ITEM 1.
BUSINESSES
OVERVIEW
NorthWestern Corporation, doing business as Northwestern Energy, is one of the largest providers of electricity and natural gas in the Upper Midwest and Northwest, serving approximately 640,000 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. On February 15, 2002, we acquired electricity and natural gas transmission and distribution assets and natural gas storage assets of the former Montana Power Company, which have been in operation since 1912.
On April 25, 2006, we entered into an Agreement and Plan of Merger (Merger Agreement) with Babcock & Brown Infrastructure Limited (BBI) under which BBI will acquire NorthWestern Corporation in an all-cash transaction. For more information on the proposed transaction, see Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
Our utility operations are regulated primarily by the Montana Public Service Commission, the South Dakota Public Utilities Commission, the Nebraska Public Service Commission, and the Federal Energy Regulatory Commission. We operate our business in five reporting segments:
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regulated electric operations;
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unregulated electric operations;
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regulated natural gas operations;
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unregulated natural gas operations;
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all other, which primarily consists of our other miscellaneous service activities that are not included in the other identified segments, together with the unallocated corporate costs and investments, and any eliminating amounts.
For additional information related to our industry segments, see Note 25 of “Notes to Consolidated Financial Statements,” included in Item 8 herein.
We were incorporated in Delaware in November 1923. Our principal office is located at 125 S. Dakota Avenue, Sioux Falls, South Dakota 57104 and our telephone number is (605) 978-2908. We maintain an Internet site at http://www.northwesternenergy.com. 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 and 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 this site as soon as reasonably practicable after we electronically file those documents with, or otherwise furnish them to, the Securities and Exchange Commission (SEC). Our Internet Website and those of our subsidiaries and the information contained therein or connected thereto are not intended to be incorporated into this Annual Report on Form 10-K and should not be considered a part of this Annual Report on Form 10-K.
REGULATED ELECTRIC OPERATIONS
Montana
Our regulated electric utility business consists of an extensive electric transmission and distribution network. Our service territory covers approximately 107,600 square miles, representing approximately 73% of Montana’s land area, and includes a population of approximately 786,000 according to the 2000 census. We deliver electricity to approximately 322,000 customers in 187 communities and their surrounding rural areas, 15 rural electric cooperatives and in Wyoming to the Yellowstone National Park. In 2006, by category, residential, commercial and industrial, and other sales accounted for approximately 35%, 51%, and 14% of our Montana regulated electric utility revenue, respectively. 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 1,644 megawatts, the average daily load was approximately 1,165 megawatts, and more than 10.2 million megawatt hours were supplied during the year ended December 31, 2006.
Our Montana electric transmission system consists of approximately 7,000 miles of transmission lines, ranging from 50 to 500 kilovolts, 260 circuit segments and 125,000 transmission poles 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. Our 230 kilovolt and 161 kilovolt facilities form the key assets of our Montana transmission system. Lower voltage systems, which range from 50 kilovolts to 115 kilovolts, provide for local area service needs. We also jointly own a 500-kilovolt transmission system that is part of the Colstrip Transmission System, which transfers electricity generated from the 2,180 megawatt Colstrip generation facility to markets within the state and west of Montana. The system has interconnections with five major nonaffiliated transmission systems located in the Western Electricity Coordinating Council area, as well as one interconnection to a nonaffiliated system that connects with the Mid-Continent Area Power Pool region. With these interconnections, we transmit power to and from diverse interstate transmission systems, including those operated by Avista Corporation; Idaho Power Company; PacifiCorp; the Bonneville Power Administration; and the Western Area Power Administration.
Our Montana electric distribution system consists of approximately 20,700 miles of overhead and underground distribution lines and approximately 335 transmission and distribution substations.
Montana’s Electric Utility Industry Restructuring and Customer Choice Act was passed in 1997, which allowed for electric customer choice and competition among electric suppliers. Although larger Montana customers have a choice with regard to electricity suppliers, we do not currently face material competition in the transmission and distribution of electricity within our service territory.
Default Supply
Under Montana law, we are the permanent default supplier and are obligated to provide default supply electric service to customers who have not chosen or have not had an opportunity to choose an alternative electricity supplier. We own no regulated generation assets in Montana. Accordingly, we purchase substantially all of our Montana capacity and energy requirements for default supply from third parties.
Our annual default supply load requirements are slightly in excess of 700 average megawatts. We currently have power purchase agreements with PPL Montana for 300 megawatts of firm base-load and 150 megawatts of unit-contingent on peak energy through June 30, 2007. We also purchase power from 19 QF contracts entered into under the Public Utility Regulatory Policies Act of 1978, which provide a total of 101 megawatts of capacity. We have additional contracts for 135 megawatts of wind generation, 50 megawatts of gas-fired generation and 5 megawatts of seasonal base-load hydro supply. In addition, our Colstrip Unit 4 division has committed to supply 90 megawatts of unit-contingent, base-load energy for a term of 11.5 years, commencing on July 1, 2007, to meet a portion of our default supply requirements. In December 2005, we filed a biennial Electric Default Supply Resource Procurement Plan (Plan) with the MPSC. In accordance with this Plan, during 2006 we entered into new supply contracts through bilateral negotiations and a first-ever energy supply auction in Montana, that combined will provide approximately 50 percent of our default supply portfolio requirements beginning July 1, 2007. We currently have under contract approximately 96 percent of the energy requirements necessary to meet our projected load requirements through June 30, 2007, with approximately 74 percent at fixed prices. For the period July 1, 2007 through June 30, 2008, we have under contract approximately 83 percent of our projected load requirements, with approximately 74 percent at fixed prices. Remaining customer load requirements are met with market purchases.
Our electric supply purchases are being recovered through an electricity cost tracking process pursuant to which rates are adjusted on a monthly basis for electricity loads and electricity costs for the upcoming 12-month period. On an annual basis, rates are adjusted to include any differences in the previous tracking year’s actual to estimated information, for recovery in the subsequent tracking year. The MPSC reviews the prudency of our energy supply procurement activities as part of the annual tracking filing.
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 population of approximately 99,900 according to the 2000 census. We provide retail electricity to more than 59,700 customers in 110 communities in South Dakota. In 2006, by category, residential, commercial and industrial, wholesale, and other sales accounted for approximately 37%, 51%, 9% and 3% of our South Dakota electric utility revenue, respectively. Currently, we serve these customers principally from generation capacity obtained through our undivided ownership interests in three generation plants and other peaking facilities that provide us with 310 megawatts of demonstrated capacity. Peak demand was approximately 307 megawatts, the average daily load was approximately 145 megawatts, and more than 1.2 million megawatt hours were supplied during the year ended December 31, 2006.
Residential, commercial and industrial services are generally bundled packages of generation, transmission, distribution, meter reading, billing and other services. In addition, we provide wholesale transmission of electricity to a number of South Dakota municipalities, state government agencies and agency buildings. For these wholesale sales, we are responsible for the transmission of contracted electricity to a substation or other distribution point, and the purchaser is responsible for further distribution, billing, collection and other related functions. We also provide sales of electricity to resellers, primarily including power pools or other utilities. Sales to power pools fluctuate from year to year depending on a number of factors, including the availability of excess short-term generation and the ability to sell excess power to other utilities in the power pool.
Our transmission and distribution network in South Dakota consists of approximately 3,200 miles of overhead and underground transmission and distribution lines as well as 120 substations. We have interconnection and pooling arrangements with the transmission facilities of Otter Tail Power Company; Montana-Dakota Utilities Co.; Xcel Energy, Inc.; and the Western Area Power Administration. 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.
Direct competition does not presently exist within our South Dakota service territory for the supply and delivery of electricity, except with regard to certain new large load customers. The SDPUC, pursuant to the South Dakota Public Utilities Act, assigned the South Dakota service territory to us effective March 1976. Pursuant to that law, we have the exclusive right, other than as previously noted, to provide fully bundled services to all present and future electric customers within our assigned territory for so long as the service provided is adequate. There have been no allegations of inadequate service since assignment in 1976. The assignment of a service territory is perpetual under current South Dakota law.
We sell a portion of the electricity generated in facilities that we own jointly into the wholesale market. We face competition from other electricity suppliers with respect to our wholesale sales. These wholesale sales are made with electricity in excess of our load requirements and are not a material part of our operating results.
Electricity Supply
Most of the electricity that we supply to customers in South Dakota is generated by power plants that we own jointly with unaffiliated parties. In addition, we 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. Each of the jointly owned plants is subject to a joint management structure. Except as otherwise noted, 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 expenses, based upon our ownership interest. Most of the power allocated to us from these facilities is distributed to our South Dakota customers, although in 2006, approximately 16% of the power was sold in the wholesale market.
We have agreements with MidAmerican Energy Company (MidAmerican) to supply firm capacity during the summer months of 2007-2009 as follows: 40 megawatts in 2007; 43 megawatts in 2008; and 46 megawatts in 2009. During 2006, MidAmerican provided 40 megawatts of firm capacity during the summer months. In addition, we are a member of the Midcontinent Area Power Pool (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. The terms and conditions of the MAPP agreement and transactions between MAPP members are subject to the jurisdiction of the FERC. The 2006 MAPP accredited capacity was approximately 304 megawatts.
We have a resource plan that includes estimates of customer usage and programs to provide for economic, reliable and timely supplies 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. This forecast shows customer peak demand growing modestly, which will result in the need to add peaking capacity in the future. However, we have adequate base-load generation capacity to meet customer supply needs in the foreseeable future.
Electric Generation Costs
Coal was used to generate approximately 99% of the electricity utilized for South Dakota operations for the year ended December 31, 2006. Our natural gas and fuel oil peaking units provided the balance of generating capacity. We have no interests in nuclear generating plants. 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 I receive their fuel supply via rail. Continuing upward pressure on coal prices and transportation costs could result in increases in costs to our customers due to mechanisms to recover fuel adjustments in our rates. The average cost, inclusive of transportation costs, by type of fuel burned is shown below for the periods indicated:
During the year ended December 31, 2006, the average delivered cost per ton of fuel burned for our base-load plants was $25.87 at Big Stone I, $13.50 at Coyote and $16.67 at Neal #4. The average cost by type of fuel burned and delivered cost per ton of fuel 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.
The Big Stone I facility currently burns sub-bituminous coal from the Powder River Basin delivered under a contract through the end of 2007, which can be extended by mutual agreement. Neal #4 also receives sub-bituminous coal from the Powder River Basin delivered under multiple firm and spot contracts with terms of up to several years in duration. The Coyote facility has a contract for the supply of lignite coal that expires in 2016 and provides for an adequate fuel supply for Coyote’s estimated economic life.
The South Dakota Department of Environment and Natural Resources has given approval for Big Stone I to burn a variety of alternative fuels, including tire-derived fuel and refuse-derived fuel. In 2006, approximately 1.3% of the fuel consumption at Big Stone I was derived from alternative fuels.
Although we have no firm contract for the supply of diesel fuel or natural gas for our electric peaking units, we have historically been able to purchase diesel fuel requirements from local suppliers and have enough diesel fuel in storage to satisfy our current requirements. We have been able to use excess capacity from our natural gas operations as the fuel source for our gas peaking units.
We must pay fees to third parties to transmit the power generated at our Big Stone I, Coyote, and Neal #4 plants to our South Dakota transmission system. We have a 10-year agreement, expiring in 2011, with the Western Area Power Administration for transmission services, including transmission of electricity from Big Stone I and Neal #4 to our South Dakota service areas through seven points of interconnection on the Western Area Power Administration’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 the Western Area Power Authority’s system. In 2006, our costs for services under this contract totaled approximately $4.4 million. Our tariffs in South Dakota generally allow us to pass through these transmission costs to our customers.
REGULATED NATURAL GAS OPERATIONS
Montana
We distribute natural gas to approximately 174,000 customers located in 105 Montana communities. We also serve several smaller distribution companies that provide service to approximately 30,000 customers. Our natural gas distribution system consists of approximately 3,800 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 38.8 billion dekatherms, and our peak capacity was approximately 314 million dekatherms per day during the year ended December 31, 2006.
Our natural gas transmission system consists of more than 2,000 miles of pipeline, which vary in diameter from two inches to 20 inches, and serve more than 130 city gate stations. We have connections in Montana with five major, nonaffiliated transmission systems: Williston Basin Interstate Pipeline, NOVA Gas Transmission Ltd., Colorado Interstate Gas, Encana and Havre Pipeline. Seven compressor sites provide more than 42,000 horsepower, capable of moving more than 314 million dekatherms per day. In addition, we own and operate a pipeline border crossing through our wholly owned subsidiary, Canadian-Montana Pipe Line Corporation.
We own and operate three working natural gas storage fields in Montana with aggregate working gas capacity of approximately 16.2 billion dekatherms and maximum aggregate daily deliverability of approximately 185 million dekatherms. We own a fourth storage field that is no longer economically feasible as a working storage field and is being depleted at approximately 0.02 million dekatherms per day, with approximately 53 million dekatherms of remaining reserves as of December 31, 2006.
We have nonexclusive municipal franchises to transport and distribute natural gas in the Montana communities we serve. The terms of the franchises vary by community, but most are for 30 to 50 years. During the next five years, 18 of our municipal franchises, which account for approximately 77,000 customers, are scheduled to expire. Our policy is to seek
renewal of a franchise in the last year of its term.
Montana’s Natural Gas Utility Restructuring and Customer Choice Act, which was passed in 1997, provides that a natural gas utility may voluntarily offer its customers their choice of natural gas suppliers and provide open access in Montana. Although we have opened access to our Montana gas transmission and distribution systems and gas supply choice is available to all of our natural gas customers in Montana, we currently do not face material competition in the transmission and distribution of natural gas in our Montana service areas.
Default Supply
Under an agreement with the MPSC, we provide default supply service to customers that have not chosen other suppliers. Our natural gas supply requirements are fulfilled through third-party fixed-term purchase contracts and short-term market purchases. Our portfolio approach to natural gas supply enables 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), Mid-Continent, Panhandle (Texas/Oklahoma), Montana, and Alberta, Canada. These suppliers also provide us with market insight, which assists us in making procurement decisions. Our Montana natural gas supply requirements for the year ended December 31, 2006, were approximately 19.4 million dekatherms. We have contracted with several major producers and marketers with varying contract durations to provide the necessary supply to meet ongoing requirements.
Similar to our electric supply in Montana, our gas supply purchases are recovered through a gas cost tracking process, which provides for the adjustment of rates on a monthly basis to reflect changes in gas prices. On an annual basis rates are adjusted to include any differences in the previous tracking year’s actual to estimated information, for recovery in the subsequent tracking year. The MPSC reviews the prudency of our procurement activities as part of this annual tracking filing.
We filed a Biennial Natural Gas Procurement Plan (Gas Plan) in December 2006. This Gas Plan provides the MPSC the blueprint we will follow in procuring natural gas supply to meet our default supply needs and reliability requirements and the implementation of hedging strategies to reduce price volatility.
South Dakota and Nebraska
We provide natural gas to approximately 83,900 customers in 59 South Dakota communities and four Nebraska communities. We have approximately 2,200 miles of distribution gas mains in South Dakota and Nebraska. We also transport natural gas for other gas suppliers and marketers in South Dakota and Nebraska, and in South Dakota we sell natural gas to a number of large volume customers delivered through the distribution system of an unaffiliated natural gas utility company. In South Dakota, we also transport natural gas for two gas-marketing firms currently serving 90 customers through our distribution systems. In Nebraska, we transport natural gas for three customers, whose supply is contracted from another gas company. We delivered approximately 5.3 million dekatherms of third-party transportation volume on our South Dakota distribution system and approximately 2.1 million dekatherms of third-party transportation volume on our Nebraska distribution system during 2006.
We have nonexclusive municipal franchises to purchase, transport, distribute and store 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 is to seek renewal of a franchise in the last year of its term. During the next five years, 15 of our South Dakota and Nebraska municipal franchises, which account for approximately 41,175 customers, are scheduled to expire.
In South Dakota and Nebraska, we are subject to competition for natural gas supply. In addition, competition currently exists for commodity sales to large volume customers and for delivery in the form of system by-pass, alternative fuel sources such as propane and fuel oil and, in some cases, duplicate providers. We do not face material competition from alternative natural gas supply companies in the communities we serve in South Dakota and Nebraska.
Competition in the natural gas industry may result in the further unbundling of natural gas services. Separate markets may emerge for the natural gas commodity, transmission, distribution, meter reading, billing and other services currently provided by utilities. At present, it is unclear when or to what extent further unbundling of utility services will occur.
Natural gas is used primarily for residential and commercial heating. As a result, the demand for natural gas depends
upon weather conditions. Natural gas is a commodity that is subject to market price fluctuations. Purchase adjustment clauses contained in South Dakota and Nebraska tariffs allow us to pass through increases or decreases in gas supply and interstate transportation costs on a timely basis, so we are generally allowed to pass these changes in natural gas prices through to our customers.
Natural Gas Supply
Our South Dakota natural gas supply requirements for the year ended December 31, 2006, were approximately 4.8 million dekatherms. We have contracted with Tenaska Marketing Ventures, Inc. in South Dakota to manage transportation, storage and procurement of supply in order to minimize cost and price volatility to our customers.
Our Nebraska natural gas supply requirements for the year ended December 31, 2006, were approximately 4.9 million dekatherms. Our Nebraska natural gas supply, storage and pipeline requirements are fulfilled primarily through a third-party contract with ONEOK Energy Marketing and Trading, LP.
To supplement firm gas supplies in South Dakota and Nebraska, we also contract for firm natural gas storage services to meet the heating season and peak day requirements of our natural gas customers. We also maintain and operate two propane-air gas peaking units with a peak daily capacity of approximately 6,400 dekatherms. These plants provide an economic alternative to pipeline transportation charges to meet the peaks caused by customer demand on extremely cold days.
UNREGULATED ELECTRIC OPERATIONS
We lease a 30% share of Colstrip Unit 4, a 740 megawatt demonstrated-capacity coal-fired power plant located in southeastern Montana. The lease term runs through December 31, 2018. Our leased interest represents approximately 222 megawatts at full load. We expect to finalize the purchase of the owner participant interest in a portion of the Colstrip Unit 4 generating facility in the first quarter of 2007, representing approximately 79 megawatts of our leased interest for approximately $39 million.
We sell the majority of our generation from Colstrip Unit 4 to Puget Sound Energy (Puget) and DB Energy Trading, LLC, (DB) under agreements expiring on December 29, 2010. When operating at full contract capacity, we deliver 97 megawatts to Puget and 111 megawatts to DB plus losses.
We have a separate agreement with DB to repurchase 111 megawatts through December 2010, which are available for market sales to other third parties through June 2007. Beginning July 1, 2007, 90 megawatts have been committed to supply a portion of the Montana default supply load through December 31, 2018. We currently have approximately 132 megawatts of uncommitted base-load capacity after December 31, 2010. Due to the base-load nature of this capacity and the fact that the northwestern region of the United States is projected to be “short” of base-load capacity in 2010, we do not believe that we have a material financial risk arising from this merchant capacity.
A long-term coal supply contract with Western Energy Company provides the coal necessary to run the Colstrip facility.
UNREGULATED NATURAL GAS OPERATIONS
Our subsidiary, NorthWestern Services LLC (NSC), provides natural gas supply and management services, to approximately 70 retail choice customers in eastern South Dakota. In addition, NSC’s subsidiary, Nekota Resources LLC, (Nekota), owns and operates 88 miles of intrastate natural gas pipeline used to make retail deliveries of natural gas. In 2006, NSC managed 14.7 million dekatherms and sold approximately 6 million dekatherms of natural gas supply. We are currently evaluating our unregulated natural gas business. During the first quarter of 2007, we expect to transfer Nekota and certain customers to our regulated natural gas segment. In addition, we may seek to sell the remaining unregulated natural gas business.
Natural gas is a commodity that is subject to significant market price fluctuations. Moreover, competition currently exists for commodity sales to large volume customers and for delivery in the form of system by-pass, alternative fuel sources such as propane and fuel oil and, in some cases, duplicate providers. As a result, NSC faces material competition from alternative natural gas supply companies for certain customers.
NSC’s natural gas supply portfolio is comprised of third-party fixed-term purchase contracts and short-term market
purchases. To allow NSC to focus on more profitable transactions, certain customers have been encouraged to obtain natural gas supply from other providers.
SEASONALITY AND CYCLICALITY
Our electric and gas utility businesses are seasonal businesses, and weather patterns can have a material impact on their 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 revenues 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 summers in the future, these weather patterns could adversely affect our results of operations and financial condition.
REGULATION
Electric Operations
Our utility operations are subject to various federal, state and local laws and regulations affecting businesses generally, such as laws and regulations concerning service areas, tariffs, issuances of securities, employment, occupational health and safety, protection of the environment and other matters.
Federal
We are a “public utility” within the meaning of the Federal Power Act. Accordingly, we are subject to the jurisdiction of, and regulation by, the FERC with respect to the issuance of securities, incurrence of certain long-term debt, the transmission of electric energy in interstate commerce and the setting of wholesale electric rates. As such, we are required to submit annual filings of certain financial information on the FERC Form No. 1, Annual Report of Major Electric Utilities, Licensees and Others, and quarterly filings of certain financial information on the FERC Form No. 3-Q, Quarterly Financial Report of Electric Companies, Licensees, and Natural Gas Companies.
In Montana, we sell transmission service across our system under terms, conditions and rates defined in our Open Access Transmission Tariff (OATT), on file with FERC, which became effective in July 1996. We are required to provide retail transmission service in Montana under tariffs for customers still receiving “bundled” service and under the OATT for “choice” customers. In October 2006, we submitted a filing with FERC requesting an increase in transmission rates in Montana under the OATT. While the request presents a net increase of $28.8 million in overall transmission costs, the rate adjustment pertains only to wholesale transmission and retail choice customers. Therefore, the portion of the requested cost increase pertaining to the remaining Montana retail customer default supply loads, which represents approximately 70% of this increase, is subject to MPSC jurisdictional rates, and will be subject to MPSC review and approval prior to any increase in rates. Since the last FERC transmission rate adjustment, which was filed in March 1998, our cost of service has increased and the type of transmission service that we provide has changed as partial retail access has developed in Montana. The overall net effect of this filing for affected customers is expected to be an average rate increase of between 6 - 18%, depending on the type of customer.
We have also requested certain changes to the tariff, most notably, changing network service to a stated rate instead of a load ratio share-based charge and the inclusion of a new schedule for generation imbalance service. In December 2006, FERC issued an initial order approving our proposal to convert from load ratio share to a stated rate. The FERC accepted our proposed revisions for filing, and suspended them until May 18, 2007, at which time the rates may be implemented, subject to refund. The FERC also set the proposed revisions for hearing and settlement judgment procedures. We expect to complete this process by June 2007; however, we cannot currently predict the outcome.
In South Dakota, the FERC has approved our request for waiver of the requirements of FERC Order No. 889 as it relates to the “Standards of Conduct,” exempting us as a small public utility. Without the waiver, the “Standards of Conduct” would have required us to physically separate our transmission operations and reliability functions from our marketing and merchant functions.
We have been participating with other transmission owners in the Pacific Northwest in the pursuit of independent
regional transmission management by an independent entity that had been known as Grid West. Grid West was dissolved during 2006 due to lack of support. Various transmission owners continued working on some of the Grid West initiatives, believing that an incremental approach to adding new services would be a better fit for the region. As a result, we signed a contract with Idaho Power Company, PacifiCorp and British Columbia Transmission Corporation to implement Area Control Error Diversity Interchange (ADI) between the control areas. This effort may reduce the regulating reserves required for our control area and help us to meet the required Western Energy Coordinating Council (WECC) control area reliability standards. It is anticipated that ADI will be implemented during the first quarter of 2007.
Our South Dakota transmission operations underlie the MISO system and are part of the WAPA Control Area. The Coyote and Big Stone I power plants, of 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 are not participating in the MISO markets that began operation on April 1, 2005, but continue to utilize WAPA to handle our scheduling requirements. We have negotiated a settlement as a grandfathered agreement with MISO and the other Big Stone I 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 are working with the other non-MISO MAPP members in developing an Independent Transmission Services Coordinator. It is still intended for MISO to provide the reliability coordinator functions for MAPP.
On November 25, 2003, FERC issued Order No. 2004 on Standards of Conduct. In Order No. 2004, FERC adopted standards of conduct that apply uniformly to interstate natural gas pipelines and public utilities (jointly referred to as Transmission Providers) that are subject to the gas and electric standards of conduct in Part 161 and Part 37 of FERC’s regulations, respectively. The standards of conduct govern the relationship between regulated Transmission Providers and their Energy Affiliates. We are a Transmission Provider because we are a public utility currently subject to Part 37 of FERC’s regulations. On April 9, 2004, we submitted a compliance filing under Order No. 2004 requesting the FERC to clarify and confirm that our Montana natural gas system operations do not qualify as an “Energy Affiliate” of our electric transmission operations or, in the alternative, grant us a limited waiver of the independent functioning requirements of sections 358.2 and 358.4 of the FERC’s regulations. The request for a limited waiver would allow us to (1) operate our interstate electric transmission and Montana’s intrastate natural gas distribution (and associated transmission and storage) systems in a common control center with employees trained in both areas but operating in only one discipline on any given shift, and (2) train our scheduling employees on both electric and gas systems to ensure adequate staffing during emergencies and employee vacations. On July 20, 2006, the FERC ruled, based on our representations that our gas LDC division is not engaged in any off-system sales or any of the other Energy Affiliate activities, that our LDC division meets the criteria for exemption of sections 358.3(d)(6)(v), and, therefore is not an Energy Affiliate under Order No. 2004.
We have conducted an “Open Season” for the development of new electric transmission capacity from Montana to Idaho. Although still early in the development stages, potential customers have made transmission service requests for 850 megawatts of capacity in the project. These requests can be revoked at any time by the customer up to the point of an executed service agreement between the customer and us. The customer would be responsible for the costs of development through defined FERC Tariff procedures. If successful, the process could lead to a significant transmission project for the movement of energy from Montana to the south or vice versa and would be the first large-scale bulk transmission project in our control area in nearly 20 years. On September 12, 2006, we submitted a petition for declaratory order seeking FERC approval to use a transmission rate design that allocates cost responsibility for new and expanded transmission facilities along two related but distinct transmission paths, according to the cost of the new facilities required to satisfy particular service requests. On December 22, 2006, FERC granted our petition and found that our pricing proposal is consistent with the FERC’s “Or” pricing policy. With FERC’s approval of our pricing proposal, we have begun developing “indicative” prices for the various transmission alternatives under the “Open Season” and will be meeting with the participants early in 2007 to discuss these prices. These proposed rates will be subject to review by the FERC in a future rate proceeding.
In August 2006, we entered into an Amended and Restated Interconnection Agreement with Idaho Power Company, PacifiCorp, and Avista Corporation which governs the operation and maintenance of a jointly owned 230,000-volt transmission line (commonly referred to as the “AMPS” line) that extends from the Noxon area in northwestern Montana to Treasureton in southeast Idaho. The original Interconnection Agreement was executed in 1965. The Amendment serves several purposes. First, certain provisions of the Agreement regarding resource sharing that are no longer applicable were eliminated. Second, the Amended Agreement provides for the installation of a Phase Shifting Transformer (PST) in our Mill Creek Substation near Butte, Montana. The PST is required to control power flows on the AMPS line and assure electricity reliability of the parties’ interconnected systems. NorthWestern Energy, Idaho Power Company, and PacifiCorp will own the PST, which is expected to be installed and energized in the spring of 2008. Finally, the Amended and Restated Interconnection Agreement extends the term of the original agreement by 10 years to April 2025. By its order dated
December 18, 2006, FERC accepted the Amended and Restated Interconnection Agreement for filing.
One of the principal legislative initiatives of the current administration is the adoption of comprehensive federal energy legislation. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (2005 Act). The 2005 Act includes a wide range of provisions addressing many aspects of the energy industry. Specifically, with respect to the electric utility industry, the 2005 Act includes provisions which, among other things, repeal the Public Utility Holding Company Act of 1935 (PUHCA) as of February 8, 2006, create incentives for the construction of transmission infrastructure, eliminates the statutory restrictions on ownership of qualifying facilities by electric utilities, and expand the authority of FERC to include overseeing the reliability of the bulk power system.
Montana
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. As a public utility, we are also subject to MPSC jurisdiction when we issue, assume, or guarantee securities in Montana, or when we create liens on our regulated Montana properties. As such, we are required to submit annual filings of certain financial information on our Electric, Natural Gas, and Propane Utilities.
In accordance with a 2004 stipulation and settlement agreement between NorthWestern, the MPSC and the MCC, on September 29, 2006 we submitted an informational filing to the MPSC outlining our cost of providing electric and natural gas delivery service in Montana. The informational filing is based on actual costs in 2005, adjusted for known and measurable cost changes that occurred in 2006. The filing demonstrates a revenue deficiency of approximately $29.1 million in electric rates and $12.3 million in natural gas rates; however, we did not seek a rate adjustment, as we would like the MPSC to give priority to its approval of the transaction with BBI.
Montana’s Electric Utility Industry Restructuring and Customer Choice Act (Montana Restructuring Act) enabled larger customers in Montana to choose their supplier of commodity electricity beginning on July 1, 1998, and provided that all other Montana customers would be able to choose their electric supplier during a transition period through June 30, 2007. Under this legislation, during this transition period, we were designated to serve as the “default supplier” for customers who have not chosen an alternate supplier. The Montana Restructuring Act provided for the full recovery of costs incurred in procuring default supply contracts during this transition period. Two additional electric energy bills, HB 509 and SB 247, were passed by the 2003 Montana Legislature. These bills established us as the permanent default supplier, extended the transition period to June 30, 2027, required smaller customers to remain default supply customers through the transition period, and established a specific set of requirements and procedures that guide power supply procurements and their cost recovery. Compliance with these procurement procedures should mitigate the risk of nonrecovery of our costs of acquiring electric supply.
South Dakota
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 operations. Under the South Dakota Public Utilities Act, a requested rate increase may be implemented 30 days after the date of its filing unless its effectiveness is suspended by the SDPUC and, in such event, can be implemented subject to refund with interest six months after the date of filing, unless authorized sooner by the SDPUC. Our electric rate schedules provide that we may pass along to all classes of customers qualified increases or decreases in costs related to fuel used in electric generation, purchased power, energy delivery costs and ad valorem taxes.
