10-K 1 nwe1231201310k.htm FORM 10-K DECEMBER 31, 2013 NWE 12.31.2013 10K


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

For the fiscal year ended December 31, 2013

OR
£
 
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
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 past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for shorter period that the registrant was required to submit and post such files). Yes x No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).
Large Accelerated Filer x           Accelerated Filer o           Non-accelerated Filer o           Smaller Reporting Company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
 
The aggregate market value of the voting and non-voting common stock held by nonaffiliates of the registrant was $1,534,085,000 computed using the last sales price of $39.90 per share of the registrant’s common stock on June 30, 2013, the last business day of the registrant’s most recently completed second fiscal quarter.
 
As of February 14, 2014, 38,767,473 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 2014 Annual Meeting of Shareholders
are incorporated by reference into Part III of this Form 10-K

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INDEX
 
 
 
Part I
Page
 
 
 
 
Part II
 
 
 
 
 
Part III
 
 
 
 
 
Part IV
 



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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:
 
potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, as well as adverse determinations by regulators, 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.

In addition, actual results may differ materially from those contemplated in any forward-looking statement due to the timing and likelihood of the closing of the purchase of PPL Montana LLC's hydro-electric generating facilities (Hydro Transaction). See Note 3 - Acquisitions and Significant Events, to the Consolidated Financial Statements for additional information relative to this transaction.

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 annual and periodic reports filed with the Securities and Exchange Commission (SEC) on Forms 10-K, 10-Q and 8-K and Proxy Statements on Schedule 14A.

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


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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.

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

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).

Hinshaw Exemption - A pipeline company (defined by the Natural Gas Act (NGA) and exempted from FERC jurisdiction under the NGA) defined as a regulated company engaged in transportation in interstate commerce, or the sale in interstate commerce for resale, of natural gas received by that company from another person within or at the boundary of a state, if all the natural gas so received is ultimately consumed within such state. A pipeline company with a Hinshaw exemption may receive a certificate authorizing it to transport natural gas out of the state in which it is located, without giving up its Hinshaw exemption.

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 Area Power Pool (MAPP) - A voluntary association of electric utilities and other electric industry participants that acts as a regional transmission group, responsible for facilitating open access of the transmission system and a generation reserve sharing pool to meet regional demand.

Midwest Independent Transmission System Operator (MISO) - The 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.

Mountain States Transmission Intertie (MSTI) - Our proposed 500 kV transmission line from southwestern Montana to southeastern Idaho with a potential capacity of 1,500 MWs.

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


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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, a QF sells power to a regulated utility at a price determined by a public service commission that is intended to be equal to that which the utility would otherwise pay if it were to build its own power plant or buy power from another source.

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.

Sub-bituminous Coal - A coal whose properties range from those of lignite to those of bituminous coal and used primarily as fuel for steam-electric power generation. Sub-bituminous coal contains 20 to 30 percent inherent moisture by weight. The heat content of sub-bituminous coal ranges from 17 to 24 million Btu per ton on a moist, mineral-matter-free basis.

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 natural gas to approximately 678,200 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 were incorporated in Delaware in November 1923. Our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to such reports filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, 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. We maintain an Internet website at http://www.northwesternenergy.com. Our Internet website and the information contained therein or connected thereto are not intended to be incorporated by reference into this Annual Report on Form 10-K and should not be considered a part of this Annual Report on Form 10-K.
 
We operate our business in the following reporting segments:
 
Electric operations;
 
Natural gas operations;
 
All other, which primarily consists of a remaining unregulated natural gas contract, the wind down of our captive insurance subsidiary and our unallocated corporate costs.

SIGNIFICANT DEVELOPMENTS

Hydro Transaction

On September 26, 2013, we entered into an agreement with PPL Montana, LLC (PPL Montana), a wholly owned subsidiary of PPL Corporation, to purchase PPL Montana's hydro-electric generating facilities and associated assets located in Montana, which includes approximately 633 megawatts of hydro-electric generation capacity, for a purchase price of $900 million (Hydro Transaction). Assuming receipt of reasonably satisfactory regulatory approvals, we expect this transaction to close in the second half of 2014. See Note 3 - Acquisitions and Significant Events, to the Consolidated Financial Statements for additional information relative to this transaction.

ELECTRIC OPERATIONS

MONTANA

Our regulated electric utility business in Montana includes generation, transmission and distribution. Our service territory covers approximately 107,600 square miles, representing approximately 73% of Montana's land area, and includes a 2010 census population of approximately 875,700. We deliver electricity to approximately 344,500 customers in 187 communities and their surrounding rural areas, 15 rural electric cooperatives and in Wyoming to the Yellowstone National Park. In 2013, by category, residential, commercial, industrial, and other sales accounted for approximately 37%, 44%, 6%, and 13%, respectively, of our Montana regulated electric utility revenue. We also transmit electricity for nonregulated entities owning generation facilities, other utilities and power marketers serving the Montana electricity market. The total control area peak demand was approximately 1,730 MWs, with approximately 1,227 MWs per hour for the year on average, and energy delivered of more than 10.7 million MWHs during the year ended December 31, 2013. Our Montana electric distribution system consists of approximately 17,500 miles of overhead and underground distribution lines and 386 transmission and distribution substations.
 
Our Montana electric transmission system consists of approximately 6,900 miles of transmission lines, ranging from 50 to 500 kV, 288 circuit segments and approximately 104,000 transmission poles on approximately 76,000 structures with

7



associated transformation and terminal facilities, and extends throughout the western two-thirds of Montana from Colstrip in the east to Thompson Falls in the west. The system has interconnections with six major nonaffiliated transmission systems located in the WECC area, including a 2013 interconnection to Alberta, Canada, as well as one interconnection to a nonaffiliated system that connects with the MAPP region. We are directly interconnected with Avista Corporation; Idaho Power Company; PacifiCorp; the Bonneville Power Administration; WAPA; and the 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.

Our current annual retail electric supply load requirements average approximately 750 MWs, with a peak load of approximately 1,200 MWs, and are supplied by contracted and owned resources and market purchases with multiple counterparties. Owned generation resources supplied approximately 30% of our retail load requirements for 2013. We have a power purchase agreement with PPL Montana for 200 MWs of on-peak supply and 125 MWs of off-peak supply through June 2014. We also purchase power under QF contracts entered into under the Public Utility Regulatory Policies Act of 1978, which provide a total of 174 MWs of contracted capacity, including capacity from waste petroleum coke and waste coal and 87 MWs of capacity from hydro and wind resources located in Montana. We have several other long and medium-term power purchase agreements including contracts for 135 MWs of renewable wind generation and 21 MWs of seasonal base-load hydro supply. We file a biennial Electric Supply Resource Procurement Plan with the MPSC, which guides future resource acquisition activities. Our most recent plan was filed in December 2013. Including both owned and contracted resources, for 2014 we have resources to provide 88% of the energy requirements necessary to meet our forecasted retail load requirements.

We have a 30% joint ownership interest in Colstrip Unit 4, which provides base-load supply and is operated by PPL Montana. PPL Montana has a 30% joint ownership interest in Colstrip Unit 3. We have a risk sharing agreement with PPL Montana regarding the operation of Colstrip Units 3 and 4, where 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. We also own the 40 MW Spion Kop wind project, which we purchased and placed into service in 2012. Details of our generating facilities are described further in the chart below.
Name and Location of Plant
 
Fuel Source
 
Plant Capacity (MW)
 
Ownership
Interest
 
Demonstrated
Capacity (MW)
Colstrip Unit 4, located near Colstrip in southeastern Montana
 
Sub-bituminous coal
 
740

 
30
%
 
222

Spion Kop Wind, located in Judith Basin County in Montana
 
Wind
 
40

 
100
%
 
40


The Dave Gates Generating Station at Mill Creek (DGGS), a 150 MW natural gas fired facility, provides regulation service (in place of previously contracted services). The facility normally operates with two units, with a third unit available as an operating spare. With the two units, DGGS is capable of providing up to 93 MW of regulation service under optimum conditions. The third unit can be placed into service which, together with the two units, can provide up to 105 MW of capacity which is our current peak regulation requirement. In addition, DGGS provided approximately 7 MWs of retail base-load requirements in 2013.
Name and Location of Plant
 
Fuel Source
 
Plant Capacity (MW)
 
Ownership
Interest
 
Regulation
Capacity (MW)
Dave Gates Generating Station, located near Anaconda, Montana
 
Natural Gas
 
150

 
100
%
 
105


Renewable portfolio standards (RPS) enacted in Montana require that 10% of our annual electric supply portfolio be derived from eligible renewable sources, including resources such as wind, biomass, solar, and small hydroelectric. In 2015, the RPS requirement increases to 15%. We can use renewable energy credits (RECs) to satisfy the RPS. 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.


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The following is a summary of our RPS requirements and RECs over the last three years:

 
December 31,
 
2013
 
2012
 
2011
RPS
10%
 
10%
 
10%
 
 
 
 
 
 
RECs beginning of period
94,258

 
152,065
 
191,959

RECs generated
832,889

 
537,088
 
535,218

RPS requirement
(593,140
)
 
(594,895)
 
(575,112
)
Estimated Excess RECs carried forward
334,007

 
94,258
 
152,065


The amounts in the table above reflect estimates of the RECs for the year, with the final amounts determined in the following year and any prior year adjustment is reflected in the RECs generated. The penalty for not meeting the RPS is up to $10 per MWH for each REC short of the requirement. Given our portfolio of resources, including the addition of the Spion Kop wind project and carry forward RECs, we believe we will meet the Montana RPS requirements through at least 2028.

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 62,100 customers in 110 communities in South Dakota. In 2013, by category, residential, commercial and other sales accounted for approximately 38%, 55%, and 7%, respectively, of our South Dakota electric utility revenue. Peak demand was approximately 326 MWs, the average daily load was approximately 179 MWs, and more than 1.56 million MWHs were supplied during the year ended December 31, 2013.
 
Our transmission and distribution network in South Dakota consists of approximately 3,350 miles of overhead and underground transmission and distribution lines as well as 123 substations. We have interconnection and pooling arrangements 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. These interconnection and pooling arrangements enable us to arrange purchases or sales of substantial quantities of electric power and energy with other pool members and to participate in the efficiency benefits of pool arrangements.
 
