Attached files
file | filename |
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EX-23 - EX 23 CONSENT - NORTHWESTERN CORP | ex23-1_consent.htm |
EX-21 - EX 21 SUBSIDIARIES - NORTHWESTERN CORP | ex21_subsidiaries.htm |
EX-32.1 - EX 32.1 CERTIFICATION - NORTHWESTERN CORP | ex32-1_certification.htm |
EX-32.2 - EX 32.2 CERTIFICATION - NORTHWESTERN CORP | ex32-2_certification.htm |
EX-10.2 - EX 10.2 BOND PURCHASE AGREEMENT - NORTHWESTERN CORP | ex10-2_bondpurchagmt.htm |
EX-31.2 - EX 31.2 CERTIFICATION (SECTION 302) - NORTHWESTERN CORP | ex31-2_certification.htm |
EX-12.1 - EX 12.1 EARNINGS TO FIXED CHARGES - NORTHWESTERN CORP | ex12-1_earningstofixed.htm |
EX-31.1 - EX 31.2 CERTIFICATION (SECTION 302) - NORTHWESTERN CORP | ex31-1_certification.htm |
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Form 10-K
(Mark
One)
x
|
ANNUAL
REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
|
|
For
the fiscal year ended December 31, 2009
|
||
OR
|
||
¨
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
|
For
the transition period from
to
Commission
File Number: 1-10499
NORTHWESTERN
CORPORATION
(Exact
name of registrant as specified in its charter)
Delaware
|
46-0172280
|
|
(State
or other jurisdiction of
incorporation
or organization)
|
(I.R.S.
Employer
Identification
No.)
|
|
3010
W. 69th
Street, Sioux Falls, South Dakota
|
57108
|
|
(Address
of principal executive offices)
|
(Zip
Code)
|
Registrant’s telephone number,
including area code: 605-978-2900
Securities
registered pursuant to Section 12(b) of the Act:
(Title
of each class)
|
(Name
of each exchange on which registered)
|
|
Common
Stock, $0.01 par value
|
New
York Stock Exchange
|
Securities
registered pursuant to Section 12(g) of the Act:
None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes x No o
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. Yes o No x
Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the past 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes x No o
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Website, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding
12 months (or for shorter period that the registrant was required to submit and
post such files). Yes o No o
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the
best of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. x
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting company (as
defined in Rule 12b-2 of the Exchange Act).
Large
Accelerated Filer x Accelerated
Filer o Non-accelerated
Filer o Smaller
Reporting Company o
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). Yes o No x
The
aggregate market value of the voting and non-voting common stock held by
nonaffiliates of the registrant was $818,036,000 computed using the last sales
price of $22.76 per share of the registrant’s common stock on June 30,
2009, the last business day of the registrant’s most recently completed second
fiscal quarter.
As of
February 5, 2010, 36,005,742 shares of the registrant’s common stock, par value
$0.01 per share, were outstanding.
Documents
Incorporated by Reference
Certain
sections of our Proxy Statement for the 2010 Annual Meeting of
Shareholders
are
incorporated by reference into Part III of this Form 10-K
1
INDEX
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Part I
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Page
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Part II
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Part III
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Part IV
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2
SPECIAL
NOTE REGARDING FORWARD-LOOKING STATEMENTS
On one or
more occasions, we may make statements in this Annual Report on Form 10-K
regarding our assumptions, projections, expectations, targets, intentions or
beliefs about future events. All statements other than statements of historical
facts, included or incorporated by reference in this Annual Report, relating to
management's current expectations of future financial performance, continued
growth, changes in economic conditions or capital markets and changes in
customer usage patterns and preferences are forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934.
Words or
phrases such as “anticipates," “may," “will," “should," “believes," “estimates,"
“expects," “intends," “plans," “predicts," “projects," “targets," “will likely
result," “will continue" or similar expressions identify forward-looking
statements. Forward-looking statements involve risks and uncertainties, which
could cause actual results or outcomes to differ materially from those
expressed. We caution that while we make such statements in good faith and
believe such statements are based on reasonable assumptions, including without
limitation, management's examination of historical operating trends, data
contained in records and other data available from third parties, we cannot
assure you that we will achieve our projections. Factors that may cause such
differences include, but are not limited to:
·
|
potential
adverse federal, state, or local legislation or regulation or adverse
determinations by regulators could have a material adverse effect on our
liquidity, results of operations and financial
condition;
|
·
|
changes
in availability of trade credit, creditworthiness of counterparties,
usage, commodity prices, fuel supply costs or availability due to higher
demand, shortages, weather conditions, transportation problems or other
developments, may reduce revenues or may increase operating costs, each of
which could adversely affect our liquidity and results of
operations;
|
·
|
unscheduled
generation outages or forced reductions in output, maintenance or repairs,
which may reduce revenues and increase cost of sales or may require
additional capital expenditures or other increased operating costs;
and
|
·
|
adverse
changes in general economic and competitive conditions in the U.S.
financial markets and in our service
territories.
|
We have
attempted to identify, in context, certain of the factors that we believe may
cause actual future experience and results to differ materially from our current
expectation regarding the relevant matter or subject area. In addition to the
items specifically discussed above, our business and results of operations are
subject to the uncertainties described under the caption “Risk Factors" which is
part of the disclosure included in Part I, Item 1A of this Annual
Report.
From time
to time, oral or written forward-looking statements are also included in our
reports on Forms 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases,
analyst and investor conference calls, and other communications released to the
public. We believe that at the time made, the expectations reflected in all of
these forward-looking statements are and will be reasonable. However, any or all
of the forward-looking statements in this Annual Report on Form 10-K, our
reports on Forms 10-Q and 8-K, our Proxy Statements on Schedule 14A and any
other public statements that are made by us may prove to be incorrect. This may
occur as a result of assumptions, which turn out to be inaccurate or as a
consequence of known or unknown risks and uncertainties. Many factors discussed
in this Annual Report on Form 10-K, certain of which are beyond our control,
will be important in determining our future performance. Consequently, actual
results may differ materially from those that might be anticipated from
forward-looking statements. In light of these and other uncertainties, you
should not regard the inclusion of any of our forward-looking statements in this
Annual Report on Form 10-K or other public communications as a representation by
us that our plans and objectives will be achieved, and you should not place
undue reliance on such forward-looking statements.
3
We
undertake no obligation, to publicly update or revise any forward-looking
statements, whether as a result of new information, future events or otherwise.
However, your attention is directed to any further disclosures made on related
subjects in our subsequent annual and periodic reports filed with the Securities
and Exchange Commission (SEC) on Forms 10-K, 10-Q and 8-K and Proxy Statements
on Schedule 14A.
Unless
the context requires otherwise, references to “we,” “us,” “our,” “NorthWestern
Corporation,” “NorthWestern Energy,” and “NorthWestern” refer specifically to
NorthWestern Corporation and its subsidiaries.
4
GLOSSARY
Accounting Standards Codification
(ASC) - The single source of authoritative nongovernmental GAAP, which
supersedes all existing accounting standards.
Allowance for Funds Used During
Construction (AFUDC) - A regulatory accounting convention that
represents the estimated composite interest costs of debt and a return on equity
funds used to finance construction. The allowance is capitalized in the property
accounts and included in income.
Base-Load - The minimum amount
of electric power or natural gas delivered or required over a given period of
time at a steady rate. The minimum continuous load or demand in a power system
over a given period of time usually is not temperature sensitive.
Base-Load Capacity - The
generating equipment normally operated to serve loads on an around-the-clock
basis.
Competitive Transition Charges
- Out of market energy costs associated with the change of an industry from a
regulated, bundled service to a competitive open-access service.
Cushion Gas - The natural gas
required in a gas storage reservoir to maintain a pressure sufficient to permit
recovery of stored gas.
Deregulation - In the energy
industry, the process by which regulated markets become competitive markets,
giving customers the opportunity to choose their energy supplier.
Environmental Protection Agency
(EPA) - A Federal agency charged with protecting the
environment.
Federal Energy Regulatory Commission
(FERC) - The Federal agency that has jurisdiction over interstate
electricity sales, wholesale electric rates, hydroelectric licensing, natural
gas transmission and related services pricing, oil pipeline rates and gas
pipeline certification.
Franchise - A special
privilege conferred by a unit of state or local government on an individual or
corporation to occupy and use the public ways and streets for benefit to the
public at large. Local distribution companies typically have exclusive
franchises for utility service granted by state or local
governments.
GAAP - Accounting principles
generally accepted in the United States of America.
Hedging - Entering into
transactions to manage various types of risk (e.g. commodity risk).
Hinshaw Exemption - A pipeline
company (defined by the Natural Gas Act (NGA) and exempted from FERC
jurisdiction under the NGA) defined as a regulated company engaged in
transportation in interstate commerce, or the sale in interstate commerce for
resale, of natural gas received by that company from another person within or at
the boundary of a state, if all the natural gas so received is ultimately
consumed within such state. A pipeline company with a Hinshaw exemption may
receive a certificate authorizing it to transport natural gas out of the state
in which it is located, without giving up its Hinshaw exemption.
Lignite Coal - The lowest rank
of coal, often referred to as brown coal, used almost exclusively as fuel for
steam-electric power generation. It has high inherent moisture content,
sometimes as high as 45 percent. The heat content of lignite ranges from 9 to 17
million Btu per ton on a moist, mineral-matter-free basis.
Midcontinent Area Power Pool
(MAPP) - A voluntary association of electric utilities and other electric
industry participants that acts as a regional transmission group, responsible
for facilitating open access of the transmission system and a generation reserve
sharing pool to meet regional demand.
Midwest Independent Transmission
System Operator (MISO) - The MISO is a nonprofit organization created in
compliance with FERC as a Regional Transmission Organization, to improve the
flow of electricity in the regional marketplace and to enhance electric
reliability. Additionally, MISO is responsible for managing the energy markets,
managing transmission constraints, managing the day-ahead, real-time and
financial transmission rights markets and managing the ancillary
market.
5
Montana Public Service Commission
(MPSC) - The state agency that regulates public utilities doing business
in Montana.
Nebraska Public Service Commission
(NPSC) - The state agency that regulates public utilities doing business
in Nebraska.
North American Electric Reliability
Corporation (NERC) - NERC oversees eight regional reliability entities
and encompasses all of the interconnected power systems of the contiguous United
States. NERC's major responsibilities include developing standards for power
system operation, monitoring and enforcing compliance with those standards,
assessing resource adequacy, and providing educational and training resources as
part of an accreditation program to ensure power system operators remain
qualified and proficient.
Open Access -
Non-discriminatory, fully equal access to transportation or transmission
services offered by a pipeline or electric utility.
Open Access Transmission Tariff
(OATT) -The OATT, which is established by the FERC, defines the terms and
conditions of point-to-point and network integration transmission services
offered by us, and requires that transmission owners provide open,
non-discriminatory access on their transmission system to transmission
customers.
Open Season - A period of time
in which potential customers can bid for services, and during which such
customers are treated equally regarding priority in the queue for
service.
Peak Load - A measure of the
maximum amount of energy delivered at a point in time.
Qualifying Facility (QF) - As
defined under the Public Utility Regulatory Policies Act of 1978, a QF sells
power to a regulated utility at a price determined by a public service
commission that is intended to be equal to that which the utility would
otherwise pay if it were to build its own power plant or buy power from another
source.
Regional Transmission Organization
(RTO) - An independent entity, which is established to have “functional
control" over utilities' transmission systems, to expedite transmission of
electricity. RTO's typically operate markets within their
territories.
Securities and Exchange Commission
(SEC) - The U.S. agency charged with protecting investors, maintaining
fair, orderly and efficient markets and facilitating capital
formation.
South Dakota Public Utilities
Commission (SDPUC) - The state agency that regulates public utilities
doing business in South Dakota.
Sub-bituminous Coal - A coal
whose properties range from those of lignite to those of bituminous coal and
used primarily as fuel for steam-electric power generation. Sub-bituminous coal
contains 20 to 30 percent inherent moisture by weight. The heat content of
sub-bituminous coal ranges from 17 to 24 million Btu per ton on a moist,
mineral-matter-free basis.
Tariffs - A collection of the
rate schedules and service rules authorized by a federal or state commission. It
lists the rates a regulated entity will charge to provide service to its
customers as well as the terms and conditions that it will follow in providing
service.
6
Test Period - In a rate case,
a test period is used to determine the cost of service upon which the utility's
rates will be based. A test period consists of a base period of twelve
consecutive months of recent actual operational experience, adjusted for changes
in revenues and costs that are known and are measurable with reasonable accuracy
at the time of the rate filing and which will typically become effective within
nine months after the last month of actual data utilized in the rate
filing.
Tolling Contract - An
arrangement whereby a party moves fuel to a power generator and receives
kilowatt hours (kWh) in return for a pre-established fee.
Transmission - The flow of
electricity from generating stations over high voltage lines to substations. The
electricity then flows from the substations into a distribution
network.
Western Area Power Administration
(WAPA) - One of five federal power-marketing administrations and electric
transmission agencies established by Congress.
Western Electricity Coordination
Council (WECC) - WECC is one of eight regional electric reliability
councils under NERC.
Measurements:
Billion Cubic Feet (Bcf) - A
unit used to measure large quantities of gas, approximately equal to 1 trillion
Btu.
British Thermal Unit (Btu) - a
basic unit used to measure natural gas; the amount of natural gas needed to
raise the temperature of one pound of water by one degree
Fahrenheit.
Degree-Day - A measure of the
coldness / warmness of the weather experienced, based on the extent to which the
daily mean temperature falls below or above a reference
temperature.
Dekatherm - A measurement of
natural gas; ten therms or one million Btu.
Kilovolt (kV) - A unit of
electrical power equal to one thousand volts.
Megawatt (MW) - A unit of
electrical power equal to one million watts or one thousand
kilowatts.
Megawatt Hour (MWH) - One
million watt-hours of electric energy. A unit of electrical energy which equals
one megawatt of power used for one hour.
7
Part
I
OVERVIEW
NorthWestern
Corporation, doing business as NorthWestern Energy, provides electricity and
natural gas to approximately 661,000 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
generated and distributed electricity and distributed natural gas in Montana
since 2002.
We were
incorporated in Delaware in November 1923. Our Annual Report on Form 10-K, our
Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments
to such reports filed or furnished pursuant to section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended, along with our annual report to
shareholders and other information related to us, are available, free of charge,
on our Internet website as soon as reasonably practicable after we
electronically file those documents with, or otherwise furnish them to, the SEC.
This information is available in print to any shareholder who requests it.
Requests should be directed to: Investor Relations, NorthWestern Corporation,
3010 W. 69th Street, Sioux Falls, South Dakota 57108 and our telephone number is
(605) 978-2900. We maintain an Internet website at http://www.northwesternenergy.com.
Our Internet website and the information contained therein or connected thereto
are not intended to be incorporated by reference into this Annual Report on Form
10-K and should not be considered a part of this Annual Report on Form
10-K.
We
operate our business in the following reporting segments:
·
|
Regulated
electric operations;
|
·
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Regulated
natural gas operations;
|
·
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All
other, which primarily consists of a remaining unregulated natural gas
contract, the wind down of our captive insurance subsidiary and our
unallocated corporate costs.
|
SIGNIFICANT
DEVELOPMENTS
Effective
January 1, 2009, our joint ownership interest in Colstrip Unit 4 was placed
into Montana utility rate base due to an MPSC order and is reflected in our
regulated operations as a component of electric supply. Previously, this asset
was reflected in our unregulated electric segment. We have not revised the
presentation of the prior years segmented financial results due to the nature of
the transfer of the asset from unregulated to the regulated business. For
financial information regarding these segments, see Note 19 to the Consolidated
Financial Statements.
We began
construction in June 2009 on the Mill Creek Generating Station, which will
provide regulating resources to balance our transmission system in Montana to
maintain reliability and enable wind power to be integrated onto the network to
meet renewable energy portfolio needs. The project is estimated to cost
approximately $202 million and is scheduled to be operational by December 31,
2010. In addition, we have proposed three major transmission projects in Montana
– the Colstrip Upgrade, Collector Project and MSTI – to facilitate development
of new generation. The Colstrip Upgrade involves an expansion of the existing
Colstrip 500 kV system including an additional substation and related
electrical equipment to increase westbound capacity out of Montana by more than
500 MW. The Collector Project consists of up to five new transmission lines in
Montana that would connect new generation, primarily wind farms, to our existing
transmission system and to the proposed MSTI line. All of the new proposed wind
generation that would be served by the Collector Project would be located in
Montana. MSTI is a proposed 500kV transmission line from southwestern Montana to
southeastern Idaho. For further discussion of these projects, see the Strategy
section in Management’s Discussion and Analysis of Financial Condition and
Results of Operations.
8
REGULATED
ELECTRIC OPERATIONS
MONTANA
Our
regulated electric utility business in Montana includes generation, transmission
and distribution. Our service territory covers approximately 107,600 square
miles, representing approximately 73% of Montana's land area, and includes a
population of approximately 786,000 according to the 2000 census. We deliver
electricity to approximately 335,000 customers in 187 communities and their
surrounding rural areas, 15 rural electric cooperatives and in Wyoming to the
Yellowstone National Park. In 2009, by category, residential, commercial and
industrial, and other sales accounted for approximately 33%, 46%, and 21%,
respectively, of our Montana regulated electric utility revenue. We also
transmit electricity for nonregulated entities owning generation facilities,
other utilities and power marketers serving the Montana electricity market. The
total control area peak demand was approximately 1,766 MWs, the average daily
load was approximately 1,216 MWs, and more than 10.6 million MWHs were
supplied during the year ended December 31, 2009.
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 WECC area, as well as one interconnection to a nonaffiliated system that
connects with the MAPP region. With these interconnections, we transmit power to
and from diverse interstate transmission systems, including those operated by
Avista Corporation; Idaho Power Company; PacifiCorp; the Bonneville Power
Administration; and WAPA.
Our
Montana electric distribution system consists of approximately 21,400 miles of
overhead and underground distribution lines and 336 transmission and
distribution substations.
Electric
Supply
Our joint
ownership interest in Colstrip Unit 4 is expected to supply approximately 13% of
our Montana base-load requirements through 2010 and approximately 25%
thereafter. During 2009, we purchased the remaining quantity of our Montana
capacity and energy requirements from third parties. Our annual electric supply
load requirements average approximately 730 MWs. We currently have under
contract approximately 75% of the energy requirements necessary to meet our
projected load requirements through June 30, 2010, with approximately 74% at
fixed prices. For the period July 1, 2010 through June 30, 2011, we have under
contract approximately 76% of our projected load requirements, with
approximately 75% 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. We
also purchase power under several QF contracts entered into under the Public
Utility Regulatory Policies Act of 1978, which provide a total of 114 MWs of
contracted capacity. We have several other long and medium-term power purchase
agreements including contracts for 148 MWs of wind generation and 14 MWs of
seasonal base-load hydro supply, with an additional 13 MW of seasonal hydro
under contract and expected to begin commercial operation in 2011. We file a
biennial Electric Supply Resource Procurement Plan with the MPSC which guides
future resource acquisition activities. We expect to file the next plan in April
2010.
Renewable
portfolio standards enacted in Montana require that a certain portion of our
electric supply be obtained from renewable sources, including wind, biomass,
solar and small hydroelectric. The requirements are currently 5%, increasing to
10% by 2010 and 15% by 2015. Based on our current projections, we believe we
will meet these requirements. Approximately 8% of our electric supply
requirements for 2009 were from renewable resources. The amounts in excess of
the annual requirements can be carried forward to future periods. In addition to
the general renewable requirements, beginning in 2012, under a separate
Community Renewable Energy Project provision, we are required to purchase output
from community projects that total approximately 45 MWs in nameplate
capacity.
9
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 electric supply procurement
activities as part of the annual electric tracker 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 certain securities, incurrence of
certain long-term debt, and compliance with mandatory reliability regulations,
among other things.
In
Montana, we sell transmission service across our system under terms, conditions
and rates defined in our OATT, on file with FERC. We are required to provide
retail transmission service in Montana under MPSC approved tariffs for customers
still receiving “bundled" service and under the OATT for other wholesale
transmission customers such as cooperatives. 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 Order
890.
In
January 2009, we filed a request with the FERC seeking negotiated rates for the
proposed MSTI project and to directly assign the cost of the Collector Project
to the generators. The request for negotiated rates for MSTI was not for
specific rates; rather, it was for confirmation from the FERC that MSTI would
satisfy the FERC’s negotiated rate criteria. As a transmission export project in
a region that lacks a RTO, MSTI would have no readily available regional tariff
through which to recover costs and thereby mitigate project development risk.
The request was based on a rate approach that FERC had approved for similar
projects in the region, which would provide us with the flexibility to meet
market demand from primarily new renewable generation resources in Montana and
to insulate our native load customers from the costs and risks of the project.
FERC issued an order in May 2009 denying our request for negotiated rates, and
encouraged us to meet our needs by pursuing the MSTI project on a
cost-of-service basis by requesting appropriate waivers under our OATT. As to
the Collector Project, FERC approved our proposal to directly assign the cost of
the project to the generators. This also has the effect of insulating native
load customers from the cost of the project. While FERC deferred ruling on our
request for tariff waivers, FERC specifically found the proposed Collector
Project open season process to be a reasonable means of accommodating a large
number of interconnection requests in the queue.
NERC Reliability
- The Energy Policy Act of 2005 added a requirement for FERC to certify
an Electric Reliability Organization (ERO) to develop mandatory and enforceable
electric system reliability standards. FERC has certified the NERC as the ERO to
develop these standards subject to FERC review and approval. On March 16, 2007,
FERC issued Order 693, Mandatory Reliability Standards for the Bulk-Power
System, which imposes penalties of up to $1.0 million per day per violation for
failure to comply with new electric reliability standards. FERC initially
approved 83 reliability standards developed by NERC. The 83 standards comprise
over 550 requirements and sub-requirements. We must comply with the standards
and requirements, which apply to the NERC functions for which we have registered
in both the MRO (Midwest Reliability Organization) for our South Dakota
operations and the WECC for our Montana operations. WECC has responsibility for
monitoring and enforcing compliance with the FERC approved mandatory reliability
standards within the western interconnection of the United States. Additional
standards continue to be developed and will be adopted in the future. We expect
that the existing standards will change often as a result of modifications,
guidance and clarification following industry implementation and ongoing audits
and enforcement.
We
completed our compliance audit for our Montana operations under the compliance
monitoring and enforcement program of the WECC during 2009. In connection with
the compliance audit, WECC found no violations of the applicable standards.
Since June 2007, we have identified and self-reported violations of 32
requirements to WECC. All but nine of these violations were dismissed or were
subject to expedited dispositions with no penalties. During the fourth quarter
of 2009, we reached a settlement agreement with WECC addressing six of the
remaining nine violations for a total penalty of $80,000, which has been
accrued. The settlement is pending formal NERC and FERC approval. The remaining
three violations all relate to one standard and this standard is pending a NERC
interpretation. We also filed mitigation plans for two potential violations with
the MRO for our South Dakota operations. We have completed the mitigation
measures in compliance with the plans and expect to hear from the MRO during the
first half of 2010 of any further action. We expect our compliance with NERC
standards will be audited at least every three years.
10
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 allows the participating utilities to net their control error
balances across the participating utilities, rather than requiring each utility
to balance on a one-to-one basis, which allows the utilities to stay in balance
as a group (and make less generation level movements (regulating service) to
stay in balance), thereby reducing the costs of staying in compliance with
NERC’s requirements. Since the initial implementation, thirteen additional
Balancing Authorities (BAs) have signed the ADI agreement. Seven BAs have fully
implemented the system and two BAs are expected to complete implementation in
early 2010. The remaining four are expected to complete implementation in the
third quarter of 2010. The BAs are located in the Pacific Northwest and
Southwest regions of the WECC Interconnection.
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.
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 removed 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 permits
utilities to build and own electric generation assets that would be included in
utility cost of service. In addition, the bill provided for a timely advanced
approval process for electric supply resource projects and requires carbon
offsets to reduce carbon dioxide emissions.
Mill Creek
Generating Station - In August 2008, we filed a request with the MPSC for
advanced approval to construct a 150 MW natural gas fired facility. The
Mill Creek Generating Station, estimated to cost approximately $202 million,
will provide energy supply and transmission regulating resources to balance our
transmission system in Montana. In May 2009, the MPSC issued an order granting
approval to construct the facility, authorizing a return on equity of 10.25% and
a preliminary cost of debt of 6.5%, with a capital structure of 50% equity and
50% debt. In addition, the MPSC determined the $81 million cost for the
turbines is prudent, with the remainder of the project costs to be submitted to
the MPSC for review and approval once construction of the facility is complete.
Construction began in June 2009, and the plant is scheduled to be operational by
December 31, 2010.
Montana General
Rate Case - In October 2009, we filed
a request with the MPSC for an annual electric transmission and distribution
revenue increase of $15.5 million, and an annual natural gas transmission,
storage and distribution revenue increase of $2.0 million. The request was
based on a 2008 test period, a return on equity of 10.9%, an equity ratio of
49.45% and rate base of $632.2 million and $256.6 million for electric
and natural gas, respectively.
In
November 2009, the MPSC issued a determination that the rate case filing did not
meet the MPSC’s applicable minimum filing requirements, related to allocated
cost of service and rate design. We submitted a supplemental filing on January
15, 2010 to meet the MPSC’s minimum filing requirements, which was accepted as
compliant on February 2, 2010. We have agreed to extend the timeframe by which
the MPSC must issue a final order concerning the general rate filing by 90 days
to October 11, 2010. We requested interim rate adjustments, which may be
authorized during the processing of the filing if the MPSC finds it meets the
established criteria. Final rate adjustments would become effective upon the
issuance of a final order on this matter.
11
Cost
Recovery Clauses
Electric and Natural Gas Supply
Trackers - Rates
for our Montana electric and natural gas supply are set by the MPSC. Each year
we submit electric and natural gas tracker filings for recovery of supply costs.
The MPSC reviews such filings and makes its cost recovery determination based on
whether or not our electric and natural gas energy supply procurement activities
were prudent. If the MPSC subsequently determines that a procurement activity
was imprudent, then it may disallow such costs.
On May
30, 2008, we filed an annual electric supply cost tracker request with the MPSC
for any unrecovered actual electric supply costs for the 12-month period ended
June 30, 2008 and for the projected electric supply costs for the 12-month
period ended June 30, 2009. On June 27, 2008, the MPSC issued an interim order
approving recovery of our projected electric supply costs. On May 29, 2009, we
filed an annual electric supply cost tracker request with the MPSC for any
unrecovered actual electric supply costs for the 12-month period ended June 30,
2009 and for the projected electric supply costs for the 12-month period ended
June 30, 2010. On June 26, 2009, the MPSC issued an interim order approving
recovery of our projected electric supply costs. Our annual electric supply cost
tracker requests for the 12-month periods ended June 30, 2008 and June 30, 2009
were combined and are still pending final approval of the MPSC. The MCC disputed
(1) our ability to use financial swaps in purchasing electricity supply, (2) the
recovery of certain labor costs associated with real-time schedulers and (3) our
estimated revenues associated with demand side management for our Colstrip Unit
4 generation asset. During the fourth quarter of 2009, we entered into a
settlement with the MCC agreeing to (a) withdraw our request to use financial
swaps, (b) remove approximately $100,000 in labor costs and (c) remove
approximately $83,000 of calculated lost revenues from the tracker. On February
3, 2010, the MPSC conducted a hearing to review the filings and resulting
settlement and scheduled additional briefing for March 2010.
On June
2, 2009, we filed an annual gas cost tracker request with the MPSC for any
unrecovered actual gas costs for the 12-month period ended June 30, 2009, and
for the projected gas costs for the 12-month period ending June 30, 2010. On
June 24, 2009, the MPSC issued an interim order, approving recovery of our
projected gas costs pending its review. No procedural schedule has been
established for this request.
Montana Property Tax
Tracker - In
December 2009, we filed our annual property tax tracker (including other
state/local taxes and fees) with the MPSC for an automatic rate adjustment,
which reflected 60% of the change in 2009 actual property taxes and estimated
property taxes for 2010. This filing also included an adjustment for property
taxes related to Colstrip Unit 4. In our 2008 filing requesting to include our
interest in Colstrip Unit 4 in utility rate base, we estimated base property
taxes would be approximately $5.5 million, by multiplying the rate base value by
the latest known mill levy. This filing was approved by the MPSC. Actual 2009
Colstrip Unit 4 related property taxes were approximately $2.1 million and we
proposed refunding 60% of the change to customers, consistent with previous MPSC
orders. In January 2010, the MPSC issued an order requiring us to reset the base
rates for Colstrip, effectively requiring us to refund 100% of the change in
property taxes from our original 2008 filing. While we have accounted for our
property tax tracker consistent with the MPSC’s January 2010 order, we are
disputing various aspects of the order and have filed a Motion for
Reconsideration with the MPSC.
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 60,500 customers in 110 communities in South Dakota. In 2009, by
category, residential, commercial and industrial, wholesale, and other sales
accounted for approximately 39%, 55%, 5% and 1%, respectively, of our South
Dakota electric utility revenue. Peak demand was approximately 284 MWs, the
average daily load was approximately 162 MWs, and more than 1.42 million MWHs
were supplied during the year ended December 31, 2009.
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.
12
Our
transmission and distribution network in South Dakota consists of approximately
3,300 miles of overhead and underground transmission and distribution lines as
well as 123 substations. We have interconnection and pooling arrangements with
the transmission facilities of Otter Tail Power Company; Montana-Dakota
Utilities Co.; Xcel Energy Inc.; and WAPA. We have emergency interconnections
with the transmission facilities of East River Electric Cooperative, Inc. and
West Central Electric Cooperative. These interconnection and pooling
arrangements enable us to arrange purchases or sales of substantial quantities
of electric power and energy with other pool members and to participate in the
efficiency benefits of pool arrangements.
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, as described above, to all present and future electric customers
within our assigned territory for so long as the service provided is adequate.
We are not aware of any allegations of inadequate service since assignment in
1976. The assignment of a service territory is perpetual under current South
Dakota law; however, the local government of each of the municipalities we serve
does have the right to condemn our facilities and establish a municipal utility
distribution system.
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 is sold in the competitive wholesale market. In
2009, this was approximately 14% of our share of the power generated. We use
market purchases and internal peaking generation to provide peak supply in
excess of our base-load capacity.
Name and Location of Plant
|
Fuel Source
|
Our
Ownership
Interest
|
Our Share of 2009
Peak Summer
Demonstrated
Capacity
(MW)
|
% of Total 2009
Peak Summer
Demonstrated
Capacity
|
|||||
Big
Stone Plant, located near Big Stone City in northeastern South
Dakota
|
Sub-bituminous
coal
|
23.4
|
%
|
110.54
|
35.4
|
%
|
|||
Coyote
I Electric Generating Station, located near Beulah, North
Dakota
|
Lignite
coal
|
10.0
|
42.70
|
13.7
|
|||||
Neal
Electric Generating Unit No. 4, located near Sioux
City, Iowa
|
Sub-bituminous
coal
|
8.7
|
56.83
|
18.2
|
|||||
Miscellaneous
combustion turbine units and small diesel units (used only
during peak periods)
|
Combination
of fuel oil and natural gas
|
100.0
|
102.14
|
32.7
|
|||||
Total
Capacity
|
312.21
|
100.0
|
%
|
Legislation
passed in 2008 in South Dakota established a voluntary renewable and recycled
energy objective for retail providers of electricity. The objective states that
10% of all electricity sold at retail within South Dakota by 2015 be obtained
from renewable energy and recycled energy sources. In December 2008, we entered
into a 20-year power purchase
agreement for 25
MWs of electric supply from the Titan I Wind Project in Hand County, South
Dakota. Under this agreement, at the end of the fourth and fifth contract year
we have an option to purchase the project. In addition, if additional capacity
is built we have the first right of refusal to purchase the output. The
commercial operation date was November 25, 2009. This power is expected to cover
approximately 5% of our load and is the first renewable source of energy to be
made available to customers in South Dakota. We are in the process of conducting
Request for Proposals (RFP) for additional renewable resources in South Dakota
in order to meet this objective.
13
MidAmerican
provided 71 MWs of firm capacity during the summer months of 2009 and we have an
agreement with them to supply firm capacity of 74 MWs in 2010, 77 MWs in 2011
and 80 MWs in 2012, pending transmission availability. 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 believe we have
adequate base-load generation capacity to meet customer supply needs through at
least 2015. 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, 2009. 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 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:
Cost per Million Btu for the
Year Ended December 31,
|
Percent of 2009
|
|||||||||||
Fuel Type
– Generating Station
|
2009
|
2008
|
2007
|
MWH
Generated
|
||||||||
Sub-bituminous-Big
Stone
|
$
|
1.85
|
$
|
1.77
|
$
|
1.55
|
51.8
|
%
|
||||
Lignite-Coyote
|
1.19
|
1.18
|
1.06
|
19.5
|
||||||||
Sub-bituminous-Neal
|
1.37
|
1.24
|
1.15
|
28.3
|
||||||||
Natural
Gas
|
5.44
|
8.52
|
7.41
|
0.2
|
||||||||
Oil
|
15.82
|
19.34
|
13.11
|
0.2
|
During
the year ended December 31, 2009, the average delivered cost per ton of fuel
burned for our base-load plants was $30.41 at Big Stone, $16.41 at Coyote and
$19.64 at Neal #4. The average delivered cost by type of fuel burned varies
between generation facilities due to differences in transportation costs and
owner purchasing power for coal supply. Changes in our fuel costs are passed on
to customers through the operation of the fuel adjustment clause in our South
Dakota tariffs.
The Big
Stone facility currently burns sub-bituminous coal from the Powder River Basin
delivered under a contract through 2010. Big Stone is in process of submitting a
request for proposal for coal supply through 2012. 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.
14
The South
Dakota Department of Environment and Natural Resources has given approval for
Big Stone to burn a variety of alternative fuels, including tire-derived fuel
and refuse-derived fuel. In 2009, approximately 0.3% of the fuel consumption at
Big Stone 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,
Coyote, and Neal #4 plants to our South Dakota transmission system. We have a
10-year agreement, expiring December 31, 2010, with WAPA for transmission
services, including transmission of electricity from Big Stone, Coyote, and Neal
#4 to our South Dakota service areas through seven points of interconnection on
WAPA's system. We anticipate renewing this agreement with WAPA in advance of the
expiration date. Transmission services under this agreement, and our costs for
such services, are variable and depend upon a number of factors, including the
respective parties' system peak demand and the number of our transmission assets
that are integrated into WAPA's system. In 2009, our costs for services under
this contract totaled approximately $6.1 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 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 have
negotiated a settlement as a grandfathered agreement with MISO and the other Big
Stone 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 not participating in the MISO markets
directly, but continue to utilize WAPA to handle our scheduling and power
marketing activities who does utilize the MISO market. MISO
provides the reliability coordinator functions for MAPP. We updated
the South Dakota OATT to accommodate the required planning functions that rely
heavily on MAPP’s planning process and MAPP’s coordination with
MISO.
See the
“Montana - FERC Regulation” section for a discussion of the NERC compliance
requirements also applicable to our South Dakota operations.
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 180,100 customers in 105 Montana
communities. We also serve several smaller distribution companies
that provide service to approximately 32,000 customers. Our natural gas
distribution system consists of approximately 4,100 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 40 Bcf, and our peak capacity was approximately 335,000 dekatherms
per day during the year ended December 31, 2009.
15
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 325,000 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 17.75 Bcf and maximum aggregate daily
deliverability of approximately 195,000 dekatherms.
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, 19 of our municipal
franchises, which account for approximately 79,900 customers, are scheduled to
expire. Our policy is to seek renewal of a franchise in the last year of its
term.
Natural
Gas Supply
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 is intended to enable us to maintain a diversified supply of natural gas
sufficient to meet our supply requirements. We benefit from direct access to
suppliers in the major natural gas producing regions in the United States,
primarily the Rockies (Colorado), 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, 2009, were approximately
21 Bcf. We have contracted with several major producers and marketers
with varying contract durations to provide the anticipated supply to meet
ongoing requirements.
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. Our gas supply purchases
are also 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 gas procurement activities
as part of this annual gas tracking filing.
We filed
a Biennial Natural Gas Procurement Plan in December 2008. This gas plan provides
the MPSC the blueprint we will follow in procuring natural gas supply to meet
our gas supply needs and reliability requirements and the implementation of
hedging strategies to reduce price volatility.
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.
16
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 our operations.
Montana General
Rate Case – See “Regulated Electric Operations – Montana - MPSC
Regulation – Montana General Rate Case” for a discussion of the Montana general
rate filing.
SOUTH DAKOTA AND
NEBRASKA
We
provide natural gas to approximately 85,100 customers in 60 South Dakota
communities and four Nebraska communities. We have approximately 2,300 miles of
underground distribution pipelines in South Dakota and Nebraska. In
South Dakota, we also transport natural gas for five gas-marketing firms and
three 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 22.2 Bcf of third-party
transportation volume on our South Dakota distribution system and approximately
2.1 Bcf of third-party transportation volume on our Nebraska distribution system
during 2009.
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 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, 47 of
our South Dakota and Nebraska municipal franchises, which account for
approximately 59,700 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 Supply
Our South
Dakota natural gas supply requirements for the year ended December 31, 2009,
were approximately 6.25 Bcf. We have contracted with Tenaska Marketing
Ventures, Inc. in South Dakota to manage transportation, storage and procurement
of supply to minimize cost and price volatility to our customers.
Our
Nebraska natural gas supply requirements for the year ended December 31, 2009,
were approximately 5.4 Bcf. Our Nebraska natural gas supply, storage and
pipeline requirements are fulfilled primarily through a third-party contract
with ONEOK Energy Services Co., which expires June 30, 2010. We are currently
evaluating vendors for this contract.
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 one
propane-air gas peaking unit with a peak daily capacity of approximately 4,140
Mcf. These plants provide an economic alternative to pipeline transportation
charges to meet the peaks caused by customer demand on extremely cold
days.
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.
17
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. Usage for these customers is
monitored daily through electronic metering equipment by us and balanced against
respective supply agreements.
