Item
7.
|
Management's
Discussion and Analysis of Financial Condition and Results of
Operations
|
Overview
The
Company’s strategy is to apply its expertise in energy and transportation
infrastructure industries to increase market share, increase profitability and
enhance shareholder value through:
·
|
Organic
growth as well as a continued disciplined approach to the acquisition of
well-managed companies and
properties
|
·
|
The
elimination of system-wide cost redundancies through increased focus on
integration of operations and standardization and consolidation of various
support services and functions across companies within the
organization
|
·
|
The
development of projects that are accretive to earnings per share and
return on invested capital
|
The
Company has capabilities to fund its growth and operations through various
sources, including internally generated funds, commercial paper facilities and
the issuance from time to time of debt and equity securities. Due to recent
economic volatility, the Company in 2009 increased its focus on the use of
operating cash flows to substantially fund capital expenditures. In the event
that access to the commercial paper markets were to become unavailable, the
Company may need to borrow under its credit agreements. For more information on
the Company’s net capital expenditures, see Liquidity and Capital
Commitments.
The key
strategies for each of the Company’s business segments and certain related
business challenges are summarized below. For a summary of the Company's
business segments, see Item 8 – Note 15.
Key
Strategies and Challenges
Electric
and Natural Gas Distribution
Strategy Provide
competitively priced energy to customers while working with them to ensure
efficient usage. Both the electric and natural gas distribution segments
continually seek opportunities for growth and expansion of their customer base
through extensions of existing operations, including electric generation and
transmission build-out, and through selected acquisitions of companies and
properties at prices that will provide stable cash flows and an opportunity for
the Company to earn a competitive return on investment.
Challenges Both segments
are subject to extensive regulation in the state jurisdictions where they
conduct operations with respect to costs and permitted returns on investment as
well as subject to certain operational regulations at the federal level. The
ability of these segments to grow through acquisitions is subject to significant
competition from other energy providers. In addition, the ability of both
segments to grow service territory and customer base is affected by the economic
environment of the markets served and competition from other energy providers
and fuels. The construction of electric generating facilities and transmission
lines may be subject to increasing cost and lead time, extensive permitting
procedures, and federal and state legislative and regulatory initiatives, which
may necessitate increases in electric energy prices. Legislative and regulatory
initiatives to increase renewable energy resources and reduce GHG emissions
could increase the price and decrease the retail demand for electricity and
natural gas.
Construction
Services
Strategy Provide a
competitive return on investment while operating in a competitive industry by:
building new and strengthening existing customer relationships; effectively
controlling costs; retaining, developing and recruiting talented employees;
focusing business development efforts on project areas that will permit higher
margins; and properly managing risk. This segment continuously seeks
opportunities to expand through strategic acquisitions.
Challenges This segment
operates in highly competitive markets with many jobs subject to competitive
bidding. Maintenance of effective operational and cost controls, retention of
key personnel, managing through downturns in the economy and effective
management of working capital are ongoing challenges.
Pipeline
and Energy Services
Strategy Utilize the
segment’s existing expertise in energy infrastructure and related services to
increase market share and profitability through optimization of existing
operations, internal growth, and acquisitions of energy-related assets and
companies. Incremental and new growth opportunities include: access to new
sources of natural gas for storage, gathering and transportation services;
expansion of existing gathering, transmission and storage facilities; expansion
of related energy services; and incremental expansion of pipeline capacity to
allow customers access to more liquid and higher-priced markets.
Challenges Challenges for this
segment include: energy price volatility; natural gas basis differentials;
regulatory requirements; recruitment and retention of a skilled workforce; and
competition from other natural gas pipeline and gathering
companies.
Natural
Gas and Oil Production
Strategy Apply technology
and utilize existing exploration and production expertise, with a focus on
operated properties, to increase production and reserves from existing
leaseholds, and to seek additional reserves and production opportunities in new
areas to further expand the segment’s asset base. By optimizing existing
operations and taking advantage of new and incremental growth opportunities,
this segment’s goal is to increase both production and reserves over the long
term so as to generate competitive returns on investment.
Challenges Volatility in
natural gas and oil prices; ongoing environmental litigation and administrative
proceedings; timely receipt of necessary permits and approvals; recruitment and
retention of a skilled workforce; availability of drilling rigs, materials,
auxiliary equipment and industry-related field services, and inflationary
pressure on development and operating costs, all primarily in a higher price
environment; and competition from other natural gas and oil companies are
ongoing challenges for this segment.
Construction
Materials and Contracting
Strategy Focus on
high-growth strategic markets located near major transportation corridors and
desirable mid-sized metropolitan areas; strengthen long-term, strategic
aggregate reserve position through purchase and/or lease opportunities; enhance
profitability through cost containment, margin discipline and vertical
integration of the segment’s operations; and continue growth through organic and
acquisition opportunities. Ongoing efforts to increase margin are being pursued
through the implementation of a variety of continuous improvement programs,
including corporate purchasing of equipment, parts and commodities (liquid
asphalt, diesel fuel, cement and other materials), and negotiation of contract
price escalation provisions. Vertical integration allows the segment to manage
operations from aggregate mining to final lay-down of concrete
and
asphalt,
with control of and access to adequate quantities of permitted aggregate
reserves being significant. A key element of the Company’s long-term strategy
for this business is to further expand its presence, through acquisition, in the
higher-margin materials business (rock, sand, gravel, liquid asphalt,
ready-mixed concrete and related products), complementing and expanding on the
Company’s expertise.
Challenges The economic
downturn has adversely impacted operations, particularly in the private market.
This business unit expects to continue cost containment efforts and a greater
emphasis on industrial, energy and public works projects. Significant volatility
in the cost of raw materials such as diesel, gasoline, liquid asphalt, cement
and steel continue to be a concern. Increased competition in certain
construction markets has also lowered margins.
For
further information on the risks and challenges the Company faces as it pursues
its growth strategies and other factors that should be considered for a better
understanding of the Company's financial condition, see Item 1A – Risk Factors.
For further information on each segment's key growth strategies, projections and
certain assumptions, see Prospective Information.
For
information pertinent to various commitments and contingencies, see Item 8 –
Notes to Consolidated Financial Statements.
Earnings
Overview
The
following table summarizes the contribution to consolidated earnings
(loss) by each of the Company's businesses.
Years
ended December 31,
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Electric
|
|
$ |
24.1 |
|
|
$ |
18.7 |
|
|
$ |
17.7 |
|
Natural
gas distribution
|
|
|
30.8 |
|
|
|
34.8 |
|
|
|
14.0 |
|
Construction
services
|
|
|
25.6 |
|
|
|
49.8 |
|
|
|
43.8 |
|
Pipeline
and energy services
|
|
|
37.8 |
|
|
|
26.4 |
|
|
|
31.4 |
|
Natural
gas and oil production
|
|
|
(296.7 |
) |
|
|
122.3 |
|
|
|
142.5 |
|
Construction
materials and contracting
|
|
|
47.1 |
|
|
|
30.2 |
|
|
|
77.0 |
|
Other
|
|
|
7.3 |
|
|
|
10.8 |
|
|
|
(4.3 |
) |
Earnings
(loss) before discontinued operations
|
|
|
(124.0 |
) |
|
|
293.0 |
|
|
|
322.1 |
|
Income
from discontinued operations, net of tax
|
|
|
— |
|
|
|
— |
|
|
|
109.3 |
|
Earnings
(loss) on common stock
|
|
$ |
(124.0 |
) |
|
$ |
293.0 |
|
|
$ |
431.4 |
|
Earnings
(loss) per common share – basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
(loss) before discontinued operations
|
|
$ |
(.67 |
) |
|
$ |
1.60 |
|
|
$ |
1.77 |
|
Discontinued
operations, net of tax
|
|
|
— |
|
|
|
— |
|
|
|
.60 |
|
Earnings
(loss) per common share – basic
|
|
$ |
(.67 |
) |
|
$ |
1.60 |
|
|
$ |
2.37 |
|
Earnings
(loss) per common share – diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
(loss) before discontinued operations
|
|
$ |
(.67 |
) |
|
$ |
1.59 |
|
|
$ |
1.76 |
|
Discontinued
operations, net of tax
|
|
|
— |
|
|
|
— |
|
|
|
.60 |
|
Earnings
(loss) per common share – diluted
|
|
$ |
(.67 |
) |
|
$ |
1.59 |
|
|
$ |
2.36 |
|
Return
on average common equity
|
|
|
(4.9 |
)% |
|
|
11.0 |
% |
|
|
18.5 |
% |
2009 compared to
2008 Consolidated loss for 2009 was $124.0 million compared to earnings
of $293.0 million in 2008. This decrease was due to:
·
|
A
noncash write-down of natural gas and oil properties of $384.4 million
(after tax) as well as lower average realized natural gas and oil prices
of 30 percent and 42 percent, respectively and decreased natural gas
production of 13 percent, partially offset by the absence of the 2008
noncash write-down of natural gas and oil properties of $84.2 million
(after tax), lower depreciation, depletion and amortization expense and
lower production taxes at the natural gas and oil production
business
|
·
|
Lower
construction workloads, partially offset by lower general and
administrative expense at the construction services
business
|
Partially
offsetting these decreases were:
·
|
Increased
earnings from liquid asphalt oil and asphalt operations, as well as lower
selling, general and administrative expense at the construction materials
and contracting business
|
·
|
Increased
volumes transported to storage, higher storage services revenue and lower
operation and maintenance expense at the pipeline and energy services
business
|
2008 compared to
2007 Consolidated earnings for 2008 decreased $138.4 million from
the prior year due to:
·
|
The
absence in 2008 of income from discontinued operations, net of tax,
largely related to the gain on the sale of the Company's domestic
independent power production assets and earnings related to an electric
generating facility construction
project
|
·
|
An
$84.2 million after-tax noncash write-down of natural gas and oil
properties as well as higher depreciation, depletion and amortization
expense, production taxes and lease operating costs at the natural gas and
oil production business
|
·
|
Decreased
earnings at the construction materials and contracting business, primarily
construction workloads and margins, as well as product volumes from
existing operations, that were significantly lower as a result of the
economic downturn
|
Partially
offsetting these decreases were higher average natural gas and oil prices as
well as increased oil and natural gas production at the natural gas and oil
production business; increased earnings at the natural gas distribution
business, largely due to the July 2007 acquisition of Cascade and the October
2008 acquisition of Intermountain; and higher construction workloads at the
construction services business.
Financial
and Operating Data
Below are
key financial and operating data for each of the Company's
businesses.
Electric
Years
ended December 31,
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues
|
|
$ |
196.2 |
|
|
$ |
208.3 |
|
|
$ |
193.4 |
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
65.7 |
|
|
|
75.4 |
|
|
|
69.6 |
|
Operation
and maintenance
|
|
|
60.7 |
|
|
|
64.8 |
|
|
|
61.7 |
|
Depreciation,
depletion and amortization
|
|
|
24.7 |
|
|
|
24.0 |
|
|
|
22.5 |
|
Taxes,
other than income
|
|
|
8.4 |
|
|
|
8.7 |
|
|
|
7.9 |
|
|
|
|
159.5 |
|
|
|
172.9 |
|
|
|
161.7 |
|
Operating
income
|
|
|
36.7 |
|
|
|
35.4 |
|
|
|
31.7 |
|
Earnings
|
|
$ |
24.1 |
|
|
$ |
18.7 |
|
|
$ |
17.7 |
|
Retail
sales (million kWh)
|
|
|
2,663.5 |
|
|
|
2,663.4 |
|
|
|
2,601.7 |
|
Sales
for resale (million kWh)
|
|
|
90.8 |
|
|
|
223.8 |
|
|
|
165.6 |
|
Average
cost of fuel and purchased power per kWh
|
|
$ |
.023 |
|
|
$ |
.025 |
|
|
$ |
.025 |
|
2009 compared to
2008 Electric earnings
increased $5.4 million (28 percent) compared to the prior year due
to:
·
|
Higher
other income, primarily allowance for funds used during construction of
$5.0 million (after tax)
|
·
|
Lower
operation and maintenance expense of $2.3 million (after tax), largely
payroll and benefit-related costs
|
Partially
offsetting these increases were decreased sales for resale margins due to lower
average rates of 31 percent and decreased volumes of 59 percent due to lower
market demand and decreased plant generation.
2008 compared to
2007 Electric earnings
increased $1.0 million (6 percent) compared to the prior year due
to:
·
|
Higher
retail sales margins, largely due to the implementation of higher rates in
Montana, and increased retail sales volumes of
2 percent
|
·
|
Increased
sales for resale volumes of 35 percent, primarily due to the addition
of the wind-powered electric generating station near Baker, Montana, and
higher plant availability
|
Partially
offsetting these increases were:
·
|
Higher
operation and maintenance expense of $1.7 million (after tax),
primarily higher payroll and benefit-related costs, as well as higher
scheduled maintenance outage costs at electric generating
facilities
|
·
|
Increased
interest expense of $1.2 million (after
tax)
|
·
|
Higher
depreciation, depletion and amortization expense of $900,000 (after tax),
largely due to higher property, plant and equipment
balances
|
Natural
Gas Distribution
Years
ended December 31,
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues
|
|
$ |
1,072.8 |
|
|
$ |
1,036.1 |
|
|
$ |
533.0 |
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
757.6 |
|
|
|
757.6 |
|
|
|
372.2 |
|
Operation
and maintenance
|
|
|
140.5 |
|
|
|
123.6 |
|
|
|
88.5 |
|
Depreciation,
depletion and amortization
|
|
|
42.7 |
|
|
|
32.6 |
|
|
|
19.0 |
|
Taxes,
other than income
|
|
|
55.1 |
|
|
|
45.4 |
|
|
|
20.4 |
|
|
|
|
995.9 |
|
|
|
959.2 |
|
|
|
500.1 |
|
Operating
income
|
|
|
76.9 |
|
|
|
76.9 |
|
|
|
32.9 |
|
Earnings
|
|
$ |
30.8 |
|
|
$ |
34.8 |
|
|
$ |
14.0 |
|
Volumes
(MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
102.7 |
|
|
|
87.9 |
|
|
|
53.0 |
|
Transportation
|
|
|
132.7 |
|
|
|
103.5 |
|
|
|
54.7 |
|
Total
throughput
|
|
|
235.4 |
|
|
|
191.4 |
|
|
|
107.7 |
|
Degree
days (% of normal)*
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
|
104.4 |
% |
|
|
102.7 |
% |
|
|
92.9 |
% |
Cascade
|
|
|
105.1 |
% |
|
|
108.0 |
% |
|
|
101.7 |
% |
Intermountain
|
|
|
107.3 |
% |
|
|
90.3 |
% |
|
|
— |
|
Average
cost of natural gas,
|
|
|
|
|
|
|
|
|
|
|
|
|
including
transportation, per dk**
|
|
$ |
7.38 |
|
|
$ |
8.14 |
|
|
$ |
6.53 |
|
*Degree days are a measure of the
daily temperature-related demand for energy for heating.
|
|
**
Regulated natural gas sales only.
|
|
Note:
Cascade and Intermountain were acquired on July 2, 2007, and October 1,
2008, respectively. For further information, see Item 8 – Note
2.
|
|
2009 compared to
2008 The natural gas distribution business experienced a decrease in
earnings of $4.0 million (11 percent) compared to the prior year due
to:
·
|
Absence
of a $4.4 million (after tax) gain on the sale of Cascade’s natural gas
management service in June 2008
|
|
Lower earnings from energy-related services of $2.0 million (after
tax)
|
Partially
offsetting these decreases was lower operation and maintenance expense at
existing operations of $2.2 million (after tax), including lower payroll and
benefit-related costs.
2008 compared to
2007 The natural gas distribution business experienced an increase in
earnings of $20.8 million (148 percent) compared to the prior year due
to:
·
|
Earnings
of $18.4 million at Cascade and Intermountain, including a $4.4 million
(after tax) gain on the sale of Cascade's natural gas management service,
which were acquired on July 2, 2007, and October 1, 2008,
respectively
|
·
|
Increased
retail sales volumes from existing operations resulting from colder
weather than last year
|
Construction
Services
Years
ended December 31,
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
millions)
|
|
Operating
revenues
|
|
$ |
819.0 |
|
|
$ |
1,257.3 |
|
|
$ |
1,103.2 |
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
736.3 |
|
|
|
1,122.7 |
|
|
|
979.7 |
|
Depreciation,
depletion and amortization
|
|
|
12.8 |
|
|
|
13.4 |
|
|
|
14.3 |
|
Taxes,
other than income
|
|
|
25.7 |
|
|
|
39.7 |
|
|
|
33.7 |
|
|
|
|
774.8 |
|
|
|
1,175.8 |
|
|
|
1,027.7 |
|
Operating
income
|
|
|
44.2 |
|
|
|
81.5 |
|
|
|
75.5 |
|
Earnings
|
|
$ |
25.6 |
|
|
$ |
49.8 |
|
|
$ |
43.8 |
|
2009 compared to
2008 Construction services earnings decreased $24.2 million
(49 percent) compared to the prior year, primarily due to lower
construction workloads, largely in the Southwest region, partially offset by
lower general and administrative expense of $6.7 million (after tax), largely
payroll-related.
2008 compared to
2007 Construction services earnings increased $6.0 million
(14 percent) compared to the prior year, primarily due to higher
construction workloads, largely in the Southwest region. Partially offsetting
this increase were lower construction margins in certain
regions.
Pipeline
and Energy Services
Years
ended December 31,
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues
|
|
$ |
307.8 |
|
|
$ |
532.2 |
|
|
$ |
447.1 |
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
138.8 |
|
|
|
373.9 |
|
|
|
291.7 |
|
Operation
and maintenance
|
|
|
63.1 |
|
|
|
73.8 |
|
|
|
65.6 |
|
Depreciation,
depletion and amortization
|
|
|
25.5 |
|
|
|
23.6 |
|
|
|
21.7 |
|
Taxes,
other than income
|
|
|
11.0 |
|
|
|
11.3 |
|
|
|
10.1 |
|
|
|
|
238.4 |
|
|
|
482.6 |
|
|
|
389.1 |
|
Operating
income
|
|
|
69.4 |
|
|
|
49.6 |
|
|
|
58.0 |
|
Income
from continuing operations
|
|
|
37.8 |
|
|
|
26.4 |
|
|
|
31.4 |
|
Income
from discontinued operations, net of tax
|
|
|
— |
|
|
|
— |
|
|
|
.1 |
|
Earnings
|
|
$ |
37.8 |
|
|
$ |
26.4 |
|
|
$ |
31.5 |
|
Transportation
volumes (MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
|
38.9 |
|
|
|
32.0 |
|
|
|
29.3 |
|
Other
|
|
|
124.4 |
|
|
|
106.0 |
|
|
|
111.5 |
|
|
|
|
163.3 |
|
|
|
138.0 |
|
|
|
140.8 |
|
Gathering
volumes (MMdk)
|
|
|
92.6 |
|
|
|
102.1 |
|
|
|
92.4 |
|
2009 compared to
2008 Pipeline and energy services earnings increased $11.4 million
(44 percent) largely due to:
·
|
Increased
transportation volumes of $4.9 million (after tax), largely volumes
transported to storage
|
·
|
Lower
operation and maintenance expense of $4.5 million (after tax), largely
associated with the natural gas storage litigation, which was settled in
July 2009
|
·
|
Higher
storage services revenues of $3.1 million (after
tax)
|
·
|
Higher
gathering rates of $2.2 million (after
tax)
|
Partially
offsetting the earnings improvement were decreased gathering volumes of 9
percent. Results also reflect lower operating revenues and lower purchased
natural gas sold, both related to lower natural gas prices. The above table also
reflects lower operation and maintenance expense and revenues related to
energy-related service projects.
2008 compared to
2007 Pipeline and energy services earnings decreased $5.1 million
(16 percent) largely due to:
·
|
Lower
storage services revenue of $3.1 million (after tax), largely related
to lower storage balances and decreased volumes transported to storage of
31 percent
|
·
|
Higher
operation and maintenance expense, largely related to natural gas storage
litigation, as previously discussed, as well as higher materials and
payroll-related costs
|
·
|
Higher
depreciation, depletion and amortization expense of $1.3 million
(after tax), largely due to higher property, plant and equipment
balances
|
Partially
offsetting these decreases were a 10 percent increase in off-system
transportation volumes and demand fees, related to an expansion of the
Grasslands system, and $3.0 million (after tax) of higher gathering volumes
and rates.
Natural
Gas and Oil Production
Years
ended December 31,
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$ |
292.3 |
|
|
$ |
482.8 |
|
|
$ |
374.1 |
|
Oil
|
|
|
147.4 |
|
|
|
229.3 |
|
|
|
140.1 |
|
Other
|
|
|
— |
|
|
|
.2 |
|
|
|
.6 |
|
|
|
|
439.7 |
|
|
|
712.3 |
|
|
|
514.8 |
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
— |
|
|
|
.1 |
|
|
|
.3 |
|
Operation
and maintenance:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
|
70.1 |
|
|
|
82.0 |
|
|
|
66.9 |
|
Gathering
and transportation
|
|
|
24.0 |
|
|
|
24.8 |
|
|
|
20.4 |
|
Other
|
|
|
39.2 |
|
|
|
41.0 |
|
|
|
34.6 |
|
Depreciation,
depletion and amortization
|
|
|
129.9 |
|
|
|
170.2 |
|
|
|
127.4 |
|
Taxes,
other than income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
and property taxes
|
|
|
29.1 |
|
|
|
54.7 |
|
|
|
36.7 |
|
Other
|
|
|
.8 |
|
|
|
.8 |
|
|
|
.8 |
|
Write-down
of natural gas and oil properties
|
|
|
620.0 |
|
|
|
135.8 |
|
|
|
— |
|
|
|
|
913.1 |
|
|
|
509.4 |
|
|
|
287.1 |
|
Operating
income (loss)
|
|
|
(473.4 |
) |
|
|
202.9 |
|
|
|
227.7 |
|
Earnings
(loss)
|
|
$ |
(296.7 |
) |
|
$ |
122.3 |
|
|
$ |
142.5 |
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (MMcf)
|
|
|
56,632 |
|
|
|
65,457 |
|
|
|
62,798 |
|
Oil
(MBbls)
|
|
|
3,111 |
|
|
|
2,808 |
|
|
|
2,365 |
|
Total
Production (MMcfe)
|
|
|
75,299 |
|
|
|
82,303 |
|
|
|
76,988 |
|
Average
realized prices (including hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
5.16 |
|
|
$ |
7.38 |
|
|
$ |
5.96 |
|
Oil
(per Bbl)
|
|
$ |
47.38 |
|
|
$ |
81.68 |
|
|
$ |
59.26 |
|
Average
realized prices (excluding hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
2.99 |
|
|
$ |
7.29 |
|
|
$ |
5.37 |
|
Oil
(per Bbl)
|
|
$ |
49.76 |
|
|
$ |
82.28 |
|
|
$ |
59.53 |
|
Average
depreciation, depletion and amortization rate, per equivalent
Mcf
|
|
$ |
1.64 |
|
|
$ |
2.00 |
|
|
$ |
1.59 |
|
Production
costs, including taxes, per
|
|
|
|
|
|
|
|
|
|
|
|
|
equivalent
Mcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
$ |
.93 |
|
|
$ |
1.00 |
|
|
$ |
.87 |
|
Gathering
and transportation
|
|
|
.32 |
|
|
|
.30 |
|
|
|
.26 |
|
Production
and property taxes
|
|
|
.39 |
|
|
|
.66 |
|
|
|
.48 |
|
|
|
$ |
1.64 |
|
|
$ |
1.96 |
|
|
$ |
1.61 |
|
2009 compared to
2008 The natural gas and oil production business experienced a loss of
$296.7 million in 2009 compared to earnings of $122.3 million in 2008 due
to:
·
|
A
noncash write-down of natural gas and oil properties of $384.4 million
(after tax) in 2009, partially offset by the absence of the 2008 noncash
write-down of natural gas and oil properties of $84.2 million (after tax),
both discussed in Item 8 – Note 1
|
·
|
Lower
average realized natural gas and oil prices of 30 percent and 42 percent,
respectively
|
·
|
Decreased
natural gas production of 13 percent, largely related to normal production
declines at certain properties
|
Partially
offsetting these decreases were:
·
|
Lower
depreciation, depletion and amortization expense of $25.0 million (after
tax), due to lower depletion rates and decreased combined production. The
lower depletion rates are largely the result of the write-downs of natural
gas and oil properties in December 2008 and March
2009.
|
·
|
Lower
production taxes of $15.8 million (after tax) associated largely with
lower average prices
|
·
|
Increased
oil production of 11 percent, largely related to drilling activity in the
Bakken area, partially offset by normal production declines at certain
properties
|
·
|
Decreased
lease operating expenses of $7.3 million (after
tax)
|
2008 compared to
2007 The natural gas and oil production business experienced a decrease
in earnings of $20.2 million (14 percent) due to:
·
|
A noncash write-down of natural gas and oil properties of
$84.2 million (after tax), as previously
discussed
|
·
|
Higher depreciation, depletion and amortization expense of
$26.6 million (after tax), due to higher depletion rates and
increased production
|
·
|
Higher production taxes of $11.1 million (after tax), primarily
due to higher average prices and increased
production
|
·
|
Increased lease operating costs of $9.3 million (after tax),
including the East Texas properties acquired in early
2008
|
Partially
offsetting these decreases were:
·
|
Higher
average realized natural gas prices of
24 percent
|
·
|
Higher
average realized oil prices of
38 percent
|
·
|
Increased
oil production of 19 percent, largely related to drilling activity in
the Bakken area and Paradox Basin as well as production from the East
Texas properties
|
·
|
Increased
natural gas production of 4 percent, primarily related to the
acquisition of the East Texas properties, as previously
discussed
|
Construction
Materials and Contracting
Years
ended December 31,
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues
|
|
$ |
1,515.1 |
|
|
$ |
1,640.7 |
|
|
$ |
1,761.5 |
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
1,292.0 |
|
|
|
1,437.9 |
|
|
|
1,483.5 |
|
Depreciation,
depletion and amortization
|
|
|
93.6 |
|
|
|
100.9 |
|
|
|
95.8 |
|
Taxes,
other than income
|
|
|
36.2 |
|
|
|
39.1 |
|
|
|
43.6 |
|
|
|
|
1,421.8 |
|
|
|
1,577.9 |
|
|
|
1,622.9 |
|
Operating
income
|
|
|
93.3 |
|
|
|
62.8 |
|
|
|
138.6 |
|
Earnings
|
|
$ |
47.1 |
|
|
$ |
30.2 |
|
|
$ |
77.0 |
|
Sales
(000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregates
(tons)
|
|
|
23,995 |
|
|
|
31,107 |
|
|
|
36,912 |
|
Asphalt
(tons)
|
|
|
6,360 |
|
|
|
5,846 |
|
|
|
7,062 |
|
Ready-mixed
concrete (cubic yards)
|
|
|
3,042 |
|
|
|
3,729 |
|
|
|
4,085 |
|
2009 compared to
2008 Earnings at the construction materials and contracting business
increased $16.9 million (56 percent) due to:
·
|
Higher
earnings of $17.2 million (after tax) resulting from higher liquid asphalt
oil and asphalt volumes and margins
|
·
|
Lower
selling, general and administrative expense of $14.6 million (after tax),
largely the result of cost reduction
measures
|
·
|
Higher
aggregate margins of $8.3 million (after
tax)
|
Partially
offsetting the increases were:
·
|
Lower
aggregate and ready-mixed concrete sales volumes as a result of the
continuing economic downturn
|
·
|
Lower
gains on the sale of property, plant and equipment of $5.5 million (after
tax)
|
2008 compared to
2007 Earnings at the construction materials and contracting business
decreased $46.8 million (61 percent) due to decreased construction workloads,
margins and product volumes that were significantly lower as a result of the
economic downturn, primarily as it relates to the residential market, as well as
higher diesel fuel costs at existing operations, which had a combined negative
effect on earnings of $53.0 million (after tax). Partially offsetting this
decrease were earnings from companies acquired since the comparable prior
period, which contributed approximately 8 percent of earnings for
2008.
Other
and Intersegment Transactions
Amounts
presented in the preceding tables will not agree with the Consolidated
Statements of Income due to the Company's other operations and the elimination
of intersegment transactions. The amounts relating to these items are as
follows:
Years
ended December 31,
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
millions)
|
|
Other:
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$ |
9.5 |
|
|
$ |
10.5 |
|
|
$ |
10.0 |
|
Operation
and maintenance
|
|
|
8.1 |
|
|
|
5.9 |
|
|
|
15.9 |
|
Depreciation,
depletion and amortization
|
|
|
1.3 |
|
|
|
1.3 |
|
|
|
1.2 |
|
Taxes,
other than income
|
|
|
.3 |
|
|
|
.4 |
|
|
|
.2 |
|
Intersegment
transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$ |
183.6 |
|
|
$ |
394.1 |
|
|
$ |
315.1 |
|
Purchased
natural gas sold
|
|
|
156.7 |
|
|
|
365.7 |
|
|
|
286.8 |
|
Operation
and maintenance
|
|
|
26.9 |
|
|
|
28.4 |
|
|
|
28.3 |
|
For
further information on intersegment eliminations, see Item 8 –
Note 15.
Prospective
Information
The
following information highlights the key growth strategies, projections and
certain assumptions for the Company and its subsidiaries and other matters for
certain of the Company’s businesses. Many of these highlighted points are
“forward-looking statements.” There is no assurance that the Company’s
projections, including estimates for growth and changes in earnings, will in
fact be achieved. Please refer to assumptions contained in this section, as well
as the various important factors listed in Item 1A – Risk Factors. Changes
in such assumptions and factors could cause actual future results to differ
materially from the Company’s growth and earnings projections.
MDU
Resources Group, Inc.
·
|
Earnings
per common share for 2010, diluted, are projected in the range of $1.10 to
$1.35.
|
·
|
The
Company expects the percentage of 2010 earnings per common share by
quarter to be in the following approximate
ranges:
|
–
|
First
quarter – 15 percent to 20 percent
|
–
|
Second
quarter – 20 percent to 25 percent
|
–
|
Third
quarter – 30 percent to 35 percent
|
–
|
Fourth
quarter – 25 percent to 30 percent
|
·
|
Long-term
compound annual growth goals on earnings per share from operations are in
the range of 7 percent to
10 percent.
|
·
|
The
Company continually seeks opportunities to expand through strategic
acquisitions and organic growth
opportunities.
|
Electric
·
|
The Company continues to realize efficiencies and enhanced service
levels through its efforts to standardize operations, share services and
consolidate back-office functions among its four utility
companies.
|
·
|
The
Company is pursuing expansion
opportunities.
|
–
|
In April 2009, the Company purchased a 25 MW ownership interest
in the Wygen III power generation facility which is under
construction near Gillette, Wyoming. This rate-based generation will
replace a portion of the purchased power for the Wyoming system. The plant
is expected to be online during the second quarter of 2010. In
August 2009, Montana-Dakota filed an application with the WYPSC for
an electric rate increase, as discussed in Item 8 –
Note 18.
|
–
|
The Company is developing additional wind generation, including a
19.5 MW wind generation facility in southwest North Dakota and a
10.5 MW expansion of the Diamond Willow wind facility near Baker,
Montana. Both projects are expected to be commercial midyear
2010.
|
–
|
The Company is analyzing potential projects for accommodating load
growth and replacing purchased power contracts with company-owned
generation. The Company is reviewing the construction of natural gas-fired
combustion and wind generation.
|
·
|
The
Company is reviewing opportunities associated with the potential
development of high voltage transmission lines targeted towards delivery
of renewable energy from the wind rich regions that lie within its
traditional electric service territory to major metropolitan
areas.
|
Natural
gas distribution
·
|
The
Company continues to realize efficiencies and enhanced service levels
through its efforts to standardize operations, share services and
consolidate back-office functions among its four utility
companies.
|
Construction
services
·
|
The
Company anticipates margins in 2010 to be lower than 2009
levels.
|
·
|
The
Company is aggressively pursuing expansion in high voltage transmission
construction, renewable resource construction and military installation
services. The Company was recently awarded the engineering, procurement
and construction contract to build the 214-mile Montana Alberta Tie Line
between Lethbridge, Alberta and Great Falls,
Montana.
|
·
|
The
Company continues to focus on costs and efficiencies to enhance margins.