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. An 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.
The states of South Dakota, North Dakota and Iowa have enacted laws with respect to the siting of large electric generating plants and transmission lines. The SDPUC, the North Dakota Public Service Commission and the Iowa Utilities Board have been granted authority in their respective states to issue site permits for nonexempt facilities.
Natural Gas Operations
Federal
FERC Order No. 636 requires that all companies with interstate natural gas pipelines separate natural gas supply and production services from interstate transportation service and underground storage services. The effect of the order was that natural gas distribution companies, such as us, and individual customers purchase natural gas directly from producers, third parties and various gas-marketing entities and transport it through interstate pipelines. We have established transportation rates on our transmission and distribution systems to allow customers to have supply choices. Our transportation tariffs have been designed to make us economically indifferent as to whether we sell and transport natural gas or merely deliver it for the customer.
Our natural gas transportation pipelines are generally not subject to the jurisdiction of the FERC, 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.
Montana
Our Montana operations are subject to the jurisdiction of the MPSC with respect to natural gas rates, terms and conditions of service, accounting records, and other aspects of its operations. As a public utility, we are also subject to MPSC jurisdiction when we issue, assume or guarantee securities in Montana, or when we create liens on our Montana properties.
South Dakota
Our South Dakota operations are subject to the jurisdiction of the SDPUC with respect to rates, terms and conditions of service, accounting records and other aspects of our natural gas distribution operations in South Dakota. Under the South Dakota Public Utilities Act, a requested rate increase may be implemented 30 days after the date of its filing unless its effectiveness is suspended by the SDPUC and, in such event, can be implemented subject to refund with interest six months after the date of filing, unless authorized sooner by the SDPUC. 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. 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.
Our retail natural gas tariffs, approved by the SDPUC, 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’s premises. Such transporting customers nominate the amount of natural gas to be delivered daily and telemetric equipment installed for each customer monitors daily usage.
Nebraska
Our natural gas rates and terms and conditions of service for residential and smaller commercial customers are regulated in Nebraska by the NPSC. High volume customers are not subject to such regulation but can file complaints if they allege discriminatory treatment. Under the State Natural Gas Regulation Act, for a regulated natural gas utility to propose a change in rates to its regulated customers, it is required to file 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, or it may proceed to have the NPSC review the filing and make a determination. While the utility and the communities are negotiating a settlement, the utility can commence charging the requested rate, as interim rates subject to refund, 60 days after the filing of the increase request. If the utility and the communities are unable to reach a settlement, then the matter is transferred to the NPSC for its review and further proceedings. The interim rates become final and no longer subject to refund if the NPSC has not taken final action within 210 days after the matter is referred to the NPSC.
Since enactment of the State Natural Gas Regulation Act, our initial tariffs, representing rates in effect at the time the law was approved, 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.
ENVIRONMENTAL
Environmental laws and regulations are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be accurately predicted. The range of exposure for environmental remediation obligations at present is estimated to range between $20.4 million to $56.1 million. As of December 31, 2006, we have a reserve of approximately $34.1 million. We anticipate that as environmental costs become fixed and reliably determinable, we will seek insurance reimbursement and/or authorization to recover these in rates; therefore, we do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.
The Clean Air Act Amendments of 1990 and subsequent amendments stipulate limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants. We comply with these existing emission requirements through purchase of sub-bituminous coal, and we believe that we are in compliance with all presently applicable environmental protection requirements and regulations with respect to these plants. Recent legislation has been proposed, which may require further limitations on emissions of these pollutants along with limitations on carbon dioxide, particulate matter, and mercury emissions. The recent regulatory and legislative proposals are subject to normal administrative processes, and we cannot make any prediction as to whether the proposals will pass or the impact of those actions. In November 2006, The Sierra Club sent a Notice of Intent to File a Suit to the owners, including us, of Big Stone I, asserting that it would file a lawsuit in 60 days alleging that the plant failed to obtain permits for certain projects undertaken in 1995, 2001 and 2005 and otherwise failed to comply with the Clean Air Act. The owners intend to vigorously defend against any lawsuit filed by The Sierra Club.
Coal-Fired Plants
Citing its authority under the Clean Air Act, the EPA has finalized Clean Air Mercury Regulations (CAMR) that affect coal-fired plants. These regulations establish a cap-and-trade program to take effect in two phases, with a first phase to begin in January 2010, and a second phase with more stringent caps to begin in January 2018. Under CAMR, each state is allocated a mercury emissions cap and is required to develop regulations to implement the requirements, which can follow the federal requirements or be more restrictive.
Montana has finalized its own, more stringent rules that would require every coal-fired generating plant in the state to achieve by 2010 reduction levels more stringent than CAMR’s 2018 cap. Because enhanced chemical injection technologies may not be sufficiently developed to meet this level of reductions by 2010, there is a risk that adsorption/absorption technology with fabric filters at the Colstrip Unit 4 generation facility would be required, which could represent a material cost. We expect the Montana mercury rules to be challenged. If those rules are overturned and we are instead required to comply with CAMR, achievement of the 2010 and 2018 requirements may be possible with more refined chemical injection technology combined with adjustments to boiler/fireball dynamics at a minimal cost. We are continuing to work with the other Colstrip owners to determine the ultimate financial impact of these new rules.
Manufactured Gas Plants
Approximately $28.6 million of our environmental reserve accrual is related to manufactured gas plants. Two formerly operated manufactured gas plants located in Aberdeen and Mitchell, South Dakota, have been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS) list as contaminated with coal tar residue. At this time, no material remediation is necessary at the Mitchell location. In January 2007, we received a letter from the South Dakota Department of Environment and Natural Resources (SD DENR) that this location is at a No Further Action Status. We are currently investigating and characterizing the Aberdeen site pursuant to work plans approved by the SD DENR and some remedial activities commenced at the Aberdeen site in 2006. Our current reserve for remediation costs at the Aberdeen site is approximately $15.4 million, and we estimate that approximately $13 million of this amount will be incurred during the next five years. During 2006, we incurred remediation costs of approximately $0.4 million.
We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. During 2005, the Nebraska Department of Environmental Quality (NDEQ) conducted Phase II investigations of soil and groundwater at our Kearney and Grand Island sites. On March 30, 2006 and May 17, 2006, the NDEQ released to us the Phase II Limited Subsurface Assessment performed by the NDEQ’s environmental consulting firm for Kearney and Grand Island, respectively, and we are evaluating the results of these reports. We plan to conduct additional site investigation and assessment work at these locations in 2007. At present, we cannot determine with a reasonable degree of certainty the
nature and timing of any remediation cleanup at our Nebraska locations.
In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require entry into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program, but required preparation of a groundwater monitoring plan. The Butte and Helena sites, were placed into the MDEQ’s voluntary remediation program for cleanup due to the existence of exceedences of regulated pollutants in the groundwater. We conducted additional groundwater monitoring during 2005 at the Butte and Missoula sites and have analyzed the data and presented it to the MDEQ. At this time, we believe that natural attenuation should address the problems at these sites; however, additional groundwater monitoring will be necessary. Closure of the Butte and Missoula sites is expected shortly. Recent monitoring of groundwater at the Helena manufactured gas plant site suggests that groundwater remediation may be necessary to prevent certain contaminants from migrating offsite. We have evaluated the results of a pilot program meant to promote aerobic degradation of certain targeted contaminants. Further data collection is necessary to complete the evaluation and assess other remediation technologies to determine the optimal remedial technology for this site. Monitoring of groundwater at this site will be necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remediation at the Helena site.
Based upon our investigations to date, our current environmental liability reserves, applicable insurance coverage, and the potential to recoup some portion of prudently incurred remediation costs in rates, we do not expect remediation costs at these locations to be materially different from the established reserve.
Milltown Mining Waste
Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the Milltown Dam hydroelectric facility, a three megawatt generation facility located at the confluence of the Clark Fork and Blackfoot Rivers. In April 2003, the Environmental Protection Agency (EPA) announced its proposed remedy to address the mining waste contamination located in the Milltown Reservoir. This remedy proposed partial removal of the contaminated sediments located within the Milltown Reservoir, together with the removal of the Milltown Dam and powerhouse (this remedy was incorporated into the EPA’s formal Record of Decision issued on December 20, 2004). In light of this pre-Record of Decision announcement, we entered into a stipulation (Stipulation) with Atlantic Richfield, the EPA, the Department of the Interior, the State of Montana and the Confederated Salish and Kootenai Tribes (collectively the Government Parties), which capped NorthWestern’s and CFB’s collective liability to Atlantic Richfield and the Government Parties at $11.4 million. In April 2006, we released escrowed amounts of $2.5 million and $7.5 million to the State of Montana and Atlantic Richfield, respectively, in accordance with the terms of the consent decree described below. Pursuant to the terms of the consent decree, the parties expect that the remaining financial obligation of $1.4 million to the State of Montana will be covered through a combination of any refund of premium upon cancellation of the catastrophic release policy described below, and the sale or transfer of land and water rights associated with the Milltown Dam operations.
On July 18, 2005, CFB and we executed the Milltown Reservoir superfund site consent decree, which incorporated the terms set forth in the Stipulation. The consent decree was approved by the Federal District Court for the District of Montana on February 8, 2006 and became effective on April 10, 2006. In light of the material environmental risks associated with the catastrophic failure of the Milltown Dam, we secured a 10-year, $100 million environmental insurance policy, effective May 31, 2002, to mitigate the risk of future environmental liabilities arising from the structural failure of the Milltown Dam caused by an act of God. We are obligated under the settlement to continue to maintain the environmental insurance policy until the Milltown Dam is removed during implementation of the remedy.
Other
We continue to manage polychlorinated biphenyl (PCB)-containing oil and equipment in accordance with the EPA’s Toxic Substance Control Act regulations. We, along with other potentially responsible parties, are currently negotiating with EPA over remediation of an oil recycling facility in Oregon to which waste oil had been transported by The Montana Power Company and others. We anticipate that these negotiations will be successfully resolved during 2007. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.
We routinely engage the services of a third-party environmental consulting firm to perform a comprehensive evaluation of our environmental reserve. Based upon information available to our consultants at this time, we believe that the current
environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:
•
We and our third-party consultant may not know all sites for which we are alleged or will be found to be responsible for remediation; and
•
Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.
EMPLOYEES
As of December 31, 2006, we had 1,354 employees. Of these, 1,031 employees were in Montana and 323 were in South Dakota or Nebraska. Of our Montana employees, 407 were covered by six collective bargaining agreements involving five unions. In addition, our South Dakota and Nebraska operations had 195 employees covered by the System Council U-26 of the International Brotherhood of Electrical Workers. We consider our relations with employees to be in good standing.
ITEM 1A.
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 shares or other securities.
The agreement to sell NorthWestern to BBI will be completed only if certain conditions are met, including various federal and state regulatory approvals. If the sale is not completed, then our shareholders may not be able to obtain the premium for their shares of common stock offered in the proposed transaction.
The agreement to sell NorthWestern to BBI is still subject to MPSC approval and certain other closing conditions. The inability to obtain MPSC approval or fulfill those closing conditions could result in the termination of the agreement. If the BBI transaction does not close, then our shareholders will not receive the agreed upon purchase price per share.
We have incurred, and may continue to incur, significant costs associated with outstanding litigation and the formal investigation being conducted by the SEC relating to the restatement of our 2002 quarterly financial statements and other accounting and financial reporting matters (SEC investigation), which may adversely affect our results of operations and cash flows.
These costs, which are being expensed as incurred, have had, and may continue to have an adverse affect on our results of operations and cash flows. Pending litigation matters are discussed in detail under the Legal Proceedings section in Note 23 to the Consolidated Financial Statements. An adverse result in any of these matters could have an adverse effect on our business.
We are subject to extensive governmental regulations that affect our industry and our operations. Existing and changed regulations and possible deregulation have the potential to impose significant costs, increase competition and change in rates which could have a material adverse effect on our results of operations and financial condition.
Our operations are subject to extensive federal, state and local laws and regulations concerning taxes, service areas, tariffs, rates, issuances of securities, employment, occupational health and safety, protection of the environment and other matters. In addition, we are required to obtain and comply with a wide variety of licenses, permits and other approvals in order to operate our facilities. In the course of complying with these requirements, we may incur significant costs. If we fail to comply with these requirements, then we could be subject to civil or criminal liability and the imposition of liens or fines. In addition, existing regulations may be revised or reinterpreted, new laws, regulations, and interpretations thereof may be adopted or become applicable to us and future changes in laws and regulations may have a detrimental effect on our business.
We are regulated by commissions in the states we serve. As a result, these commissions review our books and records, including energy supply contracts, which could result in rate changes or other limitations on our ability to recover costs and have a material adverse effect on our results of operations and financial condition.
Competition for various aspects of electric and natural gas services has been introduced throughout the country that will
open these markets to new providers of some or all of traditional electric utility and natural gas services. Competition could result in the further unbundling of electric utility and natural gas services as has occurred in Montana for electricity and in Montana, South Dakota and Nebraska for natural gas. Separate markets may emerge for generation, transmission, distribution, meter reading, billing and other services currently provided by electric utility and natural gas providers as a bundled service. As a result, additional competitors could become active in the generation, transmission and distribution segments of our industry.
To the extent our incurred supply costs are deemed imprudent by the applicable state regulatory commissions, we would under-recover 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 contract 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 MPSC or other applicable state regulatory commissions, we would under-recover our costs, which could adversely impact our results of operations. During the fourth quarter of 2005, the MCC submitted testimony alleging we were imprudent and recommending the MPSC consider disallowing portions of our forecasted electric and natural gas supply costs contained in the 2005 tracker filings. In March 2006, upon signing a stipulation with the MCC, we recognized a loss of approximately $4.3 million related to the removal of replacement costs and certain forward sales contracts from our 2005-2006 electric tracking period forecast. The stipulation settles various issues relative to our electric supply costs raised by the MCC and has been approved by the MPSC in its final order regarding our 2005 electric tracker filing. Our actual costs for the 2005-2006 tracking period were presented in our 2006 tracker filing. The MPSC suspended the 2006 electric tracker docket and will combine it with our 2007 tracker filing for processing purposes. In May 2006, the MPSC approved our 2005 annual natural gas tracker as filed.
We do not own any natural gas reserves or regulated electric generation assets to service our Montana operations. As a result, we are required to procure our entire natural gas supply and substantially all of our Montana electricity 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 commercially reasonable 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.
Our obligation to supply a minimum annual quantity of power to the Montana default supply could expose us to material commodity price risk if certain qualifying facilities (QFs) under contract with us do not supply during a time of high commodity prices, as we are required to supply any quantity deficiency.
We perform management of the QF portfolio of resources under the terms and conditions of the QF Tier II Stipulation. This Stipulation may subject us to commodity price risk if the QF portfolio does not perform in a manner to meet the annual minimum energy requirement.
As part of the Stipulation and Settlement with the MPSC and other parties in the Tier II Docket, we agreed to supply the default supply with a certain minimum amount of power at an agreed upon price per megawatt. The annual minimum energy requirement is achievable under normal QF operations, including normal periods of planned and forced outages. Furthermore, we will not realize commodity price risk, unless any required replacement energy cost is in excess of the total amount recovered under the QF contracts.
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 secure the quantity deficiency from other sources. Since we own no material generation in Montana, the anticipated source for any quantity deficiency is the wholesale market which, in turn, would subject us to commodity price volatility.
The value of our Colstrip Unit 4 leasehold improvements could be impaired if we are unable to obtain adequate terms on 132 megawatts of power that are not under contract after 2010.
Beginning July 1, 2007, 90 megawatts of base-load energy from Colstrip Unit 4 has been committed to supply a portion of the Montana default supply for a term of 11.5 years, commencing on July 1, 2007, at an average nominal price of $35.80 per megawatt hour. We expect that the sale of the 132 megawatts of our remaining output, which is not under contract after
2010, will be sufficient to allow us to recover the carrying value of our Colstrip Unit 4 leasehold improvements. If we are unable to sell the 132 megawatts at such a sufficient price, then the value of our Colstrip Unit 4 leasehold improvements would be materially adversely impacted.
Our jointly owned electric generating facilities and our leasehold interest in Colstrip Unit 4 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. Most of our generating capacity is coal-fired. We rely on a limited number of suppliers of coal, 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 I Plant (our largest source of generation in South Dakota), making us vulnerable to railroad capacity issues and/or increased prices for coal transportation from a sole supplier. Operational risks also include facility shutdowns due to breakdown or failure of equipment or processes, labor disputes, operator error and catastrophic events such as fires, explosions, floods, intentional acts of destruction or other similar occurrences affecting the electric generating facilities. The loss of a major generating facility would require us to find other sources of supply, if available, and expose us to higher purchased power costs.
Seasonal and quarterly fluctuations of our business 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 revenues 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 condition 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.
Our utility business is subject to extensive environmental laws and regulations and potential environmental liabilities, which could result in significant costs and liabilities.
Our utility business is 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, solid waste disposal and other environmental considerations. We believe that we are in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect our financial position or results of operations. However, possible future developments, including the promulgation of more stringent environmental laws and regulations, such as the new mercury emissions rules in Montana, and the timing of future enforcement proceedings that may be taken by environmental authorities could affect the costs and the manner in which we conduct our business and could require us to make substantial additional capital expenditures.
Many of these environmental laws and regulations create permit and license requirements and provide for substantial civil and criminal fines which, if imposed, could result in material costs or liabilities. We cannot predict with certainty the occurrence of private tort allegations or government claims for damages associated with specific environmental conditions. 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 in order to meet future requirements and obligations under environmental laws.
Environmental laws and regulations require us to incur certain costs, which could be substantial, to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment. Governmental regulations establishing environmental protection standards are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be predicted. Our range of exposure for environmental remediation obligations is estimated to be $20.4 million to $56.1 million. We had an environmental reserve of $34.1 million at December 31, 2006. This reserve was
established in anticipation of future remediation activities at our various environmental sites and does not factor in any exposure to us arising from new regulations, private tort actions or claims for damages allegedly associated with specific environmental conditions. To the extent that our environmental liabilities are greater than our reserves or we are unsuccessful in recovering anticipated insurance proceeds under the relevant policies or recovering a material portion of remediation costs in our rates, our results of operations and financial condition could be adversely affected.
A downgrade in our credit ratings could negatively affect our ability to operate our business and/or access capital.
A downgrade of our credit ratings could adversely affect our liquidity, as counter parties could require us to post collateral. In addition, our ability to raise capital on favorable terms could be hindered and our borrowing costs could increase.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None
ITEM 2.
ITEM 2.
PROPERTIES
NorthWestern’s executive offices are located at 125 S. Dakota Avenue, Sioux Falls, South Dakota 57104, where we lease approximately 27,350 square feet of office space, pursuant to a lease that expires on June 30, 2007.
Our principal office for our South Dakota and Nebraska operations is owned and located at 600 Market Street W., Huron, South Dakota 57350. Substantially all of our South Dakota and Nebraska facilities are owned. Our principal office for our Montana operations is owned and located at 40 East Broadway Street, Butte, Montana 59701. We own or lease other offices throughout the state of Montana, including a 20,000 square foot facility in Butte, Montana, where we provide call center customer support services and conduct customer billing and other functions.
For further information regarding our operating properties, including generation and transmission, see the descriptions included in Item 1.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
We discuss details of our legal proceedings in Note 23, Commitments and Contingencies, to the Consolidated Financial Statements. Some of this information is about costs or potential costs that may be material to our financial results.
ITEM 4.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of our security holders during the quarter ended December 31, 2006.
Part II
ITEM 5.
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 NWEC, is listed on the NASDAQ Global Select Market System. As of February 23, 2007, there were approximately 1,071 common stockholders of record.
Dividends
We pay dividends on our common stock after our Board of Directors (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 2006. Quarterly dividends were declared and paid on our common stock during 2006 as set forth in the table below.
QUARTERLY COMMON STOCK PRICE RANGES AND DIVIDENDS
On February 23, 2007, the last reported sale price on the NASDAQ for our common stock was $36.41.
Securities Authorized for Issuance under Equity Compensation Plans
The following table presents summary information about our equity compensation plans, including our employee incentive plan. The table presents the following data on our plans as of the close of business on December 31, 2006:
(i)
the aggregate number of shares of our common stock subject to outstanding stock options, warrants and rights;
(ii)
the weighted average exercise price of those outstanding stock options, warrants and rights; and
(iii)
the number of shares that remain available for future option grants, excluding the number of shares to be issued upon the exercise of outstanding options, warrants and rights described in (i) above.
For additional information regarding our stock option plans and the accounting effects of our stock-based compensation, please see Notes 3 and 19 to our Financial Statements included in Item 8 herein.
(1)
Upon emergence from bankruptcy, a New Incentive Plan, which is described more fully in Item 11 herein, was established pursuant to our Plan of Reorganization, which set aside 2,265,957 shares for the new Board to establish equity-based compensation plans for employees and directors. As the New Incentive Plan was established by provisions of the Plan of Reorganization, shareholder approval was not required. Upon emergence, 228,315 shares of restricted stock were granted (Special Recognition Grants) under the New Incentive Plan to certain officers and key employees. There are 17,582 remaining unvested shares under this grant. In addition, during 2005 the NorthWestern Corporation 2005 Long-Term Incentive Plan was established under the New Incentive Plan, under which restricted stock grants of 588,238 shares, net of forfeitures, have been distributed and 43,739 deferred stock units and 11,000 shares of restricted stock have been granted to our Board.
ITEM 6.
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. Between September 14, 2003 and October 31, 2004, we operated as a debtor-in-possession under the supervision of the Bankruptcy Court. Our financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code. In accordance with SOP 90-7, we applied the principles of fresh-start reporting as of the close of business on October 31, 2004. During 2003, we committed to a plan to sell or liquidate our interest in Expanets and Blue Dot and accounted for our interest in these subsidiaries as discontinued operations. In 2002, we disposed of our interest in CornerStone and accounted for the disposal as discontinued operations. Accordingly, the financial data below for 2002 has been restated.
FIVE-YEAR FINANCIAL SUMMARY
(1)
Income (loss) from continuing operations includes reorganization items. The financial position information is that of the Successor Company as of October 31, 2004.
(2)
Per share results have not been presented for the Predecessor Company as all shares were cancelled upon emergence.
(3)
The fixed charges exceeded earnings, as defined by this ratio, by $11.5 million for the two-months ended December 31, 2004, and $86.6 million and $77.8 million for the years ended December 31, 2003 and 2002, respectively.
ITEM 7.
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 25 of “Notes to Consolidated Financial Statements” of our consolidated financial statements, which are included in Item 8 herein. For information regarding our revenues, net income (losses) and assets, see our consolidated financial statements included in Item 8.
OVERVIEW
NorthWestern Corporation, doing business as Northwestern Energy, is one of the largest providers of electricity and natural gas in the Upper Midwest and Northwest, serving approximately 640,000 customers in Montana, South Dakota and Nebraska. As you read this discussion and analysis, refer to our Consolidated Statements of Income (Loss), which present the results of our operations for 2006, 2005 and 2004. Following is a brief overview of highlights for 2006, and a discussion of our strategy. Additional details on our results of operations follow the Critical Accounting Policies and Estimates section.
Pending Merger with Babcock & Brown Infrastructure Limited
On April 25, 2006, we entered into an Agreement and Plan of Merger (Merger Agreement) with BBI, an infrastructure investment company listed on the Australian Stock Exchange, under which BBI will acquire NorthWestern Corporation in an all-cash transaction at $37 per share. The Merger Agreement has been unanimously approved by both companies’ Boards of Directors. Our shareholders approved the Merger Agreement at our August 2, 2006 annual meeting.
The transaction is conditioned upon a number of federal and state regulatory approvals or reviews, and satisfaction of other customary closing conditions. We have received approvals or clearances from the following:
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Committee on Foreign Investments in the United States in July 2006;
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United States Federal Trade Commission and the United States Department of Justice under the Hart-Scott-Rodino Antitrust Improvement Act of 1976 in October 2006;
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NPSC in October 2006;
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FERC in October 2006;
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Federal Communications Commission in February 2007.
Due to existing statutory language in South Dakota, we submitted a filing to the SDPUC to determine if it has jurisdiction over the sale and, if so, for transaction approval. In July, the SDPUC filed a notice with FERC that it intended to intervene and file a protest in the federal proceedings. In October, we reached a settlement agreement under which the SDPUC will not oppose approval of the transaction by FERC, which includes the following provisions:
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We and BBI will not seek rate recovery of costs associated with the transaction;
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The majority of our future Board of Directors will be U.S. citizens with at least one South Dakota resident and at least one independent member who will have substantial utility or financial experience. In addition, the independent member(s) shall serve as chair of the Audit Committee and the Governance Committee;
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We will apply the ring fencing provisions of the 2004 Stipulation and Settlement Agreement between us, the MPSC and MCC for the benefit of the SDPUC and South Dakota ratepayers;
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We will not borrow money secured by South Dakota regulated utility assets to upstream funds to either BBI or its affiliates without prior approval of the SDPUC; and
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We will maintain our corporate headquarters in Sioux Falls, South Dakota until the later of June 30, 2010 or three years following the effective date of the merger. We will continue to maintain senior management personnel in both South Dakota and Montana.
In December, the SDPUC determined that current state law does not allow them to exercise jurisdiction over the proposed sale.
We must still obtain the approval of the MPSC. We and the intervenors have submitted testimony and additional information to the MPSC. The MPSC has set a tentative date of March 14, 2007 to commence a technical hearing on the transaction. We anticipate receiving the MPSC’s decision during the first half of 2007. If so, then we anticipate closing the transaction in the second quarter of 2007.
The Merger Agreement contains certain covenants whereby NorthWestern is required to continue to operate in the ordinary course of business and must obtain BBI’s consent prior to making certain new investments or divestitures, issuing new debt or common stock or making dividend changes, among other provisions. In addition, the Merger Agreement also contains certain termination rights for both NorthWestern and BBI in which under specified circumstances NorthWestern may be required to pay BBI a termination fee of $50 million and BBI may be required to pay NorthWestern a business interruption fee of $70 million.
In November 2006, a majority of the remaining shares available under our 2005 Long-Term Incentive Plan were granted to directors, officers and employees. These service-based restricted share awards vest over the next five years; however, all unvested shares will vest immediately upon closing of the transaction with BBI. If the transaction is completed in 2007 as anticipated, stock-based compensation expense will be approximately $14 million. Upon closing, NorthWestern's common stock will cease to be publicly traded.
Other Highlights
Other highlights for the year include:
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On July 5, 2006, we signed a seven-year power purchase agreement with PPL Montana (PPL) beginning July 1, 2007. The megawatt hours purchased decline over the seven-year period, allowing us to methodically transition our Montana default supply electricity mix to more diverse resources. Over the life of the agreement, NorthWestern will purchase 13.7 million megawatt hours at a cost of approximately $675 million. Our purchase obligation under this agreement is not conditioned upon approval by the MPSC, however we will, in a timely manner, seek review and approval by the MPSC on the key commercial terms (price, term and quantity) set forth in the agreement. The structure of this power purchase agreement provides us with flexibility to pursue other long-term electricity supply options and is consistent with our 2005 Electricity Default Supply Resource Plan that was filed with the MPSC in December 2005.
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Achieved an investment grade credit rating on a senior secured debt basis from Moody’s Investor Service, giving us an investment grade credit rating on a senior secured basis by all three ratings agencies.
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Completed the refinancing of our Montana Pollution Control Obligations and Montana First Mortgage Bonds, reducing annualized interest expense by approximately $4.3 million.
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Completed the liquidation of Netexit in May 2006, and NorthWestern received additional cash proceeds of approximately $7.7 million during the six months ended June 30, 2006. In addition, during the first quarter of 2006, we completed the sale of our Montana First Megawatts generation assets and received net additional proceeds of $17.2 million.
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Received proceeds from a settlement agreement with an insurance provider totaling $9.3 million during the third quarter of 2006, which is reflected as a reduction to operating, general and administrative expenses.
Strategy
Our primary focus during 2007 will be to complete the proposed transaction with BBI. Once the transaction is completed, we will work with BBI to refine our long-term strategy. In addition, we are currently implementing plans to build an electric transmission pathway as described below.
Our Montana transmission assets are strategically located to take advantage of the potential transmission grid expansion in the Northwest part of the United States. We feel these types of FERC regulated projects would be able to provide stable and reliable returns. There are a number of potential paths and more than a dozen points of interconnection with major players in the Northwest.
We have conducted an “Open Season” for the development of new electric transmission capacity from Montana to Idaho. Although still early in the development stages, potential customers have made transmission service requests for 850 megawatts of capacity in the project. These requests can be revoked at any time by the customer up to the point of an executed service agreement between the customer and us. The customer(s) is responsible for the costs of development through defined FERC Tariff procedures. If successful, the process could lead to a significant transmission project for the movement of energy from Montana to the south or vice versa and would be the first large-scale bulk transmission project in our control area in nearly 20 years. On September 12, 2006, we submitted a petition for declaratory order seeking FERC approval to use a transmission rate design that allocates cost responsibility for new and expanded transmission facilities along two related but distinct transmission paths, according to the cost of the new facilities required to satisfy particular service requests. On December 22, 2006, FERC granted our petition and found that our pricing proposal is consistent with the FERC’s “Or” pricing policy. With FERC’s approval of our pricing proposal, we have begun developing “indicative” prices for the various transmission alternatives under the “Open Season” and will be meeting with the participants early in 2007 to discuss these prices. These proposed rates will be subject to review by FERC in a future rate proceeding.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Management’s discussion and analysis of financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances. We continually evaluate the appropriateness of our estimates and assumptions, including those related to goodwill, qualifying facilities liabilities, impairment of long-lived assets and revenue recognition, among others. Actual results could differ from those estimates.
We have identified the policies and related procedures below as critical to understanding our historical and future performance, as these polices affect the reported amounts of revenue and the more significant areas involving management’s judgments and estimates.
Goodwill and Long-lived Assets
We believe that the accounting estimate related to determining the fair value of goodwill and long-lived assets, and thus any impairment, is a “critical accounting estimate” because: (i) it is highly susceptible to change from period to period since it requires company management to make cash flow assumptions about future revenues, operating costs and discount rates over an indefinite life; and (ii) recognizing an impairment could have a significant impact on the assets reported on our balance sheet and our operating results. Management’s assumptions about future sales margins and volumes require significant judgment because actual margins and volumes have fluctuated in the past and are expected to continue to do so. In estimating future margins, we use our internal budgets.
