Part
I
OVERVIEW
NorthWestern Corporation, doing business as Northwestern Energy, provides
electricity and natural gas to approximately 650,000 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 and have distributed electricity and
natural gas in Montana since 2002.
We were incorporated in Delaware in November 1923. Our principal office
is located at 3010 W. 69
th
Street, Sioux Falls, South Dakota 57108 and our
telephone number is (605) 978-2900. 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 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.
We operate our business in the following reporting segments:
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regulated electric operations;
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regulated natural gas operations;
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unregulated electric operations;
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all other, which primarily consists of our remaining
unregulated natural gas operations and our unallocated corporate costs.
During 2007 we changed our management of the unregulated natural gas
segment, moved certain customers to our regulated natural gas segment and
sold several customer contracts; therefore, the unregulated natural gas
operations are no longer reported separately.
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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 328,000 customers in 187 communities and their surrounding rural areas, 15
rural electric cooperatives and in Wyoming to the Yellowstone National Park. In 2007, by
category, residential, commercial and industrial, and other sales accounted for
approximately 36%, 52%, and 12% 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 1,724 MWs, the average daily load was
approximately 1,186 MWs, and more than 10.4 million
MWHs were
supplied during the year ended December 31, 2007.
Our Montana electric transmission system consists of approximately 7,000
miles of transmission lines, ranging from 50 to 500 kV, 272 circuit segments and
approximately 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 500 kV transmission system, which is jointly owned,
230 kV and 161 kV facilities form the key assets of our Montana transmission system. Lower
voltage systems, which range from 50 kV to 115 kV, provide for local area service needs.
The system has interconnections with five major nonaffiliated transmission systems located
in the Western Electricity Coordinating Council (WECC) 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
8
Power
Administration; and the Western Area Power Administration.
Our Montana electric distribution system consists of approximately 21,000
miles of overhead and underground distribution lines and approximately 335 transmission and
distribution substations.
Electric Supply
Currently, we own no regulated generation assets in Montana. Accordingly, we
purchase substantially all of our Montana capacity and energy requirements for electric
supply from third parties. Our annual electric supply load requirements are slightly in
excess of 700 average MWs. We currently have under contract approximately 94 percent of the
energy requirements necessary to meet our projected load requirements through June 30,
2008, with approximately 96 percent at fixed prices. For the period July 1, 2008 through
June 30, 2009, we have under contract approximately 73 percent of our projected load
requirements, with approximately 96 percent at fixed prices. Remaining customer load
requirements are met with market purchases. Specifically, we have a seven year power
purchase agreement with PPL Montana for 325 MWs of on-peak supply and 175 MWs of off-peak
supply through June 2010 and decreasing volumes thereafter through June 2014. Our jointly
owned interest in Colstrip Unit 4 supplies 90 MWs of unit-contingent, base-load energy for
a term of 11.5 years, which commenced on July 1, 2007, to meet a portion of our electric
supply requirements and, in a separate agreement 21 MWs of unit contingent power for 76
months beginning March 2008. We also purchase power under several QF contracts entered into
under the Public Utility Regulatory Policies Act of 1978, which provide a total of 101 MWs
of capacity. We have several other long and medium-term power purchase agreements including
contracts for 135 MWs of wind generation and 5 MWs of seasonal base-load hydro supply. In
December 2007, we filed a biennial Electric Default Supply Resource Procurement Plan with
the MPSC which will guide future resource acquisition activities.
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.
FERC Regulation
We are subject to the jurisdiction of, and regulation by, the FERC with
respect to rates for electric transmission service in interstate commerce and electricity
sold at wholesale rates, the issuance of securities, incurrence of certain long-term debt,
and compliance with mandatory reliability regulations.
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. 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 and other wholesale transmission customers such as cooperatives. In 2007, FERC
issued Order No. 890,
Preventing Undue Discrimination and
Preference in Transmission Service
(Order 890). FERC Order 890
contained many changes to the OATT, and a number of items which all FERC jurisdictional
entities, including us, were to comply with under various time frames defined by Order 890.
We met or have approved mitigation plans for each of the compliance tasks by the dates
specified by FERC. In 2008, FERC expects the North American Electric Reliability
Corporation (NERC) and the North American Energy Standards Board to further define and
develop business practices and changes to the Open Access Same-time Information System
(OASIS), which will allow for further transparency and nondiscriminatory use of the
transmission system. We intend to participate in the processes under which these standards
and business practices are developed, and will ultimately be subject to them once they are
complete.
The Area Control Error Diversity Interchange (ADI) between the Idaho Power
Company, PacifiCorp and our control areas was implemented during the first quarter of 2007.
The ADI effort is expected to improve our ability to satisfy NERC required reliability
criteria. Other entities in the Northwest and Southwest regions of the WECC may be joining
this effort in the second quarter of 2008.
Under an agreement beginning in 2005, Idaho Power Company (Idaho Power) sold
regulating reserve service to us, which in turn we used to provide service under Schedule 3
(Regulation and Frequency Response) to our customers under our OATT. Idaho Power terminated
the agreement as of December 31, 2007. Upon completion of a competitive RFP process, we
entered into one-year agreements with Avista Utilities and Powerex to replace the Idaho
Agreement, which will allow us to
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balance
loads and resources within our balancing authority area on a moment-to-moment basis and to
provide Schedule 3 service under our Montana OATT. Both agreements have been approved by
the FERC. We are in the process of conducting an RFP for services beyond 2008. Our tariffs
allow for pass-through of ancillary costs, including the regulating reserve described
above.
In October 2006, we submitted a filing with FERC requesting an increase in
transmission rates in Montana under our OATT. While the request is due to an increase 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 electric supply loads, which represents
approximately 70% of this increase, is subject to MPSC jurisdictional rates.
We 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 were implemented, subject to refund. The FERC also set the proposed
revisions for hearing and settlement judgment procedures. We filed settlement documents on
February 15, 2008 and are awaiting FERC approval, which is expected during the first half
of 2008.
MPSC Regulation
Our Montana operations are subject to the jurisdiction of the MPSC with
respect to rates, terms and conditions of service, accounting records, electric service
territorial issues and other aspects of our operations, including when we issue, assume, or
guarantee securities in Montana, or when we create liens on our regulated Montana
properties.
In July 2007, we filed a request with the MPSC for an electric transmission
and distribution revenue increase of $31.4 million. In December 2007, we and the MCC filed
a joint Stipulation and Agreement (Stipulation) regarding the rate filing. Specific terms
of the Stipulation include:
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An increase in base electric rates of $10
million;
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Interim rates effective January 1, 2008;
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Capital investment in our electric and natural gas system
totaling $38.8 million to be completed in 2008 and 2009 on which we will
not earn a return on, but will recover depreciation expense;
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A commitment of 21 MWs of unit contingent power from
Colstrip Unit 4 at Mid-C minus $19 per MWH to electric supply for a period
of 76 months beginning March 1, 2008; and
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We will submit a general electric and natural gas rate
filing no later than July 31, 2009 based on a 2008 test year.
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The MPSC
has approved interim rates, subject to refund, beginning January 1, 2008, and we anticipate
finalizing the rate case during the second quarter of 2008.
Montana's Electric Utility Industry Restructuring and Customer Choice Act
was passed in 1997, which provided for deregulation and allowed for customer choice and
competition among suppliers. During 2007, the Montana legislature passed House Bill 25 (HB
25), labeled
The Generation Reintegration
Act
, which became effective October 1, 2007. This bill largely
removes the remaining remnants of deregulation from Montana Law that began in 1997 by
eliminating customer choice for all customers except for the largest industrial customers
using more than five MWs, and providing utilities with the ability to build and own
electric generation assets that would be included in utility cost of service. In addition,
the bill provides for a timely upfront approval process for electricity supply resource
projects and requires carbon offsets to reduce carbon dioxide emissions.
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 60,100 customers in 110 communities in South Dakota. In 2007, by category,
residential, commercial and industrial, wholesale, and other sales accounted for
approximately 38%, 53%, 5% and 4% of our South Dakota electric utility revenue,
respectively. Currently, we serve these customers principally from generation capacity
obtained through our joint ownership interests in three base-load generation plants and
other peaking facilities that provide us with 312 MWs of demonstrated capacity. In
addition, we have contracted capacity with MidAmerican Energy Company (MidAmerican) for an
additional 50 MWs. Peak demand was
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approximately 317 MWs, the average daily load was approximately 154 MWs, and
more than 1.35 million MWHs were supplied during the year ended December 31, 2007. We
use market purchases and internal peaking generation to provide peak supply in excess of
our base-load capacity.
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 with demand in excess of two MWs. 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.
Electric 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.
We are not the operator of any of these plants. 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. During periods of lower demand, electricity in excess of our load
requirements are sold in the competitive wholesale market. In 2007, this was approximately
10% of the power generated.
Name
and
Location
of
Plant
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Fuel
Source
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Our
Ownership
Interest
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Our
Share
of
2007
Peak
Summer
Demonstrated
Capacity (MW)
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%
of
Total
2007
Peak
Summer
Demonstrated
Capacity
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Big Stone Plant, located near Big Stone City in
northeastern South Dakota
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Sub-bituminous coal
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23.4
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%
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108.95
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34.8
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%
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Coyote I Electric Generating Station, located near Beulah,
North Dakota
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Lignite coal
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10.0
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%
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42.70
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13.7
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%
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Neal Electric Generating Unit No. 4, located near Sioux
City, Iowa
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Sub-bituminous coal
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8.7
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%
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56.30
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18.0
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%
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Miscellaneous combustion turbine units and small
diesel units (used only during peak periods)
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Combination of fuel oil and natural gas
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100.0
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%
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104.73
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33.5
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%
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Total Capacity
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312.68
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100.0
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%
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MidAmerican provided 50 MWs of firm capacity during the summer months of
2007 and we have an agreement with them to supply firm capacity of 53 MWs and 56 MWs during
the summer months of 2008 and 2009, respectively. MidAmerican has provided us notification
that they will not extend the agreement beyond 2009 and we are currently analyzing other
firm capacity resources to replace this contract. We are a member of the MAPP, which is an
area power pool arrangement consisting of utilities and power suppliers having transmission
interconnections located in a nine-state area in the North Central region of the United
States and in two Canadian provinces. The terms and conditions of the MAPP agreement and
transactions between MAPP members are subject to the jurisdiction of the FERC.
We have a resource plan that includes estimates of customer usage and
programs to provide for economic, reliable and timely supply of energy. We continue to
update our load forecast to identify the future electric energy needs of our customers, and
we evaluate additional generating capacity requirements on an ongoing basis. 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 through at least 2013. We are undergoing an evaluation of our needs
for base-load supply beyond that point based on our current load forecast.
Coal was used to generate approximately 99% of the electricity utilized for
South Dakota operations for the year ended December 31, 2007. 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:
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Cost
per
Million
Btu
for
the
Year
Ended
December
31,
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Percent
of
2007
MW
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Fuel
Type
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2007
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2006
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2005
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Hours
Generated
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Sub-bituminous-Big Stone
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$
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1.55
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$
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1.49
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$
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1.43
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45.57
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%
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Lignite-Coyote
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1.06
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0.96
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0.85
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21.47
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Sub-bituminous-Neal
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1.15
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1.10
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0.90
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32.53
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Natural Gas
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7.41
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7.17
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8.49
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0.22
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Oil
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13.11
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15.38
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7.52
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0.21
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During the year ended December 31, 2007, the average delivered cost per
ton of fuel burned for our base-load plants was $25.49 at Big Stone I, $14.70 at Coyote and
$16.39 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 2010. 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 2007, 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
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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 2007, our
costs for services under this contract totaled approximately $5.1 million. Our tariffs
in South Dakota generally allow us to pass through these transmission costs to our
customers.
FERC Regulation
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 and power marketing activities. 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.
SDPUC Regulation
Our South
Dakota operations are subject to SDPUC jurisdiction with respect to rates, terms and
conditions of service, accounting records, electric service territorial issues and other
aspects of our operations. Our retail electric rates, approved by the SDPUC, provide
several options for residential, commercial and industrial customers, including dual-fuel,
interruptible, special all-electric heating, and other special rates, as well as various
incentive riders to encourage business development. 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.
REGULATED NATURAL GAS OPERATIONS
MONTANA
We distribute natural gas to approximately 177,000 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 3,900 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 billion dekatherms, and our peak capacity was approximately
335 million dekatherms per day during the year ended December 31,
2007.
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 195 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
47 million dekatherms of remaining reserves as of December 31, 2007.
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, 17 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.
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Natural Gas Supply
Under an agreement with the MPSC, we supply natural gas 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,
2007, were approximately 19.2 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 electric supply needs and reliability requirements and the
implementation of hedging strategies to reduce price volatility. The next Gas Plan will be
filed in December 2008.