NPSC
Regulation
Our
Nebraska natural gas rates and terms and conditions of service for residential
and smaller commercial customers are regulated by the NPSC. High volume
customers are not subject to such regulation but can file complaints if they
allege discriminatory treatment. Under the Nebraska State Natural Gas Regulation
Act, a regulated natural gas utility may propose a change in rates to its
regulated customers, if it files an application for a rate increase with the
NPSC and with the communities in which it serves customers. The utility may
negotiate with those communities for a settlement with regard to the rate
change, or it may proceed to have the NPSC review the filing and make a
determination.
Subsequent
to the 2004 enactment of the State Natural Gas Regulation Act, our tariffs have
been accepted by the NPSC, and the NPSC has adopted certain rules governing the
terms and conditions of service of regulated natural gas utilities. Our retail
natural gas tariffs provide residential, general service and commercial and
industrial options, as well as firm and interruptible transportation service. A
purchased gas adjustment clause provides for adjustments based on changes in gas
supply and interstate pipeline transportation costs.
SEASONALITY
AND CYCLICALITY
Our
electric and gas utility businesses are seasonal businesses, and weather
patterns can have a material impact on operating performance. Because natural
gas is used primarily for residential and commercial heating, the demand for
this product depends heavily upon weather patterns throughout our market areas,
and a significant amount of natural gas revenues are recognized in the first and
fourth quarters related to the heating season. Demand for electricity is often
greater in the summer and winter months for cooling and heating, respectively.
Accordingly, our operations have historically generated less revenues and income
when weather conditions are milder in the winter and cooler in the summer. When
we experience unusually mild winters or summers in the future, these weather
patterns could adversely affect our results of operations, financial condition
and liquidity.
18
ENVIRONMENTAL
The
operation of electric generating, transmission and distribution facilities, and
gas transportation and distribution facilities, along with the development
(involving site selection, environmental assessments, and permitting) and
construction of these assets, are subject to extensive federal, state, and local
environmental and land use laws and regulations. Our activities involve
compliance with diverse laws and regulations that address emissions and impacts
to air and water, and protection of natural resources. We continuously monitor
federal, state, and local environmental initiatives to determine potential
impacts on our financial results. As new laws or regulations are promulgated,
our policy is to assess their applicability and implement the necessary
modifications to our facilities or their operation to maintain ongoing
compliance.
Our
environmental exposure includes a number of components, including remediation
expenses related to the cleanup of current or former properties, and costs to
comply with changing environmental regulations related to our operations. At
present, the majority of our environmental reserve relates to the remediation of
former manufactured gas plant (MGP) sites owned by us. We use a combination of
site investigations and monitoring to formulate an estimate of environmental
remediation costs for specific sites. Our monitoring procedures and development
of actual remediation plans depend not only on site specific information but
also on coordination with the different environmental regulatory agencies in our
respective jurisdictions, therefore, while remediation exposure exists, it may
be many years before costs become fixed and reliably determinable.
Our
liability for environmental remediation obligations is estimated to range
between $22.4 million to $44.1 million. As of December 31, 2009, we have a
reserve of approximately $31.9 million. Environmental costs are recorded when it
is probable we are liable for the remediation and we can reasonably estimate the
liability. Over time, as specific laws are implemented and we gain experience in
operating under them, a portion of the costs related to such laws will become
determinable, and we may seek authorization to recover such costs in rates or
seek insurance reimbursement as applicable; therefore, we do not expect these
costs to have a material adverse effect on our consolidated financial position
or ongoing operations. There can be no assurance, however, of regulatory
recovery.
Global
Climate Change
We have a
joint 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. In addition, a significant portion of the electric supply we procure
in the market is generated by coal-fired plants.
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 gas emissions. Recently, two federal courts of appeal reinstated
nuisance claims against emitters of carbon dioxide, including several utility
companies, alleging that such emissions contribute to global
warming.
Specifically,
coal-fired plants have come under scrutiny due to their emissions of carbon
dioxide, and in September 2009, the U.S. Court of Appeals for the Second Circuit
reversed a federal district court’s decision and ruled that several states and
public interest groups could sue five electric utility companies under federal
common law for allegedly causing a public nuisance as a result of their
emissions of greenhouse gases. In October 2009, the U.S. Court of Appeals for
the Fifth Circuit reversed a federal district court and ruled that individuals
damaged by Hurricane Katrina could sue a variety of companies that emit carbon
dioxide, including electric utilities, for allegedly causing a public nuisance
that contributed to their damages. Additional litigation in federal and state
courts over these issues is continuing.
In
addition to litigation during 2009, the EPA issued a finding that greenhouse gas
emissions endanger the public health and welfare. The EPA’s finding indicated
that the current and projected levels of six greenhouse gas emissions – carbon
dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur
hexafluoride contribute to climate change. In a related matter, the EPA also
proposed rules that would require all new or modified “stationary sources,” such
as power plants, that emit 25,000 tons of greenhouse gases per year to obtain
permits incorporating the “best available control technology” for such
emissions.
19
In June
2009, the U.S. House of Representatives passed the American Clean Energy and
Security Act of 2009, a bill introduced by Rep. Henry Waxman and Rep. Edward
Markey and popularly known as the Waxman-Markey bill. The bill would regulate
greenhouse gas emissions by instituting a cap-and-trade-system, in which an
economy-wide cap on U.S. greenhouse gas emissions would be established starting
in 2012 with a cap 3% below the baseline 2005 level. The cap would steeply
decline over time until in 2050 it reaches 83% below the baseline level.
Emission allowances, which are rights to emit greenhouse gases, would be both
allocated for free and auctioned. In addition, the draft legislation contains a
renewable energy standard of 25% by the year 2025 and an energy efficiency
mandate for electric and natural gas utilities, as well as other requirements.
Pending in the U.S. Senate is the Clean Energy Jobs and American Power Act
introduced by Sens. John Kerry and Barbara Boxer, known as the Kerry-Boxer bill.
The Kerry-Boxer bill also proposes to regulate greenhouse gas emissions by
instituting a cap-and-trade-system, with primarily the same target levels
proposed by the Waxman-Markey bill; however, the Kerry-Boxer bill is more
aggressive in its 2020 target – a reduction to 20% below 2005 levels by 2020
(versus 17% in Waxman-Markey). Although the Waxman-Markey bill is widely viewed
as the most probable climate change bill to be enacted into law, the prospects
for passage of a similar bill by the U.S. Senate are uncertain.
Other
nations have agreed to regulate emissions of greenhouse gases pursuant to the
United Nations Framework Convention on Climate Change, also known as the “Kyoto
Protocol,” an international treaty pursuant to which participating countries
(not including the United States) have agreed to reduce their emissions of
greenhouse gases to below 1990 levels by 2012. At the end of 2009, an
international conference to develop a successor to the Kyoto Protocol issued a
document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the
United States submitted a greenhouse gas emission reduction target of 17%
compared to 2005 levels.
The
Montana Governor’s office has joined the Western Regional Climate Initiative
(WCI) and is expected to participate in any greenhouse gas emission control
regulations that are adopted by the WCI. The WCI, which has a goal of
reducing carbon dioxide emissions 15% below the 2005 levels by 2020, currently
is developing greenhouse gas emission allocations, offsets, and reporting
recommendations.
While we
cannot predict the impact of any legislation until final, 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 and / or our customers could be significant. We are
proactively involved in analyzing the impacts of current legislative efforts on
our customers and shareholders and are participating in public policy forums
related to these issues.
In
September 2009, the EPA announced the adoption of the first comprehensive
national system for reporting emissions of carbon dioxide and other greenhouse
gases produced by major sources in the United States. The new reporting
requirements will apply to suppliers of fossil fuel and industrial chemicals,
manufacturers of motor vehicles and engines, as well as large direct emitters of
greenhouse gases with emissions equal to or greater than a threshold of 25,000
metric tons per year, which includes certain of our facilities. The effective
date for gathering the data is January 2010 with the first mandatory reporting
due in March 2011.
Clean Air Act - The Clean Air
Act Amendments of 1990 and subsequent amendments stipulate limitations on sulfur
dioxide and nitrogen oxide emissions from coal-fired power plants and motor
vehicles. We comply with 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.
In
September 2009, the EPA proposed rules to reduce greenhouse gas emissions from
light-duty vehicles. Final adoption of the proposed standards for light-duty
vehicles is contingent on the EPA first finalizing its proposed endangerment
finding for greenhouse gas emissions from motor vehicles.
Clean Air Mercury Rule - In
March 2005, the EPA issued the Clean Air Mercury Regulations (CAMR) to reduce
the emissions of mercury from coal-fired facilities through a market-based
cap-and-trade program. Although the U.S. Court of Appeals for the District of
Columbia Circuit struck down CAMR, the state of Montana has finalized its own
rules more stringent than CAMR's 2018 cap that require every coal-fired
generating plant in the state to achieve reduction levels by 2010. Chemical
injection technologies were installed at Colstrip Unit 4 during the fourth
quarter of 2009 to meet these requirements, and our share of the capital cost
was approximately $1.0 million, with ongoing annual operating costs
estimated to be approximately $1.5 million. If the enhanced chemical injection
technologies are not sufficient to meet the required levels of reduction, then
adsorption/absorption technology with fabric filters would be required, which
could represent a material cost. We are continuing to work with the other
Colstrip owners to assess compliance with these reduction levels.
20
There is
a gap between proposed emissions reduction levels and the current capabilities
of technology, as there is no currently available commercial scale technology
that would achieve the proposed reduction levels. Such technology may not be
available within a timeframe consistent with the implementation of climate
change legislation or at all. To the extent that such technology does become
available, we can provide no assurance that it will be suitable or
cost-effective for installation at the generation facilities in which we have a
joint interest. We believe future legislation and regulations that affect carbon
dioxide emissions from power plants are likely, although technology to
efficiently capture, remove and sequester carbon dioxide emissions is not
presently available on a commercial scale.
The
proposed regulations and/or current litigation related to global climate change
could have a material impact on our future capital expenditures and results of
operations, but the costs are not determinable at this time. Our current capital
expenditures projections do not include significant amounts related to
environmental projects. We believe the cost of purchasing carbon emissions
credits, or alternatively the proceeds from the sale of any excess carbon
emissions credits would be included in our supply trackers and passed through to
customers. For more information on environmental contingencies, see Note 17 -
Commitments and Contingencies, in the Notes to Consolidated Financial
Statements.
21
EMPLOYEES
As of
December 31, 2009, we had 1,354 employees. Of these, 1,037 employees were in
Montana and 317 were in South Dakota or Nebraska. Of our Montana employees, 405
were covered by six collective bargaining agreements involving five unions. All
six of these agreements were renegotiated in 2008 for terms of four years. In
addition, our South Dakota and Nebraska operations had 186 employees covered by
the System Council U-26 of the International Brotherhood of Electrical Workers.
This collective bargaining agreement expired on December 31, 2009, and a
tentative agreement has been reached. We consider our relations with employees
to be in good standing.
Executive
Officers
Executive
Officer
|
Current
Title and Prior Employment
|
Age
on Feb. 6, 2010
|
||
Robert
C. Rowe
|
President,
Chief Executive Officer and Director since August 2008. Prior to joining
NorthWestern, Mr. Rowe was a co-founder and senior partner at Balhoff,
Rowe & Williams, LLC, a specialized national professional services
firm providing financial and regulatory advice to clients in the
telecommunications and energy industries (January 2005-August, 2008); and
served as Chairman and Commissioner of the Montana Public Service
Commission (1993–2004).
|
54
|
||
Brian
B. Bird
|
Vice
President, Chief Financial Officer and Treasurer since May 2009, formerly
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.
|
47
|
||
Patrick
R. Corcoran
|
Vice
President-Government and Regulatory Affairs since December 2004; formerly
Vice President-Regulatory Affairs since February 2002; formerly Vice
President-Regulatory Affairs for the former Montana Power Company
(2000-2002).
|
58
|
||
David
G. Gates
|
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.
|
53
|
||
Kendall
G. Kliewer
|
Vice
President and Controller since August 2006; Controller since June 2004;
formerly Chief Accountant since November 2002. Prior to joining
NorthWestern, Mr. Kliewer was a Senior Manager at KPMG LLP
(1999-2002).
|
40
|
||
Curtis
T. Pohl
|
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.
|
45
|
22
Bobbi
L. Schroeppel
|
Vice
President, Customer Care, Communications and Human Resources since May
2009, formerly Vice President-Customer Care and Communications since
September 2005; formerly Vice President-Customer Care since June 2002;
formerly Director-Staff Activities and Corporate Strategy since August
2001; formerly Director-Corporate Strategy since June
2000.
|
41
|
||
Officers
are elected annually by, and hold office at the pleasure of the Board, and do
not serve a “term of office” as such. Miggie E. Cramblit, Vice President,
General Counsel, Corporate Secretary and Chief Compliance Officer, terminated
her employment with NorthWestern effective January 5, 2010. The Board
appointed Timothy P. Olson to act as interim general counsel and corporate
secretary, effective upon Ms. Cramblit’s departure and until the Board appoints
a permanent replacement.
You
should carefully consider the risk factors described below, as well as all other
information available to you, before making an investment in our common stock or
other securities.
Economic
conditions and instability in the financial markets could negatively impact our
business.
Our
operations are impacted by local, national and worldwide economic conditions.
The consequences of a prolonged recession may include a lower level of economic
activity and uncertainty regarding energy prices and the capital and commodity
markets. A lower level of economic activity has resulted in a decline in energy
consumption and a decrease in customers’ ability to pay their accounts, which
may adversely affect our liquidity, results of operations and future growth.
While our territories have been less impacted than other parts of the country,
during 2009 we experienced declines in electric and natural gas usage per
customer and lower electric transmission sales, due in part to the recession. In
addition, demand for our Montana transmission capacity is impacted by market
conditions in states to the South and West of our service territory, which have
been more significantly impacted by the economic downturn.
Access to
the capital and credit markets, at a reasonable cost, is necessary for us to
fund our operations, including capital requirements. We rely on a revolving
credit facility for short-term liquidity needs due to the seasonality of our
business, and on capital markets to raise capital for growth projects that are
not otherwise provided by operating cash flows. Instability in the financial
markets may increase the cost of capital, limit our ability to draw on our
revolving credit facility and/or raise capital. If we are unable to obtain the
liquidity needed to meet our business requirements on favorable terms, we may
defer growth projects and/or capital expenditures.
We
are subject to extensive governmental laws and regulations that affect our
industry and our operations, which could have a material adverse effect on our
liquidity and results of operations.
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. For example, in our 2008
proceeding related to Colstrip Unit 4, the MPSC approved a 10% return on equity
and 6.5% cost of debt for the expected 34-year life of the plant. In addition,
existing regulations may be revised or reinterpreted, new laws, regulations, and
interpretations thereof may be adopted or become applicable to us and future
changes in laws and regulations may have a detrimental effect on our
business.
Our rates
are approved by our respective commissions and are effective until new rates are
approved. The outcome of our Montana electric and natural gas rate case filed in
2009 could have a significant impact on our liquidity and results of operations.
The filing is based upon a 2008 test period, and we anticipate a final
determination on the filing during the fourth quarter of 2010, which creates a
delay between the timing of when such costs are incurred and when the costs are
recovered from customers. This lag can adversely impact our cash flows. 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
liquidity and results of operations.
23
We are
also subject to the jurisdiction of FERC with regard to electric system
reliability standards. We must comply with the standards and requirements
established, which apply to the NERC functions for which we have registered in
both the Midwest Reliability Organization for our South Dakota operations and
the WECC for our Montana operations. To the extent we are deemed to not be
compliant with these standards, we could be subject to fines or
penalties.
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 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, 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.
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 U.S. Supreme Court decision holding that the
EPA relied on improper factors in deciding not to regulate carbon dioxide
emissions from motor vehicles under the Clean Air Act and two federal courts of
appeal have reinstated nuisance claims against emitters of carbon dioxide,
including several utility companies, alleging that such emissions contribute to
global warming. 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 to meet future requirements and
obligations under environmental laws.
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 position could be adversely
affected.
We
are subject to physical and financial risks associated with climate
change.
Physical
risks from climate change could include changes in weather conditions, such as
an increase in changes in precipitation and extreme weather events. Our
customers' energy needs vary with weather conditions, primarily temperature and
humidity. For residential customers, heating and cooling represent their largest
energy use. To the extent weather conditions are affected by climate change, our
customers' energy use could increase or decrease depending on the duration and
magnitude of the changes. Increased energy use due to weather changes may
require us to invest in additional electric generation assets, transmission and
other infrastructure to serve increased loads. Decreased energy use due to
weather changes could result in decreased revenues. Extreme weather conditions
in general increase the stress on our system. Weather conditions outside of our
service territories could have an impact on our results of operations through
impacts to the market prices for supply and transmission capacity. We purchase
and sell electric and natural gas supply depending upon system needs and market
opportunities. Extreme weather conditions creating high energy demand on our own
and/or other systems may raise market prices as we buy short-term energy to
serve our own system. Severe weather impacts our service territories, primarily
through thunderstorms, tornadoes and snow or ice storms. To the extent the
frequency of extreme weather events increase, this could increase our cost of
providing service. Changes in precipitation resulting in droughts or water
shortages could adversely affect our ability to provide electricity to
customers, as well as increase the price they pay for energy. We may not recover
all costs related to mitigating these physical and financial risks.
24
To the
extent climate change impacts a region's economic health, it also may impact our
revenues. Our financial performance is tied to the health of the regional
economies we serve. The price of energy, as a factor in a region's cost of
living as well as an important input into the cost of goods, has an impact on
the economic health of our communities. The cost of additional regulatory
requirements, such as a tax on greenhouse gases or additional environmental
regulation, would normally be borne by consumers through higher prices for
energy and purchased goods. To the extent financial markets view climate change
and emissions of greenhouse gases as a financial risk, this could negatively
affect our ability to access capital markets or cause us to receive less than
ideal terms and conditions.
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 are
required to procure our entire natural gas supply and a large portion of our
Montana electric supply pursuant to contracts with third-party suppliers. In
light of this reliance on third-party suppliers, we are exposed to certain risks
in the event a third-party supplier is unable to satisfy its contractual
obligation. If this occurred, then we might be required to purchase gas and/or
electricity supply requirements in the energy markets, which may not be on
commercially reasonable terms, if at all. If prices were higher in the energy
markets, it could result in a temporary material under recovery that would
reduce our liquidity.
Poor
investment performance of plan assets of our defined benefit pension and
post-retirement benefit plans, in addition to other factors impacting these
costs, could unfavorably impact our results of operations and
liquidity.
Our costs
for providing defined benefit retirement and postretirement benefit plans are
dependent upon a number of factors, including rate of return on plan assets,
discount rates, other actuarial assumptions, and government regulation. Due to
the unprecedented volatility in equity markets, we experienced plan asset market
gains during 2009 in excess of 20%, and plan asset market losses during 2008 in
excess of 30%. Without sustained growth in the plan assets over time and
depending upon the other factors noted above, the costs of such plans reflected
in our results of operations and financial position and cash funding obligations
may change significantly from projections.
Our
plans for future expansion through transmission grid expansion, the construction
of power generation facilities and capital improvements to current assets
involve substantial risks. Failure to adequately execute and manage significant
construction plans, as well as the risk of recovering such costs, could
materially impact our results of operations and liquidity.
We have
proposed capital investment projects in excess of $1 billion. The completion of
these projects, which are primarily investments in electric transmission
projects and electric generation projects, is subject to many construction and
development risks, including, but not limited to, risks related to financing,
regulatory recovery, obtaining and complying with terms of permits, escalating
costs of materials and labor, meeting construction budgets and schedules, and
environmental compliance. In addition, there are projects proposed by other
parties that may result in direct competition to our proposed transmission
expansion.
25
Our
proposed capital investment projects are based on assumptions regarding future
growth and resulting power demand that may not be realized. The timing and
extent of the recovery of the economy, and its impact on demand cannot be
predicted. Additionally, our customers may undertake further individual energy
conservation measures, which could decrease the demand for electricity. We may
increase our transmission and/or baseload capacity and have
excess
capacity if anticipated growth levels are not realized. The resulting
excess
capacity could exceed our obligation to serve retail customers or demand for
transmission capacity and, as a result, may not be recoverable from
customers.
The
construction of new generation and expansion
of our transmission system will require a significant amount of capital
expenditures. We cannot provide certainty that adequate external financing will
be available to support these
projects.
Additionally, borrowings incurred to finance
construction may adversely impact our
leverage, which could increase our cost of capital. We may pursue joint ventures
or similar arrangements with third parties in order to share some of the
financing and operational risks associated with these projects, but we cannot be
certain we will be able to successfully negotiate any such arrangement.
Furthermore, joint ventures or joint ownership arrangements also present risks
and uncertainties, including those associated with sharing control over the
construction and operation of a facility and
reliance on the other party’s financial or operational strength.
We have
filed for and received advanced approval from the MPSC to construct the Mill
Creek Generating Station. The MPSC determined the cost of the gas turbines is
prudent, with the remainder of the project costs to be submitted for review upon
completion of construction. A portion of these future costs could potentially be
deemed imprudent, which we would not be able to recover from
customers.
Should
our efforts be unsuccessful, we could be subject to additional costs,
termination payments under committed contracts, and/or the write-off of
investments in these projects. As of December 31, 2009, we have
capitalized approximately $84.7 million in construction work in progress
associated with the Mill Creek Generating Station and $11.4 million in
preliminary survey and investigative costs associated with transmission
projects.
Our
obligation to include a minimum annual quantity of power in our Montana electric
supply portfolio at an agreed upon price per MWh could expose us to material
commodity price risk if certain QFs under contract with us do not perform during
a time of high commodity prices, as we are required to supply any quantity
deficiency. In addition, we are subject to price escalation risk with one of our
largest QF contracts.
As part
of a previous stipulation with the MPSC and other parties, we agreed to include
a minimum annual quantity of power in our Montana electric supply portfolio at
an agreed upon price per MWh. 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 obligation.
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. The anticipated source for any quantity
deficiency is the wholesale market which, in turn, would subject us to commodity
price volatility.
In
addition, we are subject to price escalation risk with one of our largest QF
contracts due to variable contract terms. In estimating our QF liability, we
have estimated an annual escalation rate of 1.9% over the term of the contract
(through June 2024). To the extent the annual escalation rate exceeds 1.9%, our
results of operations and financial position could be adversely
affected.
Our
jointly owned electric generating facilities are subject to operational risks
that could result in unscheduled plant outages, unanticipated operation and
maintenance expenses and increased power purchase costs.
Operation
of electric generating facilities involves risks, which can adversely affect
energy output and efficiency levels. 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 Plant (our largest source of generation in
South Dakota), making us vulnerable to railroad capacity and operational issues
and/or increased prices for coal transportation from a sole supplier.
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, and 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.
26
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 position could be
adversely affected. In addition, exceptionally hot summer weather or unusually
cold winter weather could add significantly to working capital needs to fund
higher than normal supply purchases to meet customer demand for electricity and
natural gas.
We
must meet certain credit quality standards. If we are unable to maintain
investment grade credit ratings, our liquidity, access to capital and operations
could be materially adversely affected.
A
downgrade of our credit ratings to less than investment grade could adversely
affect our liquidity. Certain of our credit agreements and other credit
arrangements with counterparties require us to provide collateral in the form of
letters of credit or cash to support our obligations if we fall below investment
grade. Also, a downgrade below investment grade could hinder our ability to
raise capital on favorable terms and increase our borrowing costs.
Our
secured credit ratings are also tied to our ability to invest in unregulated
ventures due to an existing stipulation with the MPSC and MCC, which establishes
diminishing limits for such investment at certain credit rating levels. The
stipulation does not limit investment in unregulated ventures so long as we
maintain credit ratings on a secured basis of at least BBB+ (S&P) and Baa1
(Moody’s). For a further discussion of how a lack of liquidity and access to
adequate capital could affect our operations, please see the Risk Factor above,
“Economic conditions and instability in the financial markets could negatively
impact our business.”
None
NorthWestern's
corporate support office is located at 3010 West 69th Street, Sioux Falls, South
Dakota 57108, where we lease approximately 20,000 square feet of office space,
pursuant to a lease that expires on December 1, 2012.
Our
operational support office for our Montana operations is owned by us and located
at 40 East Broadway Street, Butte, Montana 59701. We own or lease other
facilities throughout the state of Montana. Our operational support office for
our South Dakota and Nebraska operations is owned by us and located at 600
Market Street W., Huron, South Dakota 57350. Substantially all of our South
Dakota and Nebraska facilities are owned.
Substantially
all of our Montana electric and natural gas assets are subject to the lien of
our Montana First Mortgage Bond indenture. Substantially all of our South Dakota
and Nebraska electric and natural gas assets are subject to the lien of our
South Dakota Mortgage Bond indenture. For further information regarding our
operating properties, including generation and transmission, see the
descriptions included in Item 1.
27
ITEM 3. LEGAL PROCEEDINGS
We
discuss details of our legal proceedings in Note 17, 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.
No
matters were submitted to a vote of our security holders during the quarter
ended December 31, 2009.
28
Part
II
|
ITEM
5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES
|
Our
common stock, which is traded under the ticker symbol NWE, is listed on the New
York Stock Exchange (NYSE). As of February 5, 2010, there were approximately 883
common stockholders of record.
Dividends
We pay
dividends on our common stock after our Board of Directors (Board) declares
them. The Board reviews the dividend quarterly and establishes the dividend rate
based upon such factors as our earnings, financial condition, capital
requirements, debt covenant requirements and/or other relevant conditions.
Although we expect to continue to declare and pay cash dividends on our common
stock in the future, we cannot assure that dividends will be paid in the future
or that, if paid, the dividends will be paid in the same amount as during 2009.
Quarterly dividends were declared and paid on our common stock during 2009 as
set forth in the table below.
QUARTERLY
COMMON STOCK PRICE RANGES AND DIVIDENDS
Prices
|
Cash
Dividends Paid
|
||||||||
High
|
Low
|
||||||||
2009—
|
|||||||||
Fourth
Quarter
|
$
|
26.85
|
$
|
23.61
|
$
|
0.335
|
|||
Third
Quarter
|
24.94
|
22.58
|
0.335
|
||||||
Second
Quarter
|
23.49
|
20.00
|
0.335
|
||||||
First
Quarter
|
25.39
|
18.48
|
0.335
|
||||||
2008—
|
|||||||||
Fourth
Quarter
|
$
|
25.49
|
$
|
17.24
|
$
|
0.33
|
|||
Third
Quarter
|
26.30
|
23.74
|
0.33
|
||||||
Second
Quarter
|
26.72
|
23.78
|
0.33
|
||||||
First
Quarter
|
29.32
|
24.22
|
0.33
|
On
February 5, 2010, the last reported sale price on the NYSE for our common stock
was $24.24.
Securities
Authorized for Issuance under Equity Compensation Plans
The
following table presents summary information about our equity compensation
plans, including our long-term incentive plan. The table presents the following
data on our plans as of the close of business on December 31, 2009:
i.
|
The
aggregate number of shares of our common stock subject to outstanding
stock options, warrants and rights;
|
ii.
|
The
weighted average exercise price of those outstanding stock options,
warrants and rights; and
|
iii.
|
The
number of shares that remain available for future option grants, excluding
the number of shares to be issued upon the exercise of outstanding
options, warrants and rights described in (i)
above.
|
29
For
additional information regarding our stock long-term incentive plans and the
accounting effects of our stock-based compensation, please see Note 13 to our
Consolidated Financial Statements included in Item 8 herein.
Plan category
|
Number of securities
to be issued upon exercise of
outstanding options, warrants and rights
(a)
|
Weighted average
exercise price of outstanding options,
warrants and rights
(b)
|
Number of securities remaining
available for future issuance
under equity compensation plans (excluding securities
reflected in column (a))
(c)
|
|||
Equity
compensation plans approved by security holders
|
||||||
None
|
||||||
Equity
compensation plans not approved by security holders
|
||||||
New
Incentive Plan (1)
|
—
|
1,259,465
|
||||
Total
|
—
|
1,259,465
|
1)
|
Upon
our emergence from bankruptcy in 2004, a New Incentive Plan was
established pursuant to our Plan of Reorganization, which set aside
2,265,957 shares for the new Board to establish equity-based compensation
plans for employees and directors. As the New Incentive Plan was
established by provisions of the Plan of Reorganization, shareholder
approval was not required. During 2005 the NorthWestern Corporation 2005
Long-Term Incentive Plan was established under the New Incentive Plan,
under which 815,074 shares have been distributed to officers and employees
and 191,418 shares have been used for Board
compensation.
|
30
The
following selected financial data has been derived from our consolidated
financial statements and should be read in conjunction with the consolidated
financial statements and notes thereto and with “Management's Discussion and
Analysis of Financial Condition and Results of Operations" and other financial
data included elsewhere in this report. The historical results are not
necessarily indicative of results to be expected for any future
period.
FIVE-YEAR
FINANCIAL SUMMARY
Year
Ended December 31,
|
|||||||||||||||||
2009
|
2008
|
2007
|
2006
|
2005
|
|||||||||||||
Financial
Results (in thousands, except per share data)
|
|||||||||||||||||
Operating
revenues
|
$
|
1,141,910
|
$
|
1,260,793
|
$
|
1,200,060
|
$
|
1,132,653
|
$
|
1,165,750
|
|||||||
Income
from continuing operations (1)
|
73,420
|
67,601
|
53,191
|
37,482
|
61,547
|
||||||||||||
Basic
earnings per share from continuing operations
|
2.03
|
1.78
|
1.45
|
1.06
|
1.73
|
||||||||||||
Diluted
earnings per share from continuing operations
|
2.02
|
1.77
|
1.44
|
1.00
|
1.71
|
||||||||||||
Dividends
declared & paid per common share
|
1.34
|
1.32
|
1.28
|
1.24
|
1.00
|
||||||||||||
Financial
Position
|
|||||||||||||||||
Total
assets
|
$
|
2,795,132
|
$
|
2,762,037
|
$
|
2,547,380
|
$
|
2,395,937
|
$
|
2,400,403
|
|||||||
Long-term
debt and capital leases, including current portion
|
1,024,186
|
900,047
|
846,368
|
747,117
|
742,970
|
||||||||||||
Ratio
of earnings to fixed charges
|
2.3
|
2.7
|
2.4
|
2.0
|
2.4
|
(1)
|
Income
from continuing operations includes reorganization items for the year
ended December 31, 2005.
|
31
The
following discussion and analysis should be read in conjunction with “Item 6
Selected Financial Data" and our consolidated financial statements and related
notes contained elsewhere in this Annual Report on Form 10-K. For additional
information related to our industry segments, see Note 19 to the Consolidated
Financial Statements, which is included in Item 8 herein. For information
regarding our revenues, net income and assets; see our Consolidated Financial
Statements included in Item 8.
OVERVIEW
NorthWestern
Corporation, doing business as NorthWestern Energy, provides electricity and
natural gas to approximately 661,000 customers in Montana, South Dakota and
Nebraska. As you read this discussion and analysis, refer to our Consolidated
Statements of Income, which present the results of our operations for 2009, 2008
and 2007. Following is a brief overview of highlights for 2009, and a discussion
of our strategy and outlook.
SUMMARY
Significant
achievements for the year ended December 31, 2009 include:
·
|
Improvement
in net income of approximately $5.8 million as compared with 2008, due
primarily to
|
o
|
obtaining
Internal Revenue Service (IRS) approval of a tax accounting method change
to deduct repairs that would have previously been capitalized, resulting
in an income tax benefit of $16.6 million during 2009,
and
|
o
|
the
transfer of Colstrip Unit 4 to utility rate base, resulting in improved
gross margin of $13.8 million;
|
·
|
Successfully
accessed the capital markets to refinance existing maturities and to
finance the Mill Creek Generating Station project and capital
expenditures;
|
o
|
Issuance
of $250 million, 6.34% Montana First Mortgage Bonds with a 10 year
term
|
o
|
Issuance
of $55 million, 5.71% Montana First Mortgage Bonds with a 30 year
term.
|
o
|
Amended
our revolving credit facility to increase the availability to $250 million
from $200 million and extended the maturity date to June 30,
2012;
|
·
|
Received
approval from the MPSC to construct the 150 MW Mill Creek Generating
Station project with a 50% debt and 50% equity capital structure, return
on equity at 10.25% and debt at 6.5%;
and
|
·
|
Upgrade
of our senior secured and unsecured credit ratings by Moody’s Investors
Service (Moody’s).
|
Repairs
Tax Deduction
In
December 2008, we filed a request with the IRS to change our accounting method
related to costs to repair and maintain utility assets. The IRS approved our
request in September 2009, which allows us to take a current tax deduction for a
significant amount of repair costs that were previously capitalized for tax
purposes. For regulatory purposes, we flow these current tax deductions through
to our customers. Due to this regulatory treatment, we recorded an income tax
benefit of approximately $16.6 million during the year ended December 31, 2009
to reflect this change in tax accounting method, of which approximately $8.7
million and $7.9 million related to the 2009 and 2008 tax years, respectively.
Our effective tax rate was 17.2% for 2009, as compared with 37.3% and 37.8% for
2008 and 2007, respectively. The 2009 rate reflects the impact of the change in
tax accounting method for repairs for both 2008 and 2009, as well as lower 2009
taxable income. We expect our effective tax rate for 2010 to be approximately
30%. See Note 9 – Income Taxes, in the Notes to Consolidated Financial
Statements for further discussion.
32
Colstrip
Unit 4
In
January 2009, as approved by the MPSC in 2008, we placed our joint ownership
interest in Colstrip Unit 4, which had previously been an unregulated asset,
into utility rate base at a value of $407 million. The MPSC order included a
capital structure of 50% equity and 50% debt, an authorized return on equity of
10% and cost of debt of 6.5%, which are set for 34 years based on the estimated
useful life of the plant. Our interest in Colstrip Unit 4 is expected to supply
approximately 13% of our base-load requirements through 2010 and approximately
25% thereafter (upon expiration of an existing power sale agreement) and will
help provide rate stability for our customers. The generation related costs and
return on rate base related to Colstrip Unit 4 are included in customer rates as
part of our annual electric supply tracker filing.
STRATEGY
We are
focused on growing through investing in our core utility business and earning a
reasonable return on invested capital, while providing safe, reliable service.
In response to growing customer demand and aging infrastructure, we continue to
make significant maintenance capital investments in our system in excess of our
depreciation, which is the amount of these costs we recover through rates. These
investments reflect our focus on maintaining our system reliability, and allow
us to pursue the deployment of newer technology that promotes the efficient use
of electricity, including smart grid. See the “Capital Requirements" discussion
below for further detail on planned maintenance capital expenditures. We are
considering opportunities consistent with our load growth for the ownership
and/or development of rate-base electric generation facilities, which help to
stabilize our customers’ energy costs while providing us the opportunity to grow
our rate-base and earn a return on investment.
In
addition to the organic load growth in our service territories we also have a
number of growth opportunities due to legislative changes that allow us to
invest in electric generation and gas reserves in Montana on a regulated basis,
and the increased focus on renewable energy. We are considering opportunities
consistent with our load growth for the ownership and/or development of electric
generation facilities, which help to stabilize our customers’ energy costs while
providing us the opportunity to grow our rate base and earn a return on
investment. In addition, our service territories have some of the best wind
resources in the country, and we are focusing on leveraging our unique
geographic position to pursue the construction of the associated transmission
facilities required to support this renewable expansion.
Montana
General Rate Case
Rate
cases are a key component of our earnings growth and achieving our financial
objectives. In October 2009, we filed a request with the MPSC for an annual
electric transmission and distribution revenue increase of $15.5 million, and an
annual natural gas transmission, storage and distribution revenue increase of
$2.0 million. The request was based on a 2008 test period, a return on
equity of 10.9%, an equity ratio of 49.45% and rate base of $632.2 million
and $256.6 million for electric and natural gas, respectively.
In
November 2009, the MPSC issued a determination that the rate case filing did not
meet the MPSC’s applicable minimum filing requirements, related to allocated
cost of service and rate design. We submitted a supplemental filing on January
15, 2010 to meet the MPSC’s minimum filing requirements, which was accepted as
compliant on February 2, 2010. We have agreed to extend the timeframe by which
the MPSC must issue a final order concerning the general rate filing by 90 days
to October 11, 2010. We requested interim rate adjustments, which may be
authorized during the processing of the filing if the MPSC finds it meets the
established criteria. Final rate adjustments would become effective upon the
issuance of a final order on this matter.
Distribution
System Investment
As part
of our commitment to maintain high level reliability and system performance we
continue to evaluate the condition of our distribution assets to address aging
infrastructure through our asset management process. We are working on various
solutions taking a proactive and pragmatic approach to replace these assets
while also evaluating the implementation of additional technologies to prepare
the overall system for smart grid applications. We are in the initial phases of
analyzing the value of implementing additional smart grid technologies. In 2010
we expect to implement a smart grid pilot project as part of an overall regional
smart grid demonstration project, which has been accepted for 50% funding by the
Department of Energy under the American Recovery and Reinvestment Act of 2009.
This project involves testing various smart grid applications in four urban
circuits in Helena, Montana and one rural circuit in the Georgetown Lake area of
Montana. We anticipate spending up to $5 million over three to five years as we
gather information and gain a better understanding of the costs versus benefits
that could then be applied on a larger scale to the rest of our distribution
infrastructure. We have also formed an Infrastructure Stakeholder Group to
assist us as we consider possible future scenarios for investment in our
distribution system and evaluate the potential impacts of different scenarios to
rates and future service quality. While the projected capital amounts needed
under the various scenarios are currently uncertain, we expect to continue
investing amounts in excess of our annual depreciation.
33
Generation
Investment
Mill Creek
Generating Station - In August 2008, we filed a request with the MPSC for
advanced approval to construct a 150 megawatt natural gas fired facility.
The Mill Creek Generating Station, estimated to cost approximately $202 million,
will provide regulating resources to balance our transmission system in Montana
to maintain reliability and enable wind power to be integrated onto the network
to meet renewable energy portfolio needs. In May 2009, the MPSC issued an order
granting approval to construct the facility, authorizing a return on equity of
10.25% and a preliminary cost of debt of 6.5%, with a capital structure of 50%
equity and 50% debt. In addition, the MPSC determined the $81 million cost
for the turbines is prudent, with the remainder of the project costs to be
submitted to the MPSC for review and approval once construction of the facility
is complete. Construction began in June 2009, and the plant is scheduled to be
operational by December 31, 2010. As of December 31, 2009, we have capitalized
approximately $84.7 million in construction work in progress related to
this project.
