Company Quick10K Filing
Quick10K
Northwestern
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$63.91 50 $3,220
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
8-K 2019-02-11 Officers, Exhibits
8-K 2019-02-11 Earnings, Regulation FD, Exhibits
8-K 2018-12-13 Officers, Exhibits
8-K 2018-12-04 Regulation FD, Exhibits
8-K 2018-11-09 Regulation FD, Exhibits
8-K 2018-10-24 Earnings, Regulation FD, Exhibits
8-K 2018-09-27 Regulation FD, Exhibits
8-K 2018-09-12 Regulation FD, Exhibits
8-K 2018-09-04 Regulation FD, Exhibits
8-K 2018-07-23 Regulation FD, Exhibits
8-K 2018-07-19 Earnings, Regulation FD, Exhibits
8-K 2018-05-18 Regulation FD, Exhibits
8-K 2018-04-25 Shareholder Vote
8-K 2018-03-21 Regulation FD, Exhibits
8-K 2018-02-15 Other Events, Exhibits
8-K 2018-02-12 Officers, Exhibits
EXC Exelon
PEG Public Service Enterprise Group
EVRG Evergy
CMS CMS Energy
PCG Pg&E
SCG Scana
GNE Genie Energy
VVPR VivoPower
ENJ Entergy New Orleans
ENO Enodis
NWE 2018-12-31
Part I
Item 1. Business
Item 1A. Risk Factors -
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedule
Item 16. Form 10-K Summary
EX-21 exhibit21subsidiaries10k20.htm
EX-23.1 exhibit231consent10k2018.htm
EX-31.1 exhibit311certification10k.htm
EX-31.2 exhibit312certification10k.htm
EX-32.1 exhibit321certification10k.htm
EX-32.2 exhibit322certification10k.htm

Northwestern Earnings 2018-12-31

NWE 10K Annual Report

Balance SheetIncome StatementCash Flow

10-K 1 nwe1231201810k.htm FORM 10-K 2018 Document


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, 2018

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
logoa12.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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for shorter period that the registrant was required to submit 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
 
 
 
 
 

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 $2,880,555,000 computed using the last sales price of $57.25 per share of the registrant’s common stock on June 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter.
 
As of February 8, 2019, 50,347,571 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 2019 Annual Meeting of Shareholders
are incorporated by reference into Part III of this Form 10-K






INDEX
 
PAGE
 
Part I
 
Mine Safety Disclosures
 
 
 
 
Part II
 
 
 
 
 
Part III
 
 
 
 
 
Part IV
 
Exhibits and Financial Statement Schedule
Form 10-K Summary
Index to Financial Statements and Financial Statement Schedule



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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 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.


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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).


4



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.


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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 726,400 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 manage our businesses by the nature of services provided, and operate principally in three business segments: electric utility operations; natural gas utility operations; and all other, which primarily consists of unallocated corporate costs. Our electric utility operations include the generation, purchase, transmission and distribution of electricity, and our natural gas utility operations include the production, purchase, transmission, storage, and distribution of natural gas. Our customer base consists of a mix of residential, commercial, and diversified industrial customers.

serviceterritorymap2018.jpg

NorthWestern Energy - Delivering a Bright Future        

We provide essential energy infrastructure and valuable services that enrich lives and empower communities while serving as long-term partners to our customers and communities. We are working to deliver safe, reliable, and innovative energy solutions that create value for customers, communities, employees, and investors. This includes bridging our history as a regulated utility safely providing low-cost and reliable service with our future as a globally-aware company offering a broader array of services performed by highly-adaptable and skilled employees.

Sustainability

We are focused on meeting current energy infrastructure and service needs at a reasonable and fair cost for today’s customers while ensuring the ability to meet the needs of tomorrow’s customers. “Sustainability” requires meeting economic, societal, and environmental objectives. As a provider of essential infrastructure and service, a sustainable enterprise is vital to

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our customers and communities, as well as to our investors and employees. For further information on our environmental, social, governance, and sustainability-related (ESG) efforts see our reports on Environmental Stewardship: Our Commitment in Action and our ESG reporting template available at www.northwesternenergy.com.

We strive to balance legal 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. We support cost-effective energy efficiency programs and low or carbon-free resources as part of our diverse supply portfolio. In 2018, approximately 55% of our retail needs originated from carbon-free resources.





            

a2018electricgeneration.jpg

8



ELECTRIC OPERATIONS

Our electric utility operations include the generation, purchase, transmission, and distribution of electricity. Our electric utility operations are not dependent on a single customer, or even a few customers, and the loss of any one or even a few of our largest customers is not reasonably likely to have a material adverse effect on our financial condition. Our electric utility operations are seasonal and weather patterns can have a material impact on operating performance. Consumption of electricity is often greater in the summer and winter months for cooling and heating, respectively.

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 2017 census estimated population of approximately 922,900. During 2018, we delivered electricity to approximately 374,000 customers in 208 communities and their surrounding rural areas, 11 rural electric cooperatives and, in Wyoming, to the Yellowstone National Park. In 2018, 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 1,843 MWs on August 10, 2018. Our control area average demand for 2018 was approximately 1,307 MWs per hour, with total energy delivered of more than 11.45 million MWHs.

Our Montana electric transmission and distribution network consists of approximately 24,765 miles of overhead and underground transmission and distribution lines and 386 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 customers' future energy needs and is used to guide resource acquisition activities. We filed our last resource plan with the MPSC during 2016 and expect to file our draft 2019 resource plan during the first quarter of 2019. We have significant generation capacity deficits and negative reserve margins. In addition to our responsibility to meet peak demand, national reliability standards effective July 2016 increase the need for us to have 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. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations for further discussion.

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.
        




9



mt2018elecgenportfolioa01.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 65% of our retail load requirements for 2018. We expect that approximately 65% of our retail obligations will be met by owned generation in 2019 as well. In addition, QFs provide a total of 491 MWs of nameplate capacity, including 107 MWs of capacity from waste petroleum coke and waste coal, 351 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 2019, 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.

Western Energy Imbalance Market

In November 2018, we announced our intent to enter the Western Energy Imbalance Market (EIM), operated by the California Independent System Operator (California ISO), in the spring of 2021. We studied the value and costs of the EIM for several years prior to the decision to participate in the Western EIM. Utilities in the western United States outside the California ISO have traditionally relied upon a combination of automated and manual dispatch within the hour to balance generation and load to maintain reliable supply. These utilities have limited capability to transact within the hour outside their balancing area. In contrast, energy imbalance markets use automated intra-hour economic dispatch of generation from committed resources to serve loads. The Western EIM is intended to reduce the power supply costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability. Participation in the Western EIM is voluntary and available to all balancing authorities in the western United States.





















10



Generation Facilities

        genfacilimtmap18.jpg
    
Details of these generating facilities are described in the following tables.