Our electric supply load requirements are primarily provided by power plants that we own jointly with unaffiliated parties. Each of the jointly owned plants is subject to a joint management structure. We are not the operator of any of these plants. Except as otherwise noted, based upon our ownership interest, we are entitled to a proportionate share of the electricity generated in our jointly owned plants and are responsible for a proportionate share of the operating expense. During periods of lower demand, electricity in excess of our load requirements is sold in the competitive wholesale market. In 2013, this was approximately 6% of our share of the power generated. We estimate our base-load generation capacity is adequate to meet customer supply needs through at least 2015.

We use market purchases and peaking generation to provide peak supply in excess of our base-load capacity. We entered into an agreement with Basin Electric Power Cooperative to supply firm capacity of 11 MW in 2013, 15 MW in 2014, and 19 MW in 2015. 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 completed construction of a 60 MW simple cycle peaking facility located in Aberdeen, South Dakota and placed it in operation during April 2013. We also have several wholly owned peaking/standby generating units at seven locations throughout our service territory.


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Details of our generating facilities are described further in the chart below.

Name and Location of Plant
 
Fuel Source
 
Plant Capacity (MW)
 
Ownership
Interest
 
Demonstrated
Capacity (MW)
Big Stone Plant, located near Big Stone City in northeastern South Dakota
 
Sub-bituminous coal
 
475

 
23.4
%
 
111.15

Coyote I Electric Generating Station, located near Beulah, North Dakota
 
Lignite coal
 
427

 
10.0
%
 
42.70

Neal Electric Generating Unit No. 4, located near Sioux City, Iowa
 
Sub-bituminous coal
 
644

 
8.7
%
 
56.11

Aberdeen Generating Unit, located near Aberdeen, South Dakota
 
Natural gas
 
60

 
100.0
%
 
43.87

Miscellaneous combustion turbine units and small diesel units (used only during peak periods)
 
Combination of fuel oil and natural gas
 
 
 
100.0
%
 
106.13

Total Capacity
 
 
 
 
 
 
 
359.96


For the year ended December 31, 2013, 93% of the electricity utilized in South Dakota came from coal, 6% came from a wind purchased power contract, and 1% came from natural gas and fuel oil.
 
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.
 
Instead of an RPS, South Dakota has a voluntary renewable and recycled energy objective. The objective states that 10% of all electricity sold at retail within South Dakota by 2015 be obtained from renewable energy and recycled energy sources. In 2013, approximately 5.4% of the South Dakota retail needs were generated from renewable resources.

Our South Dakota operations are a member of the MAPP, which is an area power pool arrangement consisting of utilities and power suppliers having transmission interconnections located in a nine-state area in the North Central region of the United States and in two Canadian provinces. WAPA is a member of MAPP. We are within WAPA's balancing authority and are transmission dependent on WAPA. WAPA has announced that it is evaluating joining the Southwest Power Pool (SPP) regional transmission organization by the end of 2015. Due to our transmission ties with WAPA, we have also begun an evaluation process of alternatives should WAPA move from MAPP. The terms and conditions of our agreements with MAPP and WAPA are subject to the jurisdiction of FERC.
 
We have a contract through 2020 with WAPA for transmission services, including transmission of electricity from Big Stone, Coyote, and Neal #4 to our South Dakota service areas through seven points of interconnection on WAPA's system. Transmission services under this agreement, and our costs for such services, are variable and depend upon a number of factors, including the respective parties' system peak demand and the number of our transmission assets that are integrated into WAPA's system. In 2013, our costs for services under this contract totaled approximately $4.5 million. Our tariffs in South Dakota generally allow us to pass through these transmission costs to our customers.


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NATURAL GAS OPERATIONS

MONTANA

We distribute natural gas to approximately 184,300 customers in 105 Montana communities, along with propane to 563 customers in the Townsend area. We also serve several smaller distribution companies that provide service to approximately 32,000 customers. Our natural gas distribution system consists of approximately 5,000 miles of underground distribution pipelines. 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 Bcf, and our peak capacity was approximately 335,000 dekatherms per day during the year ended December 31, 2013.
 
Our natural gas transmission system consists of more than 2,000 miles of pipeline, which vary in diameter from two inches to 24 inches, and serve more than 130 city gate stations. We have connections in Montana with four major, nonaffiliated transmission systems: Williston Basin Interstate Pipeline, NOVA Gas Transmission Ltd., Colorado Interstate Gas, and Spur Energy. Seven compressor sites provide more than 42,000 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.
 
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.
 
We have municipal franchises to transport and distribute natural gas in the Montana communities we serve. The terms of the franchises vary by community. They typically have a fixed 30 - 50 year term and continue indefinitely unless and until terminated by ordinance. Our policy generally is to seek renewal or extension of a franchise in the last year of its fixed term. We currently have 12 franchises, which account for approximately 41,000 or approximately 22 percent of our natural gas customers, where the fixed term has expired. We continue to serve those customers while we obtain formal renewals. During the next five years, seven additional municipal franchises are scheduled to reach the end of their fixed term. We do not anticipate termination of any of these franchises.
Natural gas is used 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, 2013, were approximately 20.0 Bcf. Our Montana natural gas supply requirements for fuel for the year ended December 31, 2013, were approximately 6 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 primarily fulfilled through third-party fixed-term purchase contracts and short-term market purchases. 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 the major natural gas producing regions in the United States, primarily the Rockies (Colorado), Montana, and Alberta, Canada.
 
Since 2010, we have acquired gas production and gathering system assets as a part of an overall strategy to provide rate stability and customer value through the addition of regulated assets that are not subject to market forces. As of December 31, 2013, these owned reserves total approximately 76.7 Bcf and are estimated to provide approximately 6.4 Bcf each year, or about 32 percent of our current annual natural gas load in Montana.

We file a biennial Natural Gas Procurement Plan, which provides the MPSC the procurement blueprint we intend to follow to meet our gas supply needs and reliability requirements and hedging strategies used to reduce price volatility. Our last filing was in December 2012.

 SOUTH DAKOTA AND NEBRASKA

We provide natural gas to approximately 86,700 customers in 60 South Dakota communities and four Nebraska communities. We have approximately 2,350 miles of underground distribution pipelines and 55 miles of transmission pipeline in South Dakota and Nebraska. In South Dakota, we also transport natural gas for eight gas-marketing firms and three large end-user accounts, currently serving 81 customers through our distribution systems. In Nebraska, we transport natural gas for four gas-marketing firms and one end-user account, servicing 68 customers through our distribution system. We delivered approximately 25.8 Bcf of third-party transportation volume on our South Dakota distribution system and approximately 3.2 Bcf of third-party transportation volume on our Nebraska distribution system during 2013.
 

11



We have municipal franchises to purchase, transport and distribute natural gas in the South Dakota and Nebraska communities we serve. 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. During the next five years, 11 of our South Dakota franchises are scheduled to reach the end of their fixed term. We do not anticipate termination of any of these franchises.

Our South Dakota natural gas supply requirements for the year ended December 31, 2013, were approximately 6.3 Bcf. We have contracted 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.
 
Our Nebraska natural gas supply requirements for the year ended December 31, 2013, were approximately 4.6 Bcf. We have contracted with a third party under an asset management agreement that includes pipeline capacity, supply, and asset optimization activities.
 
To supplement firm gas supplies in South Dakota and Nebraska, we contract for firm natural gas storage services to meet the heating season and peak day requirements of our natural gas customers.

REGULATION

Base rates are the rates we are allowed to charge our customers for the cost of providing delivery service, plus a reasonable rate of return on invested capital. We have both electric and natural gas base rates. We may ask the respective regulatory commission to increase base rates from time to time. We have historically been allowed to increase base rates to recover our utility plant investment and operating costs, plus a return on our capital investment. Rate increases are normally granted based on historical data and those increases may not always keep pace with increasing costs. Other parties may petition the respective regulatory commission to decrease base rates. 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 (4)
 
January 2011
 
632.5

 
774.5

 
7.8
%
10.25
%
48
%
Montana - DGGS (4)
 
January 2011
 
172.7

 
137.5

 
8.16
%
10.25
%
50
%
Montana - Colstrip Unit 4
 
January 2009
 
400.4

 
343.8

 
8.25
%
10.00
%
50
%
Montana Spion Kop
 
December 2012
 
81.7

 
62.0

 
7.0
%
10.00
%
48
%
Montana natural gas delivery
 
June 2013
 
309.2

 
362.7

 
7.48
%
9.80
%
48
%
Montana natural gas production
 
November 2012
 
12.0

 
85.6

 
7.65
%
10.00
%
48
%
South Dakota electric
 
September 1981
 
186.7

 
251.0

 
n/a

n/a

n/a

South Dakota natural gas (3)
 
December 2011
 
65.9

 
64.0

 
7.8
%
n/a

n/a

Nebraska natural Gas (3)
 
December 2007
 
24.3

 
25.4

 
n/a

10.40
%
n/a

 
 
 
 
$
1,885.4

 
$2,106.5
 
 
 
 
(1)    Rate base reflects amounts on which we are authorized to earn a return.
(2)    Rate base amounts are estimated as of December 31, 2013.
(3)    For those items marked as "n/a," the respective settlement and/or order was not specific as to these terms.
(4)    The FERC regulated portion of Montana electric transmission and DGGS are included as revenue credits to our MPSC jurisdiction customers. Therefore, we do not separately reflect FERC authorized rate base or authorized returns.

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


12



Electric and Natural Gas Supply Trackers - Rates for our Montana electric and natural gas supply are set by the MPSC. 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 electric and 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 electric and 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 60% of the change in property taxes. Adjusted rates are typically effective January 1st of each year.
 
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, as well as various incentive riders to encourage business development. 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. Usage for these customers is monitored daily by us through electronic metering equipment and balanced against 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.
 
Federal
 
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, 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, as amended, governing the communication of non-public information between our transmission employees and wholesale merchant employees.
 
In Montana, we sell transmission service, including ancillary services, across our system under terms, conditions and rates defined in our OATT, on file with FERC. We are required to provide retail transmission service in Montana under MPSC approved tariffs for customers still receiving “bundled" service and under the OATT for other wholesale transmission customers such as cooperatives.
 

13



Our South Dakota transmission operations underlie the MISO system and are part of the WAPA Control Area. The Coyote and Big Stone power plants in which we are a joint owner, are connected directly to the MISO system, and we have ownership rights in the transmission lines from these plants to our distribution system. We have negotiated a settlement as a grandfathered agreement with MISO and the other Big Stone, Neal #4, and Coyote power plant joint owners related to providing MISO with the information it needs to operate its system, while exempting us from assignment of MISO operational costs. We do not participate in the MISO markets directly as we utilize WAPA to handle our scheduling and power marketing activities. MISO provides the reliability coordinator functions for MAPP. We updated the South Dakota OATT to accommodate the required planning functions that rely heavily on MAPP's planning process and MAPP's coordination with MISO.
 