FERC Regulation
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.
MPSC Regulation
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.
In July 2007, we filed a request with the MPSC for a natural gas
transmission, storage and distribution revenue increase of $10.5 million. In December 2007,
we and the MCC filed a joint Stipulation regarding the rate filing. The specific terms of
the Stipulation include an increase in base natural gas rates of $5 million. The remaining
terms of the Stipulation are discussed above in the MPSC regulation section related to our
Montana electric operations.
SOUTH DAKOTA AND NEBRASKA
We provide natural gas to approximately 84,500 customers in 60 South Dakota
communities and four Nebraska communities. We have approximately 2,200 miles of
distribution gas mains in South Dakota and Nebraska. In South Dakota, we also transport
natural gas for five gas-marketing firms and two large end-user accounts, currently serving
85 customers through our distribution systems. In Nebraska, we transport natural gas for
three gas-marketing firms and one end-user account, servicing eight customers through our
distribution system. We delivered approximately 15.2 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 2007.
We have nonexclusive municipal franchises to purchase, transport and
distribute natural gas in the South Dakota and Nebraska communities we serve. The maximum
term permitted under Nebraska law for these franchises is 25 years while
the
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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, 30 of our South Dakota
and Nebraska municipal franchises, which account for approximately 53,300 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, 2007, were approximately 5.2 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, 2007, were approximately 5.2 million dekatherms. Our Nebraska
natural gas supply, storage and pipeline requirements are fulfilled primarily through a
third-party contract with ONEOK Energy Services Co.
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.
FERC Regulation
Our natural gas transportation pipelines are generally not subject to the
jurisdiction of the FERC, although we are subject to state regulation. We have capacity
agreements with interstate pipelines that are subject to FERC jurisdiction.
SDPUC Regulation
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. 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.
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.
In June 2007, we filed a request with the SDPUC for a natural gas
distribution revenue increase of $3.7 million. In December 2007, the SDPUC approved our
settlement with SDPUC Staff related to our natural gas rate case, granting an annual
revenue increase of approximately $3.1 million.
15
NPSC Regulation
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.
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.
In June 2007, we filed a request with the NPSC for a natural gas
distribution revenue increase of $2.8 million. We and the cities chose the process
described above whereby we can negotiate the settlement directly with the cities regarding
the outcome of the rate case. In November, a settlement was reached between us and the
cities resulting in an annual revenue increase of approximately $1.5 million. The NPSC
issued an order in December approving the settlement.
UNREGULATED ELECTRIC OPERATIONS
We have a 30% interest in Colstrip Unit 4, a 740 MW demonstrated-capacity
coal-fired power plant located in southeastern Montana. Our interest represents
approximately 222 MWs at full load, and was historically a leased interest; however, during
2007 we purchased our leased interest for approximately $145.2 million, plus the assumption
of $53.7 million of debt.
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 MWs to Puget and 111 MWs to
DB plus losses. We have a separate agreement with DB to repurchase 111 MWs through December
2010, which has been committed to supply a portion of the Montana electric supply
load.
We currently have approximately 111 MWs 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. In January 2008, we retained a financial advisor to assist us in
evaluating our strategic options with respect to our interest in Colstrip Unit
4.
A long-term coal supply contract with Western Energy Company provides the
coal necessary to run the Colstrip facility.
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.
16
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 $19.8 million to $57.0 million. As of December 31, 2007, we have a
reserve of approximately $32.7 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.
Coal-Fired Plants
We have a jointly owned interest in Colstrip Unit 4, a coal-fired power
plant located in southeastern Montana. In addition, we are joint owners in three coal-fired
plants used to serve our South Dakota customer supply demands. Citing its authority under
the Clean Air Act, the EPA had finalized Clean Air Mercury Regulations (CAMR) that affect
coal-fired plants. These regulations established 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. In February 2008 the
EPA’s mercury regulations were turned down by the U.S. Court of Appeals for the
District of Columbia Circuit; however, Montana has finalized its own rules more stringent
than CAMR’s 2018 cap that would require every coal-fired generating plant in the
state to achieve reduction levels by 2010. If the Montana rules are maintained in their
current form and enhanced chemical injection technologies are not sufficiently developed to
meet these Montana levels of reduction by 2010, then adsorption/absorption technology with
fabric filters at the Colstrip Unit 4 generation facility would be required, which could
represent a material cost. Recent tests have shown that it may be possible to meet the
Montana rules 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 rules.
In addition to the requirements related to emissions noted above, there is a
growing concern nationally and internationally about global climate change and the
contribution of emissions of greenhouse gases including, most significantly, carbon
dioxide. This concern has led to increased interest in legislation at the federal level,
actions at the state level, as well as litigation relating to greenhouse emissions,
including a recent US Supreme Court decision holding that the EPA has the authority to
regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. Increased
pressure for carbon dioxide emissions reduction also is coming from investor organizations.
If legislation or regulations are passed at the federal or state levels imposing mandatory
reductions of carbon dioxide and other greenhouse gases on generation facilities, the cost
to us of such reductions could be significant.
Manufactured Gas Plants
Approximately $26.1 million of our environmental reserve accrual is related
to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen,
South Dakota, has been identified on the Federal Comprehensive Environmental Response,
Compensation, and Liability Information System (CERCLIS) list as contaminated with coal tar
residue. We are currently investigating, characterizing, and initiating remedial actions at
the Aberdeen site pursuant to work plans approved by the South Dakota Department of
Environment and Natural Resources. In 2007, we completed remediation of sediment in a short
segment of Moccasin Creek that had been impacted by the former manufactured gas plant
operations. Our current reserve for remediation costs at this site is approximately $12.4
million, and we estimate that approximately $10 million of this amount will be incurred
during the next five years.
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
17
Grand
Island, respectively. We have initiated additional site investigation and assessment work
at these locations. At present, we cannot determine with a reasonable degree of certainty
the nature and timing of any risk-based remedial action 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 exceedences of regulated pollutants in the
groundwater. We have conducted additional groundwater monitoring at the Butte and Missoula
sites and, at this time, we believe natural attenuation should address the problems at
these sites; however, additional groundwater monitoring will be necessary. In Helena, we
continue limited operation of an oxygen delivery system implemented to enhance natural
biodegradation of pollutants in the groundwater and we are currently evaluating limited
source area treatment/removal options. 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 risk-based remedial action at the Helena
site.
Based upon our investigations to date, our current environmental liability
reserves, applicable insurance coverage, and the potential to recover 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 MW 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.
On July 18, 2005, we and CFB 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. Dam removal activities will be initiated in January of
2008.
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, and the sale or transfer of land and water rights associated with the
Milltown Dam operations.
Other
We continue to manage equipment containing polychlorinated biphenyl (PCB)
oil in accordance with the EPA's Toxic Substance Control Act regulations. 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 assist in performing a comprehensive evaluation of our environmental reserve. Based
upon information available 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
18
portion of
our environmental reserve applicable to site remediation may be subject to change as a
result of the following uncertainties:
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•
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We may not know all sites for which we are alleged or will
be found to be responsible for remediation; and
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•
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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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19
EMPLOYEES
As of December 31, 2007, we had 1,351 employees. Of these, 1,037
employees were in Montana and 314 were in South Dakota or Nebraska. Of our Montana
employees, 413 were covered by six collective bargaining agreements involving five unions.
Five of these agreements expire in 2008. In addition, our South Dakota and Nebraska
operations had 192 employees covered by the System Council U-26 of the International
Brotherhood of Electrical Workers. This collective bargaining agreement expires in 2009. We
consider our relations with employees to be in good standing.
Executive Officers
Executive Officer
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Current Title and Prior Employment
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Age on
Feb.
26,
2008
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Michael J. Hanson
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President and Chief Executive Officer since May 20, 2005;
formerly President since March 2005; Chief Operating Officer since August
2003; formerly President and Chief Executive Officer of NorthWestern's
utility operations (1998-2003). Prior to joining NorthWestern,
Mr. Hanson was General Manager and Chief Executive of Northern States
Power Company of South Dakota and North Dakota in Sioux Falls, S.D.
(1994-1998). Mr. Hanson serves on the board of directors of a
NorthWestern subsidiary.
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49
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Brian B. Bird
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Vice President and Chief Financial Officer since December
2003. Prior to joining NorthWestern, Mr. Bird was Chief Financial
Officer and Principal of Insight Energy, Inc., a Chicago-based independent
power generation development company (2002-2003). Previously, he was Vice
President and Treasurer of NRG Energy, Inc., in Minneapolis, MN
(1997-2002). Mr. Bird serves on the board of directors of a
NorthWestern subsidiary.
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45
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Patrick R. Corcoran
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Vice President-Government and Regulatory Affairs since
December 2004; formerly Vice President-Regulatory Affairs for the Company
and the former Montana Power Company since September 2000.
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56
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David G. Gates
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Vice President-Wholesale Operations since September 2005;
formerly Vice President-Transmission Operations since May 2003; formerly
Executive Director-Distribution Operations since January 2003; formerly
Executive Director-Distribution Operations for the former Montana Power
Company (1996-2002). Mr. Gates serves on the board of directors of a
NorthWestern subsidiary.
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51
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Kendall G. Kliewer
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Vice President and Controller since August 2006; Controller
since June 2004; formerly Chief Accountant since November 2002. Prior to
joining NorthWestern, Mr. Kliewer was a Senior Manager at KPMG LLP
(1999-2002).
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38
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Thomas J. Knapp
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Vice President, General Counsel and Corporate Secretary
since November 2004; formerly Vice President and Deputy General Counsel
since March 2003; formerly consultant to NorthWestern since May 2002. Prior
to joining NorthWestern, Mr. Knapp was Of Counsel at Paul, Hastings,
Janofsky &Walker (2000-2002). Mr. Knapp serves on the boards of
directors of two NorthWestern subsidiaries.
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55
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Curtis T. Pohl
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Vice President-Retail Operations since September 2005;
formerly Vice President-Distribution Operations since August 2003; formerly
Vice President-South Dakota/Nebraska Operations since June 2002; formerly
Vice President-Engineering and Construction since June 1999. Mr. Pohl
serves on the board of directors of a NorthWestern subsidiary.
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43
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Bobbi L. Schroeppel
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Vice President-Customer Care and Communications since
September 2005; formerly Vice President-Customer Care since June 2002;
formerly Director-Staff Activities and Corporate Strategy since August
2001; formerly Director-Corporate Strategy since June 2000.
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39
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Gregory G. A. Trandem
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Vice President-Administrative Services since September 2005;
formerly Vice President-Support Services since March 2004; formerly Vice
President-Asset Management since June 2002; formerly Vice President-Energy
Operations since August 1999.
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56
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Officers are elected annually by, and hold office at the pleasure of the
Board and do not serve a “term of office” as such.
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.
We
have incurred, and may continue to incur, significant costs associated with outstanding
litigation, 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 21
to the Consolidated Financial Statements. An adverse result in any of these matters could
have an adverse effect on our business.
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.
We are
subject to extensive governmental laws and regulations that affect our industry and our
operations, which could have a material adverse effect on our results of operations and
financial condition.
We are subject to regulation by federal and state governmental entities,
including the FERC, MPSC, SDPUC and NPSC. Regulations can affect allowed rates of return,
recovery of costs and operating requirements. In addition, existing regulations may be
revised or reinterpreted, new laws, regulations, and interpretations thereof may be adopted
or become applicable to us
21
and future
changes in laws and regulations may have a detrimental effect on our business.
Our rates are approved by our respective commissions and are effective until
new rates are approved. In addition, supply costs are recovered through adjustment charges
that are periodically reset to reflect current and projected costs. Inability to recover
costs in rates or adjustment clauses could have a material adverse effect on our results of
operations, cash flows and financial position.
We are
subject to extensive environmental laws and regulations and potential environmental
liabilities, which could result in significant costs and liabilities.
We are subject to extensive laws and regulations imposed by federal, state
and local government authorities in the ordinary course of operations with regard to the
environment, including environmental laws and regulations relating to air and water
quality, 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.
In addition to the requirements related to the mercury emissions rules noted
above, there is a growing concern nationally and internationally about global climate
change and the contribution of emissions of greenhouse gases including, most significantly,
carbon dioxide. This concern has led to increased interest in legislation at the federal
level, actions at the state level, as well as litigation relating to greenhouse emissions,
including a recent US Supreme Court decision holding that the EPA has the authority to
regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. Increased
pressure for carbon dioxide emissions reduction also is coming from investor organizations.
If legislation or regulations are passed at the federal or state levels imposing mandatory
reductions of carbon dioxide and other greenhouse gases on generation facilities, the cost
to us of such reductions could be significant.
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.