Wind Generation
– We are currently conducting a Request for Information in Montana and
Request for Proposals in South Dakota for additional renewable resources for the
respective electric supply portfolios. Both efforts are designed to assure we
meet the required renewables portfolio standard of 15% by 2015 in Montana and
the renewable energy objective of 10% by 2015 in South Dakota. We have expressed
a preference for an equity ownership position rather than power purchase
agreements in these requests. Upon receiving responses to these requests we will
further evaluate wind related capital expenditure projections.
Transmission
Investment
Due to
the abundance of natural resources in Montana, significant electric generation
projects, particularly wind generation, are in development by various parties.
Uncertainty surrounding global climate change and environmental concerns related
to new coal-fired generation development is changing the mix of the potential
sources of new generation in the region. State renewable portfolio standards are
increasing the region's reliance on wind generation and Montana has one of the
best wind regimes in the country. Our Montana transmission assets are
strategically located between these renewable generation resources and the
population base desiring them, which should allow us to take advantage of the
potential transmission grid expansion in the west.
In
Montana, we have begun development on three significant electric transmission
projects:
·
|
an
expansion of the existing Colstrip 500 kV system that would increase
capacity by 500-700 MWs, of which we assume a 30% joint ownership;
and
|
·
|
a
230 kV Collector Project in central Montana designed to aggregate
renewables and facilitate their access to markets;
and
|
·
|
a
new 500 kV transmission line from southwestern Montana to southeastern
Idaho with a potential capacity of 1,500
MWs.
|
All of
the current joint owners of the existing Colstrip 500 kV transmission line from
Colstrip, Montana to mid-Columbia, as well as the Bonneville Power Authority,
are working to develop an upgrade to the system, which involves an additional
substation and related electrical equipment to increase westbound capacity out
of Montana by more than 500 MWs. We anticipate completing the technical analysis
for the project in 2010. If constructed, we expect the upgrade to be completed
by the end of 2012.
34
The
Collector Project consists of up to five new transmission lines in Montana that
would connect new generation, primarily wind farms, to our existing transmission
system and to the proposed MSTI line. All of the new proposed wind generation
that would be served by the Collector Project would be located in Montana. The
proposed new 500 kV transmission line between southwestern Montana and
southeastern Idaho is known as MSTI. The transmission line's main purpose will
be to meet requests for transmission service from customers and relieve
constraints on the high-voltage transmission system in the region. An initial
siting study identified several reasonable alternatives for the route and we
have selected a preferred, as well as two alternative routes.
In
January 2009, we filed a request with the FERC seeking negotiated rates for the
proposed MSTI project and to directly assign the cost of the Collector Project
to the generators. The request for negotiated rates for MSTI was not for
specific rates rather it was for confirmation from the FERC that MSTI satisfies
the FERC’s negotiated rate criteria. As a transmission export project in a
region that lacks a RTO, MSTI has no readily available regional tariff through
which to recover costs and thereby mitigate project development risk. The
request was based on a rate approach that FERC had approved for similar projects
in the region, which would provide us with the flexibility to meet market demand
from primarily new renewable generation resources in Montana and to insulate our
native load customers from the costs and risks of the project. FERC issued an
order in May 2009 denying our request for negotiated rates, and encouraged us to
meet our needs by pursuing the MSTI project on a cost-of-service basis by
requesting appropriate waivers under our OATT. As to the Collector Project, FERC
approved our proposal to directly assign the cost of the project to the
generators. This also has the effect of insulating native load customers from
the cost of the project. While FERC deferred ruling on our request for tariff
waivers, FERC specifically found the proposed Collector Project open season
process to be a reasonable means of accommodating a large number of
interconnection requests in the queue.
We are
planning to conduct open seasons for both MSTI and the Collector Project during
the first half of 2010 to identify potential interest for new transmission
capacity on this path due to the changing nature of generation projects. The
results of the open season will be used to size the projects according to
customer demand. The open season process is intended to ensure that the projects
have sufficient contracts with credit-worthy shippers to support financing.
Customers can revoke open season requests at any time up to the point of an
executed service agreement. Based on our current timeline, we anticipate the
Collector Project and MSTI line will be in service by 2014 and 2015,
respectively.
Construction
on these projects cannot commence until all local, state and federal
permits/regulatory requirements are met. We expect the administrative routing
decision on the combined environmental impact statement from the Montana
Department of Environmental Quality and Bureau of Land Management for the MSTI
project in the second quarter of 2010, with a final Record of Decision in late
2010. Due to the uncertainty surrounding the proposed generation, certain
aspects of our proposed transmission development projects are scaleable and thus
can be built out to more closely match the timing of new generation and loads.
The first step in any of these growth opportunities is to obtain regulatory
support prior to making substantial investment. To avoid excessive risk for us,
it is critical to reduce regulatory uncertainty before making large capital
investments. In addition, we are contemplating a strategic partner for the MSTI
project for ownership up to 50%. We have capitalized approximately $11.4 million
of preliminary survey and investigative costs associated with proposed
transmission projects, which include approximately $11.2 million for the MSTI
transmission project and approximately $0.2 million for the Colstrip 500 kV
upgrade. We currently estimate aggregate capital expenditures related to these
transmission projects to range between approximately $20 and $25 million in
2010.
ECONOMIC CONDITIONS AND
OUTLOOK
The
recent capital and credit market crisis is adversely affecting the US and global
economies, which can lead to adverse impacts on our business. Slower economic
growth could lead to lower demand for electricity and gas, resulting in a
decrease in sales volumes to our commercial, industrial and residential
customers. In addition, customers may not be able to pay, or may delay payment
of their bills. Each of the significant growth opportunities described above are
elective, which allows us to be flexible in adjusting to changing economic
conditions by deferring the timing of, or reducing the scale of the projects. In
addition, in response to the change in economic conditions, we have reviewed our
access to liquidity in the credit and capital markets, counterparty
creditworthiness, and the funding requirements of our employee benefit
plans.
35
Outlook -
The current weak economic conditions have resulted, and we believe likely will
continue into 2010, in weaker customer demand, among other things. While
customer counts increased, retail residential and commercial electric volumes
were relatively flat. In addition, industrial volumes declined, however, our
margins are minimally impacted by changes in industrial demand due to our rate
structure. The weak economy also contributed reduced pricing for wholesale sales
and decreased demand for transmission capacity, which we expect to continue into
2010.
Liquidity
– We believe we have sufficient liquidity despite the volatility in the credit
and capital markets. We use our revolving credit facility to manage the
variability in our cash flows due to the seasonality of our business, and were
able to increase the size of this credit facility during 2009. We closely
monitor the financial institutions associated with our credit facility, and have
had no exposure to the banks that have failed or were purchased in distressed
transactions.
We
believe our cash flows from operations and existing borrowing capacity should be
sufficient to fund our operations, service existing debt, pay dividends, and
fund capital expenditures (excluding strategic growth opportunities). We may
defer planned capital expenditures to maintain sufficient liquidity in response
to changing economic conditions. To fund our strategic growth opportunities we
intend to utilize available cash flow, debt capacity that would allow us to
maintain investment grade ratings (50-55% debt to total capital ratio), and if
necessary additional equity financing. We do not anticipate the need for equity
financing until we proceed further with transmission or a combination of other
investment opportunities. We currently expect to continue targeting a long-term
dividend payout ratio of 60 – 70 % of net income; however, there can be no
assurance that we will be able to meet this target. See the “Liquidity and
Capital Resources” section for further discussion.
Counterparty
Credit Risk – We are exposed to counterparty credit risk related to the
ability of our counterparties to meet their contractual payment obligations, and
the potential non-performance of counterparties to deliver contracted
commodities or services at the contracted price. We have risk management
policies in place to limit our transactions to high quality counterparties, and
continue to monitor closely the status of our counterparties, and will take
action, as appropriate, to further manage this risk. This includes, but is not
limited to, requiring letters of credit or prepayment terms.
Defined Benefit
Pension Plans – Due to the unprecedented volatility in equity markets, we
experienced plan asset market gains during 2009 in excess of 20%, and plan asset
market losses during 2008 in excess of 30%. We remeasure our benefit obligations
annually using a December 31 measurement date, and use this information to
project our cash funding requirements. Pension costs in Montana are included in
expense using the average of our actual and estimated funding amounts from 2005
through 2012 based on an MPSC accounting order. Therefore, changes in our
funding estimates create increased volatility to earnings. Our Montana pension
expense totaled $28.4 million in 2009 as compared with $30.6 million in 2008 and
$22.0 million in 2007. Based on current projections, we expect annual expense to
be approximately $28.4 million through 2012. As a result of the significant
increase in unfunded status as of December 31, 2008, we reviewed our funding
strategy for the plans, and significantly increased our 2009 cash funding in
order to decrease the volatility of these plans to our long-term results of
operations and liquidity as follows:
2009
|
2008
|
2007
|
||||||||
NorthWestern
Energy Pension Plan (MT)
|
$
|
80,600
|
$
|
31,140
|
$
|
21,966
|
||||
NorthWestern
Corporation Pension Plan (SD)
|
12,300
|
1,594
|
672
|
|||||||
$
|
92,900
|
$
|
32,734
|
$
|
22,638
|
For
further discussion of our sensitivity to plan asset returns and other
assumptions for these plans, see the “Critical Accounting Policies” section. For
further discussion of the impact of the additional cash funding in 2009, see the
“Liquidity and Capital Resources” section. For discussion of the plan’s funded
status, see Note 12- Employee Benefit Plans, in the Notes to Consolidated
Financial Statements.
36
RESULTS
OF OPERATIONS
Our
consolidated results include the results of our divisions and subsidiaries
constituting each of our business segments. The overall consolidated discussion
is followed by a detailed discussion of gross margin by segment.
NON-GAAP
FINANCIAL MEASURE
The
following discussion includes financial information prepared in accordance with
generally accepted accounting principles (GAAP), as well as another financial
measure, Gross Margin, that is considered a “
non-GAAP financial measure.” Generally, a
non-GAAP financial measure is a numerical
measure of a company’s financial performance, financial position or cash flows
that exclude (or include) amounts that are included in (or excluded from) the
most directly comparable measure calculated and presented in accordance with
GAAP. Gross Margin (Revenues less Cost of Sales) is a non-GAAP financial measure
due to the exclusion of depreciation from the measure. The presentation of Gross
Margin is intended to supplement investors’ understanding of our operating
performance. Gross Margin is used by us to determine whether we are
collecting the appropriate amount of energy costs from customers to allow
recovery of operating costs. Our Gross Margin measure may not be comparable
to other companies’ Gross Margin measure. Furthermore, this measure is not
intended to replace operating income as determined in accordance with GAAP as an
indicator of operating performance.
Factors
Affecting Results of Operations
Our
revenues may fluctuate substantially with changes in supply costs, which are
generally collected in rates from customers. In addition, various regulatory
agencies approve the prices for electric and natural gas utility service within
their respective jurisdictions and regulate our ability to recover costs from
customers.
Revenues
are also impacted to a lesser extent by customer growth and usage, the latter of
which is primarily affected by weather. Very cold winters increase demand for
natural gas and to a lesser extent, electricity, while warmer than normal
summers increase demand for electricity, especially among our residential and
commercial customers. We measure this effect using degree-days, which is the
difference between the average daily actual temperature and a baseline
temperature of 65 degrees. Heating degree-days result when the average daily
temperature is less than the baseline. Cooling degree-days result when the
average daily temperature is greater than the baseline. The statistical weather
information in our regulated segments represents a comparison of this
data.
37
OVERALL
CONSOLIDATED RESULTS
Year
Ended December 31, 2009 Compared with Year Ended December 31, 2008
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
Change
|
%
Change
|
|||||||||
(in
millions)
|
||||||||||||
Operating
Revenues
|
||||||||||||
Regulated
Electric
|
$
|
782.3
|
$
|
774.2
|
$
|
8.1
|
1.0
|
%
|
||||
Regulated
Natural Gas
|
354.5
|
416.7
|
(62.2
|
)
|
(14.9
|
)
|
||||||
Unregulated
Electric
|
—
|
77.7
|
(77.7
|
)
|
(100.0
|
)
|
||||||
Other
|
6.7
|
30.0
|
(23.3
|
)
|
(77.7
|
)
|
||||||
Eliminations
|
(1.6
|
)
|
(37.8
|
)
|
36.2
|
95.8
|
||||||
$
|
1,141.9
|
$
|
1,260.8
|
$
|
(118.9
|
)
|
(9.4
|
)%
|
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
Change
|
%
Change
|
|||||||||
(in
millions)
|
||||||||||||
Cost
of Sales
|
||||||||||||
Regulated
Electric
|
$
|
356.7
|
$
|
410.4
|
$
|
(53.7
|
)
|
(13.1
|
)%
|
|||
Regulated
Natural Gas
|
210.0
|
271.7
|
(61.7
|
)
|
(22.7
|
)
|
||||||
Unregulated
Electric
|
—
|
23.5
|
(23.5
|
)
|
(100.0
|
)
|
||||||
Other
|
7.0
|
29.1
|
(22.1
|
)
|
(75.9
|
)
|
||||||
Eliminations
|
—
|
(36.0
|
)
|
36.0
|
100.0
|
|||||||
$
|
573.7
|
$
|
698.7
|
$
|
(125.0
|
)
|
(17.9
|
)%
|
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
Change
|
%
Change
|
|||||||||
(in
millions)
|
||||||||||||
Gross
Margin
|
||||||||||||
Regulated
Electric
|
$
|
425.6
|
$
|
363.8
|
$
|
61.8
|
17.0
|
%
|
||||
Regulated
Natural Gas
|
144.5
|
145.0
|
(0.5
|
)
|
(0.3
|
)
|
||||||
Unregulated
Electric
|
—
|
54.2
|
(54.2
|
)
|
(100.0
|
)
|
||||||
Other
|
(0.3
|
)
|
0.9
|
(1.2
|
)
|
(133.3
|
)
|
|||||
Eliminations
|
(1.6
|
)
|
(1.8
|
)
|
0.2
|
11.1
|
||||||
$
|
568.2
|
$
|
562.1
|
$
|
6.1
|
1.1
|
%
|
Consolidated
gross margin in 2009 was $568.2 million, an increase of $6.1 million, or 1.1%,
from gross margin in 2008. Primary components of this change include the
following:
Gross
Margin
|
||||
2009
vs. 2008
|
||||
(in
millions)
|
||||
Transfer
of Colstrip Unit 4 to regulated electric
|
$
|
68.0
|
||
2008
Unregulated electric
|
(54.2
|
)
|
||
Net
Colstrip Unit 4 increase to gross margin
|
13.8
|
|||
Operating
expenses recovered in supply trackers
|
4.0
|
|||
Montana
property tax tracker
|
2.9
|
|||
Regulated
electric wholesale
|
(4.6
|
)
|
||
Regulated
electric transmission capacity
|
(3.3
|
)
|
||
QF
supply costs
|
(2.6
|
)
|
||
Loss
on capacity contract
|
(1.5
|
)
|
||
Other
|
(2.6
|
)
|
||
Increase
in Consolidated Gross Margin
|
$
|
6.1
|
38
The
transfer of our interest in Colstrip Unit 4 to Montana utility rate base
contributed approximately $68.0 million to gross margin. Prior to the transfer
of Colstrip Unit 4, all of our Montana electric supply costs were based on power
purchase agreements, which are passed through to customers at actual cost with
no return component. Results of operations of this plant were reflected in our
unregulated electric segment through December 31, 2008, which impacts the
comparability of our segmented results. The absence of Colstrip Unit 4 from our
unregulated electric segment reduced gross margin by approximately $54.2 million
as compared with the same period of 2008.
Consolidated
margin also increased due to higher revenues for operating, general and
administrative expenses primarily related to costs incurred for customer
efficiency programs, which are recovered from customers through the supply
trackers and therefore have no impact on operating income, and an increase in
property taxes recovered compared with 2008. These increases in margin were
offset in part by lower wholesale pricing and volumes, lower transmission
capacity revenues due to decreased demand, higher QF related supply costs based
on actual QF pricing and output, and a loss on a capacity contract included in
our “other” segment. This capacity contract runs through October 2013 and was
primarily used to serve one customer. The customer terminated their supply
contract with us during the second quarter of 2009 and we have recorded a loss
to reflect the change in the estimate of the market value for the capacity
during the remaining term. Our remaining exposure related to this capacity
contract is approximately $0.9 million as of December 31, 2009.
Year
Ended December 31,
|
||||||||||||
2009
|
2008
|
Change
|
%
Change
|
|||||||||
(in
millions)
|
||||||||||||
Operating
Expenses (excluding cost of sales)
|
||||||||||||
Operating,
general and administrative
|
$
|
245.6
|
$
|
226.1
|
$
|
19.5
|
8.6
|
%
|
||||
Property
and other taxes
|
79.6
|
80.6
|
(1.0
|
)
|
(1.2
|
)
|
||||||
Depreciation
|
89.0
|
85.1
|
3.9
|
4.6
|
||||||||
$
|
414.2
|
$
|
391.8
|
$
|
22.4
|
5.7
|
%
|
Consolidated
operating, general and administrative expenses were $245.6 million in 2009 as
compared to $226.1 million in 2008. Primary components of this change include
the following:
Operating,
General, & Administrative Expenses
|
||||
2009
vs. 2008
|
||||
(in
millions)
|
||||
Insurance
recoveries and settlements
|
$
|
10.9
|
||
Insurance
reserves
|
6.3
|
|||
Jointly
owned plant operations
|
4.4
|
|||
Labor
|
4.4
|
|||
Operating
expenses recovered in supply trackers
|
4.0
|
|||
Postretirement
health care
|
2.8
|
|||
Legal
and professional fees
|
(6.8
|
)
|
||
Fleet
and materials expense
|
(2.9
|
)
|
||
Stock
based compensation
|
(1.4
|
)
|
||
Bad
debt expense
|
(0.9
|
)
|
||
Other
|
(1.3
|
)
|
||
Increase
in Operating, General & Administrative Expenses
|
$
|
19.5
|
The
increase in operating, general and administrative expenses of $19.5 million was
primarily due to the following:
·
|
Lower
insurance recoveries and litigation settlements as compared with 2008.
During 2009, we received approximately $5.6 million of insurance
recoveries related primarily to previously incurred Montana generation
related environmental remediation costs. During 2008, we received $16.5
million of insurance reimbursements and litigation settlement proceeds
related to costs incurred in prior
years;
|
·
|
Increased
insurance reserves due to general liability and workers compensation
matters;
|
39
·
|
Increased
plant operations costs due to scheduled maintenance and an unplanned
outage at Colstrip Unit 4 for a rotor
repair;
|
·
|
Increased
labor costs due primarily to compensation increases and severance
costs;
|
·
|
Higher
operating, general and administrative expenses primarily related to costs
incurred for customer efficiency programs, which are recovered from
customers through supply trackers and therefore have no impact on
operating income; and
|
·
|
Increased
postretirement health care costs due to plan asset market losses in 2008
and changes in actuarial assumptions. Postretirement healthcare costs
totaled approximately $5.7 million during 2009 as compared with $2.9
million during 2008. We amended our postretirement healthcare plan during
the fourth quarter of 2009 and we anticipate 2010 costs will decrease to
approximately $1.0 million.
|
These
increases were partially offset by:
·
|
Decreased
legal and professional fees as 2008 included costs related to a proposed
Colstrip Unit 4 transaction and other matters where we received insurance
reimbursements or settlement
proceeds;
|
·
|
Decreased
fleet and material expense primarily due to lower average fuel
costs;
|
·
|
Lower
stock-based compensation due to the timing of equity grants and vesting
criteria; and
|
·
|
Lower
bad debt expense based on lower average customer receivable balances and
less days outstanding.
|
Property
and other taxes were $79.6 million in 2009 as compared with $80.6 million in
2008.
Depreciation
expense was $89.0 million in 2009 as compared with $85.1 million in 2008.
This increase was primarily due to plant additions.
Consolidated
operating income in 2009 was $154.0 million, as compared with $170.2 million in
2008. The decrease was primarily due to higher operating expenses, partially
offset by the $6.1 million increase in gross margin discussed
above.
Consolidated
interest expense in 2009 was $67.8 million, an increase of $3.8 million, or
5.9%, from 2008. This increase was primarily due to increased debt outstanding.
We expect interest expense for 2010 to be consistent with 2009 due to an
increase in the amounts capitalized for the debt portion of allowance for funds
used during construction (AFUDC), related to the Mill Creek Generating Station,
offsetting an increase in debt outstanding.
Consolidated
other income in 2009 was $2.5 million, an increase of $0.9 million from 2008.
This increase was primarily due to capitalizing approximately $1.4 million of
costs for the equity portion of AFUDC. We expect to capitalize approximately
$8.1 million of AFUDC costs related to the Mill Creek Generating Station
during 2010.
Consolidated
income tax expense in 2009 was $15.3 million as compared with $40.2 million in
2008. The effective tax rate in 2009 was 17.2% as compared with 37.3% for the
same period of 2008. These effective tax rates differ from the federal tax rate
of 35% primarily due to the effects of tax credits, state income taxes, utility
rate-making, and other permanent book-to-tax differences. The effective tax rate
in 2009 was significantly impacted by a change in tax accounting method related
to repair costs as discussed above in the MD&A “Overview” section. While we
reflect an income tax provision in our financial statements, we expect our cash
payments for income taxes will be minimal through at least 2014, based on our
projected taxable income and anticipated use of consolidated net operating loss
carryforwards (CNOLs).
Consolidated
net income in 2009 was $73.4 million as compared with $67.6 million in
2008. The increase was primarily due to lower income tax expense, offset by
lower operating income and higher interest expense as discussed
above.
40
Year
Ended December 31, 2008 Compared with Year Ended December 31, 2007
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
Change
|
%
Change
|
|||||||||
(in
millions)
|
||||||||||||
Operating
Revenues
|
||||||||||||
Regulated
Electric
|
$
|
774.2
|
$
|
736.7
|
$
|
37.5
|
5.1
|
%
|
||||
Regulated
Natural Gas
|
416.7
|
363.6
|
53.1
|
14.6
|
||||||||
Unregulated
Electric
|
77.7
|
74.2
|
3.5
|
4.7
|
||||||||
Other
|
30.0
|
56.7
|
(26.7
|
)
|
(47.1
|
)
|
||||||
Eliminations
|
(37.8
|
)
|
(31.1
|
)
|
(6.7
|
)
|
(21.5
|
)
|
||||
$
|
1,260.8
|
$
|
1,200.1
|
$
|
60.7
|
5.1
|
%
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
Change
|
%
Change
|
|||||||||
(in
millions)
|
||||||||||||
Cost
of Sales
|
||||||||||||
Regulated
Electric
|
$
|
410.4
|
$
|
389.7
|
$
|
20.7
|
5.3
|
%
|
||||
Regulated
Natural Gas
|
271.7
|
236.0
|
35.7
|
15.1
|
||||||||
Unregulated
Electric
|
23.5
|
18.0
|
5.5
|
30.6
|
||||||||
Other
|
29.1
|
54.2
|
(25.1
|
)
|
(46.3
|
)
|
||||||
Eliminations
|
(36.0
|
)
|
(29.5
|
)
|
(6.5
|
)
|
(22.0
|
)
|
||||
$
|
698.7
|
$
|
668.4
|
$
|
30.3
|
4.5
|
%
|
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
Change
|
%
Change
|
|||||||||
(in
millions)
|
||||||||||||
Gross
Margin
|
||||||||||||
Regulated
Electric
|
$
|
363.8
|
$
|
347.0
|
$
|
16.8
|
4.8
|
%
|
||||
Regulated
Natural Gas
|
145.0
|
127.6
|
17.4
|
13.6
|
||||||||
Unregulated
Electric
|
54.2
|
56.2
|
(2.0
|
)
|
(3.6
|
)
|
||||||
Other
|
0.9
|
2.5
|
(1.6
|
)
|
(64.0
|
)
|
||||||
Eliminations
|
(1.8
|
)
|
(1.6
|
)
|
(0.2
|
)
|
(12.5
|
)
|
||||
$
|
562.1
|
$
|
531.7
|
$
|
30.4
|
5.7
|
%
|
Consolidated
gross margin in 2008 was $562.1 million, an increase of $30.4 million, or 5.7%,
from gross margin in 2007. Primary components of this change included the
following:
Gross
Margin
|
||||
2008
vs. 2007
|
||||
(in
millions)
|
||||
Rate
increases
|
$
|
20.4
|
||
Regulated
electric and gas volumes
|
6.9
|
|||
Unregulated
electric volumes
|
8.2
|
|||
Regulated
electric QF supply costs
|
5.0
|
|||
Wholesale
electric
|
2.6
|
|||
Unregulated
electric pricing and fuel supply costs
|
(10.2
|
)
|
||
Montana
property tax tracker
|
(8.6
|
)
|
||
Other
|
6.1
|
|||
Improvement
in Gross Margin
|
$
|
30.4
|
Our
regulated electric and gas margin improved due to the combination of an increase
in electric rates in Montana and gas rates in Montana, South Dakota and
Nebraska, and an 11.7% increase in volumes in our regulated gas segment due
primarily to colder winter weather. In addition, regulated electric QF supply
costs were lower due to a combination of pricing and output, and electric
wholesale margin improved from increased plant availability and higher average
prices. Partly offsetting these increases was a reduction in revenues related to
the recovery of our Montana property taxes in rates. The decrease was due to
lower 2008 property taxes, a credit to customers related to the property tax
settlement discussed below, and a change in calculation by the MPSC to reduce
the allocation of property taxes to Montana electric retail customers. See
additional discussion related to property taxes below. In addition, unregulated
electric margin decreased due to lower average contract prices and higher fuel
supply costs partially offset by higher volumes due to increased plant
availability.
41
Year
Ended December 31,
|
||||||||||||
2008
|
2007
|
Change
|
%
Change
|
|||||||||
(in
millions)
|
||||||||||||
Operating
Expenses (excluding cost of sales)
|
||||||||||||
Operating,
general and administrative
|
$
|
226.1
|
$
|
221.6
|
$
|
4.5
|
2.0
|
%
|
||||
Property
and other taxes
|
80.6
|
87.6
|
(7.0
|
)
|
(8.0
|
)
|
||||||
Depreciation
|
85.1
|
82.4
|
2.7
|
3.3
|
||||||||
$
|
391.8
|
$
|
391.6
|
$
|
0.2
|
0.1
|
%
|
Consolidated
operating, general and administrative expenses were $226.1 million in 2008 as
compared to $221.6 million in 2007. Primary components of this change included
the following:
Operating,
General, & Administrative Expenses
|
||||
2008
vs. 2007
|
||||
(in
millions)
|
||||
2007
Environmental clean-up cost recovery
|
$
|
12.6
|
||
Pension
expense
|
8.4
|
|||
Labor
and benefits
|
7.3
|
|||
Legal
and professional fees
|
5.4
|
|||
Insurance
reimbursements and settlements
|
(16.5
|
)
|
||
Operating
lease expense
|
(14.4
|
)
|
||
Other
|
1.7
|
|||
Increase
in Operating, General & Administrative
Expenses
|
$
|
4.5
|
The
increase in operating, general and administrative expenses of $4.5 million was
primarily due to the following:
·
|
Lower
environmental expense in 2007 due to a settlement to recover MGP clean-up
costs in our South Dakota natural gas rate
case;
|
·
|
Higher
pension expense related to our Montana plan as pension costs are included
in expense on a pay as you go (cash funding) basis. With the revised MPSC
pension accounting order, pension expense was approximately $30.6 million
in 2008, as compared with $22.0 million in 2007, which reflects increased
plan funding projections due to plan asset market losses during
2008;
|
·
|
Increased
labor and benefits costs due to a combination of compensation increases,
severance costs and higher medical claims;
and
|
·
|
Higher
legal and professional fees related to the Colstrip Unit 4 transaction and
other matters where we obtained insurance reimbursements or settlement
proceeds noted below.
|
Offsets
to these increases included the following:
·
|
The
receipt in 2008 of insurance reimbursements and litigation settlement
proceeds related to costs incurred in prior years;
and
|
·
|
Decreased
operating lease expense due to the purchase of our previously leased
interest in Colstrip Unit 4 during
2007.
|
42
Property
and other taxes were $80.6 million in 2008 as compared with $87.6 million in
2007. This $7.0 million decrease was due to a $4.6 million property tax refund
in Montana as a result of a settlement with the Montana Department of Revenue,
and a reduction of approximately $2.4 million due to a lower property tax
valuation in Montana as compared with 2007. We file annual property tax tracker
filings in Montana to reflect a portion of property tax increases or decreases
in customer rates. Our latest property tax tracker filing reflected the
reductions noted above. In January 2009, the MPSC reviewed our filing and made
various changes to allocation factors for the years 2007, 2008 and projections
for 2009, which resulted in a lower property tax allocation to our Montana
electric retail customers and a higher property tax allocation to electric FERC
jurisdictional transmission customers (we do not have a property tax tracker for
FERC jurisdictional purposes).
Depreciation
expense was $85.1 million in 2008 as compared with $82.4 million in 2007. The
increase was primarily due to the purchase of our previously leased interest in
Colstrip Unit 4.
Consolidated
operating income in 2008 was $170.2 million, as compared with $140.1 million in
2007. This $30.1 million increase was primarily due to the increase in gross
margin.
Consolidated
interest expense in 2008 was $64.0 million, an increase of $7.1 million, or
12.5%, from 2007. This increase was primarily related to the additional debt
incurred with the purchase of our previously leased interest in Colstrip Unit
4.
Consolidated
other income in 2008 was $1.6 million, a decrease of $0.8 million from
2007.
Consolidated
income tax expense in 2008 was $40.2 million as compared with $32.4 million in
2007. Our effective tax rate for 2008 was 37.3% as compared to 37.8% for
2007.
Consolidated
net income in 2008 was $67.6 million as compared with $53.2 million for the same
period in 2007. This increase was primarily due to improved operating income,
partly offset by higher interest and income tax expense as discussed
above.
43
REGULATED
ELECTRIC MARGIN
Year
Ended December 31, 2009 Compared with Year Ended December 31, 2008
The
following summarizes the regulated electric revenue, cost of sales, and gross
margin for the years ended December 31, 2009 and 2008:
Results
|
||||||||||||||
2009
|
2008
|
Change
|
%
Change
|
|||||||||||
(in
millions)
|
||||||||||||||
Retail
revenue
|
$
|
660.7
|
$
|
709.7
|
$
|
(49.0
|
)
|
(6.9
|
)%
|
|||||
Transmission
|
45.5
|
48.7
|
(3.2
|
)
|
(6.6
|
)
|
||||||||
Wholesale
|
43.9
|
10.4
|
33.5
|
322.1
|
||||||||||
Regulatory
Amortization and Other
|
32.2
|
5.4
|
26.8
|
496.3
|
||||||||||
Total
Revenues
|
782.3
|
774.2
|
8.1
|
1.0
|
||||||||||
Total
Cost of Sales
|
356.7
|
410.4
|
(53.7
|
)
|
(13.1
|
)
|
||||||||
Gross
Margin
|
$
|
425.6
|
$
|
363.8
|
$
|
61.8
|
17.0
|
%
|
Revenues
|
Megawatt
Hours (MWH)
|
Avg.
Customer Counts
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
(in
thousands)
|
|||||||||||||||||
Retail
Electric
|
|||||||||||||||||
Montana
|
$
|
222,610
|
$
|
236,921
|
2,317
|
2,285
|
268,492
|
266,100
|
|||||||||
South
Dakota
|
43,971
|
45,199
|
523
|
513
|
48,258
|
47,967
|
|||||||||||
Residential
|
266,581
|
282,120
|
2,840
|
2,798
|
316,750
|
314,067
|
|||||||||||
Montana
|
270,558
|
289,209
|
3,161
|
3,190
|
60,445
|
59,595
|
|||||||||||
South
Dakota
|
63,004
|
65,608
|
877
|
872
|
11,659
|
11,492
|
|||||||||||
Commercial
|
333,562
|
354,817
|
4,038
|
4,062
|
72,104
|
71,087
|
|||||||||||
Industrial
|
35,902
|
46,504
|
2,899
|
3,122
|
71
|
71
|
|||||||||||
Other
|
24,697
|
26,221
|
181
|
182
|
5,943
|
5,823
|
|||||||||||
Total
Retail Electric
|
$
|
660,742
|
$
|
709,662
|
9,958
|
10,164
|
394,868
|
391,048
|
|||||||||
Wholesale
Electric
|
|||||||||||||||||
Montana
|
$
|
38,263
|
$
|
—
|
642
|
—
|
N/A
|
N/A
|
|||||||||
South
Dakota
|
5,653
|
10,370
|
217
|
265
|
N/A
|
N/A
|
|||||||||||
Total
Wholesale Electric
|
$
|
43,916
|
$
|
10,370
|
859
|
265
|
N/A
|
N/A
|
2009 as compared with:
|
|||||
Cooling
Degree-Days
|
2008
|
Historic Average
|
|||
Montana
|
6%
colder
|
4%
warmer
|
|||
South
Dakota
|
25%
colder
|
37%
colder
|
The
following summarizes the components of the changes in regulated electric margin
for the years ended December 31, 2009 and 2008:
Gross
Margin
|
||||
2009
vs. 2008
|
||||
(in
millions)
|
||||
Transfer
of interest in Colstrip Unit 4 to regulated electric
|
$
|
68.0
|
||
Montana
property tax tracker
|
2.6
|
|||
Operating
expenses recovered in supply
tracker
|
2.4
|
|||
South
Dakota wholesale
|
(4.6
|
)
|
||
Transmission
capacity
|
(3.3
|
)
|
||
QF
supply costs
|
(2.6
|
)
|
||
Other
|
(0.7
|
)
|
||
Improvement
in Regulated Electric Gross Margin
|
61.8
|
|||
Reduction
in Unregulated Electric Gross Margin
|
(54.2
|
)
|
||
Net
Increase in Electric Gross Margin
|
$
|
7.6
|
44
The net
increase in gross margin is due primarily to the transfer of Colstrip Unit 4 to
the regulated utility. Prior to the transfer of Colstrip Unit 4, all of our
Montana electric supply costs were based on power purchase agreements, which are
passed through to customers at actual cost with no return component. Revenues
from the sales of the output of this plant were reflected in our unregulated
electric segment through December 31, 2008, which impacts the comparability of
the results of our regulated electric segment. The absence of gross margin from
our unregulated electric segment reduced gross margin by approximately $54.2
million as compared with 2008. In addition, we are continuing to fulfill a prior
third party power purchase agreement, which is reflected as an increase in
Montana wholesale revenues and volumes above. Also contributing to the increase
in gross margin is an increase in property taxes recovered in revenues as
compared with 2008; and higher revenues for operating, general and
administrative expenses primarily related to customer efficiency programs, which
are recovered from customers through the supply trackers and therefore have no
impact on operating income.
This
increase in gross margin was offset in part by lower South Dakota wholesale
margin due to lower sales at lower average prices, lower transmission capacity
revenues with less demand to transmit energy for others across our lines, and
higher QF related supply costs based on actual QF pricing and output. In
addition, average electric supply prices decreased resulting in decreased retail
revenues and cost of sales in 2009 as compared with 2008, with no impact to
gross margin. Regulatory amortizations increased due to changes in our electric
supply and property tax trackers. These amortizations are offset in retail
revenue; therefore they have no impact on gross margin.
Regulated
wholesale electric volumes increased due to the 2009 transfer of Colstrip Unit 4
to the regulated utility discussed above. This increase in regulated wholesale
electric volumes was offset in part by a decrease in South Dakota wholesale
volumes from lower plant availability related to scheduled maintenance. We
estimate our South Dakota wholesale volumes will increase by approximately 53
MWHs and margin will increase by approximately $1.8 million in 2010 due
primarily to lower planned maintenance.
45
Year
Ended December 31, 2008 Compared with Year Ended December 31, 2007
The
following summarizes the regulated electric revenue, cost of sales, and gross
margin for the years ended December 31, 2008 and 2007:
Results
|
||||||||||||||
2008
|
2007
|
Change
|
%
Change
|
|||||||||||
(in
millions)
|
||||||||||||||
Retail
revenue
|
$
|
709.7
|
$
|
668.8
|
$
|
40.9
|
6.1
|
%
|
||||||
Transmission
|
48.7
|
48.7
|
—
|
—
|
||||||||||
Wholesale
|
10.4
|
6.0
|
4.4
|
73.3
|
||||||||||
Regulatory
Amortization and Other
|
5.4
|
13.2
|
(7.8
|
)
|
(59.1
|
)
|
||||||||
Total
Revenues
|
774.2
|
736.7
|
37.5
|
5.1
|
||||||||||
Total
Cost of Sales
|
410.4
|
389.7
|
20.7
|
5.3
|
||||||||||
Gross
Margin
|
$
|
363.8
|
$
|
347.0
|
$
|
16.8
|
4.8
|
%
|
Revenues
|
Megawatt
Hours (MWH)
|
Avg.