With its highly skilled technical workforce, this group is prepared to
take advantage of government stimulus spending on transmission
infrastructure.
|
·
|
Work
backlog as of December 31, 2009, was approximately $383 million,
compared to $604 million at December 31, 2008. The
December 31, 2009, backlog includes the new Montana Alberta Tie Line
project, and excludes $182 million related to the Fontainebleau
project, which is proceeding through the bankruptcy
process.
|
Pipeline
and energy services
·
|
An
incremental expansion to the Grasslands Pipeline of 75,000 Mcf per
day went into service August 31, 2009. The firm capacity of the
Grasslands Pipeline is at its ultimate full capacity of 213,000 Mcf
per day.
|
·
|
The
Company continues to pursue expansion of facilities and services offered
to customers. Energy development within its geographic region, which
includes portions of Colorado, Wyoming, Montana and North Dakota, is
expanding, most notably the Bakken Shale of North Dakota and eastern
Montana. Ongoing energy development is expected to have many direct and
indirect benefits to its business.
|
·
|
The
Company has natural gas storage fields, including the largest storage
field in North America located near Baker, Montana. Total working gas
storage capacity is 193 Bcf for its three storage fields. The Company
is pursuing a project to increase its firm deliverability and related
transportation capacity from the Baker Storage field with a targeted
in-service date in 2012.
|
Natural
gas and oil production
·
|
The
Company expects to spend approximately $375 million in capital
expenditures for 2010 for further exploitation of its existing properties,
exploratory drilling and acquisitions of properties. This includes
approximately $150 million for new growth opportunities, including
acquisitions.
|
·
|
The
Company is also actively pursuing other potential exploratory and reserve
acquisitions, which are not included in the current
forecast.
|
·
|
With
the reduced 2009 capital expenditures and the forecasted 2010 capital
expenditures, the Company expects its 2010 combined natural gas and oil
production to be approximately equal to 2009 levels. The 2010 production
forecast includes 3.5 Bcfe to 4 Bcfe related to growth
opportunities.
|
·
|
Earnings
guidance reflects estimated natural gas prices for February through
December as follows:
|
Index*
|
Price
Per Mcf
|
Ventura
|
$5.00
to $5.50
|
NYMEX
|
$5.25
to $5.75
|
CIG
|
$4.75
to $5.25
|
*
Ventura is an index pricing point related to Northern Natural Gas Co.’s
system; CIG is an index pricing point related to Colorado Interstate Gas
Co.’s system.
|
·
|
Earnings
guidance reflects estimated NYMEX crude oil prices for February through
December in the range of $70 to $75 per
barrel.
|
·
|
For
2010, the Company has hedged 45 percent to 50 percent of both its
estimated natural gas and oil production. For 2011, the Company has hedged
10 percent to 15 percent of both its estimated natural gas and
oil production. For 2012, the Company has hedged 5 percent to 10 percent
of its estimated natural gas production. The hedges that are in place as
of January 29, 2010, are summarized in the following
chart:
|
Commodity
|
Type
|
Index*
|
Period
Outstanding
|
Forward
Notional Volume
(MMBtu/Bbl)
|
Price
(Per
MMBtu/Bbl)
|
Natural
Gas
|
Swap
|
HSC
|
1/10
- 12/10
|
1,606,000
|
$8.08
|
Natural
Gas
|
Swap
|
NYMEX
|
1/10
- 12/10
|
3,650,000
|
$6.18
|
Natural
Gas
|
Swap
|
NYMEX
|
1/10
- 12/10
|
1,825,000
|
$6.40
|
Natural
Gas
|
Collar
|
NYMEX
|
1/10
- 12/10
|
1,825,000
|
$5.63-$6.00
|
Natural
Gas
|
Swap
|
NYMEX
|
1/10
- 12/10
|
1,825,000
|
$5.855
|
Natural
Gas
|
Swap
|
NYMEX
|
1/10
- 12/10
|
1,825,000
|
$6.045
|
Natural
Gas
|
Swap
|
NYMEX
|
1/10
- 12/10
|
1,825,000
|
$6.045
|
Natural
Gas
|
Swap
|
CIG
|
1/10
- 12/10
|
3,650,000
|
$5.03
|
Natural
Gas
|
Swap
|
HSC
|
1/10
- 10/10
|
608,000
|
$5.57
|
Natural
Gas
|
Swap
|
NYMEX
|
1/10
- 10/10
|
2,432,000
|
$5.645
|
Natural
Gas
|
Swap
|
Ventura
|
1/10
- 12/10
|
1,825,000
|
$5.95
|
Natural
Gas
|
Swap
|
NYMEX
|
4/10
- 12/10
|
3,025,000
|
$5.54
|
Natural
Gas
|
Collar
|
NYMEX
|
1/10
- 3/11
|
2,275,000
|
$5.62-$6.50
|
Natural
Gas
|
Swap
|
HSC
|
1/11
- 12/11
|
1,350,500
|
$8.00
|
Natural
Gas
|
Swap
|
NYMEX
|
1/11
- 12/11
|
4,015,000
|
$6.1027
|
Natural
Gas
|
Swap
|
NYMEX
|
1/12
- 12/12
|
3,477,000
|
$6.27
|
Crude
Oil
|
Collar
|
NYMEX
|
1/10
- 12/10
|
365,000
|
$60.00-$75.00
|
Crude
Oil
|
Swap
|
NYMEX
|
1/10
- 12/10
|
365,000
|
$73.20
|
Crude
Oil
|
Collar
|
NYMEX
|
1/10
- 12/10
|
365,000
|
$70.00-$86.00
|
Crude
Oil
|
Swap
|
NYMEX
|
1/10
- 12/10
|
365,000
|
$83.05
|
Crude
Oil
|
Collar
|
NYMEX
|
1/11
- 12/11
|
547,500
|
$80.00-$94.00
|
Natural
Gas
|
Basis
|
NYMEX
to Ventura
|
1/10
- 12/10
|
3,650,000
|
$0.25
|
Natural
Gas
|
Basis
|
NYMEX
to Ventura
|
1/10
- 12/10
|
912,500
|
$0.245
|
Natural
Gas
|
Basis
|
NYMEX
to Ventura
|
1/10
- 12/10
|
4,562,500
|
$0.25
|
Natural
Gas
|
Basis
|
NYMEX
to Ventura
|
1/10
- 12/10
|
1,825,000
|
$0.225
|
Natural
Gas
|
Basis
|
NYMEX
to Ventura
|
1/10
- 12/10
|
912,500
|
$0.23
|
Natural
Gas
|
Basis
|
NYMEX
to Ventura
|
1/10
- 12/10
|
2,737,500
|
$0.23
|
Natural
Gas
|
Basis
|
NYMEX
to Ventura
|
1/11
- 3/11
|
450,000
|
$0.135
|
*
Ventura is an index pricing point related to Northern Natural Gas Co.’s
system; CIG is an index pricing point related to Colorado Interstate Gas
Co.’s system; HSC is the Houston Ship Channel hub in southeast Texas which
connects to several pipelines.
|
Construction
materials and contracting
·
|
Most
of the markets served by construction materials are seeing positive
impacts related to the federal stimulus
spending.
|
·
|
The
Company is well positioned to take advantage of government stimulus
spending on transportation infrastructure particularly in the asphalt
paving and liquid asphalt oil product lines. Federal transportation
stimulus of $7.9 billion was directed to states where the
Company
|
operates.
Of that amount, 21 percent was spent in 2009, the remainder to be spent
over the next two years, with 82 percent already obligated to specific
projects by the various states.
·
|
The
Company continues to pursue work related to energy projects, such as wind
towers, transmission projects, geothermal and refineries. It is also
pursuing opportunities for expansion of its existing business lines
including initiatives aimed at capturing additional market share and
expansion into new markets. The Company has planned green field expansions
for its liquid asphalt oil
business.
|
·
|
The
Company has a strong emphasis on operational efficiencies and cost
reduction.
|
·
|
Liquid
asphalt margins are expected to be lower in 2010 than the record levels
experienced in 2009.
|
·
|
Work
backlog as of December 31, 2009, was approximately $459 million,
compared to $453 million at December 31, 2008. Although
public project margins tend to be somewhat lower than private
construction-related work, the Company anticipates significant
contributions to revenue from public works volume. Ninety-four percent of
its year-end backlog is related to public works projects compared to
80 percent at December 31,
2008.
|
·
|
As
the country’s 8th largest aggregate producer, the Company will continue to
strategically manage its 1.1 billion tons of aggregate reserves in
all its markets, as well as take further advantage of being vertically
integrated.
|
New
Accounting Standards
For
information regarding new accounting standards, see Item 8 – Note 1,
which is incorporated by reference.
Critical
Accounting Policies Involving Significant Estimates
The
Company has prepared its financial statements in conformity with GAAP. The
preparation of these financial statements requires management 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 as well as the reported amounts of revenues and expenses during the
reporting period. The Company's significant accounting policies are discussed in
Item 8 – Note 1.
Estimates
are used for items such as impairment testing of long-lived assets, goodwill and
natural gas and oil properties; fair values of acquired assets and liabilities
under the purchase method of accounting; natural gas and oil reserves; aggregate
reserves; property depreciable lives; tax provisions; uncollectible accounts;
environmental and other loss contingencies; accumulated provision for revenues
subject to refund; costs on construction contracts; unbilled revenues;
actuarially determined benefit costs; asset retirement obligations; the
valuation of stock-based compensation; and the fair value of derivative
instruments. The Company's critical accounting policies are subject to judgments
and uncertainties that affect the application of such policies. As discussed
below, the Company's financial position or results of operations may be
materially different when reported under different conditions or when using
different assumptions in the application of such policies.
As
additional information becomes available, or actual amounts are determinable,
the recorded estimates are revised. Consequently, operating results can be
affected by revisions to prior accounting estimates. The following critical
accounting policies involve significant judgments and
estimates.
Impairment
of long-lived assets and intangibles
The
Company reviews the carrying values of its long-lived assets and intangibles,
excluding natural gas and oil properties, whenever events or changes in
circumstances indicate that such carrying values may not be recoverable and
annually for goodwill. Unforeseen events and changes in circumstances and market
conditions and material differences in the value of long-lived assets and
intangibles due to changes in estimates of future cash flows could negatively
affect the fair value of the Company's assets and result in an impairment
charge. If an impairment indicator exists for tangible and intangible assets,
excluding goodwill, the asset group held and used is tested for recoverability
by comparing an estimate of undiscounted future cash flows attributable to the
assets compared to the carrying value of the assets. If impairment has occurred,
the amount of the impairment recognized is determined by estimating the fair
value of the assets and recording a loss if the carrying value is greater than
the fair value. In the case of goodwill, the first step, used to identify a
potential impairment, compares the fair value of the reporting unit using
discounted cash flows, with its carrying amount, including goodwill. The second
step, used to measure the amount of the impairment loss if step one indicates a
potential impairment, compares the implied fair value of the reporting unit
goodwill with the carrying amount of goodwill.
Fair
value is the amount at which the asset could be bought or sold in a current
transaction between market participants. The Company uses critical estimates and
assumptions when testing assets for impairment, including present value
techniques based on estimates of cash flows, quoted market prices or valuations
by third parties, or multiples of earnings or revenue performance measures. The
fair value of the asset could be different using different estimates and
assumptions in these valuation techniques.
There is
risk involved when determining the fair value of assets, tangible and
intangible, as there may be unforeseen events and changes in circumstances and
market conditions and changes in estimates of future cash flows.
The
Company believes its estimates used in calculating the fair value of long-lived
assets, including goodwill and identifiable intangibles, are reasonable based on
the information that is known when the estimates are made.
Natural
gas and oil properties
The
Company uses the full-cost method of accounting for its natural gas and oil
production activities. Capitalized costs are subject to a “ceiling test” that
limits such costs to the aggregate of the present value of future net cash flows
from proved reserves discounted at 10 percent, as mandated under the rules of
the SEC, plus the cost of unproved properties less applicable income taxes.
Future net revenue was estimated based on end-of-quarter spot market prices
adjusted for contracted price changes prior to the fourth quarter of 2009.
Effective December 31, 2009, the Modernization of Oil and Gas
Reporting rules issued by the SEC changed the pricing used to estimate reserves
and associated future cash flows to SEC Defined Prices. The Company hedges a
portion of its natural gas and oil production and the effects of the cash flow
hedges are used in determining the full-cost ceiling. Judgments and assumptions
are made when estimating and valuing reserves. There is risk that sustained
downward movements in natural gas and oil prices, changes in estimates of
reserve quantities and changes in operating and development costs could result
in future noncash write-downs of the Company's natural gas and oil
properties.
Estimates
of proved reserves were prepared in accordance with guidelines established by
the industry and the SEC. The estimates are arrived at using actual historical
wellhead production
trends
and/or standard reservoir engineering methods utilizing available geological,
geophysical, engineering and economic data. Other factors used in the reserve
estimates are prices, estimates of well operating and future development costs,
taxes, timing of operations, and the interests owned by the Company in the
properties. These estimates are refined as new information becomes
available.
Revenue
recognition
Revenue
is recognized when the earnings process is complete, as evidenced by an
agreement between the customer and the Company, when delivery has occurred or
services have been rendered, when the fee is fixed or determinable and when
collection is reasonably assured. The recognition of revenue in conformity with
GAAP requires the Company to make estimates and assumptions that affect the
reported amounts of revenue. Critical estimates related to the recognition of
revenue include the accumulated provision for revenues subject to refund and
costs on construction contracts under the percentage-of-completion
method.
Estimates
for revenues subject to refund are established initially for each regulatory
rate proceeding and are subject to change depending on the applicable regulatory
agency's (Agency) approval of final rates. These estimates are based on the
Company's analysis of its as-filed application compared to previous Agency
decisions in prior rate filings by the Company and other regulated companies.
The Company periodically reviews the status of its outstanding regulatory
proceedings and liability assumptions and may from time to time change its
liability estimates subject to known developments as the regulatory proceedings
move through the regulatory review process. The accuracy of the estimates is
ultimately determined when the Agency issues its final ruling on each regulatory
proceeding for which revenues were subject to refund. Estimates have changed
from time to time as additional information has become available as to what the
ultimate outcome may be and will likely continue to change in the future as new
information becomes available on each outstanding regulatory proceeding that is
subject to refund.
The
Company recognizes construction contract revenue from fixed-price and modified
fixed-price construction contracts at its construction businesses using the
percentage-of-completion method, measured by the percentage of costs incurred to
date to estimated total costs for each contract. This method depends largely on
the ability to make reasonably dependable estimates related to the extent of
progress toward completion of the contract, contract revenues and contract
costs. Inasmuch as contract prices are generally set before the work is
performed, the estimates pertaining to every project could contain significant
unknown risks such as volatile labor, material and fuel costs, weather delays,
adverse project site conditions, unforeseen actions by regulatory agencies,
performance by subcontractors, job management and relations with project
owners.
Several
factors are evaluated in determining the bid price for contract work. These
include, but are not limited to, the complexities of the job, past history
performing similar types of work, seasonal weather patterns, competition and
market conditions, job site conditions, work force safety, reputation of the
project owner, availability of labor, materials and fuel, project location and
project completion dates. As a project commences, estimates are continually
monitored and revised as information becomes available and actual costs and
conditions surrounding the job become known.
The
Company believes its estimates surrounding percentage-of-completion accounting
are reasonable based on the information that is known when the estimates are
made. The Company has contract administration, accounting and management control
systems in place that allow its estimates to be updated and monitored on a
regular basis. Because of the many factors that are
evaluated
in determining bid prices, it is inherent that the Company's estimates have
changed in the past and will continually change in the future as new information
becomes available for each job.
Purchase
accounting
The
Company accounts for its acquisitions under the purchase method of accounting
and, accordingly, the acquired assets and liabilities assumed are recorded at
their respective fair values. The excess of the purchase price over the fair
value of the assets acquired and liabilities assumed is recorded as goodwill.
The recorded values of assets and liabilities are based in part on third-party
estimates and valuations when available. The remaining values are based on
management's judgments and estimates, and, accordingly, the Company's financial
position or results of operations may be affected by changes in estimates and
judgments.
Acquired
assets and liabilities assumed by the Company that are subject to critical
estimates include property, plant and equipment and intangibles.
The fair
value of owned aggregate reserves is determined using qualified internal
personnel as well as geologists. Reserve estimates are calculated based on the
best available data. This data is collected from drill holes and other
subsurface investigations as well as investigations of surface features such as
mine highwalls and other exposures of the aggregate reserves. Mine plans,
production history and geologic data are also used to estimate reserve
quantities. Value is assigned to the aggregate reserves based on a review of
market royalty rates, expected cash flows and the number of years of aggregate
reserves at owned aggregate sites.
The fair
value of property, plant and equipment is based on a valuation performed either
by qualified internal personnel and/or outside appraisers. Fair values assigned
to plant and equipment are based on several factors, including the age and
condition of the equipment, maintenance records of the equipment and auction
values for equipment with similar characteristics at the time of
purchase.
The fair
value of leasehold rights is based on estimates including royalty rates, lease
terms and other discernible factors for acquired leasehold rights, and estimated
cash flows.
While the
allocation of the purchase price of an acquisition is subject to a considerable
degree of judgment and uncertainty, the Company does not expect the estimates to
vary significantly once an acquisition has been completed. The Company believes
its estimates have been reasonable in the past as there have been no significant
valuation adjustments subsequent to the final allocation of the purchase price
to the acquired assets and liabilities. In addition, goodwill impairment testing
is performed annually.
Asset
retirement obligations
Entities
are required to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. The Company has recorded
obligations related to the plugging and abandonment of natural gas and oil
wells, decommissioning of certain electric generating facilities, reclamation of
certain aggregate properties, special handling and disposal of hazardous
materials at certain electric generating facilities, natural gas distribution
and transmission facilities and buildings, and certain other obligations
associated with leased properties.
The
liability for future asset retirement obligations bears the risk of change as
many factors go into the development of the estimate of these obligations and
the likelihood that over time these factors
can and
will change. Factors used in the estimation of future asset retirement
obligations include estimates of current retirement costs, future inflation
factors, life of the asset and discount rates. These factors determine both a
present value of the retirement liability and the accretion to the retirement
liability in subsequent years.
Long-lived
assets are reviewed to determine if a legal retirement obligation exists. If a
legal retirement obligation exists, a determination of the liability is made if
a reasonable estimate of the present value of the obligation can be made. The
present value of the retirement obligation is calculated by inflating current
estimated retirement costs of the long-lived asset over its expected life to
determine the expected future cost and then discounting the expected future cost
back to the present value using a discount rate equal to the credit-adjusted
risk-free interest rate in effect when the liability was initially
recognized.
These
estimates and assumptions are subject to a number of variables and are expected
to change in the future. Estimates and assumptions will change as the estimated
useful lives of the assets change, the current estimated retirement costs
change, new legal retirement obligations occur and/or as existing legal asset
retirement obligations, for which a reasonable estimate of fair value could not
initially be made because of the range of time over which the Company may settle
the obligation is unknown or cannot be estimated, become less uncertain and a
reasonable estimate of the future liability can be made.
Pension
and other postretirement benefits
The
Company has noncontributory defined benefit pension plans and other
postretirement benefit plans for certain eligible employees. Various actuarial
assumptions are used in calculating the benefit expense (income) and liability
(asset) related to these plans. Costs of providing pension and other
postretirement benefits bear the risk of change, as they are dependent upon
numerous factors based on assumptions of future conditions.
The
Company makes various assumptions when determining plan costs, including the
current discount rates and the expected long-term return on plan assets, the
rate of compensation increases and healthcare cost trend rates. In selecting the
expected long-term return on plan assets, which is considered to be one of the
key variables in determining benefit expense or income, the Company considers
historical returns, current market conditions and expected future market trends,
including changes in interest rates and equity and bond market performance.
Another key variable in determining benefit expense or income is the discount
rate. In selecting the discount rate, the Company matches forecasted future cash
flows of the pension and postretirement plans to a yield curve which consists of
a hypothetical portfolio of high-quality corporate bonds with varying maturity
dates, as well as other factors, as a basis. The Company's pension and other
postretirement benefit plan assets are primarily made up of equity and
fixed-income investments. Fluctuations in actual equity and bond market returns
as well as changes in general interest rates may result in increased or
decreased pension and other postretirement benefit costs in the future.
Management estimates the rate of compensation increase based on long-term
assumed wage increases and the healthcare cost trend rates are determined by
historical and future trends.
The
Company believes the estimates made for its pension and other postretirement
benefits are reasonable based on the information that is known when the
estimates are made. These estimates and assumptions are subject to a number of
variables and are expected to change in the future. Estimates and assumptions
will be affected by changes in the discount rate, the expected long-term return
on plan assets, the rate of compensation increase and healthcare cost trend
rates. The Company plans to continue to use its current methodologies to
determine plan costs.
Income
taxes
Income
taxes require significant judgments and estimates including the determination of
income tax expense, deferred tax assets and liabilities and, if necessary, any
valuation allowances that may be required for deferred tax assets and accruals
for uncertain tax positions. The effective income tax rate is subject to
variability from period to period as a result of changes in federal and state
income tax rates and/or changes in tax laws. In addition, the effective tax rate
may be affected by other changes including the allocation of property, payroll
and revenues between states.
The
Company provides deferred federal and state income taxes on all temporary
differences between the book and tax basis of the Company's assets and
liabilities. Excess deferred income tax balances associated with the Company's
rate-regulated activities have been recorded as a regulatory liability and are
included in other liabilities. These regulatory liabilities are expected to be
reflected as a reduction in future rates charged to customers in accordance with
applicable regulatory procedures.
The
Company uses the deferral method of accounting for investment tax credits and
amortizes the credits on regulated electric and natural gas distribution plant
over various periods that conform to the ratemaking treatment prescribed by the
applicable state public service commissions.
Tax
positions taken or expected to be taken in an income tax return are evaluated
for recognition using a more-likely-than-not threshold, and those tax positions
requiring recognition are measured as the largest amount of tax benefit that is
greater than 50 percent likely of being realized upon ultimate settlement with a
taxing authority. The Company recognizes interest and penalties accrued related
to unrecognized tax benefits in income taxes.
The
Company believes its estimates surrounding income taxes are reasonable based on
the information that is known when the estimates are made.
Liquidity
and Capital Commitments
Cash
flows
Operating
activities The changes in cash flows from operating activities generally
follow the results of operations as discussed in Financial and Operating Data
and also are affected by changes in working capital.
Cash
flows provided by operating activities in 2009 increased $60.5 million from
the comparable prior period. Lower working capital requirements of $263.6
million were partially offset by lower income before depreciation, depletion and
amortization and before the after-tax noncash write-down of natural gas and oil
properties, largely the effects of lower commodity prices at the natural gas and
oil production business. The lower working capital requirements were largely the
result of lower receivables and lower net natural gas costs recoverable through
rate adjustments at the natural gas distribution business, as well as lower
working capital requirements at the other business segments.
Cash
flows provided by operating activities in 2008 increased $223.0 million from the
comparable prior period, due to:
·
|
Higher
income from continuing operations before depreciation, depletion and
amortization and before the after-tax noncash write-down of natural gas
and oil properties
|
·
|
Absence
of cash flows used related to discontinued operations in 2007 of $71.4
million
|
Investing
activities Cash flows used in investing activities in 2009 decreased
$675.2 million from the comparable prior period due to:
·
|
Lower
cash used in connection with acquisitions, net of cash acquired, of $527.1
million, primarily due to the absence of the 2008 acquisitions of
Intermountain and natural gas and oil producing properties in East
Texas
|
·
|
Decreased
ongoing capital expenditures of $297.8 million, primarily at the natural
gas and oil production business
|
Partially
offsetting the decrease in cash flows used in investing activities were lower
proceeds from investments of $89.5 million and decreased net proceeds from the
sale or disposition of property of $60.2 million, largely at the construction
materials and contracting business.
Cash
flows used in investing activities in 2008 increased $765.1 million from
the comparable prior period due to:
·
|
Absence
of cash flows provided by discontinued operations in 2007 of $548.2
million, primarily the result of the sale of the domestic independent
power production assets in the third quarter of
2007
|
·
|
Increased
ongoing capital expenditures of $188.2 million, largely at the natural gas
and oil production business
|
·
|
Higher
cash used in connection with acquisitions, net of cash acquired, of $185.1
million, largely due to the acquisition of Intermountain and natural gas
and oil producing properties in East Texas in 2008, partially offset by
the absence of the 2007 acquisition of
Cascade
|
Partially
offsetting the increase in cash flows used in investing activities were higher
proceeds from investments of $85.8 million in 2008, as well as the absence of
cash used for investments of $67.1 million in 2007.
Financing
activities Cash flows provided by
financing activities in 2009 decreased $559.6 million from the comparable
prior period, primarily due to lower issuance of long-term debt and short-term
borrowings, higher repayment of long-term debt, partially offset by increased
issuance of common stock. Lower cash flows provided by financing activities in
2009 reflects lower ongoing capital expenditures and acquisitions, as well as
increased cash provided by operating activities.
Cash
flows provided by financing activities in 2008 increased $456.2 million from the
comparable prior period, primarily due to higher issuance of long-term debt of
$333.7 million as well as higher net short-term borrowings of $101.7 million,
largely related to higher ongoing capital expenditures and
acquisitions.
Defined
benefit pension plans
The
Company has qualified noncontributory defined benefit pension plans (Pension
Plans) for certain employees. Plan assets consist of investments in equity and
fixed-income securities. Various actuarial assumptions are used in calculating
the benefit expense (income) and liability (asset) related to the Pension Plans.
Actuarial assumptions include assumptions about the discount rate, expected
return on plan assets and rate of future compensation increases as determined by
the Company within certain guidelines. At December 31, 2009, the Pension
Plans' accumulated benefit obligations exceeded these plans' assets by
approximately $85.0 million. Pretax pension expense reflected in the years
ended December 31, 2009, 2008 and 2007, was
$8.2 million,
$4.6 million
and $6.5 million, respectively. The Company's pension expense is currently
projected to be approximately $3.5 million to $4.5 million in 2010. Funding for
the Pension Plans is actuarially determined. The minimum required contributions
for 2009, 2008 and 2007 were approximately $7.3 million, $6.8 million
and $1.8 million, respectively. For further information on the Company's
Pension Plans, see Item 8 – Note 16.
Capital
expenditures
The
Company's capital expenditures for 2007 through 2009 and as anticipated for 2010
through 2012 are summarized in the following table, which also includes the
Company's capital needs for the retirement of maturing long-term
debt.
|
|
Actual
|
|
|
Estimated*
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
|
(In
millions)
|
|
Capital
expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
91 |
|
|
$ |
73 |
|
|
$ |
115 |
|
|
$ |
105 |
|
|
$ |
72 |
|
|
$ |
100 |
|
Natural
gas distribution
|
|
|
500 |
|
|
|
398 |
|
|
|
44 |
|
|
|
76 |
|
|
|
60 |
|
|
|
59 |
|
Construction
services
|
|
|
18 |
|
|
|
24 |
|
|
|
13 |
|
|
|
13 |
|
|
|
11 |
|
|
|
11 |
|
Pipeline
and energy services
|
|
|
39 |
|
|
|
43 |
|
|
|
70 |
|
|
|
15 |
|
|
|
28 |
|
|
|
149 |
|
Natural
gas and oil production
|
|
|
284 |
|
|
|
711 |
|
|
|
183 |
|
|
|
375 |
** |
|
|
359 |
|
|
|
321 |
|
Construction
materials and contracting
|
|
|
190 |
|
|
|
128 |
|
|
|
27 |
|
|
|
37 |
|
|
|
52 |
|
|
|
62 |
|
Other
|
|
|
2 |
|
|
|
1 |
|
|
|
3 |
|
|
|
1 |
|
|
|
1 |
|
|
|
1 |
|
Net
proceeds from sale or disposition of property
|
|
|
(25 |
) |
|
|
(87 |
) |
|
|
(27 |
) |
|
|
(4 |
) |
|
|
(7 |
) |
|
|
(1 |
) |
Net
capital expenditures before discontinued operations
|
|
|
1,099 |
|
|
|
1,291 |
|
|
|
428 |
|
|
|
618 |
|
|
|
576 |
|
|
|
702 |
|
Discontinued
operations
|
|
|
(548 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Net
capital expenditures
|
|
|
551 |
|
|
|
1,291 |
|
|
|
428 |
|
|
|
618 |
|
|
|
576 |
|
|
|
702 |
|
Retirement
of long-term debt
|
|
|
232 |
|
|
|
201 |
|
|
|
293 |
|
|
|
13 |
|
|
|
72 |
|
|
|
136 |
|
|
|
$ |
783 |
|
|
$ |
1,492 |
|
|
$ |
721 |
|
|
$ |
631 |
|
|
$ |
648 |
|
|
$ |
838 |
|
*The Company continues to
evaluate potential future acquisitions and other growth opportunities
which are dependent upon the availability of economic opportunities and,
as a result, capital expenditures may vary significantly from the above
estimates.
** Includes
approximately $150 million for new growth opportunities, including
potential acquisitions.
|
|
|
|
Capital
expenditures for 2009, 2008 and 2007 in the preceding table include noncash
transactions, including the issuance of the Company's equity securities, in
connection with acquisitions and the outstanding indebtedness related to the
2008 Intermountain acquisition and the 2007 Cascade acquisition. The net noncash
transactions were immaterial in 2009, $97.6 million in 2008 and
$217.3 million in 2007.
In 2009,
the Company acquired a pipeline and energy services business in Montana. The
total purchase consideration for this business and purchase price adjustments
with respect to certain other acquisitions made prior to 2009, consisting of the
Company's common stock and cash, was $22.0 million.
The 2009
capital expenditures, including those for the previously mentioned acquisitions
and retirements of long-term debt, were met from internal sources and the
issuance of long-term debt and the Company's equity securities. Estimated
capital expenditures for the years 2010 through 2012 include those
for:
·
|
Routine
equipment maintenance and
replacements
|
·
|
Buildings,
land and building improvements
|
·
|
Pipeline
and gathering projects
|
·
|
Further
development of existing properties, exploratory drilling and acquisitions
at the natural gas and oil production
segment
|
·
|
Power
generation opportunities, including certain costs for additional electric
generating capacity
|
·
|
Other
growth opportunities
|
The
Company continues to evaluate potential future acquisitions and other growth
opportunities; however, they are dependent upon the availability of economic
opportunities and, as a result, capital expenditures may vary significantly from
the estimates in the preceding table. It is anticipated that all of the funds
required for capital expenditures and retirement of long-term debt for the years
2010 through 2012 will be met from various sources, including internally
generated funds; the Company's credit facilities, as described below; and
through the issuance of long-term debt and the Company's equity
securities.
Capital
resources
Certain
debt instruments of the Company and its subsidiaries, including those discussed
below, contain restrictive covenants and cross-default provisions. In order to
borrow under the respective credit agreements, the Company and its subsidiaries
must be in compliance with the applicable covenants and certain other
conditions, all of which the Company and its subsidiaries, as applicable, were
in compliance with at December 31, 2009. In the event the Company and its
subsidiaries do not comply with the applicable covenants and other conditions,
alternative sources of funding may need to be pursued. For additional
information on the covenants, certain other conditions and cross-default
provisions, see Item 8 – Note 9.
