second quarter 2015 results of an insurance recovery, primarily associated with electric generation related environmental remediation costs incurred in prior periods;
An increase in employee related benefits costs due to higher compensation and pension costs;
Higher plant operator costs primarily due to the Beethoven acquisition in September 2015;
The change in value of non-employee directors deferred compensation due to changes in our stock price (offset by changes in other income with no impact on net income); and
An increase in insurance reserves primarily due to the Billings, Montana refinery outage discussed in Note 18 to the Consolidated Financial Statements.

These increases were offset in part by:

A decrease in hydro operations costs in the current period as a result of the conveyance of Kerr to the CSKT in September 2015 (offset by reduced revenue discussed above);
Lower DSIP related expenses;
A decrease in natural gas production gathering expense (offset by lower gathering fees discussed above); and
Lower bad debt expense, due to improved collection of receivables from customers.

In addition, cost control measures implemented in 2016 are included in the Other line item above.

Property and other taxes were $148.1 million in 2016 as compared with $133.4 million in 2015. This increase was primarily due to plant additions and higher estimated property valuations in Montana, offset in part by a $1.3 million decrease from the conveyance of Kerr to the CSKT in September 2015.

Depreciation and depletion expense was $159.3 million in 2016 as compared with $144.7 million in 2015. This increase was primarily due to plant additions, including approximately $4.3 million of incremental depreciation associated with the September 2015 Beethoven wind project acquisition.

Consolidated operating income in 2016 was $245.9 million, as compared with $265.8 million in 2015. This decrease was primarily due to the $20.8 million insurance recovery in 2015.

Consolidated interest expense in 2016 was $95.0 million, as compared with $92.2 million, in 2015. This increase was primarily due to $2.9 million of interest associated with the MPSC disallowance as discussed above, lower capitalization of AFUDC, and increased debt outstanding, partly offset by the debt refinancing transactions.

Consolidated other income in 2016 was $5.5 million as compared with $7.6 million in 2015. This decrease was primarily due to lower capitalization of AFUDC, partly offset by a $1.5 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation (which, as discussed above, is offset by a corresponding increase to operating, general and administrative expenses).


39



Consolidated income tax benefit in 2016 was $7.6 million as compared with income tax expense of $30.0 million in 2015. Our effective tax rate for the twelve months ended December 31, 2016 was (4.9)% as compared with 16.6% for the same period of 2015. During the third quarter of 2016, we filed a tax accounting method change with the Internal Revenue Service (IRS) related to costs to repair generation property, as discussed above. This resulted in an income tax benefit of approximately $17.0 million during the twelve months ended December 31, 2016, of which approximately $12.5 million related to 2015 and prior tax years and is reflected in the flow-through repairs deductions line below. In addition, we adopted the provisions of a new accounting standard related to share-based payments, during the fourth quarter of 2016. The excess tax benefit of share awards that vested in 2016 was treated as a discrete item.

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
 
Year Ended December 31,
 
2016
 
2015
Income Before Income Taxes
$
156.5

 
 
 
$
181.2

 
 
 
 
 
 
 
 
 
 
Income tax calculated at 35% Federal statutory rate
54.8

 
35.0
 %
 
63.4

 
35.0
 %
 
 
 
 
 
 
 
 
Permanent or flow through adjustments:
 
 
 
 
 
 
 
State income, net of federal provisions
(3.7
)
 
(2.4
)
 
0.3

 
0.1

Flow through repairs deductions
(41.1
)
 
(26.3
)
 
(24.1
)
 
(13.3
)
Production tax credits
(10.9
)
 
(7.0
)
 
(5.7
)
 
(3.2
)
Plant and depreciation of flow through items
(4.6
)
 
(2.9
)
 
(2.9
)
 
(1.6
)
Share based compensation
(1.6
)
 
(1.1
)
 

 

Prior year permanent return to accrual adjustments
(0.1
)
 
(0.1
)
 
0.2

 
0.1

Other, net
(0.4
)
 
(0.1
)
 
(1.2
)
 
(0.5
)
 
(62.4
)
 
(39.9
)
 
(33.4
)
 
(18.4
)
 
 
 
 
 
 
 
 
Income Tax (Benefit) Expense
$
(7.6
)
 
(4.9
)%
 
$
30.0

 
16.6
 %

Consolidated net income in 2016 was $164.2 million as compared with $151.2 million in 2015. This increase was primarily due to the tax benefit related to costs to repair generation property discussed above along with improved gross margin driven by an increase in South Dakota electric rates, partly offset by the inclusion in our 2015 results of a $20.8 million insurance recovery and higher property tax and depreciation expense in 2016.


40



ELECTRIC OPERATIONS

We have various classifications of electric revenues, defined as follows:

Retail: Sales of electricity to residential, commercial and industrial customers.
Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers.
Transmission: Reflects transmission revenues regulated by the FERC.
Ancillary Services: FERC jurisdictional services that ensure reliability and support the transmission of electricity from generation sites to customer loads. Such services include regulation services, reserves and voltage support.
Wholesale and other: Our South Dakota service territory is a market participant in the SPP, where we buy and sell wholesale energy and reserves through the operation of a single, consolidated balancing authority. This line also includes miscellaneous electric revenues.