Customer Counts
|
|||||||||||||||
2008
|
2007
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
(in
thousands)
|
|||||||||||||||||
Retail
Electric
|
|||||||||||||||||
Montana
|
$
|
236,921
|
$
|
221,046
|
2,285
|
2,235
|
266,100
|
262,481
|
|||||||||
South
Dakota
|
45,199
|
42,062
|
513
|
505
|
47,967
|
47,713
|
|||||||||||
Residential
|
282,120
|
263,108
|
2,798
|
2,740
|
314,067
|
310,194
|
|||||||||||
Montana
|
289,209
|
277,875
|
3,190
|
3,213
|
59,595
|
58,319
|
|||||||||||
South
Dakota
|
65,608
|
58,341
|
872
|
827
|
11,492
|
11,336
|
|||||||||||
Commercial
|
354,817
|
336,216
|
4,062
|
4,040
|
71,087
|
69,655
|
|||||||||||
Industrial
|
46,504
|
44,473
|
3,122
|
2,992
|
71
|
71
|
|||||||||||
Other
|
26,221
|
25,015
|
182
|
181
|
5,823
|
5,802
|
|||||||||||
Total
Retail Electric
|
$
|
709,662
|
$
|
668,812
|
10,164
|
9,953
|
391,048
|
385,722
|
|||||||||
Wholesale
Electric
|
|||||||||||||||||
Montana
|
$
|
—
|
$
|
—
|
—
|
—
|
N/A
|
N/A
|
|||||||||
South
Dakota
|
10,370
|
5,965
|
265
|
155
|
N/A
|
N/A
|
|||||||||||
Total
Wholesale Electric
|
$
|
10,370
|
$
|
5,965
|
265
|
155
|
N/A
|
N/A
|
2008 as compared with:
|
|||||
Cooling
Degree-Days
|
2007
|
Historic
Average
|
|||
Montana
|
42%
colder
|
8%
warmer
|
|||
South
Dakota
|
31%
colder
|
16%
colder
|
The
following summarizes the components of the changes in regulated electric margin
for the years ended December 31, 2008 and 2007:
Gross
Margin
|
||||
2008
vs. 2007
|
||||
(in
millions)
|
||||
Montana
jurisdiction transmission and distribution rate increase
|
$
|
9.9
|
||
QF
supply costs
|
5.0
|
|||
Wholesale
|
2.6
|
|||
Customer
growth and colder winter weather
|
2.0
|
|||
FERC
jurisdiction transmission rate increase
|
1.1
|
|||
Montana
property tax tracker
|
(7.4
|
)
|
||
Transmission
volumes
|
(1.1
|
)
|
||
Other
|
4.7
|
|||
Improvement
in Gross Margin
|
$
|
16.8
|
46
Regulated
electric margin increased $16.8 million primarily due to rate increases and
lower QF supply costs. Although it was significantly cooler in the summer of
2008 as compared with 2007, our Montana residential customer usage related to
air-conditioning is less sensitive to these changes. The net increase in
customer usage is due to customer growth and colder winter weather. We recorded
gains (reduced cost of sales) related to our QF liability of $5.9 million
in 2008 and $0.9 million in 2007 as actual QF output and variable pricing terms
were lower than our estimate. Wholesale margin also improved from increased
plant availability and higher average prices. These increases were partly offset
by a decrease in revenues related to the recovery of our Montana property taxes
in rates. The decrease was due to lower 2008 property taxes, a credit to
customers related to the property tax settlement and a change in calculation by
the MPSC to reduce the allocation of property taxes to Montana electric retail
customers.
Total
retail electric volumes increased 211 MWHs, or 2.1%, due primarily to
residential and commercial customer growth and an increase in industrial
volumes. Wholesale electric volumes increased 110 MWHs, or 71.0%, due to
increased plant availability.
47
REGULATED
NATURAL GAS MARGIN
Year
Ended December 31, 2009 Compared with Year Ended December 31, 2008
The
following summarizes the regulated natural gas revenue, cost of sales, and gross
margin for the years ended December 31, 2009 and 2008:
Results
|
||||||||||||||
2009
|
2008
|
Change
|
%
Change
|
|||||||||||
(in
millions)
|
||||||||||||||
Retail
revenue
|
$
|
310.1
|
$
|
374.8
|
$
|
(64.7
|
)
|
(17.3
|
)%
|
|||||
Wholesale
and other
|
44.4
|
41.9
|
2.5
|
6.0
|
||||||||||
Total
Revenues
|
354.5
|
416.7
|
(62.2
|
)
|
(14.9
|
)
|
||||||||
Total
Cost of Sales
|
210.0
|
271.7
|
(61.7
|
)
|
(22.7
|
)
|
||||||||
Gross
Margin
|
$
|
144.5
|
$
|
145.0
|
$
|
(0.5
|
)
|
(0.3
|
)%
|
Revenues
|
Dekatherms
(Dkt)
|
Customer
Counts
|
|||||||||||||
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||
(in
thousands)
|
|||||||||||||||
Retail
Gas
|
|||||||||||||||
Montana
|
$
|
132,586
|
$
|
161,393
|
13,291
|
13,426
|
156,714
|
155,409
|
|||||||
South
Dakota
|
32,462
|
37,057
|
2,925
|
2,975
|
36,815
|
36,620
|
|||||||||
Nebraska
|
28,531
|
33,164
|
2,674
|
2,717
|
36,458
|
36,466
|
|||||||||
Residential
|
193,579
|
231,614
|
18,890
|
19,118
|
229,987
|
228,495
|
|||||||||
Montana
|
66,516
|
81,262
|
6,733
|
6,754
|
21,929
|
21,703
|
|||||||||
South
Dakota
|
26,567
|
31,318
|
3,315
|
3,104
|
5,837
|
5,780
|
|||||||||
Nebraska
|
20,760
|
26,910
|
2,903
|
2,962
|
4,504
|
4,532
|
|||||||||
Commercial
|
113,843
|
139,490
|
12,951
|
12,820
|
32,270
|
32,015
|
|||||||||
Industrial
|
1,650
|
2,406
|
170
|
207
|
295
|
303
|
|||||||||
Other
|
1,003
|
1,261
|
113
|
118
|
142
|
140
|
|||||||||
Total
Retail Gas
|
$
|
310,075
|
$
|
374,771
|
32,124
|
32,263
|
262,694
|
260,953
|
2009 as compared with:
|
|||||
Heating
Degree-Days
|
2008
|
Historic
Average
|
|||
Montana
|
1%
warmer
|
Remained
flat
|
|||
South
Dakota
|
Remained
flat
|
3%
colder
|
|||
Nebraska
|
2%
warmer
|
1%
colder
|
The
following summarizes the components of the changes in regulated natural gas
margin for the years ended December 31, 2009 and 2008:
Gross
Margin
|
||||
2009
vs. 2008
|
||||
(in
millions)
|
||||
Storage
|
$
|
(1.2
|
)
|
|
Other
|
0.7
|
|||
Reduction
in Gross Margin
|
$
|
(0.5
|
)
|
The
decline in margin is primarily due to a decreased return on working gas due to
lower average prices on gas in storage. Our wholesale and other revenues are
largely gross margin neutral as they are offset by changes in cost of sales. In
addition, average natural gas supply prices decreased, resulting in decreased
retail revenues and cost of sales in 2009 as compared with 2008, with no impact
to gross margin.
Overall
retail natural gas volumes declined slightly. The increase in South Dakota
commercial volumes was primarily related to higher grain drying requirements due
to harvest conditions in our service territory.
48
Year
Ended December 31, 2008 Compared with Year Ended December 31, 2007
The following summarizes the regulated
natural gas revenue, cost of sales, and gross margin for the years ended
December 31, 2008 and 2007:
Results
|
||||||||||||||
2008
|
2007
|
Change
|
%
Change
|
|||||||||||
(in
millions)
|
||||||||||||||
Retail
revenue
|
$
|
374.8
|
$
|
307.0
|
$
|
67.8
|
22.1
|
%
|
||||||
Wholesale
and other
|
41.9
|
56.6
|
(14.7
|
)
|
(26.0
|
)
|
||||||||
Total
Revenues
|
416.7
|
363.6
|
53.1
|
14.6
|
||||||||||
Total
Cost of Sales
|
271.7
|
236.0
|
35.7
|
15.1
|
||||||||||
Gross
Margin
|
$
|
145.0
|
$
|
127.6
|
$
|
17.4
|
13.6
|
%
|
Revenues
|
Dekatherms
(Dkt)
|
Customer
Counts
|
|||||||||||||
2008
|
2007
|
2008
|
2007
|
2008
|
2007
|
||||||||||
(in
thousands)
|
|||||||||||||||
Retail
Gas
|
|||||||||||||||
Montana
|
$
|
161,393
|
$
|
128,451
|
13,426
|
12,101
|
155,409
|
152,939
|
|||||||
South
Dakota
|
37,057
|
33,027
|
2,975
|
2,771
|
36,620
|
36,662
|
|||||||||
Nebraska
|
33,164
|
30,374
|
2,717
|
2,519
|
36,466
|
36,343
|
|||||||||
Residential
|
231,614
|
191,852
|
19,118
|
17,391
|
228,495
|
225,944
|
|||||||||
Montana
|
81,262
|
64,567
|
6,754
|
6,091
|
21,703
|
21,261
|
|||||||||
South
Dakota
|
31,318
|
24,018
|
3,104
|
2,444
|
5,780
|
5,765
|
|||||||||
Nebraska
|
26,910
|
23,784
|
2,962
|
2,655
|
4,532
|
4,523
|
|||||||||
Commercial
|
139,490
|
112,369
|
12,820
|
11,190
|
32,015
|
31,549
|
|||||||||
Industrial
|
2,406
|
1,749
|
207
|
169
|
303
|
311
|
|||||||||
Other
|
1,261
|
991
|
118
|
144
|
140
|
140
|
|||||||||
Total
Retail Gas
|
$
|
374,771
|
$
|
306,961
|
32,263
|
28,894
|
260,953
|
257,944
|
2008 as compared with:
|
|||||
Heating
Degree-Days
|
2007
|
Historic
Average
|
|||
Montana
|
9%
colder
|
1%
colder
|
|||
South
Dakota
|
9%
colder
|
2%
colder
|
|||
Nebraska
|
11%
colder
|
2%
colder
|
The
following summarizes the components of the changes in regulated natural gas
margin for the years ended December 31, 2008 and 2007:
Gross
Margin
|
||||
2008
vs. 2007
|
||||
(in
millions)
|
||||
Colder
weather and customer growth
|
$
|
6.0
|
||
South
Dakota and Nebraska jurisdictions transportation and distribution rate
increase
|
4.3
|
|||
Montana
jurisdiction transportation and distribution rate increase
|
5.1
|
|||
Montana
property tax tracker
|
(1.2
|
)
|
||
Other
|
3.2
|
|||
Improvement
in Gross Margin
|
$
|
17.4
|
Regulated
natural gas margin increased $17.4 million primarily due to increased volumes
and rate increases. Volumes increased 11.7% primarily due to colder winter
weather in all of our service territories, along with 1.2% customer growth.
These increases were partly offset by a decrease in revenues related to our
Montana property tax tracker as discussed above. In addition to the colder
weather, the increase in South Dakota commercial volumes was also related to
higher grain drying requirements due to harvest conditions in our service
territory.
49
UNREGULATED
ELECTRIC MARGIN
Year
Ended December 31, 2008 Compared with Year Ended December 31, 2007
As
discussed above in the “Overview” to the MD&A, in November 2008, the MPSC
approved placing our joint ownership interest in Colstrip Unit 4 into our
Montana utility rate base. Effective January 1, 2009, we no longer present an
unregulated electric segment and the results of operations of our interest in
Colstrip Unit 4 are reflected in the regulated electric segment as a component
of electric supply.
The
following summarizes the components of the changes in unregulated electric
revenue, cost of sales, and gross margin for the years ended December 31, 2008
and 2007:
Results
|
||||||||||||
2008
|
2007
|
Change
|
%
Change
|
|||||||||
(in
millions)
|
||||||||||||
Total
Revenues
|
$
|
77.7
|
$
|
74.2
|
$
|
3.5
|
4.7
|
%
|
||||
Total
Cost of Sales
|
23.5
|
18.0
|
5.5
|
30.6
|
%
|
|||||||
Gross
Margin
|
$
|
54.2
|
$
|
56.2
|
$
|
(2.0
|
)
|
(3.6
|
)%
|
|||
%
GM/Rev
|
69.8
|
%
|
75.7
|
%
|
The
following summarizes the components of the changes in unregulated electric
margin for the years ended December 31, 2008 and 2007:
Gross
Margin
|
||||
2008
vs. 2007
|
||||
(in
millions)
|
||||
Volumes
|
$
|
8.2
|
||
Average
prices
|
(6.8
|
)
|
||
Fuel
supply costs
|
(3.4
|
)
|
||
Decline
in Gross Margin
|
$
|
(2.0
|
)
|
The
decline in unregulated electric margin was primarily due to lower average prices
on contracts and higher fuel supply costs partially offset by an increase in
volumes from higher plant availability.
The
following summarizes unregulated electric volumes for the years ended December
31, 2008 and 2007:
Volumes
MWH
|
|||||||||
2008
|
2007
|
Change
|
%
Change
|
||||||
(in
thousands)
|
|||||||||
Wholesale
Electric
|
1,812
|
1,638
|
174
|
10.6
|
%
|
Unregulated
electric volumes increased from higher energy available to sell as compared with
2007 due to increased plant availability.
50
LIQUIDITY
AND CAPITAL RESOURCES
We
require liquidity to support and grow our business, and use our liquidity for
working capital needs, capital expenditures, investments in or acquisitions of
assets, to repay debt and, from time to time, to repurchase common stock. We
anticipate that our ongoing liquidity requirements will be satisfied through a
combination of operating cash flows, borrowings, and as necessary the issuance
of debt or equity securities, consistent with our objective of maintaining a
capital structure that will support a strong investment grade credit rating on a
long-term basis. The amount of capital expenditures and dividends are subject to
certain factors including the use of existing cash, cash equivalents and the
receipt of cash from operations. A material adverse change in operations or
available financing could impact our ability to fund our current liquidity and
capital resource requirements, and we may defer capital expenditures as
necessary.
We
utilize our revolver availability to manage our cash flows due to the
seasonality of our business, and utilize any cash on hand in excess of current
operating requirements to invest in our business and reduce borrowings. As of
December 31, 2009, our total net liquidity was approximately
$185.2 million, including $4.3 million of cash and $180.9 million of
revolving credit facility availability. A total of nine banks participate in our
revolving credit facility, with no one bank providing more than 14% of the total
availability. As of December 31, 2009, no bank has advised us of its intent to
withdraw from the revolving credit facility or not to honor its obligations. To
borrow from the revolving credit facility, we are required to maintain a maximum
debt to capitalization ratio not to exceed 65%. At December 31, 2009, we were in
compliance with this ratio. The revolving credit facility also contains default
and related acceleration provisions related to default on other debt. As of
February 5, 2010, our availability under our revolving credit facility was
approximately $199.4 million.
Credit
Ratings
Fitch
Ratings (Fitch), Moody's Investors Service (Moody's) and Standard and Poor's
Rating Group (S&P) are independent credit-rating agencies that rate our debt
securities. These ratings indicate the agencies' assessment of our ability to
pay interest and principal when due on our debt. As of February 6, 2010, our
ratings with these agencies were as follows:
Senior
Secured Rating
|
Senior
Unsecured Rating
|
Outlook
|
||||
Fitch
|
BBB+
|
BBB
|
Stable
|
|||
Moody’s
(1)
|
A3
|
Baa2
|
Positive
|
|||
S&P
|
A-
(MT)
BBB+
(SD)
|
BBB
|
Stable
|
|||
(1)
|
Moody’s
upgraded our senior secured and senior unsecured credit ratings on March
6, 2009 from Baa2 toBaa1 and Baa3 to Baa2, respectively. On August 3,
2009, Moody’s upgraded our senior secured credit rating from Baa1 to A3.
These changes are reflected above.
|
In
general, less favorable credit ratings make debt financing more costly and more
difficult to obtain on terms that are economically favorable to us and impacts
our trade credit availability. A security rating is not a recommendation to buy,
sell or hold securities. Such rating may be subject to revision or withdrawal at
any time by the credit rating agency and each rating should be evaluated
independently of any other rating.
Capital
Requirements
Our
capital expenditures program is subject to continuing review and modification.
Actual utility construction expenditures may vary from estimates due to changes
in electric and natural gas projected load growth, changing business operating
conditions and other business factors. We anticipate funding capital
expenditures through cash flows from operations, available credit sources and
future rate increases. Our estimated capital expenditures (excluding strategic
growth opportunities discussed below) for the next five years is as follows (in
thousands):
51
Year
|
Maintenance
|
Mill
Creek
Generating
Station
|
Total
|
||||||||||
2010
|
$
|
124,000
|
$
|
114,000
|
$
|
236,000
|
|||||||
2011
|
140,000
|
—
|
142,000
|
||||||||||
2012
|
148,000
|
—
|
148,000
|
||||||||||
2013
|
146,000
|
—
|
146,000
|
||||||||||
2014
|
142,000
|
—
|
142,000
|
The
increase in estimated maintenance capital expenditures from our historical
amounts and previous projections reflects our need to address aging
infrastructure to maintain reliability, as well as new capacity constraints
which are dependent upon load growth projections. Our growth capital falls
within the categories of transmission and generation.
Mill Creek Generating Station
- We have entered into two key contracts related to the Mill Creek Generating
Station. In July 2009, we entered into a gas turbine purchase agreement (Gas
Turbine Agreement) with Pratt & Whitney Power Systems, Inc. The total
contract price to be paid by us under the agreement is approximately
$80.5 million. In July 2009, we also entered into an Engineering,
Procurement and Construction Services Agreement (EPC Agreement) with NewMech
Companies, Inc., for design, engineering, procurement, construction management
and construction. The total contract price, assuming all conditions and
covenants under the EPC Agreement are satisfied, is approximately $54.1 million.
We are required to make monthly progress payments to NewMech under the EPC
Agreement. These two contracts represent approximately 67% of the projected $202
million cost. We have paid approximately $56.4 million and $9.5 million under
the Gas Turbine and EPC Agreements during 2009, respectively, which is included
in construction work in progress. As of December 31, 2009 we have capitalized
approximately $84.7 million in construction work in progress related to this
project.
Strategic Growth Capital
Expenditures - We have three significant transmission projects currently
being contemplated, as discussed in the strategy section. The Colstrip
500 kV upgrade has a projected total capital cost of $125 million of which
we assume a 30% ownership and an estimated completion date by the end of 2012.
The MSTI project has an estimated cost of $1 billion with an anticipated
completion date in 2015. Decisions whether to partner and/or resize the line due
to demand would impact the ultimate capital expected from us. The capital
requirements for the 230 kV collector system project are dependent upon the
outcome of the open season in process that will determine the size of the
project. Costs for this project could exceed $200 million. We currently estimate
capital expenditures related to these projects to range between approximately
$20 and $25 million in 2010. We are currently in the process of determining
future capital needs related to additional distribution investment and wind
generation opportunities. We do not expect capital expenditures related to these
projects to be significant in 2010.
The
timing of and commitment to these proposed strategic transmission growth
projects is solely at our discretion. Significant financial commitments are not
made until appropriate commercial assurances and regulatory approvals, as
applicable, have been secured, thus limiting our risk to prudent
levels.
52
Contractual
Obligations and Other Commitments
We have a
variety of contractual obligations and other commitments that require payment of
cash at certain specified periods. The following table summarizes our
contractual cash obligations and commitments as of December 31, 2009. See
additional discussion in Note 17 – Commitments and Contingencies in the Notes to
Consolidated Financial Statements.
Total
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
||||||||||||||||
(in
thousands)
|
||||||||||||||||||||||
Long-term
Debt
|
$
|
987,419
|
$
|
6,123
|
$
|
6,578
|
$
|
69,792
|
$
|
—
|
$
|
225,000
|
$
|
679,926
|
||||||||
Capital
Leases
|
36,767
|
1,197
|
1,282
|
1,370
|
1,468
|
1,582
|
29,868
|
|||||||||||||||
Future
minimum operating lease payments
|
3,696
|
1,529
|
1,079
|
688
|
86
|
63
|
251
|
|||||||||||||||
Estimated
Pension and Other Postretirement Obligations (1)
|
51,000
|
13,800
|
13,800
|
13,800
|
4,800
|
4,800
|
N/A
|
|||||||||||||||
Qualifying
Facilities (2)
|
1,397,595
|
63,589
|
65,323
|
67,111
|
69,816
|
72,354
|
1,059,402
|
|||||||||||||||
Supply
and Capacity Contracts (3)
|
1,671,110
|
363,046
|
191,948
|
174,494
|
161,983
|
120,289
|
659,351
|
|||||||||||||||
Other
Purchase Obligations (4)
|
70,790
|
70,790
|
—
|
—
|
—
|
—
|
—
|
|||||||||||||||
Contractual
interest payments on debt (5)
|
520,326
|
55,574
|
55,187
|
53,702
|
52,512
|
52,512
|
250,839
|
|||||||||||||||
Total
Commitments (6)
|
$
|
4,738,703
|
$
|
575,648
|
$
|
335,197
|
$
|
380,957
|
$
|
290,665
|
$
|
476,600
|
$
|
2,679,637
|
(1)
|
We
have estimated cash obligations related to our pension and other
postretirement benefit programs for five years, as it is not practicable
to estimate thereafter. These estimates reflect our expected cash
contributions, which may be in excess of minimum funding
requirements.
|
(2)
|
The
QFs require us to purchase minimum amounts of energy at prices ranging
from $65 to $167 per MWH through 2029. Our estimated gross contractual
obligation related to the QFs is approximately $1.4 billion. A portion of
the costs incurred to purchase this energy is recoverable through rates
authorized by the MPSC, totaling approximately $1.1
billion.
|
(3)
|
We
have entered into various purchase commitments, largely purchased power,
coal and natural gas supply and natural gas transportation contracts.
These commitments range from one to 19
years.
|
(4)
|
This
represents contractual purchase obligations related to the Mill Creek
Generating Station construction
project.
|
(5)
|
Contractual
interest payments includes our revolving credit facility, which has a
variable interest rate. We have assumed an average interest rate of 3.23%
on an estimated revolving line of credit balance of $66.0 million through
maturity in June 2012.
|
(6)
|
Potential
tax payments related to uncertain tax positions are not practicable to
estimate and have been excluded from this
table.
|
53
Cash
Flows
Factors
Impacting our Liquidity
Supply Costs - Our operations
are subject to seasonal fluctuations in cash flow. During the heating season,
which is primarily from November through March, cash receipts from natural
gas sales and transportation services typically exceed cash requirements. During
the summer months, cash on hand, together with the seasonal increase in cash
flows and utilization of our existing revolver, are used to purchase natural gas
to place in storage, perform maintenance and make capital
improvements.
The
effect of this seasonality on our liquidity is also impacted by changes in the
market prices of our electric and natural gas supply, which is recovered through
various monthly cost tracking mechanisms. These energy supply tracking
mechanisms are designed to provide stable and timely recovery of supply costs on
a monthly basis during the July to June annual tracking period, with
an adjustment in the following annual tracking period to correct for any under
or over collection in our monthly trackers. Due to the lag between our purchases
of electric and natural gas commodities and revenue receipt from customers,
cyclical over and under collection situations arise consistent with the seasonal
fluctuations discussed above; therefore we usually under collect in the fall and
winter and over collect in the spring. Fluctuations in recoveries under our cost
tracking mechanisms can have a significant effect on cash flow from operations
and make year-to-year comparisons difficult.
As of
December 31, 2009, we are under collected on our current Montana natural gas and
electric trackers by approximately $19.8 million, as compared with an under
collection of $10.5 million as of December 31, 2008, and an over collection of
approximately $4.0 million as of December 31, 2007. This under collection is
primarily due to the volatility of commodity prices.
Pension Plan Contributions –
During the year ended December 31, 2009, we made contributions of
$92.9 million to our qualified pension plans, as compared with $32.7
million in 2008. The 2009 contributions exceeded our minimum funding
requirements by approximately $75.0 million and were made to improve the funded
status of our plans as well as reduce future contribution
requirements.
Financing Transactions - In
March 2009, we received net proceeds of approximately $249.8 million from the
issuance of Montana First Mortgage Bonds at a fixed interest rate of 6.34%
maturing April 1, 2019. We used the proceeds to redeem our $100 million Colstrip
Lease Holdings LLC term loan, repay outstanding borrowings on our revolving
credit facility, repay other outstanding debt obligations of $31.7 million
related to Colstrip Unit 4, fund a portion of the costs of the Mill Creek
Generating Station project, and capital expenditures.
On June
30, 2009, we amended and restated our unsecured revolving line of credit
scheduled to expire on November 1, 2009. The amended facility extends the term
to June 30, 2012, and increases the aggregate principal amount available under
the facility by $50 million to $250 million. The amended facility does not
amortize and borrowings will bear interest based on a credit ratings grid. The
‘spread’ or ‘margin’ ranges from 2.25% to 4.0% over the London Interbank Offered
Rate (LIBOR). As of December 31, 2009, the applicable spread was 3.0%. A total
of nine banks participate in the new facility, with no one bank providing more
than 14.0% of the total availability. The amended facility contains covenants
substantially similar to the previous facility.
On
October 15, 2009 we issued $55 million of Montana First Mortgage Bonds at a
fixed interest rate of 5.71% maturing October 15, 2039. We used the proceeds to
fund a portion of the costs of the Mill Creek Generating Station project and
capital expenditures.
54
The
following table summarizes our consolidated cash flows for 2009, 2008 and
2007.
Year
Ended December 31,
|
||||||||||
2009
|
2008
|
2007
|
||||||||
Operating
Activities
|
||||||||||
Net
income
|
$
|
73.4
|
$
|
67.6
|
$
|
53.2
|
||||
Non-cash
adjustments to net income
|
137.5
|
132.3
|
113.1
|
|||||||
Changes
in working capital
|
(40.3
|
)
|
(7.8
|
)
|
26.9
|
|||||
Other
noncurrent assets and liabilities
|
(53.8
|
)
|
6.2
|
8.8
|
||||||
116.8
|
198.3
|
202.0
|
||||||||
Investing
Activities
|
||||||||||
Property,
plant and equipment additions
|
(189.4
|
)
|
(124.6
|
)
|
(117.1
|
)
|
||||
Colstrip
Unit 4 acquisition
|
—
|
—
|
(141.3
|
)
|
||||||
Sale
of assets
|
0.3
|
0.2
|
1.9
|
|||||||
(189.1
|
)
|
(124.4
|
)
|
(256.5
|
)
|
|||||
Financing
Activities
|
||||||||||
Net
borrowing of debt
|
125.0
|
54.6
|
46.5
|
|||||||
Dividends
on common stock
|
(48.2
|
)
|
(49.8
|
)
|
(47.3
|
)
|
||||
Treasury
stock activity
|
(0.7
|
)
|
(78.7
|
)
|
(0.9
|
)
|
||||
Proceeds
from exercise of warrants
|
—
|
—
|
68.8
|
|||||||
Other
|
(10.8
|
)
|
(1.5
|
)
|
(1.7
|
)
|
||||
65.3
|
(75.4
|
)
|
65.4
|
|||||||
Net
(Decrease) Increase in Cash and Cash Equivalents
|
$
|
(7.0
|
)
|
$
|
(1.5
|
)
|
$
|
10.9
|
||
Cash
and Cash Equivalents, beginning of period
|
$
|
11.3
|
$
|
12.8
|
$
|
1.9
|
||||
Cash
and Cash Equivalents, end of period
|
$
|
4.3
|
$
|
11.3
|
$
|
12.8
|
Cash
Flows Provided By Operating Activities
As of
December 31, 2009, our cash and cash equivalents were $4.3 million as compared
with $11.3 million at December 31, 2008. Cash provided by operating activities
totaled $116.8 million for the year ended December 31, 2009 as compared
with $198.3 million during 2008. This decrease in operating cash flows is
primarily related to pension funding of $92.9 million, which was an
increase of approximately $60.2 million as compared with 2008, payment of the
Ammondson verdict in the fourth quarter of 2009 of approximately $26.7 million
and a $10.8 million prepayment of a power purchase agreement, offset by
lower commodity prices reflected in the change in accounts receivable, as well
as decreased cash outflows for natural gas storage injections.
Our 2008
operating cash flows decreased by approximately $3.7 million as compared with
2007 due to the combination of a $14.5 million change in our supply tracker due
to an under collected position as discussed above, an increase in accounts
receivable of $18.5 million due to colder winter weather and higher average
prices in December 2008, and increased pension funding of approximately
$10.1 million. These decreases in operating cash flows were offset in part
by higher net income, improved operating cash flows related to our Colstrip Unit
4 lease buyout of approximately $6.0 million, and the inclusion in 2007
operating cash flows of an additional semi-annual Colstrip Unit 4 lease payment
of $16.1 million due to calendar timing.
Cash
Flows Used In Investing Activities
Cash used
in investing activities totaled $189.1 million during the year ended December
31, 2009, as compared with $124.4 million during 2008, and $256.5 million in
2007. During 2009, we invested $189.4 million in property, plant and equipment
additions, including approximately $83.4 million related to Mill Creek
Generating Station, as compared with $124.6 million in property, plant and
equipment additions during 2008. During the same period in 2007, we used $141.3
million to complete the purchases of the Owner Participant interests in portions
of the Colstrip Unit 4 generating facility, and $117.1 million for property,
plant and equipment additions, partially offset by $1.9 million of proceeds
received from the sale of assets.
55
Cash
Flows Provided By (Used In) Financing Activities
Cash
provided by financing activities totaled $65.3 million during 2009, as compared
with cash used in financing activities of $75.4 million during 2008, and cash
provided of $65.4 million during 2007. During 2009 we received net proceeds from
the issuance of debt of $304.8 million (see “Financing Transactions” discussion
above), made net debt repayments of $179.8 million, paid deferred financing
costs of $10.8 million and paid dividends on common stock of $48.2 million.
During 2008, cash used to repurchase shares under our previously announced plan
was approximately $77.7 million. We had net borrowings on our revolving credit
facility of $96.0 million, and debt repayments of $41.4 million. Dividends paid
on common stock during 2008 were approximately $49.8 million.
During
2007, we received proceeds of $100 million from the issuance of debt, made debt
repayments of $53.5 million and paid dividends on common stock of
$47.3 million. In addition, we received proceeds during 2007 of $68.8
million from the exercise of warrants.
CRITICAL
ACCOUNTING POLICIES AND ESTIMATES
Management's
discussion and analysis of financial condition and results of operations is
based on our consolidated financial statements, which have been prepared in
accordance with GAAP. The preparation of these financial statements requires us
to make estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses, and related disclosure of contingent assets
and liabilities. We base our estimates on historical experience and other
assumptions that are believed to be proper and reasonable under the
circumstances. We continually evaluate the appropriateness of our estimates and
assumptions, including those related to goodwill, qualifying facilities
liabilities, impairment of long-lived assets and revenue recognition, among
others. Actual results could differ from those estimates.
We have
identified the policies and related procedures below as critical to
understanding our historical and future performance, as these polices affect the
reported amounts of revenue and the more significant areas involving
management's judgments and estimates.
Goodwill
and Long-lived Assets
We assess
the carrying value of our goodwill for impairment at least annually (October 1)
and more frequently when indications of impairment exist. We calculate the fair
value of our segments and reporting units by considering various factors,
including valuation studies based primarily on a discounted cash flow
methodology and published industry valuations and market data as supporting
information. These calculations are dependent on subjective factors such as
management’s estimate of future cash flows and the selection of appropriate
discount and growth rates. These underlying assumptions and estimates are made
as of a point in time; subsequent changes in these assumptions could result in a
future impairment charge. We monitor for events or circumstances that may
indicate an interim goodwill impairment test is necessary. Accounting standards
require that if the fair value of a reporting unit is less than its carrying
value including goodwill, an impairment charge for goodwill must be recognized
in the financial statements. To measure the amount of an impairment loss, the
implied fair value of the reporting unit's goodwill is compared with its
carrying value.
We
evaluate our property, plant and equipment for impairment if an indicator of
impairment exists. If the sum of the undiscounted cash flows from a company's
asset, without interest charges, is less than the carrying value of the asset,
impairment must be recognized in the financial statements. If an asset is deemed
to be impaired, then the amount of the impairment loss recognized represents the
excess of the asset's carrying value as compared to its estimated fair value,
based on management's assumptions and projections.
We
believe that the accounting estimate related to determining the fair value of
goodwill and long-lived assets, and thus any impairment, is a “critical
accounting estimate" because: (i) it is highly susceptible to change from period
to period since it requires company management to make cash flow assumptions
about future revenues, operating costs and discount rates over an indefinite
life; and (ii) recognizing an impairment could have a significant impact on the
assets reported in our Consolidated Balance Sheets and our Consolidated
Statements of Income. Management's assumptions about future margins and volumes
require significant judgment because actual margins and volumes have fluctuated
in the past and are expected to continue to do so. In estimating future margins,
we use our internal budgets.
56
Qualifying
Facilities Liability
Certain
QF contracts under the Public Utility Regulatory Policies Act (PURPA) require us
to purchase minimum amounts of energy at prices ranging from $65 to $167 per MWH
through 2029. As of December 31, 2009, our estimated gross contractual
obligation related to the QFs is approximately $1.4 billion. A portion of the
costs incurred to purchase this energy is recoverable though rates authorized by
the MPSC, totaling approximately $1.1 billion through 2029. We maintain a
liability based on the net present value (discounted at 7.75%) of the difference
between our estimated obligations under the QFs and the related amounts
recoverable in rates.
There are
ten contracts encompassed in the QF liability. Three of these contracts account
for more than 98% of the output. The liability was established based on certain
assumptions and projections over the contract terms related to pricing,
estimated output and recoverable amounts. The estimated capacity factor for each
QF and the estimated escalation rate for one of the contracts are key
assumptions. The estimated capacity factors are primarily based on historical
actual capacity factors. The estimated escalation rate for the one contract was
based on a combination of historical actual results and market data available
for future projections. Since the liability is based on projections over a
25-year period; actual QF output, changes in pricing, contract amendments and
regulatory decisions relating to QFs could significantly impact the liability
and our results of operations in any given year.
In
assessing the liability each reporting period, we compare our assumptions to
actual results and make adjustments as necessary for that period.
In
December 2006, the MPSC issued an order finalizing certain QF rates for the
periods July 1, 2003 through June 30, 2006. The result of this order could
provide for a significant reduction to our QF liability, as it reduces the
escalating energy and capacity rates for one contract that we utilize in
determining the present value of our obligation. We are currently in litigation
with a QF over this matter and we cannot predict the outcome of this litigation,
therefore we have not changed our historical assumptions or reduced the
liability. We will continue to assess the status of the litigation and do not
anticipate changing our assumptions until we can determine a probable outcome.
See Note 17 – Commitments and Contingencies in the Notes to Consolidated
Financial Statements for further discussion of this litigation.
Revenue
Recognition
Revenues
are recognized differently depending on the various jurisdictions. For our South
Dakota and Nebraska operations, consistent with historic treatment in the
respective jurisdictions, electric and natural gas utility revenues are based on
billings rendered to customers. For our Montana operations, operating revenues
are recorded monthly on the basis of consumption or services rendered. Customers
are billed on a monthly cycle basis. To match revenues with associated expenses,
we accrue unbilled revenues for electric and natural gas services delivered to
the customers but not yet billed at month-end. The calculation of unbilled
revenue is affected by factors that include fluctuations in energy demand for
the unbilled period, seasonality, weather, customer usage patterns, price in
effect for each customer class and estimated transmission and distribution line
losses. We base our estimate of unbilled revenue each period on the volume of
energy delivered, as valued by the billing cycle and historical usage rates and
growth by customer class for our service area. This figure is then adjusted for
the projected impact of seasonal and weather variations.
Regulatory
Assets and Liabilities
Our
operations are subject to the provisions of ASC 980, Accounting for the Effects of
Certain Types of Regulation. Our regulatory assets are the probable
future revenues associated with certain costs to be recovered from customers
through the ratemaking process, including our estimate of amounts recoverable
for natural gas and electric supply purchases. Regulatory liabilities are the
probable future reductions in revenues associated with amounts to be credited to
customers through the ratemaking process. We determine which costs are
recoverable by consulting previous rulings by state regulatory authorities in
jurisdictions where we operate or other factors that lead us to believe that
cost recovery is probable. This accounting treatment is impacted by the
uncertainties of our regulatory environment, anticipated future regulatory
decisions and their impact. If any part of our operations becomes no longer
subject to the provisions of ASC 980, or facts and circumstances lead us to
conclude that a recorded regulatory asset is no longer probable of recovery, we
would record a charge to earnings, which could be material. In addition, we
would need to determine if there was any impairment to the carrying costs of the
associated plant and inventory assets.
57
While we
believe that our assumptions regarding future regulatory actions are reasonable,
different assumptions could materially affect our results. See Note 14 –
Regulatory Assets and Liabilities in the Notes to Consolidated Financial
Statements for further discussion.
Pension
and Postretirement Benefit Plans
We
sponsor and/or contribute to pension, postretirement health care and
life insurance benefits for eligible employees. Our reported costs of providing
pension and other postretirement benefits, as described in Note 12 to the
Consolidated Financial Statements, are dependent upon numerous factors including
the provisions of the plans, changing employee demographics, rate of return on
plan assets and other economic conditions, and various actuarial calculations,
assumptions, and accounting mechanisms. As a result of these factors,
significant portions of pension and other postretirement benefit costs recorded
in any period do not reflect (and are generally greater than) the actual
benefits provided to plan participants. Due to the complexity of these
calculations, the long-term nature of the obligations, and the importance of the
assumptions utilized, the determination of these costs is considered a critical
accounting estimate.
Assumptions
Key
actuarial assumptions utilized in determining these costs include:
·
|
Discount
rates used in determining the future benefit
obligations;
|
·
|
Projected
health care cost trend rates;
|
·
|
Expected
long-term rate of return on plan assets;
and
|
·
|
Rate
of increase in future compensation
levels.
|
We review
these assumptions on an annual basis and adjust them as necessary. The
assumptions are based upon information available as of the beginning of the
year, specifically; market interest rates, past experience and management's best
estimate of future economic conditions.
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. Based on this analysis, in 2009 we
reduced our discount rate on the NorthWestern Corporation pension plan from
6.25% to 5.75% and on the NorthWestern Energy pension plan from 6.25% to
6.00%.
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 800 members),
the assumptions used are based upon both nationally expected trends and our
specific expected trends. Our average increase remains consistent with the
nationally expected trends. The long-term trend assumption is based upon our
actuary's macroeconomic forecast, which includes assumed long-term nominal gross
domestic product (GDP) growth plus the expected excess growth in national health
expenditures versus GDP, the assumed impact of population growth and aging, and
variations by healthcare sector. Based on this review, the health care cost
trend rate used in calculating the accumulated postretirement benefit obligation
remained unchanged from 2008, which was a 10% increase in health care costs in
2008, with a reset to 9.5% in 2009 and gradually decreasing each successive year
by 0.25% until it reaches an ultimate trend of 4.5% annual increase in health
care costs.
In
determining the expected long-term rate of return on plan assets, we review
historical returns, the future expectations for returns for each asset class
weighted by the target asset allocation of the pension and postretirement
portfolios, and long-term inflation assumptions. During 2009, we revised our
target asset allocation from 70% equity securities, and 30% fixed-income
securities to 60% equity securities, and 40% fixed-income securities.
Considering this information and future expectations for asset returns, we
reduced our expected long-term rate of return on assets assumption from 8.00% to
7.75% for 2010. The assumed rate of increase in future compensation levels used
to calculate benefit obligations was a weighted average of 3.50% for union and
3.55% - 3.58% for nonunion employees in 2009.