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 that is subject to FERC jurisdiction, but through a Hinshaw Exemption the FERC has allowed the MPSC to set the rates for this interstate service. We have capacity agreements in South Dakota with interstate pipelines that are subject to FERC jurisdiction.
 
Reliability Standards - NERC establishes, and regional reliability organizations enforce, mandatory reliability standards (Reliability Standards) regarding the bulk power system. The FERC oversees this process and independently enforces the Reliability Standards.
 
The Reliability Standards have the force and effect of law and apply to certain users of the bulk power electricity system, including electric utility companies, generators and marketers. The FERC enforces the Reliability Standards using, among other means, civil penalty authority. Under the Federal Power Act, the FERC may assess civil penalties of up to $1 million per day, per violation, for certain violations.  
 
We must comply with the standards and requirements, which 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 interconnections. Additional standards continue to be developed and will be adopted in the future. We expect that the existing standards will change often as a result of modifications, guidance and clarification following industry implementation and ongoing audits and enforcement.
 
SEASONALITY AND CYCLICALITY
 
Our electric and gas utility businesses are seasonal businesses, and weather patterns can have a material impact on operating performance. Because natural gas is used primarily for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Demand for electricity is often greater in the summer and winter months for cooling and heating, respectively. Accordingly, our operations have historically generated less revenue and income when weather conditions are milder in the winter and cooler in the summer. When we experience unusually mild winters or summers in the future, these weather patterns could adversely affect our results of operations, financial condition and liquidity.

ENVIRONMENTAL

The operation of electric generating, transmission and distribution facilities, and gas gathering, 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 20 - Commitments and Contingencies, to the Consolidated Financial Statements.


14



EMPLOYEES

As of December 31, 2013, we had 1,493 employees. Of these, 1,167 employees were in Montana and 326 were in South Dakota or Nebraska. Of our Montana employees, 415 were covered by six collective bargaining agreements involving five unions. All six of these agreements were renegotiated in 2012 for terms of four years. In addition, our South Dakota and Nebraska operations had 193 employees covered by the System Council U-26 of the International Brotherhood of Electrical Workers. This collective bargaining agreement expires on December 31, 2016. We consider our relations with employees to be good.

Executive Officers
Executive Officer
 
Current Title and Prior Employment
 
Age on Feb. 14, 2014
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).
 
58
 
 
 
 
 
Brian B. Bird
 
Vice President and Chief Financial Officer since December 2003. Prior to joining NorthWestern, Mr. Bird was Chief Financial Officer and Principal of Insight Energy, Inc., a Chicago-based independent power generation development company (2002-2003). Previously, he was Vice President and Treasurer of NRG Energy, Inc., in Minneapolis, MN (1997-2002). Mr. Bird serves on the board of directors of a NorthWestern subsidiary.
 
51
 
 
 
 
 
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.
 
51
 
 
 
 
 
Patrick R. Corcoran
 
Vice President-Government and Regulatory Affairs since December 2004; formerly Vice President-Regulatory Affairs since February 2002; formerly Vice President-Regulatory Affairs for the former Montana Power Company (2000-2002).
 
62
 
 
 
 
 
Heather H. Grahame
 
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).
 
58
 
 
 
 
 
John D. Hines
 
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).
 
55
 
 
 
 
 
Kendall G. Kliewer
 
Vice President and Controller since August 2006; Controller since June 2004; formerly Chief Accountant since November 2002. Prior to joining NorthWestern, Mr. Kliewer was a Senior Manager at KPMG LLP (1999-2002).
 
44
 
 
 
 
 
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.
 
49
 
 
 
 
 
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.
 
45

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.



15



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 government and regulatory outcomes, including extensive and changing laws
and regulations that affect our industry and our operations, which could have a material adverse effect on our liquidity and results of operations.
 
Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. We provide service at rates established by several regulatory commissions. These rates are generally set based on an analysis of our costs incurred in a historical test year. In addition, each regulatory commission sets rates based in part upon their acceptance of an allocated share of total utility costs. When commissions adopt different methods to calculate inter-jurisdictional cost allocations, some costs may not be recovered. Thus, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs.
 
For example, in our regulatory filings related to DGGS, we proposed an allocation of approximately 80% of costs to retail customers subject to the MPSC's jurisdiction and approximately 20% allocated to wholesale customers subject to FERC's jurisdiction. In March 2012, the MPSC's final order approved using our proposed cost allocation methodology, but requires us to complete a study of the relative contribution of retail and wholesale customers to regulation capacity needs. The results of this study may be used in determining future cost allocations between retail and wholesale customers. However, there is no assurance that both the MPSC and FERC will agree on the results of this study, which could result in an inability to fully recover our costs.

In September 2012, we received a non-binding decision from a FERC Administrative Law Judge (ALJ) concluding that we should only recover approximately 4.4% of the revenue requirement from FERC jurisdictional customers. Although we are asking the FERC to reject this decision, there is significant uncertainty related to the FERC's ultimate treatment of our cost allocation methodology, which could result in an inability to fully recover our costs.

In October 2013, the MPSC concluded that $1.4 million of incremental costs associated with regulation service acquired from third parties during a 2012 outage at DGGS were imprudently incurred, and disallowed recovery. We have appealed that decision to the Montana district court. While we believe this to be an isolated incident associated with specific circumstances at DGGS, the MPSC may use this determination as precedent for disallowing replacement costs in the future.
 
We are subject to many FERC rules and orders that regulate our electric and natural gas business. We must also comply with established reliability standards and requirements, which 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. The FERC, NERC, or a regional reliability organization may assess penalties against any responsible entity that violates their rules, regulations or standards. Violations may be discovered through various means, including self-certification, self-reporting, compliance investigations, periodic data submissions, exception reporting, and complaints. Penalties for the most severe violations can reach as high as $1 million per violation, per day. If a serious reliability incident or other incidence of noncompliance did occur, it could have a material adverse effect on our operating and financial results.
 

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

16



National and international actions have been initiated to address global climate change and the contribution of greenhouse gas (GHG) emissions including, most significantly, carbon dioxide. These actions include legislative proposals, executive and EPA actions at the federal level, actions at the state level, and private party litigation relating to GHG emissions. In June 2013, President Obama announced that he would use Executive Powers to require reductions in the amount of carbon dioxide emitted by the nation's power plants. Under the President's plan, it is possible that existing power plants may be required to comply with GHG emission performance standards as soon as July, 2016. If legislation or regulations are passed at the federal or state levels imposing mandatory reductions of carbon dioxide and other GHGs on generation facilities, the cost to us of such reductions could be significant.
 
Many of these environmental laws and regulations provide for substantial civil and criminal fines for noncompliance which, if imposed, could result in material costs or liabilities. In addition, there is a risk of environmental damages claims from private parties or government entities. We may be required to make significant expenditures in connection with the investigation and remediation of alleged or actual spills, personal injury or property damage claims, and the repair, upgrade or expansion of our facilities to meet future requirements and obligations under environmental laws.
 
To the extent that costs exceed our estimated environmental liabilities and/or we are not successful recovering a material portion of remediation costs in our rates, our results of operations and financial position could be adversely affected.

Our plans for future expansion through the acquisition of assets including hydro-electric generating facilities and natural gas reserves, capital improvements to current assets, generation investments, and transmission grid expansion involve substantial risks.
 
Acquisitions include a number of risks, including but not limited to, 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, securing adequate capital to support the transaction, and regulatory approval. Uncertainties 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 complete an acquisition successfully, or to integrate future acquisitions that we may choose to undertake could have an adverse effect on our financial condition and results of operations.

In order to complete the Hydro Transaction, we must obtain certain approvals from the MPSC and other state and federal agencies. These regulatory agencies may not approve the transaction, or may approve the transaction subject to terms or conditions that could delay closing, impose additional costs, impact the transaction's anticipated benefits, or cause the transaction to terminate. In addition, failure to obtain approvals on terms consistent with our application could negatively affect credit ratings and equity valuation, and our ability to invest in our Montana utility operations, including but not limited to supply.

In connection with the Hydro Transaction, we entered into a $900 million 364-day senior bridge credit facility (bridge facility), which may be used to temporarily finance a significant portion of the acquisition and pay related fees and expenses in the event that permanent financing is not in place at the time of the closing of the transaction. The permanent financing is anticipated to include a mix of long-term debt and common equity. Although we believe we have taken prudent steps to position ourselves for successful capital raises, there can be no assurance as to the ultimate cost or availability of permanent financing.
 
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.

Our owned and jointly owned electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.
 
Operation of electric generating facilities involves risks, which can adversely affect energy output and efficiency levels. Operational risks include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error, catastrophic events such as fires, explosions, floods, and intentional acts of destruction or other similar occurrences

17



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.

For example, in early July 2013, following the return to service from a scheduled maintenance outage, Colstrip Unit 4 tripped off-line and incurred damage to its stator and rotor. Colstrip Unit 4 returned to service in early 2014. There is no assurance that we will be able to fully recover our costs for the purchase of replacement power while Colstrip Unit 4 was out of service.

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

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 population growth as well as by economic factors. Our customers may voluntarily reduce their consumption of electricity and natural gas from us in response to increases in prices, decreases in their disposable income, individual energy conservation efforts or the use of distributed generation for electricity.

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, transmission availability and the availability of generation for wholesale sales, 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.

We implemented a new customer information system, and we may experience additional difficulties, delays and interruptions associated with the transition to this new system. Any unexpected significant difficulties in completing the transition could negatively impact our business.

During September 2013, we implemented a new customer information system. There are inherent risks associated with replacing and changing these types of systems, such as delayed and / or inaccurate customer bills, potential disruption of our business, and substantial unplanned costs, any of which could harm our reputation and have a material adverse effect on our business, financial condition or results of operations.

Consistent with our expectations, we have experienced billing delays, which resulted in delays in collections of customer receivables and increased bad debt expense during the transition to this new system. Any additional unexpected significant difficulties in completing the transition of our customer information system could materially impact our ability to timely and accurately record, process and report information that is important to our business.

Our natural gas distribution services involve numerous activities that may result in accidents and other operating risks and costs.
 