The
following table summarizes the outstanding credit facilities of the Company and
its subsidiaries at December 31, 2009:
Company
|
Facility
|
|
|
Facility
Limit
|
|
|
|
Amount
Outstanding
|
|
|
|
Letters
of
Credit
|
|
|
Expiration
Date
|
|
(Dollars
in millions)
|
MDU
Resources
Group,
Inc.
|
Commercial
paper/Revolving
credit
agreement
|
(a)
|
|
$ |
125.0 |
|
|
|
$ |
— |
|
(b)
|
|
$ |
— |
|
|
6/21/11
|
|
MDU
Energy
Capital,
LLC
|
Master
shelf
agreement
|
|
|
$ |
175.0 |
|
|
|
$ |
165.0 |
|
|
|
$ |
— |
|
|
8/14/10
|
(c)
|
Cascade
Natural
Gas Corporation
|
Revolving
credit
agreement
|
|
|
$ |
50.0 |
|
(d)
|
|
$ |
— |
|
|
|
$ |
1.9 |
|
(e)
|
12/28/12
|
(f)
|
Intermountain
Gas
Company
|
Revolving
credit
agreement
|
|
|
$ |
65.0 |
|
(g)
|
|
$ |
10.3 |
|
|
|
$ |
— |
|
|
8/31/10
|
|
Centennial
Energy
Holdings,
Inc.
|
Commercial
paper/Revolving
credit
agreement
|
(h)
|
|
$ |
400.0 |
|
|
|
$ |
— |
|
(b)
|
|
$ |
26.4 |
|
(e)
|
12/13/12
|
|
Williston
Basin Interstate
Pipeline
Company
|
Uncommitted
long-term
private
shelf
agreement
|
|
|
$ |
125.0 |
|
|
|
$ |
87.5 |
|
|
|
$ |
— |
|
|
12/23/10
|
(i)
|
(a)
|
The
$125 million commercial paper program is supported by a revolving credit
agreement with various banks totaling $125 million (provisions allow for
increased borrowings, at the option of the Company on stated conditions,
up to a maximum of $150 million). There were no amounts outstanding under
the credit agreement.
|
(b)
|
Amount
outstanding under commercial paper program.
|
(c)
|
Or
such time as the agreement is terminated by either of the parties
thereto.
|
(d)
|
Certain
provisions allow for increased borrowings, up to a maximum of $75
million.
|
(e)
|
The
outstanding letters of credit, as discussed in Item 8 – Note 19, reduce
amounts available under the credit agreement.
|
(f)
|
Provisions
allow for an extension of up to two years upon consent of the
banks.
|
(g)
|
Certain
provisions allow for increased borrowings, up to a maximum of
$70 million.
|
(h)
|
The
$400 million commercial paper program is supported by a revolving credit
agreement with various banks totaling $400 million (provisions allow for
increased borrowings, at the option of Centennial on stated conditions, up
to a maximum of $450 million). There were no amounts outstanding under the
credit agreement.
|
(i)
|
Certain
provisions allow for an extension to
December 23, 2011.
|
In order
to maintain the Company’s and Centennial’s respective commercial paper programs
in the amounts indicated above, both the Company and Centennial must have
revolving credit agreements in place at least equal to the amount of their
commercial paper programs. While the amount of commercial paper outstanding does
not reduce available capacity under the respective revolving credit agreements,
the Company and Centennial do not issue commercial paper in an aggregate amount
exceeding the available capacity under their credit agreements.
The
following includes information related to the above table.
MDU Resources
Group, Inc. The Company’s revolving credit agreement supports its
commercial paper program. The commercial paper borrowings are classified as
long-term debt as they are intended to be refinanced on a long-term basis
through continued commercial paper borrowings. The Company’s objective is to
maintain acceptable credit ratings in order to access the capital markets
through the issuance of commercial paper. Downgrades in the Company’s credit
ratings have not limited, nor are currently expected to limit, the Company’s
ability to access the capital markets. If the Company were to experience a
further downgrade of its credit ratings, it may need to borrow under its credit
agreement and may experience an increase in overall interest rates with respect
to its cost of borrowings.
Prior to
the maturity of the credit agreement, the Company expects that it will negotiate
the extension or replacement of this agreement. If the Company is unable to
successfully negotiate an extension of, or replacement for, the credit
agreement, or if the fees on this facility become too expensive, which the
Company does not currently anticipate, the Company would seek alternative
funding.
In
November 2009, the Company completed a defeasance of its outstanding 8.60%
Secured Medium-Term Notes under the Mortgage and the Mortgage was discharged.
For more information, see Item 8 – Note 9.
The
Company's coverage of fixed charges including preferred stock dividends was
5.3 times for the 12 months ended December 31, 2008. Due to
the $384.4 million after-tax noncash write-down of natural gas and oil
properties in the first quarter of 2009, earnings were insufficient by $228.7
million to cover fixed charges for the 12 months ended December 31, 2009. If the
$384.4 million after-tax noncash write-down is excluded, the coverage of fixed
charges including preferred stock dividends would have been 4.6 times for
the 12 months ended December 31, 2009. Common stockholders' equity as a
percent of total capitalization was 63 percent and 61 percent at
December 31, 2009 and 2008, respectively.
The
coverage of fixed charges including preferred stock dividends, that excludes the
effect of the after-tax noncash write-down of natural gas and oil properties is
a non-GAAP financial measure. The Company believes that this non-GAAP financial
measure is useful because the write-down excluded is not indicative of the
Company’s cash flows available to meet its fixed charges obligations. The
presentation of this additional information is not meant to be considered a
substitute for financial measures prepared in accordance with GAAP.
In
September 2008, the Company entered into a Sales Agency Financing Agreement with
Wells Fargo Securities, LLC with respect to the issuance and sale of up to
5 million shares of the Company’s common stock. The common stock may be
offered for sale, from time to time, in accordance with the terms and conditions
of the agreement, which terminates on May 28, 2011. Proceeds from the sale
of shares of common stock under the agreement have been and are expected to be
used for corporate development purposes and other general corporate purposes.
The Company issued approximately 600,000 shares of stock during the fourth
quarter under the Sales Agency Financing Agreement, resulting in net proceeds of
$12.2 million, and has issued a total of approximately 3.2 million
shares of stock under the Sales Agency Financing Agreement through December 31,
2009, resulting in total net proceeds of $63.1 million.
The
Company currently has authorization to issue and sell up to $1.0 billion of
securities pursuant to a registration statement on file with the SEC. The
Company may sell all or a portion of such securities if warranted by market
conditions and the Company's capital requirements. Any offer
and sale
of such securities will be made only by means of a prospectus meeting the
requirements of the Securities Act and the rules and regulations
thereunder.
Centennial Energy
Holdings, Inc. Centennial’s revolving credit agreement supports its
commercial paper program. The Centennial commercial paper borrowings are
classified as long-term debt as Centennial intends to refinance these borrowings
on a long-term basis through continued Centennial commercial paper borrowings.
Centennial’s objective is to maintain acceptable credit ratings in order to
access the capital markets through the issuance of commercial paper. Downgrades
in Centennial’s credit ratings have not limited, nor are currently expected to
limit, Centennial’s ability to access the capital markets. If Centennial
were to experience a further downgrade of its credit ratings, it may need to
borrow under its credit agreement and may experience an increase in overall
interest rates with respect to its cost of borrowings.
Prior to
the maturity of the Centennial credit agreement, Centennial expects that it will
negotiate the extension or replacement of this agreement, which provides credit
support to access the capital markets. In the event Centennial is unable to
successfully negotiate this agreement, or in the event the fees on this facility
become too expensive, which Centennial does not currently anticipate, it would
seek alternative funding.
Off
balance sheet arrangements
In
connection with the sale of MPX in June 2005 to Petrobras, an indirect wholly
owned subsidiary of the Company has agreed to indemnify Petrobras for
49 percent of any losses that Petrobras may incur from certain contingent
liabilities specified in the purchase agreement. For more information, see
Item 8 – Note 19.
Centennial
continues to guarantee CEM’s obligations under a construction contract for a
550-MW combined-cycle electric generating facility near Hobbs, New Mexico. For
more information, see Item 8 – Note 19.
Contractual
obligations and commercial commitments
For more
information on the Company's contractual obligations on long-term debt,
operating leases, purchase commitments and uncertain tax positions, see
Item 8 – Notes 9, 14 and 19. At December 31, 2009, the Company's
commitments under these obligations were as follows:
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
(In
millions)
|
|
Long-term
debt
|
|
$ |
12.6 |
|
|
$ |
72.3 |
|
|
$ |
136.3 |
|
|
$ |
258.8 |
|
|
$ |
9.1 |
|
|
$ |
1,010.2 |
|
|
$ |
1,499.3 |
|
Estimated
interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
payments*
|
|
|
91.9 |
|
|
|
87.8 |
|
|
|
84.0 |
|
|
|
69.8 |
|
|
|
62.3 |
|
|
|
342.6 |
|
|
|
738.4 |
|
Operating
leases
|
|
|
25.2 |
|
|
|
20.3 |
|
|
|
15.3 |
|
|
|
12.6 |
|
|
|
6.7 |
|
|
|
43.9 |
|
|
|
124.0 |
|
Purchase
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
commitments
|
|
|
507.6 |
|
|
|
288.3 |
|
|
|
192.1 |
|
|
|
105.7 |
|
|
|
90.3 |
|
|
|
234.9 |
|
|
|
1,418.9 |
|
|
|
$ |
637.3 |
|
|
$ |
468.7 |
|
|
$ |
427.7 |
|
|
$ |
446.9 |
|
|
$ |
168.4 |
|
|
$ |
1,631.6 |
|
|
$ |
3,780.6 |
|
*
Estimated interest payments are calculated based on the applicable rates
and payment dates.
|
|
Not
reflected in the table above are $6.1 million in uncertain tax positions for
which the year of settlement is not reasonably possible to
determine.
Effects
of Inflation
Inflation
did not have a significant effect on the Company's operations in 2009, 2008 or
2007.
Item
7A. Quantitative and Qualitative Disclosures About Market
Risk
|
The
Company is exposed to the impact of market fluctuations associated with
commodity prices, interest rates and foreign currency. The Company has policies
and procedures to assist in controlling these market risks and utilizes
derivatives to manage a portion of its risk.
For more
information on derivatives and the Company's derivative policies and procedures,
see Item 8 – Notes 1 and 7.
Commodity
price risk
Fidelity
utilizes derivative instruments to manage a portion of the market risk
associated with fluctuations in the price of natural gas and oil and basis
differentials on forecasted sales of natural gas and oil production. Cascade and
Intermountain utilize derivative instruments to manage a portion of their
regulated natural gas supply portfolio in order to manage fluctuations in the
price of natural gas.
The
following table summarizes derivative agreements entered into by Fidelity,
Cascade and Intermountain as of December 31, 2009. These agreements call
for Fidelity to receive fixed prices and pay variable prices, and for Cascade
and Intermountain to receive variable prices and pay fixed prices.
(Forward
notional volume and fair value in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Forward
|
|
|
|
|
|
|
Fixed
|
|
|
Notional
|
|
|
|
|
|
|
Price
(Per
|
|
|
Volume
|
|
|
|
|
|
|
MMBtu/Bbl)
|
|
|
(MMBtu/Bbl)
|
|
|
Fair
Value
|
|
Fidelity
|
|
|
|
|
|
|
|
|
|
Natural
gas swap agreements maturing in 2010
|
|
$ |
5.99 |
|
|
|
21,071 |
|
|
$ |
5,968 |
|
Natural
gas swap agreement maturing in 2011
|
|
$ |
8.00 |
|
|
|
1,351 |
|
|
$ |
2,377 |
|
Natural
gas basis swap agreements maturing in 2010
|
|
$ |
.24 |
|
|
|
14,600 |
|
|
$ |
(4,021 |
) |
Natural
gas basis swap agreement maturing in 2011
|
|
$ |
.14 |
|
|
|
450 |
|
|
$ |
(108 |
) |
Oil
swap agreements maturing in 2010
|
|
$ |
78.13 |
|
|
|
730 |
|
|
$ |
(3,043 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cascade
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas swap agreements maturing in 2010
|
|
$ |
8.03 |
|
|
|
8,922 |
|
|
$ |
(23,058 |
) |
Natural
gas swap agreements maturing in 2011
|
|
$ |
8.10 |
|
|
|
2,270 |
|
|
$ |
(4,756 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Intermountain
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas swap agreements maturing in 2010
|
|
$ |
6.03 |
|
|
|
900 |
|
|
$ |
(86 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Forward
|
|
|
|
|
|
|
|
Floor/Ceiling
|
|
|
Notional
|
|
|
|
|
|
|
|
Price
(Per
|
|
|
Volume
|
|
|
|
|
|
|
|
MMBtu/Bbl)
|
|
|
(MMBtu/Bbl)
|
|
|
Fair
Value
|
|
Fidelity
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas collar agreements maturing in 2010
|
|
|
$5.63/$6.25 |
|
|
|
3,650 |
|
|
$ |
(39 |
) |
Natural
gas collar agreement maturing in 2011
|
|
|
$5.62/$6.50 |
|
|
|
450 |
|
|
$ |
(6 |
) |
Oil
collar agreements maturing in 2010
|
|
|
$65.00/$80.50 |
|
|
|
730 |
|
|
$ |
(4,867 |
) |
Oil
collar agreement maturing in 2011
|
|
|
$80.00/$94.00 |
|
|
|
548 |
|
|
$ |
357 |
|
The
following table summarizes derivative agreements entered into by Fidelity,
Cascade and Intermountain as of December 31, 2008. These agreements call
for Fidelity to receive fixed prices and pay variable prices, and for Cascade
and Intermountain to receive variable prices and pay fixed prices.
(Forward
notional volume and fair value in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Forward
|
|
|
|
|
|
|
Average
|
|
|
Notional
|
|
|
|
|
|
|
Fixed
Price
|
|
|
Volume
|
|
|
|
|
|
|
(Per
MMBtu)
|
|
|
(MMBtu)
|
|
|
Fair
Value
|
|
Fidelity
|
|
|
|
|
|
|
|
|
|
Natural
gas swap agreements maturing in 2009
|
|
$ |
8.73 |
|
|
|
10,920 |
|
|
$ |
33,059 |
|
Natural
gas swap agreements maturing in 2010
|
|
$ |
8.08 |
|
|
|
1,606 |
|
|
$ |
2,011 |
|
Natural
gas swap agreements maturing in 2011
|
|
$ |
8.00 |
|
|
|
1,351 |
|
|
$ |
1,211 |
|
Natural
gas basis swap agreement maturing in 2009
|
|
$ |
.61 |
|
|
|
3,650 |
|
|
$ |
(1,349 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cascade
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas swap agreements maturing in 2009
|
|
$ |
8.26 |
|
|
|
19,350 |
|
|
$ |
(49,883 |
) |
Natural
gas swap agreements maturing in 2010
|
|
$ |
8.03 |
|
|
|
8,922 |
|
|
$ |
(18,947 |
) |
Natural
gas swap agreements maturing in 2011
|
|
$ |
8.10 |
|
|
|
2,270 |
|
|
$ |
(4,587 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Intermountain
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas swap agreements maturing in 2009
|
|
$ |
5.54 |
|
|
|
7,905 |
|
|
$ |
(5,297 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Forward
|
|
|
|
|
|
|
|
Floor/Ceiling
|
|
|
Notional
|
|
|
|
|
|
|
|
Price
(Per
|
|
|
Volume
|
|
|
|
|
|
|
|
MMBtu)
|
|
|
(MMBtu)
|
|
|
Fair
Value
|
|
Fidelity
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas collar agreements maturing in 2009
|
|
|
$8.52/$9.56 |
|
|
|
14,965 |
|
|
$ |
45,105 |
|
Note: The fair value of Cascade’s
natural gas swap agreements is presented net of the collateral provided to
the counterparty of $11.1 million.
|
|
Interest
rate risk
The
Company uses fixed rate long-term debt and from time to time variable rate
long-term debt to partially finance capital expenditures and mandatory debt
retirements. These debt agreements expose the Company to market risk related to
changes in interest rates. The Company manages this risk by taking advantage of
market conditions when timing the placement of long-term or permanent financing.
The Company also has historically used interest rate swap agreements to manage a
portion of the Company's interest rate risk and may take advantage of such
agreements in the future to minimize such risk. At December 31, 2009 and 2008,
the Company had no outstanding interest rate hedges.
The
following table shows the amount of debt, including current portion, and related
weighted average interest rates, both by expected maturity dates, as of
December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
|
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
Thereafter
|
|
|
Total
|
|
|
Value
|
|
|
|
(Dollars
in millions)
|
|
Long-term
debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed
rate
|
|
$ |
12.6 |
|
|
$ |
72.3 |
|
|
$ |
136.3 |
|
|
$ |
258.8 |
|
|
$ |
9.1 |
|
|
$ |
1,010.2 |
|
|
$ |
1,499.3 |
|
|
$ |
1,566.3 |
|
Weighted
average
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
interest
rate
|
|
|
6.9 |
% |
|
|
7.1 |
% |
|
|
5.9 |
% |
|
|
6.0 |
% |
|
|
6.9 |
% |
|
|
6.1 |
% |
|
|
6.1 |
% |
|
|
— |
|
Foreign
currency risk
MDU
Brasil's equity method investments in the Brazilian Transmission Lines are
exposed to market risks from changes in foreign currency exchange rates between
the U.S. dollar and the Brazilian Real. For further information, see Item 8
– Note 4. At December 31, 2009 and 2008, the Company had no
outstanding foreign currency hedges.
Item 8. Financial
Statements and Supplementary Data
|
Management's
Report on Internal Control Over Financial Reporting
The
management of MDU Resources Group, Inc. is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in
Rules 13a-15(f) under the Securities Exchange Act of 1934. The Company's
internal control system is designed 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.
All
internal control systems, no matter how well designed, have inherent
limitations. Therefore, even those systems determined to be effective can
provide only reasonable assurance with respect to financial statement
preparation and presentation. Because of its inherent limitations, internal
control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may
deteriorate.
Management
assessed the effectiveness of the Company's internal control over financial
reporting as of December 31, 2009. In making this assessment, 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 under the framework in Internal Control–Integrated Framework,
management concluded that the Company's internal control over financial
reporting was effective as of December 31, 2009.
The
effectiveness of the Company's internal control over financial reporting as of
December 31, 2009, has been audited by Deloitte & Touche LLP, an
independent registered public accounting firm, as stated in their
report.
/s/ Terry D.
Hildestad
|
/s/ Doran N.
Schwartz
|
Terry
D. Hildestad
|
Doran
N. Schwartz
|
President
and Chief Executive Officer
|
Vice
President and Chief Financial Officer
|
|
|
Report of
Independent Registered Public Accounting Firm
To
the Board of Directors and Stockholders of MDU Resources Group,
Inc.:
We have
audited the accompanying consolidated balance sheets of MDU Resources Group,
Inc. and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and
the related consolidated statements of income, common stockholders’ equity, and
cash flows for each of the three years in the period ended December 31,
2009. Our audits also included the financial statement schedule for each of the
three years in the period ended December 31, 2009, 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 these 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
consolidated financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the consolidated financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall consolidated 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 MDU Resources Group, Inc. and
subsidiaries as of December 31, 2009 and 2008, and the results of their
operations and their 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, the financial
statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, present fairly, in all material respects,
the information set forth therein.
As
discussed in Note 1 to the consolidated financial statements, the Company
adopted the definitions and required pricing assumptions outlined in the
Modernization of Oil and Gas Reporting rules issued by the Securities and
Exchange Commission effective as of December 31, 2009.
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 17, 2010, expressed an
unqualified opinion on the Company’s internal control over financial
reporting.
/s/
Deloitte & Touche LLP
Minneapolis,
Minnesota
February 17,
2010
Report of
Independent Registered Public Accounting Firm
To
the Board of Directors and Stockholders of MDU Resources Group,
Inc.:
We have
audited the internal control over financial reporting of MDU Resources
Group, Inc. 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
February 17, 2010 expressed an unqualified opinion on those consolidated
financial statements and financial statement schedule and included an
explanatory paragraph regarding the Company’s adoption of the definitions and
required pricing assumptions outlined in the Modernization of Oil and Gas
Reporting rules issued by the Securities and Exchange Commission effective as of
December 31, 2009.
/s/
Deloitte & Touche LLP
Minneapolis,
Minnesota
February 17,
2010
MDU
RESOURCES GROUP, INC.
Consolidated
Statements of Income
Years
ended December 31,
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands, except per share amounts)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
Electric,
natural gas distribution and pipeline and energy services
|
|
$ |
1,504,269 |
|
|
$ |
1,685,199 |
|
|
$ |
1,095,709 |
|
Construction
services, natural gas and oil production, construction materials and
contracting, and other
|
|
|
2,672,232 |
|
|
|
3,318,079 |
|
|
|
3,152,187 |
|
Total
operating revenues
|
|
|
4,176,501 |
|
|
|
5,003,278 |
|
|
|
4,247,896 |
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
65,717 |
|
|
|
75,333 |
|
|
|
69,616 |
|
Purchased
natural gas sold
|
|
|
739,678 |
|
|
|
765,900 |
|
|
|
377,404 |
|
Operation
and maintenance:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric,
natural gas distribution and pipeline and energy services
|
|
|
263,869 |
|
|
|
262,053 |
|
|
|
215,587 |
|
Construction
services, natural gas and oil production, construction
materials and contracting, and other
|
|
|
2,143,195 |
|
|
|
2,686,055 |
|
|
|
2,572,864 |
|
Depreciation,
depletion and amortization
|
|
|
330,542 |
|
|
|
366,020 |
|
|
|
301,932 |
|
Taxes,
other than income
|
|
|
166,597 |
|
|
|
200,080 |
|
|
|
153,373 |
|
Write-down
of natural gas and oil properties (Note 1)
|
|
|
620,000 |
|
|
|
135,800 |
|
|
|
— |
|
Total
operating expenses
|
|
|
4,329,598 |
|
|
|
4,491,241 |
|
|
|
3,690,776 |
|
Operating
income (loss)
|
|
|
(153,097 |
) |
|
|
512,037 |
|
|
|
557,120 |
|
Earnings
from equity method investments
|
|
|
8,499 |
|
|
|
6,627 |
|
|
|
19,609 |
|
Other
income
|
|
|
9,331 |
|
|
|
4,012 |
|
|
|
8,318 |
|
Interest
expense
|
|
|
84,099 |
|
|
|
81,527 |
|
|
|
72,237 |
|
Income
(loss) before income taxes
|
|
|
(219,366 |
) |
|
|
441,149 |
|
|
|
512,810 |
|
Income
taxes
|
|
|
(96,092 |
) |
|
|
147,476 |
|
|
|
190,024 |
|
Income
(loss) from continuing operations
|
|
|
(123,274 |
) |
|
|
293,673 |
|
|
|
322,786 |
|
Income
from discontinued operations, net of tax (Note 3)
|
|
|
— |
|
|
|
— |
|
|
|
109,334 |
|
Net
income (loss)
|
|
|
(123,274 |
) |
|
|
293,673 |
|
|
|
432,120 |
|
Dividends
on preferred stocks
|
|
|
685 |
|
|
|
685 |
|
|
|
685 |
|
Earnings
(loss) on common stock
|
|
$ |
(123,959 |
) |
|
$ |
292,988 |
|
|
$ |
431,435 |
|
Earnings
(loss) per common share – basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
(loss) before discontinued operations
|
|
$ |
(.67 |
) |
|
$ |
1.60 |
|
|
$ |
1.77 |
|
Discontinued
operations, net of tax
|
|
|
— |
|
|
|
— |
|
|
|
.60 |
|
Earnings (loss) per common share –
basic
|
|
$ |
(.67 |
) |
|
$ |
1.60 |
|
|
$ |
2.37 |
|
Earnings
(loss) per common share – diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
(loss) before discontinued operations
|
|
$ |
(.67 |
) |
|
$ |
1.59 |
|
|
$ |
1.76 |
|
Discontinued
operations, net of tax
|
|
|
— |
|
|
|
— |
|
|
|
.60 |
|
Earnings (loss) per common share –
diluted
|
|
$ |
(.67 |
) |
|
$ |
1.59 |
|
|
$ |
2.36 |
|
Dividends
per common share
|
|
$ |
.6225 |
|
|
$ |
.6000 |
|
|
$ |
.5600 |
|
Weighted
average common shares outstanding – basic
|
|
|
185,175 |
|
|
|
183,100 |
|
|
|
181,946 |
|
Weighted
average common shares outstanding – diluted
|
|
|
185,175 |
|
|
|
183,807 |
|
|
|
182,902 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
Consolidated
Balance Sheets
December 31,
|
|
2009
|
|
|
2008
|
|
(In
thousands, except shares and per share amounts)
|
|
Assets
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
175,114 |
|
|
$ |
51,714 |
|
Receivables,
net
|
|
|
531,980 |
|
|
|
707,109 |
|
Inventories
|
|
|
249,804 |
|
|
|
261,524 |
|
Deferred
income taxes
|
|
|
28,145 |
|
|
|
— |
|
Short-term
investments
|
|
|
2,833 |
|
|
|
2,467 |
|
Commodity
derivative instruments
|
|
|
7,761 |
|
|
|
78,164 |
|
Prepayments
and other current assets
|
|
|
66,021 |
|
|
|
171,314 |
|
Total
current assets
|
|
|
1,061,658 |
|
|
|
1,272,292 |
|
Investments
|
|
|
145,416 |
|
|
|
114,290 |
|
Property,
plant and equipment (Note 1)
|
|
|
6,766,582 |
|
|
|
7,062,237 |
|
Less
accumulated depreciation, depletion and amortization
|
|
|
2,872,465 |
|
|
|
2,761,319 |
|
Net
property, plant and equipment
|
|
|
3,894,117 |
|
|
|
4,300,918 |
|
Deferred
charges and other assets:
|
|
|
|
|
|
|
|
|
Goodwill
(Note 5)
|
|
|
629,463 |
|
|
|
615,735 |
|
Other
intangible assets, net (Note 5)
|
|
|
28,977 |
|
|
|
28,392 |
|
Other
|
|
|
231,321 |
|
|
|
256,218 |
|
Total
deferred charges and other assets
|
|
|
889,761 |
|
|
|
900,345 |
|
Total
assets
|
|
$ |
5,990,952 |
|
|
$ |
6,587,845 |
|
Liabilities
and Stockholders' Equity
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
Short-term
borrowings (Note 9)
|
|
$ |
10,300 |
|
|
$ |
105,100 |
|
Long-term
debt due within one year
|
|
|
12,629 |
|
|
|
78,666 |
|
Accounts
payable
|
|
|
281,906 |
|
|
|
432,358 |
|
Taxes
payable
|
|
|
55,540 |
|
|
|
49,784 |
|
Deferred
income taxes
|
|
|
— |
|
|
|
20,344 |
|
Dividends
payable
|
|
|
29,749 |
|
|
|
28,640 |
|
Accrued
compensation
|
|
|
47,425 |
|
|
|
55,646 |
|
Commodity
derivative instruments
|
|
|
36,907 |
|
|
|
56,529 |
|
Other
accrued liabilities
|
|
|
192,729 |
|
|
|
140,408 |
|
Total
current liabilities
|
|
|
667,185 |
|
|
|
967,475 |
|
Long-term
debt (Note 9)
|
|
|
1,486,677 |
|
|
|
1,568,636 |
|
Deferred
credits and other liabilities:
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
590,968 |
|
|
|
727,857 |
|
Other
liabilities
|
|
|
674,475 |
|
|
|
562,801 |
|
Total
deferred credits and other liabilities
|
|
|
1,265,443 |
|
|
|
1,290,658 |
|
Commitments
and contingencies (Notes 16, 18 and 19)
|
|
|
|
|
|
|
|
|
Stockholders'
equity:
|
|
|
|
|
|
|
|
|
Preferred
stocks (Note 11)
|
|
|
15,000 |
|
|
|
15,000 |
|
Common
stockholders' equity:
|
|
|
|
|
|
|
|
|
Common
stock (Note 12)
|
|
|
|
|
|
|
|
|
Authorized
– 500,000,000 shares, $1.00 par value
|
|
|
|
|
|
|
|
|
Issued
– 188,389,265 shares in 2009 and 184,208,283 shares in
2008
|
|
|
188,389 |
|
|
|
184,208 |
|
Other
paid-in capital
|
|
|
1,015,678 |
|
|
|
938,299 |
|
Retained
earnings
|
|
|
1,377,039 |
|
|
|
1,616,830 |
|
Accumulated
other comprehensive income (loss)
|
|
|
(20,833 |
) |
|
|
10,365 |
|
Treasury
stock at cost – 538,921 shares
|
|
|
(3,626 |
) |
|
|
(3,626 |
) |
Total
common stockholders' equity
|
|
|
2,556,647 |
|
|
|
2,746,076 |
|
Total stockholders'
equity
|
|
|
2,571,647 |
|
|
|
2,761,076 |
|
Total
liabilities and stockholders’ equity
|
|
$ |
5,990,952 |
|
|
$ |
6,587,845 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
Consolidated
Statements of Common Stockholders' Equity
Years
ended December 31, 2009, 2008 and 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
Paid-in
|
|
|
Retained
|
|
|
Comprehensive
|
|
|
Treasury Stock
|
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Earnings
|
|
|
Income
(Loss)
|
|
|
Shares
|
|
|
Amount
|
|
|
Total
|
|
|
|
(In
thousands, except shares)
|
|
Balance
at December 31, 2006
|
|
|
181,557,543 |
|
|
$ |
181,558 |
|
|
$ |
874,253 |
|
|
$ |
1,104,210 |
|
|
$ |
(6,482 |
) |
|
|
(538,921 |
) |
|
$ |
(3,626 |
) |
|
$ |
2,149,913 |
|
Comprehensive
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
432,120 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
432,120 |
|
Other
comprehensive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
income
(loss), net of tax -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
unrealized loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
on
derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
qualifying
as hedges
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(13,505 |
) |
|
|
— |
|
|
|
— |
|
|
|
(13,505 |
) |
Postretirement
liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
adjustment
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
3,012 |
|
|
|
— |
|
|
|
— |
|
|
|
3,012 |
|
Foreign
currency
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
translation
adjustment
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
7,177 |
|
|
|
— |
|
|
|
— |
|
|
|
7,177 |
|
Net
unrealized gain
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
on
available-for-sale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
investments
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
405 |
|
|
|
— |
|
|
|
— |
|
|
|
405 |
|
Total
comprehensive income
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
429,209 |
|
Uncertain
tax positions transition adjustment
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
31 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
31 |
|
Dividends
on preferred stocks
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(685 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(685 |
) |
Dividends
on common stock
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(102,091 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(102,091 |
) |
Tax
benefit on stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation
|
|
|
— |
|
|
|
— |
|
|
|
5,398 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
5,398 |
|
Issuance
of common stock
|
|
|
1,388,985 |
|
|
|
1,389 |
|
|
|
33,155 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
34,544 |
|
Balance
at December 31, 2007
|
|
|
182,946,528 |
|
|
|
182,947 |
|
|
|
912,806 |
|
|
|
1,433,585 |
|
|
|
(9,393 |
) |
|
|
(538,921 |
) |
|
|
(3,626 |
) |
|
|
2,516,319 |
|
Comprehensive
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
293,673 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
293,673 |
|
Other
comprehensive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
income
(loss), net of tax -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
unrealized gain
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
on
derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
qualifying
as hedges
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
43,448 |
|
|
|
— |
|
|
|
— |
|
|
|
43,448 |
|
Postretirement
liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
adjustment
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(13,751 |
) |
|
|
— |
|
|
|
— |
|
|
|
(13,751 |
) |
Foreign
currency
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
translation
adjustment
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(9,534 |
) |
|
|
— |
|
|
|
— |
|
|
|
(9,534 |
) |
Total
comprehensive income
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
313,836 |
|
Fair
value option transition adjustment
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
405 |
|
|
|
(405 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Dividends
on preferred stocks
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(685 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(685 |
) |
Dividends
on common stock
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(110,148 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(110,148 |
) |
Tax
benefit on stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation
|
|
|
— |
|
|
|
— |
|
|
|
4,441 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
4,441 |
|
Issuance
of common stock
|
|
|
1,261,755 |
|
|
|
1,261 |
|
|
|
21,052 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
22,313 |
|
Balance
at December 31, 2008
|
|
|
184,208,283 |
|
|
|
184,208 |
|
|
|
938,299 |
|
|
|
1,616,830 |
|
|
|
10,365 |
|
|
|
(538,921 |
) |
|
|
(3,626 |
) |
|
|
2,746,076 |
|
Comprehensive
loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
loss
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(123,274 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(123,274 |
) |
Other
comprehensive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
income
(loss), net of tax -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
unrealized loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
on
derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
qualifying
as hedges
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(51,684 |
) |
|
|
— |
|
|
|
— |
|
|
|
(51,684 |
) |
Postretirement
liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
adjustment
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
9,918 |
|
|
|
— |
|
|
|
— |
|
|
|
9,918 |
|
Foreign
currency
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
translation
adjustment
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
10,568 |
|
|
|
— |
|
|
|
— |
|
|
|
10,568 |
|
Total
comprehensive loss
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(154,472 |
) |
Dividends
on preferred stocks
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(685 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(685 |
) |
Dividends
on common stock
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(115,832 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(115,832 |
) |
Tax
benefit on stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation
|
|
|
— |
|
|
|
— |
|
|
|
(117 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(117 |
) |
Issuance
of common stock
|
|
|
4,180,982 |
|
|
|
4,181 |
|
|
|
77,496 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
81,677 |
|
Balance
at December 31, 2009
|
|
|
188,389,265 |
|
|
$ |
188,389 |
|
|
$ |
1,015,678 |
|
|
$ |
1,377,039 |
|
|
$ |
(20,833 |
) |
|
|
(538,921 |
) |
|
$ |
(3,626 |
) |
|
$ |
2,556,647 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
Consolidated
Statements of Cash Flows
Years
ended December 31,
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Operating
activities:
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
(123,274 |
) |
|
$ |
293,673 |
|
|
$ |
432,120 |
|
Income
from discontinued operations, net of tax
|
|
|
— |
|
|
|
— |
|
|
|
109,334 |
|
Income
(loss) from continuing operations
|
|
|
(123,274 |
) |
|
|
293,673 |
|
|
|
322,786 |
|
Adjustments
to reconcile net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
to
net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
330,542 |
|
|
|
366,020 |
|
|
|
301,932 |
|
Earnings,
net of distributions, from equity
|
|
|
|
|
|
|
|
|
|
|
|
|
method
investments
|
|
|
(3,018 |
) |
|
|
365 |
|
|
|
(14,031 |
) |
Deferred
income taxes
|
|
|
(169,764 |
) |
|
|
64,890 |
|
|
|
67,272 |
|
Write-down
of natural gas and oil properties (Note 1)
|
|
|
620,000 |
|
|
|
135,800 |
|
|
|
— |
|
Changes
in current assets and liabilities, net of
|
|
|
|
|
|
|
|
|
|
|
|
|
acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
132,939 |
|
|
|
27,165 |
|
|
|
(40,256 |
) |
Inventories
|
|
|
13,969 |
|
|
|
(18,574 |
) |
|
|
(7,130 |
) |
Other
current assets
|
|
|
67,803 |
|
|
|
(64,771 |
) |
|
|
(7,356 |
) |
Accounts
payable
|
|
|
(61,867 |
) |
|
|
28,205 |
|
|
|
24,702 |
|
Other
current liabilities
|
|
|
44,039 |
|
|
|
(38,738 |
) |
|
|
(22,932 |
) |
Other
noncurrent changes
|
|
|
(4,683 |
) |
|
|
(7,848 |
) |
|
|
9,594 |
|
Net
cash provided by continuing operations
|
|
|
846,686 |
|
|
|
786,187 |
|
|
|
634,581 |
|
Net
cash used in discontinued operations
|
|
|
— |
|
|
|
— |
|
|
|
(71,389 |
) |
Net cash provided by operating activities
|
|
|
846,686 |
|
|
|
786,187 |
|
|
|
563,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(448,675 |
) |
|
|
(746,478 |
) |
|
|
(558,283 |
) |
Acquisitions,
net of cash acquired
|
|
|
(6,410 |
) |
|
|
(533,543 |
) |
|
|
(348,490 |
) |
Net
proceeds from sale or disposition of property
|
|
|
26,679 |
|
|
|
86,927 |
|
|
|
24,983 |
|
Investments
|
|
|
(3,740 |
) |
|
|
85,773 |
|
|
|
(67,140 |
) |
Proceeds
from sale of equity method investments
|
|
|
— |
|
|
|
— |
|
|
|
58,450 |
|
Net
cash used in continuing operations
|
|
|
(432,146 |
) |
|
|
(1,107,321 |
) |
|
|
(890,480 |
) |
Net
cash provided by discontinued operations
|
|
|
— |
|
|
|
— |
|
|
|
548,216 |
|
Net
cash used in investing activities
|
|
|
(432,146 |
) |
|
|
(1,107,321 |
) |
|
|
(342,264 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of short-term borrowings
|
|
|
10,300 |
|
|
|
216,400 |
|
|
|
311,700 |
|
Repayment
of short-term borrowings
|
|
|
(105,100 |
) |
|
|
(113,000 |
) |
|
|
(310,000 |
) |
Issuance
of long-term debt
|
|
|
145,000 |
|
|
|
453,929 |
|
|
|
120,250 |
|
Repayment
of long-term debt
|
|
|
(292,907 |
) |
|
|
(200,527 |
) |
|
|
(232,464 |
) |
Proceeds
from issuance of common stock
|
|
|
65,207 |
|
|
|
15,011 |
|
|
|
17,263 |
|
Dividends
paid
|
|
|
(115,023 |
) |
|
|
(108,591 |
) |
|
|
(100,641 |
) |
Tax
benefit on stock-based compensation
|
|
|
601 |
|
|
|
4,441 |
|
|
|
5,398 |
|
Net
cash provided by (used in) continuing operations
|
|
|
(291,922 |
) |
|
|
267,663 |
|
|
|
(188,494 |
) |
Net
cash provided by discontinued operations
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Net
cash provided by (used in) financing activities
|
|
|
(291,922 |
) |
|
|
267,663 |
|
|
|
(188,494 |
) |
Effect
of exchange rate changes on cash and cash equivalents
|
|
|
782 |
|
|
|
(635 |
) |
|
|
308 |
|
Increase
(decrease) in cash and cash equivalents
|
|
|
123,400 |
|
|
|
(54,106 |
) |
|
|
32,742 |
|
Cash
and cash equivalents – beginning of year
|
|
|
51,714 |
|
|
|
105,820 |
|
|
|
73,078 |
|
Cash
and cash equivalents – end of year
|
|
$ |
175,114 |
|
|
$ |
51,714 |
|
|
$ |
105,820 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
Notes to
Consolidated Financial Statements
Note 1
– Summary of Significant Accounting Policies
Basis
of presentation
The
consolidated financial statements of the Company include the accounts of the
following businesses: electric, natural gas distribution, construction services,
pipeline and energy services, natural gas and oil production, construction
materials and contracting, and other. The electric, natural gas distribution,
and pipeline and energy services businesses are substantially all regulated.