58
Cost
Sensitivity
The
following table reflects the sensitivity of pension costs to changes in certain
actuarial assumptions (in thousands):
Actuarial
Assumption
|
Change
in Assumption
|
Impact
on Pension Cost
|
Impact
on Projected Benefit Obligation
|
|||||||||
Discount
rate
|
0.25
|
%
|
$
|
(997
|
)
|
$
|
(11,390
|
)
|
||||
(0.25
|
)
|
1,001
|
11,697
|
|||||||||
Rate
of return on plan assets
|
0.25
|
(700
|
)
|
N/A
|
||||||||
(0.25
|
)
|
700
|
N/A
|
Accounting
Treatment
We
recognize the funded status of each plan as an asset or liability in the
Consolidated Balance Sheets. 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, which reduces the
volatility of reported pension costs. If necessary, the excess is amortized over
the average remaining service period of active employees.
Due to
the various regulatory treatments of the plans, our financial statements reflect
the effects of the different rate making principles followed by the jurisdiction
regulating us. Pension costs in Montana and other postretirement benefit costs
in South Dakota are included in rates on a pay as you go basis for regulatory
purposes. Pension costs in South Dakota and other postretirement benefit costs
in Montana are included in rates on an accrual basis for regulatory purposes.
Regulatory assets have been recognized for the obligations that will be included
in future cost of service.
Income
Taxes
Judgment
and the use of estimates are required in developing the provision for income
taxes and reporting of tax-related assets and liabilities. Deferred income tax
assets and liabilities represent the future effects on income taxes from
temporary differences between the bases of assets and liabilities for financial
reporting and tax purposes. Deferred tax assets and liabilities are measured
using enacted tax rates expected to apply to taxable income in the years in
which those temporary differences are expected to be recovered or settled. The
probability of realizing deferred tax assets is based on forecasts of future
taxable income and the availability of tax planning strategies that can be
implemented, if necessary, to realize deferred tax assets. We establish a
valuation allowance when it is more likely than not that all, or a portion of, a
deferred tax asset will not be realized. Exposures exist related to various tax
filing positions, which may require an extended period of time to resolve and
may result in income tax adjustments by taxing authorities. We have reduced
deferred tax assets or established liabilities based on our best estimate of
future probable adjustments related to these exposures. On a quarterly basis, we
evaluate exposures in light of any additional information and make adjustments
as necessary to reflect the best estimate of the future outcomes. We currently
estimate that as of December 31, 2009, we have approximately $476 million
of CNOLs to offset federal taxable income in future years. We believe our
deferred tax assets and established liabilities are appropriate for estimated
exposures; however, actual results may differ significantly from these
estimates.
The
interpretation of tax laws involves uncertainty. Ultimate resolution of income
tax matters may result in favorable or unfavorable impacts to net income and
cash flows and adjustments to tax-related assets and liabilities could be
material. The uncertainty and judgment involved in the determination and filing
of income taxes is accounted for by prescribing a minimum recognition threshold
that a tax position is required to meet before being recognized in the financial
statements. We recognize tax positions that meet the more-likely-than-not
threshold 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. We have unrecognized tax
benefits of approximately $122.8 million as of December 31, 2009. The resolution
of tax matters in a particular future period could have a material impact on our
cash flows, results of operations and provision for income taxes.
59
NEW
ACCOUNTING STANDARDS
See Note
2, Significant Accounting Policies, to the Consolidated Financial Statements,
included in Item 8 herein for a discussion of new accounting
standards.
60
We are
exposed to market risks, including, but not limited to, interest rates, energy
commodity price volatility, and credit exposure. Management has established
comprehensive risk management policies and procedures to manage these market
risks.
Interest
Rate Risk
We
utilize various risk management instruments to reduce our exposure to market
interest rate changes. These risks include exposure to adverse interest rate
movements for outstanding variable rate debt and for future anticipated
financings. All of our debt has fixed interest rates, with the exception of our
revolving credit facility. The revolving credit facility bears interest at the
lower of prime or available rates tied to the London Interbank Offered Rate
(LIBOR) plus a credit spread, ranging from 2.25% to 4.0% over LIBOR. As of
December 31, 2009, the applicable spread was 3.0%, resulting in a borrowing rate
of 3.23%. Based upon amounts outstanding as of December 31, 2009, a 1% increase
in the LIBOR would increase our annual interest expense by approximately
$0.7 million.
Commodity
Price Risk
Commodity
price risk is a significant risk due to our lack of ownership of natural gas
reserves and minimal ownership of regulated electric generation assets within
the Montana market. Several factors influence price levels and volatility. These
factors include, but are not limited to, seasonal changes in demand, weather
conditions, available generating assets within regions, transportation
availability and reliability within and between regions, fuel availability,
market liquidity, and the nature and extent of current and potential federal and
state regulations.
As part
of our overall strategy for fulfilling our regulated electric supply
requirements, we employ the use of market purchases, including forward purchase
and sales contracts. These types of contracts are included in our electric and
natural gas supply portfolios and are used to manage price volatility risk by
taking advantage of seasonal fluctuations in market prices. While we may incur
gains or losses on individual contracts, the overall portfolio approach is
intended to provide price stability for consumers; therefore, these commodity
costs are included in our cost tracking mechanisms.
Our
“other” segment includes a pipeline capacity contract through October 2013 that
was primarily used to serve natural gas supply to one customer. During the
second quarter of 2009, this customer terminated their natural gas supply
contract with us during their bankruptcy proceedings. As a result of the supply
contract termination, we have excess capacity. We recognized a $1.5 million loss
during the year ended December 31, 2009 based on our release of the excess
capacity through October 2010 and our estimate of the market value for the
excess capacity during the remaining term. Our remaining maximum exposure is
approximately $0.9 million related to this contract. We have no other remaining
capacity contracts outside of our regulated utility operations.
Counterparty
Credit Risk
We are
exposed to counterparty credit risk related to the ability of our counterparties
to meet their contractual payment obligations, and the potential non-performance
of counterparties to deliver contracted commodities or services at the
contracted price. We have risk management policies in place to limit our
transactions to high quality counterparties, and continue to monitor closely the
status of our counterparties, and will take action, as appropriate, to further
manage this risk. This includes, but is not limited to, requiring letters of
credit or prepayment terms. There can be no assurance, however, that the
management tools we employ will eliminate the risk of loss.
61
The
consolidated financial information, including the reports of independent
accountants, the quarterly financial information, and the financial statement
schedules, required by this Item 8 is set forth on pages F-1 to F-48 of this
Annual Report on Form 10-K and is hereby incorporated into this Item 8 by
reference.
ITEM 9. CHANGES IN AND
DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
None.
Evaluation
of Disclosure Controls and Procedures
We have
established disclosure controls and procedures designed to ensure that
information required to be disclosed in the reports we file or submit under the
Securities Exchange Act of 1934 is recorded, processed, summarized and reported,
within the time periods specified in the SEC's rules and forms and accumulated
and reported to management, including the principal executive officer and
principal financial officer, to allow timely decisions regarding required
disclosure.
We
conducted an evaluation, under the supervision and with the participation of our
principal executive officer and principal financial officer, of our disclosure
controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the
Securities Exchange Act of 1934). Based on this evaluation our principal
executive officer and principal financial officer have concluded that, as of
December 31, 2009, our disclosure controls and procedures are
effective.
Changes
in Internal Control over Financial Reporting
There
have been no changes in our internal controls over financial reporting for the
three-months ended December 31, 2009 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.
Management's
Report on Internal Controls over Financial Reporting
The
management of NorthWestern is responsible for establishing and maintaining
adequate internal control over financial reporting. Our internal control system
was designed to provide reasonable assurance to our management and Board of
Directors regarding the preparation and fair presentation of published financial
statements.
All
internal controls over financial reporting, no matter how well designed, have
inherent limitations, including the possibility of human error and the
circumvention or overriding of controls. Therefore, even effective internal
control over financial reporting can provide only reasonable assurance with
respect to financial statement preparation and presentation. Further, because of
changes in conditions, the effectiveness of internal controls over financial
reporting may vary over time.
Our
management, including our chief executive officer and chief financial officer,
assessed the effectiveness of our internal control over financial reporting as
of December 31, 2009. In making its assessment of internal control over
financial reporting, management used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO) in Internal
Control—Integrated Framework. Based on our evaluation, management concluded
that, as of December 31, 2009, our internal control over financial reporting was
effective based on those criteria.
Our
independent registered public accounting firm has issued an attestation report
on our internal control over financial reporting. Their report appears on page
F-3.
62
Not
applicable.
Part
III
The
information required by this item with respect to directors and corporate
governance will be set forth in NorthWestern Corporation's Proxy Statement for
its 2010 Annual Meeting of Shareholders, which is incorporated by reference.
Information with respect to our Executive Officers is included in Item 1 to this
report.
Information
required by this Item will be set forth in NorthWestern Corporation's Proxy
Statement for its 2010 Annual Meeting of Shareholders, which is incorporated by
reference.
ITEM 12. SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER
MATTERS
Information
required by this item will be set forth in NorthWestern Corporation's Proxy
Statement for its 2010 Annual Meeting of Shareholders, which is incorporated by
reference. Information with respect to issuance under equity compensation plans
is included in Part II, Item 5 to this report.
ITEM
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
Information
concerning relationships and related transactions of the directors and officers
of NorthWestern Corporation and director independence will be set forth in
NorthWestern Corporation's Proxy Statement for its 2010 Annual Meeting of
Shareholders, which is incorporated by reference.
Information
concerning fees paid to the principal accountant for each of the last two years
is contained in NorthWestern Corporation's Proxy Statement for its 2010 Annual
Meeting of Shareholders, which is incorporated by reference.
63
Part
IV
The
following documents are filed as part of this report:
(1)
|
Financial
Statements.
|
The
following items are included in Part II, Item 8 of this annual report on Form
10-K:
FINANCIAL
STATEMENTS:
Page
|
|
Reports
of Independent Registered Public Accounting Firm
|
F-2
|
Consolidated
Statements of Income for the Years Ended December 31, 2009, 2008 and
2007
|
F-4
|
Consolidated
Statements of Cash Flows for the Years Ended December 31, 2009, 2008
and 2007
|
F-5
|
Consolidated
Balance Sheets as of December 31, 2009 and 2008
|
F-6
|
Consolidated
Statements of Shareholders' Equity and Comprehensive Income for the Years
Ended December 31, 2009, 2008 and 2007
|
F-7
|
Notes
to Consolidated Financial Statements
|
F-8
|
Quarterly
Unaudited Financial Data for the Two Years Ended December 31,
2009
|
F-47
|
(2)
|
Financial
Statement Schedule
|
Schedule II.
Valuation and Qualifying Accounts
|
F-48
|
Schedule
II, Valuation and Qualifying Accounts, is included in Part II, Item 8 of this
annual report on
Form 10-K.
All other schedules are omitted because they are not applicable or the required
information is shown in the Consolidated Financial Statements or the Notes
thereto.
64
(3)
|
Exhibits.
|
The
exhibits listed below are hereby filed with the SEC, as part of this Annual
Report on Form 10-K. Certain of the following exhibits have been previously
filed with the SEC pursuant to the requirements of the Securities Act of 1933 or
the Securities Exchange Act of 1934. Such exhibits are identified by the
parenthetical references following the listing of each such exhibit and are
incorporated by reference. We will furnish a copy of any exhibit upon request,
but a reasonable fee may be charged to cover our expenses in furnishing such
exhibit.
Exhibit
Number
|
Description
of Document
|
|||
2.1(a)
|
Second
Amended and Restated Plan of Reorganization of NorthWestern Corporation
(incorporated by reference to Exhibit 2.1 of NorthWestern
Corporation's Current Report on Form 8-K, dated October 20,
2004, Commission File No. 1-10499).
|
|||
2.1(b)
|
Order
Confirming the Second Amended and Restated Plan of Reorganization of
NorthWestern Corporation (incorporated by reference to Exhibit 2.2 of
NorthWestern Corporation's Current Report on Form 8-K, dated
October 20, 2004, Commission File
No. 1-10499).
|
|||
3.1
|
Amended
and Restated Certificate of Incorporation of NorthWestern Corporation,
dated November 1, 2004 (incorporated by reference to Exhibit 3.1
of NorthWestern Corporation's Current Report on Form 8-K, dated
October 20, 2004, Commission File
No. 1-10499).
|
|||
3.2
|
Amended
and Restated By-Laws of NorthWestern Corporation, dated June 27, 2006
(incorporated by reference to Exhibit 3.1 of NorthWestern Corporation's
Current Report on Form 8-K, dated June 27, 2006, Commission File No.
1-10499).
|
|||
4.1(a)
|
General
Mortgage Indenture and Deed of Trust, dated as of August 1, 1993,
from NorthWestern Corporation to The Chase Manhattan Bank (National
Association), as Trustee (incorporated by reference to
Exhibit 4(a) of NorthWestern Corporation's Current Report on
Form 8-K, dated August 16, 1993, Commission File
No. 1-10499).
|
|||
4.1(b)
|
Supplemental
Indenture, dated as of November 1, 2004, by and between NorthWestern
Corporation (formerly known as Northwestern Public Service Company) and
JPMorgan Chase Bank (successor by merger to The Chase Manhattan Bank
(National Association)), as Trustee under the General Mortgage Indenture
and Deed of Trust dated as of August 1, 1993 (incorporated by
reference to Exhibit 4.5 of NorthWestern Corporation's Current Report
on Form 8-K, dated November 1, 2004, Commission File
No. 1-10499).
|
|||
4.1(c)
|
Eighth
Supplemental Indenture, dated as of May 1, 2008, by and between
NorthWestern Corporation and The Bank of New York, as trustee under the
General Mortgage Indenture and Deed of Trust dated as of August 1, 1993
(incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s
Current Report on Form 10-Q for the quarter ended June 30, 2008,
Commission File No. 1-10499).
|
|||
4.2(a)
|
Indenture,
dated as of November 1, 2004, between NorthWestern Corporation and
U.S. Bank National Association, as trustee agent (incorporated by
reference to Exhibit 4.1 of NorthWestern Corporation's Current Report
on Form 8-K, dated November 1, 2004, Commission File
No. 1-10499).
|
|||
4.2(b)
|
Supplemental
Indenture No. 1, dated as of November 1, 2004, by and between
NorthWestern Corporation and U.S. Bank National Association, as trustee
(incorporated by reference to Exhibit 4.2 of NorthWestern
Corporation's Current Report on Form 8-K, dated November 1,
2004, Commission File No. 1-10499).
|
|||
4.2(c)
|
Purchase
Agreement, dated March 23, 2009, among NorthWestern Corporation and Banc
of America Securities LLC and J.P. Morgan Securities Inc., as
representatives of several initial purchasers (incorporated by reference
to Exhibit 10.1 of NorthWestern Corporation’s Current Report on Form 8-K,
dated March 23, 2009, Commission File No. 1-10499).
|
|||
4.3
|
Loan
Agreement, dated as of April 1, 2006, between NorthWestern Corporation and
the City of Forsyth, Montana, related to the issuance of City of Forsyth
Pollution Control Revenue Bonds Series 2006 (incorporated by reference to
Exhibit 4.3(e) of the Company's Report on Form 10-K for the
year ended December 31, 2006, Commission File
No. 1-10499).
|
|||
4.4(a)
|
First
Mortgage and Deed of Trust, dated as of October 1, 1945, by The
Montana Power Company in favor of Guaranty Trust Company of New York and
Arthur E. Burke, as trustees (incorporated by reference to
Exhibit 7(e) of The Montana Power Company's Registration
Statement, Commission File
No. 002-05927).
|
65
4.4(b)
|
Eighteenth
Supplemental Indenture to the Mortgage and Deed of Trust, dated as of
August 5, 1994 (incorporated by reference to
Exhibit 99(b) of The Montana Power Company's Registration
Statement on Form S-3, dated December 5, 1994, Commission File
No. 033-56739).
|
|||
4.4(c)
|
Twenty-First
Supplemental Indenture to the Mortgage and Deed of Trust, dated as of
February 13, 2002 (incorporated by reference to
Exhibit 4(v) of NorthWestern Energy, LLC's Annual Report on
Form 10-K for the year ended December 31, 2001, Commission File
No. 001-31276).
|
|||
4.4(d)
|
Twenty-Second
Supplemental Indenture to the Mortgage and Deed of Trust, dated as of
November 15, 2002 (incorporated by reference to Exhibit 4.1 of
NorthWestern Corporation's Current Report on Form 8-K, dated
February 10, 2003, Commission File
No. 1-10499).
|
|||
4.4(e)
|
Twenty-Third
Supplemental Indenture to the Mortgage and Deed of Trust, dated as of
February 1, 2002 (incorporated by reference to Exhibit 4.2 of
NorthWestern Corporation's Current Report on Form 8-K, dated
February 10, 2003, Commission File
No. 1-10499).
|
|||
4.4(f)
|
Twenty-Fourth
Supplemental Indenture, dated as of November 1, 2004, between
NorthWestern Corporation and The Bank of New York and MaryBeth Lewicki,
(incorporated by reference to Exhibit 4.4 of NorthWestern
Corporation's Current Report on Form 8-K, dated November 1,
2004, Commission File No. 1-10499).
|
|||
4.4(g)
|
Twenty-Fifth
Supplemental Indenture, dated as of April 1, 2006, between
NorthWestern Corporation and The Bank of New York and Ming Ryan, as
trustees (incorporated by reference to Exhibit 4.4(n) of the
Company's Report on Form 10-K for the year ended December 31,
2006, Commission File No.
1-10499).
|
|||
4.4(h)
|
Twenty-Sixth
Supplemental Indenture, dated as of September 1, 2006, between
NorthWestern Corporation and The Bank of New York and Ming Ryan, as
trustees (incorporated by reference to Exhibit 4.4 of NorthWestern
Corporation's Current Report on Form 8-K, dated September 13, 2006,
Commission File No. 1-10499).
|
|||
4.4(i)
|
Twenty-seventh
Supplemental Indenture, dated as of March 1, 2009, among NorthWestern
Corporation and The Bank of New York Mellon (formerly The Bank of New
York) and Ming Ryan, as trustees (incorporated by reference to Exhibit 4.1
of NorthWestern Corporation’s Current Report on Form 8-K, dated
March 23, 2009, Commission File No. 1-10499).
|
|||
4.4(j)
|
Twenty-eighth
Supplemental Indenture, dated as of October 1, 2009, by and between
NorthWestern Corporation and The Bank of New York Mellon, as trustee
(incorporated by reference to Exhibit 4.1 of NorthWestern Corporation’s
Quarterly Report on Form 10-Q for the quarter ended September 30, 2009,
Commission File No. 1-10499).
|
|||
4.5(a)
|
Natural
Gas Funding Trust Indenture, dated as of December 22, 1998, between
MPC Natural Gas Funding Trust, as Issuer, and U.S. Bank National
Association, as Trustee (incorporated by reference to
Exhibit 4.7(a) of the Company's Report on Form 10-K for the
year ended December 31, 2002, Commission File
No. 1-10499).
|
|||
4.5(b)
|
Natural
Gas Funding Trust Agreement, dated as of December 11, 1998, among The
Montana Power Company, Wilmington Trust Company, as trustee, and the
Beneficiary Trustees party thereto (incorporated by reference to
Exhibit 4.7(b) of the Company's Report on Form 10-K for the
year ended December 31, 2002, Commission File
No. 1-10499).
|
|||
4.5(c)
|
Transition
Property Purchase and Sale Agreement, dated as of December 22, 1998,
between MPC Natural Gas Funding Trust and The Montana Power Company
(incorporated by reference to Exhibit 4.7(c) of the Company's
Report on Form 10-K for the year ended December 31, 2002,
Commission File No. 1-10499).
|
|||
4.5(d)
|
Transition
Property Servicing Agreement, dated as of December 22, 1998, between
MPC Natural Gas Funding Trust and The Montana Power Company (incorporated
by reference to Exhibit 4.7(d) of the Company's Report on
Form 10-K for the year ended December 31, 2002, Commission File
No.1-10499).
|
|||
4.5(e)
|
Assumption
Agreement regarding the Transition Property Purchase Agreement and the
Transition Property Servicing Agreement, dated as of February 13,
2002, by The Montana Power, LLC to MPC Natural Gas Funding Trust
(incorporated by reference to Exhibit 4.7(e) of the Company's
Report on Form 10-K for the year ended December 31, 2002,
Commission File No. 1-10499).
|
|||
4.5(f)
|
Assignment
and Assumption Agreement (Natural Gas Transition Documents), dated as of
November 15, 2002, by and between NorthWestern Energy, LLC, as
assignor, and NorthWestern Corporation, as assignee (incorporated by
reference to Exhibit 4.7(f) of the Company's Report on
Form 10-K for the year ended December 31, 2002, Commission File
No. 1-10499).
|
66
10.1(a) †
|
NorthWestern
Corporation 2005 Deferred Compensation Plan for Non-Employee Directors
(incorporated by reference to Exhibit 10.1(c) to NorthWestern
Corporation's Annual Report on Form 10-K for the year ended
December 31, 2004, Commission File
No. 1-10499).
|
|||
10.1(b) †
|
NorthWestern
Corporation 2005 Long-Term Incentive Plan (incorporated by reference to
Exhibit 2.1 of NorthWestern Corporation's registration statement on
Form S-8, dated May 4, 2005, Commission File
No. 333-124624).
|
|||
10.1(c) †
|
Employment
agreement with Robert C. Rowe, dated August 11, 2008 (incorporated by
reference to Exhibit 10.1 to NorthWestern Corporation's Current Report on
Form 8-K, dated August 19, 2008, Commission File
No. 1-10499).
|
|||
10.1(d) †
|
NorthWestern
Corporation 2008 Key Employee Severance Plan (incorporated by reference to
Exhibit 10.1 of NorthWestern Corporation's Current Report on
Form 8-K, dated October 2, 2008, Commission File
No. 1-10499).
|
|||
10.1(e) †
|
NorthWestern
Corporation 2005 Long-Term Incentive Plan, as amended October 31,
2007 (incorporated by reference to Exhibit 10.1 of NorthWestern
Corporation's Quarterly Report on Form 10-Q, dated October 30, 2008,
Commission File No. 1-10499).
|
|||
10.1(f) †
|
NorthWestern
Energy 2009 Annual Incentive Plan (incorporated by reference to Exhibit
99.1 of NorthWestern Corporation’s Current Report on Form 8-K, dated
February 13, 2009, Commission File No. 1-10499).
|
|||
10.1(g) †
|
Form
of NorthWestern Corporation Long Term Performance Incentive Restricted
Stock Award Agreement (incorporated by reference to Exhibit 99.2 of
NorthWestern Corporation’s Current Report on Form 8-K, dated February 13,
2009, Commission File No. 1-10499).
|
|||
10.1(h) †
|
NorthWestern
Corporation 2009 Officers Deferred Compensation Plan (incorporated by
reference to Exhibit 99.2 of NorthWestern Corporation’s Current Report on
Form 8-K, dated April 22, 2009, Commission File No.
1-10499).
|
|||
10.1(i) †
|
Waiver
and Release of Miggie E. Cramblit executed January 5, 2010 (incorporated
by reference to Exhibit 10.1 of NorthWestern Corporation's Current Report
on Form 8-K, dated January 5, 2010, Commission File
No.1-10499).
|
|||
10.1(j) †
|
Consulting
agreement with Miggie E. Cramblit, executed January 6, 2010 (incorporated
by reference to Exhibit 10.2 of NorthWestern Corporation's Current Report
on Form 8-K, dated January 5, 2010, Commission File
No.1-10499).
|
|||
10.2(a)
|
Purchase
Agreement, dated September 6, 2006, among NorthWestern Corporation and
Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as
representatives of several initial purchasers (incorporated by reference
to Exhibit 10.1 of NorthWestern Corporation's Current Report on Form 8-K,
dated September 13, 2006, Commission File No. 1-10499).
|
|||
10.2(b)
|
Purchase
Agreement, dated January 18, 2007, between NorthWestern Corporation and
Mellon Leasing Corporation (incorporated by reference to Exhibit 10.1 of
NorthWestern Corporation's Current Report on Form 8-K, dated March 13,
2007, Commission File No.1-10499).
|
|||
10.2(c)
|
Purchase
Agreement, dated October 30, 2007, between NorthWestern Corporation and
SGE (New York) Associates (incorporated by reference to Exhibit 10.1 of
NorthWestern Corporation's Current Report on Form 8-K, dated October 30,
2007, Commission File No.1-10499).
|
|||
10.2(d)
|
Bond
Purchase Agreement, dated May 1, 2008, between NorthWestern Corporation
and initial purchasers (incorporated by reference to Exhibit 99.1 of
NorthWestern Corporation's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2008, Commission File
No. 1-10499).
|
|||
10.2(e)
|
Purchase
Agreement, dated March 23, 2009, among NorthWestern Corporation and Banc
of America Securities LLC and J.P. Morgan Securities Inc., as
representatives of several initial purchasers (incorporated by reference
to Exhibit 10.1 of NorthWestern Corporation’s Current Report on Form 8-K,
dated March 23, 2009, Commission File No. 1-10499).
|
|||
10.2(f)
|
Amended
and Restated Credit Agreement, dated as of June 30, 2009, among
NorthWestern Corporation, as borrower, the several banks and other
financial institutions or entities from time to time parties to the
Agreement, as lenders, Banc of America Securities LLC, as lead arranger;
JP Morgan Chase Bank, N.A., as syndication agent; Union Bank, N.A. and
U.S. Bank National Association, as co-documentation agents; and Bank of
America, N.A., as administrative agent (incorporated by reference to
Exhibit 10.1 of NorthWestern Corporation’s Current Report on Form 8-K,
dated June 30, 2009, Commission File No. 1-10499)
|
|||
10.2(g)
|
Purchase
Agreement, dated July 2, 2009, between NorthWestern Corporation and Pratt
& Whitney Power Systems, Inc. (incorporated by reference to
Exhibit 10.1 of NorthWestern Corporation's Quarterly Report on
Form 10-Q for the quarter ended June 30, 2009, Commission File
No. 1-10499).
|
67
10.2(h)
|
Engineering,
Procurement and Construction Agreement, dated July 27, 2009, between
NorthWestern Corporation and NewMech Companies, Inc. (incorporated by
reference to Exhibit 10.1 of NorthWestern Corporation's Quarterly
Report on Form 10-Q for the quarter ended September 30, 2009,
Commission File No. 1-10499).
|
|||
10.2(i)*
|
Purchase
Agreement, dated September 30, 2009, among NorthWestern Corporation and
the initial purchasers named therein.
|
|||
12.1*
|
Statement
Regarding Computation of Earnings to Fixed Charges.
|
|||
21*
|
Subsidiaries
of NorthWestern Corporation.
|
|||
23.1*
|
Consent
of Independent Registered Public Accounting Firm
|
|||
24*
|
Power
of Attorney (included on the signature page of this Annual Report on
Form 10-K)
|
|||
31.1*
|
Certification
of Chief Executive Officer pursuant to Section 302 of the Sarbanes
Oxley Act of 2002
|
|||
31.2*
|
Certification
of Chief Financial Officer pursuant to Section 302 of the Sarbanes
Oxley Act of 2002
|
|||
32.1*
|
Certification
of Robert C. Rowe pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
|
|||
32.2*
|
Certification
of Brian B. Bird pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
|
† Management contract
or compensatory plan or arrangement.
* Filed
herewith.
All
schedules for which provision is made in the applicable accounting regulations
of the SEC are not required under the related instructions or are not
applicable, and, therefore, have been omitted.
68
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the Registrant has duly caused this Annual Report on Form 10-K to be
signed on its behalf by the undersigned, thereunto duly authorized.
NORTHWESTERN
CORPORATION
|
|||
Dated:
February 12, 2010
|
By:
|
/s/
ROBERT C. ROWE
|
|
Robert
C. Rowe
|
|||
President
and Chief Executive Officer
|
69
CONFIDENTIAL
BLACKLINE DRAFT VERSION 4.1
POWER
OF ATTORNEY
We, the
undersigned directors and/or officers of NorthWestern Corporation, hereby
severally constitute and appoint Robert C. Rowe and Kendall G. Kliewer, and each
of them with full power to act alone, our true and lawful attorneys-in-fact and
agents, with full power of substitution and resubstitution and revocation, for
each of us and in our name, place, and stead, in any and all capacities, to sign
any and all amendments to this Annual Report on Form 10-K, and to file or cause
to be filed the same, with all exhibits thereto, and other documents in
connection therewith, with the Securities and Exchange Commission, and hereby
grant unto such attorneys-in-fact and agents, and each of them, the full power
and authority to do each and every act and thing requisite and necessary to be
done in and about the foregoing, as fully to all intents and purposes as each of
us might or could do in person, hereby ratifying and confirming all that said
attorneys-in-fact and agents, or any of them, or their respective substitute or
substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant
to the requirements of the Securities Exchange Act of 1934, this Annual Report
on Form 10-K has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature
|
Title
|
Date
|
||
/s/
E. LINN DRAPER, JR.
|
Chairman
of the Board
|
February
12, 2010
|
||
E.
Linn Draper, Jr.
|
||||
/s/
ROBERT C. ROWE
|
President,
Chief Executive Officer and Director
|
February
12, 2010
|
||
Robert
C. Rowe
|
(Principal
Executive Officer)
|
|||
/s/
BRIAN B. BIRD
|
Vice
President, Chief Financial Officer and Treasurer
|
February
12, 2010
|
||
Brian
B. Bird
|
(Principal
Financial Officer)
|
|||
/s/
KENDALL G. KLIEWER
|
Vice
President and Controller
|
February
12, 2010
|
||
Kendall
G. Kliewer
|
(Principal
Accounting Officer)
|
|||
/s/
STEPHEN P. ADIK
|
Director
|
February
12, 2010
|
||
Stephen
P. Adik
|
||||
/s/
DOROTHY M. BRADLEY
|
Director
|
February
12, 2010
|
||
Dorothy
M. Bradley
|
||||
/s/ DANA J.
DYKHOUSE
|
Director
|
February
12, 2010
|
||
Dana
J. Dykhouse
|
||||
Director
|
||||
Julia
L. Johnson
|
||||
/s/
PHILIP L. MASLOWE
|
Director
|
February
12, 2010
|
||
Philip
L. Maslowe
|
||||
/s/
DENTON LOUIS PEOPLES
|
Director
|
February
12, 2010
|
||
Denton
Louis Peoples
|
||||
70
Page
|
|
Financial
Statements
|
|
Reports
of Independent Registered Public Accounting Firm
|
|
Consolidated
statements of income for the years ended December 31, 2009, 2008 and
2007
|
|
Consolidated
statements of cash flows for the years ended December 31, 2009, 2008
and 2007
|
|
Consolidated
balance sheets as of December 31, 2009 and December 31,
2008
|
|
Consolidated
statements of common shareholders' equity and comprehensive income for the
years ended December 31, 2009, 2008 and 2007
|
|
Notes
to consolidated financial statements
|
|
Financial
Statement Schedule
|
|
Schedule II.
Valuation and Qualifying Accounts
|
F-1
To the
Shareholders and Board of Directors of NorthWestern Corporation:
We have
audited the accompanying consolidated balance sheets of NorthWestern Corporation
(a Delaware corporation) and subsidiaries (the “Company”) as of December 31,
2009 and 2008, and the related consolidated statements of income, common
shareholders’ equity and comprehensive income, and cash flows for each of the
three years in the period ended December 31, 2009. Our audits also included the
financial statement schedule listed in the index at Item 15. These consolidated
financial statements and financial statement schedule are the responsibility of
the Company’s management. Our responsibility is to express an opinion on the
consolidated financial statements and financial statement schedule based on our
audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our
opinion, such consolidated financial statements present fairly, in all material
respects, the financial position of the Company as of December 31, 2009 and
2008, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2009, in conformity with accounting
principles generally accepted in the United States of America. Also, in our
opinion, such financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly, in
all material respects, the information set forth therein.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Company’s internal control over financial
reporting as of December 31, 2009, based on the criteria established in Internal
Control — Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated February 12, 2010,
expressed an unqualified opinion on the Company’s internal control over
financial reporting.
/s/DELOITTE
& TOUCHE LLP
|
|
Minneapolis,
Minnesota
|
|
February
12, 2010
|
F-2
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Shareholders and Board of Directors of NorthWestern Corporation:
We have
audited the internal control over financial reporting of NorthWestern
Corporation and subsidiaries (the “Company”) as of December 31, 2009, based on
criteria established in Internal
Control — Integrated Framework, issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Company’s management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying “Management’s Report on Internal Control
over Financial Reporting.” Our responsibility is to express an opinion on the
Company’s internal control over financial reporting based on our
audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing
and evaluating the design and operating effectiveness of internal control based
on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A
company’s internal control over financial reporting is a process designed by, or
under the supervision of, the company’s principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company’s board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control
over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial
statements.
Because
of the inherent limitations of internal control over financial reporting,
including the possibility of collusion or improper management override of
controls, material misstatements due to error or fraud may not be prevented or
detected on a timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our
opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2009, based on the criteria
established in Internal
Control — Integrated Framework, issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial statements and
financial statement schedule as of and for the year ended December 31, 2009, of
the Company, and our report dated February 12, 2010, expressed an unqualified
opinion on those consolidated financial statements and financial statement
schedule.