Our range of exposure for current environmental remediation obligations is
estimated to be $19.8 million to $57.0 million. We had an environmental reserve of $32.7
million at December 31, 2007. 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.
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 applicable state regulatory commissions, we would under
recover our costs, which could adversely impact our results of operations.
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
22
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 electric supply
could expose us to material commodity price risk if certain QFs under contract with us do
not perform during a time of high commodity prices, as we are required to 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 electric supply with a certain minimum amount
of power at an agreed upon price per MW. 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.
Our
jointly owned regulated electric generating facilities and our joint ownership 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 for our regulated generation,
making us vulnerable to increased prices for fuel as existing contracts expire or in the
event of unanticipated interruptions in fuel supply. We are a captive rail shipper of the
Burlington Northern Santa Fe Railway for shipments of coal to the Big Stone 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 regulated generating facility would
require us to find other sources of supply, if available, and expose us to higher purchased
power costs.
We must
meet certain credit quality standards. If we are unable to maintain an investment grade
credit rating, we would be required under certain commodity purchase agreements to provide
collateral in the form of letters of credit or cash, which may materially adversely affect
our liquidity and /or access to 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.
23
ITEM
1B.
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UNRESOLVED STAFF COMMENTS
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None
NorthWestern's executive offices are located at 3010 West 69
th
Street, Sioux Falls, South Dakota 57108, where we lease approximately 20,000 square feet of
office space, pursuant to a lease that expires on December 1, 2012.
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 facilities throughout the state of Montana.
For further information regarding our operating properties, including
generation and transmission, see the descriptions included in Item 1.
ITEM
3.
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LEGAL PROCEEDINGS
|
We discuss details of our legal proceedings in Note 21, 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.
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SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS
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No matters were submitted to a vote of our security holders during the
quarter ended December 31, 2007.
24
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
(1)
|
Nature of Operations and Basis of
Consolidation
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NorthWestern Corporation, doing business as NorthWestern Energy, provides
electricity and natural gas to approximately 650,000 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 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 intercompany balances and transactions
have been eliminated from the consolidated financial statements.
(2)
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Termination of Merger Agreement 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 would acquire NorthWestern Corporation in an all-cash transaction
at $37 per share. We had received all approvals necessary for the transaction, except from
the Montana Public Service Commission (MPSC). On May 22, 2007, the MPSC unanimously
directed its staff to draft an order denying the transaction. On June 25, 2007, we and BBI
filed a formal joint request asking the MPSC to consider a revised proposal. In connection
with our joint request to the MPSC, we and BBI agreed that if the MPSC denied the revised
application, then either party in their sole discretion could terminate the Merger
Agreement. On July 24, 2007, the MPSC denied the joint request and BBI terminated the
Merger Agreement. The MPSC issued a final written order on July 31, 2007.
We incurred and expensed transaction related costs of approximately $1.5
million, and $13.9 million during the years ended December 31, 2007, and December 31, 2006,
respectively.
(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, asset retirement obligations, uncollectible accounts, our QF
obligation, 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.
Fresh-Start Reporting
In accordance with Statement of Position 90-7,
Financial Reporting by Entities in Reorganization under the Bankruptcy
Code,
or SOP 90-7, certain companies qualify for fresh start
reporting in connection with their emergence from bankruptcy. 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 is deemed to be created and the
recorded amounts of assets and liabilities are adjusted to reflect their estimated fair
values, which impacts the comparability of financial statements. We met these requirements
and adopted fresh-start reporting upon the our emergence from bankruptcy on November 1,
2004.
F -
8
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 allowances for uncollectible accounts of $3.2
million and $3.2 million at December 31, 2007 and December 31, 2006,
respectively. Receivables include unbilled revenues of $76.0 million and $68.9 million at
December 31, 2007 and December 31, 2006, respectively.
Inventories
Inventories are stated at average cost. Inventory consisted of the following
(in thousands):
|
|
December 31, 2007
|
|
December
31,
2006
|
|
Materials and supplies
|
|
$
|
17,670
|
|
$
|
17,599
|
|
Storage gas
|
|
45,916
|
|
42,944
|
|
|
|
$
|
63,586
|
|
$
|
60,543
|
|
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.
F -
9
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 9. 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:
|
•
|
Forward contracts, which commit us to purchase or sell
energy commodities in the future,
|
|
•
|
Option contracts, which convey the right to buy or sell a
commodity at a predetermined price, and
|
|
•
|
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.
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
8.7%, 8.8%, and 8.7% for Montana for 2007, 2006, and 2005, respectively, and 8.7%, 8.9%,
and 8.7% for South Dakota for 2007, 2006, and 2005, respectively. Interest capitalized
totaled $0.8 million for the year ended December 31, 2007, $1.0 million for the year ended
December 31, 2006, and $1.3 million for the year ended December 31, 2005, for
Montana and South Dakota combined.
F -
10
We may require contributions in aid of construction from customers when we
extend service. Amounts used from these contributions to fund capital additions were $14.6
million for the year ended December 31, 2007 and $8.7 million for the year ended
December 31, 2006.
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 3.5%, 3.4%, and
3.4% for 2007, 2006, and 2005, 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):
|
|
December 31, 2007
|
|
December
31,
2006
|
|
Pension and other employee benefits
|
|
$
|
56,521
|
|
$
|
105,477
|
|
Future QF obligation, net
|
|
158,132
|
|
147,893
|
|
Environmental
|
|
32,728
|
|
34,148
|
|
Customer advances
|
|
45,194
|
|
33,502
|
|
Other
|
|
15,575
|
|
18,328
|
|
|
|
$
|
308,150
|
|
$
|
339,348
|
|
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 17. We account for these awards using SFAS
No. 123R,
Share-Based Payment
(SFAS
No. 123R), which requires companies to recognize compensation expense for all equity-based
compensation awards issued to employees that are expected to vest. Under SFAS No. 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 associated 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 $5.6 million at
December 31, 2007 and $7.2 million at December 31, 2006.
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 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.
F -
11
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 other income and cash received is reflected as an investing activity.
Accounting Standards Issued
In December 2007, the Financial Accounting Standards Board (FASB) issued
SFAS No. 141 (revised 2007),
Business
Combinations
(SFAS No. 141R), which replaces FASB Statement
No. 141. SFAS 141R establishes principles and requirements for how an acquirer
recognizes and measures in its financial statements the identifiable assets acquired, the
liabilities assumed, any non controlling interest in the acquiree and the goodwill
acquired. The Statement also establishes disclosure requirements, which will enable users
to evaluate the nature and financial effects of the business combination. SFAS
No. 141R applies prospectively to business combinations for which the acquisition date
is on or after the beginning of the first annual reporting period beginning on or after
December 15, 2008, and interim periods within those fiscal years. SFAS No. 141R
will become effective for our fiscal year beginning January 1, 2009; accordingly, any
business combinations we engage in after this date will be recorded and disclosed in
accordance with this statement. Based on our preliminary evaluation of SFAS No. 141R, if
any of our unrecognized tax benefits reverse after adoption, they will affect the income
tax provision in the period of reversal rather than goodwill. See Note 13, Income Taxes,
for further information.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statement—amendments of ARB No.
51
(SFAS No. 160). SFAS No. 160 states that
accounting and reporting for minority interests will be recharacterized as noncontrolling
interests and eliminates diversity in practice by requiring these interests to be
classified as a component of equity. The Statement also establishes reporting
requirements that provide sufficient disclosures that clearly identify and distinguish
between the interests of the parent and the interests of the noncontrolling owners. SFAS
No. 160 applies to all entities that prepare consolidated financial statements, except
not-for-profit organizations, but will affect only those entities that have an outstanding
noncontrolling interest in one or more subsidiaries or that deconsolidate a
subsidiary. This statement will become effective for our fiscal year beginning
January 1, 2009, and early adoption is prohibited. We do not expect SFAS No. 160 to
have any effect on our financial statements.
In February 2007, the FASB issued SFAS No. 159,
The
Fair Value Option for Financial Assets and Financial Liabilities-including an amendment of
FASB Statement No. 115
(SFAS No. 159), which permits entities to
choose to measure many financial instruments and certain other items at fair value that are
not currently required to be measured at fair value, with unrealized gains and losses
related to these financial instruments reported in earnings at each subsequent reporting
date. This option would be applied on an instrument by instrument basis. If elected,
unrealized gains and losses on the affected financial instruments would be recognized in
earnings at each subsequent reporting date. This Statement is effective as of the beginning
of our 2008 fiscal year. We do not expect to apply this fair value option to our current
financial instruments, and as such do not expect SFAS No. 159 to have a material impact on
our financial statements.
F -
12
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 do not expect SFAS No. 157 to have a material
impact on our financial statements.
Accounting Standards Adopted
In July 2006, the FASB issued 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
(SFAS No. 109), 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. We adopted FIN 48 as of January 1, 2007. See
Note 13, Income Taxes for further discussion of the impact to our financial
statements.
Supplemental Cash Flow Information
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
Cash paid (received) for
|
|
|
|
|
|
|
|
Income taxes
|
|
$
|
3,921
|
|
$
|
252
|
|
$
|
(308
|
)
|
Interest
|
|
43,076
|
|
39,267
|
|
51,131
|
|
Reorganization professional fees and expenses
|
|
—
|
|
—
|
|
7,576
|
|
Significant non-cash transactions:
|
|
|
|
|
|
|
|
Assumption of debt related to Colstrip Unit 4
Acquisitions
|
|
53,685
|
|
—
|
|
—
|
|
Additions to property, plant and equipment and capital lease
obligations
|
|
2,400
|
|
40,210
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
(4)
|
Colstrip Unit 4 Acquisition
|
During 2007, we completed the purchase of the Owner Participant interest of
our 222 MW leased interest in the 740 MW coal-fired steam electric generation unit
known as Colstrip Unit 4. The purchase price was approximately $141.3 million, which
includes applicable closing costs, plus the assumption of $53.7 million in debt. The
transaction does not result in any change in control over, or operation of, Colstrip Unit
4.
In December 2007, we formed a new subsidiary, Colstrip Lease Holdings LLC
(CLH) to hold a portion of our acquired interest in Colstrip Unit 4. CLH closed on a $100
million loan on December 28, 2007, which is secured by its interest (approximately 143 MW)
in Colstrip Unit 4 and is nonrecourse to NorthWestern Corporation.
F -
13
(5)
|
Property, Plant and Equipment
|
The following table presents the major classifications of our property,
plant and equipment (in thousands):
|
|
Estimated Useful Life
|
|
December 31,
|
|
December
31,
|
|
|
|
|
2007
|
|
2006
|
|
|
|
(years)
|
|
(in thousands)
|
|
Land and improvements
|
|
26 - 63
|
|
$
|
41,286
|
|
$
|
39,805
|
|
Building and improvements
|
|
24 - 70
|
|
94,386
|
|
91,665
|
|
Storage, distribution, and transmission
|
|
13 - 87
|
|
1,908,688
|
|
1,835,984
|
|
Generation
|
|
12 - 35
|
|
430,216
|
|
200,662
|
|
Construction work in process
|
|
—
|
|
19,524
|
|
3,496
|
|
Other equipment
|
|
2 - 93
|
|
203,534
|
|
195,735
|
|
|
|
|
|
2,697,634
|
|
2,367,347
|
|
Less accumulated depreciation
|
|
|
|
(926,754
|
)
|
(875,492
|
)
|
|
|
|
|
$
|
1,770,880
|
|
$
|
1,491,855
|
|
As discussed in Note 4, we completed the purchase of our interest in
Colstrip Unit 4 during 2007, which increased our generation property, plant and equipment
by approximately $218.2 million.
Plant and equipment under capital lease were $42.3 million and $44.8 million
as of December 31, 2007 and December 31, 2006, respectively, which included $37.2
million and $39.8 million as of December 31, 2007 and 2006, respectively, related to a
long-term power supply contract with the owners of a natural gas fired peaking plant, which
has been accounted for as a capital lease.
(6)
|
Variable Interest Entities
|
FASB Interpretation No. 46 (revised December 2003),
Consolidation of Variable Interest Entities
, or
FIN 46R, requires the consolidation of entities which are determined to be variable
interest entities (VIEs) when we are the primary beneficiary of a VIE, which means we have
a controlling financial interest. 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, while we have made exhaustive
efforts, we have been unable to obtain the information necessary to further analyze this
contract under the requirements of FIN 46R. We continue to account for this qualifying
facility contract as an executory contract as we have been unable 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. Based on the current contract terms with this
qualifying facility, our estimated gross contractual payments aggregate approximately
$519.4 million through 2025, and are included in Contractual Obligations and Other
Commitments of Management's Discussion and Analysis. During the years ended December 31,
2007, 2006 and 2005 purchases from this QF were approximately $21.1 million, $23.5 million,
and $25.6 million, respectively.