Construction services, natural gas and oil production, construction materials
and contracting, and other are nonregulated. For further descriptions of the
Company's businesses, see Note 15. The statements also include the
ownership interests in the assets, liabilities and expenses of jointly owned
electric generating facilities.
The
Company's regulated businesses are subject to various state and federal agency
regulations. The accounting policies followed by these businesses are generally
subject to the Uniform System of Accounts of the FERC. These accounting policies
differ in some respects from those used by the Company's nonregulated
businesses.
The
Company's regulated businesses account for certain income and expense items
under the provisions of regulatory accounting, which requires these businesses
to defer as regulatory assets or liabilities certain items that would have
otherwise been reflected as expense or income, respectively, based on the
expected regulatory treatment in future rates. The expected recovery or flowback
of these deferred items generally is based on specific ratemaking decisions or
precedent for each item. Regulatory assets and liabilities are being amortized
consistently with the regulatory treatment established by the FERC and the
applicable state public service commissions. See Note 6 for more
information regarding the nature and amounts of these regulatory
deferrals.
Depreciation,
depletion and amortization expense is reported separately on the Consolidated
Statements of Income and therefore is excluded from the other line items within
operating expenses.
Cash
and cash equivalents
The
Company considers all highly liquid investments purchased with an original
maturity of three months or less to be cash equivalents.
Allowance
for doubtful accounts
The
Company's allowance for doubtful accounts as of December 31, 2009 and 2008,
was $16.6 million and $13.7 million, respectively.
Natural
gas in storage
Natural
gas in storage for the Company's regulated operations is generally carried at
average cost, or cost using the last-in, first-out method. The portion of the
cost of natural gas in storage expected to be used within one year was included
in inventories and was $35.6 million and $27.6 million at
December 31, 2009 and 2008, respectively. The remainder of natural gas in
storage, which largely represents the cost of the gas required to maintain
pressure levels for normal operating purposes, was included in other assets and
was $59.6 million and $43.4 million at December 31, 2009 and
2008, respectively.
Inventories
Inventories,
other than natural gas in storage for the Company's regulated operations,
consisted primarily of aggregates held for resale of $80.1 million and
$89.1 million, materials and supplies of $58.1 million and
$70.3 million, asphalt oil of $23.0 million and $22.1 million,
and other inventories of $53.0 million and $52.4 million, as of
December 31, 2009 and 2008, respectively. These inventories were stated at
the lower of average cost or market value.
Investments
The
Company's investments include its equity method investments as discussed in
Note 4, the cash surrender value of life insurance policies, investments in
fixed-income and equity securities and auction rate securities. Under the equity
method, investments are initially recorded at cost and adjusted for dividends
and undistributed earnings and losses. On January 1, 2008, the Company
elected to measure its investments in certain fixed-income and equity securities
at fair value with any unrealized gains and losses recorded on the Consolidated
Statements of Income. These investments had previously been accounted for as
available-for-sale investments and were recorded at fair value with any
unrealized gains and losses, net of income taxes, recorded in accumulated other
comprehensive income (loss) on the Consolidated Balance Sheets until realized.
The Company accounts for auction rate securities as available-for-sale. For more
information, see Notes 8 and 16 and comprehensive income (loss) in this
note.
Property,
plant and equipment
Additions
to property, plant and equipment are recorded at cost. When regulated assets are
retired, or otherwise disposed of in the ordinary course of business, the
original cost of the asset is charged to accumulated depreciation. With respect
to the retirement or disposal of all other assets, except for natural gas and
oil production properties as described in natural gas and oil properties in this
note, the resulting gains or losses are recognized as a component of income. The
Company is permitted to capitalize AFUDC on regulated construction projects and
to include such amounts in rate base when the related facilities are placed in
service. In addition, the Company capitalizes interest, when applicable, on
certain construction projects associated with its other operations. The amount
of AFUDC and interest capitalized was $11.5 million, $9.0 million and
$7.1 million in 2009, 2008 and 2007, respectively. Generally, property,
plant and equipment are depreciated on a straight-line basis over the average
useful lives of the assets, except for depletable aggregate reserves, which are
depleted based on the units-of-production method, and natural gas and oil
production properties, which are amortized on the units-of-production method
based on total reserves. The Company collects removal costs for plant assets in
regulated utility rates. These amounts are recorded as regulatory liabilities,
which are included in other liabilities.
Property,
plant and equipment at December 31 was as follows:
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Depreciable
|
|
|
|
2009
|
|
|
2008
|
|
|
Life
in Years
|
|
|
|
(Dollars
in thousands, where applicable)
|
|
Regulated:
|
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
|
Generation
|
|
$ |
486,710 |
|
|
$ |
408,851 |
|
|
|
58 |
|
Distribution
|
|
|
230,795 |
|
|
|
219,501 |
|
|
|
36 |
|
Transmission
|
|
|
146,373 |
|
|
|
142,081 |
|
|
|
44 |
|
Other
|
|
|
77,913 |
|
|
|
78,292 |
|
|
|
12 |
|
Natural
gas distribution:
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution
|
|
|
1,218,124 |
|
|
|
1,260,651 |
|
|
|
39 |
|
Other
|
|
|
238,084 |
|
|
|
168,836 |
|
|
|
21 |
|
Pipeline
and energy services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Transmission
|
|
|
351,019 |
|
|
|
322,276 |
|
|
|
52 |
|
Gathering
|
|
|
41,815 |
|
|
|
41,825 |
|
|
|
19 |
|
Storage
|
|
|
33,701 |
|
|
|
32,592 |
|
|
|
52 |
|
Other
|
|
|
33,283 |
|
|
|
31,925 |
|
|
|
27 |
|
Nonregulated:
|
|
|
|
|
|
|
|
|
|
|
|
|
Construction
services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
4,526 |
|
|
|
4,526 |
|
|
|
— |
|
Buildings
and improvements
|
|
|
15,110 |
|
|
|
12,913 |
|
|
|
23 |
|
Machinery,
vehicles and equipment
|
|
|
87,462 |
|
|
|
84,042 |
|
|
|
7 |
|
Other
|
|
|
9,138 |
|
|
|
9,820 |
|
|
|
5 |
|
Pipeline
and energy services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering
|
|
|
202,467 |
|
|
|
201,323 |
|
|
|
17 |
|
Other
|
|
|
12,914 |
|
|
|
10,980 |
|
|
|
10 |
|
Natural
gas and oil production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas and oil properties
|
|
|
1,993,594 |
|
|
|
2,443,946 |
|
|
|
* |
|
Other
|
|
|
35,200 |
|
|
|
33,456 |
|
|
|
9 |
|
Construction
materials and contracting:
|
|
|
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
127,928 |
|
|
|
127,279 |
|
|
|
— |
|
Buildings
and improvements
|
|
|
65,778 |
|
|
|
68,356 |
|
|
|
20 |
|
Machinery,
vehicles and equipment
|
|
|
925,747 |
|
|
|
932,545 |
|
|
|
12 |
|
Construction
in progress
|
|
|
3,733 |
|
|
|
11,488 |
|
|
|
— |
|
Aggregate
reserves
|
|
|
391,803 |
|
|
|
384,361 |
|
|
|
** |
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
2,942 |
|
|
|
2,942 |
|
|
|
— |
|
Other
|
|
|
30,423 |
|
|
|
27,430 |
|
|
|
19 |
|
Less
accumulated depreciation, depletion and amortization
|
|
|
2,872,465 |
|
|
|
2,761,319 |
|
|
|
|
|
Net
property, plant and equipment
|
|
$ |
3,894,117 |
|
|
$ |
4,300,918 |
|
|
|
|
|
*Amortized on the
units-of-production method based on total proved reserves at an Mcf
equivalent average rate of $1.64, $2.00 and $1.59 for the years ended
December 31, 2009, 2008 and 2007, respectively. Includes natural gas
and oil production properties accounted for under the full-cost method, of
which $178.2 million and $232.1 million were excluded from
amortization at December 31, 2009 and 2008,
respectively.
|
|
**
Depleted on the units-of-production method.
|
|
Impairment
of long-lived assets
The
Company reviews the carrying values of its long-lived assets, excluding goodwill
and natural gas and oil properties, whenever events or changes in circumstances
indicate that such carrying values may not be recoverable. The determination of
whether an impairment has occurred is based on an estimate of undiscounted
future cash flows attributable to the assets, compared to the carrying value of
the assets. If impairment has occurred, the amount of the impairment recognized
is determined by estimating the fair value of the assets and recording a loss if
the carrying value is greater than the fair value. No significant impairment
losses were recorded in 2009, 2008 and 2007. Unforeseen events and changes in
circumstances could require the recognition of other impairment losses at some
future date.
Goodwill
Goodwill
represents the excess of the purchase price over the fair value of identifiable
net tangible and intangible assets acquired in a business combination. Goodwill
is required to be tested for impairment annually, which is completed in the
fourth quarter, or more frequently if events or changes in circumstances
indicate that goodwill may be impaired. For more information on goodwill, see
Note 5.
Natural
gas and oil properties
The
Company uses the full-cost method of accounting for its natural gas and oil
production activities. Under this method, all costs incurred in the acquisition,
exploration and development of natural gas and oil properties are capitalized
and amortized on the units-of-production method based on total proved reserves.
Any conveyances of properties, including gains or losses on abandonments of
properties, are treated as adjustments to the cost of the properties with no
gain or loss recognized.
Capitalized
costs are subject to a “ceiling test” that limits such costs to the aggregate of
the present value of future net cash flows from proved reserves discounted at 10
percent, as mandated under the rules of the SEC, plus the cost of unproved
properties less applicable income taxes. Future net revenue was estimated based
on end-of-quarter spot market prices adjusted for contracted price changes prior
to the fourth quarter of 2009. Effective December 31, 2009, the Modernization of
Oil and Gas Reporting rules issued by the SEC changed the pricing used to
estimate reserves and associated future cash flows to SEC Defined Prices. Prior
to that date, if capitalized costs exceeded the full-cost ceiling at the end of
any quarter, a permanent noncash write-down was required to be charged to
earnings in that quarter unless subsequent price changes eliminated or reduced
an indicated write-down. Effective December 31, 2009, if capitalized costs
exceed the full-cost ceiling at the end of any quarter, a permanent noncash
write-down is required to be charged to earnings in that quarter regardless of
subsequent price changes.
Due to
low natural gas and oil prices that existed on March 31, 2009, and
December 31, 2008, the Company's capitalized costs under the full-cost
method of accounting exceeded the full-cost ceiling at March 31, 2009, and
December 31, 2008. Accordingly, the Company was required to write down its
natural gas and oil producing properties. The noncash write-downs amounted to
$620.0 million and $135.8 million ($384.4 million and
$84.2 million after tax) for the years ended December 31, 2009 and
2008, respectively.
The
Company hedges a portion of its natural gas and oil production and the effects
of the cash flow hedges were used in determining the full-cost ceiling. The
Company would have recognized additional write-downs of its natural gas and oil
properties of $107.9 million ($66.9 million after tax) at March 31, 2009, and
$79.2 million ($49.1 million after tax) at December 31, 2008, if
the
effects
of cash flow hedges had not been considered in calculating the full-cost
ceiling. For more information on the Company's cash flow hedges, see
Note 7.
At
December 31, 2009, the Company’s full-cost ceiling exceeded the Company’s
capitalized cost. However, sustained downward movements in natural gas and oil
prices subsequent to December 31, 2009, could result in a future write-down of
the Company’s natural gas and oil properties.
The
following table summarizes the Company's natural gas and oil properties not
subject to amortization at December 31, 2009, in total and by the year in
which such costs were incurred:
|
|
|
|
|
Year
Costs Incurred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
Total
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
and
prior
|
|
|
|
(In
thousands)
|
|
Acquisition
|
|
$ |
122,806 |
|
|
$ |
4,287 |
|
|
$ |
81,954 |
|
|
$ |
7,972 |
|
|
$ |
28,593 |
|
Development
|
|
|
20,377 |
|
|
|
9,997 |
|
|
|
7,149 |
|
|
|
3,231 |
|
|
|
— |
|
Exploration
|
|
|
28,216 |
|
|
|
19,311 |
|
|
|
8,093 |
|
|
|
811 |
|
|
|
1 |
|
Capitalized
interest
|
|
|
6,815 |
|
|
|
1,336 |
|
|
|
3,865 |
|
|
|
478 |
|
|
|
1,136 |
|
Total
costs not subject
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
to
amortization
|
|
$ |
178,214 |
|
|
$ |
34,931 |
|
|
$ |
101,061 |
|
|
$ |
12,492 |
|
|
$ |
29,730 |
|
Costs not
subject to amortization as of December 31, 2009, consisted primarily of
unevaluated leaseholds, drilling costs, seismic costs and capitalized interest
associated primarily with natural gas and oil development in the Paradox Basin
in Utah; Big Horn Basin in Wyoming; east Texas properties; and CBNG in the
Powder River Basin of Wyoming and Montana. The Company expects that the majority
of these costs will be evaluated within the next five years and included in the
amortization base as the properties are evaluated and/or developed.
Revenue
recognition
Revenue
is recognized when the earnings process is complete, as evidenced by an
agreement between the customer and the Company, when delivery has occurred or
services have been rendered, when the fee is fixed or determinable and when
collection is reasonably assured. The Company recognizes utility revenue each
month based on the services provided to all utility customers during the month.
Accrued unbilled revenue which is included in receivables, net, represents
revenues recognized in excess of amounts billed. Accrued unbilled revenue at
Montana-Dakota, Cascade and Intermountain was $92.6 million and
$123.2 million at December 31, 2009 and 2008, respectively. The
Company recognizes construction contract revenue at its construction businesses
using the percentage-of-completion method as discussed later. The Company
recognizes revenue from natural gas and oil production properties only on that
portion of production sold and allocable to the Company's ownership interest in
the related well. The Company recognizes all other revenues when services are
rendered or goods are delivered. The Company presents revenues net of taxes
collected from customers at the time of sale to be remitted to governmental
authorities, including sales and use taxes.
Percentage-of-completion
method
The
Company recognizes construction contract revenue from fixed-price and modified
fixed-price construction contracts at its construction businesses using
the percentage-of-completion method, measured by the percentage of
costs incurred to date to estimated total costs for each contract. If a loss is
anticipated on a contract, the loss is immediately recognized. Costs and
estimated earnings in excess of billings on uncompleted contracts of
$28.8 million and $40.1 million at December 31, 2009 and 2008,
respectively, represent revenues recognized in excess of amounts billed and
were
included
in receivables, net. Billings in excess of costs and estimated earnings on
uncompleted contracts of $49.3 million and $106.9 million at
December 31, 2009 and 2008, respectively, represent billings in excess of
revenues recognized and were included in accounts payable. Amounts representing
balances billed but not paid by customers under retainage provisions in
contracts amounted to $45.4 million and $86.9 million at
December 31, 2009 and 2008, respectively. The amounts expected to be paid
within one year or less are included in receivables, net, and amounted to
$44.0 million and $67.7 million at December 31, 2009 and 2008,
respectively. The long-term retainage which was included in deferred charges and
other assets – other was $1.4 million and $19.2 million at
December 31, 2009 and 2008, respectively.
Derivative
instruments
The
Company's policy allows the use of derivative instruments as part of an overall
energy price, foreign currency and interest rate risk management program to
efficiently manage and minimize commodity price, foreign currency and interest
rate risk. The Company's policy prohibits the use of derivative instruments for
speculating to take advantage of market trends and conditions, and the Company
has procedures in place to monitor compliance with its policies. The Company is
exposed to credit-related losses in relation to derivative instruments in the
event of nonperformance by counterparties.
The
Company's policy generally allows the hedging of monthly forecasted natural gas
and oil production at Fidelity for a period up to 36 months from the time the
Company enters into the hedge. The Company's policy requires that interest rate
derivative instruments not exceed a period of 24 months and foreign currency
derivative instruments not exceed a 12-month period. The Company's policy allows
the hedging of monthly forecasted purchases of natural gas at Cascade and
Intermountain for a period up to three years.
The
Company’s policy requires that each month as physical natural gas and oil
production at Fidelity occurs and the commodity is sold, the related portion of
the derivative agreement for that month’s production must settle with its
counterparties. Settlements represent the exchange of cash between the Company
and its counterparties based on the notional quantities and prices for each
month’s physical delivery as specified within the agreements. The fair value of
the remaining notional amounts on the derivative agreements is recorded on the
balance sheet as an asset or liability measured at fair value, with the
unrealized gains or losses recognized as a component of accumulated other
comprehensive income (loss). The Company's policy also requires settlement of
natural gas derivative instruments at Cascade and Intermountain monthly and all
interest rate derivative transactions must be settled over a period that will
not exceed 90 days, and any foreign currency derivative transaction settlement
periods may not exceed a 12-month period. The Company has policies and
procedures that management believes minimize credit-risk exposure. Accordingly,
the Company does not anticipate any material effect on its financial position or
results of operations as a result of nonperformance by counterparties. For more
information on derivative instruments, see Note 7.
The
Company's swap and collar agreements are reflected at fair value, based upon
futures prices, volatility and time to maturity, among other
things.
Asset
retirement obligations
The
Company records the fair value of a liability for an asset retirement obligation
in the period in which it is incurred. When the liability is initially recorded,
the Company capitalizes a cost by increasing the carrying amount of the related
long-lived asset. Over time, the liability is accreted to its present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, the Company either settles the
obligation for the
recorded
amount or incurs a gain or loss at its nonregulated operations or incurs a
regulatory asset or liability at its regulated operations. For more information
on asset retirement obligations, see Note 10.
Natural
gas costs recoverable or refundable through rate adjustments
Under the
terms of certain orders of the applicable state public service commissions, the
Company is deferring natural gas commodity, transportation and storage costs
that are greater or less than amounts presently being recovered through its
existing rate schedules. Such orders generally provide that these amounts are
recoverable or refundable through rate adjustments within a period ranging from
12 to 28 months from the time such costs are paid. Natural gas costs refundable
through rate adjustments were $37.4 million and $64,000 at December 31,
2009 and 2008, respectively, which is included in other accrued liabilities.
Natural gas costs recoverable through rate adjustments were $982,000 and
$51.7 million at December 31, 2009 and 2008, respectively, which is
included in prepayments and other current assets.
Insurance
Certain
subsidiaries of the Company are insured for workers' compensation losses,
subject to deductibles ranging up to $1 million per occurrence. Automobile
liability and general liability losses are insured, subject to deductibles
ranging up to $1 million per accident or occurrence. These subsidiaries
have excess coverage above the primary automobile and general liability policies
on a claims first-made and reported basis beyond the deductible levels. The
subsidiaries of the Company are retaining losses up to the deductible amounts
accrued on the basis of estimates of liability for claims incurred and for
claims incurred but not reported.
Income
taxes
The
Company provides deferred federal and state income taxes on all temporary
differences between the book and tax basis of the Company's assets and
liabilities. Excess deferred income tax balances associated with the Company's
rate-regulated activities have been recorded as a regulatory liability and are
included in other liabilities. These regulatory liabilities are expected to be
reflected as a reduction in future rates charged to customers in accordance with
applicable regulatory procedures.
The
Company uses the deferral method of accounting for investment tax credits and
amortizes the credits on regulated electric and natural gas distribution plant
over various periods that conform to the ratemaking treatment prescribed by the
applicable state public service commissions.
Tax
positions taken or expected to be taken in an income tax return are evaluated
for recognition using a more-likely-than-not threshold, and those tax positions
requiring recognition are measured as the largest amount of tax benefit that is
greater than 50 percent likely of being realized upon ultimate settlement with a
taxing authority. The Company recognizes interest and penalties accrued related
to unrecognized tax benefits in income taxes.
Foreign
currency translation adjustment
The
functional currency of the Company's investment in the Brazilian Transmission
Lines, as further discussed in Note 4, is the Brazilian Real. Translation
from the Brazilian Real to the U.S. dollar for assets and liabilities is
performed using the exchange rate in effect at the balance sheet date. Revenues
and expenses are translated on a year-to-date basis using weighted average daily
exchange rates. Adjustments resulting from such translations are reported as a
separate component of other comprehensive income (loss) in common stockholders'
equity.
Transaction
gains and losses resulting from the effect of exchange rate changes on
transactions denominated in a currency other than the functional currency of the
reporting entity would be recorded in income.
Earnings
(loss) per common share
Basic
earnings (loss) per common share were computed by dividing earnings (loss) on
common stock by the weighted average number of shares of common stock
outstanding during the year. Diluted earnings per common share were computed by
dividing earnings on common stock by the total of the weighted average number of
shares of common stock outstanding during the year, plus the effect of
outstanding stock options, restricted stock grants and performance share awards.
In 2008 and 2007, there were no shares excluded from the calculation of diluted
earnings per share. Diluted loss per common share for 2009 was computed by
dividing the loss on common stock by the weighted average number of shares of
common stock outstanding during the year. Due to the loss on common stock for
2009, the effect of outstanding stock options, restricted stock grants and
performance share awards was excluded from the computation of diluted loss per
common share as their effect was antidilutive. Common stock outstanding includes
issued shares less shares held in treasury.
Use
of estimates
The
preparation of financial statements in conformity with GAAP requires the Company
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, as well as the reported amounts of revenues and
expenses during the reporting period. Estimates are used for items such as
impairment testing of long-lived assets, goodwill and natural gas and oil
properties; fair values of acquired assets and liabilities under the purchase
method of accounting; natural gas and oil reserves; aggregate reserves; property
depreciable lives; tax provisions; uncollectible accounts; environmental and
other loss contingencies; accumulated provision for revenues subject to refund;
costs on construction contracts; unbilled revenues; actuarially determined
benefit costs; asset retirement obligations; the valuation of stock-based
compensation; and the fair value of derivative instruments. As additional
information becomes available, or actual amounts are determinable, the recorded
estimates are revised. Consequently, operating results can be affected by
revisions to prior accounting estimates.
Cash
flow information
Cash
expenditures for interest and income taxes were as follows:
Years
ended December 31,
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Interest,
net of amount capitalized
|
|
$ |
81,267 |
|
|
$ |
77,152 |
|
|
$ |
74,404 |
|
Income
taxes
|
|
$ |
39,807 |
|
|
$ |
113,212 |
|
|
$ |
214,573 |
|
Income
taxes paid for the year ended December 31, 2007, were higher than the
amount paid for the years ended December 31, 2009 and 2008, primarily due
to higher estimated quarterly tax payments paid in 2007 due in large part to the
gain on the sale of the domestic independent power production assets as
discussed in Note 3.
New
accounting standards
Codification
In June 2009, the FASB established the ASC as the source of
authoritative generally accepted accounting principles recognized by the FASB.
The ASC is a reorganization of GAAP into a topical format. It was effective for
the Company in the third quarter of 2009. The adoption of the Codification
required the Company to revise its disclosures when referencing generally
accepted accounting principles.
Fair Value
Measurements and Disclosures In September 2006, the FASB established
guidance that defines fair value, establishes a framework for measuring fair
value and expands disclosures about fair value measurements. The guidance
applies under other accounting pronouncements that require or permit fair value
measurements with certain exceptions and was effective for the Company on
January 1, 2008. In February 2008, this guidance was revised to delay the
effective date for certain nonfinancial assets and nonfinancial liabilities to
January 1, 2009. The types of assets and liabilities that are recognized at
fair value effective January 1, 2009, due to the delayed effective date,
include nonfinancial assets and nonfinancial liabilities initially measured at
fair value in a business combination or new basis event, certain fair value
measurements associated with goodwill impairment testing, indefinite-lived
intangible assets and nonfinancial long-lived assets measured at fair value for
impairment assessment, and asset retirement obligations initially measured at
fair value. The adoption of the fair value measurements and disclosure guidance,
including the application to certain nonfinancial assets and nonfinancial
liabilities with a delayed effective date of January 1, 2009, did not have
a material effect on the Company's financial position or results of
operations.
Business
Combinations In December 2007,
the FASB issued guidance related to business combinations that requires an
acquirer to recognize and measure the assets acquired, liabilities assumed and
any noncontrolling interests in the acquiree at the acquisition date, measured
at their fair values as of that date, with limited exception. The business
combination guidance also requires that acquisition-related costs will be
generally expensed as incurred, and expands the disclosure requirements for
business combinations. In addition, the business combination guidance was
amended and clarified to address application issues raised in regard to initial
recognition and measurement, subsequent measurement and accounting, and
disclosure of assets and liabilities arising from contingencies in a business
combination. This guidance and its amendments were effective for the Company on
January 1, 2009. The adoption of the business combination guidance and its
amendments did not have a material effect on the Company’s financial position or
results of operations.
Noncontrolling
Interests In December 2007, the FASB established accounting and
reporting standards for the noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary. This guidance was effective for the Company on
January 1, 2009. The adoption of the noncontrolling interest guidance did
not have a material effect on the Company’s financial position or results of
operations.
Derivative
Instruments and Hedging Activities In March 2008, the FASB released
guidance related to derivative instruments and hedging activities that requires
enhanced disclosures about an entity’s derivative and hedging activities
including how and why an entity uses derivative instruments, how derivative
instruments and related hedged items are accounted for, and how derivative
instruments and related hedged items affect an entity’s financial position,
financial performance and cash flows. This guidance was effective for the
Company on January 1, 2009. The adoption of the derivative instruments and
hedging activities guidance requires additional disclosures regarding the
Company’s derivative instruments; however, it did not impact the Company’s
financial position or results of operations.
Pensions and
Other Postretirement Benefits In December 2008, the FASB issued
guidance on an employer’s disclosures about plan assets of a defined benefit
pension or other postretirement plan to provide users of financial statements
with an understanding of how investment allocation decisions are made, the major
categories of plan assets, the inputs and valuation techniques used to measure
the fair value of plan assets, the effect of fair value measurements using
significant unobservable inputs on changes in plan assets for the period and
significant concentrations of risk within plan assets. This guidance was
effective for the Company on January 1, 2009. The adoption of the pension
and other postretirement benefits guidance required additional disclosures
regarding the Company's defined benefit pension and other postretirement plans
in the annual financial statements; however, it did not impact the Company's
financial position or results of operations.
Modernization of
Oil and Gas Reporting In January 2009, the SEC adopted final rules
amending its oil and gas reporting requirements. The new rules include changes
to the pricing used to estimate reserves, the ability to include nontraditional
resources in reserves, the use of new technology for determining reserves and
permitting disclosure of probable and possible reserves. The final rules were
effective on December 31, 2009. For information on the impacts of adopting
the SEC’s final rules for oil and gas reporting, see Supplementary Financial
Information.
Financial
Instruments In April 2009, the FASB issued guidance that requires
disclosures about the fair value of financial instruments for interim reporting
periods of publicly traded companies as well as in annual financial statements,
which was effective for the Company in the second quarter of 2009. The adoption
of the financial instruments guidance required additional disclosures regarding
the Company’s fair value of financial instruments; however, it did not impact
the Company’s financial position or results of operations.
Subsequent
Events In May 2009, the FASB issued subsequent events guidance which
establishes standards of accounting for and disclosure of events that occur
after the balance sheet date but before financial statements are issued or are
available to be issued. In addition it requires disclosure of the date through
which the Company has evaluated subsequent events and whether it represents the
date the financial statements were issued or were available to be issued. This
guidance was effective for the Company on June 30, 2009. The adoption of
the subsequent events guidance did not have a material effect on the Company’s
financial position or results of operations.