Statement of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible Assets, was issued during 2001 and is effective for all fiscal years beginning after December 15, 2001. According to the guidance set forth in SFAS No. 142, we are required to evaluate our goodwill for impairment at least annually (October 1) and more frequently when indications of impairment exist. Accounting standards require that if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements. To measure the amount of the impairment loss to recognize, we compare the implied fair value of the reporting unit’s goodwill with its carrying value.
We evaluate our property, plant and equipment for impairment whenever indicators of impairment exist. SFAS No. 144, Accounting for the Impairment or the Disposal of Long-Lived Assets, requires that if the sum of the undiscounted cash flows from a company’s asset, without interest charges, is less than the carrying value of the asset, impairment must be recognized in the financial statements. If an asset is deemed to be impaired, then the amount of the impairment loss recognized represents the excess of the asset’s carrying value as compared to its estimated fair value, based on management’s assumptions and projections.
Qualifying Facilities Liability
Certain QFs under the Public Utility Regulatory Policy Act (PURPA) require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. As of December 31, 2006, our gross contractual obligation related to the QFs is approximately $1.6 billion. A portion of the costs incurred to purchase this energy is recoverable though rates authorized by the MPSC, totaling approximately $1.2 billion through 2029. We maintain a liability based on the net present value (discounted at 7.75%) of the difference between our estimated obligations under the QFs and the related amounts recoverable in rates. Our obligation may fluctuate substantially due to variable pricing and actual QF output. The liability was established based on certain assumptions over the contract terms related to pricing, output, capacity utilization and recoverable amounts.
In assessing the liability each reporting period, we compare our assumptions to actual results and make adjustments as necessary. Actual QF utilization, QF contract amendments and regulatory decisions relating to QFs could significantly impact the liability and our results of operations. During the first quarter of 2005, we amended one of our QF contracts, which reduced our capacity and energy rates over the term of the contract (through 2028). As a result of this amendment, we reduced our QF liability based on the new rates, resulting in a $4.9 million gain.
In December 2006, the MPSC issued an order finalizing certain QF rates for the periods July 1, 2003 through June 30, 2006. The result of this order could provide for a significant reduction to our QF liability, as it reduces escalating energy and capacity rates that we utilize in determining the present value of our obligation. If the order is upheld in its current form, we anticipate reducing our QF liability by approximately $25 million. This order has been contested by certain QFs, and we will not recognize a reduction to the liability until any appeals are exhausted. We have submitted interim rates for the period July 1, 2006 through June 30, 2007, that if approved and ultimately upheld, would result in an additional reduction to our QF liability of approximately $24 million. At December 31, 2006, our estimated QF liability was $147.9 million.
Revenue Recognition
Revenues are recognized differently depending on the various jurisdictions. For our South Dakota and Nebraska operations, consistent with historic treatment in the respective jurisdictions, electric and natural gas utility revenues are based on billings rendered to customers. For our Montana operations, operating revenues are recorded monthly on the basis of consumption or services rendered. Customers are billed on a monthly cycle basis. To match revenues with associated expenses, we accrue unbilled revenues for electric and natural gas services delivered to the customers but not yet billed at month-end.
Regulatory Assets and Liabilities
Our regulated operations are subject to the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process, including our estimate of amounts recoverable for natural gas and electric supply purchases. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. If any part of our operations become no longer subject to the provisions of SFAS No. 71, then we would need to evaluate the probable future recovery of or reduction in revenue with respect to the related regulatory assets and liabilities. In addition, we would need to determine if there was any impairment to the carrying costs of the associated plant and inventory assets.
While we believe that our assumptions regarding future regulatory actions are reasonable, different assumptions could materially affect our results.
Pension and Postretirement Benefit Plans
We sponsor defined benefit pension plans, which cover substantially all employees, and provide postretirement health care and life insurance benefits for certain of our employees. Our reported costs of providing pension and other postretirement benefits, as described in Note 18 to the consolidated financial statements, are dependent upon numerous factors including the provisions of the plans, changing employee demographics and economic conditions, and various actuarial calculations, assumptions, and accounting mechanisms. As a result of these factors, significant portions of pension and other postretirement benefit costs recorded in any period do not reflect (and are generally greater than) the actual benefits provided to plan participants. Due to the complexity of these calculations, long-term nature of the obligations, and the
importance of the assumptions utilized, the determination of these costs is considered a critical accounting estimate.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
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Discount rates used in determining the future benefit obligations;
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Projected health care cost trend rates;
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Expected long-term rate of return on plan assets; and
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Rate of increase in future compensation levels.
We review these assumptions on an annual basis and adjust them as necessary. The assumptions are based upon information available as of the beginning of the year, specifically, market interest rates, past experience and management’s best estimate of future economic conditions.
For 2006 we set the discount rate using a yield curve analysis, which projects benefit cash flows into the future and then discounts those cash flows to the measurement date using a yield curve. For our analysis we reviewed both the yield curve of our actuaries and Citigroup. Based on this analysis, we increased our discount rate 0.25% to 5.75%. We previously set the discount rate based upon our review of the Citigroup Pension Index and Moody’s Aa bond rate index. Based on this analysis, we used a discount rate of 5.5% in 2005 and 2004.
The health care cost trend rates are established through a review of actual recent cost trends and projected future trends. Our retiree medical trend assumptions are the best estimate of expected inflationary increases to our healthcare costs. Due to the relative size of our retiree population (under 700 members), the assumptions used are based upon both nationally expected trends and our specific expected trends. Our average increase remains consistent with the nationally expected trends. The long-term trend assumption is based upon our actuary’s macroeconomic forecast, which includes assumed long-term nominal gross domestic product (GDP) growth plus the expected excess growth in national health expenditures versus GDP, the assumed impact of population growth and aging, and variations by healthcare sector. Based on this review, the health care cost trend rate used in calculating the December 31, 2006 accumulated postretirement benefit obligation was an 8% increase in health care costs in 2007 gradually decreasing each successive year until it reaches a 5.0% annual increase in health care costs in 2010.
The expected long-term rate of return assumption on plan assets was determined based on the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of the pension and postretirement portfolios. We target an asset allocation of roughly 70% equity securities, and 30% fixed-income securities. Considering this information and future expectations for asset returns, we decreased our expected long-term rate of return on assets assumption from 8.5% during 2005 to 8.00% for 2006. The assumed rate of increase in future compensation levels used to calculate benefit obligations was 3.50% for union and 3.57% - 3.64% for nonunion employees in 2006.
Cost Sensitivity
The following table reflects the sensitivity of pension costs to changes in certain actuarial assumptions (in thousands):
Accounting Mechanisms
In accordance with SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, which is effective for us as of December 31, 2006, and SFAS No. 87, Employers’ Accounting for Pensions, we utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. SFAS No. 158 also requires that a plan’s funded status be recognized as an asset or liability. Through fresh-start reporting in 2004 we had previously recorded the funded status of our plans on the balance sheet, and adjusted our qualified pension and other postretirement benefit plans to their projected benefit obligation by recognition of all previously unamortized actuarial gains and losses. Therefore, we recognized all prior service costs, and net actuarial gains and losses from 2005 and 2006 as of December 31, 2006.
As our regulated operations are subject to the provisions of SFAS No. 71, our financial statements reflect the effects of the different rate making principles followed by the jurisdiction regulating us. Pension costs in Montana and other postretirement benefit costs in South Dakota are included in rates on a pay as you go basis for regulatory purposes. Pension costs in South Dakota and other postretirement benefit costs in Montana are included in rates on an accrual basis for regulatory purposes. Regulatory assets have been recognized for the obligations that will be included in future cost of service. In 2005, the MPSC authorized the recognition of pension costs based on an average of the funding to be made over a 5-year period for the calendar years 2005 through 2009.
Income Taxes
Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We currently estimate that as of December 31, 2006, we have approximately $420 million of consolidated net operating loss carryforwards (CNOLs) to offset federal taxable income in future years. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ from these estimates. The resolution of tax matters in a particular future period could have a material impact on our consolidated statement of operations and provision for income taxes.
In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). FIN 48 is an interpretation of FASB Statement No. 109, Accounting for Income Taxes, and it seeks to reduce the diversity in practice associated with certain aspects of measurement and recognition in accounting for income taxes by prescribing a recognition threshold and measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. Additionally, FIN 48 provides guidance on the derecognition, classification, accounting in interim periods and expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for us as of January 1, 2007. We are currently in process of reviewing our uncertain tax positions to determine the impact to our financial statements. FIN 48 provides that a tax position that meets the more-likely-than-not threshold shall initially and subsequently be measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Based on our preliminary assessment, during the first quarter of 2007, we expect to increase our net deferred tax assets by $70 million to $90 million with a corresponding decrease to goodwill.
RESULTS OF OPERATIONS
The following is a summary of our results of operations in 2006, 2005, and 2004. Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. This discussion is followed by a more detailed discussion of operating results by segment.
Factors Affecting Results of Continuing Operations
Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. Revenues are also impacted to a lesser extent by customer growth and usage, the latter of which is primarily affected by weather. 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.
Weather affects the demand for electricity and natural gas, especially among residential and commercial customers. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity. The weather’s effect is measured 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 actual temperature is less than the baseline. Cooling degree-days result when the average daily actual temperature is greater than the baseline. The statistical weather information provided in our regulated segments represents a comparison of these degree-days.
OVERALL CONSOLIDATED RESULTS
Year Ended December 31, 2006 Compared with Year Ended December 31, 2005
Consolidated gross margin in 2006 was $519.1 million, a decrease of $4.9 million, or 0.9%, from gross margin in 2005. The regulated electric gross margin increase in 2006 was primarily due to increased transmission revenues and retail volumes offset by the following items. During March 2006, we signed a stipulation with the Montana Consumer Counsel (MCC) to settle various issues raised relative to our 2005 and 2006 electric tracker filings. As a result of this stipulation we recognized increased cost of sales of $4.3 million during the first quarter of 2006 related to the removal of replacement costs and certain forward sales contracts from our electric tracker. Regulated electric results for 2005 also included a $4.9 million gain related to a QF contract amendment. The $3.8 million decrease in regulated natural gas margin was primarily due to a $4.6 million recovery of supply costs during the second quarter of 2005 that were previously disallowed by the MPSC, partly offset by higher transmission and storage revenue. Unregulated electric margin decreased $3.2 million primarily due to lower volumes partially offset by higher average prices. Unregulated natural gas gross margin decreased $1.5 million primarily due to a renegotiated gas supply and management services contract and lower volumes.
Gross margin as a percentage of revenues increased to 45.8% for 2006, from 44.9% for 2005. Gross margin as a percentage of revenue is primarily impacted by the fluctuations that occur in regulated electric and natural gas supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.
Consolidated operating, general and administrative expenses were $240.2 million in 2006 as compared to $225.5 million in 2005. The $14.7 million increase was primarily due to $13.8 million in transaction related costs pursuant to the proposed BBI transaction and $2.2 million in higher legal and professional fees associated with assessing our strategic alternatives and addressing outstanding litigation. While an acquiring entity typically capitalizes its acquisition related costs, the transaction costs incurred by an acquiree are expensed as incurred. These costs included payment of $8.6 million transaction fees to our strategic advisor during 2006. Under the terms of our agreement with our strategic advisor, we will be required to pay an additional $8.6 million upon consummation of the proposed transaction. Since this additional payment is contingent on consummation of the transaction, it will be expensed in the period the transaction occurs. Other items impacting operating, general and administrative expense were increased pension expense of $3.0 million, increased bad debt expense of $1.9 million due to increases in past due customer balances, and higher operating costs of approximately $1.8 million primarily due to increased line clearance, maintenance and fuel costs. In addition, our self-insurance reserves decreased $2.8 million in 2006 with past claims settling at or below their estimated amounts, as compared to a $5.0 million decrease in the 2005 primarily based on claims settled for less than anticipated and positive loss experience. The receipt of $9.3 million from an insurance settlement and a $3.1 million reduction in stock-based compensation and short-term incentive expense partially offset these increases. Due to our anticipated purchase of the owner participant interest in a portion of the Colstrip Unit 4 generating facility in the first quarter of 2007, we expect operating expenses to decrease approximately $7.8 million in 2007.
Property and other taxes were $74.2 million in 2006 as compared to $72.1 million in 2005. We have seen significant increases in our Montana property taxes since 2003 due primarily to increasing valuation assessments of our property by the Montana Department of Revenue. We have protested approximately $11.6 million and $16.3 million of our 2005 and 2006 property taxes, respectively and are currently appealing our 2005 valuation before the State Tax Appeal Board in Montana. We have recognized our property tax expense based on the total amount billed (including amounts protested), so if we are successful with our appeal, we will recognize a reduction of property tax expense in the period the appeal is resolved.
Under Montana law, we are allowed to track the changes in the actual level of state and local taxes and fees and recover these amounts; however, the MPSC has only authorized recovery of approximately 60% of this increase for 2005, 2006 and 2007, as compared to the related amount included in rates during our last general rate case in 1999. We are disputing the reduction and have filed a Petition for Judicial Review in Montana District Court seeking to recover 100% of the increase in these taxes, however, we cannot currently predict an outcome.
Depreciation expense was $75.3 million in 2006 as compared with $74.4 million in 2005. Due to our anticipated purchase of the owner participant interest in a portion of the Colstrip Unit 4 generating facility in the first quarter of 2007, we expect depreciation expense to increase by approximately $1.7 million in 2007.
In February 2007, a jury verdict was rendered against us in Montana state court, which ordered us to pay $17.4 million in compensatory and $4.0 million in punitive damages in a case called Ammondson, et al. v. NorthWestern Corporation, et al. Due to the verdict, we recognized a loss of $19.0 million in our 2006 results of operations to increase our recorded liability related to this claim. We intend to appeal this verdict; however, there can be no assurance that we will prevail in our efforts. In addition, we expect to incur additional legal and court costs related to these proceedings.
The case relates to 15 former Montana Power Company (MPC) executives who had supplemental retirement contracts that provided additional payments above and beyond their qualified pension and 401K Plan. These executives, and seven other former executives who were not included in the suit, were the only individuals that were offered these supplemental contracts. The supplemental payments were suspended during our bankruptcy proceedings and later reinstated. These former MPC executives received all funds that had previously been suspended and as of November 2005 were again receiving the monthly amount determined in their contracts.
Reorganization items in 2005 of $7.5 million consisted of bankruptcy related professional fees and expenses. During 2005 reorganization related professional fees were primarily associated with the attempted resolution of the QUIPs litigation and the resolution of other disputed Class 9 claims. Reorganization expenses for 2005 include a $2.6 million loss for the reestablishment of a liability that was removed from our balance sheet upon emergence from bankruptcy. We continue to incur professional fees during 2006 associated with various legal proceedings that must be resolved before our bankruptcy case can be closed and, these costs are included in operating, general and administrative expenses.
Consolidated operating income in 2006 was $110.4 million, as compared with $144.5 million in 2005. This $34.1 million decrease was primarily due to the adverse jury verdict, BBI transaction related costs and lower margins discussed above.
Consolidated interest expense in 2006 was $56.0 million, a decrease of $5.3 million, or 8.6%, from 2005. This decrease was primarily attributable to a $94 million decrease in debt in 2005 as well as our 2006 refinancing transactions, which replaced our $90.2 million and $80.0 million Montana pollution control obligations and our $150 million Montana first mortgage bonds with lower interest rate debt. Our credit facility borrowings have also decreased in 2006 by $31million. Due to our anticipated purchase of the owner participant interest in a portion of the Colstrip Unit 4 generating facility in the first quarter of 2007, we expect interest expense to increase by approximately $5.3 million in 2007. See “Liquidity and Capital Resources” for additional information regarding our refinancing activities.
Consolidated loss on extinguishment of debt of $0.5 million in 2005 resulted from an early principal payment of $25.0 million on our senior secured term loan B on April 22, 2005.
Consolidated other income in 2006 was $9.1 million, a decrease of $8.4 million from 2005. In 2006, we recorded a $3.9 million gain related to an interest rate swap and a $2.3 million gain on the sale of a partnership interest in oil and gas properties. In 2005, we recorded a $9.0 million gain from a dispute settlement and a $4.7 million gain from the sale of excess sulfur dioxide (SO2) emission allowances. The market value of SO2 emission allowances increased significantly during the third quarter of 2005 and we sold our excess SO2 emission allowances covering years 2011 through 2016. Proceeds from the
sale of these emission allowances are not subject to regulatory jurisdiction. We have excess SO2 emission allowances remaining for years 2017 through 2031, however the market for these years is presently illiquid, and these emission allowances have no carrying value in our financial statements.
Consolidated income tax provision in 2006 was $25.9 million as compared with $38.5 million in 2005. Our effective tax rate for 2006 was 40.9% as compared to 38.5% for 2005. Portions of our BBI transaction related costs are non-deductible for taxes, which increased our effective tax rate in 2006. While we reflect an income tax provision in our financial statements, we expect our cash payments for income taxes will be minimal through at least 2010, based on our anticipated use of net operating losses.
Income from discontinued operations in 2006 was $0.4 million compared to a loss of $2.1 million in 2005. The income in 2006 related to the final liquidation of Netexit, while the 2005 loss was primarily related to professional fees and settlement of claims in Netexit’s bankruptcy proceedings.
Consolidated net income in 2006 was $37.9 million compared with $59.5 million for the same period in 2005. This decline was primarily due to a $29.2 million increase in operating expenses due largely to the adverse jury verdict and transaction related costs pursuant to the proposed BBI transaction, a $4.9 million decrease in gross margin, and an $8.4 million decline in other income. Partially offsetting this decline was a decrease in tax expense of $12.6 million, decreased interest expense of $5.3 million and a $2.5 million increase in income from discontinued operations.
Year Ended December 31, 2005 Compared with Year Ended December 31, 2004 (Combined)
The adoption of fresh-start reporting as of November 1, 2004 has impacted the comparability of our financial statements. As the impact to our statement of operations is limited to the Reorganization Items line detail, we have combined the Successor Company’s results from November 1, 2004 through December 31, 2004 with the results of the Predecessor Company from January 1, 2004 through October 31, 2004 for comparison and analysis purposes.
Consolidated gross margin in 2005 was $524.0 million, an increase of $48.8 million, or 10.3%, over 2004. Margins in our regulated electric segment increased $25.9 million primarily due to $12.7 million higher volume sales to our transmission and distribution customers due to increased volumes and decreases in out of market costs of approximately $9.1 million associated with our QF contracts. A $2.3 million decrease in wholesale revenues partially offset these increases. In addition, we recorded a $2.1 million loss in the second quarter of 2004 related to a contract dispute settlement with a wholesale power supply vendor. Margins in our regulated gas segment increased $12.4 million due to the recovery of $4.6 million in the second quarter of 2005 of gas supply costs previously disallowed by the MPSC combined with $5.6 million of unrecovered gas costs during 2004, and an approximate $2.5 million improvement due to increased volumes. Our unregulated electric segment margins increased $7.8 million primarily due to increased volumes, and our unregulated natural gas segment margins increased $2.9 million due to losses recorded during 2004 on fixed price sales contracts.
Gross margin as a percentage of revenues was 44.9% in 2005, a decrease from 45.7% in 2004. Gross margin as a percentage of revenue is primarily impacted by the fluctuations that occur in regulated electric and natural gas supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.
Consolidated operating, general and administrative expenses were $225.5 million in 2005, an increase of $3.8 million, or 1.7%, over 2004. There were various increases and offsetting reductions accounting for this overall increase in operating, general and administrative expenses. The increases were primarily due to increased pension expense of approximately $9.9 million, lower overhead capitalization in 2005 of approximately $5.7 million, and other increases aggregating approximately $9.2 million consisting primarily of increases in compensation expenses, professional fees and fleet fuel costs. The overhead capitalization reduction in 2005 was due to a change in estimate based on an updated overhead capitalization study of administrative time spent supporting construction activity. Increases in compensation expenses were primarily due to broad based stock grants to employees, severance costs and increased directors fees. Offsetting these increases in operating, general and administrative expenses were reduced lease expense of approximately $10.2 million related to the extension of our operating lease for the Colstrip Unit 4 generation facility, a $5.8 million decrease in directors and officers insurance, and a $5.0 million decrease in our self-insurance reserves primarily based on claims settled for less than anticipated and positive loss experience during 2005.
Property and other taxes were $72.1 million in 2005 as compared to $65.1 million in 2004. This increase was primarily due to a higher valuation assessment and increased mill levies in our Montana service territory. Depreciation expense was $74.4 million in 2005 as compared to $72.9 million in 2004.
Reorganization items consist of bankruptcy related professional fees and expenses. These expenses totaled $7.5 million in 2005 as compared to reorganization income of $532.6 million in 2004. During 2005 reorganization related professional fees were primarily associated with the attempted resolution of the QUIPs litigation and the resolution of other disputed Class 9 claims. Reorganization expenses for 2005 include a $2.6 million loss for the reestablishment of a liability that was removed from our balance sheet upon emergence from bankruptcy. We continued to pay professional fees incurred by the Plan Committee in addition to our own professional fees. Reorganization items associated with our emergence from bankruptcy in 2004 were primarily gains on cancellation of indebtedness and discharge of other liabilities, partially offset by professional fees.
The asset impairment charges of $10.0 million in 2004 related to a decline in the estimated realizable value of our Montana First Megawatts generation assets.
Consolidated loss on extinguishment of debt in 2005 was $0.5 million, resulting from an early principal payment of $25.0 million on our senior secured term loan B on April 22, 2005. Consolidated loss on extinguishment of debt for 2004 was $21.3 million, resulting from the write off of financing costs associated with our senior secured term loan that we replaced on November 1, 2004.
Consolidated operating income in 2005 was $144.5 million, as compared to $638.1 million in 2004. This $493.6 million decrease was primarily due to the $532.6 million of reorganization income included in operating income during 2004 partially offset by higher gross margins during 2005.
Consolidated interest expense in 2005 was $61.3 million, a decrease of $22.5 million, or 26.8%, from 2004. This decrease was attributable to repayment of approximately $175 million in secured debt since September 30, 2004, as well as our November 1, 2004 financing transaction, which replaced our $390 million senior secured term loan with lower interest rate debt.
Consolidated other income in 2005 was $17.4 million, an increase of $14.2 million from 2004. This increase was primarily due to a $4.7 million gain from the sale of SO2 emission allowances and a $9.0 million gain from a dispute settlement.
Consolidated provision for income taxes in 2005 was $38.5 million as compared to a benefit of $6.3 million in 2004. While we were in bankruptcy, we maintained a valuation allowance against our deferred tax assets. Due to our significant net operating losses, the valuation allowance had the effect of minimizing our income tax expense as most changes in income were offset by an increase or decrease in the valuation allowance. Upon emergence from bankruptcy, we reduced our valuation allowance based on our estimated realizability of these tax benefits. Our effective tax rate for 2005 was 38.5%.
Loss from discontinued operations in 2005 was $2.1 million as compared to income of $2.1 million in 2004. The loss in 2005 is primarily related to professional fees and settlement of claims in Netexit’s bankruptcy proceedings. The 2004 results were primarily due to a Netexit settlement related gain of $11.5 million offset by an increase in liabilities for claims filed in the Netexit bankruptcy proceedings.
Consolidated net income in 2005 was $59.5 million as compared to $544.4 million in 2004. When excluding the effects of our bankruptcy reorganization items, consolidated net income increased approximately $55.2 million. This improvement was primarily due to higher margins, particularly in our regulated segments, the effects of our debt reduction and financing transaction, including a decrease in interest expense and the prior year loss on debt extinguishment, and higher investment income, partly offset by an increase in income taxes discussed above.
REGULATED ELECTRIC SEGMENT
Year Ended December 31, 2006 Compared with Year Ended December 31, 2005
Rate Schedule Revenue
Rate schedule revenue consists of revenue for electric supply, transmission and distribution. This includes fully bundled rates for supplying, transmitting, and distributing electricity to customers who utilize us as their commodity supplier. Customers that have chosen other commodity suppliers are billed for moving their electricity across our lines and their distribution revenues are reflected as rate schedule revenue, while their transmission revenues are reflected as transmission revenue.
Electric rate schedule revenue in 2006 increased $24.5 million, or 4.3% over results in 2005. Electric supply revenue, which consists of supply costs that are collected in rates from customers, increased $20.0 million due to $15.5 million, or 5.0%, higher average prices and a $4.5 million, or 1.5%, increase in volumes related to a combination of customer growth and warmer summer weather. This increase in volumes was also the primary cause of the transmission and distribution revenue increase.
Transmission Revenue
Transmission revenue consists of revenue earned for transmitting energy across our lines for customers who select other suppliers and for off-system, or open access, customers. Transmission revenues in Montana can fluctuate substantially from year to year based on market conditions in surrounding states. During the second quarter of 2006, the Pacific Northwest experienced strong hydro generation, which resulted in increased electric supply at significantly lower prices than states to our south. Since Pacific Northwest energy prices were substantially lower than in these states, suppliers realized more profit by transmitting electricity across our lines. These market conditions created significant price differentials and a $5.3 million, or 13.2%, increase in transmission revenue in 2006 as compared with 2005.
Gross Margin
Gross margin in 2006 increased $3.7 million, or 1.1% as compared with the same period in 2005. The gross margin increase in 2006 was primarily due to higher transmission revenue and increased retail volumes offset by the items discussed below. During March 2006, we signed a stipulation with the MCC to settle various issues they raised relative to our 2005 and 2006 electric tracker filings. As a result of this stipulation, we recognized increased cost of sales of $4.3 million during the first quarter of 2006 related to the removal of replacement costs and certain forward sales contracts from our electric tracker. We also recorded a $3.2 million gain in 2006 as compared to $2.5 million in 2005, as actual QF output was lower than our estimate. Results for 2005 also included a $4.9 million gain related to a QF contract amendment.
Margin as a percentage of revenues decreased to 49.7% for 2006, from 51.5% for 2005 due to the items discussed above. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in power supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.
Volumes
Regulated retail electric volumes in 2006 totaled 9,742,214 MWHs, which increased 1.5% as compared with 9,598,364 MWHs in 2005 due primarily to a 1.8% increase in customer growth and warmer summer weather. Regulated wholesale electric volumes in 2006 were 248,246 MWHs, an increase over 219,081 MWHs in 2005 due primarily to increased availability at our jointly owned plants with less down time for maintenance.
Year Ended December 31, 2005 Compared with Year Ended December 31, 2004 (Combined)
Rate Schedule Revenue
Electric rate schedule revenue increased $59.2 million, or 11.5%. This increase consisted of $46.6 million related to increased electric supply revenues, which consists of our supply costs that are collected in rates from customers. This $46.6 million increase included $27.4 million due to higher supply prices and $19.2 million due to an increase in volumes related to a combination of customer growth and warmer summer weather. Transmission and distribution revenue increased $12.6 million due to a 4.0% increase in volumes related to the combination of warmer summer weather and customer growth.
Transmission Revenue
Transmission revenue consists of revenue for transmitting energy across our lines for customers who select other suppliers and for off-system, or open access, customers. Transmission revenues in Montana can fluctuate substantially from year to year based on market conditions in surrounding states. Price differentials were the primary reasons for the $1.6 million, or 4.1%, increase in transmission revenue.
Wholesale Revenues
Wholesale revenues are from our joint ownership in generation facilities. Excess power not used by our South Dakota customers is sold in the wholesale market. These revenues decreased $2.3 million, or 19.0%, in 2005 primarily due to an $8.1 million, or 45.5%, decrease in volumes sold in the secondary markets partially offset by $5.8 million, or 47.8% higher average prices. We had less wholesale energy available to sell because our retail customers used greater volume due to warmer summer weather and there was decreased plant availability resulting from scheduled maintenance.
Gross Margin
Gross margin in 2005 increased $25.9 million, or 8.7% over 2004, primarily related to the $12.6 million increase in transmission and distribution revenues due to higher volumes and decreases in out of market supply costs of approximately $9.1 million associated with our QF contracts, including a $4.9 million gain related to a QF contract amendment. This amendment reduces our capacity and energy rates over the term of the contract (through 2028) and we have reduced our QF liability based on the new rates. QF costs can differ substantially from year to year depending on the actual output of the QFs as compared to the estimates we used in recording our QF liability. We also recorded a $2.1 million loss in the second quarter of 2004 related to a dispute settlement with a wholesale power supply vendor.
Margin as a percentage of revenues decreased to 51.5% in 2005, from 52.3% in 2004. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in power supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.
Volumes
Regulated retail electric volumes in 2005 totaled 9,598,364 MWHs, compared with 9,228,028 MWHs in 2004. This increase was primarily related to customer growth of 1.6% and warmer summer weather as compared to the prior period in all regulated markets. Regulated wholesale electric volumes in 2005 were 219,081 MWHs, compared with 401,691 MWHs in 2004. Regulated wholesale electric volumes decreased during 2005 resulting from increased retail demand due to warmer summer weather and lower generation plant availability due to scheduled maintenance.
REGULATED NATURAL GAS SEGMENT
Year Ended December 31, 2006 Compared with Year Ended December 31, 2005
Rate Schedule Revenue
Rate schedule revenue consists of revenue for supply, transportation, distribution, and storage of natural gas. This includes fully bundled rates for supplying, transporting, and distributing natural gas to customers who utilize us as their commodity supplier. Customers that have chosen other commodity suppliers are billed for moving their natural gas through our pipelines and their distribution revenues are reflected as rate schedule revenue, while their transportation revenues are reflected as transportation revenue.
Gas rate schedule revenue in 2006 decreased $2.6 million, or 0.8% over results in 2005. Gas supply revenues, which consist of supply costs that are collected in rates from customers, decreased $2.7 million due to an $8.1 million, or 3.5%, weather related decrease in volumes partially offset by $5.4 million, or 2.4%, higher average prices. In addition, 2005 revenues included the recovery of $4.6 million of supply costs previously disallowed by the MPSC.
Transportation & Storage Revenue
Transportation revenue consists of revenue earned for transporting natural gas through our pipelines for customers who select other suppliers and for off-system, or open access, customers. Transportation and storage revenue increased $0.9 million in 2006 as compared to 2005. Transportation and storage revenue can fluctuate significantly from year to year based on the anticipated spread and volatility between summer and winter gas prices. For example, producers may elect to store summer gas production for later delivery during the traditionally higher priced winter heating season. Likewise, choice customers may utilize storage to secure lower priced summer gas production for use during the winter season.