(7)
|
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
.
These amounts do not represent SFAS No. 143,
Accounting for Asset Retirement Obligations
,
legal retirement obligations. As of
F -
14
December
31, 2007 and December 31, 2006, we have recognized accrued removal costs of $165.4
million and $153.4 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 $13.8 million and $13.3 million as of December 31, 2007 and
December 31, 2006, 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 $3.9
million and $3.5 million, as of December 31, 2007 and December 31, 2006, 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, 2007,
is as follows (in thousands):
Liability at January 1, 2007
|
$
|
3,801
|
|
Accretion expense
|
|
294
|
|
Liabilities incurred
|
|
61
|
|
Liabilities settled
|
|
(43
|
)
|
Revisions to cash flows
|
|
340
|
|
Liability at December 31, 2007
|
$
|
4,453
|
|
Our goodwill balance is related to our adoption of fresh-start reporting
upon emergence from Chapter 11 bankruptcy on October 31, 2004. 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.
As a result of the implementation of FIN 48, we increased our deferred tax
assets by $77.5 million and decreased other noncurrent liabilities by $2.4 million, with a
corresponding decrease to goodwill. The decrease to goodwill is consistent with the
guidance in SFAS No. 109 and the requirements of fresh-start reporting, as our uncertain
tax positions relate to periods prior to our emergence from bankruptcy.
Goodwill by segment is as follows for December 31, 2007 and 2006 (in
thousands):
|
|
December 31, 2007
|
|
|
December 31, 2006
|
|
Regulated electric
|
$
|
241,100
|
|
$
|
295,377
|
|
Regulated natural gas
|
|
114,028
|
|
|
139,699
|
|
Unregulated electric
|
|
—
|
|
|
—
|
|
|
$
|
355,128
|
|
$
|
435,076
|
|
Goodwill is not amortized; rather, it is evaluated for impairment at least
annually. We evaluated our goodwill during the fourth quarters of 2007 and 2006 and
determined that it was not impaired.
(9)
|
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.
F -
15
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 (AOCI) in
our Consolidated Balance Sheets.
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.
During the second and third quarters of 2006, we issued $170.2 million of
Montana Pollution Control Obligations and $150 million of Montana First Mortgage Bonds. In
association with these refinancing transactions, 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. AOCI includes
unrealized pre-tax gains related to these transactions of $12.8 million and $14.0 million
at December 31, 2007 and December 31, 2006, respectively. We reclassify gains and losses on
the hedges from AOCI into interest expense in our Consolidated Statements of Income during
the periods in which the interest payments being hedged occur. We expect to reclassify
approximately $1.2 million of pre-tax gains on these cash-flow hedges from AOCI into
interest expense during the next twelve months. The cash proceeds related to these hedges
are reflected in operating activities on the statement of cash flows. We have no further
interest rate swaps outstanding.
(10)
|
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.
Netexit and its subsidiaries filed for bankruptcy protection in 2004, and
Netexit's amended and restated liquidating plan of reorganization was confirmed by the
Bankruptcy Court in 2005. The liquidation of Netexit was completed during the second
quarter of 2006, and total distributions to NorthWestern were $7.7 million in 2006, and
$42.2 million in 2005.
Summary financial information for the discontinued Netexit operations is as
follows (in thousands):
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
2005
|
|
Revenues
|
|
$
|
—
|
|
$
|
—
|
|
Income (Loss) before income taxes
|
|
$
|
418
|
|
$
|
(1,179
|
)
|
Gain (loss) on disposal
|
|
—
|
|
—
|
|
Income tax provision
|
|
—
|
|
—
|
|
Income (Loss) from discontinued operations, net of
income taxes
|
|
$
|
418
|
|
$
|
(1,179
|
)
|
During 2005, Blue Dot sold its final operating location. Summary financial
information for the discontinued Blue Dot operations is as follows (in
thousands):
|
|
Year Ended December 31, 2005
|
|
Revenues
|
|
$
|
3,177
|
|
Loss before income taxes
|
|
$
|
(901
|
)
|
Gain (loss) on disposal
|
|
—
|
|
Income tax provision
|
|
—
|
|
Income (Loss) from discontinued operations, net of
income taxes
|
|
$
|
(901
|
)
|
F -
16
(11)
|
Long-Term Debt and Capital Leases
|
Long-term debt and capital leases consisted of the following (in
thousands):
|
|
Due
|
|
December
31,
2007
|
|
December
31,
2006
|
|
Unsecured Debt:
|
|
|
|
|
|
|
|
Unsecured Revolving Line of Credit
|
|
2009
|
|
$
|
12,000
|
|
$
|
50,000
|
|
|
|
|
|
|
|
|
|
Secured Debt:
|
|
|
|
|
|
|
|
Mortgage bonds—
|
|
|
|
|
|
|
|
South Dakota—7.00%
|
|
2023
|
|
55,000
|
|
55,000
|
|
|
|
|
|
|
|
|
|
Montana—6.04%
|
|
2016
|
|
150,000
|
|
150,000
|
|
Montana—8.25%
|
|
2007
|
|
—
|
|
365
|
|
|
|
|
|
|
|
|
|
South Dakota & Montana—5.875%
|
|
2014
|
|
225,000
|
|
225,000
|
|
|
|
|
|
|
|
|
|
Pollution control obligations—
|
|
|
|
|
|
|
|
South Dakota—5.85%
|
|
2023
|
|
7,550
|
|
7,550
|
|
South Dakota—5.90%
|
|
2023
|
|
13,800
|
|
13,800
|
|
Montana—4.65%
|
|
2023
|
|
170,205
|
|
170,205
|
|
|
|
|
|
|
|
|
|
Montana Natural Gas Transition Bonds— 6.20%
|
|
2012
|
|
27,746
|
|
32,994
|
|
|
|
|
|
|
|
|
|
Other Long Term Debt:
|
|
|
|
|
|
|
|
Colstrip Unit 4 debt—13.25%
|
|
2010
|
|
44,891
|
|
—
|
|
Colstrip Lease Holdings, LLC—floating rate
|
|
2009
|
|
100,000
|
|
—
|
|
|
|
|
|
|
|
|
|
Discount on Notes and Bonds
|
|
—
|
|
(215
|
)
|
(259
|
)
|
|
|
|
|
805,977
|
|
704,655
|
|
Less current maturities
|
|
|
|
(18,617
|
)
|
(5,614
|
)
|
|
|
|
|
$
|
787,360
|
|
$
|
699,041
|
|
|
|
|
|
|
|
|
|
|
|
Capital Leases:
|
|
|
|
|
|
|
|
|
|
Total Capital Leases
|
|
Various
|
|
$
|
40,391
|
|
$
|
42,462
|
|
Less current maturities
|
|
|
|
|
(2,389
|
)
|
|
(2,079
|
)
|
|
|
|
|
$
|
38,002
|
|
$
|
40,383
|
|
Unsecured Revolving Line of Credit
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
6.2%, which is 1.125% over LIBOR. As of December 31, 2007, we had $29.3 million in
letters of credit and $12 million of borrowings outstanding under the unsecured revolving
line of credit. The weighted average interest rate on the outstanding revolver borrowings
was 4.5% as of December 31, 2007.
Commitment fees for the unsecured revolving line of credit were $0.3 million
and $0.3 million for the years ended December 31, 2007 and 2006, respectively.
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
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
F -
17
“investment grade" by two of the three major credit rating agencies
consisting of Fitch, Moody's and S&P. A default on the South Dakota or Montana first
mortgage bonds would trigger a cross default on the credit facility; however a default on
the credit facility would not trigger a default on any other obligations.
Secured
Debt
First Mortgage Bonds and Pollution Control
Obligations
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.
Other
Long-Term Debt
As discussed in Note 4, in association with the Colstrip Unit 4 transaction
our subsidiary, CLH, closed on a $100 million loan on December 28, 2007, which is secured
by its interest in Colstrip Unit 4 and is nonrecourse to NorthWestern Corporation. The loan
bears interest at a floating rate of 5.96% as of December 31, 2007, which is 1.25% over
LIBOR. In addition, we also consolidated $53.7 million in existing debt. This debt
amortizes through December 31, 2010 and is at a fixed interest rate of 13.25%. Covenants
associated with this loan are consistent with the covenants on our revolving credit
facility, with additional requirements related to the funded status of our pension plans
and environmental costs. There are no cross default provisions associated with this
loan.
As of December 31, 2007, we are in compliance with all of our debt
covenants.
Maturities of Long-Term Debt
The aggregate minimum principal maturities of long-term debt and capital
leases, during the next five years are $21.0 million in 2008, $133.3 million in
2009, $24.8 million in 2010, $7.8 million in 2011 and $5.2 million in
2012.
(12)
|
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, 2007 and 2006.
F -
18
The estimated fair value of financial instruments is summarized as follows
(in thousands):
|
|
December
31, 2007
|
|
December
31,
2006
|
|
|
|
Carrying
Amount
|
|
Fair
Value
|
|
Carrying
Amount
|
|
Fair
Value
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
12,773
|
|
$
|
12,773
|
|
$
|
1,930
|
|
$
|
1,930
|
|
Restricted cash
|
|
14,482
|
|
14,482
|
|
15,836
|
|
15,836
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases (including current
portion)
|
|
846,368
|
|
849,770
|
|
747,117
|
|
750,296
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense applicable to continuing operations is comprised of the
following (in thousands):
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
Federal
|
|
|
|
|
|
|
|
Current
|
|
$
|
1,449
|
|
$
|
11
|
|
$
|
4
|
|
Deferred
|
|
28,586
|
|
24,062
|
|
36,156
|
|
Investment tax credits
|
|
(531
|
)
|
(536
|
)
|
(537
|
)
|
State
|
|
2,884
|
|
2,394
|
|
2,887
|
|
|
|
$
|
32,388
|
|
$
|
25,931
|
|
$
|
38,510
|
|
The following table reconciles our effective income tax rate to the federal
statutory rate:
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
Federal statutory rate
|
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
State income, net of federal provisions
|
|
3.4
|
|
3.8
|
|
3.4
|
|
Amortization of investment tax credit
|
|
(0.7
|
)
|
(0.7
|
)
|
(0.5
|
)
|
Depreciation of flow through items
|
|
(0.7
|
)
|
—
|
|
(0.9
|
)
|
Nondeductible professional fees
|
|
1.5
|
|
1.7
|
|
2.0
|
|
Prior year permanent return to accrual
adjustments
|
|
(1.1
|
)
|
(0.5
|
)
|
(1.8
|
)
|
Other, net
|
|
0.4
|
|
1.6
|
|
1.3
|
|
|
|
37.8
|
%
|
40.9
|
%
|
38.5
|
%
|
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.
F -
19
The components of the net deferred income tax liability recognized in our
Consolidated Balance Sheets are related to the following temporary differences (in
thousands):
|
|
December
31,
2007
|
|
December
31,
2006
|
|
Excess tax depreciation
|
|
$
|
(104,113
|
)
|
$
|
(97,613
|
)
|
Regulatory assets
|
|
(12,179
|
)
|
(20,392
|
)
|
Regulatory liabilities
|
|
(2,288
|
)
|
1,264
|
|
Unbilled revenue
|
|
3,819
|
|
2,960
|
|
Unamortized investment tax credit
|
|
1,883
|
|
2,169
|
|
Compensation accruals
|
|
5,034
|
|
3,275
|
|
Reserves and accruals
|
|
23,577
|
|
24,203
|
|
Goodwill amortization
|
|
(50,914
|
)
|
(42,155
|
)
|
Net operating loss carryforward (NOL)
|
|
65,394
|
|
15,573
|
|
AMT credit carryforward
|
|
5,483
|
|
3,186
|
|
Capital loss carryforward
|
|
6,376
|
|
6,376
|
|
Valuation allowance
|
|
(12,758
|
)
|
(12,758
|
)
|
Other, net
|
|
(373
|
)
|
576
|
|
|
|
$
|
(71,059
|
)
|
$
|
(113,336
|
)
|
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, 2007 against capital loss carryforwards and certain state NOL
carryforwards as we do not believe these assets will be realized.
At December 31, 2007 we estimate our total federal NOL carryforward to
be approximately $346.0 million. If unused, $172.4 million will expire in the year 2023,
and $173.6 million will expire in the year 2025. We estimate our state NOL carryforward as
of December 31, 2007 is approximately $491.9 million. If unused, $320.0 million will expire
in 2010, $33.8 million will expire in 2011, and $138.1 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.