Variable Interest
Entities In June 2009, the FASB issued guidance related to variable
interest entities which changes how a reporting entity determines when an entity
that is insufficiently capitalized or is not controlled through voting rights
should be consolidated and modifies the approach for determining the primary
beneficiary of a variable interest entity. This guidance will require a
reporting entity to provide additional disclosures about its involvement with
variable interest entities and any significant changes in risk exposure due to
that involvement. The guidance related to variable interest entities was
effective for the Company on January 1, 2010. The adoption of this guidance
did not have a material effect on the Company’s financial position or results of
operations.
Oil and Gas
Reserve Estimation and Disclosure In January 2010, the FASB issued
guidance related to oil and gas reserve estimation and disclosure requirements,
which aligned the current oil and gas reserve estimation and disclosures with
those of the SEC’s final rule, Modernization of Oil and Gas Reporting, and
requires disclosure in the first annual period of the estimated effect of the
initial application of the guidance. The guidance related to oil and gas reserve
estimation and disclosure was effective for the Company on December 31,
2009. For more information on the
effects
of adopting the oil and gas reserve estimation and disclosure guidance, see
Supplementary Financial Information.
Improving
Disclosure About Fair Value Measurements In January 2010, the FASB issued
guidance related to improving disclosures about fair value measurements. The
guidance requires separate disclosures of the amounts of transfers in and out of
Level 1 and Level 2 fair value measurements and a description of the reason for
such transfers. In the reconciliation for Level 3 fair value measurements using
significant unobservable inputs, information about purchases, sales, issuances
and settlements shall be presented separately. These disclosures are required
for interim and annual reporting periods and were effective for the Company on
January 1, 2010, except for the disclosures related to the purchases, sales,
issuances and settlements in the roll forward activity of Level 3 fair value
measurements, which are effective on January 1, 2011. The guidance will
require additional disclosures but will not impact the Company’s financial
position or results of operations.
Comprehensive
income (loss)
Comprehensive
income (loss) is the sum of net income (loss) as reported and other
comprehensive income (loss). The Company's other comprehensive income (loss)
resulted from gains (losses) on derivative instruments qualifying as hedges,
postretirement liability adjustments, foreign currency translation adjustments
and gains on available-for-sale investments. For more information on derivative
instruments, see Note 7.
The
components of other comprehensive income (loss), and their related tax effects
for the years ended December 31, 2009, 2008 and 2007, were as
follows:
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Other
comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
Net
unrealized gain (loss) on derivative instruments
|
|
|
|
|
|
|
|
|
|
qualifying
as hedges:
|
|
|
|
|
|
|
|
|
|
Net
unrealized gain (loss) on derivative instruments
|
|
|
|
|
|
|
|
|
|
arising
during the period, net of tax of
|
|
|
|
|
|
|
|
|
|
$(2,509),
$30,414 and $3,989 in 2009,
|
|
|
|
|
|
|
|
|
|
2008
and 2007, respectively
|
|
$ |
(4,094 |
) |
|
$ |
49,623 |
|
|
$ |
6,508 |
|
Less:
Reclassification adjustment for gain on
|
|
|
|
|
|
|
|
|
|
|
|
|
derivative
instruments included in net income,
|
|
|
|
|
|
|
|
|
|
|
|
|
net
of tax of $29,170, $3,795 and $12,504 in
|
|
|
|
|
|
|
|
|
|
|
|
|
2009,
2008 and 2007, respectively
|
|
|
47,590 |
|
|
|
6,175 |
|
|
|
20,013 |
|
Net
unrealized gain (loss) on derivative
|
|
|
|
|
|
|
|
|
|
|
|
|
instruments
qualifying as hedges
|
|
|
(51,684 |
) |
|
|
43,448 |
|
|
|
(13,505 |
) |
Postretirement
liability adjustment, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
of
$6,291, $(8,750) and $1,835 in 2009,
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
and 2007, respectively
|
|
|
9,918 |
|
|
|
(13,751 |
) |
|
|
3,012 |
|
Foreign
currency translation adjustment, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
of
$6,814, $(6,108) and $3,606 in 2009, 2008 and 2007,
respectively
|
|
|
10,568 |
|
|
|
(9,534 |
) |
|
|
7,177 |
|
Net
unrealized gain on available-for-sale
|
|
|
|
|
|
|
|
|
|
|
|
|
investments,
net of tax of $270 in 2007
|
|
|
— |
|
|
|
— |
|
|
|
405 |
|
Total
other comprehensive income (loss)
|
|
$ |
(31,198 |
) |
|
$ |
20,163 |
|
|
$ |
(2,911 |
) |
The
after-tax components of accumulated other comprehensive income (loss) as of
December 31, 2009, 2008 and 2007, were as follows:
|
|
Net
Unrealized
Gain
(Loss) on
Derivative
Instruments
Qualifying
as
Hedges
|
|
|
Post-retirement
Liability
Adjustment
|
|
|
Foreign
Currency
Translation
Adjustment
|
|
|
Net
Unrealized
Gain
on
Available-for-sale Investments
|
|
|
Total
Accumulated
Other
Comprehensive
Income
(Loss)
|
|
|
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
Balance
at December 31, 2007
|
|
$ |
5,938 |
|
|
$ |
(21,330 |
) |
|
$ |
5,594 |
|
|
$ |
405 |
|
|
$ |
(9,393 |
) |
Balance
at December 31, 2008
|
|
$ |
49,386 |
|
|
$ |
(35,081 |
) |
|
$ |
(3,940 |
) |
|
$ |
— |
|
|
$ |
10,365 |
|
Balance
at December 31, 2009
|
|
$ |
(2,298 |
) |
|
$ |
(25,163 |
) |
|
$ |
6,628 |
|
|
$ |
— |
|
|
$ |
(20,833 |
) |
Note 2
– Acquisitions
In 2009,
the Company acquired a pipeline and energy services business in Montana which
was not material. The total purchase consideration for this business and
purchase price adjustments with respect to certain other acquisitions made prior
to 2009, consisting of the Company’s common stock and cash, was
$22.0 million.
In 2008,
the Company acquired a construction services business in Nevada; natural gas
properties in Texas; construction materials and contracting businesses in
Alaska, California, Idaho and Texas; and Intermountain, a natural gas
distribution business, as discussed below. The total purchase consideration for
these businesses and properties and purchase price adjustments with respect to
certain other acquisitions made prior to 2008, consisting of the Company’s
common stock and cash and the outstanding indebtedness of Intermountain, was
$624.5 million.
On
October 1, 2008, the acquisition of Intermountain was finalized and
Intermountain became an indirect wholly owned subsidiary of the Company.
Intermountain’s service area is in Idaho.
In 2007,
the Company acquired construction materials and contracting businesses in North
Dakota, Texas and Wyoming; a construction services business in Nevada; and
Cascade, a natural gas distribution business, as discussed below. The total
purchase consideration for these businesses and properties and purchase price
adjustments with respect to certain other acquisitions made prior to 2007,
consisting of the Company's common stock and cash and the outstanding
indebtedness of Cascade, was $526.3 million.
On
July 2, 2007, the acquisition of Cascade was finalized and Cascade became
an indirect wholly owned subsidiary of the Company. Cascade's natural gas
service areas are in Washington and Oregon.
The above
acquisitions were accounted for under the purchase method of accounting and,
accordingly, the acquired assets and liabilities assumed have been preliminarily
recorded at their respective fair values as of the date of acquisition. On the
above acquisition made in 2009, a final fair market value is pending the
completion of the review of the relevant assets and liabilities as of the
acquisition date. The results of operations of the acquired businesses and
properties are included in the financial statements since the date of each
acquisition. Pro forma financial amounts reflecting the effects of the above
acquisitions are not presented, as such acquisitions were not material to the
Company's financial position or results of operations.
Note 3
– Discontinued Operations
Innovatum,
a component of the pipeline and energy services segment, specialized in cable
and pipeline magnetization and location. During the third quarter of 2006, the
Company initiated a plan to sell Innovatum because the Company determined that
Innovatum is a non-strategic asset. During the fourth quarter of 2006, the stock
and a portion of the assets of Innovatum were sold and the Company sold the
remaining assets of Innovatum in January 2008. The loss on disposal of
Innovatum was not material.
During
the fourth quarter of 2006, the Company initiated a plan to sell certain of the
domestic assets of Centennial Resources. The plan to sell was based on the
increased market demand for independent power production assets, combined with
the Company's desire to efficiently fund future capital needs. The Company
subsequently committed to a plan to sell CEM due to strong interest in the
operations of CEM during the bidding process for the domestic independent power
production assets in the first quarter of 2007.
In July
2007, Centennial Resources sold its domestic independent power production
business consisting of Centennial Power and CEM to Bicent Power LLC (formerly
known as Montana Acquisition Company LLC). The transaction was valued at
$636 million, which included the assumption of approximately
$36 million of project-related debt. The gain on the sale of the assets,
excluding the gain on the sale of Hartwell as discussed in Note 4, was
approximately $85.4 million (after tax).
The
Company's consolidated financial statements and accompanying notes for prior
periods present the results of operations of Innovatum and the domestic
independent power production assets as discontinued operations. In addition, the
assets and liabilities of these operations were treated as held for sale, and as
a result, no depreciation, depletion and amortization expense was recorded from
the time each of the assets was classified as held for sale.
Operating
results related to Innovatum for the year ended December 31, 2007, were as
follows:
|
|
2007
|
|
(In
thousands)
|
|
Operating
revenues
|
|
$ |
1,748 |
|
Loss
from discontinued operations before income tax benefit
|
|
|
(210 |
) |
Income
tax benefit
|
|
|
(316 |
) |
Income
from discontinued operations, net of tax
|
|
$ |
106 |
|
Operating
results related to the domestic independent power production assets for the year
ended December 31, 2007, were as follows:
|
|
2007
|
|
(In
thousands)
|
|
Operating
revenues
|
|
$ |
125,867 |
|
Income
from discontinued operations (including gain on disposal in 2007 of
$142.4 million) before income tax expense
|
|
|
177,666 |
|
Income
tax expense
|
|
|
68,438 |
|
Income
from discontinued operations, net of tax
|
|
$ |
109,228 |
|
Revenues
at the former independent power production operations were recognized based on
electricity delivered and capacity provided, pursuant to contractual commitments
and, where applicable, revenues were recognized ratably over the terms of the
related contract. Arrangements
with
multiple revenue-generating activities were recognized with the multiple
deliverables divided into separate units of accounting based on specific
criteria and revenues of the arrangements allocated to the separate units based
on their relative fair values.
Note 4
– Equity Method Investments
Investments
in companies in which the Company has the ability to exercise significant
influence over operating and financial policies are accounted for using the
equity method. The Company's equity method investments at December 31, 2009
and 2008, include the Brazilian Transmission Lines.
In
August 2006, MDU Brasil acquired ownership interests in companies owning
the Brazilian Transmission Lines. The interests involve the ENTE (13.3-percent
ownership interest), ERTE (13.3-percent ownership interest) and ECTE (25-percent
ownership interest) electric transmission lines, which are primarily in
northeastern and southern Brazil. The transmission contracts provide for
revenues denominated in the Brazilian Real, annual inflation adjustments and
change in tax law adjustments and have between 21 and 23 years remaining under
the contracts. Alusa and CEMIG hold the remaining ownership interests, with
CELESC also having an ownership interest in ECTE. The functional currency for
the Brazilian Transmission Lines is the Brazilian Real.
In the
fourth quarter of 2009, multiple sales agreements were signed with three
separate parties for the Company to sell its ownership interests in the
Brazilian Transmission Lines. This sale is pending regulatory approvals. One of
the parties will purchase 15.6 percent of the Company’s ownership interests
over a four-year period. The other parties will purchase 84.4 percent of the
Company’s ownership interests at the financial close of the
transaction.
In
September 2004, Centennial Resources, through indirect wholly owned
subsidiaries, acquired a 50 percent ownership interest in Hartwell, which owns a
310-MW natural gas-fired electric generating facility near Hartwell, Georgia. In
July 2007, the Company sold its ownership interest in Hartwell, and realized a
gain of $10.1 million ($6.1 million after tax) from the sale which is
recorded in earnings from equity method investments on the Consolidated
Statements of Income.
At
December 31, 2009 and 2008, the investments in which the Company held an
equity method interest had total assets of $387.0 million and
$294.7 million, respectively, and long-term debt of $176.7 million and
$158.0 million, respectively. The Company's investment in its equity method
investments was approximately $62.4 million and $44.4 million,
including undistributed earnings of $9.3 million and $6.8 million, at
December 31, 2009 and 2008, respectively.
Note 5
– Goodwill and Other Intangible Assets
The
changes in the carrying amount of goodwill for the year ended December 31,
2009, were as follows:
|
|
Balance
|
|
|
Goodwill
|
|
|
Balance
|
|
|
|
as
of
|
|
|
Acquired
|
|
|
as
of
|
|
|
|
January 1,
|
|
|
During
|
|
|
December 31,
|
|
|
|
2009
|
|
|
the
Year*
|
|
|
2009
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Natural
gas distribution
|
|
|
344,952 |
|
|
|
784 |
|
|
|
345,736 |
|
Construction
services
|
|
|
95,619 |
|
|
|
4,508 |
|
|
|
100,127 |
|
Pipeline
and energy services
|
|
|
1,159 |
|
|
|
6,698 |
|
|
|
7,857 |
|
Natural
gas and oil production
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Construction
materials and contracting
|
|
|
174,005 |
|
|
|
1,738 |
|
|
|
175,743 |
|
Other
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Total
|
|
$ |
615,735 |
|
|
$ |
13,728 |
|
|
$ |
629,463 |
|
*
Includes purchase price adjustments that were not material related to
acquisitions in a prior period.
|
|
The
changes in the carrying amount of goodwill for the year ended December 31,
2008, were as follows:
|
|
Balance
|
|
|
Goodwill
|
|
|
Balance
|
|
|
|
as
of
|
|
|
Acquired
|
|
|
as
of
|
|
|
|
January 1,
|
|
|
During
|
|
|
December 31,
|
|
|
|
2008
|
|
|
the
Year*
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Natural
gas distribution
|
|
|
171,129 |
|
|
|
173,823 |
|
|
|
344,952 |
|
Construction
services
|
|
|
91,385 |
|
|
|
4,234 |
|
|
|
95,619 |
|
Pipeline
and energy services
|
|
|
1,159 |
|
|
|
— |
|
|
|
1,159 |
|
Natural
gas and oil production
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Construction
materials and contracting
|
|
|
162,025 |
|
|
|
11,980 |
|
|
|
174,005 |
|
Other
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Total
|
|
$ |
425,698 |
|
|
$ |
190,037 |
|
|
$ |
615,735 |
|
*
Includes purchase price adjustments that were not material related to
acquisitions in a prior period.
|
|
Other
amortizable intangible assets at December 31 were as follows:
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
Customer
relationships
|
|
$ |
24,942 |
|
|
$ |
21,842 |
|
Accumulated
amortization
|
|
|
(9,500 |
) |
|
|
(6,985 |
) |
|
|
|
15,442 |
|
|
|
14,857 |
|
Noncompete
agreements
|
|
|
12,377 |
|
|
|
10,080 |
|
Accumulated
amortization
|
|
|
(6,675 |
) |
|
|
(5,126 |
) |
|
|
|
5,702 |
|
|
|
4,954 |
|
Other
|
|
|
10,859 |
|
|
|
10,949 |
|
Accumulated
amortization
|
|
|
(3,026 |
) |
|
|
(2,368 |
) |
|
|
|
7,833 |
|
|
|
8,581 |
|
Total
|
|
$ |
28,977 |
|
|
$ |
28,392 |
|
Amortization
expense for intangible assets for the years ended December 31, 2009, 2008
and 2007, was $5.0 million, $5.1 million and $4.4 million,
respectively. Estimated amortization expense for intangible assets is
$4.5 million in 2010, $4.0 million in 2011, $3.9 million in 2012,
$3.4 million in 2013, $3.0 million in 2014 and $10.2 million
thereafter.
Note 6
– Regulatory Assets and Liabilities
The
following table summarizes the individual components of unamortized regulatory
assets and liabilities as of December 31:
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
Regulatory
assets:
|
|
|
|
|
|
|
Pension
and postretirement benefits (a)
|
|
$ |
91,078 |
|
|
$ |
119,868 |
|
Deferred
income taxes*
|
|
|
85,712 |
|
|
|
46,855 |
|
Natural
gas supply derivatives (a) (b)
|
|
|
27,900 |
|
|
|
89,813 |
|
Costs
related to potential generation development (a)
|
|
|
15,499 |
|
|
|
— |
|
Long-term
debt refinancing costs (a)
|
|
|
12,089 |
|
|
|
9,991 |
|
Taxes
recoverable from customers (a)
|
|
|
10,102 |
|
|
|
4,824 |
|
Plant
costs (a)
|
|
|
7,775 |
|
|
|
8,534 |
|
Natural
gas cost recoverable through rate adjustments (b)
|
|
|
982 |
|
|
|
51,699 |
|
Other
(a) (b)
|
|
|
12,242 |
|
|
|
7,978 |
|
Total
regulatory assets
|
|
|
263,379 |
|
|
|
339,562 |
|
Regulatory
liabilities:
|
|
|
|
|
|
|
|
|
Plant
removal and decommissioning costs (c)
|
|
|
251,143 |
|
|
|
94,737 |
|
Deferred
income taxes*
|
|
|
53,835 |
|
|
|
65,909 |
|
Natural
gas costs refundable through rate adjustments (d)
|
|
|
37,356 |
|
|
|
64 |
|
Taxes
refundable to customers (c)
|
|
|
34,571 |
|
|
|
25,642 |
|
Natural
gas supply derivatives (c)
|
|
|
— |
|
|
|
5,540 |
|
Other
(c) (d)
|
|
|
17,767 |
|
|
|
7,460 |
|
Total
regulatory liabilities
|
|
|
394,672 |
|
|
|
199,352 |
|
Net
regulatory position
|
|
$ |
(131,293 |
) |
|
$ |
140,210 |
|
*Represents deferred income taxes
related to regulatory assets and liabilities.
(a)
Included in deferred charges and other assets on the Consolidated Balance
Sheets.
(b)
Included in prepayments and other current assets on the Consolidated
Balance Sheets.
(c)
Included in other liabilities on the Consolidated Balance
Sheets.
(d)
Included in other accrued liabilities on the Consolidated Balance
Sheets.
|
|
The
regulatory assets are expected to be recovered in rates charged to customers. A
portion of the Company's regulatory assets are not earning a return; however,
these regulatory assets are expected to be recovered from customers in future
rates. In 2009, the Company determined that plant removal costs related to
recent acquisitions should be reclassified from accumulated depreciation to a
regulatory liability. This reclassification is reflected in the preceding
table.
If, for
any reason, the Company's regulated businesses cease to meet the criteria for
application of regulatory accounting for all or part of their operations, the
regulatory assets and liabilities relating to those portions ceasing to meet
such criteria would be removed from the balance sheet and included in the
statement of income as an extraordinary item in the period in which the
discontinuance of regulatory accounting occurs.
Note 7
– Derivative Instruments
Derivative
instruments, including certain derivative instruments embedded in other
contracts, are required to be recorded on the balance sheet as either an asset
or liability measured at fair value. The Company’s policy is to not offset fair
value amounts for derivative instruments, and as a result the Company’s
derivative assets and liabilities are presented gross on the Consolidated
Balance Sheets. Changes in the derivative instrument's fair value are recognized
currently in earnings unless specific hedge accounting criteria are met.
Accounting for qualifying hedges
allows
derivative gains and losses to offset the related results on the hedged item in
the income statement and requires that a company must formally document,
designate and assess the effectiveness of transactions that receive hedge
accounting treatment.
In the
event a derivative instrument being accounted for as a cash flow hedge does not
qualify for hedge accounting because it is no longer highly effective in
offsetting changes in cash flows of a hedged item; if the derivative instrument
expires or is sold, terminated or exercised; or if management determines that
designation of the derivative instrument as a hedge instrument is no longer
appropriate, hedge accounting would be discontinued and the derivative
instrument would continue to be carried at fair value with changes in its fair
value recognized in earnings. In these circumstances, the net gain or loss at
the time of discontinuance of hedge accounting would remain in accumulated other
comprehensive income (loss) until the period or periods during which the hedged
forecasted transaction affects earnings, at which time the net gain or loss
would be reclassified into earnings. In the event a cash flow hedge is
discontinued because it is unlikely that a forecasted transaction will occur,
the derivative instrument would continue to be carried on the balance sheet at
its fair value, and gains and losses that had accumulated in other comprehensive
income (loss) would be recognized immediately in earnings. In the event of a
sale, termination or extinguishment of a foreign currency derivative, the
resulting gain or loss would be recognized immediately in earnings. The
Company's policy requires approval to terminate a derivative instrument prior to
its original maturity. As of December 31, 2009, the Company had no
outstanding foreign currency or interest rate hedges.
Cascade
and Intermountain
At
December 31, 2009, Cascade and Intermountain held natural gas swap
agreements, with total forward notional volumes of 12.1 million MMBtu,
which were not designated as hedges. Cascade and Intermountain utilize natural
gas swap agreements to manage a portion of their regulated natural gas supply
portfolios in order to manage fluctuations in the price of natural gas related
to core customers in accordance with authority granted by the IPUC, WUTC and
OPUC. Core customers consist of residential, commercial and smaller industrial
customers. The fair value of the derivative instrument must be estimated as of
the end of each reporting period and is recorded on the Consolidated Balance
Sheets as an asset or a liability. Cascade and Intermountain record periodic
changes in the fair market value of the derivative instruments on the
Consolidated Balance Sheets as a regulatory asset or a regulatory liability, and
settlements of these arrangements are expected to be recovered through the
purchased gas cost adjustment mechanism. Gains and losses on the settlements of
these derivative instruments are recorded as a component of purchased natural
gas sold on the Consolidated Statements of Income as they are recovered through
the purchased gas cost adjustment mechanism. Under the terms of these
arrangements, Cascade and Intermountain will either pay or receive settlement
payments based on the difference between the fixed strike price and the monthly
index price applicable to each contract. For the year ended December 31,
2009, Cascade and Intermountain recorded the decrease in the fair market value
of the derivative instruments of $61.9 million in regulatory
assets.
Certain
of Cascade's derivative instruments contain credit-risk-related contingent
features that permit the counterparties to require collateralization if
Cascade's derivative liability positions exceed certain dollar thresholds. The
dollar thresholds in certain of Cascade's agreements are determined and may
fluctuate based on Cascade's credit rating on its debt. In addition, Cascade's
and Intermountain's derivative instruments contain cross-default provisions that
state if the entity fails to make payment with respect to certain of its
indebtedness, in excess of specified amounts, the counterparties could require
early settlement or termination of such entity's derivative instruments in
liability positions. The aggregate fair value of Cascade and Intermountain's
derivative instruments with credit-risk-related contingent features that are in
a liability position at December 31, 2009, was $27.9 million. The
aggregate fair value of assets that would have been
needed to
settle the instruments immediately if the credit-risk-related contingent
features were triggered on December 31, 2009, was
$27.9 million.
Fidelity
At
December 31, 2009, Fidelity held natural gas swaps and collar agreements
with total forward notional volumes of 26.5 million MMBtu, natural gas
basis swaps with total forward notional volumes of 15.1 million MMBtu, and
oil swaps and collar agreements with total forward notional volumes of
2.0 million Bbl, all of which were designated as cash flow hedging
instruments. Fidelity utilizes these derivative instruments to manage a portion
of the market risk associated with fluctuations in the price of natural gas and
oil and basis differentials on its forecasted sales of natural gas and oil
production.
The fair
value of the derivative instruments must be estimated as of the end of each
reporting period and is recorded on the Consolidated Balance Sheets as an asset
or liability. Changes in the fair value attributable to the effective portion of
hedging instruments, net of tax, are recorded in stockholders' equity as a
component of accumulated other comprehensive income (loss). At the date the
natural gas and oil quantities are settled, the amounts accumulated in other
comprehensive income (loss) are reported in the Consolidated Statements of
Income. To the extent that the hedges are not effective, the ineffective portion
of the changes in fair market value is recorded directly in earnings. The
proceeds received for natural gas and oil production are generally based on
market prices.
For the
years ended December 31, 2009, 2008 and 2007, the amount of hedge
ineffectiveness was immaterial, and there were no components of the derivative
instruments’ gain or loss excluded from the assessment of hedge effectiveness.
Gains and losses must be reclassified into earnings as a result of the
discontinuance of cash flow hedges if it is probable that the original
forecasted transactions will not occur. There were no such reclassifications
into earnings as a result of the discontinuance of hedges.
Gains and
losses on derivative instruments that are reclassified from accumulated other
comprehensive income (loss) to current-period earnings are included in operating
revenues on the Consolidated Statements of Income. For further information
regarding the gains and losses on derivative instruments qualifying as cash flow
hedges that were recognized in other comprehensive income (loss) and the gains
and losses reclassified from accumulated other comprehensive income (loss) into
earnings, see Note 1.
As of
December 31, 2009, the maximum term of the swap and collar agreements, in
which the exposure to the variability in future cash flows for forecasted
transactions is being hedged, is 24 months. The Company estimates that over
the next 12 months net losses of approximately $3.8 million (after tax)
will be reclassified from accumulated other comprehensive loss into earnings,
subject to changes in natural gas and oil market prices, as the hedged
transactions affect earnings.
Certain
of Fidelity's derivative instruments contain cross-default provisions that state
if Fidelity fails to make payment with respect to certain indebtedness, in
excess of specified amounts, the counterparties could require early settlement
or termination of derivative instruments in liability positions. The aggregate
fair value of Fidelity's derivative instruments with credit-risk-related
contingent features that are in a liability position at December 31, 2009,
was $13.9 million. The aggregate fair value of assets that would have been
needed to settle the instruments immediately if the credit-risk-related
contingent features were triggered on December 31, 2009, was
$13.9 million.
The
location and fair value of all of the Company’s derivative instruments on the
Consolidated Balance Sheets as of December 31, 2009, were as
follows:
|
Asset
Derivatives
|
|
Liability
Derivatives
|
|
|
Location
on Consolidated
Balance
Sheets
|
|
Fair
Value
|
|
Location
on Consolidated
Balance
Sheets
|
|
Fair
Value
|
|
|
(In
thousands)
|
|
Commodity
derivatives
designated
as hedges:
|
|
|
Commodity
derivative instruments
|
|
$ |
7,761 |
|
Commodity
derivative instruments
|
|
$ |
13,763 |
|
|
Other
assets - noncurrent
|
|
|
2,734 |
|
Other
liabilities – noncurrent
|
|
|
114 |
|
Total
derivatives designated as hedges
|
|
|
|
10,495 |
|
|
|
|
13,877 |
|
|
|
Commodity
derivatives
not
designated as hedges:
|
|
|
Commodity
derivative instruments
|
|
|
— |
|
Commodity
derivative instruments
|
|
|
23,144 |
|
|
Other
assets - noncurrent
|
|
|
— |
|
Other
liabilities – noncurrent
|
|
|
4,756 |
|
Total
derivatives not designated as hedges
|
|
|
|
— |
|
|
|
|
27,900 |
|
Total
derivatives
|
|
|
$ |
10,495 |
|
|
|
$ |
41,777 |
|
Note 8
– Fair Value Measurements
On
January 1, 2008, the Company elected to measure its investments in certain
fixed-income and equity securities at fair value with changes in fair value
recognized in income. These investments had previously been accounted for as
available-for-sale investments. The Company anticipates using these investments
to satisfy its obligations under its unfunded, nonqualified benefit plans for
executive officers and certain key management employees, and invests in these
fixed-income and equity securities for the purpose of earning investment returns
and capital appreciation. These investments, which totaled $34.8 million
and $27.7 million as of December 31, 2009 and 2008, respectively, are
classified as Investments on the Consolidated Balance Sheets. The increase in
the fair value of these investments for the year ended December 31, 2009,
was $7.1 million (before tax). The decrease in the fair value of these
investments for the year ended December 31, 2008, was $8.6 million (before
tax). The change in fair value, which is considered part of the cost of the
plan, is classified in operation and maintenance expense on the Consolidated
Statements of Income. The Company did not elect the fair value option for its
remaining available-for-sale securities, which are auction rate securities. The
Company’s auction rate securities, which totaled $11.4 million at
December 31, 2009 and 2008, are accounted for as available-for-sale and are
recorded at fair value. The fair value of the auction rate securities
approximate cost and, as a result, there are no accumulated unrealized gains or
losses recorded in accumulated other comprehensive income (loss) on the
Consolidated Balance Sheets related to these investments.
Fair
value is defined as the price that would be received to sell an asset or paid to
transfer a liability (an exit price) in an orderly transaction between market
participants at the measurement date. The statement establishes a hierarchy for
grouping assets and liabilities, based on the significance of inputs. The
Company’s assets and liabilities measured at fair value on a recurring basis are
as follows:
|
|
Fair
Value Measurements at
December 31,
2009, Using
|
|
|
|
|
|
|
|
|
|
Quoted
Prices in Active Markets for Identical Assets
(Level 1)
|
|
|
Significant
Other Observable Inputs (Level 2)
|
|
|
Significant
Unobservable Inputs (Level 3)
|
|
|
Collateral
Provided to Counterparties
|
|
|
Balance
at December 31, 2009
|
|
|
|
(In
thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money
market funds
|
|
$ |
9,124 |
|
|
$ |
151,000 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
160,124 |
|
Available-for-sale
securities
|
|
|
9,078 |
|
|
|
37,141 |
|
|
|
— |
|
|
|
— |
|
|
|
46,219 |
|
Commodity
derivative instruments - current
|
|
|
— |
|
|
|
7,761 |
|
|
|
— |
|
|
|
— |
|
|
|
7,761 |
|
Commodity
derivative instruments - noncurrent
|
|
|
— |
|
|
|
2,734 |
|
|
|
— |
|
|
|
— |
|
|
|
2,734 |
|
Total
assets measured at fair value
|
|
$ |
18,202 |
|
|
$ |
198,636 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
216,838 |
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivative instruments - current
|
|
$ |
— |
|
|
$ |
36,907 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
36,907 |
|
Commodity
derivative instruments - noncurrent
|
|
|
— |
|
|
|
4,870 |
|
|
|
— |
|
|
|
— |
|
|
|
4,870 |
|
Total
liabilities measured at fair value
|
|
$ |
— |
|
|
$ |
41,777 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
41,777 |
|
|
|
Fair
Value Measurements at
December 31,
2008, Using
|
|
|
|
|
|
|
|
|
|
Quoted
Prices in Active Markets for Identical Assets
(Level 1)
|
|
|
Significant
Other Observable Inputs (Level 2)
|
|
|
Significant
Unobservable Inputs (Level 3)
|
|
|
Collateral
Provided to Counterparties
|
|
|
Balance
at December 31, 2008
|
|
|
|
(In
thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available-for-sale
securities
|
|
$ |
27,725 |
|
|
$ |
11,400 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
39,125 |
|
Commodity
derivative instruments - current
|
|
|
— |
|
|
|
78,164 |
|
|
|
— |
|
|
|
— |
|
|
|
78,164 |
|
Commodity
derivative instruments - noncurrent
|
|
|
— |
|
|
|
3,222 |
|
|
|
— |
|
|
|
— |
|
|
|
3,222 |
|
Total
assets measured at fair value
|
|
$ |
27,725 |
|
|
$ |
92,786 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
120,511 |
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivative instruments - current
|
|
$ |
— |
|
|
$ |
67,629 |
|
|
$ |
— |
|
|
$ |
11,100 |
|
|
$ |
56,529 |
|
Commodity
derivative instruments - noncurrent
|
|
|
— |
|
|
|
23,534 |
|
|
|
— |
|
|
|
— |
|
|
|
23,534 |
|
Total
liabilities measured at fair value
|
|
$ |
— |
|
|
$ |
91,163 |
|
|
$ |
— |
|
|
$ |
11,100 |
|
|
$ |
80,063 |
|
The
estimated fair value of the Company’s Level 1 money market funds is valued
at the net asset value of shares held by the Company, based on published market
quotations in active markets. The estimated fair value of the Company’s Level 1
available-for-sale securities is based on quoted market prices in active markets
for identical equity and fixed-income securities. The estimated fair value of
the Company’s Level 2 money market funds and available-for-sale securities
is based on comparable market transactions or underlying investments. The
estimated fair value of the Company’s Level 2 commodity
derivative
instruments is
based upon futures prices, volatility and time to maturity, among other
things.