Wholesale Revenue
Wholesale revenue decreased $8.1 million, or 40.1%, due to a decrease in sales of excess purchased gas in the secondary markets. As the sales of excess purchased gas are also reflected in cost of sales, there is no gross margin impact.
Gross Margin
Gross margin in 2006 decreased $3.8 million, or 3.1% from the same period in 2005 primarily due the recovery of $4.6 million of supply costs reflected in the 2005 margin, which were previously disallowed by the MPSC, partly offset by higher transportation and storage revenue.
Margin as a percentage of revenue decreased to 33.1% for 2006, from 33.2% for 2005. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in gas supply costs, which are generally collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.
Volumes
Regulated retail natural gas volumes were 28,092,867 dekatherms during 2006, a 3.5 % decline from 29,107,170 dekatherms for the same period in 2005. This decline was due primarily to warmer weather in Montana and South Dakota.
Year Ended December 31, 2005 Compared with Year Ended December 31, 2004 (Combined)
Rate Schedule Revenue
Gas supply revenues in 2005 increased $57.2 million, or 33.4% over results in 2004. Gas supply revenues essentially consist of our supply costs that are collected in rates from customers. This increase primarily consisted of a $50.9 million increase in supply prices and the recognition of $4.6 million for the recovery of supply costs previously disallowed by the MPSC.
Wholesale Revenue
Wholesale revenue decreased $5.6 million due to reduced sales of excess purchased gas in the secondary markets. As the sales of excess purchased gas are also reflected in cost of sales, there is no gross margin impact.
Transportation & Storage Revenue
Transportation and storage revenue increased $0.9 million in 2005 as compared to 2004.
Gross Margin
Gross margin was $122.7 million in 2005, an increase of $12.4 million, or 11.2%, from 2004 due to the recovery of previously disallowed gas costs as discussed above and the higher transmission, distribution and storage revenue. In addition, during 2004, we wrote off $2.8 million associated with the MPSC’s disallowance of gas costs and $2.8 million related to a fixed price sales contract.
Margin as a percentage of revenue decreased to 33.2% for 2005, from 35.0% for 2004. Gross margin as a percentage of revenue is largely impacted by the fluctuations that occur in gas supply costs, which are typically collected in rates from customers. While these fluctuations impact gross margin as a percentage of revenue, they only impact gross margin amounts if they cannot be passed through to customers.
Volumes
Regulated retail natural gas volumes were 29,107,170 dekatherms during 2005, compared with 28,885,705 dekatherms in 2004. This increase resulted primarily from a 1.7% increase in customer growth and 3% colder weather as compared with the prior period in Montana.
UNREGULATED ELECTRIC SEGMENT
Year Ended December 31, 2006 Compared with Year Ended December 31, 2005
Our unregulated electric segment primarily consists of our lease of a 30% share of the Colstrip Unit 4 generation facility. We sell our Colstrip Unit 4 generation, representing approximately 222 megawatts at full load, principally to two unrelated third parties under agreements through December 2010. We also have a separate agreement to repurchase 111 megawatts through December 2010. These 111 megawatts are available for market sales to other third parties through June 2007. Beginning July 1, 2007, 90 megawatts have been committed to supply a portion of the Montana default supply load (included in our regulated electric segment) for a term of 11.5 years at an average nominal price of $35.80 per megawatt hour.
Revenue
Unregulated electric revenue decreased $4.0 million, or 4.6%, in 2006 primarily due to $12.5 million, or 15.7% lower volumes partially offset by $9.3 million, or 13.6%, higher average prices. Strong hydro generation in the Pacific Northwest during the second quarter of 2006 provided increased supply in the wholesale electricity market, resulting in reduced demand for our Colstrip power. In addition, we had less energy available to sell due to decreased plant availability in 2006 related to planned and unplanned outages for plant maintenance.
Gross Margin
Gross margin decreased $3.2 million, or 4.6%, primarily due to lower volumes partially offset by higher average prices.
We expect our revenue and margin to decrease in 2007 under the terms of our Colstrip 4 commitment to default supply as discussed above. Including this commitment and our other forward sales contracts, we estimate our margin will decrease to approximately $52.0 million for 2007 based on an anticipated volumes of 1,622,180 MWH at an overall average sales price of $50.44 per MWH. If Colstrip 4 experiences unplanned outages, we may not achieve our planned margin.
Volumes
Unregulated electric volumes were 1,503,608 MWHs in 2006, compared with 1,785,293 MWHs in the same period in 2005. The lower volumes in 2006 were due to reduced demand and less plant availability related to planned and unplanned outages as discussed above.
Year Ended December 31, 2005 Compared with Year Ended December 31, 2004 (Combined)
Revenue
Unregulated electric revenue increased $7.1 million, or 8.9% due to a combination of factors, including higher market prices on increased volumes generated, partially offset by less favorable pricing under existing agreements. We had more energy available to sell due to increased plant availability in 2005 with less down time for scheduled maintenance.
Gross Margin
Gross margin increased $7.8 million, or 12.6%, primarily due to higher market prices on increased volumes generated, partially offset by less favorable pricing under existing agreements.
Volumes
Unregulated electric volumes were 1,785,293 MWHs in 2005, compared with 1,571,811 MWHs in 2004. The 2005 increase in volumes was due primarily to increased generation plant availability with less down time for scheduled maintenance.
UNREGULATED NATURAL GAS SEGMENT
Year Ended December 31, 2006 Compared with Year Ended December 31, 2005
Our unregulated natural gas segment reflects the operations of our subsidiary, NSC, which provides natural gas supply and management services and, through its subsidiary, Nekota, operates pipelines used to make retail deliveries of natural gas. In addition, this segment also reflects the results of our unregulated Montana retail propane operations. We are currently evaluating our unregulated natural gas business. During the first quarter of 2007, we expect to transfer Nekota and certain customers to our regulated natural gas segment. In addition, we may seek to sell the remaining unregulated natural gas business.
Revenue
Unregulated natural gas revenue decreased $77.9 million, or 50.5%, due primarily to certain customers contracting directly with other providers for their commodity supply needs. We have continued to encourage certain customers to choose other commodity suppliers as we receive little to no margin on commodity costs.
Gross Margin
Gross margin decreased $1.5 million, or 19.2%, primarily due to a renegotiated gas supply and management services contract and lower volumes.
Volumes
Unregulated wholesale natural gas volumes delivered totaled 17,240,639 dekatherms in 2006, compared with 21,050,277 dekatherms in 2005. This decrease was due primarily to unplanned outages at various ethanol facilities in South Dakota and the transfer of certain customers to our regulated gas segment.
Year Ended December 31, 2005 Compared with Year Ended December 31, 2004 (Combined)
Revenue
Unregulated natural gas revenue increased $21.3 million, or 16.0%, due primarily to a 9.2% increase in average price and a 6.2% increase in volumes.
Gross Margin
Gross margin increased $2.9 million, or 59.2%, primarily due to a $2.3 million loss recorded on out of market fixed price sales contracts in 2004.
Volumes
Unregulated wholesale natural gas volumes delivered totaled 21,050,277 dekatherms in 2005, compared with 19,802,960 dekatherms in 2004. The increase in volumes in 2005 is due primarily to sales to ethanol facilities in South Dakota.
LIQUIDITY AND CAPITAL RESOURCES
As of December 31, 2006, we had cash and cash equivalents of $1.9 million, and revolver availability of $134.7 million. During the year ended December 31, 2006, we used existing cash to repay $37.5 million of debt, including repayments of $31.0 million on our revolver. In addition, we paid dividends on common stock of $44.1 million, contributed $23.1 million to our pension and other postretirement benefit plans, and made property tax payments of $74.1 million. We have also increased our natural gas in storage by approximately $26.4 million, rather than utilizing deferred storage arrangements. During 2006, we also received net proceeds of $17.7 million from the sale of our Montana First Megawatts generation assets, $7.7 million related to our allowed claim in Netexit’s bankruptcy, $19.9 million from the settlement of interest rate swaps, and $9.4 million from a settlement with an insurance provider.
Sources and Uses of Funds
We believe that our cash on hand, operating cash flows, and borrowing capacity, taken as a whole, provide sufficient resources to fund our ongoing operating requirements, debt maturities, anticipated dividends, and estimated future capital expenditures during the next 12 months. We expect to finalize the purchase of the owner participant interest in a portion of the Colstrip Unit 4 generating facility in the first quarter of 2007, representing approximately 79 megawatts of our leased interest for approximately $39 million. As of February 23, 2007, our availability under our revolving line of credit was approximately $185.2 million.
The amount of debt reduction and dividends is subject to certain factors including the use of existing cash, cash equivalents and the receipt of cash from operations. A material adverse change in operations or available financing could impact our ability to fund our current liquidity and capital resource requirements.
Capital Requirements
Our capital expenditures program is subject to continuing review and modification. Actual utility construction expenditures may vary from estimates due to changes in electric and natural gas projected load growth, changing business operating conditions and other business factors. We anticipate funding capital expenditures through cash flows from operations, available credit sources and future rate increases. Our estimated cost of capital expenditures (excluding strategic growth opportunities discussed in our strategy section above) for the next five years is as follows (in thousands):
(1) The expected buyout of the owner participant interest of a portion of our Colstrip Unit 4 operating lease is not reflected in this amount.
Capital expenditures at the levels noted in the table above are higher than our depreciation, and as such we are not getting full recovery of these costs through rates. This under recovery may impact future capital expenditure amounts.
Contractual Obligations and Other Commitments
We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of December 31, 2006. See additional discussion in Note 12 to the Consolidated Financial Statements.
(1)
During the third quarter of 2006, we recorded an increase to property, plant and equipment and capital lease obligations of $40.2 million to reflect an electric default supply capacity and energy sale agreement with the owners of a natural gas fired peaking plant as a lease under the provisions of Emerging Issues Task Force 01-8.
(2)
Our operating leases include a lease agreement for our share of the Colstrip Unit 4 generation facility requiring payments of $32.2 million annually through 2010 and decreasing to $14.5 million annually through 2018. We expect to finalize the buyout of the owner participant interest of a portion of this lease in the first quarter of 2007, reducing the annual lease payments to $20.8 million annually through 2010, and $9.3 million annually through 2018.
(3)
We have only estimated cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter.
(4)
The QFs require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. Our estimated gross contractual obligation related to the QFs is approximately $1.6 billion. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $1.3 billion.
(5)
We have entered into various purchase commitments, largely purchased power, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 24 years.
(6)
Contractual interest payments include an assumed average interest rate of 6.5% on an estimated revolving line of credit balance of $50.0 million through maturity in November 2009, which is our only variable rate debt.
Cash Flows
Factors Impacting our Liquidity
Our operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from natural gas sales and transportation services typically exceed cash requirements. During the summer months, cash on hand, together with the seasonal increase in cash flows and utilization of our existing revolving line of credit, are used to purchase natural gas to place in storage, perform maintenance and make capital improvements.
The effect of this seasonality on our liquidity is also impacted by changes in the market prices of our electric and natural gas supply, which is recovered through various monthly cost tracking mechanisms. These energy supply tracking mechanisms are designed to provide stable and timely recovery of supply costs on a monthly basis during the July to June annual tracking period, with an adjustment in the following annual tracking period to correct for any under or over collection in our monthly trackers. Due to the lag between our purchases of electric and natural gas commodities and revenue
receipt from customers, cyclical over and under collection situations arise consistent with the seasonal fluctuations discussed above, therefore we usually under collect in the fall and winter and over collect in the spring. As of December 31, 2006, we were under collected on our current Montana natural gas and electric trackers by approximately $16.9 million, as compared to $46.5 million as of December 31, 2005. Our ability to utilize our company-owned gas inventory currently in storage limits the impact of a natural gas under collection on our liquidity. Any under collected balance at the end of the tracking year will be amortized and collected in rates over the following tracker year.
Fresh-start reporting has impacted the comparability of our financial statements. The consummation of our Plan of Reorganization on November 1, 2004 resulted in, among other things, a new capital structure, the satisfaction or disposition of various types of claims against the Predecessor Company, the assumption or rejection of certain contracts, and the establishment of a new board of directors. In total 35.5 million shares of new common stock and 4.6 million warrants were issued in exchange for unsecured debt and other unsecured claims. As the consummation of our Plan of Reorganization and fresh-start reporting had no impact to our cash flows, we have combined the cash flows from the Successor Company with the Predecessor Company for comparison and analysis purposes. The following table summarizes our consolidated cash flows for 2006, 2005 and 2004.
Cash Flows Provided By Continuing Operating Activities
As of December 31, 2006, cash and cash equivalents were $1.9 million, compared with $2.7 million at December 31, 2005, and $17.1 million at December 31, 2004. Cash provided by continuing operating activities totaled $165.1 million during 2006, compared with $146.7 million during 2005. This improvement in operating cash flows is primarily due to the timing of our semi-annual Colstrip Unit 4 lease payment of $16.1 million, which is typically paid by December 31st each year, but was not paid until January 2, 2007. Other positive operating cash flow impacts were the reduced under collection of supply costs discussed above, proceeds received from hedging activities in 2006, and decreases in pension funding in 2006 versus 2005, offset by decreased net income and increases in natural gas held in storage. Cash provided by continuing operations totaled $146.7 million during 2005, compared with $146.4 million during 2004. This improvement in operating cash flows is due to improved net income (excluding reorganization items), primarily offset by increased pension and other postretirement benefits funding of $19.3 million and the natural gas and electric tracker under collections discussed above.
The cash improvement in 2004 was substantially due to significant improvements in working capital and the suspension of interest payments on our unsecured debt during our bankruptcy reorganization.
Cash Flows Used In Investing Activities
Cash used in investing activities of continuing operations totaled $71.5 million in 2006, compared with $68.7 million during 2005, and $64.5 million during 2004. During 2006, we received approximately $24.2 million from the sale of assets and $5.3 million from the settlement of hedging activities, offset by cash used of approximately $101.0 million for property, plant and equipment additions. In 2005, we received approximately $4.7 million of net proceeds from the sale of short-term investments, approximately $7.5 million of proceeds from the sale of assets and we used approximately $80.9 million for property, plant and equipment additions. During 2004, we used approximately $80.1 million to make property, plant and equipment additions offset primarily by proceeds from sale of assets of $15.5 million.
Cash Flow Used In Financing Activities
Cash used in financing activities of continuing operations totaled $102.0 million during 2006 compared with $135.3 million in 2005, and $89.8 million during 2004. In 2006, we made debt repayments of $37.5 million, paid dividends on common stock of $44.1 million, and paid $11.7 million for deferred storage transactions. Cash used to repurchase shares during 2006 was approximately $4.3 million. In addition, in association with our debt refinancings during 2006, we incurred financing costs of $7.2 million. In 2005 we made debt repayments of $94.3 million, and paid dividends on common stock of $35.6 million. Cash used to repurchase shares during 2005 was approximately $2.8 million. During 2004, we issued $325 million of long-term debt. Proceeds from these issuances and cash on hand were used to repay $398 million of long-term debt.
Discontinued Operations Cash Flows
The decrease in restricted cash held by discontinued operations during 2006 and 2005 was primarily due to Netexit’s $7.7 million and $42.2 million distribution to us, respectively, along with payment of other allowed claims pursuant to its liquidating plan of reorganization in 2005. The increase in restricted cash held by discontinued operations during 2004 was primarily due to a settlement in which Netexit received $17.5 million, offset by a Blue Dot distribution to us of $10.0 million.
Financing Transactions
During the second quarter of 2006, we issued $170.2 million of Montana Pollution Control Obligations (PCOs) at a fixed interest rate of 4.65%, and used the proceeds to redeem our 6.125%, $90.2 million and 5.90%, $80.0 million Montana pollution control obligations due in 2023. Consistent with our historical regulatory treatment, the remaining deferred financing costs of approximately $3.8 million were recorded as a regulatory asset and will be amortized over the remaining life of the debt. The new PCOs will mature on August 1, 2023, and are secured by our Montana electric and natural gas assets. This transaction will reduce our annual interest expense by approximately $2.4 million.
During the third quarter of 2006, we issued $150 million of Montana First Mortgage Bonds at a fixed interest rate of 6.04% and used the proceeds to redeem our 7.30%, $150 million Montana first mortgage bonds due December 1, 2006. Consistent with our historical regulatory treatment, the remaining deferred financing costs and prepayment penalty of $0.8 million were recorded as a regulatory asset and will be amortized over the remaining life of the debt. The new first mortgage bonds will mature September 1, 2016, and are secured by our Montana electric and natural gas assets. This transaction will reduce our annual interest expense by approximately $1.9 million.
There were no changes to our debt covenants related to these refinancing transactions.
Credit Ratings
Fitch Investors Service (Fitch), Moody’s Investors Service (Moody’s) and Standard and Poor’s Rating Group (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of February 23, 2007, our ratings with these agencies are as follows:
*
S&P ratings are tied to the corporate credit rating. By formula, the secured rating is one level above the corporate rating, and the unsecured rating is two levels below the corporate rating. Our current outstanding senior secured debt in South Dakota and Nebraska is rated BB+ by S&P.
**
The negative outlook assigned by S&P is due to the uncertainty surrounding BBI’s acquisition of NorthWestern.
In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are economically favorable to us and impacts our trade credit availability. Our credit ratings have remained consistent during the fourth quarter.
NEW ACCOUNTING STANDARDS
See Note 3 of “Notes to Consolidated Financial Statements,” included in Item 8 herein for a discussion of new accounting standards.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and credit exposure. Management has established comprehensive risk management policies and procedures to manage these market risks.
Interest Rate Risk
We utilize various risk management instruments to reduce our exposure to market interest rate changes. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. All of our debt has fixed interest rates, with the exception of our revolver, which bears interest at a variable rate (currently approximately 6.475%) tied to the London Interbank Offered Rate (LIBOR) plus a credit spread. Based upon amounts outstanding as of December 31, 2006, a 1% increase in the LIBOR would increase annual interest expense on this line of credit by approximately $0.5 million.
During the second quarter of 2005, we implemented a risk management strategy of utilizing interest rate swaps to manage our interest rate exposures associated with anticipated refinancing transactions of approximately $380 million. These swaps were designated as cash-flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in accumulated other comprehensive income in our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive income into interest expense in our Consolidated Statements of Income during the periods in which the interest payments being hedged occur. During the first quarter of 2006, based on a review of our capital structure and cash flow, and approval by our Board, we decided not to refinance $60 million included in the interest rate swap that was being carried on our revolver. This forward starting interest rate swap was settled during the second quarter of 2006, and we received an aggregate payment of approximately $3.9 million.
In association with the refinancing transactions completed during the second and third quarters of 2006, we settled $170.2 million and $150.0 million of forward starting interest rate swap agreements, and received aggregate settlement payments of approximately $6.3 million and $8.3 million, respectively. These amounts are being amortized as a reduction to interest expense over the term of the underlying debt, which is 17 years and 10 years, respectively. The cash proceeds related to these hedges are reflected in operating activities on the statement of cash flows. As of December 31, 2006, we have no interest rate swaps outstanding.
Commodity Price Risk
Commodity price risk is one our most significant risks due to our position as the default supplier in Montana, and our lack of ownership of natural gas reserves or regulated electric generation assets within the Montana market. Several factors influence price levels and volatilities. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.
As part of our overall strategy for fulfilling our requirement as the default supplier in Montana, we employ the use of market purchases, including forward purchase and sales contracts. These types of contracts are included in our default supply portfolio and are used to manage price volatility risk by taking advantage of seasonal fluctuations in market prices. While we may incur gains or losses on individual contracts, the overall portfolio approach is intended to provide price stability for consumers, therefore these commodity costs are included in our cost tracking mechanisms.
In our unregulated electric segment, due to our lease of a 30% share of the Colstrip Unit 4 generation facility, we are exposed to the market price fluctuations of electricity. We have entered into forward contracts for the sale of a significant portion of Colstrip Unit 4’s generation through the first quarter of 2007. To the extent Colstrip Unit 4 experiences unplanned outages and generation is lower than our contracted sales, we would need to secure the quantity deficiency from the wholesale market to fulfill our forward sales contracts. As of December 31, 2006, market prices exceeded our contracted forward sales prices by approximately $2.7 million.
In our unregulated natural gas segment, we currently have a capacity contract through 2013 with a pipeline that gives us basis risk depending on gas prices at two different delivery points. We have sales contracts with certain customers that provide for a selling price based on the index price of gas coming from a delivery point in Ventura, Iowa. The pipeline
capacity contract allows us to take delivery of gas from Canada, which has typically been cheaper than gas coming from Ventura, even when including transportation costs. If the Canadian gas plus transportation cost exceeds the index price at Ventura, then we will lose money on these gas sales. The annual capacity payments are approximately $1.8 million, which represents our maximum exposure related to this basis risk.
Counterparty Credit Risk
We have considered a number of risks and costs associated with the future contractual commitments included in our energy portfolio. These risks include credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks. Declines in the creditworthiness of our counterparties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our counterparties that, in management’s view, reduce our overall credit risk. There can be no assurance, however, that the management tools we employ will eliminate the risk of loss.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial information, including the reports of independent accountants, the quarterly financial information, and the financial statement schedules, required by this Item 8 is set forth on pages to of this Annual Report on Form 10-K and is hereby incorporated into this Item 8 by reference.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information relating to NorthWestern is made known to the officers who certify the financial statements and to other members of senior management and the Audit Committee of the Board.
We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation our principal executive officer and principal financial officer have concluded that, as of December 31, 2006, our disclosure controls and procedures are effective.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal controls over financial reporting for the three-months ended December 31, 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Controls over Financial Reporting
The management of NorthWestern is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.
All internal controls over financial reporting, no matter how well designed, have inherent limitations, including the possibility of human error and the circumvention or overriding of controls. Therefore, even effective internal control over financial reporting can provide only reasonable assurance with respect to financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal controls over financial reporting may vary over time.
Our management, including our chief executive officer and chief financial officer, assessed the effectiveness of our internal control over financial reporting as of December 31, 2006. In making its assessment of internal control over financial reporting, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our evaluation, management concluded that, as of December 31, 2006, our internal control over financial reporting was effective based on those criteria.
NorthWestern’s independent registered public accounting firm has issued an attestation report on our assessment of our internal control over financial reporting. This report appears on page.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
Not applicable.
Part III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Directors
The following information is furnished with respect to the directors of NorthWestern Corporation. All directors are elected annually.
Executive Officers
The following information is furnished with respect to the executive officers of NorthWestern Corporation as of February 28, 2007:
The Chief Executive Officer (CEO), President, Corporate Secretary and Treasurer are elected annually by the Board. Other officers may be elected or appointed by the Board at any meeting but are generally elected annually by the Board. All officers serve at the pleasure of the Board. Mr. Hanson was serving as an executive officer at the time NorthWestern Corporation filed for bankruptcy in September 2003. Mr. Bird was serving as an executive officer of Netexit, Inc. when the entity filed for bankruptcy in May 2004.
Corporate Governance
Audit Committee
The Audit Committee provides oversight of (i) the financial reporting process, the system of internal controls and the audit process of NorthWestern, and (ii) NorthWestern’s independent auditor. The Audit Committee also recommends to the Board the appointment of NorthWestern’s independent auditor. On September 23, 2005, the Board adopted a revised Audit Committee Charter. The Audit Committee Charter is reviewed annually and is available on the Company’s Web site at http://www.northwesternenergy.com.
The Audit Committee is composed of four nonemployee directors who are financially literate in financial and auditing matters and are independent as defined by NASD Rule 4200(a)(15) and the SEC. The members of the Audit Committee are Chairman Stephen P. Adik, Jon S. Fossel, Philip L. Maslowe and D. Louis Peoples. Audit Committee Chairman Adik has been identified as the Committee’s financial expert, as defined in Item 407(d)(5) of Regulation S-K. The Audit Committee held seven meetings during 2006.
Code of Ethics
Our Board adopted our revised Code of Business Conduct and Ethics (Code of Conduct) on January 26, 2005, and reviews it annually. Our Code of Conduct sets forth standards of conduct for all officers, directors and employees of NorthWestern and our subsidiary companies, including all full- and part-time employees and certain persons that provide services on our behalf, such as agents. Our Code of Conduct is available on the Company’s Web site at http://www.northwesternenergy.com. We intend to post on our Web site any amendments to, or waivers from, our Code of Conduct. In addition, on August 26, 2003, our former Board adopted a code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions (CEO and CFO Code of Ethics), which provides for a complaint procedure that specifically applies to this code. The CEO and CFO Code of Ethics along with the complaint procedures are also available on the Company’s Web site.
Section 16(A) Beneficial Ownership Reporting Compliance
Based solely on information furnished to us and contained in reports filed with the SEC, as well as written representations that no other reports were required, NorthWestern believes that during 2006 all SEC filings of its directors and executive officers complied with the requirements of Section 16 of the Securities Exchange Act of 1934, as amended.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
General Philosophy
Our compensation philosophy is designed to provide a total compensation package to our executive officers that is competitive within the utility industry to enable us to attract, retain and motivate the appropriate talent for long-term success. We believe that total compensation should be reflective of individual performance, should vary with our performance in achieving financial and non-financial objectives, and that any long-term incentive compensation should be closely aligned with shareholder interests. Depending upon officer responsibilities, between 30% and 60% of total targeted compensation is provided through annual and long-term incentives that are based on performance measures that benefit our shareholders. Salary, annual cash incentive awards and long-term equity grants are consistent with our overall compensation philosophy and are determined through review of market data provided by third party executive compensation consultants and include industry surveys and evaluation of proxy data from other utility companies.
Targeted Overall Compensation
We engage Towers Perrin, an executive compensation consultant, to assist us in establishing competitive compensation levels. Towers Perrin analyzes published survey data from several sources, focusing on the energy and utility industry and using data regressed for our revenues for appropriate market comparison. The revenue-regressed data is the primary market reference for determining appropriate base pay and annual incentive targets. Towers Perrin also provides proxy data for the five most highly compensated executives from 20 publicly traded utility companies. The proxy data is used as a reference to confirm the validity of the revenue-regressed survey data and is considered a secondary source for evaluating executive compensation levels. For long-term incentive purposes, Towers Perrin analyzes expected values using the Towers Perrin Compensation DataBank, focusing on companies across industries and the energy services industry specifically with annual revenues less than $3 billion. This data is utilized by the Human Resources Committee (HR Committee) of our Board and management to determine an appropriate blend of base salary and annual and long-term incentives based on comparable positions in the industry. Following are the companies included in the proxy data review:
The components of total compensation for our executive officers are as follows:
•
Base salary
•
Annual cash incentive awards
•
Long-term equity grants
•
Retirement benefits
•
Perquisites and other benefits.
Base Salary -- Base salary is used to recognize experience, skills and knowledge that individuals bring to their roles. Salary levels, for all executive officers, including the CEO, are generally targeted within a range around the median of the regressed survey data provided by Towers Perrin, with adjustments based on individual performance and internal equity considerations. NorthWestern has established five officer market ranges for internal equity valuations. Positions are assigned to a market range by the CEO with consideration for additional roles the officer may have that are not typical of the market, how those roles relate to other officer roles within NorthWestern, and the individual characteristics that the officer brings to the organization, such as experience and educational background.
Annual Cash Incentive Awards -- Annual cash incentive awards reflect the performance of NorthWestern, using both financial and non-financial measures, and the individual performance of the employee. Overall target metrics are reviewed and approved annually by the HR Committee, based on a review of data provided by our compensation consultants, various benchmarks and organizational goals. The HR Committee reviews data submitted by management as to company performance against each of the targets and determines the final funding amount for each metric. The HR Committee may use discretion in adjusting the final funding amounts from actual performance due to specific facts and circumstances.
Each employee, including the CEO and executive officers, is assigned a performance rating based on individual performance against established goals for the year. Individual target incentive opportunities are expressed as a percentage of base salary in accordance with market data provided by Towers Perrin. To determine individual payouts, the achieved funding percentage is multiplied by the individual's target incentive opportunity, and then by a multiple based on the individual's performance for the year. This formula provides for individual payouts ranging from 85 - 130 percent of the individual’s target incentive opportunity. Total annual cash incentive distributions cannot exceed the plan funding for the year.
The incentive metrics and targets established for 2006 include both financial and operational measures. The financial measures are targeted at budgeted operating income and cash flow from operations. The operational measures are targeted indices or averages for safety, reliability and customer satisfaction. The following table shows the associated weighting and final funding percentage for 2006 for each of the incentive metrics:
(1) The HR Committee reviewed 2006 performance against plan targets and made discretionary adjustments to fund at 45.3%. The impact on current operating income of the Ammondson verdict, BBI related transaction costs and certain litigation costs were considered in determining these adjustments. In addition, the HR Committee considered the previous items noted and the year over year timing impact of certain transactions on cash flow from operations.
Long-term Equity Grants -- Equity grants are a key element of our total compensation package for executive officers. In November 2004, pursuant to the bankruptcy court’s confirmation order, restricted stock awards were granted to our executive officers and certain other management employees under the NorthWestern Corporation 2004 Special Recognition Grant Restricted Stock Plan (2004 Plan). These grants were awarded at emergence from bankruptcy to provide an immediate stake in the reorganized NorthWestern and linkage to shareholder interests. The grants under the 2004 Plan are subject to a Board established service-based vesting schedule over a period of four years.
In March 2005, the Board established the NorthWestern Corporation 2005 Long-Term Incentive Plan (2005 LTIP), an equity-based plan, which provides for grants of stock options, share appreciation rights, restricted and unrestricted share awards, deferred share units and performance awards. There was a total of 700,000 shares designated for use under the 2005 LTIP, and all employees are eligible to receive grants. We have elected to provide all long-term incentive awards for employees in the form of restricted stock.
Retirement Benefits -- Retirement benefits are offered to all employees through tax-qualified plans, including company-funded pension plans and 401(k) defined contribution plan. Executive officers, including the CEO, participate in these plans, and the terms governing the retirement benefits under these plans are the same as those available for other employees. These plans do not involve any guaranteed minimum returns or above-market returns; the investment returns are dependent upon actual investment results.