FIN
48
We adopted the provisions of FIN 48 on January 1, 2007. 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. As a result of the implementation of FIN 48, we
increased our deferred tax assets by $77.5 million and decreased other noncurrent
liabilities by $2.4 million, with a corresponding decrease to goodwill. The decrease to
goodwill is consistent with the guidance in SFAS No. 109 and the requirements of
fresh-start reporting, as our uncertain tax positions relate to periods prior to our
emergence from bankruptcy. The change in unrecognized tax benefits since adoption of FIN 48
is as follows:
Unrecognized Tax Benefits at January 1, 2007
|
$
|
100,264
|
|
Gross increases - tax positions in prior period
|
|
13,228
|
|
Gross decreases - tax positions in prior period
|
|
(2,368
|
)
|
Unrecognized Tax Benefits at December 31, 2007
|
$
|
111,124
|
|
If any of our unrecognized tax benefits were recognized, they would have no
impact on our effective tax rate. We do not anticipate that total unrecognized tax benefits
will significantly change due to the settlement of audits or the expiration of statute of
limitations within the next twelve months.
Our policy is to recognize interest and penalties related to uncertain tax
positions in income tax expense. During the year ended December 31, 2007, we have not
recognized expense for interest or penalties, and do not have any amounts accrued
at
F -
20
December
31, 2007 and 2006, respectively, for the payment of interest and penalties.
Our federal tax returns from 2000 forward remain subject to examination by
the Internal Revenue Service.
(14)
|
Jointly Owned Plants
|
We have an ownership interest in four electric generating plants, all of
which are coal fired and operated by other 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.
The participants each finance their own investment.
Information relating to our ownership interest in these facilities is as
follows (in thousands):
|
|
|
Big Stone (S.D.)
|
|
Neal #4 (Iowa)
|
|
Coyote (N.D.)
|
|
Colstrip Unit
4
(MT)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
Ownership
percentages
|
|
23.4
|
%
|
8.7
|
%
|
10.0
|
%
|
30.0
|
%
|
Plant in service
|
|
$
|
55,691
|
|
$
|
29,686
|
|
$
|
42,655
|
|
257,129
|
|
|
|
Accumulated
depreciation
|
|
34,933
|
|
19,816
|
|
25,567
|
|
14,139
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
Ownership
percentages
|
|
23.4
|
%
|
8.7
|
%
|
10.0
|
%
|
—
|
|
Plant in service
|
|
$
|
52,948
|
|
$
|
29,930
|
|
$
|
42,797
|
|
—
|
|
|
|
Accumulated
depreciation
|
|
34,588
|
|
19,309
|
|
24,393
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We lease vehicles, office equipment and facilities under various long-term
operating leases. At December 31, 2007 future minimum lease payments for the next five
years under non-cancelable lease agreements are as follows (in thousands):
2008
|
|
$
|
1,828
|
|
2009
|
|
1,081
|
|
2010
|
|
684
|
|
2011
|
|
501
|
|
2012
|
|
429
|
|
Lease and rental expense incurred was $19.0 million, $30.9 million, and
$31.0 million for the years ended December 31, 2007, 2006 and 2005,
respectively.
(16)
|
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.
In accordance with SFAS No. 158,
Employers'
Accounting for Defined Benefit Pension and Other Postretirement
Plans
, 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
F -
21
F -
39
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. See Note 18 for further discussion on how these costs are
recovered through rates charged to our customers.
Benefit Obligation and Funded Status
Following is a reconciliation of the changes in plan benefit obligations and
fair value and a statement of the funded status (in thousands):
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
|
|
December 31,
2007
|
|
December
31,
2006
|
|
December
31,
2007
|
|
December
31,
2006
|
|
Reconciliation of Benefit Obligation
|
|
|
|
|
|
|
|
|
|
Obligation at beginning of period
|
|
$
|
387,562
|
|
$
|
386,915
|
|
$
|
53,063
|
|
$
|
55,620
|
|
Service cost
|
|
8,947
|
|
9,049
|
|
581
|
|
741
|
|
Interest cost
|
|
21,799
|
|
20,791
|
|
2,442
|
|
2,775
|
|
Actuarial gain
|
|
(21,106
|
)
|
(10,265
|
)
|
(6,219
|
)
|
(2,705
|
)
|
Gross benefits paid
|
|
(20,330
|
)
|
(18,928
|
)
|
(3,373
|
)
|
(3,368
|
)
|
Benefit obligation at end of period
|
|
$
|
376,872
|
|
$
|
387,562
|
|
$
|
46,494
|
|
$
|
53,063
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
|
|
December 31,
2007
|
|
December
31,
2006
|
|
December
31,
2007
|
|
December
31,
2006
|
|
Reconciliation of Fair Value of
Plan Assets
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at
beginning of period
|
|
$
|
301,100
|
|
$
|
271,103
|
|
$
|
13,358
|
|
$
|
10,363
|
|
Return on plan assets
|
|
27,038
|
|
30,918
|
|
892
|
|
1,041
|
|
Employer contributions
|
|
22,638
|
|
18,007
|
|
5,578
|
|
5,322
|
|
Gross benefits paid
|
|
(20,330
|
)
|
(18,928
|
)
|
(3,373
|
)
|
(3,368
|
)
|
Fair value of plan assets at end of period
|
|
$
|
330,446
|
|
$
|
301,100
|
|
$
|
16,455
|
|
$
|
13,358
|
|
Funded Status
|
|
$
|
(46,426
|
)
|
$
|
(86,463
|
)
|
$
|
(30,039
|
)
|
$
|
(39,705
|
)
|
Unrecognized net actuarial (gain) loss
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Unrecognized prior service
cost
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Accrued benefit cost
|
|
$
|
(46,426
|
)
|
$
|
(86,463
|
)
|
$
|
(30,039
|
)
|
$
|
(39,705
|
)
|
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 $376.9
million and $330.4 million, respectively, as of December 31, 2007. 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 $374.9 million and $330.4
million, respectively, as of December 31, 2007.
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.
F -
22
Balance Sheet Recognition
The accrued pension and other postretirement benefit obligations recognized
in the accompanying Consolidated Balance Sheets are computed as follows (in
thousands):
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
|
|
December
31,
2007
|
|
December
31,
2006
|
|
December
31,
2007
|
|
December
31,
2006
|
|
Accrued benefit cost
|
|
$
|
(91,629
|
)
|
$
|
(107,700
|
)
|
$
|
(37,885
|
)
|
$
|
(41,768
|
)
|
Amounts not yet reflected in net periodic benefit
cost:
|
|
|
|
|
|
|
|
|
|
Prior service cost
|
|
(2,177
|
)
|
(2,419
|
)
|
—
|
|
—
|
|
Accumulated gain
|
|
47,380
|
|
23,656
|
|
7,846
|
|
2,063
|
|
Net amount recognized
|
|
$
|
(46,426
|
)
|
$
|
(86,463
|
)
|
$
|
(30,039
|
)
|
$
|
(39,705
|
)
|
Plan
Assets
Our investment strategy provides for the following asset allocation, within
an allowable range of plus or minus 5%:
|
|
Pension
Benefits
|
|
Other
Benefits
|
|
Debt securities
|
|
30.0
|
%
|
30.0
|
%
|
Domestic equity securities
|
|
60.0
|
|
60.0
|
|
International equity securities
|
|
10.0
|
|
10.0
|
|
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, 2007 and
December 31, 2006, are as follows:
|
|
NorthWestern Energy Pension
|
|
NorthWestern Corporation
Pension
|
|
NorthWestern Energy
Health and Welfare
|
|
|
|
December
31,
2007
|
|
December
31,
2006
|
|
December
31,
2007
|
|
December
31,
2006
|
|
December
31,
2007
|
|
December
31,
2006
|
|
Cash and cash equivalents
|
|
0.2
|
%
|
1.9
|
%
|
0.2
|
%
|
0.7
|
%
|
0.1
|
%
|
—
|
%
|
Debt securities
|
|
29.8
|
|
30.5
|
|
2.4
|
|
—
|
|
30.3
|
|
28.3
|
|
Domestic equity securities
|
|
58.8
|
|
56.1
|
|
59.2
|
|
57.0
|
|
58.6
|
|
71.3
|
|
International equity securities
|
|
11.2
|
|
11.5
|
|
11.4
|
|
11.6
|
|
11.0
|
|
0.4
|
|
Participating group annuity contracts
|
|
—
|
|
—
|
|
26.8
|
|
30.7
|
|
—
|
|
—
|
|
|
|
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
Our investment goals with respect to managing the pension and other
postretirement assets are to meet current and future benefit payment needs while maximizing
total investment returns (income and appreciation) after inflation within the constraints
of diversification, prudent risk taking, and the Prudent Man Rule of the Employee
Retirement Income Security Act of 1974 (ERISA). Each plan is diversified across asset
classes to achieve optimal balance between risk and return and between income and growth
through capital appreciation. 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 calculate the market related value of plan assets based on the fair
market value of plan assets. Debt and equity securities are recorded at their fair market
value each year end as determined by quoted closing market prices on national securities
exchanges or other markets as applicable. The participating group annuity contracts are
valued based on discounted cash flows of current yields of similar contracts with
comparable duration.
Our investment policy allows for all or a portion of each benefit plan to be
invested in commingled funds, including mutual funds, collective investment funds, bank
commingled funds and insurance company separate accounts. These pooled investment funds
must have an adequate asset base relative to their asset class and be invested in a
diversified manner and have a minimum of three years of verified investment performance
experience or verified portfolio manager investment experience in a particular investment
strategy and have management and oversight by an Investment Advisor registered with the
SEC. The direct holding of company stock is not permitted; however, any holding in a
diversified mutual fund or
F -
23
collective
investment fund is permitted. The policy prohibits any transactions that would threaten the
tax exempt status of the fund and actions that would create a conflict of interest or
transactions between fiduciaries and parties in interest as defined under ERISA.
Our investment policy for fixed income investments consist of U.S. as well
as international instruments. Core domestic portfolios can be invested in government,
corporate, asset-backed and mortgage-backed obligation securities. The portfolio may invest
in high yield securities, however, the average quality must be rated at least
“investment grade" by rating agencies including Moodys and S&P. In addition, the
NorthWestern Corporation pension plan assets also include a participating group annuity
contract in the John Hancock General Investment Account, which consists primarily of
fixed-income securities.
Equity investments consist primarily of U.S. stocks including large, mid and
small cap stocks, which are diversified across investment styles such as growth and value.
Non-U.S. equities are utilized with exposure to developing and emerging markets.
Derivatives, options and futures are permitted for the purpose of reducing risk but may not
be used for speculative purposes.
Actuarial Assumptions
The measurement dates used to determine pension and other postretirement
benefit measurements for the plans are December 31, 2007 and 2006. 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 2007 and 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. This is done by constructing a hypothetical bond
portfolio whose cash flow from coupons and maturities matches the year-by-year, projected
benefit cash flow from our plans.
The expected long-term rate of return assumption on plan assets for both the
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 portfolios.
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:
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
2007
|
|
2006
|
|
2005
|
|
Discount rate
|
|
6.25
|
%
|
5.75
|
%
|
5.50
|
%
|
5.75-6.00
|
%
|
5.50 - 5.75
|
%
|
5.50
|
%
|
Expected rate of return on assets
|
|
8.00
|
%
|
8.00
|
%
|
8.50
|
%
|
8.00
|
%
|
8.00
|
%
|
8.50
|
%
|
Long-term rate of increase in compensation levels
(nonunion)
|
|
3.58
|
%
|
3.61
|
%
|
3.64
|
%
|
3.55
|
%
|
3.57
|
%
|
3.64
|
%
|
Long-term rate of increase in compensation levels
(union)
|
|
3.50
|
%
|
3.50
|
%
|
3.50
|
%
|
3.50
|
%
|
3.50
|
%
|
3.50
|
%
|
The postretirement benefit obligation is calculated assuming that health
care costs increased by 10% in 2007 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
2013.
