ITEM 1.  BUSINESS

OVERVIEW

 

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 692,600 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:

 

 

 

SIGNIFICANT DEVELOPMENTS

Hydro Transaction

In November 2014, we completed the purchase of hydroelectric generating facilities and associated assets located in Montana for an adjusted purchase price of approximately $904 million (Hydro Transaction). The addition of hydroelectric generation is intended to provide long-term supply diversity to our portfolio and reduce risks associated with variable fuel prices. We expect the Hydro Transaction to allow us to reduce our reliance on third party power purchase agreements and spot market purchases, more closely matching our electric generation resources with forecasted customer demand. With reduced amounts of purchased power, we believe we will be less exposed to market volatility and will be better positioned to control the cost of supplying electricity to our customers. We received approval from the MPSC to include the hydroelectric generating assets in our Montana rate base and will be allowed to recover our costs plus an allowed rate of return.

The facilities acquired include eleven hydro-electric plants and one storage reservoir (each a ‘‘Facility’’ and together the ‘‘Facilities’’) located in central and western Montana along the Missouri, Flathead, Clark Fork and Madison Rivers and Rosebud Creek. The net aggregate generating capacity of the Facilities is 633 MWs, which includes the Kerr Project, a 194 MW hydroelectric generating facility that we expect to transfer to the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT) in September 2015. Eight of the Facilities, along with the storage reservoir, are collectively licensed as the Missouri-Madison Project, by the FERC. Each of the remaining three Facilities is licensed by FERC as a separate project.

With the addition of these generating assets and assuming ownership of the Kerr Project is transferred (see Note 3 - Hydro Transaction for further discussion), we own generation facilities that provide approximately 60% of our average electric load serving requirements in Montana. The following chart provides an overview of the Facilities by name, net capacity in MWs, commercial operation date (COD), river source, and FERC license expiration date. We are the sole direct owner of each facility.

(1) Hebgen facility (0 MW net capacity) excluded from figures. These are run-of-river dams except for Kerr and Mystic, which are storage generation.

Kerr Project - The Hydro Transaction includes the Kerr Project, a 194 MW hydro-electric generating facility that we expect will be transferred to the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT) in September 2015, in accordance with its FERC license, which gives the CSKT the right to acquire the project between September 2015 and September 2025. The CSKT have formally provided notice of their intent to acquire the Kerr Project and designated September 5, 2015, as the date for conveyance to occur. PPL Montana and the CSKT previously conducted an arbitration over the conveyance price of the Kerr Project. In March 2014, an arbitration panel set an estimated conveyance price of approximately $18.3 million . Under our agreement with PPL Montana, the purchase price for the Hydro Transaction includes a $30 million reference price for the Kerr Project. If the CSKT complete the acquisition and pay $18.3 million for the Kerr Project, PPL Montana will pay the difference of $11.7 million to us. We expect to sell any excess generation from the Kerr Project in the market and provide revenue credits to our Montana retail customers until the CSKT exercises their right to acquire the Kerr Project. The MPSC Order provides that customers will have no financial risk related to our temporary ownership of the Kerr Project, with a compliance filing required upon completion of the transfer to CSKT.

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 2013 census estimated population of approximately 887,100. We deliver electricity to approximately 353,600 customers in 187 communities and their surrounding rural areas, 15 rural electric cooperatives and in Wyoming to the Yellowstone National Park. In 2014 , by category, residential, commercial, industrial, and other sales accounted for approximately 40%, 50%, 6%, and 4%, respectively, of our Montana retail 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 1,740 MWs, with approximately 1,241 MWs per hour for the year on average, and energy delivered of more than 10.9 million MWHs during the year ended December 31, 2014 . Our Montana electric distribution system consists of approximately 17,600 miles of overhead and underground distribution lines and 393 transmission and distribution substations.