/s/
DELOITTE & TOUCHE LLP
|
|
Minneapolis,
Minnesota
|
|
February
12, 2010
|
F-3
CONSOLIDATED
STATEMENTS OF INCOME
(in
thousands, except per share amounts)
Year
Ended December 31,
|
|||||||||||||
2009
|
2008
|
2007
|
|||||||||||
Revenues
|
|||||||||||||
Electric
|
$
|
781,186
|
$
|
773,029
|
$
|
735,513
|
|||||||
Gas
|
353,977
|
416,070
|
362,800
|
||||||||||
Other
|
6,747
|
71,694
|
101,747
|
||||||||||
Total
Revenues
|
1,141,910
|
1,260,793
|
1,200,060
|
||||||||||
Operating
Expenses
|
|||||||||||||
Cost
of sales
|
573,686
|
698,740
|
668,405
|
||||||||||
Operating,
general and administrative
|
245,618
|
226,164
|
221,566
|
||||||||||
Property
and other taxes
|
79,582
|
80,602
|
87,581
|
||||||||||
Depreciation
|
89,039
|
85,071
|
82,415
|
||||||||||
Total
Operating Expenses
|
987,925
|
1,090,577
|
1,059,967
|
||||||||||
Operating
Income
|
153,985
|
170,216
|
140,093
|
||||||||||
Interest
Expense
|
(67,760
|
)
|
(63,952
|
)
|
(56,942
|
)
|
|||||||
Other
Income
|
2,499
|
1,558
|
2,428
|
||||||||||
Income
Before Income Taxes
|
88,724
|
107,822
|
85,579
|
||||||||||
Income
Tax Expense
|
(15,304
|
)
|
(40,221
|
)
|
(32,388
|
)
|
|||||||
Net
Income
|
$
|
73,420
|
$
|
67,601
|
$
|
53,191
|
|||||||
Average
Common Shares Outstanding
|
36,091
|
37,976
|
36,623
|
||||||||||
Basic
Earnings per Average Common Share
|
$
|
2.03
|
$
|
1.78
|
$
|
1.45
|
|||||||
Diluted
Earnings per Average Common Share
|
$
|
2.02
|
$
|
1.77
|
$
|
1.44
|
|||||||
Dividends
Declared per Average Common Share
|
$
|
1.34
|
$
|
1.32
|
$
|
1.28
|
See Notes
to Consolidated Financial Statements
F-4
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(in
thousands)
Year
Ended December 31,
|
|||||||||||
2009
|
2008
|
2007
|
|||||||||
OPERATING
ACTIVITIES:
|
|||||||||||
Net
Income
|
$
|
73,420
|
$
|
67,601
|
$
|
53,191
|
|||||
Items
not affecting cash:
|
|||||||||||
Depreciation
|
89,039
|
85,071
|
82,415
|
||||||||
Amortization
of debt issue costs, discount and deferred hedge gain
|
2,168
|
2,444
|
1,617
|
||||||||
Amortization
of restricted stock
|
1,627
|
3,088
|
7,116
|
||||||||
Equity
portion of allowance for funds used during construction
|
(2,113
|
)
|
(641
|
)
|
(508
|
)
|
|||||
Gain
on rate case settlement
|
—
|
—
|
(12,636
|
)
|
|||||||
(Gain)
loss on sale of assets
|
(287
|
)
|
(214
|
)
|
85
|
||||||
Deferred
income taxes
|
47,014
|
42,587
|
34,994
|
||||||||
Changes
in current assets and liabilities:
|
|||||||||||
Restricted
cash
|
1,119
|
(245
|
)
|
1,354
|
|||||||
Accounts
receivable
|
11,913
|
(12,150
|
)
|
6,311
|
|||||||
Inventories
|
23,436
|
(7,155
|
)
|
(3,096
|
)
|
||||||
Prepaid
energy supply costs
|
199
|
432
|
(772
|
)
|
|||||||
Other
current assets
|
(866
|
)
|
(1,768
|
)
|
1,693
|
||||||
Accounts
payable
|
(9,224
|
)
|
3,218
|
12,123
|
|||||||
Accrued
expenses
|
(48,396
|
)
|
(9,883
|
)
|
(13,918
|
)
|
|||||
Regulatory
assets
|
1,109
|
9,248
|
1,221
|
||||||||
Regulatory
liabilities
|
(19,601
|
)
|
10,522
|
21,929
|
|||||||
Other
noncurrent assets
|
(3,928
|
)
|
28,348
|
23,662
|
|||||||
Other
noncurrent liabilities
|
(49,825
|
)
|
(22,177
|
)
|
(14,817
|
)
|
|||||
Cash
provided by operating activities
|
116,804
|
198,326
|
201,964
|
||||||||
INVESTING
ACTIVITIES:
|
|||||||||||
Property,
plant, and equipment additions
|
(189,360
|
)
|
(124,563
|
)
|
(117,084
|
)
|
|||||
Colstrip
Unit 4 acquisition
|
—
|
—
|
(141,257
|
)
|
|||||||
Proceeds
from sale of assets
|
326
|
200
|
1,842
|
||||||||
Cash
used in investing activities
|
(189,034
|
)
|
(124,363
|
)
|
(256,499
|
)
|
|||||
FINANCING
ACTIVITIES:
|
|||||||||||
Proceeds
from exercise of warrants
|
—
|
—
|
68,834
|
||||||||
Dividends
on common stock
|
(48,186
|
)
|
(49,833
|
)
|
(47,286
|
)
|
|||||
Issuance
of long term debt
|
304,833
|
55,000
|
100,000
|
||||||||
Repayment
of long-term debt
|
(137,800
|
)
|
(96,355
|
)
|
(15,540
|
)
|
|||||
Line
of credit borrowings
|
348,000
|
254,000
|
623,001
|
||||||||
Line
of credit repayments
|
(390,000
|
)
|
(158,000
|
)
|
(661,001
|
)
|
|||||
Treasury
stock activity
|
(741
|
)
|
(78,706
|
)
|
(896
|
)
|
|||||
Financing
costs
|
(10,824
|
)
|
(1,550
|
)
|
(1,734
|
)
|
|||||
Cash
provided by (used in) provided by financing activities
|
65,282
|
(75,444
|
)
|
65,378
|
|||||||
(Decrease)
Increase in Cash and Cash Equivalents
|
(6,948
|
)
|
(1,481
|
)
|
10,843
|
||||||
Cash
and Cash Equivalents, beginning of period
|
11,292
|
12,773
|
1,930
|
||||||||
Cash and Cash Equivalents, end
of period
|
$
|
4,344
|
$
|
11,292
|
$
|
12,773
|
See Notes
to Consolidated Financial Statements
F-5
CONSOLIDATED
BALANCE SHEETS
(in
thousands, except per share amounts)
Year
Ended December 31,
|
|||||||
2009
|
2008
|
||||||
ASSETS
|
|||||||
Current
Assets:
|
|||||||
Cash
and cash equivalents
|
$
|
4,344
|
$
|
11,292
|
|||
Restricted
cash
|
13,608
|
14,727
|
|||||
Accounts
receivable, net
|
143,759
|
155,672
|
|||||
Inventories
|
47,305
|
70,741
|
|||||
Regulatory
assets
|
40,509
|
46,905
|
|||||
Prepaid
energy supply
|
2,535
|
2,734
|
|||||
Deferred
income taxes
|
1,239
|
685
|
|||||
Other
|
11,528
|
10,661
|
|||||
Total current
assets
|
264,827
|
313,417
|
|||||
Property,
plant, and equipment, net
|
1,964,121
|
1,839,699
|
|||||
Goodwill
|
355,128
|
355,128
|
|||||
Regulatory
assets
|
182,382
|
233,102
|
|||||
Other
noncurrent assets
|
28,674
|
20,691
|
|||||
Total
assets
|
$
|
2,795,132
|
$
|
2,762,037
|
|||
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|||||||
Current
Liabilities:
|
|||||||
Current
maturities of capital leases
|
$
|
1,197
|
$
|
1,193
|
|||
Current
maturities of long-term debt
|
6,123
|
228,045
|
|||||
Accounts
payable
|
92,923
|
94,685
|
|||||
Accrued
expenses
|
165,127
|
215,431
|
|||||
Regulatory
liabilities
|
29,622
|
49,223
|
|||||
Total current
liabilities
|
294,992
|
588,577
|
|||||
Long-term
capital leases
|
35,570
|
36,798
|
|||||
Long-term
debt
|
981,296
|
634,011
|
|||||
Deferred
income taxes
|
161,188
|
114,707
|
|||||
Noncurrent
regulatory liabilities
|
238,332
|
222,969
|
|||||
Other
noncurrent liabilities
|
296,730
|
401,442
|
|||||
Total
liabilities
|
2,008,108
|
1,998,504
|
|||||
Commitments
and Contingencies (Note 17)
|
|||||||
Shareholders'
Equity:
|
|||||||
Common
stock, par value $0.01; authorized 200,000,000 shares; issued
and
outstanding 39,566,846 and 36,003,434, respectively; Preferred
stock,
par
value $0.01; authorized 50,000,000 shares; none issued
|
395
|
395
|
|||||
Treasury
stock at cost
|
(90,228
|
)
|
(89,487
|
)
|
|||
Paid-in
capital
|
807,527
|
805,900
|
|||||
Retained
earnings
|
59,605
|
34,371
|
|||||
Accumulated
other comprehensive income
|
9,725
|
12,354
|
|||||
Total
shareholders' equity
|
787,024
|
763,533
|
|||||
Total
liabilities and shareholders' equity
|
$
|
2,795,132
|
$
|
2,762,037
|
See Notes
to Consolidated Financial Statements
F-6
CONSOLIDATED
STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
AND
COMPREHENSIVE INCOME
(in
thousands)
Number
of Common
Shares
|
Number of
Treasury
Shares
|
Common
Stock
|
Paid in
Capital
|
Treasury
Stock
|
Retained
Earnings
|
Accumulated
Other
Comprehensive
Income
|
Total
Shareholders' Equity
|
|||||||||||||||||||
Balance at
December 31, 2006
|
35,968
|
330
|
$
|
360
|
$
|
727,327
|
$
|
(9,885
|
)
|
$
|
10,698
|
$
|
14,271
|
$
|
742,771
|
|||||||||||
Net income
|
$
|
—
|
$
|
—
|
$
|
—
|
$
|
53,191
|
$
|
—
|
$
|
53,191
|
||||||||||||||
Other
comprehensive income:
|
||||||||||||||||||||||||||
Foreign
currency translation adjustment
|
318
|
318
|
||||||||||||||||||||||||
Reclassification
of net gains on derivative instruments from OCI to net
income,
|
—
|
—
|
—
|
—
|
—
|
—
|
(1,188
|
)
|
(1,188
|
)
|
||||||||||||||||
Pension
and postretirement medical liability adjustment, net of taxes of
$133
|
—
|
—
|
—
|
—
|
—
|
—
|
347
|
347
|
||||||||||||||||||
Total
comprehensive income
|
52,668
|
|||||||||||||||||||||||||
Treasury stock
activity
|
—
|
33
|
—
|
—
|
(896
|
)
|
—
|
—
|
(896
|
)
|
||||||||||||||||
Amortization of
unearned restricted stock compensation
|
104
|
—
|
1
|
6,932
|
—
|
—
|
—
|
6,933
|
||||||||||||||||||
Warrants
exercise
|
3,262
|
—
|
32
|
68,802
|
—
|
—
|
—
|
68,834
|
||||||||||||||||||
Dividends on common
stock
|
—
|
—
|
—
|
—
|
—
|
(47,286
|
)
|
—
|
(47,286
|
)
|
||||||||||||||||
Balance at
December 31, 2007
|
39,334
|
363
|
$
|
393
|
$
|
803,061
|
$
|
(10,781
|
)
|
$
|
16,603
|
$
|
13,748
|
$
|
823,024
|
|||||||||||
Net income
|
—
|
—
|
—
|
—
|
—
|
67,601
|
—
|
67,601
|
||||||||||||||||||
Other
comprehensive income:
|
||||||||||||||||||||||||||
Foreign
currency translation adjustment
|
—
|
—
|
—
|
—
|
—
|
—
|
(410
|
)
|
(410
|
)
|
||||||||||||||||
Reclassification
of net gains on derivative instruments from OCI to net
income
|
—
|
—
|
—
|
—
|
—
|
—
|
(1,188
|
)
|
(1,188
|
)
|
||||||||||||||||
Pension
and postretirement medical liability adjustment, net of taxes of
$128
|
—
|
—
|
—
|
—
|
—
|
—
|
204
|
204
|
||||||||||||||||||
Total
comprehensive income
|
66,207
|
|||||||||||||||||||||||||
Treasury stock
activity
|
—
|
3,170
|
—
|
—
|
(78,706
|
)
|
—
|
—
|
(78,706
|
)
|
||||||||||||||||
Issuance of
restricted stock
|
2
|
—
|
—
|
58
|
—
|
—
|
—
|
58
|
||||||||||||||||||
Amortization of
unearned restricted stock compensation
|
125
|
—
|
2
|
2,781
|
—
|
—
|
—
|
2,783
|
||||||||||||||||||
Dividends on common
stock
|
—
|
—
|
—
|
—
|
—
|
(49,833
|
)
|
—
|
(49,833
|
)
|
||||||||||||||||
Balance at
December 31, 2008
|
39,461
|
3,533
|
$
|
395
|
$
|
805,900
|
$
|
(89,487
|
)
|
$
|
34,371
|
$
|
12,354
|
$
|
763,533
|
|||||||||||
Net income
|
—
|
—
|
—
|
—
|
—
|
73,420
|
—
|
73,420
|
||||||||||||||||||
Other
comprehensive income:
|
||||||||||||||||||||||||||
Foreign
currency translation adjustment
|
—
|
—
|
—
|
—
|
—
|
—
|
296
|
296
|
||||||||||||||||||
Reclassification
of net gains on derivative instruments from OCI to net
income
|
—
|
—
|
—
|
—
|
—
|
—
|
(1,188
|
)
|
(1,188
|
)
|
||||||||||||||||
Pension
and postretirement medical liability adjustment, net of taxes
of $1,088
|
—
|
—
|
—
|
—
|
—
|
—
|
(1,737
|
)
|
(1,737
|
)
|
||||||||||||||||
Total
comprehensive income
|
70,791
|
|||||||||||||||||||||||||
Treasury stock
activity
|
—
|
30
|
—
|
—
|
(741
|
)
|
—
|
—
|
(741
|
)
|
||||||||||||||||
Issuance of
restricted stock
|
8
|
—
|
—
|
184
|
—
|
—
|
—
|
184
|
||||||||||||||||||
Amortization of
unearned restricted stock compensation
|
98
|
—
|
—
|
1,443
|
—
|
—
|
—
|
1,443
|
||||||||||||||||||
Dividends on common
stock
|
—
|
—
|
—
|
—
|
—
|
(48,186
|
)
|
—
|
(48,186
|
)
|
||||||||||||||||
Balance at
December 31, 2009
|
39,567
|
3,563
|
$
|
395
|
$
|
807,527
|
$
|
(90,228
|
)
|
$
|
59,605
|
$
|
9,725
|
$
|
787,024
|
See Notes
to Consolidated Financial Statements
F-7
(1) Nature
of Operations and Basis of Consolidation
NorthWestern
Corporation, doing business as NorthWestern Energy, provides electricity and
natural gas to approximately 661,000 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
generated and 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.
Events occurring subsequent to December 31, 2009, have been evaluated as to
their potential impact to the Consolidated Financial Statements through February
12, 2010, the date of issuance.
(2) Significant
Accounting Policies
Use
of Estimates
The
preparation of financial statements in conformity with GAAP 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.
Revenue
Recognition
For our
South Dakota and Nebraska operations, as prescribed by the applicable 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 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 $2.8 million and
$3.0 million at December 31, 2009 and December 31, 2008, respectively.
Receivables include unbilled revenues of $72.3 million and $79.1 million at
December 31, 2009 and December 31, 2008, respectively.
F-8
Inventories
Inventories
are stated at average cost. Inventory consisted of the following (in
thousands):
December
31,
|
||||||
2009
|
2008
|
|||||
Materials
and
supplies
|
$
|
19,854
|
$
|
18,907
|
||
Storage
gas
|
27,451
|
51,834
|
||||
$
|
47,305
|
$
|
70,741
|
Regulation
of Utility Operations
Our
regulated operations are subject to the provisions of Accounting Standards
Codification (ASC) 980, Regulated Operations (ASC 980). Regulated accounting 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
Consolidated 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 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 we
were required to terminate the application of these provisions to our regulated
operations, all such deferred amounts would be recognized in the Consolidated
Income Statements at that time. This would result in a charge to earnings, net
of applicable income taxes, which could be material. In addition, we would
determine any impairment to the carrying costs of deregulated plant and
inventory assets.
Derivative
Financial Instruments
We
account for derivative instruments in accordance with ASC 815, Derivatives and
Hedging. All derivatives are recognized in the Consolidated Balance Sheets at
their fair value unless they qualify for certain exceptions, including the
normal purchases and normal sales exception. Additionally, derivatives that
qualify and are designated for hedge accounting are classified as either hedges
of the fair value of a recognized asset or liability or of an unrecognized firm
commitment (fair-value hedge) or hedges of a forecasted transaction or the
variability of cash flows to be received or paid related to a recognized asset
or liability (cash-flow hedge). For fair-value hedges, changes in fair values
for both the derivative and the underlying hedged exposure are recognized in
earnings each period. For cash-flow hedges, the portion of the derivative gain
or loss that is effective in offsetting the change in the cost or value of the
underlying exposure is deferred in accumulated OCI and later reclassified into
earnings when the underlying transaction occurs. Gains and losses from the
ineffective portion of any hedge are recognized in earnings immediately. For
other derivative contracts that do not qualify or are not designated for hedge
accounting, changes in the fair value of the derivatives are recognized in
earnings each period. Cash inflows and outflows related to derivative
instruments are included as a component of operating, investing or financing
cash flows in the Consolidated Statement of Cash Flows, depending on the
underlying nature of the hedged items.
Revenues
and expenses on contracts that qualify are designated as normal purchases and
normal sales and are recognized when the underlying physical transaction is
completed. While these contracts are considered derivative financial
instruments, they are not required to be recorded at fair value, but on an
accrual basis of accounting. Normal purchases and normal sales are contracts
where physical delivery is probable, quantities are expected to be used or sold
in the normal course of business over a reasonable period of time, and price is
not tied to an unrelated underlying derivative. As part of our regulated
electric and gas operations, we enter into contracts to buy and sell energy to
meet the requirements of our customers. These contracts include short-term and
long-term commitments to purchase and sell energy in the retail and wholesale
markets with the intent and ability to deliver or take delivery. If it were
determined that a transaction designated as a normal purchase or a normal sale
no longer met the exceptions, the fair value of the related contract would be
reflected as an asset or liability and immediately recognized through earnings.
See Note 6, Risk Management and Hedging Activities for further discussion of our
derivative activity.
F-9
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 8.4%,
8.9%, and 8.7%, for Montana for 2009, 2008, and 2007 respectively, and 8.5%,
8.8%, and 8.7% for South Dakota for 2009, 2008, and 2007 respectively. Interest
capitalized totaled $3.2 million for the year ended December 31, 2009, $0.9
million for the year ended December 31, 2008 and $0.8 million for the year ended
December 31, 2007 for Montana and South Dakota combined.
We
capitalize preliminary survey and investigation costs related to the
determination of the feasibility of transmission or generation utility projects
in other noncurrent assets. Upon commencement of construction, these costs are
transferred to construction work in process, and upon completion, these costs
will be transferred to utility plant in service. These costs totaled
approximately $11.4 million and $6.7 million as of December 31, 2009 and 2008,
respectively. Capitalized costs are charged to operating expense if the
development of the project is no longer feasible.
We may
require contributions in aid of construction from customers when we extend
service. Amounts used from these contributions to fund capital additions were
$2.6 million and $6.9 million for the years ended December 31, 2009 and
2008, respectively.
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 3.2%, 3.3%, and 3.5% for 2009, 2008, and 2007,
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.
F-10
Other
Noncurrent Liabilities
Other
noncurrent liabilities consisted of the following (in thousands):
December
31,
|
||||||
2009
|
2008
|
|||||
Pension
and other employee
benefits
|
$
|
32,695
|
$
|
139,306
|
||
Future
QF obligation,
net
|
165,839
|
162,841
|
||||
Environmental
|
31,900
|
32,051
|
||||
Customer
advances
|
47,074
|
49,998
|
||||
Other
|
19,222
|
17,246
|
||||
$
|
296,730
|
$
|
401,442
|
Insurance
Subsidiary
Risk
Partners Assurance, Ltd (Risk Partners) 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 $5.8 million and $5.4 million as of December 31, 2009 and
2008, respectively.
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 Income
Statements and provision for income taxes.
Environmental
Costs
We record
environmental costs when it is probable we are liable for the costs and we can
reasonably estimate the liability. We may defer costs as a regulatory asset if
we have prior regulatory authorization for recovery of these costs from
customers in future rates. Otherwise, we expense the costs. If an environmental
expense is related to facilities we currently use, such as pollution control
equipment, then we capitalize and depreciate the costs over the remaining life
of the asset, assuming the costs are recoverable in future rates or future cash
flows.
Our
remediation cost 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
Consolidated 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.
F-11
Accounting
Standards Issued
In June 2009, the
Financial Accounting Standards Board (FASB) amended the accounting for variable
interest entities, which is effective for us beginning January 1, 2010. This
revised guidance changes how a company determines when an entity that is
insufficiently capitalized or is not controlled through voting (or similar)
rights should be consolidated. The determination of whether a company is
required to consolidate an entity is based on, among other things, an entity’s
purpose and design and a company’s ability to direct the activities of the
entity that most significantly impact the entity’s economic performance. The
statement includes the following significant provisions:
·
|
requires
an entity to qualitatively assess the determination of the primary
beneficiary of a variable interest entity (VIE) based on whether the
entity (1) has the power to direct matters that most significantly impact
the activities of the VIE, and (2) has the obligation to absorb losses or
the right to receive benefits of the VIE that could potentially be
significant to the VIE,
|
·
|
requires
an ongoing reconsideration of the primary beneficiary instead of only upon
certain triggering events,
|
·
|
amends
the events that trigger a reassessment of whether an entity is a VIE,
and
|
·
|
for
an entity that is the primary beneficiary of a VIE, requires separate
balance sheet presentation of (1) the assets of the consolidated VIE, if
they can be used to only settle specific obligations of the consolidated
VIE, and (2) the liabilities of a consolidated VIE for which creditors do
not have recourse to the general credit of the primary
beneficiary.
|
We are
required to consolidate VIEs if we are the primary beneficiary, which means we
have a controlling financial interest. Certain long-term purchase power and
tolling contracts may be considered variable interests. We have various
long-term purchase power contracts with other utilities and certain qualifying
facility (QF) plants. We are evaluating our inventory of long-term purchase
power and tolling contracts under this guidance. Under the previous guidance, we
identified one QF contract that may constitute a VIE. We have accounted for this
QF contract as an executory contract as we have been unable to obtain the
necessary information from this QF 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 QF, our estimated gross contractual payments aggregate approximately
$468.4 million through 2025. For further discussion of our gross QF liability,
see Note 17. During the years ended December 31, 2009, 2008 and 2007 purchases
from this QF were approximately $20.1 million, $20.5 million, and $21.1
million, respectively. We will finalize our evaluation during the first
quarter of 2010 to determine the impact of adoption, if any, on our financial
position and results of operations.
Supplemental
Cash Flow Information
Year
Ended December 31,
|
|||||||||
2009
|
2008
|
2007
|
|||||||
Cash
paid for
|
|||||||||
Income
taxes
|
$
|
3
|
$
|
111
|
$
|
3,921
|
|||
Interest
|
39,473
|
47,992
|
43,076
|
||||||
Significant
non-cash transactions:
|
|||||||||
Capital
expenditures included in trade accounts payable
|
12,272
|
4,464
|
5,627
|
||||||
Assumption
of debt related to Colstrip Unit 4 acquisitions
|
—
|
—
|
53,685
|
||||||
Additions
to property, plant and equipment and capital lease
obligations
|
—
|
—
|
2,400
|
F-12
(3) Property,
Plant and Equipment
The
following table presents the major classifications of our property, plant and
equipment (in thousands):
Estimated
Useful Life
|
December
31,
|
||||||||
2009
|
2008
|
||||||||
(years)
|
(in
thousands)
|
||||||||
Land
and improvements
|
49
– 105
|
$
|
46,118
|
$
|
44,813
|
||||
Building
and improvements
|
26
– 71
|
99,578
|
95,658
|
||||||
Storage,
distribution, and transmission
|
12
– 79
|
2,056,587
|
1,974,505
|
||||||
Generation
|
30
– 46
|
247,937
|
214,893
|
||||||
Plant
acquisition adjustment
|
34
|
204,754
|
227,633
|
||||||
Other
equipment
|
2 -
31
|
238,645
|
238,379
|
||||||
Construction
work in process
|
–—
|
114,779
|
12,599
|
||||||
3,008,398
|
2,808,480
|
||||||||
Less
accumulated depreciation
|
(1,044,277
|
)
|
(968,781
|
)
|
|||||
$
|
1,964,121
|
$
|
1,839,699
|
Plant and
equipment under capital lease were $34.0 million and $36.2 million as of
December 31, 2009 and December 31, 2008, respectively, which included $33.2
million and $35.2 million as of December 31, 2009 and 2008, 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.
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
(SD)
|
Neal
#4
(IA)
|
Coyote
(ND)
|
Colstrip
Unit 4 (MT)
|
||||||||||
December
31, 2009
|
|||||||||||||
Ownership
percentages
|
23.4
|
%
|
8.7
|
%
|
10.0
|
%
|
30.0
|
%
|
|||||
Plant
in service
|
$
|
58,021
|
$
|
29,885
|
$
|
44,156
|
$
|
281,279
|
|||||
Accumulated
depreciation
|
38,609
|
21,729
|
29,083
|
46,714
|
|||||||||
December
31, 2008
|
|||||||||||||
Ownership
percentages
|
23.4
|
%
|
8.7
|
%
|
10.0
|
%
|
30.0
|
%
|
|||||
Plant
in service
|
$
|
58,026
|
$
|
29,771
|
$
|
43,406
|
$
|
266,627
|
|||||
Accumulated
depreciation
|
34,636
|
20,708
|
26,795
|
21,462
|
(4) Asset
Retirement Obligations
We
recognize a liability for the legal obligation to perform an asset retirement
activity in which the timing and/or method of settlement are conditional on a
future event. 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.
F-13
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. These
amounts do not represent legal retirement obligations. As of December 31, 2009
and December 31, 2008, we have recognized accrued removal costs of $209.2
million and $194.3 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 $14.9 million and $14.3 million as
of December 31, 2009 and December 31, 2008, respectively.
The
liabilities associated with conditional AROs are adjusted on an ongoing basis
due to the passage of new laws and regulations and revisions to either the
timing or amount of estimates of undiscounted cash flows and estimates of cost
escalation factors. We have recorded a conditional asset retirement obligation
of $5.3 million and $6.3 million, as of December 31, 2009 and 2008,
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. 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 gross conditional ARO during the year ended December 31, 2009, is
as follows (in thousands):
Liability
at January 1, 2009
|
$
|
7,160
|
||
Accretion
expense
|
480
|
|||
Liabilities
incurred
|
113
|
|||
Liabilities
settled
|
(1,048
|
)
|
||
Revisions
to cash flows
|
(17
|
)
|
||
Liability
at December 31, 2009
|
$
|
6,688
|
(5) Goodwill
Goodwill
by segment is as follows (in thousands):
December
31,
|
||||||
2009
|
2008
|
|||||
Regulated
electric
|
$
|
241,100
|
$
|
241,100
|
||
Regulated
natural gas
|
114,028
|
114,028
|
||||
$
|
355,128
|
$
|
355,128
|
Goodwill
is not amortized; rather, it is evaluated for impairment at least annually. We
evaluated our goodwill during the fourth quarters of 2009 and 2008 and
determined that it was not impaired.
(6) Risk
Management and Hedging Activities
Nature
of Our Business and Associated Risks
We are
exposed to certain risks related to the ongoing operations of our business,
including the impact of market fluctuations in the price of electricity and
natural gas commodities and changes in interest rates. Commodity price risk is a
significant risk due to our lack of ownership of natural gas reserves and
minimal ownership of regulated electric generation assets within the Montana
market. Several factors influence price levels and volatility. These factors
include, but are not limited to, seasonal changes in demand, weather conditions,
available generating assets within regions, transportation availability and
reliability within and between regions, fuel availability, market liquidity, and
the nature and extent of current and potential federal and state
regulations.
F-14
Objectives
and Strategies for Using Derivatives
To manage
our exposure to fluctuations in commodity prices, we routinely enter into
derivative contracts, such as fixed-price forward purchase and sales contracts.
The objective of these transactions is to fix the price for a portion of
anticipated energy purchases to supply our regulated customers. These types of
contracts are included in our electric and natural gas supply portfolios and are
used to manage price volatility risk by taking advantage of seasonal
fluctuations in market prices. While we may incur gains or losses on individual
contracts, the overall portfolio approach is intended to provide price stability
for consumers; therefore, these commodity costs are included in our cost
tracking mechanisms. We do not maintain a trading portfolio, and do not
currently have any derivative transactions that are not used for risk management
purposes. In addition, we may use interest rate swaps to manage our interest
rate exposures associated with new debt issuances or to manage our exposure to
fluctuations in interest rates on variable rate debt.
Accounting
for Derivative Instruments
We
evaluate new and existing transactions and agreements to determine whether they
are derivatives. Mark-to-market accounting is the default accounting treatment
for all derivatives unless they qualify, and we specifically designate them, for
one of the other accounting treatments. Derivatives designated for any of the
elective accounting treatments must meet specific, restrictive criteria both at
the time of designation and on an ongoing basis. The permitted accounting
treatments include: normal purchase normal sale; cash flow hedge; fair value
hedge; and mark-to-market. 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.
Normal
Purchases and Normal Sales
We have
applied the normal purchase and normal sale scope exception (NPNS) to most of
our contracts involving the physical purchase and sale of gas and electricity at
fixed prices in future periods. During our normal course of business, we enter
into full-requirement energy contracts, power purchase agreements and physical
capacity contracts, which qualify for NPNS. All of these contracts are accounted
for using the accrual method of accounting; therefore, there were no amounts
recorded in the Financial Statements at December 31, 2009 and 2008. 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.
Mark-to-Market
Accounting
Certain
contracts for the physical purchase of natural gas associated with our regulated
gas utilities do not qualify for NPNS. These are typically forward purchase
contracts for natural gas where we lock in a fixed price; however the contracts
are settled financially and we do not take physical delivery of the natural gas.
We use the mark-to-market method of accounting for these derivative contracts as
we do not elect hedge accounting. Upon settlement of these contracts, associated
proceeds or costs are refunded to or collected from our customers consistent
with regulatory requirements therefore we record a regulatory asset or liability
based on changes in market value.
The
following table represents the fair value and location of derivative instruments
subject to mark-to-market accounting (in thousands). For more information on the
determination of fair value see Note 7.
December
31,
|
|||||||||
Mark-to-Market
Transactions
|
Balance
Sheet Location
|
2009
|
2008
|
||||||
Regulated
natural gas net derivative liability
|
Accrued
Expenses
|
$
|
23,661
|
$
|
29,156
|
F-15
The
following table represents the net change in fair value for these derivatives
(in thousands):
Unrealized
gain (loss) recognized in
Regulatory
Assets
|
|||||||
December
31,
|
|||||||
Derivatives Subject to Regulatory
Deferral
|
2009
|
2008
|
|||||
Natural
gas
|
$
|
5,495
|
$
|
(23,436
|
)
|
Credit
Risk
We are
exposed to credit risk primarily through buying and selling electricity and
natural gas to serve customers. Credit risk is the potential loss resulting from
counterparty non-performance under an agreement. We manage credit risk with
policies and procedures for, among other things, counterparty analysis and
exposure measurement, monitoring and mitigation. We may request collateral or
other security from our counterparties based on the assessment of
creditworthiness and expected credit exposure. It is possible that volatility in
commodity prices could cause us to have material credit risk exposures with one
or more counterparties.
We enter
into commodity master arrangements with our counterparties to mitigate credit
exposure, as these agreements reduce the risk of default by allowing us or our
counterparty the ability to make net payments. The agreements generally are:
Western Systems Power Pool agreements (WSPP) – standardized power sales
contracts in the electric industry; (2) International Swaps and Derivatives
Association agreements (ISDA) – standardized financial gas and electric
contracts; (3) North American Energy Standards Board agreements (NAESB) –
standardized physical gas contracts; and (4) Edison Electric Institute Master
Purchase and Sale Agreements – standardized power sales contracts in the
electric industry.
Many of
our forward purchase contracts contain provisions that require us to maintain an
investment grade credit rating from each of the major credit rating agencies. If
our credit rating were to fall below investment grade, it would be in violation
of these provisions, and the counterparties could require immediate payment or
demand immediate and ongoing full overnight collateralization on contracts in
net liability positions.
The
following table presents, as of December 31, 2009, the aggregate fair value
of forward purchase contracts that do not qualify as normal purchases in a net
liability position with credit risk-related contingent features, collateral
posted, and the aggregate amount of additional collateral that we would be
required to post with counterparties, if the credit risk-related contingent
features underlying these agreements were triggered on December 31, 2009
(in thousands):
Contracts
with Contingent Feature
|
Fair
Value Liability
|
Posted
Collateral
|
Contingent
Collateral
|
|||||||
Credit
rating
|
$
|
23,199
|
$
|
—
|
$
|
23,199
|
Interest
Rate Swaps Designated as Cash Flow Hedges
If we
enter into contracts to hedge 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.
F-16
We have
used interest rate swaps designated as cash flow hedges to manage our interest
rate exposures associated with new debt issuances. These swaps were designated
as cash-flow hedges with the effective portion of gains and losses, net of
associated deferred income tax effects, recorded in Accumulated Other
Comprehensive Income (AOCI). We reclassify these gains from AOCI into interest
expense during the periods in which the hedged interest payments occur. The
following table shows the effect of these derivative instruments on the
Financial Statements:
Cash
Flow Hedges
|
Amount
of Gain Remaining in AOCI as of December 31, 2009
|
Location
of Gain Reclassified from AOCI to Income
|
Amount
of Gain Reclassified from AOCI into Income during the Year
Ended
December
31, 2009
|
|||||||
Interest
rate contracts
|
$
|
10,464
|
Interest
Expense
|
$
|
1,188
|
|||||
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. These
gains relate to swaps previously terminated, and we have no current interest
rate swaps outstanding.
(7) Fair
Value Measurements
Fair
value is defined as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at
the measurement date (i.e., an exit price). Measuring fair value requires the
use of market data or assumptions that market participants would use in pricing
the asset or liability, including assumptions about risk and the risks inherent
in the inputs to the valuation technique. These inputs can be readily
observable, corroborated by market data, or generally unobservable. Valuation
techniques are required to maximize the use of observable inputs and minimize
the use of unobservable inputs.
A fair
value hierarchy that prioritizes the inputs used to measure fair value, and
requires fair value measurements to be categorized based on the observability of
those inputs has been established by the applicable accounting guidance. The
hierarchy gives the highest priority to unadjusted quoted prices in active
markets for identical assets or liabilities (Level 1 inputs) and the lowest
priority to unobservable inputs (Level 3 inputs). The three levels of the fair
value hierarchy are as follows:
·
|
Level
1 – Unadjusted quoted prices available in active markets at the
measurement date for identical assets or
liabilities;
|
·
|
Level
2 – Pricing inputs, other than quoted prices included within Level 1,
which are either directly or indirectly observable as of the reporting
date; and
|
·
|
Level
3 – Significant inputs that are generally not observable from market
activity.
|
F-17
We
classify assets and liabilities within the fair value hierarchy based on the
lowest level of input that is significant to the fair value measurement of each
individual asset and liability taken as a whole. The table below sets forth by
level within the fair value hierarchy the gross components of our assets and
liabilities measured at fair value on a recurring basis. Normal purchases and
sales transactions are not included in the fair values by source table as they
are not recorded at fair value. See Note 6 for further discussion.
December
31, 2009
|
Quoted
Prices in Active Markets for Identical Assets or Liabilities (Level
1)
|
Significant
Other Observable Inputs
(Level
2)
|
Significant
Unobservable Inputs
(Level
3)
|
Margin
Cash Collateral Offset
|
Total
Net Fair Value
|
|||||||||||
(in
thousands)
|
||||||||||||||||
Cash
equivalents
|
$
|
3,000
|
$
|
—
|
$
|
—
|
$
|
—
|
$
|
3,000
|
||||||
Restricted
cash
|
12,942
|
—
|
—
|
—
|
12,942
|
|||||||||||
Derivative
asset (1)
|
—
|
972
|
—
|
—
|
972
|
|||||||||||
Derivative
liability (1)
|
—
|
(24,633
|
)
|
—
|
—
|
(24,633
|
)
|
|||||||||
Net
derivative position
|
—
|
(23,661
|
)
|
—
|
—
|
(23,661
|
)
|
|||||||||
Total
|
$
|
15,942
|
$
|
(23,661
|
)
|
$
|
—
|
$
|
—
|
$
|
(7,719
|
)
|
||||
December
31, 2008
|
||||||||||||||||
Restricted
cash
|
14,719
|
—
|
—
|
—
|
14,719
|
|||||||||||
Derivative
liability (1)
|
—
|
(29,156
|
)
|
—
|
—
|
(29,156
|
)
|
|||||||||
Total
|
$
|
14,719
|
$
|
(29,156
|
)
|
$
|
—
|
$
|
—
|
$
|
(14,437
|
)
|
(1)
|
The
changes in the fair value of these derivatives are deferred as a
regulatory asset or liability until the contracts are settled. Upon
settlement, associated proceeds or costs are passed through the applicable
cost tracking mechanism to
customers.
|
We
present our derivative assets and liabilities on a net basis in the Consolidated
Balance Sheets. The table above disaggregates our net derivative assets and
liabilities on a gross contract-by-contract basis as required and classifies
each individual asset or liability within the appropriate level in the fair
value hierarchy, regardless of whether a particular contract is eligible for
netting against other contracts. These gross balances are intended solely to
provide information on sources of inputs to fair value and do not represent our
actual credit exposure or net economic exposure. Increases and decreases in the
gross components presented in each of the levels in this table also do not
indicate changes in the level of derivative activities. Rather, the primary
factors affecting the gross amounts are commodity prices.
Cash
equivalents and restricted cash represent amounts held in money market mutual
funds. Fair value for the commodity derivatives was determined using internal
models based on quoted forward commodity prices. We consider nonperformance risk
in our valuation of derivative instruments by analyzing the credit standing of
our counterparties and considering any counterparty credit enhancements (e.g.,
collateral). The fair value measurement of liabilities also reflects the
nonperformance risk of the reporting entity, as applicable. Therefore, we have
factored the impact of our credit standing as well as any potential credit
enhancements into the fair value measurement of both derivative assets and
derivative liabilities. Consideration of our own credit risk did not have a
material impact on our fair value measurements.
Financial Instruments
The
estimated fair value of financial instruments is summarized as follows (in
thousands):
December
31, 2009
|
December
31, 2008
|
|||||||||||
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
|||||||||
Liabilities:
|
||||||||||||
Long-term
debt (including current portion)
|
$
|
987,419
|
$
|
1,034,122
|
$
|
862,056
|
$
|
780,023
|
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.
We used
the following methods and assumptions 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, cash equivalents, and restricted cash
approximate fair value due to the short maturity of the
instruments.
|
·
|
We
determined fair values for debt 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, for which fair value is based
on market prices for the same or similar issues or upon the quoted market
prices of U.S. treasury issues having a similar term to maturity, adjusted
for our bond issuance rating and the present value of future cash
flows.
|
(8) Long-Term
Debt and Capital Leases
Long-term
debt and capital leases consisted of the following (in thousands):
December
31,
|
|||||||||
Due
|
2009
|
2008
|
|||||||
Unsecured
Debt:
|
|||||||||
Unsecured
Revolving Line of Credit
|
2012
|
$
|
66,000
|
$
|
108,000
|
||||
Secured
Debt:
|
|||||||||
Mortgage
bonds—
|
|||||||||
South
Dakota—6.05%
|
2018
|
55,000
|
55,000
|
||||||
Montana—6.04%
|
2016
|
150,000
|
150,000
|
||||||
Montana—6.34%
|
2019
|
250,000
|
—
|
||||||
Montana—5.71%
|
2039
|
55,000
|
—
|
||||||
South
Dakota & Montana—5.875%
|
2014
|
225,000
|
225,000
|
||||||
Pollution
control obligations—
|
|||||||||
Montana—4.65%
|
2023
|
170,205
|
170,205
|
||||||
Montana
Natural Gas Transition Bonds— 6.20%
|
2012
|
16,493
|
22,355
|
||||||
Other
Long Term Debt:
|
|||||||||
Colstrip
Unit 4 debt—13.25%
|
2010
|
—
|
31,666
|
||||||
Colstrip
Lease Holdings, LLC—floating rate
|
2009
|
—
|
100,000
|
||||||
Discount
on Notes and Bonds
|
—
|
(279
|
)
|
(170
|
)
|
||||
987,419
|
862,056
|
||||||||
Less
current maturities
|
(6,123
|
)
|
(228,045
|
)
|
|||||
$
|
981,296
|
$
|
634,011
|
||||||
Capital
Leases:
|
|||||||||
Total
Capital Leases
|
Various
|
$
|
36,767
|
$
|
37,991
|
||||
Less
current maturities
|
(1,197
|
)
|
(1,193
|
)
|
|||||
$
|
35,570
|
$
|
36,798
|
F-19
Unsecured
Revolving Line of Credit
On June
30, 2009, we amended and restated our unsecured revolving line of credit
scheduled to expire on November 1, 2009. The amended facility extends the term
to June 30, 2012, and increases the aggregate principal amount available under
the facility by $50 million to $250 million. The amended facility does not
amortize and borrowings will bear interest based on a credit ratings grid. A
total of nine banks participate in the new facility, with no one bank providing
more than 14% of the total availability. The amended facility contains covenants
substantially similar to the previous facility.
The
‘spread’ or ‘margin’ ranges from 2.25% to 4.0% over the London Interbank Offered
Rate (LIBOR). The facility bears interest at a rate of approximately 3.23%,
which is 3.0% over LIBOR, as of December 31, 2009, and we had $3.1 million in
letters of credit and $66 million of borrowings outstanding. The weighted
average interest rate on the outstanding revolving credit facility borrowings
was 2.9% as of December 31, 2009.
Commitment
fees for the unsecured revolving line of credit were $0.7 million and $0.3
million for the years ended December 31, 2009 and 2008,
respectively.
The
credit facility includes covenants, which require us to meet certain financial
tests, including a maximum debt to capitalization ratio not to exceed 65%. The
amended and restated line of credit also contains covenants which, among other
things, limit our ability to engage in any consolidation or merger or otherwise
liquidate or dissolve, dispose of property, and enter into transactions with
affiliates. 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 a series of general obligation bonds issued 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.