F -
24
Net Periodic Cost
The components of the net costs for our pension and other postretirement
plans are as follows (in thousands):
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
December 31,
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
2007
|
|
2006
|
|
2005
|
|
Components of Net Periodic Benefit Cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
8,947
|
|
$
|
9,049
|
|
$
|
8,531
|
|
$
|
580
|
|
$
|
741
|
|
$
|
688
|
|
Interest cost
|
|
21,800
|
|
20,791
|
|
20,174
|
|
2,442
|
|
2,775
|
|
2,853
|
|
Expected return on plan assets
|
|
(24,422
|
)
|
(21,458
|
)
|
(20,347
|
)
|
(1,068
|
)
|
(829
|
)
|
(562
|
)
|
Amortization of transitional obligation
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Amortization of prior service cost
|
|
242
|
|
242
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Recognized actuarial (gain) loss
|
|
—
|
|
—
|
|
—
|
|
(259
|
)
|
117
|
|
—
|
|
Net Periodic Benefit Cost
|
|
$
|
6,567
|
|
$
|
8,624
|
|
$
|
8,358
|
|
$
|
1,695
|
|
$
|
2,804
|
|
$
|
2,979
|
|
We estimate amortizations from regulatory assets into net periodic cost
during 2008 will be as follows (in thousands):
|
|
Pension
Benefits
|
|
Other Postretirement Benefits
|
|
Prior service cost
|
$
|
242
|
$
|
—
|
|
Accumulated gain
|
|
(854
|
)
|
(292
|
)
|
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):
Effect of a one percentage point increase in assumed health
care cost trend
|
|
|
|
on total service and interest cost components
|
|
$
|
150
|
|
on postretirement benefit obligation
|
|
1,639
|
|
Effect of a one percentage point decrease in assumed health
care cost trend
|
|
|
|
on total service and interest cost components
|
|
$
|
(129
|
)
|
on postretirement benefit obligation
|
|
(1,450
|
)
|
Cash Flows
On August 17, 2006 the Pension Protection Act of 2006 (PPA) was signed into
law, with changes that impact the funding calculation for benefit plans. Pension funding is
based on annual actuarial studies prepared for each plan in accordance with contribution
guidelines established by PPA, ERISA and the Internal Revenue Code. We anticipate making
contributions of approximately $26.1 million to our pension and other postretirement
benefit plans in 2008. 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):
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
|
2008
|
|
$
|
20,415
|
|
$
|
3,900
|
|
2009
|
|
20,776
|
|
3,986
|
|
2010
|
|
21,544
|
|
4,129
|
|
2011
|
|
22,443
|
|
4,072
|
|
2012
|
|
23,312
|
|
4,038
|
|
2013-2017
|
|
137,730
|
|
21,542
|
|
|
|
|
|
|
|
|
|
F -
25
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 $4.7 million for 2007, $4.3 million
for 2006, and $3.4 million for 2005, respectively.
(17)
|
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 1,300,000 shares have
been 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. As of December
31, 2007 there were 625,107 shares of common stock remaining available for grants. 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 in the event of a change in
control.
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 $7.0 million, $3.6 million and $4.7 million for the years ended December 31, 2007, 2006
and 2005, respectively. The total income tax benefit recognized in the income statement for
these restricted stock awards was $4.4 million, $1.5 million and $1.8 million for the years
ended December 31, 2007, 2006 and 2005, respectively.
Summarized share information for our restricted stock awards is as
follows:
|
|
Year Ended
December 31,
2007
|
|
Weighted-Average Grant-Date Fair Value
|
|
Year Ended
December 31,
2006
|
|
Weighted-Average Grant-Date Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
Beginning nonvested grants
|
|
476,105
|
|
$ 29.54
|
|
35,164
|
|
$ 20.00
|
|
Granted
|
|
4,208
|
|
31.72
|
|
503,337
|
|
34.42
|
|
Vested
|
|
107,973
|
|
31.94
|
|
57,393
|
|
29.94
|
|
Forfeited
|
|
11,027
|
|
34.37
|
|
5,003
|
|
34.39
|
|
Remaining nonvested grants
|
|
361,313
|
|
34.45
|
|
476,105
|
|
29.54
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007 we had $6.6 million of unrecognized compensation
cost related to nonvested portion of outstanding restricted stock awards, which is
reflected as unearned restricted stock as a portion of additional paid in capital in our
Statement of Common Shareholders' Equity. The cost is expected to be recognized over a
weighted-average period of 1.9 years. The total fair value of shares vested was $3.4
million, $1.7 million and $4.6 million for the years ended December 31, 2007, 2006 and
2005.
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 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
F -
26
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, 2007 and 2006,
DSUs issued to members of our Board totaled 30,563 and 22,805, respectively. Total
compensation expense attributable to the DSUs during the years ended December 31, 2007,
2006 and 2005 was approximately $0.7 million, $0.9 million and $0.7 million,
respectively.
(18)
|
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 97% of our regulatory assets and 100% of our
regulatory liabilities.
|
|
Note
|
|
Remaining Amortization
|
|
December 31,
|
|
|
|
Reference
|
|
Period
|
|
2007
|
|
|
2006
|
|
Pension
|
|
16
|
|
Undetermined
|
$
|
47,091
|
|
$
|
87,397
|
|
Postretirement benefits
|
|
16
|
|
Undetermined
|
|
21,099
|
|
|
28,725
|
|
Competitive transition charges
|
|
|
|
5 Years
|
|
23,227
|
|
|
27,954
|
|
Environmental clean-up
|
|
|
|
Various
|
|
14,765
|
|
|
—
|
|
Supply costs
|
|
|
|
1 Year
|
|
14,195
|
|
|
15,205
|
|
Income taxes
|
|
13
|
|
Plant Lives
|
|
11,279
|
|
|
9,453
|
|
State & local taxes & fees
|
|
|
|
1 Year
|
|
—
|
|
|
5,105
|
|
Deferred financing costs
|
|
|
|
Various
|
|
4,318
|
|
|
4,637
|
|
Other
|
|
|
|
Various
|
|
14,116
|
|
|
12,364
|
|
Total regulatory assets
|
|
|
|
|
$
|
150,090
|
|
$
|
190,840
|
|
Removal cost
|
|
7
|
|
Various
|
$
|
178,968
|
|
$
|
166,705
|
|
Gas storage sales
|
|
|
|
32 Years
|
|
13,354
|
|
|
13,774
|
|
Supply costs
|
|
|
|
1 Year
|
|
32,443
|
|
|
11,053
|
|
Environmental clean-up
|
|
|
|
3 Years
|
|
2,208
|
|
|
—
|
|
Other
|
|
|
|
Various
|
|
8,621
|
|
|
2,797
|
|
Total regulatory liabilities
|
|
|
|
|
$
|
235,594
|
|
$
|
194,329
|
|
Pension and Postretirement Benefits
A regulatory asset has been recognized for costs in excess of amounts
recovered in rates. 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.
The MPSC allows recovery of SFAS No. 106 costs on an accrual basis. This amount
also includes adjustments recognized due to the adoption of fresh-start reporting in 2004
and SFAS No. 158 in 2006 (see Note 16).
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.
F -
27
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 7.96%, respectively, in South Dakota; and 8.55% for natural gas in Nebraska. These same
rates are paid to our customers in the event of a refund.
Environmental clean-up
Environmental clean-up costs are the estimated costs of investigating and
cleaning up contaminated sites we own. We discuss the specific sites and clean-up
requirements further in Note 21. In December 2007, the SDPUC approved our settlement with
SDPUC Staff related to our natural gas rate case, which included a provision allowing us to
include approximately $1.4 million annually in rates to recover MGP environmental clean-up
costs. This was partially offset by a requirement to return approximately $2.3 million
($0.8 million annually) of previous insurance recoveries to customers. The SDPUC's approval
of our settlement provides reasonable assurance that we will recover future South Dakota
related MGP costs, therefore we recorded net regulatory assets (with a corresponding
reduction to operating, general and administrative expenses) of $12.6 million in December
2007 to offset the previously recorded South Dakota MGP related liabilities.
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.
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. In 2007, we filed a general rate case in Montana which
reestablishes the amount of state and local taxes and fees collected in base
rates.
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 7, 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.
F -
28
South Dakota Natural Gas Rate Case
- In
June 2007, we filed a request with the South Dakota Public Utilities Commission (SDPUC) for
a natural gas distribution revenue increase of $3.7 million. We reached a settlement with
the SDPUC, and in December 2007 an order was issued authorizing a base rate increase of
$3.1 million annually. This settlement includes a rate moratorium for a period of three
years.
Nebraska Natural Gas Rate Case
- In June
2007, we filed a request with the Nebraska Public Service Commission (NPSC) for a natural
gas distribution revenue increase of $2.8 million. We reached a settlement with the NPSC,
and in December 2007 an order was issued authorizing a base rate increase of $1.5 million
annually.
FERC Transmission Rate Case
- In October
2006, we filed a request with the FERC for an electric transmission revenue increase. Our
requested increase pertains only to FERC jurisdictional wholesale transmission and retail
choice customers representing approximately $8.6 million in revenue. In May 2007, we
implemented interim rates, which are subject to refund plus interest pending final
resolution. We filed settlement documents on February 15, 2008 and are awaiting FERC
approval, which is expected during the first half of 2008. This proposed settlement would
result in an annualized margin increase of approximately $3.0 million.
Montana Electric and Natural Gas Rate
Case
- In July 2007, we filed a request with the MPSC for a
electric transmission and distribution revenue increase of $31.4 million, and a natural gas
transmission, storage and distribution revenue increase of $10.5 million. In December 2007,
we and the Montana Consumer Counsel filed a joint stipulation with the MPSC to settle our
electric and natural gas rate cases. Specific terms of the Stipulation include:
|
•
|
An increase in base electric rates of $10 million and base
natural gas rates of $5 million;
|
|
•
|
Interim rates effective January 1, 2008;
|
|
•
|
Capital investment in our electric and natural gas system
totaling $38.8 million to be completed in 2008 and 2009 on which we will
not earn a return on, but will recover depreciation expense;
|
|
•
|
A commitment of 21 MWs of unit contingent power from
Colstrip Unit 4 at Mid-C minus $19 per MWH to electric supply for a period
of 76 months beginning March 1, 2008; and
|
|
•
|
We will submit a general electric and natural gas rate
filing no later than July 31, 2009 based on a 2008 test year.
|
The MPSC
has approved interim rates, subject to refund, beginning January 1, 2008, and we anticipate
finalizing the rate case during the second quarter of 2008.
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 unvested restricted shares were to vest. Common stock
equivalent shares are calculated using the treasury stock method, as applicable. 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 and deferred share units. Average shares used in computing the basic and
diluted earnings per share are as follows:
|
|
December 31, 2007
|
|
December
31,
2006
|
|
Basic computation
|
|
36,622,547
|
|
35,554,498
|
|
Dilutive effect of
|
|
|
|
|
|
Restricted shares and deferred share units
|
|
435,615
|
|
519,844
|
|
Stock warrants
|
|
—
|
|
1,407,993
|
|
Diluted computation
|
|
37,058,162
|
|
37,482,335
|
|
Warrants issued in 2004 were exercisable through the close of business
November 1, 2007. A total of 4,238,765 warrants were exercised during the year ended
December 31, 2007. Warrants outstanding as of December 31, 2006 of 4,506,525 were dilutive
and have been included in the 2006 earnings per share calculation.
F -
29
(21)
|
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
MWH through 2029. Our gross contractual obligation related to the QFs is approximately
$1.5 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):
|
|
December 31,
2007
|
|
December 31,
2006
|
|
Beginning QF liability
|
|
$
|
147,893
|
|
$
|
140,467
|
|
Unrecovered amount
|
|
(1,223
|
)
|
(3,460
|
)
|
Interest expense
|
|
11,462
|
|
10,886
|
|
Ending QF liability
|
|
$
|
158,132
|
|
$
|
147,893
|
|
The following summarizes the estimated gross contractual obligation less
amounts recoverable through rates (in thousands):
|
|
Gross
Obligation
|
|
Recoverable
Amounts
|
|
Net
|
|
2008
|
|
$
|
60,574
|
|
$
|
(53,060
|
)
|
$
|
7,514
|
|
2009
|
|
62,598
|
|
(53,583
|
)
|
9,015
|
|
2010
|
|
64,580
|
|
(54,086
|
)
|
10,494
|
|
2011
|
|
66,067
|
|
(54,628
|
)
|
11,439
|
|
2012
|
|
68,156
|
|
(55,180
|
)
|
12,976
|
|
Thereafter
|
|
1,196,704
|
|
(907,370
|
)
|
289,334
|
|
Total
|
|
$
|
1,518,679
|
|
$
|
(1,177,907
|
)
|
$
|
340,772
|
|
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 23 years. Costs incurred under these contracts were approximately $445.0 million,
$447.1 million, and $433.9 million for the years ended December 31, 2007, 2006 and 2005,
respectively. As of December 31, 2007 our commitments under these contracts are
$544 million in 2008, $330 million in 2009, $307 million in 2010, $151
million in 2011, $129 million in 2012, and $454 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 $19.8 million to $57.0 million. As of December 31, 2007, we have a
reserve of approximately $32.7 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.
F -
30
Coal-Fired Plants
We have a jointly owned interest in Colstrip Unit 4, a coal-fired power
plant located in southeastern Montana. In addition, we are joint owners in three coal-fired
plants used to serve our South Dakota customer supply demands. Citing its authority under
the Clean Air Act, the EPA had finalized Clean Air Mercury Regulations (CAMR) that affect
coal-fired plants. These regulations established 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. In February 2008 the
EPA’s mercury regulations were turned down by the U.S. Court of Appeals for the
District of Columbia Circuit; however, Montana has finalized its own rules more stringent
than CAMR's 2018 cap that would require every coal-fired generating plant in the state to
achieve reduction levels by 2010. If the Montana rules are maintained in their current form
and enhanced chemical injection technologies are not sufficiently developed to meet the
Montana levels of reduction by 2010, then adsorption/absorption technology with fabric
filters at the Colstrip Unit 4 generation facility would be required, which could represent
a material cost. Recent tests have shown that it may be possible to meet the Montana rules
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 rules.