Hydro Facilities
COD
River
Source
FERC
License
Expiration
Maximum
Capacity
(MW) (1)
Black Eagle
1927
Missouri
2040
21
Cochrane
1958
Missouri
2040
62
Hauser
1911
Missouri
2040
17
Holter
1918
Missouri
2040
53
Madison
1906
Madison
2040
8
Morony
1930
Missouri
2040
49
Mystic
1925
West Rosebud Creek
2050
12
Rainbow
1910/2013
Missouri
2040
64
Ryan
1915
Missouri
2040
68
Thompson Falls
1915
Clark Fork
2025
94
 Total
 
 
 
448
(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
 
Ownership
Interest
 
Maximum
Capacity (MW)
Colstrip Unit 4, located near Colstrip in southeastern Montana
 
Sub-bituminous coal
 
30%
 
222
Dave Gates Generating Station (DGGS), located near Anaconda, Montana
 
Natural Gas
 
100%
 
150
Spion Kop Wind, located in Judith Basin County in Montana
 
Wind
 
100%
 
40
Two Dot Wind, located in Wheatland County in Montana
 
Wind
 
100%
 
11

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 reciprocal 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 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.

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

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.

The capacity of Two Dot represents the upgraded nameplate MW achieved through a software upgrade. Two Dot has been approved as a community renewable energy project (CREP) by the MPSC.

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. While our hydro generation assets acquired in 2014 are not eligible resources under the RPS, any qualifying additions would be eligible. 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, 2018, approximately 65 MW of CREPs. While we have made progress and believe we have taken all reasonable steps to meet this requirement, we have been unable to do so to date for various reasons, including the fact that proposed projects fail to qualify as CREPS or do not meet the statutory cost cap. The MPSC granted waivers for 2012 through 2016. We expect to file waiver requests for 2017 and 2018. If the requested waivers are not granted, we may be liable for penalties, although 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 63,800 customers in 110 communities in South Dakota. In 2018, by category, residential, commercial and other sales accounted for approximately 40%, 58%, and 2%, respectively, of our South Dakota retail electric utility revenue. Peak demand was approximately 330 MWs and the average load was approximately 200 MWs during the year ended December 31, 2018.
 
Our transmission and distribution network in South Dakota consists of approximately 3,572 miles of overhead and underground transmission and distribution lines as well as 128 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 submitted a plan in 2018 to provide for the modernization of our fleet, which is focused on improving reliability and flexibility. It also identifies a need of approximately 90MWs of existing generation that should be retired and replaced over the next 10 years to meet our goal of improved reliability and lower operating costs.

We use market purchases and peaking generation to provide peak supply in excess of our base-load capacity. 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. Marketing activities in SPP are handled for us by a third-party provider acting as our agent.

Our sources of energy by type during 2018 were as follows:


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sd2018electgenportfolio.jpg



Generation Facilities                                

            sdmapa01.jpg
Details of our generating facilities are described further in the following chart:

13



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 on 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 one wholly owned wind project. 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 four wind projects, three of which are QFs, 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.
 
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 340 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. Along with operating the transmission system, SPP also coordinates regional transmission planning for all members of the organization.
 

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NATURAL GAS OPERATIONS

Our natural gas utility operations include the production, purchase, transmission, storage, and distribution of natural gas. Our natural gas utility operations are not dependent on a single customer, or even a few customers, and the loss of any one or even a few of our largest customers is not reasonably likely to have a material adverse effect on our financial condition. Our gas utility business is seasonal 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.

Montana

Our regulated natural gas utility business in Montana includes production, storage, transmission and distribution. During 2018, we distributed natural gas to approximately 199,200 customers in 118 Montana communities over a system that consists of approximately 4,781 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 42.3 Bcf during the year ended December 31, 2018.
 
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 149 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, 2018, were approximately 21.8 Bcf. Our Montana natural gas supply requirements for electric generation fuel for the year ended December 31, 2018, were approximately 3.8 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 Rocky Mountains (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, 2018, these owned reserves totaled approximately 51.7 Bcf and are estimated to provide approximately 4.1 Bcf in 2019, or about 19 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 89,400 customers in 59 South Dakota communities and three Nebraska communities. We have approximately 2,437 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 nine 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 28.3 Bcf of third-party transportation volume on our South Dakota distribution system and approximately 3.5 Bcf of third-party transportation volume on our Nebraska distribution system during 2018.
 
Our South Dakota natural gas supply requirements for the year ended December 31, 2018, were approximately 6.7 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, 2018, were approximately 4.9 Bcf. We contract with a third party under an asset management agreement that includes pipeline

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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 additional 10-year terms unless and until canceled, with 5 years notice. The maximum term permitted under Nebraska law for these franchises is 25 years while 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, eleven of our Montana franchises are scheduled to reach the end of their fixed term, which account for approximately 62,000 or 31 percent of our Montana natural gas customers. Seven of our South Dakota franchises and two franchises in Nebraska, which account for approximately 35,400 or 40% 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 4 - 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
 
$1,233.0
 
7.92%
 
10.25%
 
48%
Montana - DGGS (3)
 
January 2011
 
172.7
 
167.8
 
8.16%
 
10.25%
 
50%
Montana - Colstrip Unit 4
 
January 2009
 
400.4
 
280.4
 
8.25%
 
10.00%
 
50%
Montana Spion Kop
 
December 2012
 
69.8
 
54.1
 
7.00%
 
10.00%
 
48%
Montana hydro assets
 
November 2014
 
841.8
 
777.4
 
6.91%
 
9.80%
 
48%
Montana natural gas delivery and production
 
September 2017
 
430.2
 
451.4
 
6.96%
 
9.55%
 
46.79%
   Total Montana
 
 
 
$2,547.4
 
$2,964.1
 
 
 
 
 
 
South Dakota electric (4)
 
December 2015
 
$557.3
 
$587.8
 
7.24%
 
n/a
 
n/a
South Dakota natural gas (4)
 
December 2011
 
65.9
 
61.6
 
7.80%
 
n/a
 
n/a
   Total South Dakota
 
 
 
$623.2
 
$649.4
 
 
 
 
 
 
Nebraska natural gas (4)
 
December 2007
 
$24.3
 
$26.5
 
8.49%
 
10.40%
 
n/a
 
 
 
 
$3,194.9
 
$3,640.0
 
 
 
 
 
 
(1)    Rate base reflects amounts on which we are authorized to earn a return.
(2)    Rate base amounts are estimated as of December 31, 2018.
(3)
The revenue requirement associated with 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

16



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 - Effective July 1, 2017, the Montana legislature granted the MPSC discretion whether to approve an electric supply cost tracking mechanism. After considering our application in a contested case proceeding, the MPSC approved an electric Power Cost and Credit Adjustment Mechanism (PCCAM) effective July 1, 2017 that incorporates sharing of a portion of the business risk or benefit associated with the cost of power purchased and fuel used to generate electricity. Customer prices may be adjusted annually to absorb a portion of the difference between base revenues and actual costs for the annual tracking period. Annual filings are based on a July through June 12-month tracking period, and are subject to a review by the MPSC to determine if electric supply procurement activities are prudent. If the MPSC subsequently determines that a procurement activity was imprudent, then it may disallow recovery of such costs. For additional information, see the Overview section in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

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 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 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
 

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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 defines the terms, conditions and rates of our Montana transmission service, including ancillary services. Our South Dakota transmission operations are in the SPP and transmission service is provided under the SPP OATT.
  
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, and 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.

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 19 - 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

18



incorporation by reference of the information contained on, or available through, the website. Therefore, such information should not be considered part of this report.

EMPLOYEES

As of December 31, 2018, we had 1,528 employees. Of these, 1,220 employees were in Montana and 308 were in South Dakota or Nebraska. Of our Montana employees, 446 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. One additional collective bargaining agreement, representing six employees, is currently being negotiated, and those negotiations are expected to be completed during the first quarter of 2019. Of our South Dakota and Nebraska employees, 185 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. 8, 2019
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).
 