Inherent in our natural gas distribution services are a variety of hazards and operating risks, such as leaks, explosions and mechanical problems. These risks could cause a loss of human life, significant damage to property, environmental pollution, impairment of our operations, and substantial financial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. For our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks potentially is greater.
 

18



To the extent our incurred supply costs are deemed imprudent by the applicable state regulatory commissions, we would not recover some of our costs, which could adversely impact our results of operations and liquidity.
 
Our wholesale costs for electricity and natural gas are recovered through various pass-through cost tracking mechanisms in each of the states we serve. The rates are established based upon projected market prices or contractual obligations. As these variables change, we adjust our rates through our monthly trackers. To the extent our energy supply costs are deemed imprudent by the applicable state regulatory commissions, we would not recover some of our costs, which could adversely impact our results of operations.
 
We currently procure a large portion of our natural gas supply and our Montana electric supply pursuant to contracts with third-party suppliers. In light of this reliance on third-party suppliers, we are exposed to certain risks in the event a third-party supplier is unable to satisfy its contractual obligation. If this occurred, then we might be required to purchase gas and/or electricity supply requirements in the energy markets, which may not be on favorable terms, if at all. If prices were higher in the energy markets, it could result in a temporary material under recovery that would reduce our liquidity.
 
Poor investment performance of plan assets of our defined benefit pension and post-retirement benefit plans, in addition to other factors impacting these costs, could unfavorably impact our results of operations and liquidity.
 
Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors. Assumptions related to future costs, return on investments and interest rates have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance and changes in governmental regulations. Without sustained growth in the plan assets over time and depending upon interest rate changes as well as other factors noted above, the costs of such plans reflected in our results of operations and financial position and cash funding obligations may change significantly from projections.
 
Our obligation to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWH could expose us to material commodity price risk if certain QFs under contract with us do not perform during a time of high commodity prices, as we are required to make up the difference. In addition, we are subject to price escalation risk with one of our largest QF contracts.
 
As part of a stipulation in 2002 with the MPSC and other parties, we agreed to include a minimum annual quantity of power in our Montana electric supply portfolio at an agreed upon price per MWH through June 2029. The annual minimum energy requirement is achievable under normal QF operations, including normal periods of planned and forced outages. However, to the extent the supplied QF power for any year does not reach the minimum quantity set forth in the settlement, we are obligated to purchase the difference from other sources. The anticipated source for any QF shortfall is the wholesale market, which would subject us to commodity price risk if the cost of replacement power is higher than contracted QF rates.
 
In addition, we are subject to price escalation risk with one of our largest QF contracts due to variable contract terms. In estimating our QF liability, we have estimated an annual escalation rate of 3% over the remaining term of the contract (through June 2024). To the extent the annual escalation rate exceeds 3%, our results of operations, cash flows and financial position could be adversely affected.

Weather and weather patterns, including normal seasonal and quarterly fluctuations of weather, as well as extreme weather events that might be associated with climate change, could adversely affect our results of operations and liquidity.
 
Our electric and natural gas utility business is seasonal, and weather patterns can have a material impact on our financial performance. Demand for electricity and natural gas is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our market areas, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenue and income when weather conditions are milder in the winter and cooler in the summer. In the event that we experience unusually mild winters or cool summers in the future, our results of operations and financial position could be adversely affected. 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.
 
There is also a concern that the physical risks of climate change could include changes in weather conditions, such as an increase in changes in 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

19



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. Severe weather impacts our service territories, primarily through thunderstorms, tornadoes and snow or ice storms. To the extent the frequency of extreme weather events increase, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages could adversely affect our ability to provide electricity to customers, as well as increase the price they pay for energy. In addition, extreme weather may exacerbate the risks to physical infrastructure. We may not recover all costs related to mitigating these physical and financial risks.
 
Our business is dependent on our ability to successfully access capital markets on favorable terms. Limits on our access to capital may adversely impact our ability to execute our business plan or pursue improvements that we would otherwise rely on for future growth.

Our cash requirements are driven by the capital-intensive nature of our business. Access to the capital and credit markets, at a reasonable cost, is necessary for us to fund our operations, including capital requirements. We rely on a revolving credit facility and commercial paper market for short-term liquidity needs due to the seasonality of our business, and on capital markets to raise capital for growth projects that are not otherwise provided by operating cash flows. Instability in the financial markets may increase the cost of capital, limit our ability to draw on our revolving credit facility, access the commercial paper market and/or raise capital. If we are unable to obtain the liquidity needed to meet our business requirements on favorable terms, we may defer growth projects and/or capital expenditures.
 
We must meet certain credit quality standards. If we are unable to maintain investment grade credit ratings, our liquidity, access to capital and operations could be materially adversely affected.
 
A downgrade of our credit ratings to less than investment grade could adversely affect our liquidity. Certain of our credit agreements and other credit arrangements with counterparties require us to provide collateral in the form of letters of credit or cash to support our obligations if we fall below investment grade. Also, a downgrade below investment grade could hinder our ability to raise capital on favorable terms, including through the commercial paper markets. Higher interest rates on short-term borrowings with variable interest rates or on incremental commercial paper issuances could also have an adverse effect on our results of operations.
 
Threats of terrorism and catastrophic events that could result from terrorism, cyber attacks, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may affect our operations
in unpredictable ways and could adversely affect our liquidity and results of operations.

We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber attacks and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities, information technology systems and other infrastructure facilities and systems could be direct targets of, or indirectly affected by, such activities. Any significant interruption of these systems could prevent us from fulfilling our critical business functions, and sensitive, confidential and other data could be compromised.

Terrorist acts, cyber attacks (such as hacking and viruses) or other similar events could harm our business by limiting our ability to generate, purchase or transmit power and by delaying the development and construction of new generating facilities and capital improvements to existing facilities. 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 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.




20



ITEM 1B.  UNRESOLVED STAFF COMMENTS

None

ITEM 2.  PROPERTIES

NorthWestern's corporate support office is located at 3010 West 69th Street, Sioux Falls, South Dakota 57108, where we lease approximately 20,000 square feet of office space, pursuant to a lease that expires on November 30, 2017.

Our operational support office for our Montana operations is owned by us and located at 40 East Broadway Street, Butte, Montana 59701. We own or lease other facilities throughout the state of Montana. Our operational support office for our South Dakota and Nebraska operations is owned by us and located at 600 Market Street W., Huron, South Dakota 57350. Substantially all of our South Dakota and Nebraska facilities are owned.

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 20 - 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.



21



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 14, 2014, there were approximately 40,821 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 on our common stock in the future, 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 2013. Quarterly dividends were declared and paid on our common stock during 2013 as set forth in the table below.

QUARTERLY COMMON STOCK PRICE RANGES AND DIVIDENDS


 
Prices
 
 
 
High
 
Low
 
Cash Dividends Paid
2013-
 
 
 
 
 
Fourth Quarter
$
47.18

 
$
41.31

 
$
0.38

Third Quarter
45.85

 
39.08

 
0.38

Second Quarter
43.17

 
38.12

 
0.38

First Quarter
40.35

 
35.06

 
0.38

2012
 
 
 
 
 
Fourth Quarter
$
36.70

 
$
32.98

 
$
0.37

Third Quarter
37.96

 
35.44

 
0.37

Second Quarter
37.05

 
33.72

 
0.37

First Quarter
36.39

 
34.22

 
0.37


On February 14, 2014, the last reported sale price on the NYSE for our common stock was $46.34.




22




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,
 
2013
 
2012
 
2011
 
2010
 
2009
Financial Results (in thousands, except per share data)
 
 
 
 
 
 
 
 
 
Operating revenues
$
1,154,519

 
$
1,070,342

 
$
1,117,316

 
$
1,110,720

 
$
1,141,910

Net income
93,983

 
98,406

 
92,556

 
77,376

 
73,420

Basic earnings per share
2.46

 
2.67

 
2.55

 
2.14

 
2.03

Diluted earnings per share
2.46

 
2.66

 
2.53

 
2.14

 
2.02

Dividends declared & paid per common share
1.52

 
1.48

 
1.44

 
1.36

 
1.34

Financial Position
 
 
 
 
 
 
 
 
 
Total assets
$
3,715,260

 
$
3,485,533

 
$
3,210,438

 
$
3,037,669

 
$
2,795,132

Long-term debt and capital leases, including current portion and short-term borrowings
1,327,604

 
1,211,182

 
1,110,063

 
1,103,922

 
1,024,186

Ratio of earnings to fixed charges
2.5

 
2.7

 
2.5

 
2.5

 
2.3




23




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 industry 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 678,200 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 2013, 2012 and 2011. Following is a brief overview of highlights for 2013, and a discussion of our strategy and outlook.

SIGNIFICANT ITEMS

Significant items for the year ended December 31, 2013 include:
 
On September 26, 2013, we entered into an agreement to purchase hydro-electric generating facilities with approximately 633 megawatts of generation capacity, which is expected to close in the second half of 2014.
Acquired additional natural gas production interests in Montana for approximately $68.7 million.
Placed into service the Aberdeen Generating Station, a 60 MW natural gas peaking facility, which was constructed for a total cost of approximately $54.3 million.
Received approval from the MPSC to increase rates effective April 1, 2013, in our natural gas distribution rate case.
Successfully accessed the capital markets to fund growth projects and extend debt maturities as follows:
Received proceeds of approximately $56.8 million after commissions and other fees from the sale of 1,381,494 common shares under our Equity Distribution Agreement,
Extended the maturity date of our revolving credit facility to November 5, 2018, and
Issued $35 million of First Mortgage Bonds at 3.99% and $65 million of First Mortgage Bonds at 4.85%, maturing in 2028 and 2043, respectively.

Hydro Transaction
On September 26, 2013, we entered into an agreement with PPL Montana, LLC (PPL Montana), a wholly owned subsidiary of PPL Corporation, to purchase PPL Montana's hydro-electric generating facilities and associated assets located in Montana, which includes approximately 633 megawatts of hydro-electric generation capacity, for a purchase price of $900 million (Hydro Transaction). The purchase price will be subject to a number of adjustments, including the proration of operating expenses, the performance of planned capital expenditures, and the termination of certain power purchase agreements.