In addition to the requirements related to emissions noted above, there is a
growing concern nationally and internationally about global climate change and the
contribution of emissions of greenhouse gases including, most significantly, carbon
dioxide. This concern has led to increased interest in legislation at the federal level,
actions at the state level, as well as litigation relating to greenhouse emissions,
including a recent US Supreme Court decision holding that the EPA has the authority to
regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. Increased
pressure for carbon dioxide emissions reduction also is coming from investor organizations.
If legislation or regulations are passed at the federal or state levels imposing mandatory
reductions of carbon dioxide and other greenhouse gases on generation facilities, the cost
to us of such reductions could be significant.
Manufactured Gas Plants
Approximately $26.1 million of our environmental reserve accrual is related
to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen,
South Dakota, has been identified on the Federal Comprehensive Environmental Response,
Compensation, and Liability Information System (CERCLIS) list as contaminated with coal tar
residue. We are currently investigating, characterizing, and initiating remedial actions at
the Aberdeen site pursuant to work plans approved by the South Dakota Department of
Environment and Natural Resources. In 2007, we completed remediation of sediment in a short
segment of Moccasin Creek that had been impacted by the former manufactured gas plant
operations. Our current reserve for remediation costs at this site is approximately $12.4
million, and we estimate that approximately $10 million of this amount will be incurred
during the next five years.
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. We have initiated
additional site investigation and assessment work at these locations. At present, we cannot
determine with a reasonable degree of certainty the nature and timing of any risk-based
remedial action 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 exceedences of regulated pollutants in the
groundwater. We have conducted additional groundwater monitoring at the Butte and Missoula
sites and, at this time, we believe natural attenuation should address the problems at
these sites; however, additional groundwater monitoring will be necessary. In Helena, we
continue limited operation of an oxygen delivery system implemented to enhance natural
biodegradation of pollutants in the groundwater and we are currently evaluating limited
source area treatment/removal options. 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 risk-based remedial action at the
F -
31
Helena
site.
Based upon our investigations to date, our current environmental liability
reserves, applicable insurance coverage, and the potential to recover 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 MW 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.
On July 18, 2005, we and CFB 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. Dam removal activities will be initiated in January of
2008.
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, and the sale or transfer of land and water rights associated with the
Milltown Dam operations.
Other
We continue to manage equipment containing polychlorinated biphenyl (PCB)
oil in accordance with the EPA's Toxic Substance Control Act regulations. 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 assist in performing a comprehensive evaluation of our environmental reserve. Based
upon information available 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 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.
|
F -
32
Legal
Proceedings
Magten/Law Debenture/QUIPS Litigation
Magten and Law Debenture v. NorthWestern Corporation -
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
8.45% Quarterly Income Preferred Securities (QUIPS) 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
NorthWestern, the imposition of constructive trusts over the transferred assets and the
return of such assets to CFB. On July 18, 2007, the Delaware District Court extended the
discovery schedule and scheduled the trial for March 2008. We have and will continue to
vigorously defend against the QUIPS litigation.
Magten v. Certain Current and Former Officers of CFB -
On April 19, 2004, Magten 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. On July 18, 2007, the Delaware District Court extended the discovery
schedule and scheduled the trial for March 2008.
Magten v. Bank of New York -
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 dismissed
Magten's complaint in May 2007 and Magten has filed a notice of appeal. 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 Class 9 Disputed Claim Reserve set aside under NorthWestern's Chapter 11 Plan of
Reorganization (the “Plan"), although the Plan Committee, acting on behalf of certain
creditors of NorthWestern's bankruptcy estate, has objected to this position.
Magten and Law Debenture v. NorthWestern Corporation and Certain
Individuals -
On April 15, 2005, Magten and Law Debenture
filed an adversary complaint in the Bankruptcy Court against NorthWestern and certain
former and current officers and directors seeking to revoke the Confirmation Order of our
Plan of Reorganization 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.
F -
33
We have reached a tentative agreement with Magten, the Plan Committee and
other interested persons to resolve all the currently pending claims and litigation
involving Magten arising out of our bankruptcy proceeding. We will be preparing a
settlement agreement and expect to seek bankruptcy court approval for the settlement during
the first quarter of 2008. The tentative settlement will be funded from the Class 9
Disputed Claims Reserve and insurance proceeds. While we cannot currently predict if the
tentative settlement will be approved, the plaintiffs' claims with respect to the QUIPs
Litigation should be treated as general unsecured, or Class 9, claims which would 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.
We are one of the defendants in a second class action lawsuit brought by the
McGreevey plaintiffs, also entitled
McGreevey, et al. v. The
Montana Power Company, et al.,
pending in U.S. District Court in
Montana. This lawsuit, like the
Magten
litigation described above, seeks, among other things, the avoidance of the
transfer of assets from CFB to us, 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.
In June 2006, we and the McGreevey plaintiffs entered into an agreement to
settle all claims brought by the McGreevey plaintiffs in all of the actions described
above, wherein the McGreevey plaintiffs executed a covenant not to execute against us, and
we quit claimed 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. In November 2006, this agreement was approved by the Delaware Bankruptcy Court
and the claims were discharged. We filed a joint motion with the plaintiffs' attorneys in
U.S. District Court in Montana to dismiss the claims against us in the McGreevey lawsuits.
On March 16, 2007, the U.S. District Court in Montana denied the motion to dismiss us from
the McGreevey lawsuits, questioning the benefits of the settlement to be received by the
class members in the settlement and the authority of the plaintiffs' counsel to have
negotiated the settlement without a class having been certified by the court. On January
11, 2008, the U.S. District Court in Montana suggested that the settlement agreement was
invalid because the plaintiffs' attorneys had not secured the court's permission to engage
in settlement discussions. It is unlikely that we will be able to obtain our dismissal from
the McGreevey litigation in Montana before class representatives and class counsel are
approved by the U.S. District Court in Montana. However, we believe that given the scope of
our bankruptcy confirmation order and the injunctions issued by the Delaware Bankruptcy
Court which channeled the claims to the D&O Trust, we have limited exposure for damages
arising from the McGreevey claims. We will continue to vigorously defend against these
claims and explore ways to remove ourselves from the lawsuits.
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 claimed, 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. In
May 2006, the parties entered into a settlement agreement which provided that NorthWestern
would 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. Under the proposed agreement, the Board could 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. In December
2006, the federal court indicated it would not approve the settlement because it did not
provide any benefit to the
F -
34
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' motion seeking discovery in advance of its motion
for an award of attorneys' fees was denied. Plaintiffs then filed a motion for attorneys'
fees and costs seeking $9.9 million on the grounds that the Board's acceptance of the BBI
offer was attributable to their efforts. We have responded arguing that plaintiffs opposed
all of the Board's efforts leading to the BBI transaction and that its lawyers are thus
entitled to no fees. The plaintiffs filed a reply in May 2007. On May 24, 2007, we notified
the federal court of the MPSC unanimous direction to its staff to draft an order rejecting
the proposed BBI transaction, noting that unless the BBI transaction was approved, the
plaintiffs' argument for benefit to the estate would be moot and suggested that the federal
court delay any ruling until the MPSC reaches a final decision on the BBI transaction. On
July 25, 2007, we advised the federal court that the Merger Agreement was terminated based
on the action by the MPSC denying consideration of the revised proposal and denying
approval of the transaction. At the time, we noted that there could be no benefit to our
shareholders justifying an attorneys' fee award in light of the termination of the BBI
transaction. On December 13, 2007, the federal court ordered additional simultaneous
briefing on the issue of whether, in light of the BBI termination, the Livonia litigation
had benefited our shareholders. Briefings concluded in January 2008 and we are currently
awaiting a decision by the federal court. We believe that any award of attorneys' fees
would be reimbursed by insurance proceeds.
Ammondson
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
NorthWestern, we had engaged in malicious prosecution and should be subject to punitive
damages. 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 reviewed the amount of the punitive damages under state law and did
not alter the amount. We have appealed the judgment and posted a $25.8 million bond. We
intend to vigorously pursue the appeal; however, there can be no assurance that we will
prevail in our efforts. We expect to incur additional legal and court costs related to
these proceedings.
Other Litigation and Contingencies
During the second quarter of 2007, we voluntarily informed the FERC of
several potential regulatory compliance issues related to our natural gas business. The
FERC has initiated a nonpublic, informal investigation. We cannot currently predict the
outcome of the FERC's investigation.
In December 2006, the MPSC issued an order finalizing certain qualifying
facility rates for the periods July 1, 2003 through June 30, 2006. Colstrip Energy Limited
Partnership (CELP) is a qualifying facility with which we have a power purchase agreement
through 2025. CELP filed a complaint against NorthWestern and the MPSC in Montana district
court on July 6, 2007. Under the terms of the power purchase agreement with CELP, energy
and capacity rates were fixed (with a small portion being set by the MPSC's determination
of rates in the annual avoided cost filing) through June 30, 2004 and beginning July 1,
2004 through the end of the contract energy and capacity rates are to be determined each
year pursuant to a formula. If the MPSC's order is upheld in its current form, we
anticipate reducing our QF liability by approximately $25 million as our estimate of energy
and capacity rates for the remainder of the contract period would be reduced. CELP is
disputing inputs in to the rate-setting formula, used by us and approved by the MPSC on an
annual basis, to calculate energy and capacity payments for the contract years 2004, 2005
and 2006. CELP is claiming that NorthWestern breached the power purchase agreement causing
damages, which CELP asserts are not presently known but believed to be approximately $22
million for contract years 2004, 2005 and 2006. A temporary restraining order was agreed to
by the parties and has been issued restraining us from implementing the rates finalized by
the MPSC order pending a decision on CELP's request for a preliminary injunction. We
believe CELP has no basis for their complaint and intend to vigorously defend this action.
On January 24, 2008, we commenced an adversary proceeding against CELP in the Delaware
Bankruptcy Court seeking a declaration that no prior order of the Delaware Bankruptcy Court
either limited or curtailed the rate setting authority of the MPSC.
F -
35
Relative to our joint ownership 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 and 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 and 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 on the basis of an audit of
WECO's royalty payments during the three years 2002 to 2004. WECO appealed these orders to
the Interior Board of Land Appeals of the United States Department of Interior (IBLA) who
affirmed the orders on September 12, 2007. WECO filed a complaint and request for
declaratory ruling in the US District Court for the District of Columbia in January 2008
seeking relief from the orders issued by the MMS and affirmed by the IBLA, and we continue
to monitor the appeals process. The Colstrip Units 3 and 4 owners and WECO currently
dispute the responsibility of the expenses if the MMS position prevails. We believe that
the Colstrip Units 3 and 4 owners have reasonable defenses in this matter. 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
$4.5 million, and ongoing royalty expenses related to coal transportation. While the
percentage of our share of the alleged additional royalties is not expected to change, the
estimated amount may increase after the MMS updates the assessment to reflect interest and
ongoing royalty expenses for 2007.
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.
We have 250,000,000 shares authorized 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. In addition, 2,265,957 shares of common stock are reserved for the incentive
plan awards. For further detail of grants under this plan see Note 17.
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.
Shares tendered by employees to us to satisfy the employees' tax withholding
obligations in connection with the vesting of restricted stock awards totaled 33,196 and
16,664 during the years ended December 31, 2007 and 2006, respectively, and are reflected
in treasury stock. These shares were credited to treasury stock based on their fair market
value on the vesting date.
F -
36
(23)
|
Segment and Related Information
|
We operate the following business units: (i) regulated electric,
(ii) regulated natural gas, (iii) unregulated electric, and (iv) all other,
which primarily consists of our remaining unregulated natural gas operations and our
unallocated corporate costs. We have changed our management of the unregulated natural gas
segment, moved certain customers to our regulated natural gas business unit and sold
several customer contracts during 2007; therefore, the unregulated natural gas business
unit will no longer be considered a reportable segment under SFAS No. 131. We have two
remaining unregulated natural gas contracts that will be presented in the all other
segment.