Financing
Transactions
In March
2009, we issued $250 million of Montana First Mortgage Bonds at a fixed interest
rate of 6.34% maturing April 1, 2019, which were discounted to yield 6.349%. The
bonds are secured by our Montana electric and natural gas assets. The bonds were
issued in a transaction exempt from registration under the Securities Act of
1933, as amended. We completed an offer to exchange these bonds for a like
series of bonds registered under the Securities Act of 1933 during the third
quarter of 2009. We used the proceeds to redeem our $100 million Colstrip Lease
Holdings LLC term loan, repay outstanding borrowings on our revolving credit
facility, repay other outstanding debt obligations of $31.7 million related to
Colstrip Unit 4, fund a portion of the costs of the Mill Creek generation
project, and fund future capital expenditures.
On
October 15, 2009 we issued $55 million of Montana First Mortgage Bonds at a
fixed interest rate of 5.71% maturing October 15, 2039. The bonds are secured by
our Montana electric and natural gas assets. The transaction is exempt from the
registration requirements of the Securities Act of 1933, as amended. We used the
proceeds to fund a portion of the costs of the Mill Creek generation project and
capital expenditures.
F-20
Maturities
of Long-Term Debt
The
aggregate minimum principal maturities of long-term debt and capital leases,
during the next five years are $7.3 million in 2010, $7.9 million in 2011, $71.2
million in 2012, $1.5 million in 2013 and $226.6 million in 2014.
As of
December 31, 2009, we are in compliance with our financial debt
covenants.
(9) Income
Taxes
Income
tax expense is comprised of the following (in thousands):
Year
Ended December 31,
|
||||||||||
2009
|
2008
|
2007
|
||||||||
Federal
|
||||||||||
Current
|
$
|
(448
|
)
|
$
|
863
|
$
|
1,449
|
|||
Deferred
|
15,077
|
37,916
|
28,586
|
|||||||
Investment
tax credits
|
(494
|
)
|
(580
|
)
|
(531
|
)
|
||||
State
|
1,169
|
2,022
|
2,884
|
|||||||
$
|
15,304
|
$
|
40,221
|
$
|
32,388
|
The
following table reconciles our effective income tax rate to the federal
statutory rate:
Year
Ended December 31,
|
|||||||||
2009
|
2008
|
2007
|
|||||||
Federal
statutory rate
|
35.0
|
%
|
35.0
|
%
|
35.0
|
%
|
|||
State
income, net of federal provisions
|
1.8
|
1.9
|
3.4
|
||||||
Amortization
of investment tax credit
|
(0.5
|
)
|
(0.5
|
)
|
(0.7
|
)
|
|||
Depreciation
of flow through items
|
0.1
|
(0.6
|
)
|
(0.7
|
)
|
||||
2009
flow through repair deduction
|
(9.5
|
)
|
—
|
—
|
|||||
Nondeductible
professional fees
|
0.1
|
(0.4
|
)
|
1.5
|
|||||
Prior
year permanent return to accrual adjustments
|
(9.1
|
)
|
0.2
|
(1.1
|
)
|
||||
Other,
net
|
(0.7
|
)
|
1.7
|
0.4
|
|||||
17.2
|
%
|
37.3
|
%
|
37.8
|
%
|
The 2009
effective tax rate reflects the impact of a change in tax accounting method for
repairs for both 2008 and 2009, as well as lower 2009 taxable income. In
December 2008, we filed a request with the Internal Revenue Service (IRS) to
change our tax accounting method related to costs to repair and maintain utility
assets. The IRS approved our request in September 2009, which allowed us to take
a current tax deduction for a significant amount of repair costs that were
previously capitalized for tax purposes.
These
repair costs are capitalized and depreciated for book purposes. We record a
deferred income tax liability as we flow the temporary timing differences
between book and tax treatment through to our customers in the form of lower
rates. A regulatory asset is established to reflect that future increases in
taxes payable will be recovered from customers as the temporary differences
reverse. Due to this regulatory treatment, we recorded an income tax benefit of
approximately $16.6 million during the year ended December 31, 2009 to reflect
this change in tax accounting method, of which approximately $8.7 million and
$7.9 million related to the 2009 and 2008 tax years, respectively. The 2008
deduction is reflected as a prior year return to accrual adjustment in the table
above. For years prior to 2008, we have not recorded a regulatory asset for the
repairs deduction pending regulatory review. This change in tax accounting
method will have the effect of increasing and extending our net operating loss
carryforwards.
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 and electric costs which are deferred for book purposes but expensed
currently for tax purposes, and net operating loss carry forwards.
F-21
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,
|
|||||||
2009
|
2008
|
||||||
Unbilled
revenue
|
$
|
2,937
|
$
|
2,158
|
|||
Compensation
accruals
|
1,428
|
1,418
|
|||||
Regulatory
assets
|
(3,195
|
)
|
(2,012
|
)
|
|||
Reserves
and accruals
|
(685
|
)
|
(556
|
)
|
|||
Other,
net
|
754
|
(323
|
)
|
||||
Current
Deferred Tax Asset, net
|
1,239
|
685
|
|||||
Excess
tax depreciation
|
(190,231
|
)
|
(139,024
|
)
|
|||
Goodwill
amortization
|
(68,434
|
)
|
(59,674
|
)
|
|||
Pension
liability
|
(54,546
|
)
|
(34,605
|
)
|
|||
Flow
through depreciation
|
(19,468
|
)
|
(7,713
|
)
|
|||
Valuation
allowance
|
(6,382
|
)
|
(6,382
|
)
|
|||
Net
operating loss (NOL) carryforward
|
113,858
|
65,432
|
|||||
Regulatory
assets
|
24,880
|
16,049
|
|||||
Customer
advances
|
18,541
|
19,693
|
|||||
Environmental
liability
|
9,254
|
9,334
|
|||||
AMT
credit carryforward
|
5,604
|
5,863
|
|||||
Other,
net
|
5,736
|
16,320
|
|||||
Noncurrent
Deferred Tax Liability, net
|
(161,188
|
)
|
(114,707
|
)
|
|||
Deferred
Tax Liability, net
|
$
|
(159,949
|
)
|
$
|
(114,022
|
)
|
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 its deferred tax assets. We have a valuation allowance against certain
state NOL carryforwards as we do not believe these assets will be
realized.
At
December 31, 2009 we estimate our total federal NOL carryforward to be
approximately $475.9 million. If unused, our federal NOL carryforwards will
expire as follows: $171.0 million in 2023; $192.1 million in 2025; $88.1 million
in 2028; and $24.7 million 2029. We estimate our state NOL carryforward as of
December 31, 2009 is approximately $595.8 million. If unused, our state NOL
carryforwards will expire as follows: $318.9 million in 2010; $33.8 million in
2011; $152.9 million in 2012; $70.5 million in 2015; and $19.7 million in 2016.
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.
Uncertain
Tax Positions
We
recognize tax positions that meet the more-likely-than-not threshold 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. The change in unrecognized tax benefits
is as follows (in thousands):
2009
|
2008
|
||||||
Unrecognized
Tax Benefits at January 1
|
$
|
115,105
|
$
|
111,124
|
|||
Gross
increases - tax positions in prior period
|
9,960
|
6,468
|
|||||
Gross
decreases - tax positions in prior period
|
(2,221
|
)
|
(2,487
|
)
|
|||
Unrecognized
Tax Benefits at December 31
|
$
|
122,844
|
$
|
115,105
|
Our
unrecognized tax benefits include approximately $85.1 million related to tax
positions as of December 31, 2009 and 2008, respectively that if recognized,
would impact our annual effective tax rate. We do not anticipate total
unrecognized tax benefits will significantly change due to the settlement of
audits or the expiration of statutes of limitations within the next twelve
months.
F-22
Our
policy is to recognize interest and penalties related to uncertain tax positions
in income tax expense. During the years ended December 31, 2009 and 2008, we
have not recognized expense for interest or penalties, and do not have any
amounts accrued at December 31, 2009 and 2008, respectively, for the payment of
interest and penalties.
Our
federal tax returns from 2000 forward remain subject to examination by the
Internal Revenue Service.
(10) Accumulated
Other Comprehensive Income
The
following table displays the components of AOCI, which is included in
Shareholder’s Equity on the Consolidated Balance Sheets (in
thousands).
Net
Unrealized Gains on Hedging Instruments
|
Pension
and Other Benefits
|
Other
|
Total
|
||||||||||||||
Balances
December 31, 2006
|
$
|
14,029
|
$
|
162
|
$
|
80
|
$
|
14,271
|
|||||||||
Reclassification
of net gains on hedging instruments from OCI to net income
|
(1,188
|
)
|
—
|
—
|
(1,188
|
)
|
|||||||||||
Pension
and postretirement medical liability adjustment, net of tax of
$133
|
—
|
347
|
—
|
347
|
|||||||||||||
Foreign
currency translation
|
—
|
—
|
318
|
318
|
|||||||||||||
Balances
December 31, 2007
|
12,841
|
509
|
398
|
13,748
|
|||||||||||||
Reclassification
of net gains on hedging instruments from OCI to net income
|
(1,188
|
)
|
—
|
—
|
(1,188
|
)
|
|||||||||||
Pension
and postretirement medical liability adjustment, net of tax of
$128
|
—
|
204
|
—
|
204
|
|||||||||||||
Foreign
currency translation
|
—
|
—
|
(410
|
)
|
(410
|
)
|
|||||||||||
Balances
December 31, 2008
|
11,653
|
713
|
(12
|
)
|
12,354
|
||||||||||||
Reclassification
of net gains on hedging instruments from OCI to net income
|
(1,188
|
)
|
—
|
—
|
(1,188
|
)
|
|||||||||||
Pension
and postretirement medical liability adjustment, net of tax of
$1,088
|
—
|
(1,737
|
)
|
—
|
(1,737
|
)
|
|||||||||||
Foreign
currency translation
|
—
|
—
|
296
|
296
|
|||||||||||||
Balance
at December 31, 2009
|
$
|
10,465
|
$
|
(1,024
|
)
|
$
|
284
|
$
|
9,725
|
(11) Operating
Leases
We lease
vehicles, office equipment and facilities under various long-term operating
leases. At December 31, 2009 future minimum lease payments for the next five
years under non-cancelable lease agreements are as follows (in
thousands):
2010
|
$
|
1,529
|
|
2011
|
1,079
|
||
2012
|
688
|
||
2013
|
86
|
||
2014
|
63
|
Lease and
rental expense incurred was $1.8 million, $2.1 million and $19.0 million for the
years ended December 31, 2009, 2008 and 2007, respectively.
F-23
(12) 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 eligible employees, which includes two cash balance
pension plans. The plan for our South Dakota and Nebraska employees is referred
to as the NorthWestern pension plan, and the plan for our Montana employees is
referred to as the NorthWestern Energy pension plan.
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. The Plan’s funded
status is recognized as an asset or liability in our financial statements. See
Note 14 for further discussion on how these costs are recovered through rates
charged to our customers.
Plan
Amendment
In 2009,
we amended our postretirement medical plan to: (i) cap the company contribution
toward the premium cost for coverage; (ii) provide a company contribution toward
the premium cost for coverage to our South Dakota and Nebraska retirees; and
(iii) change eligibility provisions for the company contributions from age 50
with 5 years of service to age 60 with 20 years of service for employees
terminating on or after January 1, 2011. Previously, only our Montana retirees
received a company contribution.
In 2008,
we amended our NorthWestern Corporation and NorthWestern Energy pension plans to
close the plans to new employees effective January 1, 2009. New employees are
eligible to participate in the defined contribution plan.
F-24
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,
|
December 31,
|
||||||||||||
2009
|
2008
|
2009
|
2008
|
||||||||||
Change
in Benefit Obligation:
|
|||||||||||||
Obligation
at beginning of period
|
$
|
388,659
|
$
|
376,872
|
$
|
44,323
|
$
|
46,494
|
|||||
Service
cost
|
8,270
|
8,405
|
993
|
563
|
|||||||||
Interest
cost
|
23,705
|
22,875
|
3,149
|
2,367
|
|||||||||
Plan
amendments
|
—
|
49
|
(25,427
|
)
|
—
|
||||||||
Actuarial
loss (gain)
|
13,962
|
405
|
14,191
|
(1,275
|
)
|
||||||||
Gross
benefits paid
|
(19,318
|
)
|
(19,947 |
)
|
(4,882
|
)
|
(3,826
|
)
|
|||||
Benefit
obligation at end of period
|
$
|
415,278
|
$
|
388,659
|
$
|
32,347
|
$
|
44,323
|
|||||
Change
in Fair Value of Plan Assets:
|
|||||||||||||
Fair
value of plan assets at beginning of period
|
$
|
242,228
|
$
|
330,446
|
$
|
12,421
|
$
|
16,455
|
|||||
Return
on plan assets
|
75,619
|
(101,005
|
)
|
2,877
|
(5,063
|
)
|
|||||||
Employer
contributions
|
92,900
|
32,734
|
4,882
|
4,855
|
|||||||||
Gross
benefits paid
|
(19,318
|
) |
(19,947
|
)
|
(4,882
|
)
|
(3,826
|
)
|
|||||
Fair
value of plan assets at end of period
|
$
|
391,429
|
$
|
242,228
|
$
|
15,298
|
$
|
12,421
|
|||||
Funded
Status
|
$
|
(23,849
|
) |
$
|
(146,431
|
)
|
$
|
(17,049
|
)
|
$
|
(31,902
|
)
|
|
Unrecognized
net actuarial (gain) loss
|
—
|
—
|
—
|
—
|
|||||||||
Unrecognized
prior service cost
|
—
|
—
|
—
|
—
|
|||||||||
Accrued
benefit cost
|
$
|
(23,849
|
) |
$
|
(146,431
|
)
|
$
|
(17,049
|
)
|
$
|
(31,902
|
)
|
|
Amounts
recognized in the balance sheet consist of:
|
|||||||||||||
Current
liability
|
—
|
—
|
(1,028
|
)
|
(883
|
)
|
|||||||
Noncurrent
liability
|
(23,849
|
) |
(146,431
|
)
|
(16,021
|
)
|
(31,019
|
)
|
|||||
Net
amount recognized
|
$
|
(23,849
|
) |
$
|
(146,431
|
)
|
$
|
(17,049
|
)
|
$
|
(31,902
|
)
|
|
Amounts
recognized in regulatory assets consist of:
|
|||||||||||||
Transition
obligation
|
—
|
—
|
—
|
—
|
|||||||||
Prior
service (cost) credit
|
(1,734
|
) |
(1,980
|
)
|
27,332
|
||||||||
Net
actuarial (loss) gain
|
(38,711
|
) |
(82,061
|
)
|
(9,908
|
)
|
1,203
|
||||||
Amounts
recognized in AOCI consist of:
|
|||||||||||||
Transition
obligation
|
—
|
—
|
—
|
—
|
|||||||||
Prior
service cost
|
—
|
—
|
(1,905
|
)
|
—
|
||||||||
Net
actuarial gain
|
—
|
—
|
21
|
941
|
|||||||||
Total
|
$
|
(40,445
|
) |
$
|
(84,041
|
)
|
$
|
15,540
|
$
|
2,144
|
F-25
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 as follows (in
millions):
Pension
Benefits
|
|||||||
December
31,
|
|||||||
2009
|
2008
|
||||||
Projected
benefit obligation
|
$
|
415.3
|
$
|
388.7
|
|||
Accumulated
benefit obligation
|
413.2
|
386.5
|
|||||
Fair
value of plan assets
|
391.4
|
242.2
|
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,
|
||||||||||||||||||
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
||||||||||||||
Components
of Net Periodic Benefit Cost
|
|||||||||||||||||||
Service
cost
|
$
|
8,270
|
$
|
8,405
|
$
|
8,947
|
$
|
993
|
$
|
563
|
$
|
580
|
|||||||
Interest
cost
|
23,705
|
22,875
|
21,800
|
3,149
|
2,367
|
2,442
|
|||||||||||||
Expected
return on plan assets
|
(22,383
|
)
|
(27,212
|
)
|
(24,422
|
)
|
(994
|
)
|
(1,316
|
)
|
(1,068
|
)
|
|||||||
Amortization
of transitional obligation
|
—
|
—
|
—
|
—
|
—
|
—
|
|||||||||||||
Amortization
of prior service cost
|
246
|
246
|
242
|
—
|
—
|
—
|
|||||||||||||
Recognized
actuarial loss (gain)
|
4,058
|
(818
|
)
|
—
|
277
|
(599
|
)
|
(259
|
)
|
||||||||||
Net
Periodic Benefit Cost
|
$
|
13,896
|
$
|
3,496
|
$
|
6,567
|
$
|
3,425
|
$
|
1,015
|
$
|
1,695
|
We
estimate amortizations from regulatory assets into net periodic benefit cost
during 2010 will be as follows (in thousands):
Pension
Benefits
|
Other
Postretirement
Benefits
|
||||||
Prior
service cost
|
$
|
246
|
$
|
(1,952
|
)
|
||
Accumulated
gain
|
—
|
586
|
Actuarial
Assumptions
The
measurement dates used to determine pension and other postretirement benefit
measurements for the plans are December 31, 2009 and 2008. 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 2009
and 2008, 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.
In
determining the expected long-term rate of return on plan assets, we review
historical returns, the future expectations for returns for each asset class
weighted by the target asset allocation of the pension and postretirement
portfolios, and long-term inflation assumptions. During the fourth quarter of
2009, we revised our target asset allocation from 70% equity securities, and 30%
fixed-income securities to 60% equity securities, and 40% fixed-income
securities. Considering this information and future expectations for asset
returns, we reduced our expected long-term rate of return on assets assumption
from 8.00% to 7.75% for 2010.
F-26
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 800 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,
|
||||||||||||
2009
|
2008
|
2007
|
2009
|
2008
|
2007
|
||||||||
Discount
rate
|
5.75-6.00
|
%
|
6.25
|
%
|
6.25
|
%
|
4.75-6.00
|
%
|
6.00-6.25
|
%
|
5.75-6.00
|
%
|
|
Expected
rate of return on assets
|
8.00
|
8.00
|
8.00
|
8.00
|
8.00
|
8.00
|
|||||||
Long-term
rate of increase in compensation levels (nonunion)
|
3.58
|
3.58
|
3.58
|
3.58
|
3.55
|
3.55
|
|||||||
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 9.5% in 2009 and the rate of increase in the per capita cost of
covered health care benefits thereafter was assumed to decrease gradually to
4.5% by the year 2029.
Assumed
health care cost trend rates have had a significant effect on the amounts
reported for the costs each year as well as on the accumulated postretirement
benefit obligation. With our 2009 plan amendment to cap the company contribution
toward the premium cost, future health care cost trend rates are expected to
have a minimal impact on company costs and 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
|
$
|
—
|
|
on
postretirement benefit obligation
|
—
|
||
Effect
of a one percentage point decrease in assumed health care cost
trend
|
|||
on
total service and interest cost components
|
$
|
(1
|
)
|
on
postretirement benefit obligation
|
(14
|
)
|
F-27
Investment
Strategy
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. Each plan is diversified
across asset classes to achieve optimal balance between risk and return and
between income and growth through capital appreciation. Our investment
philosophy is based on the following:
·
|
Each
Plan should be substantially fully invested as long-term cash holdings
reduce long-term rates of return;
|
·
|
It
is prudent to diversify each Plan across the major asset
classes;
|
·
|
Equity
investments provide greater long-term returns than fixed income
investments, although with greater short-term
volatility;
|
·
|
Fixed
income investments of the Plans should strongly correlate with the
interest rate sensitivity of the Plan’s aggregate liabilities in order to
hedge the risk of change in interest rates negatively impacting the
overall funded status;
|
·
|
Allocation
to foreign equities increases the portfolio diversification and thereby
decreases portfolio risk while providing for the potential for enhanced
long-term returns;
|
·
|
Active
management can reduce portfolio risk and potentially add value through
security selection strategies;
|
·
|
A
portion of plan assets should be allocated to passive, indexed management
to provide for greater diversification and lower cost;
and
|
·
|
It
is appropriate to retain more than one investment manager, provided that
such managers offer asset class or style
diversification.
|
Investment
risk is measured and monitored on an ongoing basis through quarterly investment
portfolio reviews, annual liability measurements, and periodic asset/liability
studies.
The most
important component of an investment strategy is the portfolio asset mix, or the
allocation between the various classes of securities available. The mix of
assets is based on an optimization study that identifies asset allocation
targets in order to achieve the maximum return for an acceptable level of risk,
while minimizing the expected contributions and pension and postretirement
expense. In the optimization study, assumptions are formulated about
characteristics, such as expected asset class investment returns, volatility
(risk), and correlation coefficients among the various asset classes, and making
adjustments to reflect future conditions expected to prevail over the study
period. Based on this, the target asset allocation established, within an
allowable range of plus or minus 5%, is as follows:
Pension
Benefits
|
Other
Benefits
|
||||||||
December
31,
|
December
31,
|
||||||||
2009
|
2008
|
2009
|
2008
|
||||||
Debt
securities
|
40.0
|
%
|
30.0
|
%
|
40.0
|
%
|
30.0
|
%
|
|
Domestic
equity securities
|
50.0
|
60.0
|
50.0
|
60.0
|
|||||
International
equity securities
|
10.0
|
10.0
|
10.0
|
10.0
|
F-28
The
actual allocation by plan is as follows:
NorthWestern
Energy Pension
|
NorthWestern
Pension
|
NorthWestern
Energy
Health
and Welfare
|
|||||||||||
December 31,
|
December 31,
|
December 31,
|
|||||||||||
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||
Cash and cash
equivalents
|
—
|
%
|
0.1
|
%
|
—
|
%
|
—
|
%
|
—
|
%
|
—
|
%
|
|
Debt
securities
|
38.9
|
31.2
|
39.1
|
34.3
|
36.9
|
31.2
|
|||||||
Domestic equity
securities
|
51.2
|
58.6
|
51.0
|
56.6
|
52.5
|
58.8
|
|||||||
International equity
securities
|
9.9
|
10.1
|
9.9
|
9.1
|
10.6
|
10.0
|
|||||||
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
Generally,
the asset mix will be rebalanced to the target mix as individual portfolios
approach their minimum or maximum levels. Debt securities 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. Performance of
fixed income investments shall be measured by both traditional investment
benchmarks as well as relative changes in the present value of the plans
liabilities. 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.
Our plan
assets are primarily invested in common collective trusts (CCTs), which are
invested in equity and fixed income securities. In accordance with our
investment policy, 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. Investments in a collective investment vehicle are valued by
multiplying the investee company’s net asset value per share with the number of
units or shares owned at the valuation date. Net asset value per share is
determined by the trustee. Investments held by the CCT, including collateral
invested for securities on loan, are valued on the basis of valuations furnished
by a pricing service approved by the CCT’s investment manager, which determines
valuations using methods based on quoted closing market prices on national
securities exchanges, or at fair value as determined in good faith by the CCT’s
investment manager if applicable. The direct holding of NorthWestern Corporation
stock is not permitted; however, any holding in a diversified mutual fund or
collective investment fund is permitted. 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. The participating group annuity contract
is valued based on discounted cash flows of current yields of similar contracts
with comparable duration based on the underlying fixed income
investments.
F-29
The fair
value of our plan assets at December 31, 2009 by asset category are as follows
(in thousands):
Quoted
Market Prices in Active Markets for Identical Assets
|
Significant
Observable Inputs
|
Significant
Unobservable Inputs
|
||||||||||||
Asset
Category
|
Total
|
Level
1
|
Level
2
|
Level
3
|
||||||||||
Pension
Plan Assets
|
||||||||||||||
Cash
and cash equivalents
|
$
|
45
|
$
|
—
|
$
|
45
|
$
|
—
|
||||||
Equity
securities: (1)
|
||||||||||||||
US
small/mid cap growth
|
17,533
|
—
|
17,533
|
—
|
||||||||||
US
small/mid cap value
|
17,414
|
—
|
17,414
|
—
|
||||||||||
US
large cap growth
|
53,835
|
—
|
53,835
|
—
|
||||||||||
US
large cap value
|
52,561
|
—
|
52,561
|
—
|
||||||||||
US
large cap passive
|
58,937
|
—
|
58,937
|
—
|
||||||||||
Non-US
core
|
38,709
|
—
|
38,709
|
—
|
||||||||||
Fixed
income securities:(2)
|
||||||||||||||
US
core opportunistic
|
29,240
|
—
|
29,240
|
—
|
||||||||||
US
passive
|
16,419
|
—
|
16,419
|
—
|
||||||||||
Long
duration
|
92,325
|
—
|
92,325
|
—
|
||||||||||
Ultra
long duration
|
3,278
|
—
|
3,278
|
—
|
||||||||||
Participating
group annuity contract
|
11,133
|
—
|
11,133
|
—
|
||||||||||
$
|
391,429
|
$
|
—
|
$
|
391,429
|
$
|
—
|
|||||||
Other
Postretirement Benefit Plan Assets
|
||||||||||||||
Cash
and cash equivalents
|
$
|
4
|
$
|
—
|
$
|
4
|
$
|
—
|
||||||
Equity
securities: (1)
|
||||||||||||||
US
small/mid cap growth
|
837
|
715
|
122
|
—
|
||||||||||
US
small/mid cap value
|
810
|
689
|
121
|
—
|
||||||||||
S&P
500 index
|
5,238
|
—
|
5,238
|
—
|
||||||||||
US
large cap growth
|
375
|
—
|
375
|
—
|
||||||||||
US
large cap value
|
367
|
—
|
367
|
—
|
||||||||||
US
large cap passive
|
410
|
—
|
410
|
—
|
||||||||||
Non-US
core
|
1,623
|
1,354
|
269
|
—
|
||||||||||
Fixed
income securities: (2)
|
||||||||||||||
Passive
bond market
|
1,008
|
—
|
1,008
|
—
|
||||||||||
US
core opportunistic
|
3,786
|
3,565
|
221
|
—
|
||||||||||
US
passive
|
120
|
—
|
120
|
—
|
||||||||||
Long
duration
|
694
|
—
|
694
|
—
|
||||||||||
Ultra
long duration
|
26
|
—
|
26
|
—
|
||||||||||
$
|
15,298
|
$
|
6,323
|
$
|
8,975
|
$
|
—
|
(1) This
category consists of active and passive managed equity funds, which are invested
in multiple strategies to diversify risks and reduce volatility.
(2) This
category consists of investment grade bonds of U.S. issuers from diverse
industries, debt securities issued by national, state and local governments, and
asset-backed securities. This includes both active and passive managed
funds.
For
further discussion of the three levels of the fair value hierarchy see Note
7.
Cash
Flows
Due to
the unprecedented volatility in equity markets, we experienced plan asset market
gains during 2009 in excess of 20%, and plan asset market losses during 2008 in
excess of 30%, which impact our planned levels of contributions. In accordance
with the Pension Protection Act of 2006 (PPA), and the relief provisions of the
Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), which was signed
into law on December 23, 2008, we are required to meet minimum funding levels in
order to avoid required contributions and benefit restrictions. We have elected
to use asset smoothing provided by the WRERA, which allows the use of asset
averaging, including expected returns (subject to certain limitations), for a
24-month period in the determination of funding requirements. On March 31, 2009,
the U.S. Department of the Treasury (Treasury) provided guidance on the
selection of the corporate bond yield curve for determining plan liabilities and
allowed companies to choose from the range of months in selecting a rate, rather
than requiring the use of prescribed rates. The Treasury’s announcement
specifically referenced 2009, but also indicated that technical guidance will be
forthcoming to address future years. In addition, the IRS and Treasury issued
final regulations effective October 15, 2009 applying to plan years beginning on
or after January 1, 2010 which provided guidance on pension plan funding
requirements.
F-30
Based on
the assumptions allowed under the PPA, WRERA, Treasury guidance and IRS
guidance, and the significant contributions made during 2009, we estimate
minimum required contributions in the future will be approximately
$9 million. We may elect to make contributions earlier than the required
dates. Additional legislative or regulatory measures, as well as fluctuations in
financial market conditions, may impact these funding requirements.
Due to
the regulatory treatment of pension costs in Montana, expense is calculated
using the average of our actual and estimated funding amounts from 2005 through
2012, therefore changes in our funding estimates creates increased volatility to
earnings. As a result of the significant increase in unfunded status as of
December 31, 2008, we reviewed our funding strategy for the plans, and
significantly increased our 2009 cash funding in order to decrease the
volatility of these plans to our long-term results of operations and liquidity
as follows:
2009
|
2008
|
2007
|
||||||||
NorthWestern
Energy Pension Plan (MT)
|
$
|
80,600
|
$
|
31,140
|
$
|
21,966
|
||||
NorthWestern
Pension Plan (SD)
|
12,300
|
1,594
|
672
|
|||||||
$
|
92,900
|
$
|
32,734
|
$
|
22,638
|
The 2009
contributions exceeded our minimum funding requirements by approximately $75.0
million. For our postretirement medical 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 postretirement medical 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
|
|||||
2010
|
$
|
22,047
|
$
|
3,818
|
||
2011
|
23,327
|
3,558
|
||||
2012
|
23,900
|
3,331
|
||||
2013
|
25,714
|
3,331
|
||||
2014
|
26,740
|
3,295
|
||||
2015-2019
|
155,834
|
14,801
|
Defined
Contribution Plan
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
for the year ended December 31, 2009, 2008 and 2007 were $5.8 million, $5.3
million and $4.7 million, respectively.
F-31
(13) Stock-Based
Compensation
We grant
stock-based awards through our 2005 Long-Term Incentive Plan (LTIP), which
includes service based restricted stock awards and performance share awards. As
of December 31, 2009, there were 521,828 shares of common stock remaining
available for grants. The remaining vesting period for awards previously granted
ranges from one to three years if the service and/or performance requirements
are met. Nonvested shares do not receive dividend distributions. The long-term
incentive plan provides for accelerated vesting in the event of a change in
control.
We
account for our share-based compensation arrangements by recognizing
compensation costs for all share-based awards over the respective service period
for employee services received in exchange for an award of equity or
equity-based compensation. The compensation cost is based on the fair value of
the grant on the date it was awarded.
Restricted
Stock and Performance Share Awards
Restricted
stock awards vest within five years after the date of grant. The fair value of
restricted stock is measured based upon the closing market price of our common
stock as of the date of grant. Performance share awards are typically payable at
the end of a three-year performance period if the specified performance criteria
are met.
Performance
share awards were granted under the 2005 LTIP during 2009. With these awards,
shares will vest if, at the end of the three-year performance period, we have
achieved certain performance goals and the individual remains employed by us.
The exact number of shares issued will vary from 0% to 200% of the target award,
depending on actual company performance relative to the performance goals. These
awards contain both a market and performance based component. The performance
goals for these awards are independent of each other and equally weighted, and
are based on two metrics: (i) cumulative earnings per share (EPS) and return on
equity growth; and (ii) total shareholder return (TSR) relative to a peer group.
The fair value of the EPS component is estimated based upon the closing market
price of our common stock as of the date of grant less the present value of
expected dividends, multiplied by an estimated performance multiple determined
on the basis of historical experience, which is subsequently trued up at vesting
based on actual performance. The fair value of the TSR portion is estimated
using a statistical model that incorporates the probability of meeting
performance targets based on historical returns relative to the peer group. The
significant assumptions used to calculate fair value of the TSR component also
included a three-year risk-free rate of 1.37%, volatility of 25.1% to 46.5% for
the peer group, and maintenance of our $1.34 annual dividend over the
performance period. Both performance goals are measured over the three-year
vesting period and are charged to compensation expense over the vesting period
based on the number of shares expected to vest.
A summary
of nonvested shares as of December 31, 2009, and changes during the year ended
December 31, 2009 are as follows:
Performance
Share Awards
|
Restricted
Stock Awards
|
|||||||||||
Shares
|
Weighted-Average
Grant-Date
Fair
Value
|
Shares
|
Weighted-Average
Grant-Date
Fair
Value
|
|||||||||
Beginning
nonvested grants
|
—
|
$
|
—
|
194,072
|
$
|
34.39
|
||||||
Granted
|
80,515
|
21.53
|
8,000
|
22.85
|
||||||||
Vested
|
—
|
—
|
(117,905
|
)
|
33.75
|
|||||||
Forfeited
|
(2,169
|
)
|
21.53
|
(14,213
|
)
|
34.60
|
||||||
Remaining
nonvested grants
|
78,346
|
$
|
21.53
|
69,954
|
$
|
34.37
|
We
recognized compensation expense of $1.8 million, $3.2 million, and $7.0 million
for the years ended December 31, 2009, 2008, and 2007, respectively, and a
related income tax (expense) benefit of $(0.6) million, $0.2 million and $4.4
million, for the years ended December 31, 2009, 2008, and 2007, respectively. As
of December 31, 2009, we had $1.7 million of unrecognized compensation cost
related to the nonvested portion of outstanding awards, which is reflected as
nonvested stock as a portion of additional paid in capital in our Statement of
Common Shareholders' Equity and Comprehensive Income. The cost is expected to be
recognized over a weighted-average period of 1.1 years. The total fair value of
shares vested was $4.0 million, $4.7 million, and $3.4 million for the years
ended December 31, 2009, 2008 and 2007, respectively.
F-32
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. The DSUs are marked-to-market on a quarterly basis with an adjustment to
director’s compensation expense. Based on the election of the nonemployee
director, following separation from service on the Board, other than on account
of death, he or she shall be paid a distribution either in a lump sum or in
approximately equal installments over a designated number of years (not to
exceed 10 years). During the years ended December 31, 2009, 2008 and 2007, DSUs
issued to members of our Board totaled 42,870, 33,750 and 30,563, respectively.
Total compensation expense attributable to the DSUs during the years ended
December 31, 2009, 2008 and 2007 was approximately $1.1 million, $0.2 million
and $0.7 million, respectively.
(14) Regulatory
Assets and Liabilities
We
prepare our financial statements in accordance with the provisions of ASC 980,
as discussed in Note 2. 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
Reference
|
Remaining
Amortization Period
|
December
31,
|
|||||||||
2009
|
2008
|
||||||||||
Pension
|
12
|
Undetermined
|
$
|
87,934
|
$
|
148,534
|
|||||
Postretirement
benefits
|
12
|
Undetermined
|
6,191
|
25,010
|
|||||||
Competitive
transition charges
|
3
Years
|
12,962
|
18,273
|
||||||||
Environmental
clean-up
|
Various
|
14,631
|
15,904
|
||||||||
Supply
costs
|
1
Year
|
699
|
3,239
|
||||||||
Energy
supply derivatives
|
6
|
1
Year
|
23,812
|
29,156
|
|||||||
Income
taxes
|
9
|
Plant
Lives
|
47,241
|
16,466
|
|||||||
Deferred
financing costs
|
Various
|
8,623
|
5,061
|
||||||||
Other
|
Various
|
20,798
|
18,364
|
||||||||
Total regulatory
assets
|
$
|
222,891
|
$
|
280,007
|
|||||||
Removal
cost
|
4
|
Various
|
$
|
224,632
|
$
|
208,201
|
|||||
Gas
storage sales
|
30
Years
|
12,513
|
12,933
|
||||||||
Supply
costs
|
1
Year
|
18,563
|
31,669
|
||||||||
Energy
supply derivatives
|
1
Year
|
2,044
|
3,785
|
||||||||
Environmental
clean-up
|
1
Year
|
1,041
|
1,411
|
||||||||
State
& local taxes & fees
|
1
Year
|
6,012
|
9,701
|
||||||||
Other
|
Various
|
3,149
|
4,492
|
||||||||
Total regulatory
liabilities
|
$
|
267,954
|
$
|
272,192
|
F-33
Pension
and Postretirement Benefits
We
recognize the unfunded portion of plan benefit obligations in the Consolidated
Balance Sheets, which is remeasured at each year end, with a corresponding
adjustment to regulatory assets/liabilities as the costs associated with these
plans are recovered in rates. The portion of the regulatory asset related to our
Montana pension plan will amortize as cash funding amounts exceed accrual
expense under GAAP. The SDPUC allows recovery of pension costs on an accrual
basis. The MPSC allows recovery of postretirement benefit costs on an accrual
basis. The volatility in plan asset market returns and significant increases in
funding is discussed in Note 12, and is reflected in regulatory assets
above.
Natural
Gas Competitive Transition Charges
Natural
gas transition bonds were issued in 1998 to recover stranded costs of production
assets and related regulatory assets and provide a lower cost to utility
customers, as the cost of debt was less than the cost of capital. The MPSC
authorized the securitization of these assets and approved the recovery of the
competitive transition charges in rates over a 15-year period. The regulatory
asset relating to competitive transition charges amortizes proportionately with
the principal payments on the natural gas transition bonds.
Supply
Costs
The MPSC,
SDPUC and NPSC have authorized the use of electric and natural gas supply cost
trackers, as applicable, which enable us to track actual supply costs and either
recover the under collection or refund the over collection to our customers.
Accordingly, we have recorded a regulatory asset and liability 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; 10.60% and 7.96%,
respectively, in South Dakota; and 8.49% 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 17. Our 2007 natural gas rate case settlement with
the SDPUC allows recovery of manufactured gas plant (MGP) environmental clean-up
costs, which is reflected as a regulatory asset above.
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. These amounts are
amortized over the life of the new debt.
State
& Local Taxes & Fees (Montana Property Tax Tracker)
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. The MPSC has 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.
F-34
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, the
applicable GAAP guidance precludes this treatment. Our depreciation method,
including cost of removal, is established by the respective regulatory
commissions, therefore, consistent with this regulated treatment, we continue to
accrue removal costs for our regulated assets by increasing our regulatory
liability. See Note 4, Asset Retirement Obligations, for further information
regarding this item.
Gas
Storage Sales
A
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.
(15) Regulatory
Matters
Montana
General Rate Case
In
October 2009, we filed a request with the MPSC for an annual electric
transmission and distribution revenue increase of $15.5 million, and an annual
natural gas transmission, storage and distribution revenue increase of
$2.0 million. The request was based on a return on a 2008 test period, a
return on equity of 10.9%, an equity ratio of 49.45% and rate base of
$632.2 million and $256.6 million for electric and natural gas,
respectively.