63
 
 
 
 
 
Brian B. Bird
 
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.
 
56
 
 
 
 
 
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.
 
56
 
 
 
 
 
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).
 
63
 
 
 
 
 
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).
 
60
 
 
 
 
 
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.
 
40
 
 
 
 
 
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.
 
54
 
 
 
 
 
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.
 
50

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. For instance, our Montana electric utility is regulated by the MPSC and FERC. Differing schedules and regulatory practices between the MPSC and FERC expose us to the risk that we may not recover our costs due to timing of filings and issues such as cost allocation methodology.

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.

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

In 2018, the MPSC revised our recovery of prudently incurred supply costs to increase our risk by incorporating a sharing mechanism, which includes a +/- $4.1 million deadband applied to the difference between actual costs and revenues, with differences beyond the deadband shared by allocating 90% to customers and 10% to shareholders.
In 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.
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 a substantially lower rate for future QF contracts. The MPSC also applied the 15-year contract term to the economic evaluation of our future owned and contracted electric supply resources. As a result, we terminated our competitive solicitation process to address our intermittent capacity and reserve margin needs in Montana.
In 2016, the MPSC disallowed replacement power costs from a 2013 outage at Colstrip Unit 4 requested in our electric tracker filings.
In 2015, the MPSC issued an order eliminating the lost revenue adjustment mechanism, which allowed for recovery of fixed costs not recovered as a result of our energy efficiency program.
In 2013, the MPSC concluded that costs associated with a 2012 outage at DGGS were imprudently incurred, and disallowed recovery.

We submitted a general electric rate case filing with the MPSC in September 2018. We cannot predict how the MPSC may address this filing. If the MPSC determines our request is not supported and / or decreases overall electric rates, it could have a material adverse effect on our operating and financial results.

FERC & Other Regulation - We must comply with established reliability standards and requirements including Critical Infrastructure Protection (CIP) Reliability Standards, which apply to the NERC functions. NERC reliability standards protect the nations' bulk power system against potential disruptions from cyber and physical security breaches. The FERC, NERC, or a regional reliability organization may assess penalties against any responsible entity that violates their rules, regulations or standards. 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.

Early closure or unscheduled plant outages of our owned and jointly owned electric generating facilities due to operational or economic factors, environmental risks or litigation could have a material adverse impact on our results of operations and liquidity. We also rely on a limited number of suppliers of coal for our electric generation, making us

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vulnerable to increased prices for fuel as existing contracts expire or in the event of unanticipated interruptions in fuel supply.

Operation of electric generating facilities involves risks. Operational risks include facility shutdowns due to breakdown or failure of equipment or processes, interruptions in fuel supply, 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, which may not be recovered from customers.

In addition, environmental advocacy groups and other third parties have in recent years undertaken greater efforts to oppose the continued operation of certain facilities, expressing concerns about the environmental and climate-related impacts from continued extraction, transportation, delivery and combustion of fossil fuels. These efforts may increase in scope and frequency depending on a number of variables, including the course of Federal and State environmental regulation and the financial resources devoted to these opposition activities. These risks include litigation originated by third parties against us due to greenhouse gas or other emissions or coal combustion residuals (CCR) disposal and storage. We cannot predict the effect that any such opposition may have on our ability to operate and recover the costs of our generating facilities.

Early closure of our generation facilities due to economic conditions, environmental regulations and / or litigation could result in regulatory impairments or increased cost of operations. We are obligated to pay for the costs of closure of our share of generation facilities, including our share of the costs of reclamation of the mines that supply coal to the coal-fired power plants. Likewise, other owners or participants are responsible for their shares of the decommissioning and reclamation obligations. If recovery of our remaining investment in such facilities and the costs associated with early closure, including decommissioning, remediation, reclamation, and restoration are not recovered from customers, it could have a material adverse impact on our results of operations.

Colstrip - 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 those 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 their respective owners. 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 reduced amounts of energy transmitted 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 depreciable life of our investment in Colstrip Unit 4 is through 2042. Two of the other joint owners have entered into settlements with regulators and a third has filed a petition with its regulators to accelerate the recovery of their investment in Colstrip Units 3 and 4 by using a depreciable life through 2027, but have not established a date for closure. 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.

In addition, we have joint ownership in and operate the associated 500 kV transmission system. The closure of generation at Colstrip may impact the operation of this 500 kV system, and the joint owners may have differing needs with regard to ongoing operation of this system. This transmission system is an integral, essential part of our overall transmission system in Montana in order to maintain reliability, regardless of the status of the generation facilities.

Coal Supply - Colstrip Units 3 and 4 are supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through 2019. We and other joint owners are discussing new coal supply and transportation agreements, which anticipate expansion of the coal mine. This expansion requires environmental reviews and permitting. We cannot predict when or if those permits will be granted. Our coal supply and transportation agreements are with Western Energy Company (WeCo), a subsidiary of Westmoreland Coal Co. (Westmoreland). Westmoreland, along with WeCo filed for Chapter 11 bankruptcy protection on October 9, 2018. An auction was held for Westmoreland’s core assets, including its interest in WeCo and the mine adjacent to Colstrip, and no qualified bids were received. As a result a lenders group is expected to acquire Westmoreland’s core assets. During the course of the bankruptcy, WeCo may choose to assume or reject the existing coal supply and transportation agreements. WeCo indicated that it intends to reject the existing cost plus coal supply agreement. If WeCo rejects the existing agreement, the fuel supply to Units 3 and 4 may be interrupted until new arrangements are in place. In addition, any new arrangements may have higher costs than the existing cost plus agreement. We cannot predict the effect the Westmoreland bankruptcy may have on the ongoing operations of the facility.


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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.

Our electric and natural gas transmission and distribution operations involve numerous activities that may result in accidents, fires, system outages 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. 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 potential damages resulting from these risks could be significant.

For our electric distribution and transmission system, hazard trees located inside or outside our lines' rights of way pose risks. Hazard trees are those trees that are structurally unsound and could fall into our lines if the trees failed. We are facing challenges to address these trees. The risk of fires 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. Fires alleged to have been caused by our system could expose us to significant damage claims on theories such as strict liability, negligence, gross negligence, trespass, inverse condemnation, and others.

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.

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. Failure to maintain the security of personally identifiable information could adversely affect us.

Business 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. Cyber crime, which includes the use of malware, computer viruses, and other means for disruption or unauthorized access has increased in frequency, scope, and potential impact in recent years. Our 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 those that impact third party facilities that are interconnected to us. 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.

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.

Personally Identifiable Information - Our information systems and those of our third-party vendors contain confidential information, including information about customers and employees. Customers, shareholders, and employees expect that we will adequately protect their personal information. The regulatory environment surrounding information security and privacy is increasingly demanding. 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.

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Federally mandated purchases of power from QFs, and integration of power generated from those projects in our system, may increase costs to our customers and decrease system reliability, limit our ability to make generation investments and adversely affect our business.