We evaluate the performance of these segments based on gross margin. 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, are as follows (in
thousands):
|
|
Regulated
|
|
Unregulated
|
|
|
|
|
|
|
|
December 31, 2007
|
|
Electric
|
|
Gas
|
|
Electric
|
|
Other
|
|
Eliminations
|
|
Total
|
|
Operating revenues
|
|
$
|
736,657
|
|
$
|
363,584
|
|
$
|
74,231
|
|
$
|
56,748
|
|
$
|
(31,160
|
)
|
$
|
1,200,060
|
|
Cost of sales
|
|
389,681
|
|
235,958
|
|
18,079
|
|
54,222
|
|
(29,535
|
)
|
668,405
|
|
Gross margin
|
|
346,976
|
|
127,626
|
|
56,152
|
|
2,526
|
|
(1,625
|
)
|
531,655
|
|
Operating, general and administrative
|
|
133,091
|
|
52,008
|
|
28,662
|
|
9,430
|
|
(1,625
|
)
|
221,566
|
|
Property and other taxes
|
|
61,281
|
|
22,959
|
|
3,301
|
|
40
|
|
—
|
|
87,581
|
|
Depreciation
|
|
61,912
|
|
16,592
|
|
3,782
|
|
129
|
|
—
|
|
82,415
|
|
Operating income (loss)
|
|
90,692
|
|
36,067
|
|
20,407
|
|
(7,073
|
)
|
—
|
|
140,093
|
|
Interest expense
|
|
(39,132
|
)
|
(13,464
|
)
|
(2,849
|
)
|
(1,497
|
)
|
—
|
|
(56,942
|
)
|
Other income
|
|
801
|
|
505
|
|
57
|
|
1,065
|
|
—
|
|
2,428
|
|
Income tax (expense) benefit
|
|
(18,631
|
)
|
(8,509
|
)
|
(7,341
|
)
|
2,093
|
|
—
|
|
(32,388
|
)
|
Income (loss) from continuing operations
|
|
$
|
33,730
|
|
$
|
14,599
|
|
$
|
10,274
|
|
$
|
(5,412
|
)
|
$
|
—
|
|
|
53,191
|
|
Total assets
|
|
$
|
1,529,048
|
|
$
|
749,099
|
|
$
|
251,100
|
|
$
|
18,133
|
|
$
|
—
|
|
$
|
2,547,380
|
|
Capital expenditures
|
|
$
|
71,905
|
|
$
|
40,600
|
|
$
|
4,579
|
|
$
|
—
|
|
$
|
—
|
|
$
|
117,084
|
|
|
|
Regulated
|
|
Unregulated
|
|
|
|
|
|
|
|
December 31, 2006
|
|
Electric
|
|
Gas
|
|
Electric
|
|
Other
|
|
Eliminations
|
|
Total
|
|
Operating revenues
|
|
$
|
661,710
|
|
$
|
359,701
|
|
$
|
83,007
|
|
$
|
76,959
|
|
$
|
(48,724
|
)
|
$
|
1,132,653
|
|
Cost of sales
|
|
332,786
|
|
240,788
|
|
16,639
|
|
70,480
|
|
(47,111
|
)
|
613,582
|
|
Gross margin
|
|
328,924
|
|
118,913
|
|
66,368
|
|
6,479
|
|
(1,613
|
)
|
519,071
|
|
Operating, general and administrative
|
|
125,359
|
|
58,560
|
|
40,219
|
|
17,690
|
|
(1,613
|
)
|
240,215
|
|
Property and other taxes
|
|
51,416
|
|
19,722
|
|
2,942
|
|
107
|
|
—
|
|
74,187
|
|
Depreciation
|
|
58,033
|
|
14,614
|
|
1,597
|
|
1,061
|
|
—
|
|
75,305
|
|
Ammondson verdict
|
|
—
|
|
—
|
|
—
|
|
19,000
|
|
—
|
|
19,000
|
|
Operating income (loss)
|
|
94,116
|
|
26,017
|
|
21,610
|
|
(31,379
|
)
|
—
|
|
110,364
|
|
Interest expense
|
|
(41,770
|
)
|
(12,503
|
)
|
—
|
|
(1,743
|
)
|
—
|
|
(56,016
|
)
|
Other income
|
|
3,244
|
|
2,062
|
|
147
|
|
3,612
|
|
—
|
|
9,065
|
|
Income tax (expense) benefit
|
|
(21,556
|
)
|
(5,489
|
)
|
(8,776
|
)
|
9,890
|
|
—
|
|
(25,931
|
)
|
Income (loss) from continuing operations
|
|
$
|
34,034
|
|
$
|
10,087
|
|
$
|
12,981
|
|
$
|
(19,620
|
)
|
$
|
—
|
|
$
|
37,482
|
|
Total assets
|
|
$
|
1,547,302
|
|
$
|
762,847
|
|
$
|
54,800
|
|
$
|
30,988
|
|
$
|
—
|
|
$
|
2,395,937
|
|
Capital expenditures
|
|
$
|
71,039
|
|
$
|
24,419
|
|
$
|
5,122
|
|
$
|
466
|
|
$
|
—
|
|
$
|
101,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F -
37
|
|
Regulated
|
|
Unregulated
|
|
|
|
|
|
|
|
December 31, 2005
|
|
Electric
|
|
Gas
|
|
Electric
|
|
Other
|
|
Eliminations
|
|
Total
|
|
Operating revenues
|
|
$
|
631,676
|
|
$
|
369,463
|
|
$
|
86,978
|
|
$
|
155,036
|
|
$
|
(77,403
|
)
|
$
|
1,165,750
|
|
Cost of sales
|
|
306,431
|
|
246,809
|
|
17,407
|
|
146,997
|
|
(75,889
|
)
|
641,755
|
|
Gross margin
|
|
325,245
|
|
122,654
|
|
69,571
|
|
8,039
|
|
(1,514
|
)
|
523,995
|
|
Operating, general and administrative
|
|
125,053
|
|
63,984
|
|
32,295
|
|
5,696
|
|
(1,514
|
)
|
225,514
|
|
Property and other taxes
|
|
49,297
|
|
19,872
|
|
2,903
|
|
15
|
|
—
|
|
72,087
|
|
Depreciation
|
|
57,172
|
|
14,771
|
|
1,043
|
|
1,427
|
|
—
|
|
74,413
|
|
Reorganization items
|
|
—
|
|
—
|
|
—
|
|
7,529
|
|
—
|
|
7,529
|
|
Operating income (loss)
|
|
93,723
|
|
24,027
|
|
33,330
|
|
(6,628
|
)
|
—
|
|
144,452
|
|
Interest expense
|
|
(46,331
|
)
|
(13,466
|
)
|
—
|
|
(1,498
|
)
|
—
|
|
(61,295
|
)
|
Other income
|
|
7,748
|
|
3,961
|
|
162
|
|
5,029
|
|
—
|
|
16,900
|
|
Income tax expense (benefit)
|
|
(23,198
|
)
|
(5,611
|
)
|
(13,597
|
)
|
3,896
|
|
—
|
|
(38,510
|
)
|
Income from continuing operations
|
|
$
|
31,942
|
|
$
|
8,911
|
|
$
|
19,895
|
|
$
|
799
|
|
$
|
—
|
|
$
|
61,547
|
|
Total assets
|
|
$
|
1,516,581
|
|
$
|
752,945
|
|
$
|
48,195
|
|
$
|
74,210
|
|
$
|
—
|
|
$
|
2,391,931
|
|
Capital expenditures
|
|
$
|
63,302
|
|
$
|
14,033
|
|
$
|
2,566
|
|
$
|
976
|
|
$
|
—
|
|
$
|
80,877
|
|
(24)
|
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:
2007
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
366,565
|
|
$
|
259,608
|
|
$
|
265,863
|
|
$
|
308,024
|
|
Gross margin
|
|
147,287
|
|
118,353
|
|
126,842
|
|
139,173
|
|
Operating income
|
|
44,353
|
|
18,223
|
|
33,238
|
|
44,279
|
|
Net income
|
|
$
|
19,142
|
|
$
|
2,434
|
|
$
|
13,177
|
|
$
|
18,438
|
|
Average common shares outstanding
|
|
35,720
|
|
35,988
|
|
36,471
|
|
38,284
|
|
Income per average common share (basic):
|
|
|
|
|
|
|
|
|
|
Net income from continuing
operations
|
|
$
|
0.54
|
|
$
|
0.07
|
|
$
|
0.36
|
|
$
|
0.48
|
|
Discontinued operations
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Net income
|
|
0.54
|
|
0.07
|
|
0.36
|
|
0.48
|
|
Income per average common share (diluted):
|
|
|
|
|
|
|
|
|
|
Net income from continuing
operations
|
|
$
|
0.51
|
|
$
|
0.06
|
|
$
|
0.35
|
|
$
|
0.52
|
|
Discontinued operations
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Net income
|
|
0.51
|
|
0.06
|
|
0.35
|
|
0.52
|
|
Dividends per share
|
|
$
|
0.31
|
|
$
|
0.31
|
|
$
|
0.33
|
|
$
|
0.33
|
|
Stock price:
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
36.51
|
|
$
|
35.47
|
|
$
|
32.10
|
|
$
|
30.05
|
|
Low
|
|
35.32
|
|
30.60
|
|
25.30
|
|
26.97
|
|
Quarter-end close
|
|
35.43
|
|
31.81
|
|
27.17
|
|
29.50
|
|
F -
38
2006
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
361,482
|
|
$
|
232,186
|
|
$
|
234,637
|
|
$
|
304,348
|
|
Gross margin
|
|
141,810
|
|
114,460
|
|
123,723
|
|
139,078
|
|
Operating income
|
|
42,189
|
|
8,351
|
|
33,490
|
|
26,334
|
|
Net income (loss)
|
|
$
|
21,025
|
|
$
|
(2,446
|
)
|
$
|
11,398
|
|
$
|
7,923
|
|
Average common shares outstanding
|
|
35,584
|
|
35,511
|
|
35,510
|
|
35,613
|
|
Income (loss) per average common share (basic):
|
|
|
|
|
|
|
|
|
|
Net income from continuing
operations
|
|
$
|
0.59
|
|
$
|
(0.08
|
)
|
$
|
0.32
|
|
$
|
0.23
|
|
Discontinued operations
|
|
0.00
|
|
0.01
|
|
0.00
|
|
0.00
|
|
Net income (loss)
|
|
0.59
|
|
(0.07
|
)
|
0.32
|
|
0.23
|
|
Income (loss) per average common share (diluted):
|
|
|
|
|
|
|
|
|
|
Net income from continuing
operations
|
|
$
|
0.58
|
|
$
|
(0.08
|
)
|
$
|
0.31
|
|
$
|
0.19
|
|
Discontinued operations
|
|
0.00
|
|
0.01
|
|
0.00
|
|
0.00
|
|
Net income (loss)
|
|
0.58
|
|
(0.07
|
)
|
0.31
|
|
0.19
|
|
Dividends per share
|
|
$
|
0.31
|
|
$
|
0.31
|
|
$
|
0.31
|
|
$
|
0.31
|
|
Stock price:
|
|
|
|
|
|
|
|
|
|
High
|
|
$
|
32.75
|
|
$
|
35.18
|
|
$
|
35.15
|
|
$
|
35.80
|
|
Low
|
|
30.92
|
|
30.30
|
|
33.77
|
|
35.01
|
|
Quarter-end close
|
|
31.14
|
|
34.35
|
|
34.98
|
|
35.38
|
|
F -
39
SCHEDULE
II.
VALUATION AND QUALIFYING ACCOUNTS
NORTHWESTERN CORPORATION AND SUBSIDIARIES
Column
A
|
|
Column
B
|
|
Column
C
|
|
Column
D
|
|
Column
E
|
|
Description
|
|
Balance
at
Beginning
of
Period
|
|
Charged
to
Costs
and
Expenses
|
|
Deductions
|
|
Balance
End
of
Period
|
|
FOR THE YEAR ENDED
DECEMBER
31, 2007
(in
thousands)
|
|
|
|
|
|
|
|
|
|
RESERVES DEDUCTED FROM APPLICABLE ASSETS
|
|
|
|
|
|
|
|
|
|
Uncollectible accounts
|
|
$
|
3,240
|
|
2,705
|
|
(2,779
|
)
|
3,166
|
|
FOR THE YEAR ENDED
DECEMBER
31, 2006
(in
thousands)
|
|
|
|
|
|
|
|
|
|
RESERVES DEDUCTED FROM APPLICABLE ASSETS
|
|
|
|
|
|
|
|
|
|
Uncollectible accounts
|
|
$
|
2,164
|
|
3,892
|
|
(2,816
|
)
|
3,240
|
|
FOR THE YEAR ENDED
DECEMBER
31, 2005
(in
thousands)
|
|
|
|
|
|
|
|
|
|
RESERVES DEDUCTED FROM APPLICABLE ASSETS
|
|
|
|
|
|
|
|
|
|
Uncollectible accounts
|
|
$
|
2,104
|
|
2,024
|
|
(1,964
|
)
|
2,164
|
|