Year Ended December 31, 2017 Compared with Year Ended December 31, 2016

 
Results
 
2017
 
2016
 
Change
 
% Change
 
(in millions)
Retail revenue
$
874.4

 
$
840.7

 
$
33.7

 
4.0
 %
Regulatory amortization
3.7

 
20.9

 
(17.2
)
 
(82.3
)
   Total retail revenues
878.1

 
861.6

 
16.5

 
1.9

Transmission
58.1

 
51.1

 
7.0

 
13.7

Ancillary services
1.6

 
1.6

 

 

Wholesale and other
99.3

 
97.3

 
2.0

 
2.1

Total Revenues
1,037.1

 
1,011.6

 
25.5

 
2.5

Total Cost of Sales
334.0

 
332.8

 
1.2

 
0.4
 %
Gross Margin
$
703.1

 
$
678.8

 
$
24.3

 
3.6
 %

 
Revenues
 
Megawatt Hours (MWH)
 
Avg. Customer Counts
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
 
 
 
 
Montana
$
299,725

 
$
280,379

 
2,540

 
2,372

 
295,427

 
291,348

South Dakota
60,246

 
57,369

 
546

 
548

 
50,247

 
50,016

   Residential 
359,971

 
337,748

 
3,086

 
2,920

 
345,674

 
341,364

Montana
348,139

 
343,982

 
3,235

 
3,177

 
66,484

 
65,568

South Dakota
91,969

 
87,199

 
992

 
985

 
12,669

 
12,591

Commercial
440,108

 
431,181

 
4,227

 
4,162

 
79,153

 
78,159

Industrial
42,194

 
40,577

 
2,324

 
2,204

 
75

 
74

Other
32,110

 
31,162

 
195

 
188

 
6,195

 
6,143

Total Retail Electric
$
874,383

 
$
840,668

 
9,832

 
9,474

 
431,097

 
425,740


 
Cooling Degree Days
 
2017 as compared with:
 
2017
 
2016
 
Historic Average
 
2016
 
Historic Average
Montana
524
 
367
 
420
 
43% warmer
 
25% warmer
South Dakota
729
 
895
 
733
 
19% colder
 
1% colder


41



 
Heating Degree Days
 
2017 as compared with:
 
2017
 
2016
 
Historic Average
 
2016
 
Historic Average
Montana
7,738
 
7,011
 
7,476
 
10% colder
 
4% colder
South Dakota
7,102
 
6,593
 
7,619
 
8% colder
 
7% warmer

The following summarizes the components of the changes in electric margin for the years ended December 31, 2017 and 2016:
 
Gross Margin 2017 vs. 2016
 
(in millions)
Gross Margin Items Impacting Net Income
 
Retail volumes
$
15.7

2016 MPSC disallowance
9.5

2016 Hydro generation rates
1.5

South Dakota rate increase
1.2

Transmission
0.6

QF adjustment
0.4

2016 Lost revenue adjustment mechanism
(13.4
)
Other
2.4

Consolidated Gross Margin Impacting Net Income
17.9

 
 
Gross Margin Items Offset in Operating Expenses and Income Tax Expense
 
Property taxes recovered in trackers
4.9

Operating expenses recovered in trackers
1.5

Change in Items Offset Within Net Income
6.4

Increase in Consolidated Gross Margin
$
24.3


Gross margin for items impacting net income increased $17.9 million including the following:

An increase in retail volumes due primarily to colder winter and warmer summer weather in our Montana jurisdiction and customer growth, partly offset by cooler summer weather in our South Dakota jurisdiction and milder spring weather overall;
The inclusion in our 2016 results of the MPSC disallowance of both replacement power costs from a 2013 outage at Colstrip Unit 4 and portfolio modeling costs;
The inclusion in our 2016 results of a reduction in hydro generation rates due to the MPSC order in the hydro compliance filing;
An increase in South Dakota electric rates due to the timing of the change in customer rates in 2016;
Higher demand to transmit energy across our transmission lines due to market conditions and pricing; and
A decrease in QF related supply costs based on actual QF pricing and output.

These increases were partly offset by the recognition in 2016 of $13.4 million of deferred revenue as a result of a MPSC final order in our tracker filings.

The change in consolidated gross margin also includes the following items that had no impact on net income:

The increase in revenues for property taxes included in trackers is offset by increased property tax expense; and
An increase in operating expenses included in our supply trackers is offset by an increase in operating, general and administrative expenses.

In addition, the change in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on gross margin. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.