We are generally obligated under federal law to purchase power from certain QF projects, regardless of current load demand, availability of lower cost generation resources, transmission availability or market prices. These resources are primarily intermittent, non-dispatchable generation whose prices may be in excess of market prices during times of lower customer demand, and may not be able to generate electricity during peak times. These resources typically do not meet the requirements set forth in our supply plans for resource procurement. These requirements to purchase supply inconsistent with customer need may have several impacts, including increasing the likelihood and frequency that we will be required to reduce output from owned generation resources and that we will need to upgrade or build additional transmission facilities to serve QF projects. Either of these results would increase costs to customers. Further, balancing load and power generation on our system is challenging, and we expect that operational costs will increase as a result of integration of these intermittent, non-dispatchable generation projects. If we are unable to timely recover those costs through our power cost adjustment mechanism or otherwise, those increased costs may negatively affect our liquidity, results of operations and financial condition.

In addition, 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 that are inconsistent with resource plans developed based on a lowest cost and least risk basis while placing upward pressure on overall customer bills. This may impact our investment plans and financial condition.

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 environmental considerations. We are also subject to judicial interpretations of those laws and regulations. We believe that we are in compliance with environmental regulatory requirements; however, possible future developments, such as more stringent environmental laws and regulations, the timing of future enforcement proceedings that may be taken by environmental authorities, and judicial opinions regarding those laws and regulations, 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. On August 31, 2018, EPA published a proposed rule, the Affordable Clean Energy Rule (ACE), which is intended to serve as a replacement for the CPP. If finalized as proposed, it is expected that the ACE would generally require a lower level of carbon dioxide (CO2) emission reductions than the CPP and provide more regulatory flexibility to individual states. We cannot predict whether CPP will be repealed or whether the ACE will be implemented in its current form.

If GHG regulations are implemented, it could result in additional compliance costs that could affect our future results of operations and financial position if such costs are not recovered through regulated rates. 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.


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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.

Our need to acquire flexible energy supply and capacity in the market to meet our electric load serving obligations in Montana may have risks. Our electric and natural gas portfolios have a significant percentage of market purchases and market prices for power and natural gas and are subject to forces that are often not predictable and which can result in price volatility and general market disruption, adversely affecting our costs and ability to manage our energy portfolio and procure required energy supply, which ultimately could have an adverse effect on liquidity and results of operations.

Commodity pricing is an inherent risk component of our business operations and our financial results. Even though rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that our costs are recoverable as discussed above. The prevailing market prices for electricity may fluctuate substantially over relatively short periods of time, potentially adversely impacting our results of operations, financial condition and cash flows due to our need for market purchases and our Montana electric supply recovery mechanism.

We are obligated to supply power to retail customers and certain wholesale customers. In Montana, approximately 46% of our peak requirements are served through market purchases. We rely upon contracts with counterparties and market purchases to fulfill this need; however, there can be no assurance that the counterparties to these agreements will fulfill their obligations to us. The suppliers under these agreements may experience financial or operational problems that inhibit their ability to fulfill their obligations to us.

In addition, a significant number of base-load generation facilities, which may also serve to meet peak requirements, in the region are being retired or are scheduled to be retired in the next five to ten years. A decrease in the region’s capacity may impair the reliability of the grid, particularly during peak demand periods. This may also reduce our ability to rely upon contracts with counterparties to fulfill our ability to serve customers’ needs.

Fluctuations in actual weather conditions, generation availability, transmission constraints, and generation reserve margins may all have an impact on market prices for energy and capacity and the electricity consumption of our customers on a given day. Extreme weather conditions may force us to purchase electricity in the short-term market on days when weather is unexpectedly severe, and the pricing for market energy may be significantly higher on such days than the cost of electricity in our existing generation and contracts. Unusually mild weather conditions could leave us with excess power which may be sold in the market at a loss if the market price is lower than the cost of electricity in our existing contracts.

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.

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.

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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, microbursts, fires, 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 fires, which could threaten our communities and electric distribution and transmission lines and facilities. In addition, fires 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 fires 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 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.

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 and would increase our borrowing costs. Higher interest rates on borrowings with variable interest rates could also have an adverse effect on our results of operations.

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 inappropriately increasing rates generally and increasing rates for customers who do not own generation, unless retail rates are designed to collect distribution grid costs across all customers in a manner that reflects the 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

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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 load reduction 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, the availability of generation, and the development of the Western EIM and our expected participation, 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.

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

Acquisitions include a number of risks, including but not limited to, regulatory approval, regulatory conditions, 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 postretirement 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 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 the 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. This obligation is reflected in the electric QF liability, which reflects the unrecoverable costs associated with these specific QF contracts per the stipulation. The annual minimum energy requirement is achievable under normal operations of these facilities, including

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normal periods of planned and forced outages. However, to the extent the supplied 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 shortfall is the wholesale market, which would subject us to commodity price risk if the cost of replacement power is higher than contracted rates.

In addition, we are subject to price escalation risk with one of the largest contracts included in the electric QF liability due to variable contract terms. In recording the electric QF liability, we 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 19 - 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.


ITEM 4. MINE SAFETY DISCLOSURES

None

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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 8, 2019, there were approximately 1,066 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 2018.





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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,
 
2018
 
2017
 
2016
 
2015
 
2014
Financial Results (in thousands, except per share data)
 
 
 
 
 
 
 
 
 
Operating revenues
$
1,192,009

 
1,305,652

 
$
1,257,247

 
$
1,214,299

 
$
1,204,863

Net income
196,960

 
162,703

 
164,172

 
151,209

 
120,686

Basic earnings per share
$3.94
 
$3.35
 
$3.40
 
$3.20
 
$3.01
Diluted earnings per share
3.92
 
3.34
 
3.39
 
3.17
 
2.99
Dividends declared per common share
2.20
 
2.10
 
2.00
 
1.92
 
1.60
Financial Position
 
 
 
 
 
 
 
 
 
Total assets
$
5,644,376

 
5,420,917

 
$
5,499,321

 
$
5,264,695

 
$
4,960,902

Total debt, including capital leases and short-term borrowings
2,124,558

 
2,137,318

 
2,120,474

 
2,026,219

 
1,946,790




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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 21 - 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 726,400 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 2018, 2017 and 2016. Following is a discussion of our strategy and significant trends.

We are working to deliver safe, reliable and innovative energy solutions that create value for customers, communities, employees and investors. This includes bridging our history as a regulated utility safely providing low-cost and reliable service with our future as a globally-aware company offering a broader array of services performed by highly-adaptable and skilled employees. We seek to deliver value to our customers by providing high reliability and customer service, and an environmentally sustainable generation mix at an affordable price. 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 sustainability considerations with more predictable long-term commodity prices.

Continually improving 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.


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HOW WE PERFORMED IN 2018 COMPARED TO OUR 2017 RESULTS

 
Year ended December 31,
 
2018
 
2017
 
Change, Net of Tax
 
(in millions)
Net Income
$
197.0

 
$
162.7

 
$
34.3

Items increasing (decreasing) net income:
 
 
 
 
 
QF liability adjustment
 
 
 
 
18.7

Impacts of Tax Cuts and Jobs Act
 
 
 
 
15.2

Electric transmission
 
 
 
 
4.6

Retail volumes
 
 
 
 
2.7

Labor
 
 
 
 
2.5

Depreciation and depletion
 
 
 
 
(6.2
)
Hazard trees
 
 
 
 
(2.5
)
Other
 
 
 
 
(0.7
)
Change in net income
 
 
 
 
$
34.3


Consolidated net income in 2018 was $197.0 million as compared with $162.7 million in 2017. This increase was primarily due to a gain related to the adjustment of our electric QF liability, the net impact of the Tax Cuts and Jobs Act, demand for electric transmission, favorable weather, and lower labor costs, partly offset by an increase in depreciation and depletion expense and an increase in expense associated with removing hazard trees outside of our electric transmission and distribution lines rights of way.