The Hydro Transaction includes the Kerr Project, a 194 megawatt hydro-electric generating facility. The FERC license for the Kerr Project provides the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT) an option to acquire the facility between September 2015 and September 2025. We believe CSKT will exercise their option and acquire the Kerr Project in September 2015. PPL Montana and CSKT are currently involved in arbitration over the conveyance price of the Kerr Project. Under our agreement with PPL Montana, the $900 million purchase price includes a $30 million reference price to the Kerr Project. If CSKT exercises their option and ultimately pays more than $30 million for the Kerr Project, we will pay the difference to PPL Montana. If CSKT pays less than $30 million for the Kerr Project, PPL Montana will pay the difference to us.

Completion of the Hydro Transaction is subject to customary conditions and approvals, including approval from the FERC, the MPSC, other state and federal agencies and as required by the Hart-Scott-Rodino Antitrust Improvements Act. In December 2013, we submitted an application with the MPSC to acquire these assets, and in January 2014, we submitted three applications with the FERC concerning the Hydro Transaction. For further information on these filings see Note 4 - Regulatory Matters. Either party may terminate the agreement if the closing does not occur by September 26, 2014; however, this date will be extended for an additional six months if any governmental approval is still pending. Assuming receipt of reasonably satisfactory regulatory approvals, we expect the Hydro Transaction to close in the second half of 2014.

24




The permanent financing for the Hydro Transaction is anticipated to be a combination of long-term debt, new equity issuance and cash flows from operations. The Hydro Transaction is supported by a fully committed $900 million 364-day senior bridge credit facility (see Note 11 - Short-Term Borrowings).

During 2013, we incurred approximately $4.4 million of legal and professional fees associated with the Hydro Transaction and approximately $1.9 million of expenses related to the bridge credit facility.

If the acquisition is completed during the second half of 2014, we expect to sell any excess generation in the market and provide revenue credits to our Montana retail customers until CSKT exercises their option to acquire the Kerr Project. If CSKT exercises their option to acquire the Kerr Project in September 2015, we will own approximately 60 percent of our average electric load serving requirements in Montana.

Natural Gas Production Assets
In December 2013, we completed the purchase of additional natural gas production interests in northern Montana's Bear Paw Basin for approximately $68.7 million, subject to post-closing purchase price adjustments. This purchase includes an interest in the Havre Pipeline Company, LLC (Havre Pipeline), which represents approximately $6 million of the purchase price. As of December 31, 2013, the amount of net proven developed producing reserves associated with the acquisition was estimated to be 57.5 billion cubic feet. We estimate the current annual production associated with this acquisition to be approximately 24 percent of our total annual natural gas load in Montana, which increases our total owned production to approximately 32 percent. We expect the natural gas production interests acquired in 2013 to provide additional income before income taxes of approximately $3.7 million in 2014.

Aberdeen Generating Station
On April 30, 2013, we began commercial operations of the Aberdeen Generating Station, a 60 MW natural gas peaking facility located in Aberdeen, South Dakota. This facility was constructed for a total cost of $54.3 million and is intended to provide peaking reserve margin necessary to comply with capacity reserve requirements.

Montana Natural Gas Rate Increase
In September 2012, we filed a request with the MPSC for a natural gas delivery revenue increase of approximately $15.7 million. This request was based on a return on equity of 10.5%, a capital structure consisting of 52% debt and 48% equity
and rate base of $309.5 million.

In April 2013, we reached a joint settlement with intervenors and received MPSC approval to increase our annual natural
gas delivery rates by approximately $11.5 million, based on a return on equity of 9.8%.

Dave Gates Generating Station at Mill Creek (DGGS)
On January 1, 2011, we began commercial operations of DGGS, a 150 MW natural gas fired facility that provides regulating resources (in place of previously contracted ancillary services). DGGS was constructed for a total cost of $183 million, as compared to an original estimate of $202 million. Our regulatory filings seeking approval of rates related to DGGS are based on an allocation of approximately 80% of revenues related to the facility from retail customers being subject to the jurisdiction of the MPSC and approximately 20% of revenues allocated to wholesale customers subject to the jurisdiction of the FERC.

In March 2012, the MPSC issued a final order that found the total project costs incurred were prudent and established final rates. The MPSC's final order approves using our proposed cost allocation methodology on a temporary basis, and requires us to complete a study of the relative contribution of retail and wholesale customers to regulation capacity needs. The results of this study may be used in determining future cost allocations between retail and wholesale customers.

In our DGGS FERC proceedings, total project costs were not challenged and the parties to the case stipulated to the revenue requirement; however, intervenors challenged the allocation of costs. We proposed allocating 20% of the DGGS revenue requirement to FERC jurisdictional customers, based on our past practice of allocating 20% of the contracted costs for these services to FERC jurisdictional customers. A hearing was held in June 2012 before a FERC ALJ to consider this proposed allocation methodology.


25



In September 2012, we received an initial decision from the ALJ concluding that we should only recover approximately 4.4% of the revenue requirement from FERC jurisdictional customers. The ALJ's initial decision is nonbinding. As a result of the ALJ's nonbinding decision, we have cumulative deferred revenue of approximately $24.5 million, which is subject to refund and recorded within current regulatory liabilities in the Consolidated Balance Sheets.
                 
We do not know when the FERC will consider the matter and issue its decision. The FERC is not obligated to follow any of the ALJ's findings and conclusions, and the FERC can accept or reject the decision in whole or in part. If the FERC upholds the ALJ's decision and a portion of the costs are effectively disallowed, we would be required to assess DGGS for impairment. If we disagree with a decision issued by the FERC, we may pursue full appellate rights through rehearing and appeal to a United States Circuit Court of Appeals, which could extend into 2015 or beyond. We continue to bill FERC jurisdictional customers interim rates that have been in effect since January 1, 2011. These interim rates are subject to refund plus interest pending final resolution at FERC. We expect to defer revenues of approximately $0.7 million per month during 2014 pending final resolution at FERC.

STRATEGY

We are focused on providing our customers with safe and reliable service at reasonable rates. In response to our aging infrastructure, we continue to make significant capital investments in our generation, distribution and transmission assets in excess of our depreciation, which is the amount of these costs we recover through rates. Investing in our system and making prudent acquisitions for integrating supply resources provide us the opportunity to grow our rate base and earn a reasonable return on invested capital. These investments also reflect our focus on maintaining our system reliability, and allow us to pursue the deployment of newer technology that promotes the efficient use of electricity, including smart grid. See the “Capital Requirements" discussion below for further detail on planned maintenance capital expenditures.

During 2014, we will also be focused on closing the Hydro Transaction and fully integrating our most recent acquisition of natural gas production assets, both of which are intended to help stabilize our customers’ energy costs.

Regulatory Matters

General rate cases are necessary to cover the cost of providing safe, reliable service, while contributing to earnings growth and achieving our financial objectives. As noted above, during 2013 we received MPSC approval to increase our natural gas delivery rates in Montana.

During the first quarter of each year we evaluate the need for electric and natural gas rate changes in each state in which we provide service.

Distribution Investment

Montana Distribution System Infrastructure Project (DSIP)

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

DSIP completed its first full year of production after a two-year phase in period. This nearly $380 million ($290 million capital and $90 million expense), multi-year effort to accelerate the replacement and modernization of our existing electric and natural gas distribution system in Montana is intended to address a number of objectives to arrest and/or reverse the trend in aging infrastructure while maintaining and/or improving upon our already high level of safety and reliability. During 2013, we had DSIP capital expenditures of approximately $47 million. We expect DSIP capital expenditures of approximately $52 million during 2014.

Incremental operating and maintenance costs related to the phase-in of DSIP during 2012 and 2011 were deferred in accordance with the MPSC's approval of an accounting order. Incremental DSIP costs for 2013 forward are being expensed as incurred and the amounts previously deferred are being amortized over five years. During 2013 we amortized approximately $3.1 million and incurred incremental DSIP expenses of approximately $9.3 million. We expect DSIP expenses to be at a similar level during 2014.

26




Other Supply Investments

South Dakota Electric

The Big Stone and Neal #4 electric generation facilities are subject to additional emission reduction requirements. Our current estimate of project costs for Big Stone is approximately $405 million (our share is 23.4%) and is expected to be operational by 2016. As of December 31, 2013, we have capitalized costs of approximately $40.5 million related to this project. Neal #4 began incurring costs in 2011 and the project was substantially completed in 2013. Our share (8.7%) of the capitalized costs related to this project were approximately $22.6 million.







27



RESULTS OF OPERATIONS

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

NON-GAAP FINANCIAL MEASURE

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

Factors Affecting Results of Operations

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

Revenues are also impacted to a lesser extent 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.


28



OVERALL CONSOLIDATED RESULTS

Year Ended December 31, 2013 Compared with Year Ended December 31, 2012

 
Year Ended December 31,
 
2013
 
2012
 
Change
 
% Change
 
(in millions)
Operating Revenues
 
 
 
 
 
 
 
Electric
$
865.2

 
$
805.6

 
$
59.6

 
7.4
%
Natural Gas
287.6

 
263.4

 
24.2

 
9.2

Other
1.7

 
1.3

 
0.4

 
30.8

 
$
1,154.5

 
$
1,070.3

 
$
84.2

 
7.9
%

 
Year Ended December 31,
 
2013
 
2012
 
Change
 
% Change
 
(in millions)
Cost of Sales
 
 
 
 
 
 
 
Electric
$
358.7

 
$
277.8

 
$
80.9

 
29.1
%
Natural Gas
120.9

 
117.6

 
3.3

 
2.8

 
$
479.6

 
$
395.4

 
$
84.2

 
21.3
%

 
Year Ended December 31,
 
2013
 
2012
 
Change
 
% Change
 
(in millions)
Gross Margin
 
 
 
 
 
 
 
Electric
$
506.5

 
$
527.8

 
$
(21.3
)
 
(4.0
)%
Natural Gas
166.7

 
145.8

 
20.9

 
14.3

Other
1.7

 
1.3

 
0.4

 
30.8

 
$
674.9

 
$
674.9

 
$

 
 %


29



Consolidated gross margin in 2013 was $674.9 million, which remained flat from gross margin in 2012. Factors that impacted gross margin included:

 
Gross Margin 2013 vs. 2012
 
(in millions)
Natural gas and electric retail volumes
$
11.9

Natural gas production
8.1

Montana natural gas rate increase
6.6

Spion Kop revenue
5.6

DGGS revenues
5.1

Property tax trackers
3.8

Electric transmission
3.7

Natural gas transportation capacity
1.3

Electric QF supply costs
1.0

Gain on CELP arbitration decision
(47.9
)
Operating expenses recovered in trackers
(2.0
)
Demand Side Management (DSM) lost revenues
(0.3
)
Other
3.1

Consolidated Gross Margin
$


The changes in gross margin include the following:

An increase in natural gas and electric retail volumes due primarily to colder winter and spring weather;
An increase in natural gas production margin primarily due to the full period effect of the acquisition of gas production assets in the third quarter of 2012 and the acquisition of gas production assets in December 2013, which is subject to refund;
An increase in Montana natural gas delivery rates implemented in April 2013;
The acquisition of the Spion Kop wind farm in the fourth quarter of 2012;
Higher DGGS revenue primarily due to the inclusion in 2012 results of a $6.4 million deferral of revenues collected in 2011 related to the FERC ALJ nonbinding decision as discussed above;
An increase in property taxes included in trackers;
An increase in electric transmission revenues due to market pricing and other conditions;
An increase in demand for natural gas transportation capacity; and
Lower QF related supply costs based on actual QF pricing and output.