 

Our Montana electric transmission system consists of approximately 6,700 miles of transmission lines, ranging from 50 kV to 500 kV, 288 circuit segments and approximately 104,000 transmission poles on approximately 74,000 structures with 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. We are directly interconnected with Avista Corporation; Idaho Power Company; PacifiCorp; the Bonneville Power Administration; WAPA; and Montana Alberta Tie Ltd. (MATL). 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 owned and contracted resources and market purchases with multiple counterparties. Owned generation resources supplied approximately 30% of our retail load requirements for 2014 . Including the Hydro Transaction, with ownership of the Kerr Project until September 2015, we expect that approximately 80% of our retail obligations will be met by owned generation in 2015. 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 87 MWs of 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 2015 we have resources to provide over 95% of the energy requirements necessary to meet our forecasted retail load requirements.

In addition to the hydro generation assets detailed in the table above, 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 Hydro Facilities chart above and in the chart below.

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. If the third unit is placed into service, DGGS 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 2014 .

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. The generation assets acquired in the Hydro Transaction are not eligible renewable resources. 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.

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

The amounts in the table above reflect estimates of the RECs for the year, with the final amounts determined in the following year with prior year adjustments 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 contracts under negotiation and our portfolio of resources, 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 62,500 customers in 110 communities in South Dakota. In 2014 , by category, residential, commercial and other sales accounted for approximately 40%, 59%, and 1%, respectively, of our South Dakota retail electric utility revenue. Peak demand was approximately 304 MWs, the average daily load was approximately 180 MWs, and more than 1.57 million MWHs were supplied during the year ended December 31, 2014 .

 

Our transmission and distribution network in South Dakota consists of approximately 3,500 miles of overhead and underground transmission and distribution lines as well as 124 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 2014 , this was approximately 6.2% of our share of the power generated.

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 15 MW in 2014, and 19 MW in 2015. We have also entered into an agreement with Missouri River Energy Services to supply firm capacity of 30 MW in 2016, 30 MW in 2017, and 35 MW in 2018. 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 also have several wholly owned peaking/standby generating units at seven locations throughout our service territory.

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

For the year ended December 31, 2014 , 93% of the electricity generated for 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 2014 , approximately 6% of the South Dakota retail needs were generated from renewable resources. By the end of 2015, we expect to have purchase power contracts for an additional 80 MWs from wind resources that include renewable energy credits, which should allow us to exceed South Dakota's voluntary objective.

Our South Dakota operations are a member of the MAPP, which is an entity that coordinates centralized transmission planning for a nine-state area in the North Central region of the United States and in two Canadian provinces that includes WAPA's Upper Great Plains region. Along with WAPA and several other members of the MAPP region, we expect to join the Southwest Power Pool (SPP) regional transmission organization by October 2015. The terms and conditions of our agreements with MAPP and WAPA are subject to the jurisdiction of the FERC. The MAPP region will be dissolved during the same time frame.

 

Our estimated costs for services under the SPP tariff are still being evaluated. Our tariffs in South Dakota generally allow us to pass through these transmission costs to our customers.

NATURAL GAS OPERATIONS

MONTANA

Our regulated natural gas utility business in Montana includes production, storage, transmission and distribution. 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, 2014, these owned reserves totaled approximately 70.4 Bcf and are estimated to provide approximately 5.8 Bcf each year, or about 29 percent of our current annual retail natural gas load in Montana. In addition, we own and operate three working natural gas storage fields in Montana with aggregate working gas capacity of approximately 17.75 Bcf and maximum aggregate daily deliverability of approximately 195,000 dekatherms.

We distribute natural gas to approximately 189,000 customers in 105 Montana communities over a system that consists of approximately 5,100 miles of underground distribution pipelines. We also serve several smaller distribution companies that provide service to approximately 32,000 customers. We transmit natural gas in Montana from production receipt points and storage facilities to distribution points and other nonaffiliated transmission systems. We transported natural gas volumes of approximately 43 Bcf, and our peak capacity was approximately 335,000 dekatherms per day during the year ended December 31, 2014 .