SIGNIFICANT TRENDS AND REGULATION

Montana General Electric Rate Case

In September 2018, we filed an electric rate case with the MPSC requesting an annual increase to electric rates of approximately $34.9 million, which represents an approximate 6.6% increase in annual base revenues. Our request is based on a return on equity of 10.65% and an overall rate of return of 7.42% (except for Colstrip Unit 4 which the MPSC previously set for the life of the facility at a 10% return on equity and an 8.25% rate of return), based on approximately $2.35 billion of electric rate base and a capital structure of 51 percent debt and 49 percent equity.

We also requested that approximately $13.8 million of the rate increase be approved on an interim basis effective November 1, 2018. We expect to receive a decision on our interim request after intervenor testimony is filed. If the MPSC does not issue a final order within nine months of the filing, the new requested rates may be placed into effect on an interim and refundable basis.

Key dates in the procedural schedule are expected to be as follows:
Intervenor testimony - February 12, 2019
NorthWestern rebuttal testimony and cross-intervenor testimony - April 5, 2019
Hearing commences - May 13, 2019

We expect to file a FERC rate case for our Montana transmission assets by the end of the first quarter of 2019. The revenue requirement associated with our Montana FERC assets is reflected in our MPSC jurisdictional rates as a credit to customers.

Electric Resource Planning - Montana

In the first quarter of 2019, we expect to submit our draft 2019 Electricity Supply Resource Procurement Plan (Montana Resource Plan) with the MPSC. The Montana Resource Plan supports the goal of developing resources that will address the changing energy landscape in Montana to meet our customers' electric energy needs in a reliable and affordable manner. A

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summary of the draft Montana Resource Plan was provided for public comment in January 2019. After submission to the MPSC, the draft will be available for public comment for 60 days.

Montana is in the midst of a transition from producing more energy than is needed in the state with energy exported to the west, to a growing risk of not having enough capacity to serve Montana customers at critical times of peak load due to reductions in regional and in state energy generation as noted below:

Our current peak requirement for energy is about 1,400 MW. We are currently 630 MW short, which is subject to market purchases. We forecast that our energy portfolio will be 725 MW short by 2025 with modest increased customer demand.
Planned regional retirements of 3,500 MW of coal-fired generation are forecast by the Northwest Power and Conservation Council to cause regional peak energy shortages as early as 2021.

The long-term objective of the Montana Resource Plan is a clean, cost-effective, stable and reliable energy portfolio. Based on our customers' future energy resource needs as identified in 2019, we expect to solicit competitive proposals for up to 200 MW of peaking capacity available by 2022, which is about one-fourth of our projected need in 2025. An independent evaluator will be used to assess the proposals. We expect the process will be repeated in subsequent years to provide a resource-adequate energy and capacity portfolio. Using this staged approach, we propose to add 200 MWs of capacity per year from 2022 to 2025.

The proposal solicitation process will consider a wide variety of resource options and sizing, ownership options and contract lengths. This includes power purchase agreements and owned energy resources comprised of different structures, terms and technologies that are cost-effective resources. The staged approach is designed to allow for incremental steps through time with opportunities for different resource type of new technologies while also building a reliable portfolio to meet local and regional conditions and minimizing customer impacts.

Western Energy Imbalance Market

In November 2018, we announced our intent to enter the Western EIM, operated by the California ISO, in the spring of 2021. The Western EIM is intended to reduce the power supply costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, to integrate intermittent power from renewable generation sources more effectively, and to enhance reliability. Participation in the Western EIM is voluntary and available to all balancing authorities in the western United States. In order to participate in the Western EIM, we must demonstrate resource adequacy through a combination of owned or contracted resources.

Assumptions regarding entry into the Western EIM are incorporated into our Montana Resource Plan. In early 2018, the California ISO began a process to enhance the day-ahead market within the full Independent System Operator's footprint (the EDAM initiative). The enhancements to the day-ahead market are targeted to go live in 2019 with a platform that will allow the addition of a day-ahead market to the Western EIM. The extension of EDAM to EIM participants has not yet been formally introduced as a stakeholder process, but if current EIM members and the California ISO support moving forward, a stakeholder process will be initiated regarding the day-ahead EIM that could go live as early as 2022. Our Montana Resource Plan assumes that EIM entry will occur in 2021, followed by EDAM entry in 2022 and the development of a full market with an independent system operator in 2025.

Electric Resource Planning - South Dakota

Our 2018 South Dakota Electricity Supply Resource Procurement Plan (South Dakota Resource Plan) identified approximately 90MWs of existing generation that should be retired and replaced over the next 10 years with the goal of improving reliability and lowering operating costs. We expect to issue a request for proposal in the second quarter of 2019 to replace 60 MW of combustion turbine generation by December 2021, comparing the relative costs of the addition of a reciprocating internal combustion engine facility to other market offerings. In addition, we are currently installing 8 MW of mobile capacity generation, with units expected to be operational in the fourth quarter of 2019.

PURPA

PURPA requires us to purchase power from qualifying cogeneration and small power production facilities at a price approved by the MPSC that is meant to represent our “avoided cost” of generating power or purchasing power from another source. 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 that are inconsistent with resource plans developed based on a lowest cost and least risk basis while placing upward pressure on overall customer bills. Although the costs incurred to purchase power

32



from QFs are passed on to customers, subject to the cost recovery mechanism discussed below, mandated purchases of QF generation, potentially at above-market prices, may reduce the need for new owned generation. This in turn could have a material adverse effect on our long-term capital investment plan and the affordability of future customer prices. We expect to establish a current avoided cost in Montana in conjunction with our Montana Resource Plan.

Colstrip

Colstrip Units 3 and 4 are supplied with fuel from adjacent coal reserves under coal supply and transportation agreements with WeCo in effect through 2019. WeCo filed for Chapter 11 bankruptcy protection in October 2018. An auction was held for the core assets in January 2019, including the mine adjacent to Colstrip, with no qualified bids received. As a result a lenders group is expected to acquire the core assets. During the course of the bankruptcy, WeCo may choose to assume or reject the existing coal supply and transportation agreements. WeCo indicated that it intends to reject the existing cost plus coal supply agreement. If WeCo rejects the existing agreement, the fuel supply to Units 3 and 4 may be interrupted until new arrangements are in place. In addition, any new arrangements may have higher costs than the existing cost plus agreement.

Hazard Trees

Hazard trees are those trees that are structurally unsound and could fall into our lines if the trees failed. Hazard trees may be located inside or outside our electric transmission and distribution lines' rights of way and pose risks to our system including disruption of service, property damage, loss of life, and/or fires. We are facing challenges to address these trees. Beetle infestations have caused a significant increase in the quantity of standing dead and dying timber and have impacted our system for quite some time. As part of our normal vegetation management program, we have routinely removed trees from within our rights of way, including those infected by the beetle infestation. Additionally, in some circumstances, we were authorized to remove one or more hazard trees from outside of our rights of way that could harm our system.

The beetle infestation exacerbates the risk of fires in Montana, increasing the risk that such trees may fall from either inside or outside our right-of-way into a powerline igniting a fire. Fires alleged to have been caused by our system could expose us to significant damage claims on theories such as strict liability, negligence, gross negligence, trespass, inverse condemnation, and others. 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.