Perquisites and Other Benefits -- The primary perquisites included in compensation for executive officers are vehicle allowances or personal use of company-provided vehicles, subject to eligibility and terms that apply to all employees as defined by policy. Our healthcare, insurance, and other welfare and employee-benefit programs are the same for all eligible employees, including the CEO and executive officers. We share the cost of health and welfare benefits with our employees, which is dependent on the benefits coverage option that each employee elects.
Description of the Human Resources Committee and Responsibilities
The HR Committee performs functions similar to that of a compensation committee. The HR Committee has overall responsibility to nominate persons to serve as executive officers and to review and recommend annual and long-term compensation plans and awards for the members of the Board and for the executive officers. HR Committee recommendations are subject to approval by the Board. The HR Committee also reviews and recommends to the Board any welfare benefit and retirement plans for officers and employees. The HR Committee Charter is available on the Company's Web site at http://www.northwesternenergy.com. The HR Committee met nine times during 2006.
The HR Committee conducts an annual performance assessment of the CEO and recommends for Board approval total compensation for the CEO. The HR Committee has authorized the CEO to establish total compensation for the remaining executive officers subject to HR Committee review. The HR Committee recommends Board approval of restricted stock grants for all equity-based compensation.
Human Resources Committee Interlocks and Insider Participation
The HR Committee is composed of Chairman Philip L. Maslowe, Stephen P. Adik and Julia L. Johnson. Each is an independent member as defined by NASD rule 4200(a)(15). None of the persons who served as members of our HR Committee during 2006 are officers or employees or former employees of NorthWestern or any of our subsidiaries. In addition, no executive officer of NorthWestern or any of its subsidiaries served as a member of the board of directors or compensation committee of any other entity.
HUMAN RESOURCES COMMITTEE REPORT
The following report is submitted by the HR Committee of the Board. In connection with the December 31, 2006 annual report on Form 10-K, the HR Committee reviewed and discussed the Compensation Discussion and Analysis with management. Based on this review and discussion, the HR Committee recommended to the Board that the Compensation Discussion and Analysis be included in NorthWestern's Form 10-K.
Human Resources Committee
Philip L. Maslowe, Chairman
Stephen P. Adik
Julia L. Johnson
COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS
We are required to disclose compensation earned during 2006 for our Chief Executive Officer, Chief Financial Officer, and each of the three most highly compensated persons who were executive officers as of December 31, 2006. In addition, we are required to disclose compensation for up to two additional individuals that we would have provided information on if not for the fact that they no longer were serving as an executive officer at the end of fiscal 2006. Collectively, these officers are referred to in this Form 10-K as the Named Executive Officers (NEOs).
Summary Compensation Table
The following table sets forth the compensation earned during 2006 for services in all capacities by the NEOs:
(1)
These values reflect the 2006 compensation expense recognized for restricted stock awards under the 2004 Plan and 2005 LTIP and are calculated utilizing the provisions of SFAS No. 123R, Share-Based Payments. See Note 19 to the consolidated financial statements for further information regarding assumptions underlying the valuation of equity awards.
(2)
These amounts reflect cash incentive awards as previously described. These awards are earned during the year reflected, and paid in the following fiscal year.
(3)
These amounts are attributable to an increase in the value of each NEO’s defined benefit pension. We do not provide any nonqualified deferred compensation arrangements to officers.
(4)
All Other Compensation includes employer contributions, as applicable, for medical, dental, vision, employee assistance plan, group term life, and 401(k), which are generally available to all employees on a nondiscriminatory basis. Also included are car allowances or personal use of a company vehicle, which totaled $13,920 for Mr. Hanson; $3,000 for Mr. Bird; $9,300 for Mr. Knapp; $0 for Mr. Trandem; and $8,300 for Mr. Gates. Mr. Gates’ amount also includes $9,440 received under a paid time off sell back program, which is available to all employees.
Non-equity Incentive Plan Compensation includes amounts earned under the NorthWestern Energy 2006 Employee Incentive Plan. The HR Committee reviewed 2006 performance against plan targets and made discretionary adjustments to fund at 45.3%. In determining the discretionary adjustments, the HR Committee considered the impact of the Ammondson verdict, BBI related transaction costs and certain litigation costs on operating income. In addition, the HR Committee considered the previous items noted and the year over year timing impact of certain transactions on cash flow from operations. Officer awards varied from funded level based on guidelines applicable to all employees to reflect individual performance, as noted in the Compensation Discussion and Analysis.
Grants of Plan-Based Awards
Pursuant to the terms of the Merger Agreement with BBI, which provides that all of the shares available under the 2005 LTIP may be awarded before completion of the transaction, the Board approved granting in November the remaining shares available under the 2005 LTIP in the form of restricted stock. The awards granted to directors, executive officers and certain other employees were based on the survey data provided by Towers Perrin, which was used to establish long-term incentive targets (expressed as a percentage of base salary). The resulting value was converted to a number of shares using a share price of $37 based on the expected value that will be realized upon successful completion of the BBI transaction. The Board established a service-based vesting schedule over a period of five years for these awards as noted below; however, the 2005 LTIP provides for accelerated vesting and cash settlement in the event of a change in control. Completion of the proposed transaction with BBI would trigger the acceleration of all grants not yet vested. See Note 19 to the consolidated financial statements for further information regarding the determination of grant date fair value under SFAS No. 123R. These awards vest as follows:
•
One-ninth on November 1, 2007;
•
Two-ninths on November 1, 2008;
•
Three-ninths on November 1, 2009;
•
Two-ninths on November 1, 2010; and
•
One-ninth on November 1, 2011.
EQUITY COMPENSATION
Outstanding Equity Awards at Fiscal Year-End
This table contains information regarding outstanding equity-based awards, including the potential dollar amounts realizable with respect to each award, and requires separate disclosure of option exercise prices and expiration dates for each award, as applicable.
The vesting schedule for the 2006 grants is noted above. The vesting schedule for awards granted under the 2004 Plan is as follows: 50% on November 1, 2004; 10% on November 1, 2005; 20% on November 1, 2006; and 20% on November 1, 2007. The market value is as of December 31, 2006, and was determined utilizing the closing stock price. Dividends are not paid on any unvested shares under either plan.
Option Exercises and Stock Vests
This table shows the dollar amounts realized pursuant to the vesting or exercise of equity-based awards during the last fiscal year.
Shares vested during 2006 represent restricted shares granted on November 1, 2004 under the 2004 Plan. The value realized is determined by the fair market value of our common stock on the date of vesting. This value is taxable compensation to the NEOs on the date vested pursuant to Internal Revenue Code (Code) Section 83(a).
POST EMPLOYMENT COMPENSATION
Pension Benefits
We have two defined benefit retirement plans, one applicable to our Montana employees and one applicable to our South Dakota and Nebraska employees. Mr. Hanson, Mr. Bird, Mr. Knapp and Mr. Trandem are participants in the retirement plan applicable to South Dakota and Nebraska employees. Mr. Gates participates in the Montana plan.
Under the cash balance formula of the South Dakota and Nebraska plan, a participant's account grows based upon (1) contributions by NorthWestern made once per year, and (2) annual interest credits based on the average Federal 30-year Treasury Bill rate for November of the preceding year. Contribution rates range from 3% to 7.5% (3% for all new employees) for compensation below the taxable wage base and are doubled for compensation above the taxable wage base. Upon termination of employment, an employee, or if deceased, his or her beneficiary, may elect to receive a lump sum equal to the cash balance in the account, a monthly annuity if age 55 or greater, or defer receiving benefits until they are required to take a minimum distribution.
Under the defined benefit retirement plan applicable to Montana employees, a participant's account grows based upon (1) contributions by NorthWestern made once per year, and (2) interest credits at the rate of 6% per year. Contribution rates range from 3% to 12% for compensation below the taxable wage base and from 1.5% to 6% for compensation above one half of the taxable wage base. Upon termination of employment, an employee who is at least 50 years of age with 5 years of service may begin receiving a monthly annuity or defer receiving benefits until they are required to take a minimum distribution.
To be eligible for these retirement plans, an employee must be 21 years of age and have worked at least one year for NorthWestern, working at least 1,000 hours in that year. Non-employee directors are not eligible to participate. The present value of accumulated benefits was calculated by Mercer Human Resources Consulting, the administrator for our pension plans, using participant data provided by us.
Termination or Change In Control Arrangements
Severance Agreements
Each of our NEOs are participants in our 2006 Officer Severance Plan (Officer Plan). The Officer Plan was reviewed by the HR Committee with recommendations from advisors and approved by the Board. The Officer Plan provides for the payment of severance benefits in the event an officer is involuntarily terminated without “cause.” “Cause” generally is defined in the Officer Plan as (i) any form of illegal conduct or gross misconduct that results in substantial damage to NorthWestern, (ii) failure to comply with our Code of Conduct, (iii) willful failure to perform duties or (iv) willful and continued conduct injurious to us. For this purpose, involuntary termination does not include a termination resulting from a participant’s death or disability. The severance benefits payable under the Officer Plan include: (i) a lump-sum cash payment equal to 1 times annual base pay, (ii) a pro-rata short-term incentive bonus, (iii) reimbursement of COBRA premiums paid by the participant during the 12-month period following the participant’s termination date, and (iv) $12,000 of outplacement services during the 12-month period following the participant’s termination date.
The Officer Plan also provides for change of control severance benefits in the event an eligible officer is terminated within 18 months after a change of control of NorthWestern. Change of control is generally defined in the Officer Plan as (i) an acquisition of more than 50% of the combined voting power of our securities, (ii) a change in the majority of our board of directors in any 12-month period, (iii) a merger, or (iv) the sale or disposition of all or substantially all of our assets. Under the change of control provisions, severance benefits are payable in the event an eligible officer is involuntarily
terminated by us without cause or in the event of a voluntary termination by the participant with "good reason," within 18 months after a change of control. "Good reason" is generally defined in the Officer Plan as (i) a reduction in annual compensation in excess of 15% or $10,000, whichever is greater, (ii) relocation of more than 50 miles, (iii) the failure to provide an equivalent or better position with the successor organization or (iv) the failure to obtain satisfactory agreement from the successor to assume and agree to perform the Officer Plan. The change of control benefits include: (i) a lump-sum cash payment equal to 2 times Compensation to the Chief Executive Officer and Chief Financial Officer and 1.5 times Compensation to all other eligible officers (where Compensation is defined under Section 1.7 of the Officer Plan as annual base salary plus target annual short-term incentive pay), (ii) a pro-rata short-term incentive bonus, (iii) reimbursement of COBRA premiums paid by the participant during the 18-month period following the participant's termination date, and (iv) $12,000 in outplacement services during the 12-month period following the participant's termination date.
In the event any benefits payable under the Officer Plan result in an excess parachute payment under section 280G of the Internal Revenue Code of 1986, as amended, such change of control severance benefits is limited to the greater of: (i) the largest amount which may be paid without any portion of such amount being subject to excise tax imposed by Code Section 4999, or (ii) the change of control benefits payable under the Officer Plan without regard to such limitation, less any excise tax imposed under Code Section 4999.
The following table shows the amount of potential cash severance payable to our NEOs including the amount that each executive officer would be entitled to be reimbursed for outplacement expenses and reimbursement of costs for continuing coverage and other benefits under our group health, dental and life insurance plans to each executive officer. The Officer Plan does not provide tax gross up payments. Severance benefits are not provided for terminations with cause. The amounts are based on an assumed termination date of December 31, 2006.
(1)
Mr. Bird also has equity protection for his residence should he be terminated within a year of a change in control event. This benefit provides that if the selling price of his residence after termination is less than the purchase price, he would be entitled to receive a cash payment for the difference. We have not reflected a value for this benefit.
Nonqualified Deferred Compensation
We do not provide any nonqualified defined contribution or other deferred compensation plans.
Employment Agreements
No member of our Board or management has entered into an employment agreement with our subsidiaries or us.
DIRECTOR COMPENSATION
The following table sets forth the compensation earned by our nonemployee directors for service on our Board during 2006. Employee directors are not compensated for service on the Board.
(1)
These values reflect the compensation expense recognized for restricted stock awards and are calculated utilizing the provisions of SFAS No. 123R, Share-Based Payments. See Note 19 to the consolidated financial statements for further information regarding assumptions underlying the valuation of equity awards. In addition, for those directors who defer their compensation as described below, the meeting fee or retainer, as applicable, is the value utilized to determine the amount of deferred compensation.
(2)
These amounts reflect the earnings on compensation deferred, which is tied to changes in the market value of our common stock.
Compensation to our nonemployee directors consists of an annual cash retainer, an annual unrestricted stock award, an annual cash retainer for the chair of each committee of the Board, and meeting attendance fees. Our Chairman of the Board received an annual cash retainer of $100,000 and an annual stock award of 3,000 shares. The other non-employee Board members received an annual cash retainer of $25,000 and an annual stock award of 2,000 shares of our common stock. In addition, Mr. Peoples received a stock award of 1,000 shares of our common stock upon beginning service on the Board in January 2006. Annual cash retainers for the chairs of committees of the Board are as follows: Audit Committee - $8,000; Governance Committee - $6,000; Human Resources Committee - $6,000; and Mergers & Acquisitions Committee - $8,000. Meeting fees were $2,500 for each Board and committee meeting attended, with the exception of the Chairman of the Board, who does not receive meeting fees. Due to the significant board meeting activity that occurred during 2006 associated with our strategic review process and substantial litigation activity, the Chairman of the Board was granted an additional 2,500 shares on November 1, 2006 to be issued on January 2, 2007, which is reflected in the Stock Awards column as the compensation was earned and recognized during 2006. In addition, each director was awarded 7,500 shares in November 2006 under the 2005 LTIP. These shares vest over the same period as those granted to the NEOs as discussed above.
Nonemployee directors may elect to defer up to 100% of any qualified cash or equity-based compensation that would be otherwise payable to him or her, subject to compliance with NorthWestern's 2005 Deferred Compensation Plan for Nonemployee Directors and Section 409A of the Internal Revenue Code. The deferred compensation may be invested in deferred stock units (DSUs) or designated investment funds. Based on the election of the nonemployee director, following separation from service on the Board, other than on account of death, he or she shall receive a distribution equal to one share of common stock for each deferred stock unit either in a lump sum or in approximately equal installments over a designated number years (not to exceed 10 years). The value of the deferred compensation is adjusted based on increases or decreases in our common stock market value, which is included in the Non-Equity Incentive Plan Compensation column. Mr. Adik, Mr. Draper, Ms. Johnson and Mr. Maslowe elected to defer all or a portion of their 2006 director compensation into DSUs of our common stock.
Each member must retain at least one times his or her annual Board and committee chair retainer(s) in common stock or deferred stock units.
NorthWestern also reimburses nonemployee directors for the cost of participation in certain continuing education programs and travel costs to meetings.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS
Security Ownership by Certain Beneficial Owners and Management
The following table sets forth certain information as of December 31, 2006, with respect to the beneficial ownership of shares of NorthWestern’s common stock owned by the directors, nominees for director, the NEOs, and by all directors and executive officers of NorthWestern as a group. Except under special circumstances, NorthWestern’s common stock is the only class of voting securities. Such information (other than with respect to our directors and executive officers) is based on a review of statements filed with the SEC pursuant to Sections 13(d), 13(f) and 13(g) of the Securities Exchange Act of 1934.
*
Less than 1%.
(1)
The number of shares noted are those beneficially owned, as determined under the rules of the SEC, and such information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules, beneficial ownership includes any shares as to which a person has sole or shared voting power or investment power and any shares which the person has the right to acquire within 60 days through the exercise of option, warrant or right.
(2)
Includes warrants to purchase 115,413 additional shares of NorthWestern’s Common Stock.
(3)
Includes warrants to purchase 13,482 additional shares of NorthWestern’s Common Stock.
Information regarding equity compensation plans required by this Item 12 is included in Item 5 of Part II of this report and is incorporated into this Item 12 by reference.
Upon completion of the merger with BBI, all beneficial ownership of our current stockholders will be terminated, and all shares beneficially owned at the time the merger closes will receive the merger consideration of $37.00 per share. BBI will be the sole owner of our business, and our common stock will be removed from quotation on the NASDAQ Global Select Market and will no longer be publicly traded.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Transactions with Related Persons
The Audit Committee, in conjunction with the Vice President, General Counsel and Corporate Secretary, review and approve or ratify, when necessary, transactions involving related parties. Our executive officers and directors annually complete a questionnaire that includes questions about related party transactions. To the extent described in the questionnaire, these transactions are brought to the attention of the Audit Committee for review and approval or ratification. Because the questionnaire alerts those individuals to seek approval of related party transactions, we expect such transactions will be brought to our attention.
A review of the director and officer questionnaires revealed no material related party transactions during 2006.
Director Independence
All of our nonemployee directors are independent as defined by NASD Rule 4200(a)(15) and the SEC.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANTS FEES AND SERVICES
The following table is a summary of the fees billed to us by Deloitte & Touche, LLP (Deloitte) for professional services for the fiscal years ended December 31, 2006 and December 31, 2005:
Audit Fees
Consists of fees billed for professional services rendered for the audit of our financial statements, internal control over financial reporting and review of the interim financial statements included in quarterly reports and services that are normally provided by Deloitte in connection with statutory and regulatory filings or engagements.
Audit-related Fees
Consists of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of our consolidated financial statements and are not reported under “Audit Fees.” These services include employee benefit plan audits, attest services that are not required by statute or regulation, and consultations concerning financial accounting and reporting standards.
Tax Fees
Consists of fees billed for professional services for tax compliance of $0.3 million and $0.2 million for the years ended December 31, 2006 and 2005, respectively, and tax consulting of $0.5 million and $1.0 million for the years ended December 31, 2006 and 2005, respectively. These services include assistance regarding federal and state tax compliance, tax audit defense and bankruptcy tax planning.
All Other Fees
Consists of fees for products and services other than the services reported above. In fiscal 2006 and 2005, there were no other fees.
Preapproval Policies and Procedures
Pursuant to the provisions of the Audit Committee Charter, before Deloitte is engaged to render audit or nonaudit services, the Audit Committee must preapprove such engagement. In 2006, the Audit Committee approved all such services undertaken by Deloitte before engagement for such services.
Part IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
a)
The following documents are filed as part of this report:
(1) Financial Statements.
The following items are included in Part II, Item 8 of this annual report on Form 10-K:
FINANCIAL STATEMENTS:
Page
Reports of Independent Registered Public Accounting Firm
F - 2
Consolidated Statements of Income (Loss) for the Year Ended December 31, 2006, Year Ended December 31, 2005, Two-Months Ended December 31, 2004 (Successor Company), 10-Months Ended October 31, 2004 (Predecessor Company)
F - 4
Consolidated Statements of Cash Flows for the Year Ended December 31, 2006, Year Ended December 31, 2005, Two-Months Ended December 31, 2004 (Successor Company), 10-Months Ended October 31, 2004 (Predecessor Company)
F - 5
Consolidated Balance Sheets as of December 31, 2006 and December 31, 2005 (Successor Company)
F - 6
Consolidated Statement of Shareholders’ Equity (Deficit) for the Year Ended December 31, 2006, Year Ended December 31, 2005, Two-Months Ended December 31, 2004 (Successor Company), 10-Months Ended October 31, 2004 (Predecessor Company)
F - 7
Notes to Consolidated Financial Statements
F - 8
Quarterly Unaudited Financial Data for the Two Years Ended December 31, 2006
F - 44
(2) Financial Statement Schedules
Schedule II. Valuation and Qualifying Accounts
Schedule II, Valuation and Qualifying Accounts, is included in Part II, Item 8 of this annual report on Form 10-K. All other schedules are omitted because they are not applicable or the required information is shown in the Financial Statements or the Notes thereto.
(3) Exhibits.
The exhibits listed below are hereby filed with the SEC, as part of this annual report on Form 10-K. Certain of the following exhibits have been previously filed with the SEC pursuant to the requirements of the Securities Act of 1933 or the Securities Exchange Act of 1934. Such exhibits are identified by the parenthetical references following the listing of each such exhibit and are incorporated by reference. We will furnish a copy of any exhibit upon request, but a reasonable fee will be charged to cover our expenses in furnishing such exhibit.
Exhibit
Number
Description of Document
2.1(a)
Second Amended and Restated Plan of Reorganization of NorthWestern Corporation (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated October 20, 2004, Commission File No. 0-692).
2.1(b)
Order Confirming the Second Amended and Restated Plan of Reorganization of NorthWestern Corporation (incorporated by reference to Exhibit 2.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated October 20, 2004, Commission File No. 0-692).
2.1(c)
Agreement and Plan of Merger, dated as of April 25, 2006, among Babcock & Brown Infrastructure Limited, BBI US Holdings Pty Ltd., BBI US Holdings II Corp., BBI Glacier Corp. and NorthWestern Corporation (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated April 25, 2006, Commission File No. 0-692).
3.1
Amended and Restated Certificate of Incorporation of NorthWestern Corporation, dated November 1, 2004 (incorporated by reference to Exhibit 3.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated October 20, 2004, Commission File No. 0-692).
3.2(a)
Amended and Restated By-Laws of NorthWestern Corporation, dated November 1, 2004 (incorporated by reference to Exhibit 3.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated October 20, 2004, Commission File No. 0-692).
3.2(b)
Amended and Restated By-Laws of NorthWestern Corporation, dated May 3, 2006 (incorporated by reference to Exhibit 3.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated March 17, 2006, Commission File No. 0-692).
3.2(c)
Amended and Restated By-Laws of NorthWestern Corporation, dated May 3, 2006 (incorporated by reference to Exhibit 3.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated May 3, 2006, Commission File No. 0-692).
3.2(d)
Amended and Restated By-Laws of NorthWestern Corporation, dated May 3, 2006 (incorporated by reference to Exhibit 3.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated June 27, 2006, Commission File No. 0-692).
4.1(a)
General Mortgage Indenture and Deed of Trust, dated as of August 1, 1993, from NorthWestern Corporation to The Chase Manhattan Bank (National Association), as Trustee (incorporated by reference to Exhibit 4(a) of NorthWestern Corporation’s Current Report on Form 8-K, dated August 16, 1993, Commission File No. 0-692).
4.1(b)
Supplemental Indenture, dated as of August 15, 1993, from NorthWestern Corporation to The Chase Manhattan Bank (National Association), as Trustee (incorporated by reference to Exhibit 4(b) of NorthWestern Corporation’s Current Report on Form 8-K, dated August 16, 1993, Commission File No. 0-692).
4.1(c)
Supplemental Indenture, dated as of August 1, 1995, from NorthWestern Corporation to The Chase Manhattan Bank (National Association), as Trustee (incorporated by reference to Exhibit 4(b) of NorthWestern Corporation’s Current Report on Form 8-K, dated August 30, 1995, Commission File No. 0-692).
4.1(e)
Supplemental Indenture, dated as of November 1, 2004, by and between NorthWestern Corporation (formerly known as Northwestern Public Service Company) and JPMorgan Chase Bank (successor by merger to The Chase Manhattan Bank (National Association)), as Trustee under the General Mortgage Indenture and Deed of Trust dated as of August 1, 1993 (incorporated by reference to Exhibit 4.5 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 1, 2004, Commission File No. 0-692).
4.2(a)
Indenture, dated as of November 1, 2004, between NorthWestern Corporation and U.S. Bank National Association, as trustee agent (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 1, 2004, Commission File No. 0-692).
4.2(b)
Supplemental Indenture No. 1, dated as of November 1, 2004, by and between NorthWestern Corporation and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 1, 2004, Commission File No. 0-692).
4.2(c)
Registration Rights Agreement, dated as of November 1, 2004, between NorthWestern Corporation, as issuer, and Credit Suisse First Boston LLC and Lehman Brothers Inc., as representatives of the several initial purchasers (incorporated by reference to Exhibit 4.3 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 1, 2004, Commission File No. 0-692).
4.3(a)
Sale Agreement, dated as of June 1, 1993, between NorthWestern Corporation and Mercer County, North Dakota, related to the issuance of Pollution Control Refunding Revenue Bonds (Northwestern Public Service Company Project) Series 1993 (incorporated by reference to Exhibit 4(b)(1) of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ending June 30, 1993, Commission File No. 0-692).
4.3(b)
Loan Agreement, dated as of June 1, 1993, between NorthWestern Corporation and Grant County, South Dakota, related to the issuance of Pollution Control Refunding Revenue Bonds (Northwestern Public Service Company Project) Series 1993A (incorporated by reference to Exhibit 4(b)(2) of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ending June 30, 1993, Commission File No. 0-692).
4.3(c)
Loan Agreement, dated as of June 1, 1993, between NorthWestern Corporation and Grant County, South Dakota, related to the issuance of Pollution Control Refunding Revenue Bonds (Northwestern Public Service Company Project) Series 1993B (incorporated by reference to Exhibit 4(b)(3) of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ending June 30, 1993, Commission File No. 0-692).
4.3(d)
Loan Agreement, dated as of June 1, 1993, between NorthWestern Corporation and the City of Salix, Iowa, related to the issuance of Pollution Control Refunding Revenue Bonds (Northwestern Public Service Company Project) Series 1993 (incorporated by reference to Exhibit 4(b)(4) of NorthWestern Corporation’s Quarterly Report on Form 10-Q for the quarter ending June 30, 1993, Commission File No. 0-692).
4.3(e)*
Loan Agreement, dated as of April 1, 2006, between NorthWestern Corporation and the City of Forsyth, Montana, related to the issuance of City of Forsyth Pollution Control Revenue Bonds Series 2006.
4.4(a)
First Mortgage and Deed of Trust, dated as of October 1, 1945, by The Montana Power Company in favor of Guaranty Trust Company of New York and Arthur E. Burke, as trustees (incorporated by reference to Exhibit 7(e) of The Montana Power Company’s Registration Statement, Commission File No. 002-05927).
4.4(b)
Thirteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of December 1, 1991 (incorporated by reference to Exhibit 4(a)-14 of The Montana Power Company’s Registration Statement on Form S-3, dated December 16, 1992, Commission File No. 033-55816).
4.4(c)
Fourteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of January 1, 1993 (incorporated by reference to Exhibit 4(c) of The Montana Power Company’s Registration Statement on Form S-8, dated June 17, 1993, Commission File No. 033-64576).
4.4(d)
Fifteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of March 1, 1993 (incorporated by reference to Exhibit 4(d) of The Montana Power Company’s Registration Statement on Form S-8, dated June 17, 1993, Commission File No. 033-64576).
4.4(e)
Sixteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of May 1, 1993 (incorporated by reference to Exhibit 99(a) of The Montana Power Company’s Registration Statement on Form S-3, dated September 13, 1993, Commission File No. 033-50235).
4.4(f)
Seventeenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of December 1, 1993 (incorporated by reference to Exhibit 99(a) of The Montana Power Company’s Registration Statement on Form S-3, dated December 5, 1994, Commission File No. 033-56739).
4.4(g)
Eighteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of August 5, 1994 (incorporated by reference to Exhibit 99(b) of The Montana Power Company’s Registration Statement on Form S-3, dated December 5, 1994, Commission File No. 033-56739).
4.4(h)
Nineteenth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of December 16, 1999 (incorporated by reference to Exhibit 99 of The Montana Power Company’s Annual Report on Form 10-K for the year ended December 31, 2000, Commission File No. 001-04566).
4.4(i)
Twentieth Supplemental Indenture to the Mortgage and Deed of Trust, dated as of November 1, 2001 (incorporated by reference to Exhibit 4(u) of NorthWestern Energy, LLC’s Annual Report on Form 10-K for the year ended December 31, 2001, Commission File No. 001-31276).
4.4(j)
Twenty-first Supplemental Indenture to the Mortgage and Deed of Trust, dated as of February 13, 2002 (incorporated by reference to Exhibit 4(v) of NorthWestern Energy, LLC’s Annual Report on Form 10-K for the year ended December 31, 2001, Commission File No. 001-31276).
4.4(k)
Twenty-second Supplemental Indenture to the Mortgage and Deed of Trust, dated as of November 15, 2002 (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 10, 2003, Commission File No. 0-692).
4.4(l)
Twenty-third Supplemental Indenture to the Mortgage and Deed of Trust, dated as of February 1, 2002 (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated February 10, 2003, Commission File No. 0-692).
4.4(m)
Twenty-Fourth Supplemental Indenture, dated as of November 1, 2004, between NorthWestern Corporation and The Bank of New York and MaryBeth Lewicki, (incorporated by reference to Exhibit 4.4 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 1, 2004, Commission File No. 0-692).
4.4(n)*
Twenty-Fifth Supplemental Indenture, dated as of April 1, 2006, between NorthWestern Corporation and The Bank of New York and Ming Ryan, as trustees.
4.4(o)
Twenty-Sixth Supplemental Indenture, dated as of September 1, 2006, between NorthWestern Corporation and The Bank of New York and Ming Ryan, as trustees (incorporated by reference to Exhibit 4.4 of NorthWestern Corporation’s Current Report on Form 8-K, dated September 13, 2006, Commission File No. 0-692).
4.6(a)
Natural Gas Funding Trust Indenture, dated as of December 22, 1998, between MPC Natural Gas Funding Trust, as Issuer, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.7(a) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.6(b)
Natural Gas Funding Trust Agreement, dated as of December 11, 1998, among The Montana Power Company, Wilmington Trust Company, as trustee, and the Beneficiary Trustees party thereto (incorporated by reference to Exhibit 4.7(b) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.6(c)
Transition Property Purchase and Sale Agreement, dated as of December 22, 1998, between MPC Natural Gas Funding Trust and The Montana Power Company (incorporated by reference to Exhibit 4.7(c) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.6(d)
Transition Property Servicing Agreement, dated as of December 22, 1998, between MPC Natural Gas Funding Trust and The Montana Power Company (incorporated by reference to Exhibit 4.7(d) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.6(e)
Assumption Agreement regarding the Transition Property Purchase Agreement and the Transition Property Servicing Agreement, dated as of February 13, 2002, by The Montana Power, LLC to MPC Natural Gas Funding Trust (incorporated by reference to Exhibit 4.7(e) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
4.6(f)
Assignment and Assumption Agreement (Natural Gas Transition Documents), dated as of November 15, 2002, by and between NorthWestern Energy, LLC, as assignor, and NorthWestern Corporation, as assignee (incorporated by reference to Exhibit 4.7(f) of the Company’s Report on Form 10-K for the year ended December 31, 2002, Commission File No. 0-692).