These increases were offset by:

A $47.9 million gain recognized in 2012 associated with a favorable arbitration decision related to a dispute over energy and capacity rates with Colstrip Energy Limited Partnership (CELP),
Lower revenues for operating expenses recovered in trackers, primarily related to customer efficiency programs; and
A $1.2 million decrease in natural gas DSM lost revenues, which includes approximately $0.5 million related to 2012, offset in part by a $0.9 million increase in electric DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers.

Demand-side management (DSM) lost revenues - Base rates, including impacts of past DSM activities, are reset in general rate case filings. As time passes between rate cases, more energy saving measures (primarily more efficient residential and commercial lighting) are implemented, causing an increase in DSM lost revenues. Historically, the MPSC had authorized us to include a calculation of lost revenues based on actual historic DSM program activity, but prohibited the inclusion of forecasted or estimated future lost revenue in the electric tracker. In its April 2012 order, the MPSC authorized us to include forecasted lost revenues in future tracker filings. We had not recognized the entire forecasted amount, pending MPSC review of a detailed independent study supporting our requested DSM lost revenues that we filed during the first quarter of 2013.


30



During October 2013, the MPSC approved an order related to our 2012 electric supply tracker filing (covering July 1, 2011 through June 30, 2012), which includes a decision on their review of the independent study related to our request for DSM lost revenues and addresses future DSM lost revenue recovery. During 2013, we recognized approximately $9.0 million of DSM lost revenues, which includes approximately $1.9 million related to calendar year 2012 that we had previously deferred pending outcome of the review of the study results.

The order also includes a provision expressing concern with the policy of continuing to allow DSM lost revenue recovery, indicating that we bear the burden of demonstrating why any incremental DSM lost revenue recovery from the date of its order forward is reasonable and in the public interest. Based on the MPSC's order, we expect to be able to collect at least $7.1 million of DSM lost revenues for each annual tracker period; however, since the 2013 annual tracker filing (covering July 1, 2012 through June 30, 2013) is still subject to final approval, the MPSC may ultimately require us to refund a portion of the DSM lost revenues we have recognized since July 2012. We do not expect the MPSC to issue a final order related to the 2013 annual tracker filing until at least the second half of 2014.

 
Year Ended December 31,
 
2013
 
2012
 
Change
 
% Change
 
(in millions)
Operating Expenses (excluding cost of sales)
 
 
 
 
 
 
 
Operating, general and administrative
$
285.6

 
$
270.0

 
$
15.6

 
5.8
%
Mountain States Transmission Intertie (MSTI)

 
24.0

 
(24.0
)
 
100.0

Property and other taxes
105.5

 
97.7

 
7.8

 
8.0

Depreciation
112.8

 
106.0

 
6.8

 
6.4

 
$
503.9

 
$
497.7

 
$
6.2

 
1.2
%


Consolidated operating, general and administrative expenses were $285.6 million in 2013 as compared to $270.0 million in 2012. Primary components of this change include the following:
 
Operating, General, & Administrative
Expenses
2013 vs. 2012
 
(in millions)
DSIP expenses
$
12.4

Hydro Transaction costs
4.4

Labor
4.4

Plant operator costs
4.2

Natural gas production
3.0

Nonemployee directors deferred compensation
2.6

Bad debt expense
1.4

Pension and employee benefits
(15.4
)
Operating expenses recovered in trackers
(2.0
)
Other
0.6

Increase in Operating, General & Administrative Expenses
$
15.6



31



The increase in operating, general and administrative expenses of $15.6 million was primarily due to the following:

DSIP expenses of $12.4 million as discussed above;
Legal and professional fees associated with the Hydro Transaction. We expect to incur additional Hydro Transaction related legal and professional fees during 2014;
Increased labor costs due primarily to compensation increases, a larger number of employees, and less time spent on capital projects, which increases expense;
Higher plant operator costs primarily due to the Spion Kop acquisition and higher maintenance and outage costs at Colstrip Unit 4 and Neal #4;
Higher natural gas production costs due to the acquisition of the natural gas production assets discussed above;
Non-employee directors deferred compensation increased primarily due to changes in our stock price. Directors may defer their board fees into deferred shares held in a rabbi trust. If the market value of our stock goes up, deferred compensation expense increases; however, we account for the deferred shares as trading securities and their increase in value is reflected in other income with no impact on net income; and
Higher bad debt expense, due to a combination of higher revenues and slower collections of receivables from customers related to our customer information systems implementation.

These increases were partly offset by:

Decreased pension expense of approximately $19.1 million offset in part by higher incentive and other employee benefit costs. Our Montana pension costs are included in expense on a pay as you go (cash funding) basis. We received a pension accounting order from the MPSC in 2008, which based our Montana pension expense on an average of our funding requirements for calendar years 2005 through 2012 in order to smooth the impact of increased cash funding. Our pension expense decreased to $11.9 million in 2013 as compared with $29.4 million in 2012. We expect pension expense in 2014 to be comparable with 2013 expense; and
Lower operating expenses recovered in trackers, primarily related to customer efficiency programs. These costs are included in our supply trackers and have no impact on operating income.

In the third quarter of 2012, we recorded a charge of approximately $24.0 million for the impairment of substantially all of the preliminary survey and investigative costs associated with MSTI, a proposed 500 kV transmission project from southwestern Montana to southeastern Idaho with a potential capacity of 1500 MWs.

Property and other taxes were $105.5 million in 2013 as compared with $97.7 million in 2012. This increase was due primarily to higher assessed property valuations in Montana and plant additions.

Depreciation expense was $112.8 million in 2013 as compared with $106.0 million in 2012. This reflects an increase in depreciation expense due to plant additions, offset in part by a reduction in depreciation expense of approximately $4.5 million as a result of new depreciation studies conducted by an independent consultant and implemented during the second quarter of 2013. These studies reflect longer asset lives on our electric and natural gas assets in Montana, and electric assets in South Dakota. While we expect depreciation expense to increase in 2014 due to plant additions, this will be partially offset by approximately $1.5 million for the first quarter of 2014 as the reduction in depreciation rates was implemented in the second quarter of 2013.

Consolidated operating income in 2013 was $171.0 million, as compared with $177.2 million in 2012. This decrease was primarily due to higher operating, general and administrative expenses partly offset by the 2012 MSTI impairment as discussed above.

Consolidated interest expense in 2013 was $70.5 million, an increase of $5.4 million, or 8.3%, from 2012. This increase includes $1.9 million of expenses associated with the bridge credit facility related to the Hydro Transaction, higher interest from the issuance of long-term debt, and interest accrued on amounts subject to refund. We expect interest expense to increase by approximately $8.5 million in 2014 as a result of expenses associated with the bridge credit facility and $100 million of debt issued in December 2013. See "Liquidity and Capital Resources" for additional information regarding our financing activities.

Consolidated other income in 2013 was $7.7 million as compared with $4.4 million in 2012. This increase was primarily due to a $2.6 million gain on deferred shares held in trust for non-employee directors deferred compensation discussed above and higher capitalization of AFUDC.


32



We had a consolidated income tax expense in 2013 of $14.3 million as compared with $18.1 million in 2012. Our effective tax rate was 13.2% for 2013 and 15.5% for 2012. The following table summarizes the significant differences from the Federal statutory rate, which resulted in reduced income tax expense:
 
Year Ended December 31,
 
2013
 
2012
 
(in millions)
Income Before Income Taxes
$
108.3

 
$
116.5

 
 
 
 
Income tax calculated at 35% Federal statutory rate
37.9

 
40.8

 
 
 
 
Permanent or flow through adjustments:
 
 
 
State income, net of federal provisions
(3.1
)
 
1.1

Flow through repairs deductions
(17.8
)
 
(16.4
)
Production tax credits
(3.2
)
 

Plant and depreciation of flow through items
(0.6
)
 
(1.3
)
Recognition of state NOL benefit

 
(2.4
)
Prior year permanent return to accrual adjustments
0.5

 
(1.9
)
Other, net
0.6

 
(1.8
)
 
$
(23.6
)
 
$
(22.7
)
 
 
 
 
Income tax expense
$
14.3

 
$
18.1

 
Our effective tax rate differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions and state tax benefit of bonus depreciation deductions. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.

We recognized federal repairs related tax benefits of $17.8 million and $16.4 million for 2013 and 2012, respectively. In September 2013, the IRS issued final tangible property regulations, which includes final guidance on a safe harbor method for determining the tax treatment of repair costs related to electric transmission and distribution property. The regulations are not effective until tax years beginning on or after January 1, 2014; however, certain portions require a tax accounting method change on a retroactive basis, thus requiring an adjustment related to fixed and real asset deferred taxes. Based on our preliminary analysis of the tangible property regulations, no material adjustments were recorded during 2013. We will continue to monitor the impact of any future changes to the tangible property regulations on our tax positions prospectively.

We recognized state tax bonus depreciation related benefits (included in State income, net of federal provisions in the table above) of $3.9 million and $2.8 million for 2013 and 2012, respectively. We expect bonus depreciation related benefits to be minimal in 2014.

During 2012, we recognized a $2.4 million favorable state net operating loss (NOL) carryforward utilization benefit due to changes in our estimates of taxable income. Previously, we maintained a valuation allowance against certain state NOL carryforwards based on our forecast of taxable income and our estimate that a portion of these NOL carryforwards would more likely than not expire before we could use them.

While we reflect an income tax provision in our Consolidated Financial Statements, we expect our cash payments for income taxes will be minimal through at least 2016, based on our projected taxable income and anticipated use of consolidated NOL carryforwards.