The
Company’s long-term debt is not measured at fair value on the Consolidated
Balance Sheets and the fair value is being provided for disclosure purposes
only. The estimated fair value of the Company’s long-term debt was based on
quoted market prices of the same or similar issues. The estimated fair value of
the Company's long-term debt at December 31 was as follows:
|
|
2009
|
|
|
2008
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
(In
thousands)
|
|
Long-term
debt
|
|
$ |
1,499,306 |
|
|
$ |
1,566,331 |
|
|
$ |
1,647,302 |
|
|
$ |
1,577,907 |
|
The
carrying amounts of the Company's remaining financial instruments included in
current assets and current liabilities approximate their fair
values.
Note 9
– Debt
Certain
debt instruments of the Company and its subsidiaries, including those discussed
below, contain restrictive covenants and cross-default provisions. In order to
borrow under the respective credit agreements, the Company and its subsidiaries
must be in compliance with the applicable covenants and certain other
conditions, all of which the Company and its subsidiaries, as applicable, were
in compliance with at December 31, 2009. In the event the Company and its
subsidiaries do not comply with the applicable covenants and other conditions,
alternative sources of funding may need to be pursued.
The
following table summarizes the outstanding credit facilities of the Company and
its subsidiaries:
Company
|
Facility
|
|
|
Facility
Limit
|
|
|
|
Amount
Outstanding
at
December 31,
2009
|
|
|
|
Amount
Outstanding
at
December 31,
2008
|
|
|
|
Letters
of
Credit
at
December 31,
2009
|
|
|
Expiration
Date
|
|
(Dollars
in millions)
|
MDU
Resources Group, Inc.
|
Commercial
paper/Revolving
credit
agreement
|
(a)
|
|
$ |
125.0 |
|
|
|
$ |
— |
|
(b)
|
|
$ |
22.5 |
|
(b)
|
|
$ |
— |
|
|
6/21/11
|
|
MDU
Energy Capital, LLC
|
Master
shelf agreement
|
|
|
$ |
175.0 |
|
|
|
$ |
165.0 |
|
|
|
$ |
165.0 |
|
|
|
$ |
— |
|
|
8/14/10
|
(c)
|
Cascade
Natural Gas Corporation
|
Revolving
credit agreement
|
|
|
$ |
50.0 |
|
(d)
|
|
$ |
— |
|
|
|
$ |
48.1 |
|
|
|
$ |
1.9 |
|
(e)
|
12/28/12
|
(f)
|
Intermountain
Gas Company
|
Revolving
credit agreement
|
|
|
$ |
65.0 |
|
(g)
|
|
$ |
10.3 |
|
|
|
$ |
36.5 |
|
|
|
$ |
— |
|
|
8/31/10
|
|
Centennial
Energy
Holdings,
Inc.
|
Commercial
paper/Revolving
credit
agreement
|
(h)
|
|
$ |
400.0 |
|
|
|
$ |
— |
|
(b)
|
|
$ |
150.0 |
|
(b)
|
|
$ |
26.4 |
|
(e)
|
12/13/12
|
|
Williston
Basin Interstate Pipeline Company
|
Uncommitted
long-term private shelf agreement
|
|
|
$ |
125.0 |
|
|
|
$ |
87.5 |
|
|
|
$ |
72.5 |
|
|
|
$ |
— |
|
|
12/23/10
|
(i)
|
(a)
|
The
$125 million commercial paper program is supported by a revolving credit
agreement with various banks totaling $125 million (provisions allow for
increased borrowings, at the option of the Company on stated conditions,
up to a maximum of $150 million). There were no amounts outstanding under
the credit agreement.
|
(b)
|
Amount
outstanding under commercial paper program.
|
(c)
|
Or
such time as the agreement is terminated by either of the parties
thereto.
|
(d)
|
Certain
provisions allow for increased borrowings, up to a maximum of $75
million.
|
(e)
|
The
outstanding letters of credit, as discussed in Note 19, reduce amounts
available under the credit agreement.
|
(f)
|
Provisions
allow for an extension of up to two years upon consent of the
banks.
|
(g)
|
Certain
provisions allow for increased borrowings, up to a maximum of
$70 million.
|
(h)
|
The
$400 million commercial paper program is supported by a revolving credit
agreement with various banks totaling $400 million (provisions allow for
increased borrowings, at the option of Centennial on stated conditions, up
to a maximum of $450 million). There were no amounts outstanding under the
credit agreement.
|
(i)
|
Certain
provisions allow for an extension to
December 23, 2011.
|
In order
to maintain the Company’s and Centennial’s respective commercial paper programs
in the amounts indicated above, both the Company and Centennial must have
revolving credit agreements in place at least equal to the amount of their
commercial paper programs. While the amount of commercial paper outstanding does
not reduce available capacity under the respective revolving credit agreements,
the Company and Centennial do not issue commercial paper in an aggregate amount
exceeding the available capacity under their credit agreements.
The
following includes information related to the preceding table.
Short-term
borrowings
MDU Resources
Group, Inc. The Company had $57.0
million outstanding under a $175 million term loan agreement at December 31,
2008. This agreement expired on March 24, 2009.
Cascade Natural
Gas Corporation Any borrowings under the $50 million revolving credit
agreement would be classified as short-term borrowings as Cascade intends to
repay the borrowings within one year.
Cascade’s
credit agreement contains customary covenants and provisions, including a
covenant of Cascade not to permit, at any time, the ratio of total debt to total
capitalization to be greater than 65 percent. Cascade's credit agreement
also contains cross-default provisions. These provisions state that if Cascade
fails to make any payment with respect to any indebtedness or
contingent
obligation,
in excess of a specified amount, under any agreement that causes such
indebtedness to be due prior to its stated maturity or the contingent obligation
to become payable, Cascade will be in default under the credit agreement.
Certain of Cascade's financing agreements and Cascade's practices limit the
amount of subsidiary indebtedness.
Intermountain Gas
Company The weighted average interest rate for borrowings outstanding
under the credit agreement at December 31, 2009, was 3.25 percent. The credit
agreement contains customary covenants and provisions, including covenants of
Intermountain not to permit, as of the end of any fiscal quarter, (A) the
ratio of funded debt to total capitalization (determined on a consolidated
basis) to be greater than 65 percent, or (B) the ratio of
Intermountain’s earnings before interest, taxes, depreciation and amortization
to interest expense (determined on a consolidated basis), for the 12-month
period ended each fiscal quarter, to be less than 2 to 1. Other covenants
include limitations on the sale of certain assets and on the making of certain
loans and investments.
Intermountain's
credit agreement contains cross-default provisions. These provisions state that
if (i) Intermountain fails to make any payment with respect to any
indebtedness or guarantee in excess of $5 million, (ii) any other
event occurs that would permit the holders of indebtedness or the beneficiaries
of guarantees to become payable, or (iii) certain conditions result in an
early termination date under any swap contract, then Intermountain shall be in
default under the revolving credit agreement.
Long-term
debt
MDU Resources
Group, Inc. The Company’s revolving credit agreement supports its
commercial paper program. The commercial paper borrowings are classified as
long-term debt as they are intended to be refinanced on a long-term basis
through continued commercial paper borrowings.
The
Company’s credit agreement contains customary covenants and provisions,
including covenants of the Company not to permit, as of the end of any fiscal
quarter, (A) the ratio of funded debt to total capitalization (determined
on a consolidated basis) to be greater than 65 percent or (B) the
ratio of funded debt to capitalization (determined with respect to the Company
alone, excluding its subsidiaries) to be greater than 65 percent. Also
included is a covenant that does not permit the ratio of the Company's earnings
before interest, taxes, depreciation and amortization to interest expense
(determined with respect to the Company alone, excluding its subsidiaries), for
the 12-month period ended each fiscal quarter, to be less than 2.5 to 1. Other
covenants include restrictions on the sale of certain assets and on the making
of certain investments.
There are
no credit facilities that contain cross-default provisions between the Company
and any of its subsidiaries.
In
November 2009, the Company completed a defeasance of its outstanding 8.60%
Secured Medium-Term Notes, Series A, due April 1, 2012 (8.60% Notes), by
depositing approximately $5.5 million with the Mortgage trustee. The $5.5
million deposit will be used solely to satisfy the principal and remaining
interest obligations on the 8.60% Notes. These securities are the only
remaining first mortgage bonds outstanding under the Mortgage, other than $30.0
million of first mortgage bonds which were held by the Indenture trustee for the
benefit of the senior note holders. In connection with the defeasance of
the 8.60% Notes, the Mortgage was discharged and the lien of the Indenture was
discharged so that the Company's 5.98% Senior Notes due 2033 are now
unsecured.
MDU Energy
Capital, LLC The master shelf agreement contains customary covenants
and provisions, including covenants of MDU Energy Capital not to permit
(A) the ratio of its total debt (on a consolidated basis) to adjusted total
capitalization to be greater than 70 percent, or (B) the ratio of
subsidiary debt to subsidiary capitalization to be greater than 65 percent,
or (C) the ratio of Intermountain’s total debt (determined on a
consolidated basis) to total capitalization to be greater than 65 percent.
The agreement also includes a covenant requiring the ratio of MDU Energy Capital
earnings before interest and taxes to interest expense (on a consolidated
basis), for the 12-month period ended each fiscal quarter, to be greater than
1.5 to 1. In addition, payment obligations under the master shelf agreement
may be accelerated upon the occurrence of an event of default (as described in
the agreement).
Centennial Energy
Holdings, Inc. Centennial’s revolving credit agreement supports its
commercial paper program. The Centennial commercial paper borrowings are
classified as long-term debt as Centennial intends to refinance these borrowings
on a long-term basis through continued Centennial commercial paper
borrowings.
Centennial’s
credit agreement and the Centennial uncommitted long-term master shelf agreement
contain customary covenants and provisions, including a covenant of Centennial
and certain of its subsidiaries, not to permit, as of the end of any fiscal
quarter, the ratio of total debt to total capitalization to be greater than
65 percent (for the $400 million credit agreement) and 60 percent
(for the master shelf agreement). The master shelf agreement also includes a
covenant that does not permit the ratio of Centennial's earnings before
interest, taxes, depreciation and amortization to interest expense, for the
12-month period ended each fiscal quarter, to be less than 1.75 to 1. Other
covenants include minimum consolidated net worth, limitation on priority debt
and restrictions on the sale of certain assets and on the making of certain
loans and investments.
Pursuant
to a covenant under the credit agreement, Centennial may only make distributions
to the Company in an amount up to 100 percent of Centennial’s consolidated
net income after taxes for the immediately preceding fiscal year. The write-down
of the natural gas and oil properties in 2009 would have negatively affected
Centennial’s ability to make distributions to the Company in 2010, however, in
November 2009, the lenders under the credit agreement consented to permit
Centennial to make distributions during 2010 in an aggregate amount up to
100 percent of its consolidated net income after taxes during fiscal year
2009 without giving effect to the write-down.
Certain
of Centennial’s financing agreements contain cross-default provisions. These
provisions state that if Centennial or any subsidiary of Centennial fails to
make any payment with respect to any indebtedness or contingent obligation, in
excess of a specified amount, under any agreement that causes such indebtedness
to be due prior to its stated maturity or the contingent obligation to become
payable, the applicable agreements will be in default. Certain of Centennial’s
financing agreements and Centennial’s practices limit the amount of subsidiary
indebtedness.
Williston Basin
Interstate Pipeline Company The uncommitted
long-term private shelf agreement contains customary covenants and provisions,
including a covenant of Williston Basin not to permit, as of the end of any
fiscal quarter, the ratio of total debt to total capitalization to be greater
than 55 percent. Other covenants include limitation on priority debt and
some restrictions on the sale of certain assets and the making of certain
investments.
Long-term Debt Outstanding
Long-term
debt outstanding at December 31 was as follows:
|
|
2009
|
|
|
2008
|
|
|
|
|
(In
thousands)
|
|
|
First
mortgage bonds and notes:
|
|
|
|
|
|
|
|
Secured
Medium-Term Notes, Series A, 8.60%
|
|
$ |
— |
|
|
$ |
5,500 |
|
|
Senior
Notes, 5.98%, due December 15, 2033
|
|
|
— |
|
|
|
30,000 |
|
(a)
|
Total
first mortgage bonds and notes
|
|
|
— |
|
|
|
35,500 |
|
|
Senior
Notes at a weighted average rate of 6.07%, due on dates ranging from
October 30, 2010 to March 8, 2037
|
|
|
1,370,455 |
|
|
|
1,271,227 |
|
|
Commercial
paper supported by revolving credit agreements
|
|
|
— |
|
|
|
172,500 |
|
|
Medium-Term
Notes at a weighted average rate of 7.72%, due on dates ranging from
September 4, 2012 to March 16, 2029
|
|
|
81,000 |
|
|
|
81,000 |
|
|
Other
notes at a weighted average rate of 5.24%, due on dates ranging from
September 1, 2020 to February 1, 2035
|
|
|
42,070 |
|
|
|
42,971 |
|
|
Credit
agreements at a weighted average rate of 5.67%, due on dates ranging from
April 1, 2010 to November 30, 2038
|
|
|
5,781 |
|
|
|
44,205 |
|
|
Discount
|
|
|
— |
|
|
|
(101 |
) |
|
Total
long-term debt
|
|
|
1,499,306 |
|
|
|
1,647,302 |
|
|
Less
current maturities
|
|
|
12,629 |
|
|
|
78,666 |
|
|
Net
long-term debt
|
|
$ |
1,486,677 |
|
|
$ |
1,568,636 |
|
|
(a)
The $30.0 million of 5.98% Senior Notes became unsecured upon the
defeasance of the outstanding 8.60% Notes, as previously
discussed.
|
The
amounts of scheduled long-term debt maturities for the five years and thereafter
following December 31, 2009, aggregate $12.6 million in 2010; $72.3 million
in 2011; $136.3 million in 2012; $258.8 million in 2013;
$9.1 million in 2014 and $1,010.2 million thereafter.
Note 10
– Asset Retirement Obligations
The
Company records obligations related to the plugging and abandonment of natural
gas and oil wells, decommissioning of certain electric generating facilities,
reclamation of certain aggregate properties, special handling and disposal of
hazardous materials at certain electric generating facilities, natural gas
distribution and transmission facilities and buildings, and certain other
obligations associated with leased properties.
A
reconciliation of the Company's liability, which is included in other
liabilities, for the years ended December 31 was as follows:
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
Balance
at beginning of year
|
|
$ |
70,147 |
|
|
$ |
64,453 |
|
Liabilities
incurred
|
|
|
2,418 |
|
|
|
2,943 |
|
Liabilities
acquired
|
|
|
— |
|
|
|
2,369 |
|
Liabilities
settled
|
|
|
(9,319 |
) |
|
|
(3,188 |
) |
Accretion
expense
|
|
|
3,385 |
|
|
|
3,191 |
|
Revisions
in estimates
|
|
|
9,548 |
|
|
|
207 |
|
Other
|
|
|
180 |
|
|
|
172 |
|
Balance
at end of year
|
|
$ |
76,359 |
|
|
$ |
70,147 |
|
The
Company believes that any expenses related to asset retirement obligations at
the Company’s regulated operations will be recovered in rates over time and,
accordingly, defers such expenses as regulatory assets.
The fair
value of assets that are legally restricted for purposes of settling asset
retirement obligations at December 31, 2009 and 2008, was
$5.9 million.
Note 11
– Preferred Stocks
Preferred
stocks at December 31 were as follows:
|
|
2009
|
|
|
2008
|
|
|
|
(Dollars
in thousands)
|
|
Authorized:
|
|
|
|
|
|
|
Preferred
–
|
|
|
|
|
|
|
500,000
shares, cumulative, par value $100, issuable in series
|
|
|
|
|
|
|
Preferred
stock A –
|
|
|
|
|
|
|
1,000,000
shares, cumulative, without par value, issuable in series
|
|
|
|
|
|
|
(none
outstanding)
|
|
|
|
|
|
|
Preference
–
|
|
|
|
|
|
|
500,000
shares, cumulative, without par value, issuable in series
|
|
|
|
|
|
|
(none
outstanding)
|
|
|
|
|
|
|
Outstanding:
|
|
|
|
|
|
|
4.50%
Series – 100,000 shares
|
|
$ |
10,000 |
|
|
$ |
10,000 |
|
4.70%
Series – 50,000 shares
|
|
|
5,000 |
|
|
|
5,000 |
|
Total
preferred stocks
|
|
$ |
15,000 |
|
|
$ |
15,000 |
|
The 4.50%
Series and 4.70% Series preferred stocks outstanding are subject to redemption,
in whole or in part, at the option of the Company with certain limitations on
30 days notice on any quarterly dividend date at a redemption price, plus
accrued dividends, of $105 per share and $102 per share,
respectively.
In the
event of a voluntary or involuntary liquidation, all preferred stock series
holders are entitled to $100 per share, plus accrued
dividends.
The
affirmative vote of two-thirds of a series of the Company's outstanding
preferred stock is necessary for amendments to the Company's charter or bylaws
that adversely affect that series;
creation
of or increase in the amount of authorized stock ranking senior to that series
(or an affirmative majority vote where the authorization relates to a new class
of stock that ranks on parity with such series); a voluntary liquidation or sale
of substantially all of the Company's assets; a merger or consolidation, with
certain exceptions; or the partial retirement of that series of preferred stock
when all dividends on that series of preferred stock have not been paid. The
consent of the holders of a particular series is not required for such corporate
actions if the equivalent vote of all outstanding series of preferred stock
voting together has consented to the given action and no particular series is
affected differently than any other series.
Subject
to the foregoing, the holders of common stock exclusively possess all voting
power. However, if cumulative dividends on preferred stock are in arrears, in
whole or in part, for one year, the holders of preferred stock would obtain the
right to one vote per share until all dividends in arrears have been paid and
current dividends have been declared and set aside.
Note 12
– Common Stock
The Stock
Purchase Plan provides interested investors the opportunity to make optional
cash investments and to reinvest all or a percentage of their cash
dividends in shares of the Company's common stock. The K-Plan is partially
funded with the Company's common stock. From January 2007 through March 2007 and
October 1, 2008 through October 21, 2008, the Stock Purchase Plan and
K-Plan, with respect to Company stock, were funded with shares of authorized but
unissued common stock. From April 2007 through September 30, 2008, and
October 22, 2008 through December 2009, purchases of shares of common
stock on the open market were used to fund the Stock Purchase Plan and K-Plan.
At December 31, 2009, there were 23.2 million shares of common stock
reserved for original issuance under the Stock Purchase Plan and
K-Plan.
The
Company depends on earnings from its divisions and dividends from its
subsidiaries to pay dividends on common stock. The declaration and payment of
dividends is at the sole discretion of the board of directors, subject to
limitations imposed by state laws, applicable regulatory limitations, and
compliance with the requirements of the Company’s credit agreements. These
requirements are not expected to affect the Company’s ability to pay dividends
in the near term.
Note 13
– Stock-Based Compensation
The
Company has several stock-based compensation plans and is authorized to grant
options, restricted stock and stock for up to 16.9 million shares of common
stock and has granted options, restricted stock and stock of 7.3 million
shares through December 31, 2009. The Company generally issues new shares
of common stock to satisfy stock option exercises, restricted stock, stock and
performance share awards.
Total
stock-based compensation expense was $3.4 million, net of income taxes of
$2.2 million in 2009; $3.7 million, net of income taxes of
$2.3 million in 2008; and $4.7 million, net of income taxes of
$3.1 million in 2007.
As of
December 31, 2009, total remaining unrecognized compensation expense
related to stock-based compensation was approximately $5.6 million (before
income taxes) which will be amortized over a weighted average period of 1.5
years.
Stock
options
The
Company has stock option plans for directors, key employees and employees. The
Company has not granted stock options since 2003. Options granted to key
employees automatically vest after nine years, but the plan provides for
accelerated vesting based on the attainment of certain performance goals or upon
a change in control of the Company, and expire 10 years after the
date
of grant.
Options granted to directors and employees vest at the date of grant and three
years after the date of grant, respectively, and expire 10 years after the
date of grant.
The fair
value of each option outstanding was estimated on the date of grant using the
Black-Scholes option-pricing model.
A summary
of the status of the stock option plans at December 31, 2009, and changes
during the year then ended was as follows:
|
|
Number
of
Shares
|
|
|
Weighted
Average
Exercise
Price
|
|
Balance
at beginning of year
|
|
|
1,003,824 |
|
|
$ |
13.39 |
|
Forfeited
|
|
|
(24,188 |
) |
|
|
13.22 |
|
Exercised
|
|
|
(154,765 |
) |
|
|
13.23 |
|
Balance
at end of year
|
|
|
824,871 |
|
|
|
13.42 |
|
Exercisable
at end of year
|
|
|
799,703 |
|
|
$ |
13.41 |
|
Summarized
information about stock options outstanding and exercisable as of
December 31, 2009, was as follows:
|
|
|
Options
Outstanding
|
|
|
Options
Exercisable
|
|
|
|
|
|
|
|
Remaining
|
|
|
Weighted
|
|
|
Aggregate
|
|
|
|
|
|
Weighted
|
|
|
Aggregate
|
|
Range
of |
|
|
|
|
|
Contractual
|
|
|
Average
|
|
|
Intrinsic
|
|
|
|
|
|
Average
|
|
|
Intrinsic
|
|
Exercisable
|
|
|
Number
|
|
|
Life
|
|
|
Exercise
|
|
|
Value
|
|
|
Number
|
|
|
Exercise
|
|
|
Value
|
|
Prices
|
|
|
Outstanding
|
|
|
in
Years
|
|
|
Price
|
|
|
(000's)
|
|
|
Exercisable
|
|
|
Price
|
|
|
(000's)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
9.61
– 12.00 |
|
|
|
12,131 |
|
|
|
.5 |
|
|
$ |
9.93 |
|
|
$ |
166 |
|
|
|
12,131 |
|
|
$ |
9.93 |
|
|
$ |
166 |
|
|
12.01
– 14.50 |
|
|
|
745,970 |
|
|
|
1.2 |
|
|
|
13.21 |
|
|
|
7,751 |
|
|
|
726,235 |
|
|
|
13.21 |
|
|
|
7,545 |
|
|
14.51
– 17.13 |
|
|
|
66,770 |
|
|
|
1.2 |
|
|
|
16.48 |
|
|
|
475 |
|
|
|
61,337 |
|
|
|
16.51 |
|
|
|
435 |
|
Balance
at end of year
|
|
|
|
824,871 |
|
|
|
1.2 |
|
|
$ |
13.42 |
|
|
$ |
8,392 |
|
|
|
799,703 |
|
|
$ |
13.41 |
|
|
$ |
8,146 |
|
The
aggregate intrinsic value in the preceding table represents the total intrinsic
value (before income taxes), based on the Company's stock price on
December 31, 2009, which would have been received by the option holders had
all option holders exercised their options as of that date.
The
weighted average remaining contractual life of options exercisable was 1.2 years
at December 31, 2009.
The
Company received cash of $2.1 million, $5.9 million and
$10.2 million from the exercise of stock options for the years ended
December 31, 2009, 2008 and 2007, respectively. The aggregate intrinsic
value of options exercised during the years ended December 31, 2009, 2008
and 2007, was $1.3 million, $8.1 million and $11.2 million,
respectively.
Restricted
stock awards
Prior to
2002, the Company granted restricted stock awards under a long-term incentive
plan. The restricted stock awards granted vest at various times ranging from
one year to nine years from the date of issuance, but certain grants may
vest early based upon the attainment of certain performance goals or upon a
change in control of the Company. The grant-date fair value is the market price
of the Company's stock on the grant date.
A summary
of the status of the restricted stock awards for the year ended
December 31, 2009, was as follows:
|
|
|
|
|
Weighted
|
|
|
|
Number
|
|
|
Average
|
|
|
|
of
|
|
|
Grant-Date
|
|
|
|
Shares
|
|
|
Fair
Value
|
|
Nonvested
at beginning of period
|
|
|
20,606 |
|
|
$ |
13.22 |
|
Vested
|
|
|
— |
|
|
|
— |
|
Forfeited
|
|
|
(2,970 |
) |
|
|
13.22 |
|
Nonvested
at end of period
|
|
|
17,636 |
|
|
$ |
13.22 |
|
Stock
awards
Nonemployee
directors may receive shares of common stock instead of cash in payment for
directors' fees under the nonemployee director stock compensation plan. There
were 49,649 shares with a fair value of $879,000, 45,675 shares with a
fair value of $1.2 million and 48,228 shares with a fair value of
$1.5 million issued under this plan during the years ended
December 31, 2009, 2008 and 2007, respectively.
Performance
share awards
Since
2003, key employees of the Company have been awarded performance share awards
each year. Entitlement to performance shares is based on the Company's total
shareholder return over designated performance periods as measured against a
selected peer group.
Target
grants of performance shares outstanding at December 31, 2009, were as
follows:
|
|
Target
Grant
|
Grant
Date
|
Performance
Period
|
of
Shares
|
February
2007
|
2007-2009
|
175,596
|
February
2008
|
2008-2010
|
183,102
|
February
2009
|
2009-2011
|
275,807
|
Participants
may earn from zero to 200 percent of the target grant of shares based on
the Company's total shareholder return relative to that of the selected peer
group. Compensation expense is based on the grant-date fair value. The
grant-date fair value of performance share awards granted during the years ended
December 31, 2009, 2008 and 2007, was $20.39, $30.71 and $23.55, per share,
respectively. The grant-date fair value for the performance shares was
determined by Monte Carlo simulation using a blended volatility term structure
in the range of 40.40 percent to 50.98 percent in 2009,
21.54 percent to 22.97 percent in 2008 and 18.17 percent to
18.73 percent in 2007 comprised of 50 percent historical volatility
and 50 percent implied volatility and a risk-free interest rate term
structure in the range of .30 percent to 1.36 percent in 2009,
1.87 percent to 2.23 percent in 2008 and 4.75 percent to
5.21 percent in 2007 based on U.S. Treasury security rates in effect as of
the grant date. In addition, the mean over all simulation paths of the
discounted dividends expected to be earned in the performance period used in the
valuation was $1.79, $1.64 and $1.25 per target share for the 2009, 2008 and
2007 awards, respectively. The fair value of performance share awards that
vested during the years ended December 31, 2009, 2008 and 2007, was
$2.8 million, $8.5 million and $6.0 million,
respectively.
A summary
of the status of the performance share awards for the year ended
December 31, 2009, was as follows:
|
|
Weighted
|
|
Number
|
Average
|
|
of
|
Grant-Date
|
|
Shares
|
Fair
Value
|
Nonvested
at beginning of period
|
546,867
|
$26.55
|
Granted
|
278,178
|
20.39
|
Vested
|
(151,848)
|
25.22
|
Forfeited
|
(38,692)
|
25.35
|
Nonvested
at end of period
|
634,505
|
$24.24
|
Note 14
– Income Taxes
The
components of income (loss) before income taxes for each of the years ended
December 31 were as follows:
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
United
States
|
|
$ |
(227,021 |
) |
|
$ |
436,029 |
|
|
$ |
508,210 |
|
Foreign
|
|
|
7,655 |
|
|
|
5,120 |
|
|
|
4,600 |
|
Income
(loss) before income taxes
|
|
$ |
(219,366 |
) |
|
$ |
441,149 |
|
|
$ |
512,810 |
|
Income
tax expense (benefit) for the years ended December 31 was as
follows:
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Current:
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$ |
64,389 |
|
|
$ |
82,279 |
|
|
$ |
106,399 |
|
State
|
|
|
8,284 |
|
|
|
(184 |
) |
|
|
15,135 |
|
Foreign
|
|
|
254 |
|
|
|
(104 |
) |
|
|
235 |
|
|
|
|
72,927 |
|
|
|
81,991 |
|
|
|
121,769 |
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes –
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(147,607 |
) |
|
|
59,963 |
|
|
|
58,030 |
|
State
|
|
|
(22,370 |
) |
|
|
5,332 |
|
|
|
9,656 |
|
Investment
tax credit – net
|
|
|
213 |
|
|
|
(405 |
) |
|
|
(414 |
) |
|
|
|
(169,764 |
) |
|
|
64,890 |
|
|
|
67,272 |
|
Change
in uncertain tax benefits
|
|
|
562 |
|
|
|
422 |
|
|
|
869 |
|
Change
in accrued interest
|
|
|
183 |
|
|
|
173 |
|
|
|
114 |
|
Total
income tax expense (benefit)
|
|
$ |
(96,092 |
) |
|
$ |
147,476 |
|
|
$ |
190,024 |
|
Components
of deferred tax assets and deferred tax liabilities recognized at
December 31 were as follows:
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
Deferred
tax assets:
|
|
|
|
|
|
|
Regulatory
matters
|
|
$ |
85,712 |
|
|
$ |
46,855 |
|
Accrued
pension costs
|
|
|
79,052 |
|
|
|
93,371 |
|
Asset
retirement obligations
|
|
|
24,091 |
|
|
|
22,707 |
|
Deferred
compensation
|
|
|
11,411 |
|
|
|
12,015 |
|
Other
|
|
|
59,763 |
|
|
|
62,456 |
|
Total
deferred tax assets
|
|
|
260,029 |
|
|
|
237,404 |
|
Deferred
tax liabilities:
|
|
|
|
|
|
|
|
|
Depreciation
and basis differences on property,
|
|
|
|
|
|
|
|
|
plant
and equipment
|
|
|
601,426 |
|
|
|
562,326 |
|
Basis
differences on natural gas and oil producing
|
|
|
|
|
|
|
|
|
properties
|
|
|
116,521 |
|
|
|
284,231 |
|
Regulatory
matters
|
|
|
53,835 |
|
|
|
65,909 |
|
Natural
gas and oil price swap and collar agreements
|
|
|
— |
|
|
|
30,414 |
|
Other
|
|
|
51,070 |
|
|
|
42,725 |
|
Total
deferred tax liabilities
|
|
|
822,852 |
|
|
|
985,605 |
|
Net
deferred income tax liability
|
|
$ |
(562,823 |
) |
|
$ |
(748,201 |
) |
As of
December 31, 2009 and 2008, no valuation allowance has been recorded
associated with the above deferred tax assets.
The
following table reconciles the change in the net deferred income tax liability
from December 31, 2008, to December 31, 2009, to deferred income
tax benefit:
|
|
2009
|
|
(In
thousands)
|
|
Change
in net deferred income tax liability from the preceding
table
|
|
$ |
(185,378 |
) |
Deferred
taxes associated with other comprehensive loss
|
|
|
18,574 |
|
Deferred
taxes associated with acquisitions
|
|
|
762 |
|
Other
|
|
|
(3,722 |
) |
Deferred
income tax benefit for the period
|
|
$ |
(169,764 |
) |
Total
income tax expense (benefit) differs from the amount computed by applying the
statutory federal income tax rate to income (loss) before taxes. The reasons for
this difference were as follows:
Years
ended December 31,
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
Amount
|
|
|
%
|
|
|
Amount
|
|
|
%
|
|
|
Amount
|
|
|
%
|
|
|
|
(Dollars in
thousands)
|
|
Computed
tax at federal statutory rate
|
|
$ |
(76,778 |
) |
|
|
35.0 |
|
|
$ |
154,402 |
|
|
|
35.0 |
|
|
$ |
179,484 |
|
|
|
35.0 |
|
Increases
(reductions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
resulting
from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State
income taxes,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net
of federal income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
tax
benefit (expense)
|
|
|
(7,280 |
) |
|
|
3.3 |
|
|
|
10,709 |
|
|
|
2.4 |
|
|
|
17,121 |
|
|
|
3.3 |
|
Deductible
K-Plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
dividends
|
|
|
(2,369 |
) |
|
|
1.1 |
|
|
|
(2,144 |
) |
|
|
(.5 |
) |
|
|
(2,134 |
) |
|
|
(.4 |
) |
Depletion
allowance
|
|
|
(2,320 |
) |
|
|
1.0 |
|
|
|
(2,932 |
) |
|
|
(.7 |
) |
|
|
(4,073 |
) |
|
|
(.8 |
) |
Federal
renewable energy
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
credit
|
|
|
(1,452 |
) |
|
|
.7 |
|
|
|
(1,235 |
) |
|
|
(.3 |
) |
|
|
— |
|
|
|
— |
|
Foreign
operations
|
|
|
(1,148 |
) |
|
|
.5 |
|
|
|
423 |
|
|
|
.1 |
|
|
|
9,603 |
|
|
|
1.8 |
|
Domestic
production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
activities
deduction
|
|
|
(856 |
) |
|
|
.4 |
|
|
|
(3,031 |
) |
|
|
(.7 |
) |
|
|
(4,787 |
) |
|
|
(.9 |
) |
Resolution
of tax matters
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and
uncertain tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
positions
|
|
|
881 |
|
|
|
(.4 |
) |
|
|
595 |
|
|
|
.1 |
|
|
|
208 |
|
|
|
— |
|
Other
|
|
|
(4,770 |
) |
|
|
2.2 |
|
|
|
(9,311 |
) |
|
|
(2.0 |
) |
|
|
(5,398 |
) |
|
|
(.9 |
) |
Total
income tax expense (benefit)
|
|
$ |
(96,092 |
) |
|
|
43.8 |
|
|
$ |
147,476 |
|
|
|
33.4 |
|
|
$ |
190,024 |
|
|
|
37.1 |
|
The
income tax benefit in 2009 resulted largely from the Company’s write-down of
natural gas and oil properties, as discussed in Note 1.