We worked with third parties, including the U.S. Forest Service, to develop a plan to remove these hazard trees. We identified areas severely impacted and determined that the only way to mitigate fire and reliability risk along these lines is to clear-cut all of the trees on either side of the electric lines that could hit the lines, if they fell. In most cases, this results in a corridor of approximately 100 feet on either side of the lines. Normal rights of way vary but are generally 20 feet to 40 feet wide on distribution lines and 40 feet to 100 feet wide on transmission lines. We finalized our plan to address the identified areas in the first quarter of 2018 and began work.

During 2018, we incurred approximately $3.3 million in costs related to this work, which is incremental to costs for vegetation management within our rights of way. We expect to continue the program over the next several years with anticipated 2019 costs ranging from approximately $7 million to $9 million, with total costs exceeding $20 million.

Tax Cuts and Jobs Act

In December 2017, 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. Dockets were opened in each of our jurisdictions to investigate the customer benefit of this reduction in the federal corporate income tax rate. During 2018, we received approval of settlement agreements regarding the customer benefit of the Tax Cuts and Jobs Act, as described below.

In Montana the settlement provides a one-time credit of approximately $20.5 million to customers in early 2019. This includes a $19.2 million credit to electric customers and $1.3 million credit to natural gas customers.
In addition to eligible customers receiving a one-time bill credit, the settlement also reduces rates for all natural gas customers by approximately $1.3 million annually beginning January 1, 2019, and provides funds for low-income energy assistance and weatherization programs.
The settlement also reflects the agreement of the intervening parties not to oppose our request to include up to $3.5 million of costs to address hazard tree removal in our current Montana rate case.
Issues related to the revaluation of deferred income taxes will be addressed in our current Montana rate case.

33




In South Dakota we credited electric and natural gas customers approximately $3.0 million in the fourth quarter of 2018, and agreed to a two-year rate moratorium until January 1, 2021.

Our 2018 results include a net benefit related to the impact of the Tax Cuts and Jobs Act, which includes:
An income tax benefit of approximately $19.8 million due to the finalization of the revaluation of deferred income tax liabilities upon completion of the associated regulatory dockets; offset by
A net loss of approximately $6.1 million including a reduction in revenue of approximately $23.5 million, due to customer credits in the above regulatory settlements, offset in part by a reduction in income tax expense, of approximately $17.4 million due to the reduction in federal tax rate.

In addition, we reflected the costs of our hazard tree program in the consolidated income statement as we agreed in our Montana settlement to request recovery of these costs in base customer rates in our 2018 filing, as discussed above, rather than using a portion of the reduction in customer rates associated with the change in tax rate as proposed in our Montana Tax Cuts and Jobs Act filing.

We expect a consolidated reduction in our cash flows from operations ranging from $20 million to $22 million in 2019, as a result of the customer credits discussed above while we are not a cash taxpayer. See Liquidity and Capital Resources for further discussion. We currently estimate that our effective income tax rate will range from 0% to 5% in 2019.

Cost Recovery Mechanisms

Electric Tracker - Effective July 1, 2017, the Montana legislature granted the MPSC discretion whether to approve an electric supply tracking mechanism. After considering our application in a contested case proceeding, the MPSC issued a final order in January 2019 approving a PCCAM with the following provisions:

A baseline of power supply costs;
Annual adjustment of customer prices to reflect a portion of the difference between the established base revenues and actual costs, to the extent such difference is outside a +/- $4.1 million "deadband" from the base, with 90% of the variance above or below the deadband collected from or refunded to customers; and
Retroactive implementation to the effective date of the new legislation (July 1, 2017).

Our 2018 results include a net reduction in the recovery of supply costs from customers of approximately $1.5 million in the Consolidated Statements of Income, which includes the following:

For the 2017/2018 period, actual costs were below base revenues by approximately $3.4 million, resulting in no refund to customers.
For the 2018/2019 period, actual costs were above base revenues by approximately $11.8 million, resulting in a regulatory asset for collection from customers of approximately $6.9 million as of December 31, 2018 and an approximately $4.9 million reduction in recovery of supply costs for the first six months of the period. For further discussion, see Results of Operations below.

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):

        

34



        regulated5yearforecast2018.jpg

Distribution and Transmission Modernization and Maintenance - 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 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. We are currently installing Automated Metering Infrastructure (AMI) in our South Dakota and Nebraska jurisdictions. This project is expected to be completed in 2019 at a total cost of approximately $32 million. In Montana we are developing a similar AMI project to be started in 2020. While this project is still in the evaluation phase, we estimate our total AMI capital expenditures across all of our service territories to be in the range of approximately $100 to $110 million if fully deployed.

Electric Supply Resource Plans - Our energy resource plans discussed above identify portfolio resource requirements including potential investments. While our resource plans identify needs, any owned generation is subject to successful completion of the competitive solicitation process and are not reflected in the projections above. We anticipate that owned assets to address energy and capacity needs for both Montana and South Dakota could increase the capital forecast presented above in excess of $200 million over the next five years.

Natural Gas Production Assets - We own natural gas production and gathering system assets in Montana 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. 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.

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.  We define Gross Margin as Revenues less Cost of Sales as presented in our Consolidated Statements of Income.


35



Management believes that Gross Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers, and as a result do not typically impact operating or net income. In addition, 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, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Gross Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report.

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.


36



OVERALL CONSOLIDATED RESULTS

Year Ended December 31, 2018 Compared with Year Ended December 31, 2017

 
Electric
 
Natural Gas
 
Total
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
(in millions)
Reconciliation of gross margin to operating revenue:
 
 
 
 
 
 
 
 
 
 
 
Operating Revenues
$
921.1

 
$
1,037.1

 
$
270.9

 
$
268.6

 
$
1,192.0

 
$
1,305.7

Cost of Sales
194.6

 
334.0

 
78.3

 
76.3

 
272.9

 
410.3

Gross Margin(1)
$
726.5

 
$
703.1

 
$
192.6


$
192.3

 
$
919.1

 
$
895.4

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

 
Year Ended December 31,
 
2018
 
2017
 
Change
 
% Change
 
(in millions)
Gross Margin
 
 
 
 
 
 
 
Electric
$
726.5

 
$
703.1

 
$
23.4

 
3.3
%
Natural Gas
192.6

 
192.3

 
0.3

 
0.2

Total Gross Margin(1)
$
919.1

 
$
895.4

 
$
23.7

 
2.6
%
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Primary components of the change in gross margin include the following (in millions):
 
Gross Margin 2018 vs. 2017
Gross Margin Items Impacting Net Income
 
Electric QF liability adjustment
$
25.1

Electric transmission
6.2

Electric and natural gas retail volumes
3.6

Montana natural gas rates
0.4

Impacts of Tax Cuts and Jobs Act
(6.1
)
PCCAM supply cost recovery
(1.5
)
Other
2.3

Change in Gross Margin Impacting Net Income
30.0

 
 
Gross Margin Items Offset in Operating Expenses and Income Tax Expense
 
Impacts of Tax Cuts and Jobs Act
(17.4
)
Natural gas gathering fees
(0.5
)
Natural gas production taxes
(0.4
)
Property taxes recovered in trackers
11.7

Production tax credits flowed-through trackers
0.3

Change in Items Offset Within Net Income
(6.3
)
Increase in Consolidated Gross Margin(1)
$
23.7

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Consolidated gross margin for items impacting net income increased $30.0 million, due to the following:


37



A reduction in the electric QF liability due to the combination of (i) a periodic adjustment of the liability for price escalation, which was less than modeled resulting in a liability reduction of approximately $17.5 million; and (ii) the annual reset to actual output and pricing resulting in approximately $7.6 million in lower QF related supply costs due to outages at two facilities;
Higher demand to transmit energy across our transmission lines due to market conditions and pricing;
An increase in electric and natural gas retail volumes due primarily to customer growth and favorable weather in South Dakota; and
An increase in our Montana gas rates effective September 1, 2017.