Consolidated net income in 2013 was $94.0 million as compared with $98.4 million in 2012. This decrease was primarily due to lower operating income and higher interest expense, partly offset by higher other income and lower income tax expense.

33



Year Ended December 31, 2012 Compared with Year Ended December 31, 2011

 
Year Ended December 31,
 
2012
 
2011
 
Change
 
% Change
 
(in millions)
Operating Revenues
 
 
 
 
 
 
 
Electric
$
805.6

 
$
797.5

 
$
8.1

 
1.0
 %
Natural Gas
263.4

 
318.3

 
(54.9
)
 
(17.2
)
Other
1.3

 
1.5

 
(0.2
)
 
(13.3
)
 
$
1,070.3

 
$
1,117.3

 
$
(47.0
)
 
(4.2
)%

 
Year Ended December 31,
 
2012
 
2011
 
Change
 
% Change
 
(in millions)
Cost of Sales
 
 
 
 
 
 
 
Electric
$
277.8

 
$
327.1

 
$
(49.3
)
 
(15.1
)%
Natural Gas
117.6

 
167.4

 
(49.8
)
 
(29.7
)
 
$
395.4

 
$
494.5

 
$
(99.1
)
 
(20.0
)%

 
Year Ended December 31,
 
2012
 
2011
 
Change
 
% Change
 
(in millions)
Gross Margin
 
 
 
 
 
 
 
Electric
$
527.8

 
$
470.4

 
$
57.4

 
12.2
 %
Natural Gas
145.8

 
150.9

 
(5.1
)
 
(3.4
)
Other
1.3

 
1.4

 
(0.1
)
 
(7.1
)
 
$
674.9

 
$
622.7

 
$
52.2

 
8.4
 %


34



Consolidated gross margin in 2012 was $674.9 million, an increase of $52.2 million, or 8.4%, from gross margin in 2011. Primary components of this change included the following:

 
Gross Margin 2012 vs. 2011
 
(in millions)

Gain on CELP arbitration decision
$
47.9

DSM lost revenues
5.9

Montana property tax tracker
4.0

Gas production
3.3

Electric transmission
2.3

South Dakota natural gas rate increase
1.7

Natural gas and electric retail volumes
(7.0
)
DGGS revenues
(3.8
)
Operating expenses recovered in trackers
(1.3
)
Other
(0.8
)
Increase in Consolidated Gross Margin
$
52.2


This $52.2 million increase includes the following:

A $47.9 million gain associated with a favorable arbitration decision related to a dispute over energy and capacity rates with CELP, as discussed above;
An increase in DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers;
An increase in Montana property taxes included in a tracker as compared to 2011;
An increase in gas production margin due to the inclusion of Battle Creek in rates, including approximately $1.1 million that we had deferred in prior periods based on the difference between our cost of service and current natural gas market prices. The acquisition of the Bear Paw Basin assets in the third quarter of 2012 also contributed to the higher gas production margin;
An increase in transmission revenues due to higher demand to transmit energy for others across our lines; and
An increase in South Dakota natural gas rates implemented in December 2011.

These increases were partly offset by the following:

A decrease in natural gas retail volumes, and to a lesser extent electric residential retail volumes, due primarily to warmer winter and spring weather;
Lower DGGS related revenues primarily due to the deferral of an additional $13.7 million of DGGS FERC jurisdictional revenues as discussed above, offset in part by higher DGGS MPSC jurisdictional revenues of approximately $7.2 million due to the regulatory flow-through treatment of the state bonus depreciation deduction during 2011 and approximately $2.7 million that we had deferred in 2011 pending outcome of allocation uncertainty in Montana; and
Lower revenues for operating expenses recovered in trackers, primarily due to lower environmental remediation costs, partly offset by increases in costs for customer efficiency programs.




35



 
Year Ended December 31,
 
2012
 
2011
 
Change
 
% Change
 
(in millions)
Operating Expenses (excluding cost of sales)
 
 
 
 
 
 
 
Operating, general and administrative
$
270.0

 
$
267.2

 
$
2.8

 
1.0
%
MSTI impairment
24.0

 

 
$
24.0

 
100.0
%
Property and other taxes
97.7

 
89.1

 
8.6

 
9.7

Depreciation
106.0

 
100.9

 
5.1

 
5.1

 
$
497.7

 
$
457.2

 
$
40.5

 
8.9
%

Consolidated operating, general and administrative expenses were $270.0 million in 2012 as compared to $267.2 million in 2011. Primary components of this change included the following:

 
Operating, General, & Administrative
Expenses
2012 vs. 2011
 
(in millions)
Legal and professional fees
$
3.9

Employee benefits and labor
2.8

Plant operator costs
(1.9
)
Nonemployee directors deferred compensation
(1.7
)
Operating expenses recovered in trackers
(1.3
)
Other
1.0

Increase in Operating, General & Administrative Expenses
$
2.8


This $2.8 million increase was primarily due to the following:
 
An increase in legal and professional fees due in part to the DGGS FERC proceeding, the CELP arbitration matter and asset acquisitions discussed above; and
Higher employee benefits and labor primarily due to increased medical costs in 2012.

These increases were partly offset by the following:

Lower plant operator costs at Colstrip Unit 4 and Big Stone offset in part by higher plant operator costs at Coyote due to the timing of scheduled maintenance;
Non-employee directors deferred compensation decreased as compared to the prior year, primarily due to changes in our stock price. and
Lower operating expenses recovered from customers primarily due to lower environmental remediation costs, partly offset by increases in costs for customer efficiency programs.

As discussed above, we recorded a charge of approximately $24.0 million in the third quarter of 2012 for the impairment of substantially all of the capitalized preliminary survey and investigative costs associated with MSTI.

Property and other taxes were $97.7 million in 2012 as compared with $89.1 million in 2011. This increase was due primarily to higher assessed property valuations in Montana and plant additions.

Depreciation expense was $106.0 million in 2012 as compared with $100.9 million in 2011. This increase was primarily due to plant additions.

Consolidated operating income in 2012 was $177.2 million, as compared with $165.5 million in 2011. This increase was primarily due to the increase in gross margin partly offset by the MSTI impairment and higher operating expenses discussed above.


36



Consolidated interest expense in 2012 was $65.1 million, a decrease of $1.8 million, or 2.7%, from 2012. This decrease was primarily due to lower interest rates on debt outstanding and higher capitalization of AFUDC.

Consolidated other income in 2012 was $4.4 million, as compared with $3.9 million in 2011. This increase was primarily due to higher capitalization of AFUDC, offset in part by a $1.7 million lower gain in 2012 on deferred shares held in trust for non-employee directors deferred compensation as discussed above.
 
We had a consolidated income tax expense in 2012 of $18.1 million as compared with $10.1 million in 2011. Our effective tax rate was 15.5% for 2012 and 9.8% for 2011. The following table summarizes the significant differences from the Federal statutory rate, which resulted in reduced income tax expense:

 
Year Ended December 31,
 
2012
 
2011
 
(in millions)
Income Before Income Taxes
$
116.5

 
$
102.6

 
 
 
 
Income tax calculated at 35% Federal statutory rate
40.8

 
35.9

 
 
 
 
Permanent or flow through adjustments:
 
 
 
Flow-through repairs deductions
(16.4
)
 
(13.4
)
Flow-through of state bonus depreciation deduction
(2.8
)
 
(7.6
)
Recognition of state NOL benefit
(2.4
)
 
(2.4
)
Prior year permanent return to accrual adjustments
(1.9
)
 
(3.9
)
State income tax & other, net
0.8

 
1.5

 
$
(22.7
)
 
$
(25.8
)
 
 
 
 
Income tax expense
$
18.1

 
$
10.1


Our effective tax rate differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions and state tax benefit of bonus depreciation deductions. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.

We recognized federal repairs related tax benefits of $16.4 million and $13.4 million for 2012 and 2011, respectively.

We recognized state tax bonus depreciation related benefits of $2.8 million and $7.6 million for 2012 and 2011, respectively. The 2011 benefit related primarily to DGGS, as well as other qualifying additions.

We maintained a valuation allowance against certain state net operating loss (NOL) carryforwards based on our forecast of taxable income and our estimate that a portion of these NOL carryforwards would more likely than not expire before we could use them. During 2012 and 2011, we recognized a $2.4 million favorable state NOL carryforward utilization benefit due to changes in our estimates of taxable income.

During 2012, we recognized return to accrual adjustment benefits of $1.9 million during the normal course of preparing our 2011 income tax return. During the fourth quarter of 2011, we determined the calculation of certain differences associated primarily with plant-related basis differences had been overstated and therefore recognized a cumulative tax benefit adjustment of approximately $3.9 million. The adjustment related to prior periods and is not material to previously issued or current period financial statements.

Consolidated net income in 2012 was $98.4 million as compared with $92.6 million in 2011. This increase was primarily due to higher gross margin, largely due to the gain associated with the CELP arbitration decision, partially offset by the charge related to the MSTI project, higher property taxes, depreciation and income tax expense.

37



ELECTRIC MARGIN

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

Retail: Sales of electricity to residential, commercial and industrial customers.
Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers.
Transmission: Reflects transmission revenues regulated by the FERC.
Ancillary Services: FERC jurisdictional services that ensure reliability and support the transmission of electricity from generation sites to customer loads. Such services include regulation service, reserves and voltage support.
Wholesale: Sales of electricity to electric cooperatives, municipalities and other electric utilities, the prices for which are based on prevailing market prices.
Other: Miscellaneous electric revenues.