Prior to the sale of the
domestic independent power production assets on July 10, 2007, as discussed
in Note 3, the Company considered earnings (including the gain from
the sale of its foreign equity method investment in a natural gas-fired electric
generating facility in Brazil in 2005) to be reinvested indefinitely outside of
the United States and, accordingly, no U.S. deferred income taxes were recorded
with respect to such earnings. Following the sale of these assets, the Company
reconsidered its
long-term plans for future development and expansion of its foreign investment
and has determined that it has no immediate plans to explore or invest in
additional foreign investments at this time. Therefore in the third quarter of
2007, deferred income taxes were accrued with respect to the temporary
differences which had not been previously recorded. The amount of
cumulative undistributed earnings for which there are temporary differences is
approximately $36.8 million at December 31, 2009. The amount of deferred
tax liability, net of allowable foreign tax credits, associated with the
undistributed earnings at December 31, 2009, was approximately
$10.5 million, which was largely recognized in 2007. Future earnings
will also be subject to additional U.S. taxes, net of allowable foreign tax
credits.
The
Company and its subsidiaries file income tax returns in the U.S. federal
jurisdiction, and various state, local and foreign jurisdictions. With few
exceptions, the Company is no longer subject to U.S. federal, state and local,
or non-U.S. income tax examinations by tax authorities for years ending prior to
2004.
On
January 1, 2007, upon the adoption of accounting guidance related to
uncertain tax positions, the Company recognized a decrease in the liability for
unrecognized tax benefits, which was not
material
and was accounted for as an increase to the January 1, 2007, balance of
retained earnings. At the date of adoption, the amount of unrecognized tax
benefits was $4.5 million, including interest.
A
reconciliation of the unrecognized tax benefits (excluding interest) for the
years ended December 31, was as follows:
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Balance
at beginning of year
|
|
$ |
5,586 |
|
|
$ |
3,735 |
|
|
$ |
4,241 |
|
Additions
based on tax positions related to the current year
|
|
|
— |
|
|
|
1,102 |
|
|
|
373 |
|
Additions
for tax positions of prior years
|
|
|
562 |
|
|
|
1,811 |
|
|
|
588 |
|
Reductions
for tax positions of prior years
|
|
|
— |
|
|
|
(1,062 |
) |
|
|
— |
|
Lapse
of statute of limitations
|
|
|
— |
|
|
|
— |
|
|
|
(1,467 |
) |
Balance
at end of year
|
|
$ |
6,148 |
|
|
$ |
5,586 |
|
|
$ |
3,735 |
|
Included
in the balance of unrecognized tax benefits at December 31, 2009, were
$540,000 of tax positions for which the ultimate deductibility is highly certain
but for which there is uncertainty about the timing of such deductibility.
Because of the impact of deferred tax accounting, other than interest and
penalties, the disallowance of the shorter deductibility period would not affect
the annual effective tax rate but would accelerate the payment of cash to the
taxing authority to an earlier period. The amount of unrecognized tax benefits
that, if recognized, would affect the effective tax rate at December 31,
2009, was $6.4 million, including approximately $804,000 for the payment of
interest and penalties.
The
Company does not anticipate the amount of unrecognized tax benefits to
significantly increase or decrease within the next 12 months.
For the
years ended December 31, 2009, 2008 and 2007, the Company recognized
approximately $190,000, $819,000 and $680,000, respectively, in interest
expense. Penalties were not material in 2009, 2008 and 2007. The Company
recognized interest income of approximately $165,000, $223,000 and $480,000 for
the years ended December 31, 2009, 2008 and 2007, respectively. The Company
had accrued liabilities of approximately $1.6 million, $1.4 million
and $718,000 at December 31, 2009, 2008 and 2007, respectively, for the
payment of interest.
Note 15
– Business Segment Data
The
Company’s reportable segments are those that are based on the Company’s method
of internal reporting, which generally segregates the strategic business units
due to differences in products, services and regulation. The vast majority of
the Company’s operations are located within the United States. The Company also
has investments in foreign countries, which largely consist of Centennial
Resources’ equity method investment in the Brazilian Transmission
Lines.
The
electric segment generates, transmits and distributes electricity in Montana,
North Dakota, South Dakota and Wyoming. The natural gas distribution segment
distributes natural gas in those states as well as in Idaho, Minnesota, Oregon
and Washington. These operations also supply related value-added products and
services.
The
construction services segment specializes in constructing and maintaining
electric and communication lines, gas pipelines, fire suppression systems, and
external lighting and traffic signalization equipment. This segment also
provides utility excavation services and inside
electrical
wiring, cabling and mechanical services, sells and distributes electrical
materials, and manufactures and distributes specialty equipment.
The
pipeline and energy services segment provides natural gas transportation,
underground storage and gathering services through regulated and nonregulated
pipeline systems primarily in the Rocky Mountain and northern Great Plains
regions of the United States. This segment also provides cathodic protection and
energy-related services.
The
natural gas and oil production segment is engaged in natural gas and oil
acquisition, exploration, development and production activities in the Rocky
Mountain and Mid-Continent regions of the United States and in and around the
Gulf of Mexico.
The
construction materials and contracting segment mines aggregates and markets
crushed stone, sand, gravel and related construction materials, including
ready-mixed concrete, cement, asphalt, liquid asphalt and other value-added
products. It also performs integrated contracting services. This segment
operates in the central, southern and western United States and Alaska and
Hawaii.
The Other
category includes the activities of Centennial Capital, which insures various
types of risks as a captive insurer for certain of the Company’s subsidiaries.
The function of the captive insurer is to fund the deductible layers of the
insured companies’ general liability and automobile liability coverages.
Centennial Capital also owns certain real and personal property. The Other
category also includes Centennial Resources' equity method investment in the
Brazilian Transmission Lines.
The
information below follows the same accounting policies as described in the
Summary of Significant Accounting Policies. Information on the Company's
businesses as of December 31 and for the years then ended was as
follows:
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
External
operating revenues:
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
196,171 |
|
|
$ |
208,326 |
|
|
$ |
193,367 |
|
Natural
gas distribution
|
|
|
1,072,776 |
|
|
|
1,036,109 |
|
|
|
532,997 |
|
Pipeline
and energy services
|
|
|
235,322 |
|
|
|
440,764 |
|
|
|
369,345 |
|
|
|
|
1,504,269 |
|
|
|
1,685,199 |
|
|
|
1,095,709 |
|
Construction
services
|
|
|
818,685 |
|
|
|
1,256,759 |
|
|
|
1,102,566 |
|
Natural
gas and oil production
|
|
|
338,425 |
|
|
|
420,637 |
|
|
|
288,148 |
|
Construction
materials and contracting
|
|
|
1,515,122 |
|
|
|
1,640,683 |
|
|
|
1,761,473 |
|
Other
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
2,672,232 |
|
|
|
3,318,079 |
|
|
|
3,152,187 |
|
Total
external operating revenues
|
|
$ |
4,176,501 |
|
|
$ |
5,003,278 |
|
|
$ |
4,247,896 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment
operating revenues:
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Natural
gas distribution
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Construction
services
|
|
|
379 |
|
|
|
560 |
|
|
|
649 |
|
Pipeline
and energy services
|
|
|
72,505 |
|
|
|
91,389 |
|
|
|
77,718 |
|
Natural
gas and oil production
|
|
|
101,230 |
|
|
|
291,642 |
|
|
|
226,706 |
|
Construction
materials and contracting
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Other
|
|
|
9,487 |
|
|
|
10,501 |
|
|
|
10,061 |
|
Intersegment
eliminations
|
|
|
(183,601 |
) |
|
|
(394,092 |
) |
|
|
(315,134 |
) |
Total
intersegment operating revenues
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
24,637 |
|
|
$ |
24,030 |
|
|
$ |
22,549 |
|
Natural
gas distribution
|
|
|
42,723 |
|
|
|
32,566 |
|
|
|
19,054 |
|
Construction
services
|
|
|
12,760 |
|
|
|
13,398 |
|
|
|
14,314 |
|
Pipeline
and energy services
|
|
|
25,581 |
|
|
|
23,654 |
|
|
|
21,631 |
|
Natural
gas and oil production
|
|
|
129,922 |
|
|
|
170,236 |
|
|
|
127,408 |
|
Construction
materials and contracting
|
|
|
93,615 |
|
|
|
100,853 |
|
|
|
95,732 |
|
Other
|
|
|
1,304 |
|
|
|
1,283 |
|
|
|
1,244 |
|
Total
depreciation, depletion and amortization
|
|
$ |
330,542 |
|
|
$ |
366,020 |
|
|
$ |
301,932 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
9,577 |
|
|
$ |
8,674 |
|
|
$ |
6,737 |
|
Natural
gas distribution
|
|
|
30,656 |
|
|
|
24,004 |
|
|
|
13,566 |
|
Construction
services
|
|
|
4,490 |
|
|
|
4,893 |
|
|
|
4,878 |
|
Pipeline
and energy services
|
|
|
8,896 |
|
|
|
8,314 |
|
|
|
8,769 |
|
Natural
gas and oil production
|
|
|
10,621 |
|
|
|
12,428 |
|
|
|
8,394 |
|
Construction
materials and contracting
|
|
|
20,495 |
|
|
|
24,291 |
|
|
|
23,997 |
|
Other
|
|
|
43 |
|
|
|
374 |
|
|
|
10,717 |
|
Intersegment
eliminations
|
|
|
(679 |
) |
|
|
(1,451 |
) |
|
|
(4,821 |
) |
Total
interest expense
|
|
$ |
84,099 |
|
|
$ |
81,527 |
|
|
$ |
72,237 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
8,205 |
|
|
$ |
8,225 |
|
|
$ |
8,528 |
|
Natural
gas distribution
|
|
|
16,331 |
|
|
|
18,827 |
|
|
|
6,477 |
|
Construction
services
|
|
|
15,189 |
|
|
|
26,952 |
|
|
|
26,829 |
|
Pipeline
and energy services
|
|
|
22,982 |
|
|
|
15,427 |
|
|
|
18,524 |
|
Natural
gas and oil production
|
|
|
(187,000 |
) |
|
|
68,701 |
|
|
|
78,348 |
|
Construction
materials and contracting
|
|
|
25,940 |
|
|
|
8,947 |
|
|
|
39,045 |
|
Other
|
|
|
2,261 |
|
|
|
397 |
|
|
|
12,273 |
|
Total
income taxes
|
|
$ |
(96,092 |
) |
|
$ |
147,476 |
|
|
$ |
190,024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
(loss) on common stock:
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
24,099 |
|
|
$ |
18,755 |
|
|
$ |
17,700 |
|
Natural
gas distribution
|
|
|
30,796 |
|
|
|
34,774 |
|
|
|
14,044 |
|
Construction
services
|
|
|
25,589 |
|
|
|
49,782 |
|
|
|
43,843 |
|
Pipeline
and energy services
|
|
|
37,845 |
|
|
|
26,367 |
|
|
|
31,408 |
|
Natural
gas and oil production
|
|
|
(296,730 |
) |
|
|
122,326 |
|
|
|
142,485 |
|
Construction
materials and contracting
|
|
|
47,085 |
|
|
|
30,172 |
|
|
|
77,001 |
|
Other
|
|
|
7,357 |
|
|
|
10,812 |
|
|
|
(4,380 |
) |
Earnings
(loss) on common stock before income from discontinued
operations
|
|
|
(123,959 |
) |
|
|
292,988 |
|
|
|
322,101 |
|
Income
from discontinued operations, net of tax
|
|
|
— |
|
|
|
— |
|
|
|
109,334 |
|
Total
earnings (loss) on common stock
|
|
$ |
(123,959 |
) |
|
$ |
292,988 |
|
|
$ |
431,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
115,240 |
|
|
$ |
72,989 |
|
|
$ |
91,548 |
|
Natural
gas distribution
|
|
|
43,820 |
|
|
|
398,116 |
|
|
|
500,178 |
|
Construction
services
|
|
|
12,814 |
|
|
|
24,506 |
|
|
|
18,241 |
|
Pipeline
and energy services
|
|
|
70,168 |
|
|
|
42,960 |
|
|
|
39,162 |
|
Natural
gas and oil production
|
|
|
183,140 |
|
|
|
710,742 |
|
|
|
283,589 |
|
Construction
materials and contracting
|
|
|
26,313 |
|
|
|
127,578 |
|
|
|
189,727 |
|
Other
|
|
|
3,196 |
|
|
|
774 |
|
|
|
1,621 |
|
Net
proceeds from sale or disposition of property
|
|
|
(26,679 |
) |
|
|
(86,927 |
) |
|
|
(24,983 |
) |
Net
capital expenditures before discontinued operations
|
|
|
428,012 |
|
|
|
1,290,738 |
|
|
|
1,099,083 |
|
Discontinued
operations
|
|
|
— |
|
|
|
— |
|
|
|
(548,216 |
) |
Total
net capital expenditures
|
|
$ |
428,012 |
|
|
$ |
1,290,738 |
|
|
$ |
550,867 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric*
|
|
$ |
569,666 |
|
|
$ |
479,639 |
|
|
$ |
428,200 |
|
Natural
gas distribution*
|
|
|
1,588,144 |
|
|
|
1,548,005 |
|
|
|
942,454 |
|
Construction
services
|
|
|
328,895 |
|
|
|
476,092 |
|
|
|
456,564 |
|
Pipeline
and energy services
|
|
|
538,230 |
|
|
|
506,872 |
|
|
|
500,755 |
|
Natural
gas and oil production
|
|
|
1,137,628 |
|
|
|
1,792,792 |
|
|
|
1,299,406 |
|
Construction
materials and contracting
|
|
|
1,449,469 |
|
|
|
1,552,296 |
|
|
|
1,642,729 |
|
Other**
|
|
|
378,920 |
|
|
|
232,149 |
|
|
|
322,326 |
|
Total
assets
|
|
$ |
5,990,952 |
|
|
$ |
6,587,845 |
|
|
$ |
5,592,434 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property,
plant and equipment:
|
|
|
|
|
|
|
|
|
|
Electric*
|
|
$ |
941,791 |
|
|
$ |
848,725 |
|
|
$ |
784,705 |
|
Natural
gas distribution*
|
|
|
1,456,208 |
|
|
|
1,429,487 |
|
|
|
948,446 |
|
Construction
services
|
|
|
116,236 |
|
|
|
111,301 |
|
|
|
101,935 |
|
Pipeline
and energy services
|
|
|
675,199 |
|
|
|
640,921 |
|
|
|
600,712 |
|
Natural
gas and oil production
|
|
|
2,028,794 |
|
|
|
2,477,402 |
|
|
|
1,923,899 |
|
Construction
materials and contracting
|
|
|
1,514,989 |
|
|
|
1,524,029 |
|
|
|
1,538,716 |
|
Other
|
|
|
33,365 |
|
|
|
30,372 |
|
|
|
31,833 |
|
Less
accumulated depreciation, depletion and
|
|
|
|
|
|
|
|
|
|
|
|
|
amortization
|
|
|
2,872,465 |
|
|
|
2,761,319 |
|
|
|
2,270,691 |
|
Net
property, plant and equipment
|
|
$ |
3,894,117 |
|
|
$ |
4,300,918 |
|
|
$ |
3,659,555 |
|
*
Includes allocations of common
utility property.
|
|
**
Includes assets not
directly assignable to a business (i.e. cash and cash equivalents, certain
accounts receivable, certain investments and other miscellaneous
current and deferred assets).
|
|
Note: The
results reflect a $620.0 million ($384.4 million after tax) and
$135.8 million ($84.2 million after tax) noncash write-down of
natural gas and oil properties in 2009 and 2008,
respectively.
|
|
The
pipeline and energy services segment and the Other category recognized income
from discontinued operations, net of tax, of $106,000 and $109.2 million,
respectively for the year ended December 31, 2007.
Excluding
income from discontinued operations at pipeline and energy services, earnings
from electric, natural gas distribution and pipeline and energy services are
substantially all from regulated operations. Earnings from construction
services, natural gas and oil production, construction materials and
contracting, and other are all from nonregulated operations.
Capital
expenditures for 2009, 2008 and 2007 include noncash transactions, including the
issuance of the Company's equity securities, in connection with acquisitions and
the outstanding indebtedness related to the 2008 Intermountain acquisition and
the 2007 Cascade acquisition. The net noncash transactions were immaterial in
2009, $97.6 million in 2008 and $217.3 million in 2007.
Note 16
– Employee Benefit Plans
The
Company has noncontributory defined benefit pension plans and other
postretirement benefit plans for certain eligible employees. The Company uses a
measurement date of December 31 for all of its pension and postretirement
benefit plans.
Effective
January 1, 2006, the Company discontinued defined pension plan benefits to
all nonunion and certain union employees hired after December 31, 2005.
These employees that would have been eligible for defined pension plan benefits
are eligible to receive additional defined contribution plan benefits. In 2009,
the Company evaluated several provisions of its employee defined benefit plans
for nonunion and certain union employees. As a result of this evaluation, the
Company determined that, effective January 1, 2010, all benefit and service
accruals of these plans were frozen. These employees will be eligible to receive
additional defined contribution plan benefits.
Effective
January 1, 2010, eligibility to receive retiree medical benefits was modified at
certain of the Company’s businesses. Current employees who attain age 55 with 10
years of continuous service by December 31, 2010, will be provided the current
retiree medical insurance benefits or
can elect
the new benefit, if desired, regardless of when they retire. All other current
employees must meet the new eligibility criteria of age 60 and 10 years of
continuous service at the time they retire. These employees will be eligible for
a specified company funded Retiree Reimbursement Account. Employees hired after
December 31, 2009, will not be eligible for retiree medical
benefits.
Changes
in benefit obligation and plan assets for the year ended December 31, 2009
and 2008, and amounts recognized in the Consolidated Balance Sheets at
December 31, 2009 and 2008, were as follows:
|
|
Pension
Benefits
|
|
|
Other
Postretirement Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
Change
in benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit
obligation at beginning of year
|
|
$ |
358,525 |
|
|
$ |
359,923 |
|
|
$ |
94,325 |
|
|
$ |
81,581 |
|
Service
cost
|
|
|
8,127 |
|
|
|
8,812 |
|
|
|
2,206 |
|
|
|
1,977 |
|
Interest
cost
|
|
|
21,919 |
|
|
|
21,264 |
|
|
|
5,465 |
|
|
|
5,079 |
|
Plan
participants' contributions
|
|
|
— |
|
|
|
— |
|
|
|
2,369 |
|
|
|
2,120 |
|
Amendments
|
|
|
— |
|
|
|
— |
|
|
|
(9,319 |
) |
|
|
(382 |
) |
Actuarial
(gain) loss
|
|
|
26,188 |
|
|
|
(8,336 |
) |
|
|
813 |
|
|
|
763 |
|
Curtailment
gain
|
|
|
(38,166 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Acquisition
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
9,872 |
|
Benefits
paid
|
|
|
(23,678 |
) |
|
|
(23,138 |
) |
|
|
(7,708 |
) |
|
|
(6,685 |
) |
Benefit
obligation at end of year
|
|
|
352,915 |
|
|
|
358,525 |
|
|
|
88,151 |
|
|
|
94,325 |
|
Change
in net plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
value of plan assets at beginning of year
|
|
|
226,214 |
|
|
|
330,966 |
|
|
|
60,085 |
|
|
|
73,684 |
|
Actual
gain (loss) on plan assets
|
|
|
42,084 |
|
|
|
(83,960 |
) |
|
|
8,600 |
|
|
|
(20,058 |
) |
Employer
contribution
|
|
|
10,707 |
|
|
|
2,346 |
|
|
|
3,638 |
|
|
|
3,212 |
|
Plan
participants' contributions
|
|
|
— |
|
|
|
— |
|
|
|
2,369 |
|
|
|
2,120 |
|
Acquisition
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
7,812 |
|
Benefits
paid
|
|
|
(23,678 |
) |
|
|
(23,138 |
) |
|
|
(7,708 |
) |
|
|
(6,685 |
) |
Fair
value of net plan assets at end of year
|
|
|
255,327 |
|
|
|
226,214 |
|
|
|
66,984 |
|
|
|
60,085 |
|
Funded
status – under
|
|
$ |
(97,588 |
) |
|
$ |
(132,311 |
) |
|
$ |
(21,167 |
) |
|
$ |
(34,240 |
) |
Amounts
recognized in the Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
Sheets at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
accrued liabilities (current)
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
(459 |
) |
|
$ |
(407 |
) |
Other
liabilities (noncurrent)
|
|
|
(97,588 |
) |
|
|
(132,311 |
) |
|
|
(20,708 |
) |
|
|
(33,833 |
) |
Net
amount recognized
|
|
$ |
(97,588 |
) |
|
$ |
(132,311 |
) |
|
$ |
(21,167 |
) |
|
$ |
(34,240 |
) |
Amounts
recognized in accumulated other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
(income) loss consist of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial
loss
|
|
$ |
99,985 |
|
|
$ |
131,081 |
|
|
$ |
20,134 |
|
|
$ |
23,418 |
|
Prior
service cost (credit)
|
|
|
430 |
|
|
|
2,685 |
|
|
|
(14,716 |
) |
|
|
(8,151 |
) |
Transition
obligation
|
|
|
— |
|
|
|
— |
|
|
|
6,378 |
|
|
|
8,503 |
|
Total
|
|
$ |
100,415 |
|
|
$ |
133,766 |
|
|
$ |
11,796 |
|
|
$ |
23,770 |
|
Employer
contributions and benefits paid in the preceding table include only those
amounts contributed directly to, or paid directly from, plan assets. Accumulated
other comprehensive (income) loss in the above table includes amounts related to
regulated operations, which are recorded as regulatory assets (liabilities) and
are expected to be reflected in rates charged to customers over
time.
Unrecognized
pension actuarial losses in excess of 10 percent of the greater of the
projected benefit obligation or the market-related value of assets is amortized
on a straight-line basis over the expected average remaining service lives of
active participants. The market-related value of assets is determined using a
five-year average of assets. Unrecognized postretirement net transition
obligation is amortized over a 20-year period ending 2012.
The
accumulated benefit obligation for the defined benefit pension plans reflected
above was $340.3 million and $312.1 million at December 31, 2009
and 2008, respectively.
The
projected benefit obligation, accumulated benefit obligation and fair value of
plan assets for the pension plans with accumulated benefit obligations in excess
of plan assets at December 31 were as follows:
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
Projected
benefit obligation
|
|
$ |
352,915 |
|
|
$ |
358,525 |
|
Accumulated
benefit obligation
|
|
$ |
340,341 |
|
|
$ |
312,110 |
|
Fair
value of plan assets
|
|
$ |
255,327 |
|
|
$ |
226,214 |
|
Components
of net periodic benefit cost for the Company's pension and other postretirement
benefit plans for the years ended December 31 were as follows:
|
|
Pension
Benefits
|
|
|
Other
Postretirement Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Components
of net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$ |
8,127 |
|
|
$ |
8,812 |
|
|
$ |
9,098 |
|
|
$ |
2,206 |
|
|
$ |
1,977 |
|
|
$ |
1,865 |
|
Interest
cost
|
|
|
21,919 |
|
|
|
21,264 |
|
|
|
18,591 |
|
|
|
5,465 |
|
|
|
5,079 |
|
|
|
4,212 |
|
Expected
return on assets
|
|
|
(25,062 |
) |
|
|
(26,501 |
) |
|
|
(22,524 |
) |
|
|
(5,471 |
) |
|
|
(5,657 |
) |
|
|
(4,776 |
) |
Amortization
of prior service cost (credit)
|
|
|
605 |
|
|
|
665 |
|
|
|
756 |
|
|
|
(2,756 |
) |
|
|
(2,755 |
) |
|
|
(1,300 |
) |
Recognized
net actuarial loss
|
|
|
2,096 |
|
|
|
1,050 |
|
|
|
1,605 |
|
|
|
970 |
|
|
|
594 |
|
|
|
73 |
|
Curtailment
loss
|
|
|
1,650 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Amortization
of net transition obligation
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
2,125 |
|
|
|
2,125 |
|
|
|
2,125 |
|
Net
periodic benefit cost, including amount capitalized
|
|
|
9,335 |
|
|
|
5,290 |
|
|
|
7,526 |
|
|
|
2,539 |
|
|
|
1,363 |
|
|
|
2,199 |
|
Less
amount capitalized
|
|
|
1,127 |
|
|
|
642 |
|
|
|
991 |
|
|
|
330 |
|
|
|
307 |
|
|
|
373 |
|
Net
periodic benefit cost
|
|
|
8,208 |
|
|
|
4,648 |
|
|
|
6,535 |
|
|
|
2,209 |
|
|
|
1,056 |
|
|
|
1,826 |
|
Other
changes in plan assets and benefit obligations recognized in accumulated
other comprehensive (income) loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(gain) loss
|
|
|
(29,000 |
) |
|
|
102,125 |
|
|
|
(11,095 |
) |
|
|
(2,314 |
) |
|
|
26,478 |
|
|
|
1,507 |
|
Acquisition-related
actuarial loss
|
|
|
— |
|
|
|
— |
|
|
|
12,291 |
|
|
|
— |
|
|
|
— |
|
|
|
9,818 |
|
Prior
service credit
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(9,321 |
) |
|
|
(382 |
) |
|
|
— |
|
Acquisition-related
prior service credit
|
|
|
— |
|
|
|
— |
|
|
|
(1,842 |
) |
|
|
— |
|
|
|
— |
|
|
|
(12,472 |
) |
Amortization
of actuarial loss
|
|
|
(2,096 |
) |
|
|
(1,050 |
) |
|
|
(1,605 |
) |
|
|
(970 |
) |
|
|
(594 |
) |
|
|
(73 |
) |
Amortization
of prior service (cost) credit
|
|
|
(2,255 |
) |
|
|
(665 |
) |
|
|
(756 |
) |
|
|
2,756 |
|
|
|
2,755 |
|
|
|
1,300 |
|
Amortization
of net transition obligation
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(2,125 |
) |
|
|
(2,125 |
) |
|
|
(2,125 |
) |
Total
recognized in accumulated other comprehensive (income)
loss
|
|
|
(33,351 |
) |
|
|
100,410 |
|
|
|
(3,007 |
) |
|
|
(11,974 |
) |
|
|
26,132 |
|
|
|
(2,045 |
) |
Total
recognized in net periodic benefit cost and accumulated other
comprehensive (income) loss
|
|
$ |
(25,143 |
) |
|
$ |
105,058 |
|
|
$ |
3,528 |
|
|
$ |
(9,765 |
) |
|
$ |
27,188 |
|
|
$ |
(219 |
) |
The
estimated net loss and prior service cost for the defined benefit pension plans
that will be amortized from accumulated other comprehensive loss into net
periodic benefit cost in 2010 are $2.4 million and $152,000, respectively.
The estimated net loss, prior service credit and transition obligation for the
other postretirement benefit plans that will be amortized from accumulated other
comprehensive loss into net periodic benefit cost in 2010 are $1.0 million,
$3.5 million and $2.1 million, respectively.
Weighted
average assumptions used to determine benefit obligations at December 31
were as follows:
|
|
|
|
|
Other
|
|
|
|
Pension
Benefits
|
|
|
Postretirement
Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount
rate
|
|
|
5.75 |
% |
|
|
6.25 |
% |
|
|
5.75 |
% |
|
|
6.25 |
% |
Rate
of compensation increase
|
|
|
4.00 |
% |
|
|
4.00 |
% |
|
|
4.00 |
% |
|
|
4.00 |
% |
Weighted
average assumptions used to determine net periodic benefit cost for the years
ended December 31 were as follows:
|
|
|
|
|
Other
|
|
|
|
Pension
Benefits
|
|
|
Postretirement
Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount
rate
|
|
|
6.25 |
% |
|
|
6.00 |
% |
|
|
6.25 |
% |
|
|
6.00 |
% |
Expected
return on plan assets
|
|
|
8.50 |
% |
|
|
8.50 |
% |
|
|
7.50 |
% |
|
|
7.50 |
% |
Rate
of compensation increase
|
|
|
4.00 |
% |
|
|
4.20 |
% |
|
|
4.00 |
% |
|
|
4.50 |
% |
The
expected rate of return on plan assets is based on the targeted asset allocation
of 70 percent equity securities and 30 percent fixed-income securities
and the expected rate of return from these asset categories. The expected return
on plan assets for other postretirement benefits reflects insurance-related
investment costs.
Health
care rate assumptions for the Company's other postretirement benefit plans as of
December 31 were as follows:
|
|
2009
|
|
|
2008
|
|
Health
care trend rate assumed for next year
|
|
|
6.0%-9.0 |
% |
|
|
6.0%-9.0 |
% |
Health
care cost trend rate – ultimate
|
|
|
5.0%-6.0 |
% |
|
|
5.0%-6.0 |
% |
Year
in which ultimate trend rate achieved
|
|
|
1999-2017 |
|
|
|
1999-2017 |
|
The
Company's other postretirement benefit plans include health care and life
insurance benefits for certain employees. The plans underlying these benefits
may require contributions by the employee depending on such employee's age and
years of service at retirement or the date of retirement. The accounting for the
health care plans anticipates future cost-sharing changes that are consistent
with the Company's expressed intent to generally increase retiree contributions
each year by the excess of the expected health care cost trend rate over
6 percent.
Assumed
health care cost trend rates may have a significant effect on the amounts
reported for the health care plans. A one percentage point change in the
assumed health care cost trend rates would have had the following effects at
December 31, 2009:
|
|
1 Percentage
|
|
|
1 Percentage
|
|
|
|
Point
Increase
|
|
|
Point
Decrease
|
|
|
|
(In
thousands)
|
|
Effect
on total of service
|
|
|
|
|
|
|
and
interest cost components
|
|
$ |
91 |
|
|
$ |
(922 |
) |
Effect
on postretirement
|
|
|
|
|
|
|
|
|
benefit
obligation
|
|
$ |
2,435 |
|
|
$ |
(9,679 |
) |
The
Company's pension assets are managed by 12 outside investment managers. The
Company's other postretirement assets are managed by one outside investment
manager. The Company's investment policy with respect to pension and other
postretirement assets is to make investments solely in the interest of the
participants and beneficiaries of the plans and for the exclusive purpose of
providing benefits accrued and defraying the reasonable expenses of
administration. The Company strives to maintain investment diversification to
assist in minimizing the risk of large losses. The Company's policy guidelines
allow for investment of funds in cash equivalents, fixed-income securities and
equity securities. The guidelines prohibit investment in commodities and future
contracts, equity private placement, employer securities, leveraged or
derivative securities, options, direct real estate investments, precious metals,
venture capital and limited partnerships. The guidelines also prohibit short
selling and margin transactions. The Company's practice is to periodically
review and rebalance asset categories based on its targeted asset
allocation percentage policy.