These increases were partly offset by a $6.1 million reduction in revenue due to the impacts of the Tax Cuts and Jobs Act settlement and a $1.5 million reduction in recovery of Montana electric supply costs, as discussed above in Significant Trends and Regulation.

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

A reduction in revenue in 2018 to reflect the pass-through of the Tax Cuts and Job Act related benefits to customers, which is offset by a decrease in income tax expense;
A decrease in natural gas gathering fees which are offset by reduced operating expenses;
A decrease in natural gas production taxes which are offset by reduced property and other taxes;
An increase in revenues for property taxes included in trackers, which are offset by increased property tax expense; and
An increase in revenue due to decreased production tax credit benefits passed through to customers in our tracker mechanisms, which is offset by increased income tax expense.

 
Year Ended December 31,
 
2018
 
2017
 
Change
 
% Change
 
(in millions)
Operating Expenses (excluding cost of sales)
 
 
 
 
 
 
 
Operating, general and administrative
$
307.1

 
$
294.8

 
$
12.3

 
4.2
%
Property and other taxes
171.3

 
162.6

 
8.7

 
5.4

Depreciation and depletion
174.5

 
166.1

 
8.4

 
5.1

 
$
652.9

 
$
623.5

 
$
29.4

 
4.7
%

38




Consolidated operating, general and administrative expenses were $307.1 million in 2018, as compared with $294.8 million in 2017. Primary components of the change include the following (in millions):
 
Operating, General & Administrative Expenses
 
2018 vs. 2017
Operating, General & Administrative Expenses Impacting Net Income
 
Employee benefits
$
7.2

Hazard trees
3.3

Distribution System Infrastructure Project expenses
(3.7
)
Labor
(3.3
)
Maintenance costs
(2.6
)
Other
1.2

Change in Items Impacting Net Income
2.1

 
 
Operating, General & Administrative Expenses Offset Within Net Income
 
Pension and other postretirement benefits
10.3

Operating expenses recovered in trackers
1.1

Non-employee directors deferred compensation
(0.7
)
Natural gas gathering fees
(0.5
)
Change in Items Offset Within Net Income
10.2

Increase in Operating, General & Administrative Expenses
$
12.3



Consolidated operating, general and administrative expenses for items impacting net income increased $2.1 million due to the following:

An increase in employee benefit costs, primarily due to higher medical and employee incentive expense; and
Costs incurred in 2018 to remove hazard trees outside of our electric transmission and distribution lines rights of way.

These increases were partly offset by the following:

Lower expenses related to the Distribution System Infrastructure Project, which concluded in 2017;
Decreased labor costs due primarily to fewer employees and more time being spent by employees on capital projects rather than maintenance projects (which are expensed); and
Lower maintenance costs at electric generating facilities.

The change in consolidated operating, general and administrative expenses also includes the following items that had no impact on net income:

The regulatory treatment of the non-service cost components of pension and postretirement benefit expense, which is offset in other income;
Higher operating expenses included in trackers and recovered in revenue;
A change in the value of non-employee directors deferred compensation due to the change in our stock price, which is offset in other income; and
Lower gas gathering fees and production taxes, which is offset by lower margin discussed above.

Property and other taxes were $171.3 million in 2018, as compared with $162.6 million in 2017. This increase was primarily due to plant additions and higher estimated property valuations in Montana. Under Montana law, we are allowed to track the changes in the actual level of state and local taxes and fees and recover 74% of the increase in taxes and fees, which is net of the associated income tax benefit.


39



Depreciation and depletion expense was $174.5 million in 2018, as compared with $166.1 million in 2017. This increase was primarily due to plant additions.

Consolidated operating income in 2018 was $266.3 million as compared with $271.7 million in 2017. This decrease was primarily due to the overall increase in operating expenses, as discussed above, offset in part by higher gross margin.

Consolidated interest expense in 2018 was $92.0 million, as compared with $92.3 million in 2017. See "Liquidity and Capital Resources" for additional information regarding our financing activities.

Consolidated other income in 2018, was $4.0 million, as compared with consolidated other expense of $3.4 million in 2017. This increase includes a $10.3 million decrease in other pension expense (which is offset in operating, general, and administrative expenses), partly offset by lower capitalization of AFUDC.

Consolidated income tax benefit in 2018 was $18.7 million, as compared with consolidated income tax expense of $13.4 million in 2017. Our effective tax rate for the twelve months ended December 31, 2018 was (10.5)% as compared with 7.6% for the same period of 2017. The decrease in income tax expense in 2018 is primarily due to the impact of the lower federal tax rate and a benefit of approximately $19.8 million associated with the final measurement of excess deferred taxes.

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):
 
Year Ended December 31,
 
2018
 
2017
Income Before Income Taxes
$
178.3

 
 
 
$
176.1

 
 
 
 
 
 
 
 
 
 
Income tax calculated at federal statutory rate
37.4

 
21.0
 %
 
61.6

 
35.0
 %
 
 
 
 
 
 
 
 
Permanent or flow through adjustments:
 
 
 
 
 
 
 
State income, net of federal provisions
1.6

 
0.9

 
(3.3
)
 
(1.9
)
Impact of Tax Cuts and Jobs Act
(19.8
)
 
(11.1
)
 

 

Flow-through repairs deductions
(19.3
)
 
(10.8
)
 
(30.5
)
 
(17.3
)
Production tax credits
(10.9
)
 
(6.1
)
 
(11.0
)
 
(6.3
)
Prior year permanent return to accrual adjustments
(3.0
)
 
(1.7
)
 
(0.6
)
 
(0.3
)
Plant and depreciation of flow through items
(2.2
)
 
(1.2
)
 
(2.2
)
 
(1.3
)
Share-based compensation
0.2

 
0.1

 
(0.4
)
 
(0.2
)
Other, net
(2.7
)
 
(1.6
)
 
(0.2
)
 
(0.1
)
 
(56.1
)
 
(31.5
)
 
(48.2
)
 
(27.4
)
 
 
 
 
 
 
 
 
Income Tax (Benefit) Expense
$
(18.7
)
 
(10.5
)%
 
$
13.4

 
7.6
 %

Consolidated net income in 2018 was $197.0 million as compared with $162.7 million in 2017. This increase was primarily due to a gain related to the adjustment of our electric QF liability, demand for electric transmission, customer growth and favorable weather, and an income tax benefit associated with the impacts of the Tax Cuts and Jobs Act, partly offset by an increase in depreciation expense.