10.1(a) 
NorthWestern Energy 2005 Employee Incentive Plan, effective January 1, 2005 through December 31, 2005 (incorporated by reference to Exhibit 10.1(a) to NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 0-692).
10.1(b) 
NorthWestern Corporation 2004 Special Recognition Grant Restricted Stock Plan (incorporated by reference to Exhibit 3.1 of NorthWestern Corporation’s registration statement on Form S-8, dated January 31, 2005, Commission File No. 333-122428).
10.1(c) 
NorthWestern Corporation 2005 Deferred Compensation Plan for Non-Employee Directors (incorporated by reference to Exhibit 10.1(c) to NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 0-692).
10.1(d) 
NorthWestern Corporation Incentive Compensation and Severance Plan, effective through November 1, 2004 (incorporated by reference to Exhibit 10.1(d) to NorthWestern Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 0-692).
10.1(e) 
NorthWestern Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Exhibit 2.1 of NorthWestern Corporation’s registration statement on Form S-8, dated May 4, 2005, Commission File No. 333-124624).
10.1(f) 
NorthWestern Corporation 2006 Officer Severance Plan (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated March 31, 2006, Commission File No. 0-692).
10.1(g) 
NorthWestern Corporation 2006 Employee Severance Plan (incorporated by reference to Exhibit 99.2 of NorthWestern Corporation’s Current Report on Form 8-K, dated March 31, 2006, Commission File No. 0-692).
10.1(h)*
Relocation Memorandum between NorthWestern Corporation and Brian B. Bird.
10.2(a)
Credit Agreement among NorthWestern Corporation, as borrower, the several lenders from time to time parties thereto, Lehman Brothers Inc. and Deutsche Bank Securities Inc., as joint lead arrangers, Deutsche Bank Securities Inc., as syndication agent, Union Bank of California, N.A. and KeyBank National Association, s co-documentation agents, and Lehman Commercial Paper Inc., as administrative agent and collateral agent (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated November 1, 2004, Commission File No. 0-692).
10.2(b)
Credit Agreement, dated as of June 30, 2005, among NorthWestern Corporation, as borrower, the several lenders from time to time parties thereto, Deutsche Bank Securities Inc. and Lehman Brothers Inc., as joint lead arrangers, Lehman Commercial Paper Inc., as syndication agent, Union Bank of California, N.A. and KeyBank National Association, as co-documentation agents, and Deutsche Bank AG New York Branch, as administrative agent and collateral agent (incorporated by reference to Exhibit 99.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated June 28, 2005, Commission file No. 0-692).
10.2(c)
Purchase Agreement, dated September 6, 2006, among NorthWestern Corporation and Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as representatives of several initial purchasers (incorporated by reference to Exhibit 10.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated September 13, 2006, Commission File No. 0-692).
10.2(d)
Registration Rights Agreement, dated September 13, 2006 among NorthWestern Corporation and Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as representatives of several initial purchasers (incorporated by reference to Exhibit 10.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated September 13, 2006, Commission File No. 0-692).
12.1*
Statement Regarding Computation of Earnings to Fixed Charges.
21*
Subsidiaries of NorthWestern Corporation.
23.1*
Consent of Independent Registered Public Accounting Firm
24*
Power of Attorney (included on the signature page of this Annual Report on Form 10-K)
31.1*
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
31.2*
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
32.1*
Certification of Michael J. Hanson pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*
Certification of Brian B. Bird pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Management contract or compensatory plan or arrangement.
*
Filed herewith.
All schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instructions or are not applicable, and, therefore, have been omitted.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.
POWER OF ATTORNEY
We, the undersigned directors and/or officers of NorthWestern Corporation, hereby severally constitute and appoint Michael J. Hanson, Thomas J. Knapp, and Kendall G. Kliewer, and each of them with full power to act alone, our true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution and revocation, for each of us and in our name, place, and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, and hereby grant unto such attorneys-in-fact and agents, and each of them, the full power and authority to do each and every act and thing requisite and necessary to be done in and about the foregoing, as fully to all intents and purposes as each of us might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their respective substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ E. LINN DRAPER, JR.
Chairman of the Board
February 28, 2007
E. Linn Draper, Jr.
/s/ MICHAEL J. HANSON
President, Chief Executive Officer and Director
February 28, 2007
Michael J. Hanson
(Principal Executive Officer)
/s/ BRIAN B. BIRD
Vice President and Chief Financial Officer
February 28, 2007
Brian B. Bird
(Principal Financial Officer)
/s/ KENDALL G. KLIEWER
Vice President and Controller
February 28, 2007
Kendall G. Kliewer
(Principal Accounting Officer)
/s/ STEPHEN P. ADIK
Director
February 28, 2007
Stephen P. Adik
/s/ JULIA L. JOHNSON
Director
February 28, 2007
Julia L. Johnson
/s/ JON S. FOSSEL
Director
February 28, 2007
Jon S. Fossel
/s/ PHILIP L. MASLOWE
Director
February 28, 2007
Philip L. Maslowe
/s/ D. LOUIS PEOPLES
Director
February 28, 2007
D. Louis Peoples
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
Page
Financial Statements
Reports of Independent Registered Public Accounting Firm
Consolidated statements of income (loss) for the year ended December 31, 2006, year ended December 31, 2005, two-months ended December 31, 2004 (Successor Company), 10-months ended October 31, 2004 (Predecessor Company)
Consolidated statements of cash flows for the year ended December 31, 2006, year ended December 31, 2005, for the two-months ended December 31, 2004 (Successor Company), 10-months ended October 31, 2004 (Predecessor Company)
Consolidated balance sheets as of December 31, 2006 and December 31, 2005
Consolidated statements of common shareholders’ equity for the year ended December 31, 2006, year ended December 31, 2005, for the two-months ended December 31, 2004 (Successor Company), 10-months ended October 31, 2004 (Predecessor Company)
Notes to consolidated financial statements
Financial Statement Schedules
Schedule II. Valuation and Qualifying Accounts
F - 1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of NorthWestern Corporation:
We have audited the accompanying consolidated balance sheets of NorthWestern Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of income (loss), common shareholders’ equity, and cash flows for the year ended December 31, 2006 and 2005, and the period November 1, 2004 through December 31, 2004 (Successor Company) and for the period January 1, 2004 through October 31, 2004 (Predecessor Company). Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of NorthWestern Corporation and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for the years ended December 31, 2006 and 2005, and for the period November 1, 2004 through December 31, 2004 (Successor Company) and for the period January 1, 2004 through October 31, 2004 (Predecessor Company), in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
As discussed in Notes 1 and 4 to the consolidated financial statements, the Predecessor NorthWestern Corporation filed a petition for reorganization under Chapter 11 of the Federal Bankruptcy Code on September 14, 2003. NorthWestern Corporation’s Plan of Reorganization was substantially consummated on October 31, 2004 and the Successor NorthWestern Corporation emerged from bankruptcy. In connection with its emergence from bankruptcy, the Successor NorthWestern Corporation adopted fresh-start reporting in conformity with AICPA Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code, for the Successor Company as a new entity having carrying values not comparable with prior periods.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
F - 2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of NorthWestern Corporation:
We have audited management’s assessment, included in the accompanying “Management’s Report on Internal Controls over Financial Reporting” included in Item 9A, that NorthWestern Corporation and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2006 of the Company and our report dated February 28, 2007 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.
F - 3
NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(in thousands, except per share amounts)
See Notes to Consolidated Financial Statements
F - 4
NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
See Notes to Consolidated Financial Statements
F - 5
NORTHWESTERN CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share amounts)
See Notes to Consolidated Financial Statements
F - 6
NORTHWESTERN CORPORATION
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
(in thousands)
See Notes to Consolidated Financial Statements
F - 7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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Nature of Operations and Basis of Consolidation
We are one of the largest providers of electricity and natural gas in the Upper Midwest and Northwest, serving approximately 640,000 customers in Montana, South Dakota and Nebraska under the trade name “NorthWestern Energy.” We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have distributed electricity and natural gas in Montana since 2002.
The consolidated financial statements for the periods included herein have been prepared by NorthWestern Corporation (NorthWestern, we or us), pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The accompanying consolidated financial statements include our accounts together with those of our wholly and majority-owned or controlled subsidiaries. All significant intercompany balances and transactions have been eliminated from the consolidated financial statements.
Between September 14, 2003 and November 1, 2004, we operated as a debtor-in-possession under the supervision of the Bankruptcy Court. Our financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code (SOP 90-7). In accordance with SOP 90-7, we applied the principles of fresh-start reporting as of the close of business on October 31, 2004. “Predecessor Company” refers to us prior to emergence from bankruptcy (operations from January 1, 2004 through October 31, 2004). “Successor Company” refers to us after emergence from bankruptcy (operations after November 1, 2004). Due to the application of fresh-start reporting, the Consolidated Financial Statements have not been prepared on a consistent basis with, and therefore generally are not comparable to those of the Predecessor Company and have been presented separately. For further information on the impact of fresh-start reporting see Note 4.
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Pending Merger with Babcock & Brown Infrastructure Limited
On April 25, 2006, we entered into an Agreement and Plan of Merger (Merger Agreement) with Babcock & Brown Infrastructure Limited (BBI), an infrastructure investment company listed on the Australian Stock Exchange, under which BBI will acquire NorthWestern Corporation in an all-cash transaction at $37 per share. The Merger Agreement has been unanimously approved by both companies’ Boards of Directors. Our shareholders approved the Merger Agreement at our August 2, 2006 annual meeting.
The transaction is conditioned upon a number of federal and state regulatory approvals or reviews, and satisfaction of other customary closing conditions. We have received approvals or clearances from the following:
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Committee on Foreign Investments in the United States (CFIUS) in July 2006;
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United States Federal Trade Commission and the United States Department of Justice under the Hart-Scott-Rodino Antitrust Improvement Act of 1976 in October 2006;
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Nebraska Public Service Commission (NPSC) in October 2006;
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Federal Energy Regulatory Commission (FERC) in October 2006;
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Federal Communications Commission in February 2007.
Due to existing statutory language in South Dakota, we submitted a filing to the South Dakota Public Utilities Commission (SDPUC) to determine if it has jurisdiction over the sale and, if so, for transaction approval. In July, the SDPUC filed a notice with FERC that it intended to intervene and file a protest in the federal proceedings. In October, we reached a settlement agreement under which the SDPUC will not oppose approval of the transaction by FERC, which includes the following provisions:
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We and BBI will not seek rate recovery of costs associated with the transaction;
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The majority of our future Board of Directors will be U.S. citizens with at least one South Dakota resident and at least one independent member who will have substantial utility or financial experience. In addition, the independent member(s) shall serve as chair of the Audit Committee and the Governance Committee;
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We will apply ring fencing provisions of the 2004 Stipulation and Settlement Agreement between us, the MPSC and MCC for the benefit of the SDPUC and South Dakota ratepayers;
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We will not borrow money secured by South Dakota regulated utility assets to upstream funds to either BBI or its affiliates without prior approval of the SDPUC; and
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We will maintain our corporate headquarters in Sioux Falls, South Dakota until the later of June 30, 2010 or three years following the effective date of the merger. We will continue to maintain senior management personnel in both South Dakota and Montana.
In December, the SDPUC determined that current state law does not allow them to exercise jurisdiction over the proposed sale.
We must still obtain the approval of the Montana Public Service Commission (MPSC). We and the intervenors have submitted testimony and additional information to the MPSC. The MPSC has set a tentative date of March 14, 2007 to commence a technical hearing on the transaction. We anticipate receiving the MPSC’s decision during the first half of 2007.
The Merger Agreement contains certain covenants whereby NorthWestern is required to continue to operate in the ordinary course of business and must obtain BBI’s consent prior to making certain new investments or divestitures, issuing new debt or common stock or making dividend changes, among other provisions. In addition, the Merger Agreement also contains certain termination rights for both NorthWestern and BBI in which under specified circumstances NorthWestern may be required to pay BBI a termination fee of $50 million and BBI may be required to pay NorthWestern a business interruption fee of $70 million.
The merger will be accounted for as a purchase under GAAP. Under the purchase method of accounting, the assets and liabilities of NorthWestern will be recorded, as of the completion of the transaction, at their respective fair values, and we will record as goodwill the excess, if any, of the purchase price over the fair value of our identifiable assets, including intangibles.
During the year ended December 31, 2006, we recorded $13.8 million in pre-tax charges for advisor and professional fees related to the transaction which are included in our operating, general and administrative expenses on our consolidated statement of income. These costs included payment of $8.6 million in transaction fees to our strategic advisor during 2006. Under the terms of this agreement, we will also be required to pay an additional $8.6 million upon closing.
In addition, in November 2006, the remaining shares available under our 2005 Long-Term Incentive Plan were granted in accordance with the terms of the Merger Agreement. These service-based restricted share awards vest over the next five years, however these shares will vest immediately upon closing of the transaction with BBI. If the transaction is completed in 2007 as anticipated, stock-based compensation expense will be approximately $14 million. Upon closing, NorthWestern's common stock will cease to be publicly traded.
(3)
Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, uncollectible accounts, environmental costs, unbilled revenues and actuarially determined benefit costs. We revise the recorded estimates when we get better information or when we can determine actual amounts. Those revisions can affect operating results.
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Revenue Recognition
For our South Dakota and Nebraska operations, as prescribed by the respective regulatory authorities, electric and natural gas utility revenues are based on billings rendered to customers. For our Montana operations, as prescribed by the MPSC, operating revenues are recorded monthly on the basis of consumption or services rendered. Customers are billed monthly on a cycle basis. To match revenues with associated expenses, we accrue unbilled revenues for electrical and natural gas services delivered to Montana customers but not yet billed at month-end.
Cash Equivalents
We consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents.
Restricted Cash
Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements.
Accounts Receivable, Net
Accounts receivable are net of $3.2 million and $2.2 million of allowances for uncollectible accounts at December 31, 2006 and December 31, 2005, respectively. Receivables include unbilled revenues of $68.9 million and $81.3 million at December 31, 2006 and December 31, 2005, respectively.
Inventories
Inventories are stated at average cost. Inventory consisted of the following (in thousands):
The storage gas amount as of December 31, 2005 includes $11.7 million related to deferred gas storage arrangements.
Regulation of Utility Operations
Our regulated operations are subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulations (SFAS No. 71). Accounting under SFAS No. 71 is appropriate provided that (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise’s cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be charged to and collected from customers.
Our financial statements reflect the effects of the different rate making principles followed by the jurisdiction regulating us. The economic effects of regulation can result in regulated companies recording costs that have been, or are expected to be, allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the balance sheet and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities).
If all or a separable portion of our operations becomes no longer subject to the provisions of SFAS No. 71, an evaluation of future recovery of the related regulatory assets and liabilities would be necessary. In addition, we would determine any impairment to the carrying costs of deregulated plant and inventory assets.
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Derivative Financial Instruments
We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price of electricity and natural gas commodities as discussed further in Note 10. In order to manage these risks, we use both derivative and non-derivative contracts that may provide for settlement in cash or by delivery of a commodity, including:
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Forward contracts, which commit us to purchase or sell energy commodities in the future,
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Option contracts, which convey the right to buy or sell a commodity at a predetermined price, and
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Swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual (notional) quantity.
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), as amended, requires that all derivatives be recognized in the balance sheet, either as assets or liabilities, at fair value, unless they meet the normal purchase and normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.
For contracts in which we are hedging the variability of cash flows related to forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. The relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods in which earnings are affected by the variability of the cash flows of the related hedged item. Any ineffective portion of all hedges would be recognized in current-period earnings. Cash flows related to these contracts are classified in the same category as the transaction being hedged.
We have applied the normal purchases and normal sales scope exception, as provided by SFAS No. 133 and interpreted by Derivatives Implementation Guidance Issue C15, to certain contracts involving the purchase and sale of gas and electricity at fixed prices in future periods. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered. For certain regulated electric and gas contracts that do not physically deliver, in accordance with EITF 03-11, Reporting Gains and Losses on Derivative Instruments that are Subject to SFAS No. 133 and not “Held for Trading Purposes” as defined in Issue no. 02-3, revenue is reported net versus gross.
Property, Plant and Equipment
Property, plant and equipment are stated at original cost, including contracted services, direct labor and material, allowance for funds used during construction (AFUDC), and indirect charges for engineering, supervision and similar overhead items. All expenditures for maintenance and repairs of utility property, plant and equipment are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal. Also included in plant and equipment are assets under capital lease, which are stated at the present value of minimum lease payments. Plant and equipment under capital lease were $44.8 million and $6.0 million as of December 31, 2006 and December 31, 2005, respectively.
AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. We determine the rate used to compute AFUDC in accordance with a formula established by the FERC. This rate averaged 8.8%, 8.7% and 9.0% for Montana for 2006, 2005 and 2004, respectively, and 8.9%, 8.7%, and 7.9% for South Dakota for 2006, 2005 and 2004, respectively. Interest capitalized totaled $1.0 million for the year ended December 31, 2006, $1.3 million for the year ended December 31, 2005, $0.2 million for the two-months ended December 31, 2004, and $1.0 million for the 10-months ended October 31, 2004, respectively for Montana and South Dakota combined.
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We may require contributions in aid of construction from customers when we extend service. Amounts used from these contributions to fund capital additions were $8.7 million for the year ended December 31, 2006 and $8.9 million for the year ended December 31, 2005.
We record provisions for depreciation at amounts substantially equivalent to calculations made on a straight-line method by applying various rates based on useful lives of the various classes of properties (ranging from three to 40 years) determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provision for depreciation of utility plant was approximately 3.4%, 3.4%, and 3.5% for 2006, 2005 and 2004, respectively.
Depreciation rates include a provision for our share of the estimated costs to decommission three coal-fired generating plants at the end of the useful life of each plant. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in noncurrent regulatory liabilities.
Other Noncurrent Liabilities
Other noncurrent liabilities consisted of the following (in thousands):
Stock-based Compensation
Under our equity-based incentive plans, we have granted restricted stock awards to all employees and members of the Board of Directors (Board). We discuss these awards in further detail in Note 18. We adopted SFAS No. 123R, Share-Based Payment (SFAS No. 123R), upon emergence from bankruptcy, which was prior to the required effective date of January 1, 2006. SFAS No. 123R requires companies to recognize compensation expense for all equity-based compensation awards issued to employees that are expected to vest. Under SFAS 123R we recognize the fair value of compensation cost ratably or in tranches (depending if the award has cliff or graded vesting) over the period during which an employee is required to provide service in exchange for the award. As forfeitures of restricted stock grants occur, the compensation cost recognized to date is reversed.
Insurance Subsidiary
Risk Partners Assurance, Ltd is a wholly owned non-United States insurance subsidiary established in 2001 to insure a portion of our worker’s compensation, general liability and automobile liability risks. New policies have not been underwritten through this subsidiary since 2004. Claims that were incurred during that time period continue to be paid and managed by Risk Partners. Reserve requirements are established based on actuarial projections of ultimate losses. Any losses estimated to be paid within one year from the balance sheet date are classified as accrued expenses, while losses expected to be payable in later periods are included in other long-term liabilities. Risk Partners has purchased reinsurance policies through a third-party reinsurance company to transfer a portion of the insurance risk. Restricted cash held by this subsidiary was $7.2 million at December 31, 2006 and $8.0 million at December 31, 2005.
Income Taxes
Deferred income taxes relate primarily to the difference between book and tax methods of depreciating property, amortizing tax-deductible goodwill, the difference in the recognition of revenues and expenses for book and tax purposes, certain natural gas costs which are deferred for book purposes but expensed currently for tax purposes, and net operating loss carry forwards.
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Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures, however, actual results may differ from these estimates. The resolution of tax matters in a particular future period could have a material impact on our consolidated statement of operations and provision for income taxes.
Environmental Costs
We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset if we have prior regulatory authorization for recovery of these costs from customers in future rates. Otherwise, we expense the costs. If an environmental expense is related to facilities we currently use, such as pollution control equipment, then we capitalize and depreciate the costs over the remaining life of the asset, assuming the costs are recoverable in future rates or future cash flows.
We record estimated remediation costs, excluding inflationary increases and probable reductions for insurance coverage and rate recovery. The estimates are based on the use of an environmental consultant, our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, then we estimate and record only our share of the cost. We treat any future costs of restoring sites where operation may extend indefinitely as a capitalized cost of plant retirement. The depreciation expense levels we can recover in rates include a provision for these estimated removal costs.
Emission Allowances
We have sulfur dioxide (SO2) emission allowances and each allowance permits a generating unit to emit one ton of SO2 during or after a specified year. We have approximately 3,200 excess SO2 emission allowances per year for years 2017 through 2031, however these allowances have no carrying value in our financial statements and the market for these years is presently illiquid. These emission allowances are not subject to regulatory jurisdiction. When excess SO2 emission allowances are sold, we reflect the gain in investment income and cash received is reflected as an investing activity.
Accounting Standards Issued
In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). FIN 48 is an interpretation of FASB Statement No. 109, Accounting for Income Taxes, and it seeks to reduce the diversity in practice associated with certain aspects of measurement and recognition in accounting for income taxes by prescribing a recognition threshold and measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. Additionally, FIN 48 provides guidance on the derecognition, classification, accounting in interim periods and expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for us as of January 1, 2007. We are currently in the process of reviewing our uncertain tax positions to determine the impact to our financial statements. FIN 48 provides that a tax position that meets the more-likely-than-not threshold shall initially and subsequently be measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Based on our preliminary assessment, we expect to increase our net deferred tax assets by $70 million to $90 million with a corresponding decrease to goodwill.
In September 2006, the FASB issued SFAS No. 157 Fair Value Measurements (SFAS No. 157), which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The provisions of SFAS No. 157 are effective as of the beginning of our 2008 fiscal year. We are currently evaluating the impact, if any, adopting SFAS No. 157 will have on our financial statements.
Accounting Standards Adopted
In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin (SAB) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements
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(SAB No. 108), to address diversity in practice in quantifying financial statement misstatements. SAB No. 108 requires that we quantify misstatements based on their impact on each of our financial statements and related disclosures. SAB No. 108 is effective as of the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to retained earnings as of January 1, 2006 for errors that were not previously deemed material, but are material under the guidance in SAB No. 108. The adoption of this standard did not have any impact on our financial results.
In September 2006, the FASB issued SFAS No. 158, Employer's Accounting for Defined Benefit Pension and Other Postretirement Plans -- an amendment of FASB Statements No. 87, 88, 106, and 132(R) (SFAS No. 158). SFAS No. 158 requires that we recognize the overfunded or underfunded status of our defined benefit and retiree medical plans (our Plans) as an asset or liability in our 2006 year-end balance sheet. Upon our emergence from bankruptcy in November 2004, we recognized a liability for the underfunded status of our Plans, therefore the amount recognized upon adoption of SFAS No. 158 as of December 31, 2006 represents adjustments to our discount rate assumption, our actual 2006 return on plan assets, and other factors. This resulted in a reduction to the liability recognized for our Plans of approximately $23.3 million. As we recover certain of these costs in rates, $23.0 million of this adjustment is reflected as a change in regulatory assets. We discuss our employee benefit plans in more detail in Note 18.
Supplemental Cash Flow Information
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Emergence from Bankruptcy and Fresh-Start Reporting
On September 14, 2003 (the Petition Date), we filed a voluntary petition for relief under the provisions of Chapter 11 of the Federal Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (Bankruptcy Court). On October 19, 2004, the Bankruptcy Court entered an order confirming our Plan of Reorganization (Plan), which became effective on November 1, 2004.
Plan of Reorganization
The consummation of the Plan resulted in, among other things, a new capital structure, the satisfaction or disposition of various types of claims against the Predecessor Company, the assumption or rejection of certain contracts, and the establishment of a new board of directors.
In accordance with the Plan, we issued 31.1 million shares of new common stock to settle claims of debt holders. We also established a reserve of approximately 4.4 million shares of common stock upon emergence to be used to resolve various outstanding litigation matters and distributed pro rata to holders of allowed trade vendor and general unsecured claims in excess of $20,000. As of December 31, 2006, approximately 1.3 million shares have been distributed from this reserve in settlement of claims. Remaining disputed unsecured claims, when allowed, will receive shares out of the reserve set aside upon emergence.
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Reorganization Items
The results of operations of the Predecessor and Successor Company have been impacted by Reorganization Items, including continued costs incurred related to our reorganization since we filed for protection under Chapter 11 and the impact of fresh-start reporting. The following table provides detail of the charges incurred (in thousands):
The 2005 amount included in effects of the Plan is primarily due to a loss on the reestablishment of a liability that was removed upon emergence from bankruptcy. Included in Reorganization Items for the period ended October 31, 2004 was the Predecessor Company’s gain recognized from the effects of the Plan and fresh-start reporting. The gain results from the difference between the Predecessor Company’s carrying value of unsecured debt and the issuance of new common stock and the discharge of liabilities subject to compromise pursuant to the Plan. The gain from the effects of the Plan and the application of fresh-start reporting is comprised of the following (in thousands):
Fresh-Start Reporting
In connection with our emergence from Chapter 11, we reflected the terms of the Plan in our consolidated financial statements as of the close of business on October 31, 2004, applying fresh-start reporting under SOP 90-7. Fresh-start reporting is required if (1) the reorganization value of the emerging entity’s assets immediately before the date of confirmation is less than the total of all postpetition liabilities and allowed claims, and (2) holders of existing voting shares immediately before confirmation receive less than 50% of the voting shares of the emerging entity. Upon applying fresh-start reporting, a new reporting entity (the Successor Company) is deemed to be created and the recorded amounts of assets and liabilities are adjusted to reflect their estimated fair values. The reported historical financial statements of the Predecessor Company for periods ended prior to November 1, 2004 generally are not comparable to those of the Successor Company.
To facilitate the calculation of the reorganization value of the Successor Company as set forth in SOP 90-7, we developed a set of financial projections and engaged an independent financial advisor to assist in the determination. The reorganization value was determined using various valuation methods including, (i) reviewing historical financial information (ii) comparing the company and its projected performance to the market values of comparable companies, (iii) performing industry precedent transaction analysis, and (iv) considering certain economic and industry information relevant to the operating business. While the discounted cash flow approach was one of the three approaches used by the independent financial advisor to determine reorganization value, it was not the sole method used in the determination. This use of multiple
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approaches is consistent with methods used to determine value in most purchase business combinations. A discount rate of 7% was used in the calculation.
The independent financial advisor calculated NorthWestern’s enterprise value, which represents the net equity value of NorthWestern to be distributed to creditors plus its long-term debt to be reinstated upon emergence from bankruptcy, net of cash on hand, to be within an approximate range of $1.415 billion to $1.585 billion. We selected the midpoint value of the range, $1.5 billion, as the enterprise value. This value is consistent with the Voting Creditors and Bankruptcy Court approval of our Plan. Under paragraph 09 of SOP 90-7, an entity’s reorganization value “generally approximates fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring.”
NorthWestern’s total asset value, which is a proxy for the “reorganization value” under SOP 90-7, is approximately $2.5 billion. The projected net distributable value to NorthWestern’s creditors, as calculated by an independent financial advisor, was approximately $710 million. This reflects the “reorganization value” (or total asset value) of approximately $2.5 billion, less NorthWestern’s indebtedness of approximately $1.8 billion (comprised of approximately $900 million of secured reinstated debt, approximately $300 million in current liabilities and approximately $600 million in other noncurrent liabilities).
In applying fresh-start reporting, we followed these principles:
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The reorganization value was allocated to the assets in conformity with the procedures specified by Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations. The enterprise value exceeded the sum of the amounts assigned to assets and liabilities, with the excess allocated to goodwill.
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Deferred taxes were reported in conformity with applicable income tax accounting standards, principally SFAS No. 109, Accounting for Income Taxes. Deferred taxes assets and liabilities have been recognized for differences between the assigned values and the tax basis of the recognized assets and liabilities (see Note 13).
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Adjustment of our qualified pension and other postretirement benefit plans to their projected benefit obligation by recognition of all previously unamortized actuarial gains and losses.
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Reversal of all items included in other comprehensive loss, including recognition of the Predecessor Company’s minimum pension liability, recognition of all previously unrecognized cumulative translation adjustments and removal of a hedge gain associated with unsecured debt.
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Changes in existing accounting principles that otherwise would have been required in the consolidated financial statements of the emerging entity within the 12 months following the adoption of fresh-start reporting were adopted at the fresh-start reporting date.
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Each liability existing as of the Plan confirmation date, other than deferred taxes, was recorded at the present value of amounts to be paid determined at our computed incremental borrowing rate.
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Assets Held for Sale
Assets held for sale consisted of our interest in Montana Megawatts I, LLC, or MMI, our indirect wholly-owned subsidiary that owns the Montana First Megawatts generation project, a partially constructed, 260 megawatt, natural gas-fired, combined-cycle electric generation facility located in Great Falls, Montana. In December 2005, MMI entered into an agreement to sell substantially all of its generation assets for $20 million and we received a deposit of $2.5 million (included in Accrued Expenses on our December 31, 2005 consolidated balance sheet). The sale closed in January 2006 and we received the remaining sales proceeds. We had recorded a $10 million impairment charge to reduce the assets to their estimated realizable value of $20 million in December 2004. During 2006, we recognized a gain on the sale of assets of approximately $0.3 million, which is included in other income.
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Property, Plant and Equipment
The following table presents the major classifications of our property, plant and equipment (in thousands):
We have an electric default supply capacity and energy sale agreement with the owners of a natural gas fired peaking plant that began operating during 2006. In accordance with the agreement, we provide the natural gas necessary to meet demand, and purchase all of the net electrical capacity and output. In our assessment of this contract, we determined that it fits the criteria of a capital lease as set forth in Emerging Issues Task Force 01-8, Determining Whether an Arrangement Contains a Lease. Accordingly, during 2006 we recorded an increase to property, plant and equipment and a capital lease obligation of approximately $40.2 million, which represents the present value of future cash payments for the base capacity and facility charges under the contract.