Year Ended December 31, 2016 Compared with Year Ended December 31, 2015

42




 
Results
 
2016
 
2015
 
Change
 
% Change
 
(in millions)
Retail revenue
$
840.7

 
$
819.8

 
$
20.9

 
2.5
 %
Regulatory amortization
20.9

 
39.4

 
(18.5
)
 
(47.0
)
   Total retail revenues
861.6

 
859.2

 
2.4

 
0.3

Transmission
51.1

 
54.7

 
(3.6
)
 
(6.6
)
Ancillary services
1.6

 
1.5

 
0.1

 
6.7

Wholesale and other
97.3

 
29.0

 
68.3

 
235.5

Total Revenues
1,011.6

 
944.4

 
67.2

 
7.1

Total Cost of Sales
332.8

 
281.3

 
51.5

 
18.3
 %
Gross Margin
$
678.8

 
$
663.1

 
$
15.7

 
2.4
 %

 
Revenues
 
Megawatt Hours (MWH)
 
Avg. Customer Counts
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
 
 
 
 
Montana
$
280,379

 
$
275,971

 
2,372

 
2,359

 
291,348

 
287,387

South Dakota
57,369

 
49,469

 
548

 
551

 
50,016

 
49,807

   Residential 
337,748

 
325,440

 
2,920

 
2,910

 
341,364

 
337,194

Montana
343,982

 
344,743

 
3,177

 
3,207

 
65,568

 
64,711

South Dakota
87,199

 
75,442

 
985

 
974

 
12,591

 
12,473

Commercial
431,181

 
420,185

 
4,162

 
4,181

 
78,159

 
77,184

Industrial
40,577

 
43,838

 
2,204

 
2,260

 
74

 
75

Other
31,162

 
30,348

 
188

 
187

 
6,143

 
6,119

Total Retail Electric
$
840,668

 
$
819,811

 
$
9,474

 
$
9,538

 
$
425,740

 
$
420,572


 
Cooling Degree Days
 
2016 as compared with:
 
2016
 
2015
 
Historic Average
 
2015
 
Historic Average
Montana
367
 
440
 
433
 
17% colder
 
15% colder
South Dakota
895
 
792
 
733
 
13% warmer
 
22% warmer

 
Heating Degree Days
 
2016 as compared with:
 
2016
 
2015
 
Historic Average
 
2015
 
Historic Average
Montana
7,011
 
6,914
 
7,498
 
1% colder
 
6% warmer
South Dakota
6,593
 
6,924
 
7,674
 
5% warmer
 
14% warmer

The following summarizes the components of the changes in electric margin for the years ended December 31, 2016 and 2015:

43



 
Gross Margin 2016 vs. 2015
 
(in millions)
Gross Margin Items Impacting Net Income
 
South Dakota rate increase
$
33.5

Lost revenue adjustment mechanism
7.1

QF adjustment
6.1

MPSC disallowance
(9.5
)
Transmission
(3.6
)
Retail volumes
(2.0
)
Hydro generation rates
(1.5
)
Consolidated Gross Margin Impacting Net Income
30.1

 
 
Gross Margin Items Offset in Operating Expenses and Income Tax Expense
 
Hydro operations - Kerr conveyance
(16.5
)
Production tax credits flowed-through trackers
(8.2
)
Property taxes recovered in trackers
10.3

Change in Items Offset Within Net Income
(14.4
)
Increase in Consolidated Gross Margin
$
15.7


Gross margin for items impacting net income increased $30.1 million including the following:

An increase in South Dakota electric rates;
The recognition of $13.4 million of deferred revenue as a result of a MPSC final order in our tracker filings, offset in part by the elimination of the lost revenue adjustment mechanism decreasing the recovery of our fixed costs; and
The inclusion in our 2015 results of an increase in supply costs due to the adjustment of the QF liability based on a review of contract assumptions.

These increases were partly offset by:

The MPSC disallowance of previously incurred costs as discussed above;
Lower demand to transmit energy across our transmission lines due to market conditions and pricing;
A decrease in electric retail volumes due primarily to colder late summer weather in our Montana jurisdiction, along with lower industrial volumes of a large Montana customer, partly offset by warmer spring and summer weather in our South Dakota jurisdiction and customer growth; and
A reduction in hydro generation rates due to the MPSC order in the hydro compliance filing as discussed above;

The change in consolidated gross margin also includes the following items that had no impact on net income:

A decrease in revenues from the conveyance of the Kerr facility to the CSKT in September 2015 (offset by reduced operating expenses);
A decrease in revenues for production tax credits primarily associated with the Beethoven wind generation project, which is a reduction in our customers rates (offset by reduced income tax expense); and
An increase in revenues for property taxes included in trackers (offset by increased property tax expense).

In addition, the change in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on gross margin. Our wholesale and other revenues are largely gross margin neutral as they are offset by changes in cost of sales.






44



NATURAL GAS OPERATIONS

We have various classifications of natural gas revenues, defined as follows:
Retail: Sales of natural gas to residential, commercial and industrial customers.
Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in cost of sales and therefore has minimal impact on gross margin.
Wholesale: Primarily represents transportation and storage for others.

Year Ended December 31, 2017 Compared with Year Ended December 31, 2016

 
Results
 
2017
 
2016
 
Change
 
% Change
 
(in millions)
Retail revenue
$
233.8

 
$
201.8

 
$
32.0

 
15.9
 %
Regulatory amortization
(5.4
)
 
4.8

 
(10.2
)
 
(212.5
)
   Total retail revenues
228.4

 
206.6