40



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

 
Electric
 
Natural Gas
 
Total
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
 
(in millions)
Reconciliation of gross margin to operating revenue:
 
 
 
 
 
 
 
 
 
 
 
Operating Revenues
$
1,037.1

 
$
1,011.6

 
$
268.6

 
$
245.7

 
$
1,305.7

 
$
1,257.3

Cost of Sales
334.0

 
332.8

 
76.3

 
68.2

 
410.3

 
401.0

Gross Margin(1)
$
703.1

 
$
678.8

 
$
192.3

 
$
177.5

 
$
895.4

 
$
856.3

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

 
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

Total Gross Margin(1)
$
895.4

 
$
856.3

 
$
39.1

 
4.6
%
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

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 (in millions):

 
Gross Margin 2017 vs. 2016
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 within Net Income
 
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(1)
$
39.1

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

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;

41



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.


 
Year Ended December 31,
 
2017
 
2016
 
Change
 
% Change
 
(in millions)
Operating Expenses (excluding cost of sales)
 
 
 
 
 
 
 
Operating, general and administrative
$
294.8

 
$
293.9

 
$
0.9

 
0.3
%
Property and other taxes
162.6

 
148.1

 
14.5

 
9.8

Depreciation and depletion
166.1

 
159.3

 
6.8

 
4.3

 
$
623.5

 
$
601.3

 
$
22.2

 
3.7
%

Consolidated operating, general and administrative expenses were $294.8 million in 2017 as compared with $293.9 million in 2016. Primary components of this change include the following (in millions):
 
Operating, General, & Administrative
Expenses 2017 vs. 2016
Operating, General & Administrative Expenses Impacting Net Income
 
Bad debt expense
$
1.9

Maintenance costs
1.2

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

Change in Items Impacting Net Income
0.7

 
 
Operating, General & Administrative Expenses Offset Within Net Income
 
Operating expenses recovered in trackers
1.5

Pension and other postretirement benefits
(1.3
)
Change in Items Offset Within Net Income
0.2

Increase in Operating, General & Administrative Expenses
$
0.9


Consolidated operating, general and administrative expenses for items impacting net income increased $0.7 million primarily due to the following:


42



Higher bad debt expense due to an increase in revenues as a result of colder winter and warmer summer weather; 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.

The change in consolidated operating, general and administrative expenses also includes the following items that had no impact on net income:

Higher operating expenses recovered through our supply trackers; and
The regulatory treatment of the non-service cost component of pension and postretirement benefit expense, offset in other income.

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.

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 $271.7 million, as compared with $255.0 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.

Consolidated other income in 2017 was $3.4 million as compared with $3.5 million in 2016. This decrease was primarily due to an increase in other pension expense, offset in part by 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):

43



 
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.



44



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.
Wholesale and other are largely gross margin neutral as they are offset by changes in cost of sales.

Year Ended December 31, 2018 Compared with Year Ended December 31, 2017

 
Results
 
2018
 
2017
 
Change
 
% Change
 
(in millions)
Retail revenue
$
847.3

 
$
874.4

 
$
(27.1
)
 
(3.1
)%
Regulatory amortization
9.8

 
3.7

 
6.1

 
(164.9
)
     Total retail revenues
857.1

 
878.1

 
(21.0
)
 
(2.4
)
Transmission
58.1

 
59.7

 
(1.6
)
 
(2.7
)
Wholesale and Other
5.9

 
99.3

 
(93.4
)
 
(94.1
)
Total Revenues
921.1

 
1,037.1

 
(116.0
)
 
(11.2
)
Total Cost of Sales
194.6

 
334.0

 
(139.4
)
 
(41.7
)
Gross Margin(1)
$
726.5

 
$
703.1

 
$
23.4

 
3.3
 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.


 
Revenues
 
Megawatt Hours (MWH)
 
Avg. Customer Counts
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
(in thousands)
 
 
 
 
Montana
$
287,358

 
$
299,725

 
2,518

 
2,540

 
299,438

 
295,427

South Dakota
64,171

 
60,246

 
598

 
546

 
50,546

 
50,247

   Residential 
351,529

 
359,971

 
3,116

 
3,086

 
349,984

 
345,674

Montana
329,611

 
348,139

 
3,169

 
3,235

 
67,547

 
66,484

South Dakota
93,992

 
91,969

 
1,072

 
992

 
12,741

 
12,669

Commercial
423,603

 
440,108

 
4,241

 
4,227

 
80,288

 
79,153

Industrial
42,577

 
42,194

 
2,593

 
2,324

 
75

 
75

Other
29,600

 
32,110

 
166

 
195

 
6,185

 
6,195

Total Retail Electric
$
847,309

 
$
874,383

 
10,116

 
9,832

 
436,532

 
431,097


 
Cooling Degree Days
 
2018 as compared with:
 
2018
 
2017
 
Historic Average
 
2017
 
Historic Average
Montana
337
 
524
 
409
 
 36% colder
 
 18% colder
South Dakota
951
 
729
 
733
 
 30% warmer
 
 30% warmer



45



 
Heating Degree Days
 
2018 as compared with:
 
2018
 
2017
 
Historic Average
 
2017
 
Historic Average
Montana
7,882
 
7,738
 
7,529
 
 2% colder
 
 5% colder
South Dakota
8,385
 
7,102
 
7,752
 
 18% colder
 
 8% colder

The following summarizes the components of the changes in electric gross margin for the year ended December 31, 2018 and 2017 (in millions):
 
Gross Margin 2018 vs. 2017
Gross Margin Items Impacting Net Income
 
QF liability adjustment
$
25.1

Transmission
6.2

Retail volumes
0.3

Impacts of Tax Cuts and Jobs Act
(8.6
)
PCCAM supply cost recovery
(1.5
)
Other
3.5

Change in Gross Margin Impacting Net Income
25.0

 
 
Gross Margin Items Offset Within Net Income
 
Impacts of Tax Cuts and Jobs Act
(12.9
)
Property taxes recovered in trackers
11.0

Production tax credits flowed-through trackers
0.3

Change in Items Offset Within Net Income
(1.6
)
Increase in Gross Margin(1)
$
23.4

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Gross margin for items impacting net income increased $25.0 million including the following:

A reduction in the QF liability due to the combination of (i) a periodic adjustment of the liability for price escalation, which was less than modeled resulting in a liability reduction of approximately $17.5 million; and (ii) the annual reset to actual output and pricing resulting in approximately $7.6 million in lower QF related supply costs due to outages at two facilities;
Higher demand to transmit energy across our transmission lines due to market conditions and pricing; and
An increase in retail volumes due primarily to customer growth and favorable weather in our South Dakota jurisdiction, partly offset by unfavorable weather in our Montana jurisdiction.

These increases were partly offset by an $8.6 million decrease from the Tax Cuts and Jobs Act settlement and a $1.5 million reduction in recovery of energy supply costs associated with the Montana PCCAM, as discussed above.

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

A reduction in revenue in 2018 to reflect the pass-through of the Tax Cuts and Job Act related benefits to customers, which are offset in part by a decrease in income tax expense;
An increase in revenues for property taxes included in trackers, which are offset by increased property tax expense; and
An increase in revenue due to the decrease in production tax credit benefits passed through to customers in our tracker mechanisms, which is offset by an increase in income tax expense.

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.



46



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
59.7

 
52.7

 
7.0

 
13.3

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(1)
$
703.1

 
$
678.8

 
$
24.3

 
3.6
 %
(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

 
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

 
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 (in millions):

47



 
Gross Margin 2017 vs. 2016
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

Change in Gross Margin Impacting Net Income
17.9

 
 
Gross Margin Items Offset Within Net Income
 
Property taxes recovered in trackers
4.9

Operating expenses recovered in trackers
1.5

Change in Items Offset Within Net Income