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Variable Interest Entities
In December 2003, the FASB issued Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities (FIN 46R). FIN 46R was issued to replace FIN 46 and clarify the accounting for interests in variable interest entities. FIN 46R requires the consolidation of entities which are determined to be variable interest entities (VIEs) when the reporting company determines that it will absorb a majority of the VIE’s expected losses, receive a majority of the VIE’s residual returns, or both. Certain long-term purchase power and tolling contracts may be considered variable interests under FIN 46R. We have various long-term purchase power contracts with other utilities and certain qualifying facility plants. After evaluation of these contracts, we believe one qualifying facility contract may constitute a variable interest entity under the provisions of FIN 46R. We are currently engaged in adversary proceedings with this qualifying facility, and have been unable to obtain the information necessary to further analyze this contract under the requirements of FIN 46R. We will continue to make appropriate efforts to obtain the necessary information from this qualifying facility in order to determine if it is a VIE and if so, whether we are the primary beneficiary. We continue to account for this qualifying facility contract as an executory contract. Based on the current contract terms with this qualifying facility, our estimated gross contractual payments aggregate approximately $544.3 million through 2025, and are included in Contractual Obligations and Other Commitments of Management’s Discussion and Analysis.
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Asset Retirement Obligations
We have identified asset retirement obligations, or ARO, liabilities related to our electric and natural gas transmission and distribution assets that have been installed on easements over property not owned by us. The easements are generally perpetual and only require remediation action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as we intend to utilize these properties indefinitely. In the event we decide to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time.
Our regulated utility operations have, however, previously recognized removal costs of transmission and distribution assets as a component of depreciation in accordance with regulatory treatment. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities pursuant to SFAS No. 71,
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Accounting for the Effects of Certain Types of Regulations (SFAS No. 71). These amounts do not represent SFAS No. 143 legal retirement obligations. As of December 31, 2006 and December 31, 2005, we have recognized accrued removal costs of $153.4 million and $142.6 million, respectively. In addition, for our generation properties, we have accrued decommissioning costs since the generating units were first put into service in the amount of $13.3 million and $12.8 million as of December 31, 2006 and December 31, 2005, respectively.
In connection with the adoption of FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), we have recorded a conditional asset retirement obligation of $3.5 million and $3.2 million, as of December 31, 2006 and December 31, 2005, respectively, which increases our property, plant and equipment and other noncurrent liabilities. This is primarily related to Department of Transportation requirements to cut, purge and cap retired natural gas pipeline segments. The initial recording of the obligation had no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71. We measure the liability at fair value when incurred and capitalize a corresponding amount as part of the book value of the related assets. The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the ARO is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period and recorded as a regulatory asset until the settlement of the liability. The change in our conditional ARO during the year ended December 31, 2006, is as follows (in thousands):
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Goodwill
We review goodwill for impairment annually during the fourth quarter, or more frequently if changes in circumstances or the occurrence of events suggest an impairment exists.
We retained a third party to conduct a valuation analysis in connection with our fresh-start reporting. Our consolidated enterprise value was estimated at $1.5 billion. Upon the adoption of fresh-start reporting on October 31, 2004, we adjusted our assets and liabilities to their fair values and valued our equity at $710 million. Since we are a regulated utility, our regulated property, plant and equipment is kept at values included in allowable costs recoverable through utility rates, and the excess of reorganization value over the fair value of assets and liabilities on the date of our emergence of $435.1 million was recorded as goodwill.
Goodwill by segment is as follows for December 31, 2006 and 2005(in thousands):
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Risk Management and Hedging Activities
We are exposed to market risk, including changes in interest rates and the impact of market fluctuations in the price of electricity and natural gas commodities. We employ established policies and procedures to manage our risk associated with these market fluctuations using various commodity and financial derivative and non-derivative instruments, including forward contracts, swaps and options.
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Interest Rates
During 2005, we implemented a risk management strategy of utilizing interest rate swaps to manage our interest rate exposures associated with anticipated refinancing transactions of approximately $380 million. These swaps were designated as cash-flow hedges under SFAS No. 133, with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in accumulated other comprehensive income in our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive income (AOCI) into interest expense in our Consolidated Statements of Income during the periods in which the interest payments being hedged occur.
During the first quarter of 2006, based on a review of our capital structure and cash flow, and approval by our Board of Directors, we decided not to refinance $60 million included in the interest rate swap that was being carried on our revolver. As the refinancing transaction and associated interest payments will not occur, the market value included in AOCI of $3.8 million was recognized in Other Income. This forward starting interest rate swap was settled during the second quarter of 2006, and we received an aggregate payment of approximately $3.9 million, which is reflected in investing activities on the statement of cash flows.
In association with the refinancing transactions completed during the second and third quarters of 2006, we settled $170.2 million and $150 million of forward starting interest rate swap agreements, and received aggregate settlement payments of approximately $6.3 million and $8.3 million, respectively. These amounts are being amortized as a reduction to interest expense over the term of the underlying debt as the hedged interest payments are made, which is 17 years and 10 years, respectively. The cash proceeds related to these hedges are reflected in operating activities on the statement of cash flows. As of December 31, 2006 we have no further interest rate swaps outstanding.
Commodity Prices
During the second quarter of 2005, we implemented a risk management strategy of utilizing put options in conjunction with our forward fixed price sales to manage our commodity price risk exposure associated with our lease of a 30% share of the Colstrip Unit 4 generation facility. These transactions were designated as cash-flow hedges of forecasted electric sales of approximately 120,000 MWh in each of the third and fourth quarters of 2006 under the provisions of SFAS No. 133, with unrealized gains and losses being recorded in AOCI in our Consolidated Balance Sheets. Due to changes in forward prices for electricity during the fourth quarter of 2005, we utilized unit-contingent forward sales to lock in the remaining output during the third and fourth quarters of 2006, and as a result we undesignated the put options as a hedge of the cash flow variability. During the first quarter of 2006 the put options were sold and we recognized a $1.3 million reduction to cost of sales, reflecting the change in market value since they were undesignated. These cash proceeds are reflected in investing activities on the statement of cash flows. During the third and fourth quarters of 2006, we reclassified unrealized losses of approximately $0.9 million into earnings related to the change in market value prior to the hedges being undesignated. As of December 31, 2006 we have no put options outstanding.
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Discontinued Operations
During the second quarter of 2003, we committed to a plan to sell or liquidate our interest in Netexit and Blue Dot. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we classified the results of operations of Netexit and Blue Dot as discontinued operations.
In order to wind-down its affairs in an orderly manner, Netexit and its subsidiaries filed for bankruptcy protection on May 4, 2004. Netexit’s amended and restated liquidating plan of reorganization was confirmed by the Bankruptcy Court on September 14, 2005 and the plan became effective on September 29, 2005. Netexit resolved the majority of claims filed against it and made distributions on allowed claims prior to December 31, 2005, including distributions to NorthWestern totaling $42.2 million. NorthWestern received additional distributions of $7.7 million from Netexit in 2006. The liquidation of Netexit was completed during the second quarter of 2006.
As of December 31, 2005, Netexit had current assets of $8.5 million and current liabilities (excluding intercompany amounts) of $1.2 million.
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Summary financial information for the discontinued Netexit operations is as follows (in thousands):
No income tax provision or benefit has been recorded by Netexit because we currently believe it is not likely that deferred tax assets arising from Netexit net operating losses will be realized.
During the third quarter of 2005, Blue Dot sold its final operating location.
Summary financial information for the discontinued Blue Dot operations is as follows (in thousands):
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Long-Term Debt and Capital Leases
Long-term debt and capital leases consisted of the following (in thousands):
Unsecured Revolving Line of Credit
On June 30, 2005, we entered into an amended and restated credit agreement that replaced our existing $225 million secured credit facility with an unsecured $200 million senior revolving line of credit with lower borrowing costs. The unsecured revolving line of credit will mature on November 1, 2009 and does not amortize. The facility bears interest at a variable rate based upon a grid which is tied to our credit rating from Fitch, Moody’s, and S&P. The ‘spread’ or ‘margin’ ranges from 0.625% to 1.75% over the London Interbank Offered Rate (LIBOR). The facility currently bears interest at a rate of approximately 6.475%, which is 1.125% over LIBOR. As of December 31, 2006, we had $15.3 million in letters of credit and $50 million of borrowings outstanding under the unsecured revolving line of credit. The weighted average interest rate on the outstanding revolver borrowings was 6.475% as of December 31, 2006.
Commitment fees for the unsecured revolving line of credit were $0.3 million and $0.1 million for the years ended December 31, 2006 and 2005, respectively. Commitment fees for the revolving tranche of the old credit facility were approximately $0.2 million for the first six months of 2005, and $63,000 for the two-months ended December 31, 2004.
The credit facility includes covenants, which require us to meet certain financial tests, including a minimum interest coverage ratio and a minimum debt to capitalization ratio. The amended and restated line of credit also contains covenants
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which, among other things, limit our ability to incur additional indebtedness, create liens, engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, make restricted payments, make loans or advances, and enter into transactions with affiliates. Many of these restrictive covenants will fall away upon the line of credit being rated “investment grade” by two of the three major credit rating agencies consisting of Fitch, Moody’s and S&P. We have received a waiver of change in control covenants to allow for the BBI transaction. As of December 31, 2006, we are in compliance with all of the covenants under the amended and restated line of credit.
Secured Debt
The South Dakota Mortgage Bonds are two series of general obligation bonds we issued under our South Dakota indenture, and the South Dakota Pollution Control Obligations are three obligations under our South Dakota indenture. All of such bonds are secured by substantially all of our South Dakota and Nebraska electric and natural gas assets.
The Montana First Mortgage Bonds, and Montana Pollution Control Obligations are secured by substantially all of our Montana electric and natural gas assets. The Montana Natural Gas Transition Bonds are secured by a specified component of future revenues meant to recover the regulatory assets known as a competitive transition charge. The principal payments amortize proportionately with the regulatory asset.
Refinancing Transactions
During the second quarter of 2006, we issued $170.2 million of Montana Pollution Control Obligations (PCOs) at a fixed interest rate of 4.65%, and used the proceeds to redeem our 6.125%, $90.2 million and 5.90%, $80.0 million Montana pollution control obligations due in 2023. Consistent with our historical regulatory treatment, the remaining deferred financing costs of approximately $3.8 million were recorded as a regulatory asset and will be amortized over the remaining life of the debt. The new PCOs will mature on August 1, 2023, and are secured by our Montana electric and natural gas assets. This transaction will reduce our annual interest expense by approximately $2.4 million.
During the third quarter of 2006, we issued $150 million of Montana First Mortgage Bonds at a fixed interest rate of 6.04% and used the proceeds to redeem our 7.30%, $150 million Montana first mortgage bonds due December 1, 2006. Consistent with our historical regulatory treatment, the remaining deferred financing costs and prepayment penalty of $0.8 million were recorded as a regulatory asset and will be amortized over the remaining life of the debt. The new first mortgage bonds will mature September 1, 2016, and are secured by our Montana electric and natural gas assets. This transaction will reduce our annual interest expense by approximately $1.9 million.
Maturities of Long-Term Debt
The aggregate minimum principal maturities of long-term debt, during the next five years are $7.7 million in 2007, $7.8 million in 2008, $57.1 million in 2009, $7.3 million in 2010 and $7.8 million in 2011.
(13)
Comprehensive Income (Loss)
The Financial Accounting Standards Board defines comprehensive income as all changes to the equity of a business enterprise during a period, except for those resulting from transactions with owners. For example, dividend distributions are excepted. Comprehensive income consists of net income and other comprehensive income (OCI). Net income may include such items as income from continuing operations, discontinued operations, extraordinary items, and cumulative effects of changes in accounting principles. OCI may include foreign currency translations, adjustments of minimum pension liability, and unrealized gains and losses on certain investments in debt and equity securities. Due to our emergence from bankruptcy we made adjustments for fresh-start reporting in accordance with SOP 90-7 as discussed in Note 4. These adjustments resulted in removal of items recorded in accumulated OCI of $6.0 million. Comprehensive income (loss) is calculated as follows (in thousands):
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The after tax components of accumulated other comprehensive income were as follows (in thousands):
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Financial Instruments
The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, Disclosures About Fair Value of Financial Instruments. The estimated fair-value amounts have been determined using available market information and appropriate valuation methodologies. However, considerable judgment is necessarily required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange.
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
•
The carrying amounts of cash and cash equivalents, restricted cash approximate fair value due to the short maturity of the instruments.
•
Fair values for debt were determined based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, which is based on market prices.
The fair-value estimates presented herein are based on pertinent information available to us as of December 31, 2006 and December 31, 2005. Although we are not aware of any factors that would significantly affect the estimated fair-value amounts, such amounts have not been comprehensively revalued for purposes of these financial statements since that date, and current estimates of fair value may differ significantly from the amounts presented herein.
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The estimated fair value of financial instruments is summarized as follows (in thousands):
(15)
Income Taxes
Income tax (benefit) expense applicable to continuing operations is comprised of the following (in thousands):
The following table reconciles our effective income tax rate to the federal statutory rate:
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The components of the net deferred income tax liability recognized in our Consolidated Balance Sheets are related to the following temporary differences (in thousands):
A valuation allowance is recorded when a company believes that it will not generate sufficient taxable income of the appropriate character to realize the value of their deferred tax assets. We have a valuation allowance of $12.8 million as of December 31, 2006 against capital loss carryforwards and certain state NOL carryforwards as we do not believe these assets will be realized.
At December 31, 2006 we estimate our total federal NOL carryforward to be approximately $418.1 million. If unused, $246.0 million will expire in the year 2023, and $172.0 million will expire in the year 2025. Our state NOL carryforward as of December 31, 2006 is estimated to be approximately $549.6 million. If unused, $378.9 million will expire in 2010, $33.8 million will expire in 2011, and $136.8 million will expire in 2012. Management believes it is more likely than not that sufficient taxable income will be generated to utilize these NOL carryforwards except as noted above.
We have elected under Internal Revenue Code 46(f)(2) to defer investment tax credit benefits and amortize them against expense and customer billing rates over the book life of the underlying plant.
Due to our NOL carryforward, years 2000 and forward remain subject to examination by the IRS.
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Jointly Owned Plants
We have an ownership interest in three electric generating plants, all of which are coal fired and operated by other utility companies. We have an undivided interest in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. Our interest in each plant is reflected in the Consolidated Balance Sheets on a pro rata basis and our share of operating expenses is reflected in the Consolidated Statements of Income (Loss). The participants each finance their own investment.
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Information relating to our ownership interest in these facilities is as follows (in thousands):
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Operating Leases
We lease a generation facility, vehicles, office equipment, an airplane and office and warehouse facilities under various long-term operating leases. At December 31, 2006, future minimum lease payments for the next five years under non-cancelable lease agreements are as follows (in thousands):
Lease and rental expense incurred was $30.9 million, $31.0 million, $6.8 million and $32.5 million for the years ended December 31, 2006 and 2005, the two-month period ended December 31, 2004, and the 10-month period ended October 31, 2004, respectively.
In January 2005, we exercised an option to extend the term of our Colstrip Unit 4 generation facility lease an additional eight years. By extending the lease term, our annual lease payment remained at $32.2 million through 2010 and decreased to $14.5 million for the remainder of the lease. Beginning in 2005 our lease expense was reduced to $22.1 million annually based on a straight-line calculation over the full term of the lease. We expect to finalize the purchase of the owner participant interest of a portion of this facility in the first quarter of 2007, representing approximately 79 megawatts of our leased interest, in February 2007, reducing the annual lease payments to $20.8 million annually through 2010, and $9.3 million annually through 2018.
(18)
Employee Benefit Plans
Pension and Other Postretirement Benefit Plans
We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for employees, which includes two cash balance pension plans. The plan for our South Dakota and Nebraska employees is referred to as the NorthWestern Corporation pension plan, and the plan for our Montana employees is referred to as the NorthWestern Energy pension plan. Pension costs in Montana and other postretirement benefit costs in South Dakota are included in rates on a pay as you go basis for regulatory purposes. In 2005, we applied for and received an accounting order from the MPSC to utilize a five-year average of funding cost in our costs of service, therefore we maintain a regulatory asset and amortize it based on our five-year average funding requirement in Montana. Pension costs in South Dakota and other postretirement benefit costs in Montana are included in rates on an accrual basis for regulatory purposes. (See Note 20, Regulatory Assets and Liabilities, for the regulatory assets related to our pension and other postretirement benefit plans.) The prior service costs are amortized on a straight-line basis over the average remaining service period of active participants. Actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the market-related value of assets are normally amortized over the average remaining service period of active participants. However as a result of fresh-start reporting (see Note 4), we adjusted our qualified pension and other postretirement benefit plans to their projected benefit obligation by recognizing all previously
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unamortized actuarial gains and losses upon emergence. The generation of any future amounts subsequent to emergence will be amortized under the same method as discussed above.
Adoption of SFAS 158
As discussed in Note 3, we adopted SFAS No. 158 as of December 31, 2006, which requires that we recognize the overfunded or underfunded status of our defined benefit and retiree medical plans (our Plans) as an asset or liability in our 2006 year-end balance sheet. Upon our emergence from bankruptcy in November 2004, we recognized a liability for the underfunded status of our Plans, therefore the amount recognized upon adoption of SFAS No. 158 as of December 31, 2006 represents adjustments to our discount rate assumption, our actual 2006 return on plan assets, and other factors. In addition, as we account for the effects of regulation under SFAS No. 71, for those plans which are able to recover the costs from our customers, the change is reflected as an adjustment to regulatory assets rather than other comprehensive income. The following table illustrates the impact of adoption of SFAS No. 158 on the financial statements as of December 31, 2006 (in thousands):
Benefit Obligation
Following is a reconciliation of the changes in plan benefit obligations and fair value and a statement of the funded status (in thousands):
The total projected benefit obligation and fair value of plan assets for the pension plans with projected benefit obligations in excess of plan assets were $387.6 million and $301.1 million, respectively, as of December 31, 2006. The total accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $385.4 million and $301.1 million, respectively, as of December 31, 2006.
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The total projected benefit obligation and fair value of plan assets for the pension plans with projected benefit obligations in excess of plan assets were $386.9 million and $271.1 million, respectively, as of December 31, 2005. The total accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $384.8 million and $271.1 million, respectively, as of December 31, 2005.
The NorthWestern Energy pension plan was amended effective January 1, 2005 to increase the retirement death benefit from 50% to 100% of the accrued benefit. This is reflected in the plan amendment amount above.
Balance Sheet Recognition
The accrued pension and other postretirement benefit obligations recognized in the accompanying Consolidated Balance Sheets are computed as follows (in thousands):
Plan Assets and Funded Status
Our investment goals with respect to managing the pension and other postretirement assets is to achieve and maintain a reasonably funded status for the pension plans, improve the status of the health and welfare plan, minimize contribution requirements, and seek long-term growth by placing primary emphasis on capital appreciation and secondary emphasis on income, while minimizing risk.
Our investment policy for fixed income investments are oriented toward risk averse, investment-grade securities rated “A” or higher and are required to be diversified among individual securities and sectors (with the exception of U.S. Government securities, in which the plan may invest the entire fixed income allocation). There is no limit on the maximum maturity of securities held. In addition, the NorthWestern Corporation pension plan assets also includes a participating group
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annuity contract in the John Hancock General Investment Account, which consists primarily of fixed-income securities, reflected at current market values with a market adjustment.
Equity investments can include convertible securities, and are required to be diversified among industries and economic sectors. Limitations are placed on the overall allocation to any individual security at both cost and market value and international equities investments are diversified by country. In addition, there are limitations on investments in emerging markets.
Our investment policy prohibits short sales, margin purchases, securities lending and similar speculative transactions as well as any transactions that would threaten tax exempt status of the fund, actions that would create a conflict of interest or transactions between fiduciaries and parties in interest as defined under ERISA. With respect to international investments, foreign currency hedging is allowed under the policy for the purpose of hedging currency risk and to effect securities transactions. Permissible investments include foreign currencies in both spot and forward markets, options, futures, and options on futures in foreign currencies.
The current investment strategy provides for the following asset allocation policies, within an allowable range of plus or minus 5%:
The percentage of fair value of plan assets held in the following investment types by the NorthWestern Energy pension plan, NorthWestern Corporation pension plan and NorthWestern Energy Health and Welfare Plan as of December 31, 2006 and December 31, 2005, are as follows:
We review the asset mix on a quarterly basis. Generally, the asset mix will be rebalanced to the target mix as individual portfolios approach their minimum or maximum levels.
We continually evaluate the potential for liquidating and reinvesting the assets held in participating group annuity contracts as rebalancing and diversification opportunities are currently limited with respect to this portion of plan assets.
Actuarial Assumptions
The measurement dates used to determine pension and other postretirement benefit measurements for the plans are December 31, 2006, December 31, 2005, December 31, 2004, and October 31, 2004. The actuarial assumptions used to compute the net periodic pension cost and postretirement benefit cost are based upon information available as of the beginning of the year, specifically, market interest rates, past experience and management’s best estimate of future economic conditions. Changes in these assumptions may impact future benefit costs and obligations. In computing future costs and obligations, we must make assumptions about such things as employee mortality and turnover, expected salary and wage increases, discount rate, expected return on plan assets, and expected future cost increases. Two of these items generally have the most impact on the level of cost: (1) discount rate and (2) expected rate of return on plan assets.
For 2006, we set the discount rate using a yield curve analysis, which projects benefit cash flows into the future and then discounts those cash flows to the measurement date using a yield curve. For our analysis we reviewed both the yield curve of our actuaries and Citigroup. Based on this analysis, we increased our discount rate 0.25% to 5.75%. We previously set the
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discount rate based upon our review of the Citigroup Pension Index and Moody’s Aa bond rate index. The expected long-term rate of return assumption on plan assets for both the NorthWestern Energy and NorthWestern Corporation pension and postretirement plans was determined based on the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of the pension and postretirement portfolios. Over the 15-year period ending December 31, 2003, the returns on these portfolios, assuming they were invested at the current target asset allocation in prior periods, would have been a compound annual average of approximately 10.5%. Considering this information and future expectations for asset returns, we selected an 8.5% long-term rate of return on assets assumption for 2005 and 2004. We have reduced this assumption to 8.0% for 2006 and 2007.
The health care cost trend rates are established through a review of actual recent cost trends and projected future trends. Our retiree medical trend assumptions are the best estimate of expected inflationary increases to our healthcare costs. Due to the relative size of our retiree population (under 700 members), the assumptions used are based upon both nationally expected trends and our specific expected trends. Our average increase remains consistent with the nationally expected trends.
The weighted-average assumptions used in calculating the preceding information are as follows:
The postretirement benefit obligation is calculated assuming that health care costs increased by 8% in 2006 and the rate of increase in the per capita cost of covered health care benefits thereafter was assumed to decrease gradually to 5% by the year 2010.
Net Periodic Cost
The components of the net costs for our pension and other postretirement plans are as follows (in thousands):
We estimate amortizations from regulatory assets into net periodic cost during 2007 will be as follows (in thousands):
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Assumed health care cost trend rates have a significant effect on the amounts reported for the costs each year as well as on the accumulated postretirement benefit obligation. The following table sets forth the sensitivity of retiree welfare results (in thousands):
Cash Flows
On August 17, 2006 the Pension Protection Act of 2006 was signed into law, with changes that impact the funding calculation for benefit plans. We anticipate making contributions of approximately $27.5 million to our pension and other postretirement benefit plans in 2007. Pension funding is based upon annual actuarial studies prepared for each plan. For our postretirement welfare benefits, our policy is to contribute an amount equal to the annual actuarially determined cost that is also recoverable in rates. We generally fund our 401(h) and VEBA trusts monthly, subject to our liquidity needs and the maximum deductible amounts allowed for income tax purposes.
We estimate the plans will make future benefit payments to participants as follows (in thousands):
Predecessor Company
The Predecessor Company filed several motions to terminate various nonqualified benefit plans and individual supplemental retirement contracts for former employees. All liabilities associated with these plans were removed from our balance sheet upon emergence based on our expectation that these claims would be settled through the shares from the reserve established for Class 9 claimants. Various claimants objected to the Bankruptcy Court’s jurisdiction to terminate such plans and/or contracts. In July 2005, the Bankruptcy Court approved share-based settlements with most of the participants in the various nonqualified plans and supplemental retirement contracts. However, the Bankruptcy Court determined that it did not have jurisdiction to consider a motion to terminate various individual supplemental retirement contracts, therefore in 2005 we reestablished a liability of approximately $2.6 million and have resumed payments on those individual supplemental retirement contracts not covered by the Bankruptcy Court’s jurisdiction.
Defined Contribution Plans
Our defined contribution plan permits employees to defer receipt of compensation as provided in Section 401(k) of the Internal Revenue Code. Under the plan, employees may elect to direct a percentage of their gross compensation to be contributed to the plan. We contribute various percentage amounts of the employee’s gross compensation contributed to the plan. Matching contributions were $4.3 million for 2006, $3.4 million for 2005, $0.6 million for the two-month period ended December 31, 2004, and $2.7 million for the 10-month period ended October 31, 2004, respectively.
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(19)
Stock-Based Compensation
Restricted Stock Awards
Under our long-term incentive plans administered by the Human Resources Committee of our Board, we have granted service-based restricted stock to all eligible employees and members of our Board. Under these plans, a total of 700,000 shares were set aside for restricted stock grants, in addition to 228,315 shares of restricted stock granted upon our emergence from bankruptcy. We may issue new shares or reuse forfeited shares in order to deliver shares to employees for equity grants. Pursuant to the terms of the Merger Agreement with BBI, which provides that all of the shares available under our long term incentive plans may be awarded before completion of the transaction, 400,025 shares of restricted stock were granted in November 2006. As of December 31, 2006 there were 57,023 shares of common stock of the initial 700,000 shares remaining available for grants under this plan. The stock vests to participants at various times ranging from one to five years if the service requirements are met. Nonvested shares do not receive dividend distributions. The long-term incentive plans provide for accelerated vesting and cash settlement in the event of a change in control. The proposed transaction with BBI would trigger this acceleration.
In accordance with SFAS No. 123R, we account for our service-based restricted stock awards using the fixed accounting method, whereby we amortize the value of the market price of the underlying stock on the date of grant (grant-date fair value) to compensation expense over the service period either ratably or in tranches. We reverse any expense associated with restricted stock that is canceled or forfeited during the performance or service period. Compensation expense recognized for restricted stock awards was $3.6 million for the year ended December 31, 2006, $4.7 million for the year ended December 31, 2005, $0.2 million for the two months ended December 31, 2004, and $2.3 million for the 10-months ended October 31, 2004. The total income tax benefit recognized in the income statement for these restricted stock awards was $1.5 million for the year ended December 31, 2006, $1.8 million for the year ended December 31, 2005, $0.1 million for the two months ended December 31, 2004, and $0.9 million for the 10-months ended October 31, 2004.
Summarized share information for our restricted stock awards is as follows:
* This amount represents shares forfeited from awards granted upon our emergence from bankruptcy. Forfeited shares from this grant are cancelled. Forfeited shares from all other grants are available to be reissued.
As of December 31, 2006 we had $14.1 million of unrecognized compensation cost related to nonvested portion of outstanding restricted stock awards, which is reflected as unearned restricted stock in our Statement of Common Shareholders’ Equity. If the transaction with BBI is not completed, the cost is expected to be recognized over a weighted-average period of 2.5 years. The total fair value of shares vested was $1.7 million for the year ended December 31, 2006, $4.6 million for the year ended December 31, 2005, and $2.3 million for the two months ended December 31, 2004.
Director’s Deferred Compensation
Nonemployee directors may elect to defer up to 100% of any qualified compensation that would be otherwise payable to him or her, subject to compliance with our 2005 Deferred Compensation Plan for Nonemployee Directors and Section 409A of the Internal Revenue Code. The deferred compensation may be invested in NorthWestern stock or in designated investment funds. Compensation deferred in a particular month is recorded as a deferred stock unit (DSU) on the first of the following month based on the closing price of NorthWestern stock or the designated investment fund. A DSU entitles the grantee to receive one share of common stock for each DSU at the end of the deferral period. The value of these DSUs are
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marked-to-market on a quarterly basis with an adjustment to directors compensation expense. Based on the election of the nonemployee director, following separation from service on the Board, other than on account of death, he or she shall be paid a distribution either in a lump sum or in approximately equal installments over a designated number years (not to exceed 10 years). During the years ended December 31, 2006 and 2005, DSUs issued to members of our Board totaled 22,805 and 20,934, respectively. Total compensation expense attributable to the DSUs during the years ended December 31, 2006 and 2005 was approximately $0.9 million and $0.7 million, respectively.
(20)
Regulatory Assets and Liabilities
We prepare our financial statements in accordance with the provisions of SFAS No. 71, as discussed in Note 3 to the Financial Statements. Pursuant to this pronouncement, certain expenses and credits, normally reflected in income as incurred, are deferred and recognized when included in rates and recovered from or refunded to the customers. Regulatory assets and liabilities are recorded based on management’s assessment that it is probable that a cost will be recovered or that an obligation has been incurred. Accordingly, we have recorded the following major classifications of regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected or refunded. Of these regulatory assets and liabilities, energy supply costs are the only items earning a rate of return. The remaining regulatory items have corresponding assets and liabilities that will be paid for or refunded in future periods. Because these costs are recovered as paid, they do not earn a return. We have specific orders to cover approximately 91% of our regulatory assets and approximately 95% of our regulatory liabilities.
Pension and SFAS No. 106
Through fresh-start reporting in 2004 we adjusted our qualified pension and other postretirement benefit plans to their projected benefit obligation by recognition of all previously unamortized actuarial gains and losses. See Note 4 for further information regarding the impacts of fresh-start reporting. A pension regulatory asset has been recognized for the obligation that will be included in future cost of service. Historically, the MPSC rates have allowed recovery of pension costs on a cash basis. In 2005, the MPSC authorized the recognition of pension costs based on an average of the funding to be made over a 5-year period for the calendar years 2005 through 2009. The SDPUC allows recovery of pension costs on an accrual basis. A regulatory asset has been recognized for the SFAS No. 106 fair value adjustments resulting from fresh-start reporting. The MPSC allows recovery of SFAS No. 106 costs on an accrual basis.
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Natural Gas Competitive Transition Charges
Natural gas transition bonds were issued in 1998 to recover stranded costs of production assets and related regulatory assets and provide a lower cost to utility customers, as the cost of debt was less than the cost of capital. The MPSC authorized the securitization of these assets and approved the recovery of the competitive transition charges in rates over a 15-year period. The regulatory asset relating to competitive transition charges amortizes proportionately with the principal payments on the natural gas transition bonds.