Year Ended December 31, 2013 Compared with Year Ended December 31, 2012

 
Results
 
2013
 
2012
 
Change
 
% Change
 
(in millions)
Retail revenue
$
781.7

 
$
747.9

 
$
33.8

 
4.5
 %
Regulatory amortization
25.1

 
10.0

 
15.1

 
151.0

   Total retail revenues
806.8

 
757.9

 
48.9

 
6.5

Transmission
50.1

 
46.4

 
3.7

 
8.0

Ancillary Services
1.5

 
(6.1
)
 
7.6

 
(124.6
)
Wholesale
2.0

 
3.0

 
(1.0
)
 
(33.3
)
Other
4.8

 
4.4

 
0.4

 
9.1

Total Revenues
865.2

 
805.6

 
59.6

 
7.4

Total Cost of Sales
358.7

 
277.8

 
80.9

 
29.1
 %
Gross Margin
$
506.5

 
$
527.8

 
$
(21.3
)
 
(4.0
)%

 
Revenues
 
Megawatt Hours (MWH)
 
Avg. Customer Counts
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
(in thousands)
 
 
 
 
Retail Electric
 
 
 
 
 
 
 
 
 
 
 
Montana
$
271,283

 
$
255,623

 
2,411

 
2,356

 
276,353

 
273,984

South Dakota
48,574

 
47,696

 
580

 
544

 
49,298

 
48,929

   Residential 
319,857

 
303,319

 
2,991

 
2,900

 
325,651

 
322,913

Montana
321,261

 
308,077

 
3,182

 
3,199

 
62,744

 
62,102

South Dakota
69,800

 
69,639

 
965

 
938

 
12,073

 
12,113

Commercial
391,061

 
377,716

 
4,147

 
4,137

 
74,817

 
74,215

Industrial
41,495

 
37,835

 
2,922

 
2,876

 
74

 
74

Other
29,316

 
29,074

 
187

 
199

 
5,991

 
5,990

Total Retail Electric
$
781,729

 
$
747,944

 
10,247

 
10,112

 
406,533

 
403,192

Total Wholesale Electric
$
1,993

 
$
2,959

 
94

 
183

 
N/A

 
N/A


 
Degree Days
 
2013 as compared with:
Cooling Degree-Days
2013
 
2012
 
Historic Average
 
2012
 
Historic Average
Montana
438
 
450
 
301
 
3% colder
 
46% warmer
South Dakota
848
 
1,084
 
734
 
22% colder
 
16% warmer


38



 
Degree Days
 
2013 as compared with:
Heating Degree-Days
2013
 
2012
 
Historic Average
 
2012
 
Historic Average
Montana
7,817
 
7,331
 
7,888
 
 7% colder
 
 1% warmer
South Dakota
8,292
 
6,387
 
7,632
 
 30% colder
 
 9% colder

The following summarizes the components of the changes in electric margin for the years ended December 31, 2013 and 2012:
 
Gross Margin
2013 vs. 2012
 
(in millions)
Gain on CELP arbitration decision
$
(47.9
)
Operating expenses recovered in trackers
(1.1
)
Spion Kop revenue
5.6

Retail volumes
5.4

DGGS revenues
5.1

Property tax trackers
3.8

Transmission
3.7

QF supply costs
1.0

DSM lost revenues
0.9

Other
2.2

Decrease in Gross Margin
$
(21.3
)

This decrease in margin is primarily due to:

A $47.9 million gain in 2012 associated with a favorable arbitration decision related to a dispute over energy and capacity rates with CELP; and
Lower revenues for operating expenses recovered in trackers, primarily related to customer efficiency programs.

These decreases were offset in part by:

The acquisition of the Spion Kop wind farm in the fourth quarter of 2012;
An increase in retail volumes due primarily to colder winter and spring weather;
Higher DGGS ancillary services revenue primarily due to inclusion in 2012 results of a $6.4 million deferral of revenues collected in 2011 related to the FERC ALJ nonbinding decision discussed above;
An increase in property taxes included in a tracker;
An increase in transmission revenues due to higher demand to transmit energy for others across our lines;
Lower QF related supply costs based on actual QF pricing and output; and
An increase in DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers.

Demand for transmission can fluctuate substantially from year to year based on hydro, weather and market conditions in Montana and states to the South and West. While improved market pricing and other conditions resulted in increased demand to transmit electricity from Montana over our lines, the outage at Colstrip Unit 4 partly reduced energy available to transmit over our lines.

The increase in regulatory amortization revenue reflected above 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.

Retail volumes increased primarily due to colder winter weather. Wholesale volumes decreased from lower plant utilization in 2013 due to the combination of market conditions and scheduled maintenance.


39



Year Ended December 31, 2012 Compared with Year Ended December 31, 2011

 
Results
 
2012
 
2011
 
Change
 
% Change
 
(in millions)
Retail revenue
$
747.9

 
$
729.7

 
$
18.2

 
2.5
 %
Regulatory amortization
10.0

 
8.6

 
1.4

 
16.3

   Total retail revenues
757.9

 
738.3

 
19.6

 
2.7

Transmission
46.4

 
44.1

 
2.3

 
5.2

Ancillary Services
(6.1
)
 
7.8

 
(13.9
)
 
(178.2
)
Wholesale
3.0

 
1.9

 
1.1

 
57.9

Other
4.4

 
5.4

 
(1.0
)
 
(18.5
)
Total Revenues
805.6

 
797.5

 
8.1

 
1.0

Total Cost of Sales
277.8

 
327.1

 
(49.3
)
 
(15.1
)
Gross Margin
$
527.8

 
$
470.4

 
$
57.4

 
12.2
 %

 
Revenues
 
Megawatt Hours (MWH)
 
Avg. Customer Counts
 
2012
 
2011
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
 
 
 
 
Retail Electric
 
 
 
 
 
 
 
 
 
 
 
Montana
$
255,623

 
$
250,988

 
2,356

 
2,394

 
273,984

 
272,131

South Dakota
47,696

 
46,869

 
544

 
565

 
48,929

 
48,685

   Residential 
303,319

 
297,857

 
2,900

 
2,959

 
322,913

 
320,816

Montana
308,077

 
302,591

 
3,199

 
3,197

 
62,102

 
61,571

South Dakota
69,639

 
65,614

 
938

 
919

 
12,113

 
11,946

Commercial
377,716

 
368,205

 
4,137

 
4,116

 
74,215

 
73,517

Industrial
37,835

 
37,378

 
2,876

 
2,833

 
74

 
72

Other
29,074

 
26,298

 
199

 
170

 
5,990

 
5,875

Total Retail Electric
$
747,944

 
$
729,738

 
10,112

 
10,078

 
403,192

 
400,280

Wholesale Electric
$
2,959

 
$
1,928

 
183

 
106

 
N/A

 
N/A


 
Degree Days
 
2012 as compared with:
Cooling Degree-Days
2012
 
2011
 
Historic Average
 
2011
 
Historic Average
Montana
450
 
328
 
302
 
37% warmer
 
49% warmer
South Dakota
1,084
 
862
 
734
 
26% warmer
 
48% warmer

 
Degree Days
 
2012 as compared with:
Heating Degree-Days
2012
 
2011
 
Historic Average
 
2011
 
Historic Average
Montana
7,331
 
8,094
 
7,959
 
9% warmer
 
8% warmer
South Dakota
6,387
 
8,074
 
7,773
 
21% warmer
 
18% warmer


40



The following summarizes the components of the changes in electric margin for the years ended December 31, 2012 and 2011:
 
Gross Margin
2012 vs. 2011
 
(in millions)
Gain on CELP arbitration decision
$
47.9

DSM lost revenues
5.9

Montana property tax tracker
3.0

Operating expenses recovered in trackers
3.0

Transmission
2.3

DGGS revenues
(3.8
)
Retail volumes
(1.5
)
Other
0.6

Increase in Gross Margin
$
57.4


The improvement in margin is primarily due to:

A $47.9 million gain associated with a favorable arbitration decision related to a dispute over energy and capacity rates with CELP;
An increase in DSM lost revenues recovered through our supply trackers related to efficiency measures implemented by customers;
An increase in Montana property taxes included in a tracker as compared to the same period in 2011;
Higher revenues for operating expenses recovered in trackers, primarily related to customer efficiency programs; and
An increase in transmission capacity revenues due to higher demand to transmit energy for others across our lines.

These increases were offset in part by:

Lower DGGS related revenues related to the FERC ALJ nonbinding decision as discussed above; and
A decrease in residential retail volumes due primarily to warmer winter and spring weather.

The increase in regulatory amortization revenue reflected above 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.

Retail volumes increased from higher commercial, industrial and other usage, offset in part by lower residential volumes due primarily to warmer winter and spring weather. Wholesale volumes increased from higher plant utilization in 2012. Lower plant utilization in 2011 was due to the combination of market conditions and scheduled maintenance.

41



NATURAL GAS MARGIN

Year Ended December 31, 2013 Compared with Year Ended December 31, 2012

 
Results
 
2013
 
2012
 
Change
 
% Change
 
(in millions)
Retail revenue
$
253.4

 
$
220.8

 
$
32.6

 
14.8
 %
Regulatory amortization
(5.2
)
 
7.9

 
(13.1
)
 
(165.8
)
   Total retail revenues
248.2

 
228.7

 
19.5

 
8.5

Wholesale and other
39.4

 
34.7

 
4.7

 
13.5

Total Revenues
287.6

 
263.4

 
24.2

 
9.2

Total Cost of Sales
120.9

 
117.6

 
3.3

 
2.8

Gross Margin
$
166.7

 
$
145.8

 
$
20.9

 
14.3
 %
 
 
Revenues
 
Dekatherms (Dkt)
 
Customer Counts
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
(in thousands)
 
 
 
 
Retail Gas
 
 
 
 
 
 
 
 
 
 
 
Montana
$
111,605

 
$
102,884

 
12,736

 
11,826

 
160,516

 
159,431

South Dakota
26,302

 
21,085

 
3,074

 
2,351

 
38,230

 
37,915

Nebraska
24,740

 
19,223

 
2,648

 
2,129

 
36,692

 
36,595

Residential
162,647

 
143,192

 
18,458

 
16,306

 
235,438

 
233,941

Montana
56,356

 
51,978

 
6,591

 
6,082

 
22,455

 
22,326

South Dakota
19,163

 
13,446

 
3,025

 
2,116

 
6,045

 
5,980

Nebraska
13,160

 
10,250

 
1,971

 
1,674

 
4,601

 
4,580

Commercial
88,679

 
75,674

 
11,587

 
9,872

 
33,101

 
32,886

Industrial
1,083

 
1,021

 
129

 
121

 
264

 
272

Other
1,019

 
905

 
137

 
118

 
156

 
150

Total Retail Gas
$
253,428

 
$
220,792

 
30,311

 
26,417

 
268,959

 
267,249


 
Degree Days
 
2013 as compared with:
Heating Degree-Days
2013
 
2012
 
Historic Average
 
2012
 
Historic Average
Montana
7,817
 
7,331
 
7,888
 
 7% colder
 
 1% warmer
South Dakota
8,292
 
6,387
 
7,632
 
 30% colder
 
 9% colder
Nebraska
6,446
 
5,175
 
6,302
 
 25% colder
 
 2% colder



42



The following summarizes the components of the changes in natural gas margin for the years ended December 31, 2013 and 2012:

 
Gross Margin
2013 vs. 2012
 
(in millions)