 

Our natural gas transmission system consists of more than 2,100 miles of pipeline, which vary in diameter from two inches to 24 inches, and serve more than 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 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 four franchises, which account for approximately 40,300 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, five 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, 2014 , were approximately 20.5 Bcf. Our Montana natural gas supply requirements for fuel for the year ended December 31, 2014 , were approximately 5 Bcf. We have contracted with several major producers and marketers with varying contract durations to provide the anticipated supply to meet ongoing requirements. Our natural gas supply requirements are fulfilled through third-party fixed-term purchase contracts, short-term market purchases and owned production. Our portfolio approach to natural gas supply is intended to enable us to maintain a diversified supply of natural gas sufficient to meet our supply requirements. We benefit from direct access to suppliers in the major natural gas producing regions in the United States, primarily the Rockies (Colorado), Montana, and Alberta, Canada.

  SOUTH DAKOTA AND NEBRASKA

We provide natural gas to approximately 87,500 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. In Nebraska, we transport natural gas for three gas-marketing firms and one end-user account. We delivered approximately 26.2 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 2014 .

 

Our South Dakota natural gas supply requirements for the year ended December 31, 2014 , were approximately 6.4 Bcf. We contract with a third party under an asset management agreement to manage transportation and storage of supply to minimize cost and price volatility to our customers. In Nebraska, our natural gas supply requirements for the year ended December 31, 2014 , were approximately 4.8 Bcf. We contract with a third party under an asset management agreement that includes pipeline

capacity, supply, and asset optimization activities. To supplement firm gas supplies in South Dakota and Nebraska, we contract for firm natural gas storage services to meet the heating season and peak day requirements of our customers.

 

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, 10 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.

REGULATION

Base rates are the rates we are allowed to charge our customers for the cost of providing delivery service and rate-based supply services, 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. 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:

(1)    Rate base reflects amounts on which we are authorized to earn a return.

(2)    Rate base amounts are estimated as of December 31, 2014 .

(3)    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.

(4)    For those items marked as "n/a," the respective settlement and/or order was not specific as to these terms.

(5)    South Dakota estimated rate base does not reflect requested adjustments included in the electric rate case filed in December 2014 for assets that are expected to be placed in service during 2015.

 

MPSC Regulation

 

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

Electric and Natural Gas Supply Trackers - Rates for our Montana electric and natural gas supply are set by the MPSC. Certain supply rates are adjusted on a monthly basis for volumes and costs during each July to June 12-month tracking period. Annually, supply rates are adjusted to include any differences in the previous tracking year's actual to estimated information for recovery during the subsequent tracking year. We submit annual 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. 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, hydro licensing and operations, the issuance of certain securities, incurrence of certain long-term debt, and compliance with mandatory reliability regulations, among other things. Under FERC's open access transmission policy promulgated in Order No. 888, as owners of transmission facilities, we are required to provide open access to our transmission facilities under filed tariffs at cost-based rates. In addition, we are required to comply with FERC's Standards of Conduct, 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.

 

Our South Dakota transmission operations are part of the WAPA Balancing Authority 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 under the NGA, although we are subject to state regulation. We conduct limited interstate transportation in Montana and South Dakota that is subject to FERC jurisdiction, but FERC has allowed the MPSC and SDPUC to set the rates for this interstate service. We have capacity agreements in South Dakota and Nebraska with interstate pipelines that are also subject to FERC jurisdiction.

The Facilities acquired in the Hydro Transaction are licensed by the FERC. In connection with the relicensing of these generating facilities, applicable law permits the FERC to issue a new license to the existing licensee or to a new licensee, and alternatively allows the U.S. government to take over the facility. If the existing licensee is not relicensed, it is compensated for its net investment in the facility, not to exceed the fair value of the property taken, plus reasonable severance damages to other property affected by the lack of relicensing.

 

Reliability Standards - We must comply with the standards and requirements, 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.

EMPLOYEES

As of December 31, 2014 , we had 1,604 employees. Of these, 1,273 employees were in Montana and 331 were in South Dakota or Nebraska. Of our Montana employees, 465 were covered by seven collective bargaining agreements involving five unions. Six of these agreements expire in 2016. Through the acquisition of PPL Montana's hydroelectric generating facilities, we assumed the terms of an additional agreement, which expires in 2017. Of our South Dakota and Nebraska employees, 196 were covered by a collective bargaining agreement that expires in 2016. We consider our relations with employees to be good.

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.