In
November 2009, the MPSC issued a determination that the rate case filing did not
meet the MPSC’s applicable minimum filing requirements, related to allocated
cost of service and rate design. We submitted a supplemental filing on January
15, 2010 to meet the MPSC’s minimum filing requirements, which was accepted as
compliant on February 2, 2010. We have agreed to extend the timeframe by which
the MPSC must issue a final order concerning the general rate filing by 90 days
to October 11, 2010. We requested interim rate adjustments, which may be
authorized during the processing of the filing if the MPSC finds it meets the
established criteria. Final rate adjustments would become effective upon the
issuance of a final order on this matter.
Montana
Electric and Natural Gas Supply Trackers
Rates for
our Montana electric and natural gas supply are set by the MPSC. Each year we
submit electric and natural gas tracker filings for recovery of supply costs.
The MPSC reviews such filings and makes its cost recovery determination based on
whether or not our electric and natural gas energy supply procurement activities
were prudent. If the MPSC subsequently determines that a procurement activity
was imprudent, then it may disallow such costs.
On May
30, 2008, we filed an annual electric supply cost tracker request with the MPSC
for any unrecovered actual electric supply costs for the 12-month period ended
June 30, 2008 and for the projected electric supply costs for the 12-month
period ended June 30, 2009. On June 27, 2008, the MPSC issued an interim order
approving recovery of our projected electric supply costs. On May 29, 2009, we
filed an annual electric supply cost tracker request with the MPSC for any
unrecovered actual electric supply costs for the 12-month period ended June 30,
2009 and for the projected electric supply costs for the 12-month period ended
June 30, 2010. On June 26, 2009, the MPSC issued an interim order approving
recovery of our projected electric supply costs. Our annual electric supply cost
tracker requests for the 12-month periods ended June 30, 2008 and June 30, 2009
were combined and are still pending final approval of the MPSC. The MCC disputed
(1) our ability to use financial swaps in purchasing electricity supply, (2) the
recovery of certain labor costs associated with real-time schedulers and (3) our
estimated revenues associated with demand side management for our Colstrip Unit
4 generation asset. During the fourth quarter of 2009, we entered
into a settlement with the MCC agreeing to (a) withdraw our request to use
financial swaps, (b) remove approximately $100,000 in labor costs and (c) remove
approximately $83,000 of calculated lost revenues from the tracker. On February
3, 2010, the MPSC conducted a hearing to review the filings and resulting
settlement and scheduled additional briefing for March 2010.
F-35
On June
2, 2009, we filed an annual gas cost tracker request with the MPSC for any
unrecovered actual gas costs for the 12-month period ended June 30, 2009, and
for the projected gas costs for the 12-month period ending June 30, 2010. On
June 24, 2009, the MPSC issued an interim order, approving recovery of our
projected gas costs pending its review. No procedural schedule has been
established for this request.
Montana
Property Tax Tracker
In
December 2009, we filed our annual property tax tracker (including other
state/local taxes and fees) with the MPSC for an automatic rate adjustment,
which reflected 60% of the change in 2009 actual property taxes and estimated
property taxes for 2010. This filing also included an adjustment for property
taxes related to Colstrip Unit 4. In our 2008 filing requesting to include our
interest in Colstrip Unit 4 in utility rate base, we estimated base property
taxes would be approximately $5.5 million, by multiplying the rate base value by
the latest known mill levy. This filing was approved by the MPSC. Actual 2009
Colstrip Unit 4 related property taxes were approximately $2.1 million and we
proposed refunding 60% of the change to customers, consistent with previous MPSC
orders. In January 2010, the MPSC issued an order requiring us to reset the base
rates for Colstrip, effectively requiring us to refund 100% of the change in
property taxes from our original 2008 filing. While we have accounted for our
property tax tracker consistent with the MPSC’s January 2010 order, we are
disputing various aspects of the order and have filed a Motion for
Reconsideration with the MPSC.
Mill
Creek Generating Station
In August
2008, we filed a request with the MPSC for advanced approval to construct a
150 megawatt natural gas fired facility. The Mill Creek Generating Station,
estimated to cost approximately $202 million, will provide regulating resources
to balance our transmission system in Montana to maintain reliability and enable
wind power to be integrated onto the network to meet renewable energy portfolio
needs. In May 2009, the MPSC issued an order granting approval to construct the
facility, authorizing a return on equity of 10.25% and a preliminary cost of
debt of 6.5%, with a capital structure of 50% equity and 50% debt. In addition,
the MPSC determined the $81 million cost for the turbines is prudent, with
the remainder of the project costs to be submitted to the MPSC for review and
approval once construction of the facility is complete. Construction began in
June 2009, and the plant is scheduled to be operational by December 31, 2010. As
of December 31, 2009, we have capitalized approximately $84.7 million in
construction work in progress related to this project.
Western
Electricity Coordination Council Compliance Audit
We
completed our compliance audit for our Montana operations under the compliance
monitoring and enforcement program of the WECC, a regional electric reliability
organization, during 2009. WECC has responsibility for monitoring and enforcing
compliance with the FERC approved mandatory reliability standards within the
western interconnection of the Unites States. In connection with the compliance
audit, WECC found no violations of the applicable standards. Since June 2007, we
have identified and self-reported violations of 32 requirements to WECC. All but
nine of these violations were dismissed or were subject to expedited
dispositions with no penalties. During the fourth quarter of 2009, we reached a
settlement agreement with WECC addressing six of the remaining nine violations
for a total penalty of $80,000, which has been accrued. The settlement is
pending formal NERC and FERC approval. The remaining three violations all relate
to one standard and this standard is pending a NERC interpretation. We also
filed mitigation plans for two potential violations with the MRO for our South
Dakota operations. We have completed the mitigation measures in compliance with
the plans and expect to hear from the MRO during the first half of 2010 of any
further action. We expect our compliance with NERC standards will be audited at
least every three years.
Mountain
States Transmission Intertie (MSTI) and Other Transmission FERC
Developments
In
January 2009, we filed a request with the FERC seeking negotiated rates for the
proposed MSTI project and to directly assign the cost of the Collector Project
to the generators. The request for negotiated rates for MSTI was not for
specific rates; rather, it was for confirmation from the FERC that MSTI would
satisfy the FERC’s negotiated rate criteria. As a transmission export project in
a region that lacks a RTO, MSTI would have no readily available regional tariff
through which to recover costs and thereby mitigate project development risk.
The request was based on a rate approach that FERC had approved for similar
projects in the region, which would provide us with the flexibility to meet
market demand from primarily new renewable generation resources in Montana and
to insulate our native load customers from the costs and risks of the project.
FERC issued an order in May 2009 denying our request for negotiated rates, and
encouraged us to meet our needs by pursuing the MSTI project on a
cost-of-service basis by requesting appropriate waivers under our OATT. As to
the Collector Project, FERC approved our proposal to directly assign the cost of
the project to the generators. This also has the effect of insulating native
load customers from the cost of the project. While FERC deferred ruling on our
request for tariff waivers, FERC specifically found the proposed Collector
Project open season process to be a reasonable means of accommodating a large
number of interconnection requests in the queue.
F-36
We have
capitalized approximately $11.4 million of preliminary survey and investigative
costs associated with proposed transmission projects.
Colstrip
Unit 4
In
January 2009, as a result of approval by the MPSC, we placed our joint ownership
interest in Colstrip Unit 4, which had previously been an unregulated asset,
into utility rate base at a value of $407 million. The assets are reflected in
the Consolidated Balance Sheets at historical cost. The order included a capital
structure of 50% equity and 50% debt, an authorized return on equity of 10% and
cost of debt of 6.5%, which are set for 34 years, based on the estimated useful
life of the plant. Our interest in Colstrip Unit 4 is expected to supply
approximately 13% of our Montana base-load requirements through 2010 and
approximately 25% thereafter (upon expiration of an existing power sale
agreement). The generation related costs and return on rate base related to
Colstrip Unit 4, including the cost of any replacement power purchased during
outages, will be included in our annual electric supply tracker filing for
inclusion in customer rates.
(16) Earnings
Per Share
Basic
earnings per share are computed by dividing earnings applicable to common stock
by the weighted average number of common shares outstanding for the period.
Diluted earnings per share reflect 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 stock and
performance share awards. Average shares used in computing the basic and diluted
earnings per share are as follows:
December
31,
|
||||
2009
|
2008
|
|||
Basic
computation
|
36,091,362
|
37,975,554
|
||
Dilutive
effect of
|
||||
Restricted
stock and performance share awards (1)
|
212,980
|
302,124
|
||
Diluted
computation
|
36,304,342
|
38,277,678
|
(1) Performance
share awards are included in diluted weighted average number of shares
outstanding based upon what would be issued if the end of the most recent
reporting period was the end of the term of the award.
(17) 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
$167 per MWH through 2029. Our estimated gross contractual obligation related to
the QFs is approximately $1.4 billion through 2029. A portion of the costs
incurred to purchase this energy is recoverable through rates, totaling
approximately $1.1 billion through 2029. The fair value of the remaining QF
liability is recorded in our Consolidated Balance Sheets. The following
summarizes the change in the QF liability (in thousands):
F-37
December
31,
|
|||||||
2009
|
2008
|
||||||
Beginning
QF liability
|
$
|
162,841
|
$
|
158,132
|
|||
Unrecovered
amount
|
(9,366
|
)
|
(7,246
|
)
|
|||
Interest
expense
|
12,364
|
11,955
|
|||||
Ending
QF liability
|
$
|
165,839
|
$
|
162,841
|
The
following summarizes the estimated gross contractual obligation less amounts
recoverable through rates (in thousands):
Gross
Obligation
|
Recoverable
Amounts
|
Net
|
|||||||
2010
|
$
|
63,589
|
$
|
53,835
|
$
|
9,754
|
|||
2011
|
65,323
|
54,357
|
10,966
|
||||||
2012
|
67,111
|
54,904
|
12,207
|
||||||
2013
|
69,816
|
55,462
|
14,354
|
||||||
2014
|
72,354
|
56,025
|
16,329
|
||||||
Thereafter
|
1,059,402
|
797,190
|
262,212
|
||||||
Total
|
$
|
1,397,595
|
$
|
1,071,773
|
$
|
325,822
|
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 20 years. Costs incurred under these contracts were approximately $434.5
million, $564.0 million and $445.0 million for the years ended December 31,
2009, 2008, and 2007, respectively. As of December 31, 2009 our commitments
under these contracts are $363.0 million in 2010, $192.0 million in 2011, $174.5
million in 2012, $162.0 million in 2013, $120.3 million in 2014, and $659.4
million thereafter. These commitments are not reflected in our Consolidated
Financial Statements.
Other
Purchase Obligations
We have
entered into purchase obligations related to the construction of the Mill Creek
Generating Station, which primarily include engineering, procurement and
construction (EPC) and gas turbine generators. Total payments under these
contracts were $67.9 million during 2009. Our estimated future obligation under
these contracts is $70.8 million for 2010.
Environmental
Liabilities
Our
liability for environmental remediation obligations is estimated to range
between $22.4 million to $44.1 million. As of December 31, 2009, we have a
reserve of approximately $31.9 million, which has not been discounted.
Environmental costs are recorded when it is probable we are liable for the
remediation and we can reasonably estimate the liability. Over time, as specific
laws are implemented and we gain experience in operating under them, a portion
of the costs related to such laws will become determinable, and we may seek
authorization to recover such costs in rates or seek insurance reimbursement as
applicable; therefore, we do not expect these costs to have a material adverse
effect on our consolidated financial position or ongoing
operations.
Manufactured Gas
Plants - Approximately $26.6 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 $13.0 million, and we estimate that approximately $10
million of this amount will be incurred during the next five years.
F-38
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 conducted limited additional site investigation,
assessment and monitoring work at Kearney and Grand Island. 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 excess
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 conditions 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 is ongoing and 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 or if any
additional actions beyond monitored natural attenuation will be
required.
Milltown Dam
Removal - Our subsidiary, Clark Fork and Blackfoot, LLC (CFB), owns the
former Milltown Dam site, and previously operated a three MW hydroelectric
generation facility located at the confluence of the Clark Fork and Blackfoot
Rivers. Dam removal activities were completed in 2009. Our remaining obligation
to the State of Montana related to this site is approximately $0.6 million,
which will be solely funded through the transfer of land and water rights
associated with the former Milltown Dam operations to the State of
Montana.
Global Climate
Change - We have
a joint 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. In addition, a significant portion of the electric supply we procure
in the market is generated by coal-fired plants.
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. Specifically, coal-fired plants have come under scrutiny
due to their emissions of carbon dioxide.
Clean Air
Act - The Clean Air Act Amendments of 1990 and subsequent amendments stipulate
limitations on sulfur dioxide and nitrogen oxide emissions from coal-fired power
plants and motor vehicles. We comply with 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.
In June
2008, the Sierra Club filed a lawsuit in U.S. District Court in South Dakota
against NorthWestern and the other joint owners of the Big Stone plant alleging
certain violations of the Clean Air Act. For further discussion see the Legal
Proceedings – Sierra Club section below.
Clean Air
Mercury Rule – In
March 2005, the EPA issued the Clean Air Mercury Regulations (CAMR) to reduce
the emissions of mercury from coal-fired facilities through a market-based
cap-and-trade program. Although the U.S. Court of Appeals for the District of
Columbia Circuit struck down CAMR, the state of Montana has finalized its own
rules more stringent than CAMR's 2018 cap that require every coal-fired
generating plant in the state to achieve reduction levels by 2010. Chemical
injection technologies were installed at Colstrip Unit 4 during the fourth
quarter of 2009 to meet these requirements, and our share of the capital cost
was approximately $1.0 million, with ongoing annual operating costs
estimated to be approximately $1.5 million. If the enhanced chemical injection
technologies are not sufficient to meet the required levels of reduction, then
adsorption/absorption technology with fabric filters would be required, which
could represent a material cost. We are continuing to work with the other
Colstrip owners to assess compliance with these reduction levels.
F-39
There is
a gap between proposed emissions reduction levels and the current capabilities
of technology, as there is no currently available commercial scale technology
that would achieve the proposed reduction levels. Such technology may not be
available within a timeframe consistent with the implementation of climate
change legislation or at all. To the extent that such technology does become
available, we can provide no assurance that it will be suitable or
cost-effective for installation at the generation facilities in which we have a
joint interest. We believe future legislation and regulations that affect carbon
dioxide emissions from power plants are likely, although technology to
efficiently capture, remove and sequester carbon dioxide emissions is not
presently available on a commercial scale.
The
proposed regulations and/or current litigation related to global climate change
could have a material impact on our future capital expenditures and results of
operations, but the costs are not determinable at this time. Our current capital
expenditures projections do not include significant amounts related to
environmental projects. We believe the cost of purchasing carbon emissions
credits, or alternatively the proceeds from the sale of any excess carbon
emissions credits would be included in customer rates.
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.
|
Legal
Proceedings
Colstrip
Energy Limited Partnership
In
December 2006 and June 2007, the MPSC issued orders relating to certain QF rates
for the period July 1, 2003 through June 30, 2006. Colstrip Energy Limited
Partnership (CELP) is a QF with which we have a power purchase agreement through
June 2024. Under the terms of the power purchase agreement with CELP, energy and
capacity rates were fixed through June 30, 2004 (with a small portion to be set
by the MPSC's determination of rates in the annual avoided cost filing), 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, with the rates to be
used in that formula derived from the annual MPSC QF rate review. CELP initially
appealed the MPSC’s orders and then, in July 2007, filed a complaint against
NorthWestern and the MPSC in Montana district court, which contested the MPSC’s
orders. CELP disputed inputs into the underlying rates used in the formula,
which initially are calculated by us and reviewed by the MPSC on an annual
basis, to calculate energy and capacity payments for the contract years
2004-2005 and 2005-2006. CELP claimed that NorthWestern breached the power
purchase agreement causing damages, which CELP asserted to be approximately $23
million for contract years 2004-2005 and 2005-2006. The parties stipulated that
NorthWestern would not implement the final derived rates resulting from the MPSC
orders, pending an ultimate decision on CELP's complaint. The Montana district
court, on June 30, 2008, granted both a motion by the MPSC to bifurcate, having
the effect of separating the issues between contract/tort claims against us and
the administrative appeal of the MPSC’s orders and a motion by us to refer the
claims against us to arbitration. The order also stayed the appellate decision
pending a decision in the arbitration proceedings. Arbitration was held in June
2009 and the arbitration panel entered its interim award in August 2009, holding
that although NorthWestern failed to use certain data inputs required by the
power purchase agreement, CELP was entitled to neither damages for contract
years 2004-2005 or 2005-2006, nor to recalculation of the underlying MPSC
filings for those years, effectively finalizing CELP's contract rates for those
years. We requested clarification from the arbitration panel as to its intent
regarding the applicable rates. On November 2, 2009, we received the final award
from the arbitration panel which confirmed that the
filed rates for 2004-2005 and 2005-2006 are not required to be recalculated. In
affirming its interim award, the arbitration panel also denied CELP’s request
for attorney fees, holding that each party would be responsible for its own
fees. The final arbitration panel award is still pending confirmation by the
Montana district court. Once confirmed, the arbitration award will require us to
refile with the MPSC for a new determination of rates subsequent to June 30,
2006 using data inputs required by the purchase power agreement. Based on the
initial MPSC order and subsequent arbitration award, we had estimated that if
upheld, the reduction to our QF liability would be approximately $20 to $30
million due to the estimated reduction of energy and capacity rates for the
remainder of the contract period. CELP continues to dispute the results of the
arbitration award, and due to the uncertainty around the resolution we are
currently unable to predict the outcome of this matter.
F-40
Gonzales
We are a
defendant – along with our predecessor entities the Montana Power Company (MPC)
and pre-bankruptcy NorthWestern Corporation (NOR) – in an action (Gonzales
Action) pending in the Montana Second Judicial District Court, Butte-Silver Bow
County (Montana State Court), alleging fraud, constructive fraud and violations
of the Unfair Claim Settlement Practices Act all arising out of the adjustment
of workers’ compensation claims. Putnam and Associates, the third party
administrator of such workers’ compensation claims, also is a
defendant.
The
Gonzales Action was first filed on December 18, 1999, against MPC (NOR acquired
MPC in 2002) and was stayed due to the chapter 11 bankruptcy filing of NOR. On
August 10, 2005, the Bankruptcy Court approved a “Bankruptcy Settlement
Stipulation” which permitted the Gonzales Action to proceed, assigned to
plaintiffs NOR’s interest in MPC’s insurance policies (to the extent applicable
to the allegations made by plaintiffs), released NOR from any and all
obligations to the plaintiffs concerning such claims, and preserved plaintiffs’
right to pursue claims arising after November 1, 2004, relating to the
adjustment of workers’ compensation claims. To date, no insurance carrier has
indicated that coverage is available for any of the claims.
On
September 30, 2009 the Montana State Court granted the plaintiffs’ motions to
file a sixth amended complaint and partially granted the plaintiff’s motion for
class certification. The Montana State Court excluded the fraud claims from its
class certification. The new complaint seeks to hold us jointly and severally
liable for the acts of MPC and NOR and alleges that we negligently/intentionally
sabotaged plaintiffs’ ability to recover under the MPC insurance policies.
Plaintiffs seek compensatory and punitive damages from all defendants. Due to
the individual nature of the claims, we believe the class certification was
improper under Montana law, and we continue to believe that the new complaint
violates the bankruptcy stipulation. We have filed an appeal to the Supreme
Court of the State of Montana with respect to these issues and intend to
continue to defend the lawsuit vigorously. We also believe the sixth amended
complaint violates the Bankruptcy Settlement Stipulation and have filed a motion
with the Bankruptcy Court seeking enforcement of the Bankruptcy Settlement
Stipulation. The motion before the Bankruptcy Court is pending. In addition,
settlement discussions concerning these claims are ongoing.
Maryland
Street
On March
16, 2009, Monsignor John F. McCarthy, as the duly appointed personal
representative for the estate of Father James C. McCarthy, filed a complaint in
the Montana Second Judicial District Court, Butte-Silver Bow County against us,
one of our employees and other unknown individuals and entities. The complaint
arises out of an April 2007 natural gas explosion and alleges negligence and
strict liability with respect to the maintenance and operation of the natural
gas distribution system that served Fr. McCarthy’s residence. The explosion
destroyed a four-plex residence and nearby properties sustained damages.
Fr. McCarthy died in November 2007. The plaintiff seeks unspecified
compensatory and punitive damages and other equitable relief, costs and
attorney’s fees. The investigation of this incident is ongoing, and while we
cannot predict an outcome, we intend to vigorously defend against this
complaint. We filed a notice of removal to remove the case from Montana state
court to the Butte Division of the U.S. District Court for the District of
Montana (Montana Federal District Court), but the Montana Federal District Court
remanded the case to the Montana state court. Subsequently, we filed a motion in
the Montana state court seeking to dismiss the amended complaint as to our
employee. On November 9, 2009, the Montana Second Judicial District Court,
Silver Bow County, filed its order denying our employee’s motion to
dismiss.
F-41
Bozeman
Explosion
On March
5, 2009, a natural gas explosion occurred in downtown Bozeman, Montana. The
explosion resulted in one fatality, the destruction of or damage to several
buildings and the businesses in them, as well as damage to other nearby
properties and businesses. 11 lawsuits against NorthWestern have been filed to
date in Montana state court and a number of claims have been made with respect
to this incident. Our total available insurance coverage is approximately $150
million for known and potential claims. We have paid our deductible under these
policies and our insurance carrier has assumed the defense and handling of the
existing and anticipated future lawsuits and claims.
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. 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 of reorganization, 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 May 2005, the Bankruptcy Court found that it did not have
jurisdiction over these contracts, dismissed our action against these former
employees, and transferred our motion to terminate the contracts to Montana
state court, thereby removing any claim from consideration in the resolution of
our bankruptcy case. 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. 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 appealed
the March 5, 2007, judgment to the Montana Supreme Court. On October 13,
2009 the Montana Supreme Court issued a decision affirming the jury verdict and
the various rulings of the Montana state court before, during and after trial,
and remanded the judgment to the Montana state court so that it could be reduced
to reflect the payments made to the plaintiffs since the judgment was entered.
During December 2009, the parties settled this litigation and we paid $26.7
million (including accrued interest) to the plaintiffs.
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. (Touch America) as a result of a corporate reorganization of
The Montana Power Company), contends that the disposition of various generating
and energy-related assets by The Montana Power Company are 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 Company L.L.C. (now CFB), which plaintiffs claim is a successor to
the Montana Power Company.
We were
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. We were dismissed from this
lawsuit by the U.S. District Court in Montana in February 2009.
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. This agreement was approved by the Bankruptcy Court in
November 2006; however on January 11, 2008, the U.S. District Court in Montana
suggested that the settlement agreement was invalid and enjoined the plaintiffs
from taking any further action in any of these matters. The plaintiffs appealed
the District Court’s injunction to the Ninth Circuit U.S. Court of Appeals,
where a determination is pending. In January 2009, the U.S. District Court in
Montana asked all parties to submit memorandum discussing the party’s
willingness to enter into a global settlement of the matter.
F-42
In
October 2009, the parties to the various lawsuits reached a global settlement
involving various agreements, which must be approved by the U.S. District Court
in Montana and the Delaware Bankruptcy Court. In November 2009, the parties
submitted documentation concerning the settlement to the U.S. District Court in
Montana for its approval. Approval of the settlement by the U.S. District Court
in Montana is still pending. A fairness hearing concerning the proposed
settlement is scheduled for May 2010. If the court approves the settlement, we
will receive approximately $2.0 million from the Touch America bankruptcy estate
and have no remaining liability in the litigation.
Sierra
Club
On June
10, 2008, Sierra Club filed a complaint in the U.S. District Court for the
District of South Dakota (Northern Division) (South Dakota Federal District
Court) against us and two other co-owners (the Defendants) of Big Stone
Generating Station (Big Stone). The complaint alleged certain violations of the
(i) Prevention of Significant Deterioration and (ii) New Source Performance
Standards (NSPS) provisions of the Clean Air Act and certain violations of the
South Dakota State Implementation Plan (South Dakota SIP). The action further
alleged that the Defendants modified and operated Big Stone without obtaining
the appropriate permits, without meeting certain emissions limits and NSPS
requirements and without installing appropriate emission control technology, all
allegedly in violation of the Clean Air Act and the South Dakota SIP. Sierra
Club alleged that Defendants’ actions have contributed to air pollution and
visibility impairment and have increased the risk of adverse health effects and
environmental damage. Sierra Club sought both declaratory and injunctive relief
to bring the Defendants into compliance with the Clean Air Act and the South
Dakota SIP and to require Defendants to remedy the alleged violations. Sierra
Club also sought unspecified civil penalties, including a beneficial mitigation
project. We believe these claims are without merit and that Big Stone was and is
being operated in compliance with the Clean Air Act and the South Dakota
SIP.
The
Defendants filed a Motion to Dismiss the Sierra Club complaint on August 12,
2008, based on certain of the claims being barred by statute of limitations and
the remaining claims being an impermissible collateral attack on valid Clean Air
Permits issued by the state of South Dakota. On September 22, 2008, the Sierra
Club filed its response. Additionally on September 22, 2008, the Sierra Club
sent a Notice of Intent to Sue for additional violations of the Clean Air Act at
Big Stone, which are similar in nature and seek the same remedies as the June
2008 complaint. On March 31, 2009, the South Dakota Federal District Court
entered a Memorandum Opinion and Order granting Defendants’ Motion to Dismiss
the Sierra Club Complaint. Sierra Club filed a motion for reconsideration of the
dismissal, which was denied in July 2009. On July 30, 2009, Sierra Club appealed
the South Dakota Federal District Court’s decision to dismiss the complaint. The
briefing schedule initially adopted by the Eighth Circuit Court of Appeals
called for the appellant to submit its brief by mid-October, for appellees to
submit their brief by mid-November and for appellant to submit its reply brief
by the end of November. On October 13, 2009, the United States Department of
Justice (USDOJ) filed a motion seeking a 30-day extension of the time to file an
amicus brief in support of the Sierra Club’s position. The Court of Appeals
granted this motion, as well as our subsequent joint motion with the Sierra
Club, extending the time to file our principal brief and the Sierra Club’s reply
brief and a later joint motion with the USDOJ further extending the time for it
to file an amicus brief. In accordance with the revised briefing schedule, the
Sierra Club filed its brief on October 14, 2009, and we filed our brief on
December 24, 2009 (the state of South Dakota served an amicus brief in support
of our position on December 30, 2009).
REC
Silicon
REC
Advanced Silicon Materials LLC (REC) is a large transmission customer which
manufactures polysilicon and silane gas for the photovoltaic and electronics
industries. REC purchases services from us pursuant to our OATT. REC brought an
action against us in June 2009, in the Montana Second Judicial District Court,
Silver Bow County, which alleges breach of contract and negligence. REC claims
we failed to properly maintain a substation, which resulted in an outage for
approximately three hours and disrupted REC’s production operations for several
days. REC has reduced its alleged damage claims to approximately $760,000 from
initial allegations of $1.25 million. We do not believe the ultimate
outcome of this matter will have a material effect on our financial position,
results of operations or cash flows.
F-43
Bankruptcy
Related Litigation
Disputed Claims Reserve - In
July 2008, we obtained Bankruptcy Court approval for the purchase of the
remaining shares in the disputed claims reserve established by our plan of
reorganization that was confirmed by the Bankruptcy Court in 2004. The motion
allowed unsecured creditors and debt holders in Class 7 and Class 9 to elect to
receive their surplus distribution in stock or cash. We repurchased 1.1 million
shares from the disputed claims reserve for those claimants who elected a cash
payment. In October 2008, we filed a motion requesting the Bankruptcy Court to
determine the disputed claims reserve is taxable as a grantor trust. The IRS
filed an objection to the motion; however we reached an agreement with the IRS
and the committee of creditors to settle this matter. In September 2009, the
Bankruptcy Court approved the settlement agreement and authorized a final
distribution from the disputed claims reserve. This settlement did not have a
material impact on our financial position, results of operations or cash flows.
On October 30, 2009, we distributed the remaining cash and shares in the
disputed claims reserve to eligible claimants.
Blue Dot Bankruptcy - During
the second quarter of 2008, our subsidiary Blue Dot Services, LLC (Blue Dot)
lost an arbitration matter with an insurance carrier and the insurance carrier
was awarded $3.5 million plus interest related to a dispute that originated in
2007. The award was partially satisfied by $2.5 million in letter of credit
draws by the insurance carrier and approximately $300,000 in cash. On September
5, 2008, Blue Dot and its subsidiaries filed a petition for protection under
Chapter 7 of the Bankruptcy Code in United States Bankruptcy Court for the
District of Delaware. We classified Blue Dot as a discontinued operation in
2003. We do not anticipate Blue Dot’s ultimate liquidation will have a material
adverse effect on our financial position, results of operations or cash
flows.
We are
also subject to various other legal proceedings, governmental audits and claims
that arise in the ordinary course of business. In the opinion of management, the
amount of ultimate liability with respect to these other actions will not
materially affect our financial position, results of operations, or cash
flows.
(18) Common
Stock
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. Of these shares, 2,265,957 shares of common stock are reserved for the
incentive plan awards. For further detail of grants under this plan see Note
13.
Repurchase
of Common Stock
On May
23, 2008, we announced plans to initiate a share buyback program for
approximately 3.1 million shares, which is equal to the number of shares in the
disputed claims reserve established under our Plan of Reorganization that was
confirmed by the bankruptcy court in 2004. We purchased 1.9 million shares from
the disputed claims reserve and the remaining shares were purchased using
privately negotiated transactions, at our discretion. The actual number and
timing of share purchases were subject to market conditions, restrictions
related to price, volume, timing, and applicable SEC rules. The total aggregate
purchase price was approximately $77.7 million.
Shares
tendered by employees to us to satisfy the employees' tax withholding
obligations in connection with the vesting of restricted stock awards totaled
30,684 and 41,289 during the years ended December 31, 2009 and 2008,
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-44
(19) Segment
and Related Information
Our
reportable business segments are primarily engaged in the regulated electric and
regulated natural gas business. The remainder of our operations is presented as
other. While it is not considered a business unit, other primarily consists of
our remaining unregulated natural gas capacity contract, the wind down of our
captive insurance subsidiary and our unallocated corporate costs. As discussed
in Note 15, the operations of our joint ownership interest in Colstrip
Unit 4 were unregulated through December 31, 2008, and are included in
regulated operations beginning January 1, 2009, due to an MPSC order. We have
not revised the 2008 segment presentation due to the nature of the transfer of
the asset from unregulated to the regulated business.
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
|
||||||||||||||||
December
31, 2009
|
Electric
|
Gas
|
Other
|
Eliminations
|
Total
|
|||||||||||
Operating
revenues
|
$
|
782,318
|
$
|
354,470
|
$
|
6,747
|
$
|
(1,625
|
)
|
$
|
1,141,910
|
|||||
Cost
of sales
|
356,722
|
210,016
|
6,948
|
—
|
573,686
|
|||||||||||
Gross
margin
|
425,596
|
144,454
|
(201
|
)
|
(1,625
|
)
|
568,224
|
|||||||||
Operating,
general and administrative
|
170,656
|
76,730
|
(143
|
)
|
(1,625
|
)
|
245,618
|
|||||||||
Property
and other taxes
|
58,488
|
20,953
|
141
|
—
|
79,582
|
|||||||||||
Depreciation
|
71,968
|
17,038
|
33
|
—
|
89,039
|
|||||||||||
Operating
income (loss)
|
124,484
|
29,733
|
(232
|
)
|
—
|
153,985
|
||||||||||
Interest
expense
|
(51,193
|
)
|
(12,858
|
)
|
(3,709
|
)
|
—
|
(67,760
|
)
|
|||||||
Other
income
|
2,125
|
261
|
113
|
—
|
2,499
|
|||||||||||
Income
tax (expense) benefit
|
(13,493
|
)
|
(2,457
|
)
|
646
|
—
|
(15,304
|
)
|
||||||||
Net
income (loss)
|
$
|
61,923
|
$
|
14,679
|
$
|
(3,182
|
)
|
$
|
—
|
$
|
73,420
|
|||||
Total
assets
|
$
|
1,960,488
|
$
|
819,495
|
$
|
15,149
|
$
|
—
|
$
|
2,795,132
|
||||||
Capital
expenditures
|
$
|
167,303
|
$
|
22,057
|
$
|
—
|
$
|
—
|
$
|
189,360
|
Regulated
|
Unregulated
|
||||||||||||||||||
December
31, 2008
|
Electric
|
Gas
|
Electric
|
Other
|
Eliminations
|
Total
|
|||||||||||||
Operating
revenues
|
$
|
774,229
|
$
|
416,675
|
$
|
77,680
|
$
|
30,039
|
$
|
(37,830
|
)
|
$
|
1,260,793
|
||||||
Cost
of sales
|
410,471
|
271,690
|
23,463
|
29,141
|
(36,025
|
)
|
698,740
|
||||||||||||
Gross
margin
|
363,758
|
144,985
|
54,217
|
898
|
(1,805
|
)
|
562,053
|
||||||||||||
Operating, general and
administrative
|
149,913
|
68,912
|
15,928
|
(6,784
|
)
|
(1,805
|
)
|
226,164
|
|||||||||||
Property
and other taxes
|
56,310
|
21,381
|
2,898
|
13
|
—
|
80,602
|
|||||||||||||
Depreciation
|
61,734
|
15,980
|
7,324
|
33
|
—
|
85,071
|
|||||||||||||
Operating
income
|
95,801
|
38,712
|
28,067
|
7,636
|
—
|
170,216
|
|||||||||||||
Interest
expense
|
(36,757
|
)
|
(12,637
|
)
|
(10,911
|
)
|
(3,647
|
)
|
—
|
(63,952
|
)
|
||||||||
Other
income
|
547
|
1,001
|
154
|
(144
|
)
|
—
|
1,558
|
||||||||||||
Income
tax expense
|
(20,219
|
)
|
(10,027
|
)
|
(6,971
|
)
|
(3,004
|
)
|
—
|
(40,221
|
)
|
||||||||
Net
income
|
$
|
39,372
|
$
|
17,049
|
$
|
10,339
|
$
|
841
|
$
|
—
|
$
|
67,601
|
|||||||
Total
assets
|
$
|
1,669,350
|
$
|
824,031
|
$
|
256,507
|
$
|
12,149
|
$
|
—
|
$
|
2,762,037
|
|||||||
Capital
expenditures
|
$
|
87,198
|
$
|
34,149
|
$
|
3,216
|
$
|
—
|
$
|
—
|
$
|
124,563
|
F-45
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
|
)
|
|||||||||
Net
income (loss)
|
$
|
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
|
F-46
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:
2009
|
First
|
Second
|
Third
|
Fourth
|
||||||||
Operating
revenues
|
$
|
370,903
|
$
|
235,713
|
$
|
232,886
|
$
|
302,408
|
||||
Operating
income
|
50,463
|
27,469
|
26,967
|
49,086
|
||||||||
Net
income
|
$
|
22,813
|
$
|
6,098
|
$
|
18,900
|
$
|
25,609
|
||||
Average
common shares outstanding
|
35,934
|
35,940
|
35,968
|
36,142
|
||||||||
Income
per average common share (basic):
|
||||||||||||
Net
income
|
$
|
0.63
|
$
|
0.17
|
$
|
0.53
|
$
|
0.70
|
||||
Income
per average common share (diluted):
|
||||||||||||
Net
income
|
$
|
0.63
|
$
|
0.17
|
$
|
0.52
|
$
|
0.70
|
||||
Dividends
per share
|
$
|
0.335
|
$
|
0.335
|
$
|
0.335
|
$
|
0.335
|
||||
Stock
price:
|
||||||||||||
High
|
$
|
25.39
|
$
|
23.49
|
$
|
24.94
|
$
|
26.85
|
||||
Low
|
18.48
|
20.00
|
22.58
|
23.61
|
||||||||
Quarter-end
close
|
21.48
|
22.76
|
24.43
|
26.02
|
2008
|
First
|
Second
|
Third
|
Fourth
|
||||||||
Operating
revenues
|
$
|
385,975
|
$
|
276,506
|
$
|
272,244
|
$
|
326,068
|
||||
Operating
income
|
52,090
|
31,520
|
35,320
|
51,286
|
||||||||
Net
income
|
$
|
23,451
|
$
|
9,503
|
$
|
13,379
|
$
|
21,268
|
||||
Average
common shares outstanding
|
38,972
|
38,973
|
38,057
|
35,921
|
||||||||
Income
per average common share (basic):
|
||||||||||||
Net
income
|
$
|
0.60
|
$
|
0.24
|
$
|
0.35
|
$
|
0.59
|
||||
Income
per average common share (diluted):
|
||||||||||||
Net
income
|
$
|
0.59
|
$
|
0.24
|
$
|
0.35
|
$
|
0.59
|
||||
Dividends
per share
|
$
|
0.33
|
$
|
0.33
|
$
|
0.33
|
$
|
0.33
|
||||
Stock
price:
|
||||||||||||
High
|
$
|
29.32
|
$
|
26.72
|
$
|
26.30
|
$
|
25.49
|
||||
Low
|
24.22
|
23.78
|
23.74
|
17.24
|
||||||||
Quarter-end
close
|
24.37
|
25.42
|
25.13
|
23.47
|
F-47
NORTHWESTERN
CORPORATION AND SUBSIDIARIES
Column A
|
Column B
|
Column C
|
Column D
|
Column E
|
|||||||||
Balance at
Beginning
of Period
|
Charged to
Costs and
Expenses
|
Deductions
|
Balance End
of Period
|
||||||||||
Description
|
(in
thousands)
|
||||||||||||
FOR
THE YEAR ENDED DECEMBER 31, 2009
|
|||||||||||||
RESERVES
DEDUCTED FROM
APPLICABLE
ASSETS
|
|||||||||||||
Uncollectible
accounts
|
$
|
2,978
|
$
|
2,604
|
$
|
(2,781
|
)
|
$
|
2,801
|
||||
FOR
THE YEAR ENDED DECEMBER 31, 2008
|
|||||||||||||
RESERVES
DEDUCTED FROM
APPLICABLE
ASSETS
|
|||||||||||||
Uncollectible
accounts
|
3,166
|
3,453
|
(3,641
|
)
|
2,978
|
||||||||
FOR
THE YEAR ENDED DECEMBER 31, 2007
|
|||||||||||||
RESERVES
DEDUCTED FROM
APPLICABLE
ASSETS
|
|||||||||||||
Uncollectible
accounts
|
3,240
|
2,705
|
(2,779
|
)
|
3,166
|
F-48