Supply Costs
The MPSC has authorized the use of electric and natural gas supply cost trackers, which enable us to track actual supply costs and either recover the under collection or refund the over collection to our customers. Accordingly, a regulatory asset and liability has been recorded to reflect the future recovery of under collections and refunding of over collections through the ratemaking process. We earn interest on the electric and natural gas supply costs of 8.46% and 8.82%, respectively, in Montana; 10.61% and 8.53%, respectively, in South Dakota; and 8.32% for natural gas in Nebraska. These same rates are paid to our customers in the event of a refund.
Income Taxes
Tax assets primarily reflect the effects of plant related temporary differences such as removal costs, capitalized interest and contributions in aid of construction that we will recover or refund in future rates. We amortize these amounts as temporary differences reverse.
Deferred Financing Costs
Consistent with our historical regulatory treatment, a regulatory asset has been established to reflect the remaining deferred financing costs on long-term debt that has been replaced through the issuance of new debt. The 2006 increase is due to the refinancing of $170.2 million of PCOs and $150 million of Montana First Mortgage Bonds.
State & Local Taxes & Fees
Under Montana law, we are allowed to track the increases in the actual level of state and local taxes and fees and recover these amounts. In 2006, the MPSC authorized recovery of approximately 60% of the estimated increase in our local taxes and fees (primarily property taxes) as compared to the related amount included in rates during our last general rate case in 1999. On December 1, 2006, we filed with the MPSC for an automatic rate adjustment, which reflected 100% of the under recovery for 2006 and estimated amounts for 2007. In January 2007, the MPSC issued an order allowing recovery of the 2006 actual increase and the 2007 estimated increase, reduced by 40% for an income tax deduction. While we have recorded a regulatory asset consistent with the MPSC’s authorization, we are disputing the reduction by the MPSC and have filed a Petition for Judicial Review in Montana District Court regarding this issue. We anticipate resolving this matter in 2007; however we cannot currently predict an outcome.
Removal Cost
Historically, the anticipated costs of removing assets upon retirement were provided for over the life of those assets as a component of depreciation expense; however, SFAS No. 143 precludes this treatment. Our depreciation method, including cost of removal, is established by the respective regulatory commissions, therefore in accordance with SFAS No. 71, we continue to accrue removal costs for our regulated assets by increasing our regulatory liability. See Note 8, Asset Retirement Obligations, for further information regarding this item.
Gas Storage Sales
A gas storage sales regulatory liability was established in 2000 and 2001 based on gains on cushion gas sales in Montana. This gain is being flowed to customers over a period that matches the depreciable life of surface facilities that were added to maintain deliverability from the field after the withdrawal of the gas. This regulatory liability is a reduction of rate base.
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Regulatory Matters
The MPSC, the SDPUC, the NPSC, and the FERC approve the rates that we charge our customers for our regulated businesses, as applicable. There have been no significant regulatory matters in South Dakota or Nebraska during the past three years. Current regulatory issues are discussed below.
On September 29, 2006 we submitted an informational filing to the MPSC outlining our cost of providing electric and natural gas delivery service in Montana. The informational filing is based on actual costs in 2005, adjusted for known and measurable cost changes that occurred in 2006 and is a result of a 2004 stipulation and settlement agreement between NorthWestern, the MPSC and the Montana Consumer Counsel. The filing demonstrates a revenue deficiency of approximately $29.1 million in electric rates and $12.3 million in natural gas rates; however, we did not seek a rate adjustment, as we would like the MPSC to give priority to its approval of the transaction with BBI.
On October 17, 2006, we filed an application with the FERC requesting an increase in transmission rates in Montana under the open access transmission tariff. While the request presents a net increase of $28.8 million in overall transmission costs, the rate adjustment pertains only to wholesale transmission and retail choice customers. Therefore, the portion of the requested cost increase pertaining to the remaining Montana retail default supply customer loads, which represents approximately 70% of this increase, is subject to MPSC jurisdictional rates, and will not result in increased revenues. Since the last transmission rate adjustment, which was filed in March 1998, our cost of service has increased and the type of transmission service that we provide has changed as partial retail access has developed in Montana. The overall net effect of this filing for affected customers is expected to be an average rate increase of between 6 - 18%, depending on the type of customer.
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Earnings (Loss) Per Share
Basic earnings per share is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of common stock equivalent shares that could occur if all warrants were exercised and all unvested restricted shares were to vest. Common stock equivalent shares are calculated using the treasury stock method. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested restricted shares, deferred share units and warrants. Average shares used in computing the basic and diluted earnings per share are as follows:
Warrants outstanding as of December 31, 2006 and 2005 of 4,506,525 and 4,615,633, respectively are dilutive and have been included in the earnings per share calculations. Each warrant could be exchanged for 1.08 and 1.04 shares of common stock and have an exercise price of $26.24 and $27.48 as of December 31, 2006 and 2005, respectively. Under the terms of the warrant agreement, the exercise price of the warrants is subject to adjustment from time to time, based on certain events. These events include additional share issuances and dividend payments. An adjustment is made in the case of a cash dividend if the amount of the cash dividend increases or decreases the exercise price by at least 1%, otherwise such amount is carried forward and taken into account with any subsequent cash dividend. Adjustments in the exercise price also require an adjustment in the number of shares covered by the warrants. A total of 109,108 warrants were exercised during the year ended December 31, 2006.
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Commitments and Contingencies
Qualifying Facilities Liability
In Montana we have certain contracts with Qualifying Facilities, or QFs. The QFs require us to purchase minimum amounts of energy at prices ranging from $65 to $138 per megawatt hour through 2029. Our gross contractual obligation related to the QFs is approximately $1.6 billion through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $1.2 billion through 2029. Upon adoption of fresh-start reporting, we computed the fair value of the remaining liability of approximately $367.9 million to be approximately $143.8 million based on the net present value (using a 7.75% discount factor) of the difference between our obligations under the QFs and the related amount recoverable. The following table summarizes the change in the QF liability (in thousands):
The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands):
Long Term Supply and Capacity Purchase Obligations
We have entered into various commitments, largely purchased power, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 24 years. Costs incurred under these contracts were approximately $447.1 million for the year ended December 31, 2006, $433.9 million for the year ended December 31, 2005, $72.1 million for the two-months ended December 31, 2004, and $259.4 million for the 10-months ended October 31, 2004. As of December 31, 2006 our commitments under these contracts are $535 million in 2007, $350 million in 2008, $292 million in 2009, $274 million in 2010, $133 million in 2011, and $528 million thereafter. These commitments are not reflected in our Consolidated Financial Statements.
Environmental Liabilities
Environmental laws and regulations are continually evolving, and, therefore, the character, scope, cost and availability of the measures we may be required to take to ensure compliance with evolving laws or regulations cannot be accurately predicted. The range of exposure for environmental remediation obligations at present is estimated to range between $20.4 million to $56.1 million. As of December 31, 2006, we have a reserve of approximately $34.1 million. We anticipate that as environmental costs become fixed and reliably determinable, we will seek insurance reimbursement and/or authorization to recover these in rates; therefore, we do not expect these costs to have a material adverse effect on our consolidated financial position, ongoing operations, or cash flows.
The Clean Air Act Amendments of 1990 and subsequent amendments stipulate limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power plants. We comply with these existing emission requirements through purchase of sub-bituminous coal, and we believe that we are in compliance with all presently applicable environmental
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protection requirements and regulations with respect to these plants. Recent legislation has been proposed, which may require further limitations on emissions of these pollutants along with limitations on carbon dioxide, particulate matter, and mercury emissions. The recent regulatory and legislative proposals are subject to normal administrative processes, and we cannot make any prediction as to whether the proposals will pass or the impact of those actions. In November 2006, The Sierra Club sent a Notice of Intent to File a Suit to the owners, including us, of Big Stone I, asserting that it would file a lawsuit in 60 days alleging that the plant failed to obtain permits for certain projects undertaken in 1995, 2001 and 2005 and otherwise failed to comply with the Clean Air Act. The owners intend to vigorously defend against any lawsuit filed by The Sierra Club.
Coal-Fired Plants
Citing its authority under the Clean Air Act, the EPA has finalized Clean Air Mercury Regulations (CAMR) that affect coal-fired plants. These regulations establish a cap-and-trade program to take effect in two phases, with a first phase to begin in January 2010, and a second phase with more stringent caps to begin in January 2018. Under CAMR, each state is allocated a mercury emissions cap and is required to develop regulations to implement the requirements, which can follow the federal requirements or be more restrictive.
Montana has finalized its own, more stringent rules that would require every coal-fired generating plant in the state to achieve by 2010 reduction levels more stringent than CAMR’s 2018 cap. Because enhanced chemical injection technologies may not be sufficiently developed to meet this level of reductions by 2010, there is a risk that adsorption/absorption technology with fabric filters at the Colstrip Unit 4 generation facility would be required, which could represent a material cost. We expect the Montana mercury rules to be challenged. If those rules are overturned and we are instead required to comply with CAMR, achievement of the 2010 and 2018 requirements may be possible with more refined chemical injection technology combined with adjustments to boiler/fireball dynamics at a minimal cost. We are continuing to work with the other Colstrip owners to determine the ultimate financial impact of these new rules.
Manufactured Gas Plants
Approximately $28.6 million of our environmental reserve accrual is related to manufactured gas plants. Two formerly operated manufactured gas plants located in Aberdeen and Mitchell, South Dakota, have been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System (CERCLIS) list as contaminated with coal tar residue. At this time, no material remediation is necessary at the Mitchell location. In January 2007, we received a letter from the South Dakota Department of Environment and Natural Resources (SD DENR) that this location is at a No Further Action Status. We are currently investigating and characterizing the Aberdeen site pursuant to work plans approved by the SD DENR and some remedial activities commenced at the Aberdeen site in 2006. Our current reserve for remediation costs at the Aberdeen site is approximately $15.4 million, and we estimate that approximately $13 million of this amount will be incurred during the next five years. During 2006, we incurred remediation costs of approximately $0.4 million.
We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. During 2005, the Nebraska Department of Environmental Quality (NDEQ) conducted Phase II investigations of soil and groundwater at our Kearney and Grand Island sites. On March 30, 2006 and May 17, 2006, the NDEQ released to us the Phase II Limited Subsurface Assessment performed by the NDEQ’s environmental consulting firm for Kearney and Grand Island, respectively, and we are evaluating the results of these reports. We plan to conduct additional site investigation and assessment work at these locations in 2007. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any remediation cleanup at our Nebraska locations.
In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require entry into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program, but required preparation of a groundwater monitoring plan. The Butte and Helena sites, were placed into the MDEQ’s voluntary remediation program for cleanup due to the existence of exceedences of regulated pollutants in the groundwater. We conducted additional groundwater monitoring during 2005 at the Butte and Missoula sites and have analyzed the data and presented it to the MDEQ. At this time, we believe that natural attenuation should address the problems at these sites; however, additional groundwater monitoring will be necessary. Closure of the Butte and Missoula sites is expected shortly. Recent monitoring of groundwater at the Helena manufactured gas plant site suggests that groundwater remediation may be necessary to prevent certain contaminants from
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migrating offsite. We have evaluated the results of a pilot program meant to promote aerobic degradation of certain targeted contaminants. Further data collection is necessary to complete the evaluation and assess other remediation technologies to determine the optimal remedial technology for this site. Monitoring of groundwater at this site will be necessary for an extended time. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remediation at the Helena site.
Based upon our investigations to date, our current environmental liability reserves, applicable insurance coverage, and the potential to recoup some portion of prudently incurred remediation costs in rates, we do not expect remediation costs at these locations to be materially different from the established reserve.
Milltown Mining Waste
Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the Milltown Dam hydroelectric facility, a three megawatt generation facility located at the confluence of the Clark Fork and Blackfoot Rivers. In April 2003, the Environmental Protection Agency (EPA) announced its proposed remedy to address the mining waste contamination located in the Milltown Reservoir. This remedy proposed partial removal of the contaminated sediments located within the Milltown Reservoir, together with the removal of the Milltown Dam and powerhouse (this remedy was incorporated into the EPA’s formal Record of Decision issued on December 20, 2004). In light of this pre-Record of Decision announcement, we entered into a stipulation (Stipulation) with Atlantic Richfield, the EPA, the Department of the Interior, the State of Montana and the Confederated Salish and Kootenai Tribes (collectively the Government Parties), which capped NorthWestern’s and CFB’s collective liability to Atlantic Richfield and the Government Parties at $11.4 million. In April 2006, we released escrowed amounts of $2.5 million and $7.5 million to the State of Montana and Atlantic Richfield, respectively, in accordance with the terms of the consent decree described below. Pursuant to the terms of the consent decree, the parties expect that the remaining financial obligation of $1.4 million to the State of Montana will be covered through a combination of any refund of premium upon cancellation of the catastrophic release policy described below, and the sale or transfer of land and water rights associated with the Milltown Dam operations.
On July 18, 2005, CFB and we executed the Milltown Reservoir superfund site consent decree, which incorporated the terms set forth in the Stipulation. The consent decree was approved by the Federal District Court for the District of Montana on February 8, 2006 and became effective on April 10, 2006. In light of the material environmental risks associated with the catastrophic failure of the Milltown Dam, we secured a 10-year, $100 million environmental insurance policy, effective May 31, 2002, to mitigate the risk of future environmental liabilities arising from the structural failure of the Milltown Dam caused by an act of God. We are obligated under the settlement to continue to maintain the environmental insurance policy until the Milltown Dam is removed during implementation of the remedy.
Other
We continue to manage polychlorinated biphenyl (PCB)-containing oil and equipment in accordance with the EPA’s Toxic Substance Control Act regulations. We, along with other potentially responsible parties, are currently negotiating with EPA over remediation of an oil recycling facility in Oregon to which waste oil had been transported by The Montana Power Company and others. We anticipate that these negotiations will be successfully resolved during 2007. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.
We routinely engage the services of a third-party environmental consulting firm to perform a comprehensive evaluation of our environmental reserve. Based upon information available to our consultants at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:
•
We and our third-party consultant may not know all sites for which we are alleged or will be found to be responsible for remediation; and
•
Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.
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Legal Proceedings
Magten/Law Debenture/QUIPS Litigation
On April 16, 2004, Magten Asset Management Corporation (Magten) and Law Debenture Trust Company (Law Debenture) initiated an adversary proceeding, which we refer to as the QUIPS Litigation, against NorthWestern seeking among other things, to void the transfer of certain assets and liabilities of CFB to us. In essence, Magten and Law Debenture are asserting that the transfer of the transmission and distribution assets acquired from the Montana Power Company was a fraudulent conveyance because such transfer allegedly left CFB insolvent and unable to pay certain claims. The plaintiffs also assert that they are creditors of CFB as a result of Magten owning a portion of the Series A 8.5% Quarterly Income Preferred Securities for which Law Debenture serves as the Indenture Trustee. Plaintiffs seek, among other things, the avoidance of the transfer of assets, declaration that the assets were fraudulently transferred and are not property of our bankruptcy estate, the imposition of constructive trusts over the transferred assets and the return of such assets to CFB. On September 29, 2006, the Delaware District Court, which has jurisdiction over this lawsuit, denied NorthWestern’s Motion for a Protective Order to limit the scope of discovery sought by plaintiffs. Discovery has commenced and the District Court has scheduled trial, if any, to be held in December 2007. We intend to vigorously defend against the QUIPS litigation.
On April 19, 2004, Magten also filed a complaint against certain former and current officers of CFB in U.S. District Court in Montana, seeking compensatory and punitive damages for alleged breaches of fiduciary duties by such officers in connection with the same transaction described above which is at issue in the QUIPS Litigation, namely the transfer of the transmission and distribution assets acquired from the Montana Power Company to NorthWestern. Those officers have requested CFB to indemnify them for their legal fees and costs in defending against the lawsuit and any settlement and/or judgment in such lawsuit. That lawsuit was transferred to the Federal District Court in Delaware in July 2005 and is consolidated with the QUIPS Litigation for purposes of discovery and pre-trial matters. In February 2007, those officers asked the Federal District Court in Delaware for leave to file a motion to dismiss the complaint and Magten has filed a motion to amend its complaint to add Law Debenture as an additional plaintiff.
In July 2006, Magten served a complaint against The Bank of New York (BNY) in an action filed in New York State court, seeking damages for alleged breach of contract, breach of fiduciary duty and negligence in connection with the same transaction described above which is at issue in the QUIPS Litigation. Specifically, Magten alleges that BNY, as the Indenture Trustee at the time of the 2002 transfer of assets from Montana Power Company to NorthWestern, should have taken steps to protect the QUIPS holders’ interests by seeking to set aside the transfer and imposing a constructive trust on the assets. The New York State court is considering BNY’s motion to dismiss Magten’s complaint. BNY has asserted a right to indemnification by NorthWestern for legal fees and costs incurred in defending against Magten’s claims pursuant to the terms of the Indenture governing the QUIPS under which BNY served as Trustee. It is our position that any such recovery should be payable from the disputed claim reserve although the Plan of Reorganization Creditors Committee has objected to this position.
On April 15, 2005, Magten and Law Debenture filed an adversary complaint in the Bankruptcy Court against NorthWestern Corporation, Gary Drook, Michael Hanson, Brian Bird, Thomas Knapp and Roger Schrum seeking to revoke the Confirmation Order on the grounds that it was procured by fraud as a result of the alleged failure to adequately fund the Class 9 Disputed Claims Reserve with enough shares of New Common Stock to satisfy a potential full recovery on all pending claims against NorthWestern’s bankruptcy estate which were outstanding at the time the Plan became Effective on November 1, 2004. The plaintiffs also alleged breach of fiduciary duty on the part of certain former and current officers in connection with the alleged under-funding of the Disputed Claims Reserve. NorthWestern filed a motion to dismiss or stay the litigation and on July 26, 2005, the Bankruptcy Court ordered a stay of the litigation pending resolution of Magten’s appeal of the Order confirming our Plan of Reorganization. NorthWestern intends to seek dismissal of this action and to the extent such action is not dismissed, NorthWestern intends to vigorously defend this action.
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Twice during 2005, Magten, Law Debenture, the Plan Committee and NorthWestern unsuccessfully engaged in mediation to resolve the pending appeals and other pending litigation described above. At this time, we cannot predict the impact or resolution of any of these actions or reasonably estimate a range of possible loss, which could be material. We intend to vigorously defend against the adversary proceedings, lawsuits, appeals and any subsequently filed similar litigation. While we cannot currently predict the impact or resolution of this litigation, the plaintiffs’ claims with respect to the QUIPs Litigation will be treated as general unsecured, or Class 9, claims and will be satisfied out of the Class 9 Disputed Claims Reserve established under the Plan.
McGreevey Litigation
We are one of several defendants in a class action lawsuit entitled McGreevey, et al. v. The Montana Power Company, et al, now pending in U.S. District Court in Montana. The lawsuit, which was filed by former shareholders of The Montana Power Company (most of whom became shareholders of Touch America Holdings, Inc. as a result of a corporate reorganization of the Montana Power Company), claims that the disposition of various generating and energy-related assets by The Montana Power Company were void because of the failure to obtain shareholder approval for the transactions. Plaintiffs thus seek to reverse those transactions, or receive fair value for their stock as of late 2001, when plaintiffs claim shareholder approval should have been sought. NorthWestern is named as a defendant due to the fact that we purchased The Montana Power L.L.C., which plaintiffs claim is a successor to the Montana Power Company.
In June 2006, we and the McGreevey plaintiffs entered into an agreement to settle the claims brought by the McGreevey plaintiffs in all of the actions stated above through a covenant not to execute by McGreevey plaintiffs against us and by us quit claiming any interest we had in any claims we may or may not have under any applicable directors and officers liability insurance policy, against any insurers for contractual or extracontractual damages, and against certain defendants in the McGreevey lawsuits. This agreement was finally approved by the Bankruptcy Court in November 2006. In February 2007, we filed a motion to dismiss the claims against us in the McGreevey lawsuits and no objections have been filed. We anticipate a decision by the federal court in the next few months.
City of Livonia
In November 2005, we and our directors were named as defendants in a shareholder class action and derivative action entitled City of Livonia Employee Retirement System v. Draper, et al., pending in the U.S. District Court for the District of South Dakota. The plaintiff claims, among other things, that the directors breached their fiduciary duties by not sufficiently negotiating with Montana Public Power Inc. and Black Hills Corporation, two entities that had made public, unsolicited offers to purchase NorthWestern. On April 26, 2006, Livonia amended its complaint to add allegations that our directors had erred in choosing the BBI offer because it was not the most attractive offer they had received for the company. The parties have entered into a settlement agreement which provides that NorthWestern will redeem the existing shareholder rights plan either following shareholder approval of the Merger Agreement with BBI or upon termination of the Merger Agreement with BBI - whichever occurs first. The Board may adopt a new shareholder rights plan if the shareholders approve adoption of such a plan in advance or, in the event that circumstances require timely implementation of such a plan, the Board seeks and receives approval from shareholders within 12 months after adoption. After limited confirmatory discovery, the settlement agreement has been filed. In December 2006 the federal court indicated it would not approve the settlement because it did not provide any benefit to the class members. Based on the federal court’s order, the plaintiffs agreed to dismiss the lawsuit with prejudice on the condition that the federal court would retain jurisdiction over any award of attorneys’ fees. The plaintiffs’ lawyers have filed a motion seeking discovery in advance of its motion for an award of attorneys’ fees. NorthWestern will contest plaintiffs motion for discovery and attorneys’ fees and believe that any award of attorneys’ fees will be reimbursed by insurance proceeds.
Other Litigation
In April 2005, a group of former employees of the Montana Power Company filed a lawsuit in the state court of Montana against us and certain officers styled Ammondson, et al. v. NorthWestern Corporation, et al., Case No. DV-05-97. The former employees have alleged that by moving to terminate their supplemental retirement contracts in our bankruptcy proceeding without having listed them as claimants or giving them notice of the disclosure statement and Plan, that we breached those contracts, and breached a covenant of good faith and fair dealing under Montana law and by virtue of filing a complaint in our Bankruptcy Case against those employees from seeking to prosecute their state court action against
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NorthWestern, we had engaged in malicious prosecution and should be subject to punitive damages. On May 4, 2005, the Bankruptcy Court found that it did not have jurisdiction over these contracts, dismissed our action against these former employees, and transferred our motion to terminate the contracts to Montana state court where the former employees’ lawsuit is pending. We unsuccessfully engaged in mediation of this dispute in November 2005 and September 2006. We recorded a loss of $2.6 million in the third quarter of 2005 to reestablish a liability for the present value of amounts due to these former employees under their supplemental retirement contracts and reestablished monthly payments to these former employees under the terms of their contracts. In February 2007, a jury verdict was rendered against us in Montana state court, which ordered us to pay $17.4 million in compensatory and $4.0 million in punitive damages in a case called Ammondson, et al. v. NorthWestern Corporation, et al. Due to the verdict, we recognized a loss of $19.0 million in our 2006 results of operations to increase our recorded liability related to this claim. The Montana state court must review the amount of the punitive damages under state law and will enter a decision on the amount of punitive damages on March 2, 2007. We intend to appeal this verdict; however, there can be no assurance that we will prevail in our efforts. In addition, we expect to incur additional legal and court costs related to these proceedings.
In December 2003, the SEC notified NorthWestern that it had issued a formal order of private investigation and subsequently subpoenaed documents from NorthWestern, NorthWestern Communications Solutions, Expanets and Blue Dot. Since December 2003, we have periodically received and continue to receive subpoenas and informal requests from the SEC requesting documents and testimony from former and current employees as well as third parties regarding these matters. In January 2006, the SEC issued Wells Notices to several former officers, a current officer and a then current employee, associated with NorthWestern and NorthWestern Communications Solutions. In July 2006, additional Wells Notices were issued to former officers and directors of NorthWestern and Expanets. A Wells Notice is an indication that the SEC staff has made a preliminary decision to recommend enforcement action that provides recipients with an opportunity to respond to the SEC staff before a formal recommendation is finalized. In December 2006, the SEC filed a complaint alleging securities law violations related to NorthWestern Communications Solutions against the former officers, a current officer and a then current employee. All the individuals agreed to settle the allegations of the complaint against them except our current officer. The current officer has been removed from his officer position pending the outcome of the complaint. There have been no findings or adjudication of the underlying allegations in the Wells Notices, and the SEC’s investigation is ongoing and it could issue additional Wells Notices. In addition, certain of our former directors and several former and current employees of NorthWestern and our subsidiary affiliates have been interviewed by representatives of the FBI and IRS concerning certain of the allegations made in the now resolved class action securities and derivative litigation as well as other matters. We have not been advised that NorthWestern is the subject of any FBI or IRS investigation. We are not aware of any other governmental inquiry or investigation related to these matters. We are fully cooperating with the SEC’s investigation and intend to cooperate with the FBI and IRS if we are requested to do so in connection with any investigation. We cannot predict whether or not any other governmental inquiry or investigation will be commenced. We cannot predict when the SEC investigation will be completed or its outcome but we continue to work toward a resolution of the investigation. If the SEC determines that we have violated federal securities laws and institutes civil enforcement proceedings against us, as a result of a ruling by the Bankruptcy Court, the SEC may not be able to pursue civil sanctions, including, but not limited to, monetary penalties against NorthWestern. The SEC did not appeal such order within the allowed appeal period. The SEC could, however, pursue other remedies and penalties against NorthWestern.
Relative to our leasehold interest in Colstrip Unit 4, the Mineral Management Service of the United States Department of Interior (MMS) issued two orders to Western Energy Company (WECO) in 2002 and 2003 to pay additional royalties concerning coal sold to Colstrip Units 3 & 4 owners. The orders assert that additional royalties are owed as a result of WECO not paying royalties in connection with revenue received by WECO from the Colstrip Units 3 & 4 owners under a coal transportation agreement during the period October 1, 1991 through December 31, 2001. On April 28, 2005, the appeals division of the MMS issued an order that reduced the amount claimed due to the application of statute of limitations. The state of Montana issued a demand to WECO in May 2005 consistent with the MMS position outlined above on these transportation revenues. Further, on September 28, 2006, the MMS issued an order to pay additional royalties in the amount of $1.6 million on the basis of an audit of WECO’s royalty payments during the three years 2002 to 2004. WECO has appealed these orders and we are monitoring the process. The Colstrip Units 3 & 4 owners and WECO currently dispute the responsibility of the expenses if the MMS position prevails. We believe that the Colstrip Units 3 & 4 owners have reasonable defenses in this matter based on our review. However, if the MMS position prevails and WECO prevails in passing the expense responsibility to the owners, our share of the alleged additional royalties would be 15 percent, or approximately $1.2 million, and ongoing royalty expenses related to coal transportation.
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We are also subject to various other legal proceedings and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these actions will not materially affect our financial position, results of operations, or cash flows.
Disputed Claims Reserve
Upon consummation of our Plan of Reorganization, we established a reserve of approximately 4.4 million shares of common stock from the shares allocated to holders of our trade vendor claims in excess of $20,000 and holders of Class 9 unsecured claims. The shares held in this reserve may be used to resolve various outstanding unsecured claims and unliquidated litigation claims, as these claims were not resolved or deemed allowed upon consummation of our Plan. We have surrendered control over the common stock provided and the shares reserve is administered by our transfer agent; therefore we recognized the issuance of the common stock upon emergence. If excess shares remain in the reserve after satisfaction of all obligations, such amounts would be reallocated pro rata to the allowed Class 7 and 9 claimants. If the BBI transaction is completed, the merger consideration received for these shares will be retained by our transfer agent until resolution of the remaining claims.
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Common Stock
Successor Company
The Successor Company is a Delaware corporation and filed a new certificate of incorporation (New Articles). The New Articles authorized 250,000,000 shares consisting of 200,000,000 shares of common stock with a $0.01 par value and 50,000,000 shares of preferred stock with a $0.01 par value. As a result of the Predecessor Company’s emergence from bankruptcy, the Successor Company issued 35,500,000 shares of common stock in settlement of claims. Pursuant to the Plan, such stock had an agreed value of $710.0 million. Accordingly, the Successor Company recorded common stock and additional paid-in capital of $355,000 and $709.6 million, respectively, in the Consolidated Balance Sheet as of October 31, 2004. In addition, the Plan reserved 2,265,957 shares of new common stock for the New Incentive Plan, of which 228,315 shares were granted for Special Recognition Grants (see Note 19).
Concurrent with our emergence from bankruptcy we issued 4,620,333 warrants, each entitling the holder thereof to purchase one share of common stock, to certain holders of class 8(a) and 8(b) claims in settlement of their allowed claim. These warrants are exercisable from November 1, 2004 through November 1, 2007 at a current adjusted strike price of $26.24 (see Note 22). We recognized $3.8 million of expense associated with these warrants as a reduction of cancellation of indebtedness income.
Repurchase of Common Stock
On November 8, 2005, our Board of Directors authorized a common stock repurchase program that allowed us to repurchase up to $75 million of common stock under a specific trading plan. This plan was cancelled in May 2006. From the program’s inception through December 31, 2005 we repurchased in open market transactions 96,442 shares of common stock for approximately $2.8 million. During 2006, we repurchased in open market transactions 121,306 shares of common stock for approximately $3.7 million.
We also retired 16,664 shares and 95,799 shares of common stock during the years ended December 31, 2006 and 2005, respectively, which were tendered by employees to us to satisfy the employees’ tax withholding obligations in connection with the vesting of restricted stock awards. These shares were retired based on their fair market value on the vesting date.
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Segment and Related Information
We currently operate our business in five reporting segments: (i) regulated electric operations, (ii) regulated natural gas operations, (iii) unregulated electric, (iv) unregulated natural gas, and (v) all other, which primarily consists of our other miscellaneous service activities that are not included in the other identified segments, together with the unallocated corporate costs and investments. We evaluate the performance of these segments based on gross margin. Items below operating income are not allocated between our electric and natural gas segments. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions. Financial data for the business segments, excluding discontinued operations, are as follows (in thousands):
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Quarterly Financial Data (Unaudited)
Our quarterly financial information has not been audited, but, in management’s opinion, includes all adjustments necessary for a fair presentation. Our business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. Amounts presented are in thousands, except per share data (in thousands):
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SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS NORTHWESTERN CORPORATION AND SUBSIDIARIES
(1)
Utilization of previously recorded balances.