The fair
value of the Company’s pension net plan assets by category is as
follows:
|
Fair
Value Measurements at
December 31, 2009,
Using
|
|
|
|
Quoted
Prices
in
Active
Markets
for Identical
Assets
|
|
|
Significant
Other
Observable
Inputs
|
|
|
Significant
Unobservable Inputs
|
|
|
Balance
at December 31,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
2009
|
|
|
|
(In
thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stocks (a)
|
|
$ |
133,989 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
133,989 |
|
Collective
and mutual funds (b)
|
|
|
39,234 |
|
|
|
10,379 |
|
|
|
— |
|
|
|
49,613 |
|
U.S.
government and U.S. government-sponsored securities (c)
|
|
|
— |
|
|
|
28,091 |
|
|
|
— |
|
|
|
28,091 |
|
Corporate
and municipal bonds (d)
|
|
|
— |
|
|
|
27,968 |
|
|
|
— |
|
|
|
27,968 |
|
Collateral
held on loaned securities (e)
|
|
|
— |
|
|
|
21,597 |
|
|
|
937 |
|
|
|
22,534 |
|
Cash
and cash equivalents
|
|
|
17,958 |
|
|
|
— |
|
|
|
— |
|
|
|
17,958 |
|
Total
assets measured at fair value
|
|
|
191,181 |
|
|
|
88,035 |
|
|
|
937 |
|
|
|
280,153 |
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligation
for collateral received
|
|
|
24,826 |
|
|
|
— |
|
|
|
— |
|
|
|
24,826 |
|
Net
assets measured at fair value
|
|
$ |
166,355 |
|
|
$ |
88,035 |
|
|
$ |
937 |
|
|
$ |
255,327 |
|
(a)
|
This
category includes approximately 75 percent U.S. common stocks and 25
percent non-U.S. common stocks.
|
(b)
|
Collective
and mutual funds invest approximately 43 percent in common stock of
large-cap U.S. companies, 21 percent in asset-backed securities, 17
percent in cash and cash equivalents, 8 percent in small-cap U.S.
companies and 11 percent in other investments.
|
(c)
|
This
category includes approximately 69 percent U.S. government-sponsored
securities (asset-backed securities) and 31 percent U.S. government
securities.
|
(d)
|
This
category includes approximately 78 percent corporate bonds and 22 percent
municipal bonds.
|
(e)
|
This
category includes collateral held at December 31, 2009, as a result of
participation in a securities lending program. Cash collateral is invested
by the trustee primarily in repurchase agreements, money market funds,
corporate bonds, commercial paper, asset-backed securities and
certificates of deposit.
|
The
following table sets forth a summary of changes in the fair value of the pension
plan’s Level 3 assets for the year ended December 31, 2009:
|
Fair
Value Measurements Using Significant
Unobservable
Inputs (Level 3)
|
|
|
|
Collateral
Held on Loaned Securities
|
|
|
(In
thousands)
|
|
Balance
at beginning of year
|
|
$ |
573 |
|
Total
realized/unrealized losses
|
|
|
80 |
|
Purchases,
issuances and settlements (net)
|
|
|
284 |
|
Balance
at end of year
|
|
$ |
937 |
|
The fair
value of the Company’s other postretirement benefit plan assets by asset
category is as follows:
|
|
Fair
Value Measurements
at
December 31, 2009, Using
|
|
|
|
|
|
|
Quoted
Prices
in
Active
Markets
for Identical
Assets
|
|
|
Significant
Other
Observable
Inputs
|
|
|
Significant
Unobservable Inputs
|
|
|
Balance
at December 31,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
2009
|
|
|
|
(In
thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Money
market funds
|
|
$ |
1,469 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
1,469 |
|
Common
stock
|
|
|
2,897 |
|
|
|
— |
|
|
|
— |
|
|
|
2,897 |
|
Insurance
investment contract*
|
|
|
— |
|
|
|
62,618 |
|
|
|
— |
|
|
|
62,618 |
|
Total
assets measured at fair value
|
|
$ |
4,366 |
|
|
$ |
62,618 |
|
|
$ |
— |
|
|
$ |
66,984 |
|
*
Invested in mutual funds.
|
|
The
Company expects to contribute approximately $10.2 million to its defined
benefit pension plans and approximately $4.1 million to its postretirement
benefit plans in 2010.
The
following benefit payments, which reflect future service, as appropriate, are
expected to be paid:
|
|
|
|
|
Other
|
|
|
|
Pension
|
|
|
Postretirement
|
|
Years
|
|
Benefits
|
|
|
Benefits
|
|
|
|
(In
thousands)
|
|
2010
|
|
$ |
20,431 |
|
|
$ |
6,027 |
|
2011
|
|
|
20,744 |
|
|
|
6,244 |
|
2012
|
|
|
21,496 |
|
|
|
6,431 |
|
2013
|
|
|
22,151 |
|
|
|
6,686 |
|
2014
|
|
|
22,640 |
|
|
|
6,905 |
|
2015
- 2019
|
|
|
122,347 |
|
|
|
37,504 |
|
The
following Medicare Part D subsidies are expected: $637,000 in 2010; $675,000 in
2011; $725,000 in 2012; $765,000 in 2013; $807,000 in 2014; and
$4.7 million during the years 2015 through 2019.
In
addition to company-sponsored plans, certain employees are covered under
multi-employer pension plans administered by a union. Amounts contributed in
2009 to defined benefit and defined contribution multi-employer plans were
$32.5 million and $16.4 million, respectively. Amounts contributed to
the multi-employer plans were $73.1 million and $51.5 million in 2008
and 2007, respectively.
In
addition to the qualified plan defined pension benefits reflected in the table
at the beginning of this note, the Company also has unfunded, nonqualified
benefit plans for executive officers and certain key management employees that
generally provide for defined benefit payments at age 65 following the
employee's retirement or to their beneficiaries upon death for a 15-year period.
The Company had investments of $67.9 million at December 31, 2009,
consisting of equity securities of $32.1 million, life insurance carried on
plan participants (payable upon the employee's death) of $29.8 million,
fixed-income securities of $2.7 million and other investments of $3.3
million, which the Company anticipates using to satisfy obligations under these
plans. The Company's net periodic benefit cost for these plans was
$8.8 million, $9.0 million and $7.6 million in 2009, 2008 and
2007, respectively. The total projected benefit obligation for these plans was
$93.0 million and $87.2 million at December 31, 2009 and 2008,
respectively. The accumulated benefit obligation for these plans was
$84.8 million and $77.3 million at December 31, 2009 and 2008,
respectively. A discount rate of 5.75 percent and 6.25 percent at
December 31, 2009 and 2008, respectively, and a rate of compensation
increase of 4.00 percent at December 31, 2009 and 2008, were used to
determine benefit obligations. A discount rate of 6.25 percent and
6.00 percent at December 31, 2009 and 2008, respectively, and a rate
of compensation increase of 4.00 percent and 4.25 percent at
December 31, 2009 and 2008, respectively, were used to determine net
periodic benefit cost.
The
amount of benefit payments for the unfunded, nonqualified benefit plans, as
appropriate, are expected to aggregate $4.6 million in 2010;
$5.0 million in 2011; $5.3 million in 2012; $5.9 million in 2013;
$5.9 million in 2014; and $36.3 million for the years 2015 through
2019.
The
Company sponsors various defined contribution plans for eligible employees.
Costs incurred by the Company under these plans were $20.5 million in 2009,
$23.8 million in 2008 and $21.1 million in 2007.
Note 17
– Jointly Owned Facilities
The
consolidated financial statements include the Company's 22.7 percent and
25.0 percent ownership interests in the assets, liabilities and expenses of
the Big Stone Station and the Coyote Station, respectively. Each owner of the
Big Stone and Coyote stations is responsible for financing its investment in the
jointly owned facilities.
The
Company's share of the Big Stone Station and Coyote Station operating expenses
was reflected in the appropriate categories of operating expenses in the
Consolidated Statements of Income.
At
December 31, the Company's share of the cost of utility plant in service
and related accumulated depreciation for the stations was as
follows:
|
|
2009
|
|
|
2008
|
|
|
|
(In
thousands)
|
|
Big
Stone Station:
|
|
|
|
|
|
|
Utility
plant in service
|
|
$ |
60,220 |
|
|
$ |
61,030 |
|
Less
accumulated depreciation
|
|
|
39,940 |
|
|
|
39,473 |
|
|
|
$ |
20,280 |
|
|
$ |
21,557 |
|
Coyote
Station:
|
|
|
|
|
|
|
|
|
Utility
plant in service
|
|
$ |
131,042 |
|
|
$ |
127,151 |
|
Less
accumulated depreciation
|
|
|
82,402 |
|
|
|
82,018 |
|
|
|
$ |
48,640 |
|
|
$ |
45,133 |
|
In April
2009, the Company purchased a 25 MW ownership interest in the Wygen III electric
generation facility, which is under construction near Gillette, Wyoming, and is
expected to be online in the second quarter of 2010. The Company’s balance of
construction work in progress related to this facility that is included in
property, plant and equipment on the Consolidated Balance Sheets at December 31,
2009, is $56.1 million.
Note 18
– Regulatory Matters and Revenues Subject to Refund
In
November 2006, Montana-Dakota filed an application with the NDPSC requesting an
advance determination of prudence of Montana-Dakota's ownership interest in Big
Stone Station II. In August 2008, the NDPSC approved Montana-Dakota’s
request for advance determination of prudence for ownership in the proposed Big
Stone Station II for a minimum of 121.8 MW up to a maximum of 133 MW
and a proportionate ownership share of the associated transmission electric
resources. The intervenors in the proceeding appealed the NDPSC order to the
North Dakota District Court which affirmed the order of the NDPSC. The
intervenors then appealed the North Dakota District Court order to the North
Dakota Supreme Court. The Big Stone Station II participants subsequently decided
not to proceed with the project and on December 2, 2009, Montana-Dakota
filed an application with the NDPSC for a determination that Montana-Dakota’s
continued participation in the Big Stone Station II is no longer prudent. The
parties have stipulated that the intervenors will move to dismiss their appeal
to the North Dakota Supreme Court if the NDPSC grants Montana-Dakota’s pending
application for a determination that its participation in the Big Stone Station
II is no longer prudent. On December 4, 17, and 23, 2009, Montana-Dakota
filed an application with the NDPSC, SDPUC, and MTPSC, respectively, for
authority to defer the costs incurred for securing new electric generation,
primarily Big Stone Station II, until the next general rate case.
On
August 14, 2009, Montana-Dakota filed an application with the WYPSC for an
electric rate increase. Montana-Dakota requested a total increase of
$6.2 million annually or approximately 31 percent above current rates.
The rate increase request was necessitated by the Company’s 25 MW ownership
interest in the Wygen III power generation facility currently under construction
near Gillette, Wyoming. The generation will replace a portion of the purchased
power currently used to serve its Wyoming system. On January 14, 2010,
Montana-Dakota filed a supplement to the application to reflect the inclusion of
bonus tax depreciation on the Wygen III plant, reducing its request to a
$5.1 million annual increase or approximately 25 percent above current
rates. A hearing has been set for February 23, 2010.
In
December 1999, Williston Basin filed a general natural gas rate change
application with the FERC. Williston Basin began collecting such rates effective
June 1, 2000, subject to refund. There had been one remaining issue
outstanding related to this rate change application regarding certain service
restrictions. After various steps in this proceeding, including a Williston
Basin Request for Rehearing, an appeal to the D.C. Appeals Court, and a remand
to FERC, the FERC, on October 30, 2009, issued its Order on Remand in which
it upheld its previous decision. No party requested rehearing of the order,
which is now final, and no issue is outstanding in this
application.
Note 19
– Commitments and Contingencies
Litigation
Coalbed Natural
Gas Operations Fidelity’s CBNG operations are and have been the subject
of numerous lawsuits in Montana and Wyoming. The current cases involve the
permitting and use of water produced in connection with Fidelity’s CBNG
development in the Powder River Basin. Some of these cases challenge the
issuance of discharge permits by the Montana DEQ and approval of other water
management tools by the MBOGC.
In April
2006, the Northern Cheyenne Tribe filed a complaint in Montana Twenty-Second
Judicial District Court against the Montana DEQ seeking to set aside Fidelity’s
renewed direct discharge and treatment permits. The Northern Cheyenne Tribe
claimed the Montana DEQ violated the Clean Water Act and the Montana Water
Quality Act by failing to include in the permits conditions requiring
application of the best practicable control technology currently available and
by failing to impose a nondegradation policy like the one the BER adopted soon
after the permit was issued. In addition, the Northern Cheyenne Tribe claimed
that the actions of the Montana DEQ violated the Montana State Constitution’s
guarantee of a clean and healthful environment, that the Montana DEQ’s related
environmental assessment was invalid, that the Montana DEQ was required, but
failed, to prepare an EIS and that the Montana DEQ failed to consider other
alternatives to the issuance of the permits. Fidelity, the NPRC, and the TRWUA
were granted leave to intervene in this proceeding. On January 12, 2009,
the Montana Twenty-Second Judicial District Court decided the case in favor of
Fidelity and the Montana DEQ in all respects, denying the motions of the
Northern Cheyenne Tribe, TRWUA, and NPRC, and granting the cross-motions of the
Montana DEQ and Fidelity in their entirety. As a result, Fidelity may continue
to utilize its direct discharge and treatment permits. The NPRC, the TRWUA and
the Northern Cheyenne Tribe appealed the decision to the Montana Supreme Court
on March 9, 11, and 13, 2009, respectively.
Fidelity’s
discharge of water pursuant to its two permits is its primary means for managing
CBNG-produced water. Fidelity believes that its discharge permits should,
assuming normal operating conditions, allow Fidelity to continue its existing
CBNG operations through the expiration of the permits in March 2011. If its
permits are set aside, Fidelity’s CBNG operations in Montana could be
significantly and adversely affected.
In
October 2003, Tongue & Yellowstone Irrigation District, NPRC and MEIC filed
a lawsuit in Montana First Judicial District Court challenging the MBOGC’s ROD
adopting the 2003 Final EIS which analyzed CBNG development in the State of
Montana. Through the amendment of the plaintiffs’ pleadings and as a result of
discovery, the defendants have now determined that the primary legal issue
before the Court is whether the ROD authorizes the “wasting” of ground water in
violation of the Montana State Constitution and the public trust doctrine.
Specifically, the plaintiffs contend that various water management tools,
including Fidelity’s direct discharge permits, allow for the waste of water.
Should the Montana First Judicial District Court determine that Fidelity’s
direct discharge permits violate the Montana State Constitution, Fidelity’s
Montana CBNG operations could be significantly and adversely
affected.
Fidelity
will continue to vigorously defend its interests in all CBNG-related litigation
in which it is involved. If the plaintiffs are successful in these lawsuits, the
ultimate outcome of the actions could adversely impact Fidelity’s existing CBNG
operations and/or the future development of this resource in the affected
regions.
Electric
Operations In June 2008, the Sierra Club filed a complaint in the South
Dakota Federal District Court against Montana-Dakota and the two other co-owners
of the Big Stone Station. The complaint alleged certain violations of the PSD
and NSPS provisions of the Clean Air Act and certain violation of the South
Dakota SIP. The action further alleged that the Big Stone Station was modified
and operated 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. The Sierra Club alleged that these actions contributed to
air pollution and visibility impairment and have increased the risk of adverse
health effects and environmental damage. The Sierra Club sought declaratory and
injunctive relief to bring the co-owners of the Big Stone Station into
compliance with the Clean Air Act and the South Dakota SIP and to require them
to remedy the alleged violations. The Sierra Club also sought unspecified civil
penalties, including a beneficial mitigation project. The Company believes the
claims are without merit and that Big Stone Station has been and is being
operated in compliance with the Clean Air Act and the South Dakota SIP. On
March 31, 2009, the District Court granted the motion of the co-owners to
dismiss the complaint. The Sierra Club filed a motion requesting the District
Court to reconsider its ruling on a portion of the order dismissing the
complaint which was denied on July 22, 2009. On
July 30, 2009, the Sierra Club appealed from the orders dismissing the case
and denying the motion for reconsideration to the United States Court of Appeals
for the Eighth Circuit. The United States has filed a brief as amicus curiae
supporting the Sierra Club’s position in the appeal and the State of South
Dakota filed a brief as amicus curiae supporting the Big Stone Station owners’
position in the appeal.
Construction
Materials LTM is a third-party
defendant in litigation pending in Oregon Circuit Court regarding the concrete
floors in an industrial food processing facility located in Jackson County,
Oregon. The complaint against the facility construction contractor alleges the
concrete floors of the facility are defective and must be removed and replaced
for suitable repair. Damages, including disruption of the food processing
operations, have been estimated by the plaintiff to be in excess of
$32 million. The construction contractor’s answer and third-party complaint
alleges the owner and third-party defendants, including LTM which supplied
the concrete, are primarily responsible for any defects in the concrete
surfaces. Discovery is currently being conducted by the parties. A trial date
has not been set.
The
Company also is involved in other legal actions in the ordinary course of its
business. Although the outcomes of any such legal actions cannot be predicted,
management believes that the outcomes with respect to these other legal
proceedings will not have a material adverse effect upon the Company’s financial
position or results of operations.
Environmental
matters
Portland Harbor
Site In December 2000, MBI was named by the EPA as a PRP in connection
with the cleanup of a riverbed site adjacent to a commercial property site
acquired by MBI from Georgia-Pacific West, Inc. in 1999. The riverbed site is
part of the Portland, Oregon, Harbor Superfund Site. The EPA wants responsible
parties to share in the cleanup of sediment contamination in the Willamette
River. To date, costs of the overall remedial investigation and feasibility
study of the harbor site are being recorded, and initially paid, through an
administrative consent order by the LWG, a group of several entities, which does
not include MBI or Georgia-Pacific West, Inc. Investigative costs are indicated
to be in excess of $70 million. It is not possible to estimate the cost of
a corrective action plan until the remedial investigation and feasibility study
have been completed, the EPA has decided on a strategy and a ROD has been
published. Corrective action will be taken after the development of a proposed
plan and ROD on the harbor site is issued. MBI also received notice in January
2008 that the Portland Harbor Natural Resource Trustee Council intends to
perform an injury assessment to natural resources resulting from the release of
hazardous substances at the Harbor Superfund Site. The Trustee Council indicates
the injury determination is appropriate to facilitate early settlement of
damages and restoration for natural resource injuries. It is not possible to
estimate the costs of natural resource damages until an assessment is completed
and allocations are undertaken.
Based
upon a review of the Portland Harbor sediment contamination evaluation by the
Oregon DEQ and other information available, MBI does not believe it is a
Responsible Party. In addition, MBI has notified Georgia-Pacific West, Inc.,
that it intends to seek indemnity for liabilities incurred in relation to the
above matters pursuant to the terms of their sale agreement. MBI has entered
into an agreement tolling the statute of limitations in connection with the
LWG’s potential claim for contribution to the costs of the remedial
investigation and feasibility study. By letter of March 2, 2009, LWG stated
its intent to file suit against MBI and others to recover LWG’s investigation
costs to the extent MBI cannot demonstrate its non-liability for the
contamination or is unwilling to participate in an alternative dispute
resolution process that has been established to address the matter. At this
time, MBI has agreed to participate in the alternative dispute resolution
process.
The
Company believes it is not probable that it will incur any material
environmental remediation costs or damages in relation to the above referenced
administrative action.
Manufactured Gas
Plant Sites There are three claims against Cascade for cleanup of
environmental contamination at manufactured gas plant sites operated by
Cascade’s predecessors.
The first
claim is for soil and groundwater contamination at a site in Oregon and was
received in 1995. There are PRPs in addition to Cascade that may be liable for
cleanup of the contamination. Some of these PRPs have shared in the
investigation costs. It is expected that these and other PRPs will share in the
cleanup costs. Several alternatives for cleanup have been identified, with
preliminary cost estimates ranging from approximately $500,000 to
$11.0 million. An ecological risk assessment draft report was submitted to
the Oregon DEQ in June 2009. The assessment showed no unacceptable risk to the
aquatic ecological receptors present in the shoreline along the site and
concluded that no further ecological investigation is necessary. The report is
being reviewed by the Oregon DEQ. It is anticipated the Oregon DEQ will
recommend a cleanup
alternative
for the site after it completes its review of the report. It is not known at
this time what share of the cleanup costs will actually be borne by
Cascade.
The
second claim is for contamination at a site in Washington and was received in
1997. A preliminary investigation has found soil and groundwater at the site
contain contaminants requiring further investigation and cleanup. EPA conducted
a Targeted Brownfields Assessment of the site and released a report summarizing
the results of that assessment in August 2009. The assessment confirms that
contaminants have affected soil and groundwater at the site, as well as
sediments in the adjacent Port Washington Narrows. Alternative remediation
options have been identified with preliminary cost estimates ranging from
$340,000 to $6.4 million. Data developed through the assessment and
previous investigations indicates the contamination likely derived from
multiple, different sources and multiple current and former owners of properties
and businesses in the vicinity of the site may be responsible for the
contamination. There is currently not enough information to estimate the
potential liability to Cascade associated with this claim.
The third
claim is also for contamination at a site in Washington. Cascade received notice
from a party in May 2008 that Cascade may be a PRP, along with other parties,
for contamination from a manufactured gas plant owned by Cascade’s predecessor
from about 1946 to 1962. The notice indicates that current estimates to complete
investigation and cleanup of the site exceed $8.0 million. There is
currently not enough information available to estimate the potential liability
to Cascade associated with this claim.
To the
extent these claims are not covered by insurance, Cascade will seek recovery
through the OPUC and WUTC of remediation costs in its natural gas rates charged
to customers.
Operating
leases
The
Company leases certain equipment, facilities and land under operating lease
agreements. The amounts of annual minimum lease payments due under these leases
as of December 31, 2009, were $25.2 million in 2010,
$20.3 million in 2011, $15.3 million in 2012, $12.6 million in
2013, $6.7 million in 2014 and $43.9 million thereafter. Rent expense was
$43.4 million, $35.3 million and $35.6 million for the years
ended December 31, 2009, 2008 and 2007, respectively.
Purchase
commitments
The
Company has entered into various commitments, largely natural gas and coal
supply, purchased power, natural gas transportation and storage and construction
materials supply contracts. These commitments range from 1 to 51 years. The
commitments under these contracts as of December 31, 2009, were
$507.6 million in 2010, $288.3 million in 2011, $192.1 million in
2012, $105.7 million in 2013, $90.3 million in 2014 and $234.9 million
thereafter. These commitments were not reflected in the Company's consolidated
financial statements. Amounts purchased under various commitments for the years
ended December 31, 2009, 2008 and 2007, were $723.1 million,
approximately $1.0 billion (including the acquisition of Intermountain as
discussed in Note 2) and $857.0 million (including the acquisition of
Cascade as discussed in Note 2), respectively.
Guarantees
In
connection with the sale of MPX in June 2005 to Petrobras, an indirect wholly
owned subsidiary of the Company has agreed to indemnify Petrobras for
49 percent of any losses that Petrobras may incur from certain contingent
liabilities specified in the purchase agreement. Centennial has agreed to
unconditionally guarantee payment of the indemnity obligations to Petrobras for
periods ranging up to five and a half years from the date of sale. The guarantee
was required by Petrobras as a condition to closing the sale of
MPX.
Centennial
guaranteed CEM's obligations under a construction contract with LPP for a 550-MW
combined-cycle electric generating facility near Hobbs, New Mexico. Centennial
Resources sold CEM in July 2007 to Bicent Power LLC, which provided a
$10 million bank letter of credit to Centennial in support of the guarantee
obligation. On February 27, 2009, Centennial received a Notice and Demand
from LPP under the guaranty agreement alleging that CEM did not meet certain of
its obligations under the construction contract and demanding that Centennial
indemnify LPP against all losses, damages, claims, costs, charges and expenses
arising from CEM’s alleged failures. On December 4, 2009, LPP submitted a
demand for arbitration of its dispute with CEM to the American Arbitration
Association. The demand seeks compensatory damages of $146 million plus damages
for increased operating, capital and construction costs related to a water
treatment facility for the generating facility. LPP’s notice of demand for
arbitration also demanded performance of the guarantee by Centennial. The
Company believes the indemnification claims against Centennial are without merit
and intends to vigorously defend against such claims.
In
connection with the pending sale of the Brazilian Transmission Lines, as
discussed in Note 4, Centennial has agreed to guarantee the performance of
certain of the Company’s indirect wholly owned subsidiaries in three purchase
and sale agreements. Centennial has agreed to unconditionally guarantee payment
of the indemnity obligations of the wholly owned subsidiary sellers for periods
ranging up to 10 years from the date of sale. The guarantees were required
by the buyers as a condition to the sale of the Brazilian Transmission
Lines.
In
addition, WBI Holdings has guaranteed certain of Fidelity’s natural gas swap and
collar agreement obligations. There is no fixed maximum amount guaranteed in
relation to the natural gas swap and collar agreements as the amount of the
obligation is dependent upon natural gas commodity prices. The amount of hedging
activity entered into by the subsidiary is limited by corporate policy. The
guarantees of the natural gas swap and collar agreements at December 31,
2009, expire in 2010 and 2011; however, Fidelity continues to enter into
additional hedging activities and, as a result, WBI Holdings from time to time
may issue additional guarantees on these hedging obligations. There were no
amounts outstanding by Fidelity at December 31, 2009. In the event Fidelity
defaults under its obligations, WBI Holdings would be required to make payments
under its guarantees.
Certain
subsidiaries of the Company have outstanding guarantees to third parties that
guarantee the performance of other subsidiaries of the Company. These guarantees
are related to construction contracts, natural gas transportation and sales
agreements, gathering contracts, a conditional purchase agreement and certain
other guarantees. At December 31, 2009, the fixed maximum amounts
guaranteed under these agreements aggregated $234.4 million. The amounts of
scheduled expiration of the maximum amounts guaranteed under these agreements
aggregate $65.3 million in 2010; $141.8 million in 2011;
$16.7 million in 2012; $1.8 million in 2013; $200,000 in 2014;
$1.0 million in 2018; $300,000 in 2019; $3.3 million, which is subject
to expiration on a specified number of days after the receipt of written notice;
and $4.0 million, which has no scheduled maturity date. The amount
outstanding by subsidiaries of the Company under the above guarantees was
$570,000 and was reflected on the Consolidated Balance Sheet at
December 31,
2009. In the event of default under these guarantee obligations, the subsidiary
issuing the guarantee for that particular obligation would be required to make
payments under its guarantee.
Certain
subsidiaries have outstanding letters of credit to third parties related to
insurance policies, materials obligations, natural gas transportation agreements
and other agreements that guarantee the performance of other subsidiaries of the
Company. At December 31, 2009, the fixed maximum amounts guaranteed under
these letters of credit, aggregated $37.1 million, which are scheduled to
expire in 2010. There were no amounts outstanding under the above letters of
credit at December 31, 2009.
WBI
Holdings has an outstanding guarantee to Williston Basin. This guarantee is
related to a natural gas transportation and storage agreement that guarantees
the performance of Prairielands. At December 31, 2009, the fixed maximum
amount guaranteed under this agreement was $5.0 million and is scheduled to
expire in 2011. In the event of Prairielands’ default in its payment
obligations, WBI Holdings would be required to make payment under its guarantee.
The amount outstanding by Prairielands under the above guarantee was $870,000.
Prairielands also had $650,000 outstanding under a guarantee with Fidelity that
will expire when paid. The amounts outstanding under these guarantees were not
reflected on the Consolidated Balance Sheet at December 31, 2009, because
these intercompany transactions are eliminated in consolidation.
In
addition, Centennial and Knife River have issued guarantees to third parties
related to the Company’s routine purchase of maintenance items, materials and
lease obligations for which no fixed maximum amounts have been specified. These
guarantees have no scheduled maturity date. In the event a subsidiary of the
Company defaults under its obligation in relation to the purchase of certain
maintenance items, materials or lease obligations, Centennial or Knife River
would be required to make payments under these guarantees. Any amounts
outstanding by subsidiaries of the Company for these maintenance items and
materials were reflected on the Consolidated Balance Sheet at December 31,
2009.
In the
normal course of business, Centennial has purchased surety bonds related to
construction contracts and reclamation obligations of its subsidiaries. In the
event a subsidiary of Centennial does not fulfill a bonded obligation,
Centennial would be responsible to the surety bond company for completion of the
bonded contract or obligation. A large portion of the surety bonds is expected
to expire within the next 12 months; however, Centennial will likely
continue to enter into surety bonds for its subsidiaries in the future. As of
December 31, 2009, approximately $532 million of surety bonds were
outstanding, which were not reflected on the Consolidated Balance
Sheet.
Note 20
– Subsequent Events
The
Company evaluated for events or transactions between the balance sheet date and
February 17, 2010, the date of the issuance of the financial statements,
that would require recognition or disclosure in the financial
statements.
Supplementary
Financial Information
Quarterly
Data (Unaudited)
The
following unaudited information shows selected items by quarter for the years
2009 and 2008:
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter*
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
**
|
|
|
|
(In
thousands, except per share amounts)
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$ |
1,094,005 |
|
|
$ |
958,040 |
|
|
$ |
1,107,927 |
|
|
$ |
1,016,529 |
|
Operating
expenses
|
|
|
1,634,924 |
|
|
|
857,975 |
|
|
|
947,654 |
|
|
|
889,045 |
|
Operating
income (loss)
|
|
|
(540,919 |
) |
|
|
100,065 |
|
|
|
160,273 |
|
|
|
127,484 |
|
Net
income (loss)
|
|
|
(343,803 |
) |
|
|
55,311 |
|
|
|
92,584 |
|
|
|
72,634 |
|
Earnings
(loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
(1.87 |
) |
|
|
.30 |
|
|
|
.50 |
|
|
|
.39 |
|
Diluted
|
|
|
(1.87 |
) |
|
|
.30 |
|
|
|
.50 |
|
|
|
.38 |
|
Weighted
average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
183,787 |
|
|
|
183,964 |
|
|
|
185,160 |
|
|
|
187,748 |
|
Diluted
|
|
|
183,787 |
|
|
|
184,398 |
|
|
|
185,425 |
|
|
|
188,373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$ |
1,121,907 |
|
|
$ |
1,251,772 |
|
|
$ |
1,333,834 |
|
|
$ |
1,295,765 |
|
Operating
expenses
|
|
|
994,335 |
|
|
|
1,053,281 |
|
|
|
1,130,537 |
|
|
|
1,313,088 |
|
Operating
income (loss)
|
|
|
127,572 |
|
|
|
198,491 |
|
|
|
203,297 |
|
|
|
(17,323 |
) |
Net
income (loss)
|
|
|
71,051 |
|
|
|
115,507 |
|
|
|
118,382 |
|
|
|
(11,267 |
) |
Earnings
(loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
.39 |
|
|
|
.63 |
|
|
|
.65 |
|
|
|
(.06 |
) |
Diluted
|
|
|
.39 |
|
|
|
.63 |
|
|
|
.64 |
|
|
|
(.06 |
) |
Weighted
average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
182,599 |
|
|
|
182,972 |
|
|
|
183,219 |
|
|
|
183,603 |
|
Diluted
|
|
|
183,130 |
|
|
|
183,727 |
|
|
|
184,081 |
|
|
|
183,603 |
|
* 2009 reflects a $384.4 million after-tax noncash write-down
of natural gas and oil properties.
**
2008 reflects an $84.2 million after-tax noncash write-down of
natural gas and oil properties.
|
|
Certain
Company operations are highly seasonal and revenues from and certain expenses
for such operations may fluctuate significantly among quarterly periods.
Accordingly, quarterly financial information may not be indicative of results
for a full year.
Natural
Gas and Oil Activities (Unaudited)
Fidelity
is involved in the acquisition, exploration, development and production of
natural gas and oil resources. Fidelity's activities include the acquisition of
producing properties with potential development opportunities, exploratory
drilling and the operation and development of production properties. Fidelity
shares revenues and expenses from the development of specified properties in the
Rocky Mountain and Mid-Continent regions of the United States and in and around
the Gulf of Mexico in proportion to its ownership interests.
Fidelity
owns in fee or holds natural gas leases for the properties it operates in
Colorado, Montana, North Dakota, Texas, Utah and Wyoming. These rights are in
the Bonny Field in eastern Colorado, the Baker Field in southeastern Montana and
southwestern North Dakota, the Bowdoin area in north-central Montana, the Powder
River Basin of Montana and Wyoming, the Bakken area in North Dakota, the Paradox
Basin of Utah, the Tabasco and Texan Gardens fields of Texas
and the
Big Horn Basin in Wyoming. In 2008, Fidelity acquired and became the operator of
natural gas properties in Rusk County in eastern Texas.
The
information that follows includes Fidelity's proportionate share of all its
natural gas and oil interests.
The
following table sets forth capitalized costs and accumulated depreciation,
depletion and amortization related to natural gas and oil producing activities
at December 31:
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Subject
to amortization
|
|
$ |
1,815,380 |
|
|
$ |
2,211,865 |
|
|
$ |
1,750,233 |
|
Not
subject to amortization
|
|
|
178,214 |
|
|
|
232,081 |
|
|
|
142,524 |
|
Total
capitalized costs
|
|
|
1,993,594 |
|
|
|
2,443,946 |
|
|
|
1,892,757 |
|
Less
accumulated depreciation,
|
|
|
|
|
|
|
|
|
|
|
|
|
depletion
and amortization
|
|
|
969,630 |
|
|
|
846,074 |
|
|
|
681,101 |
|
Net
capitalized costs
|
|
$ |
1,023,964 |
|
|
$ |
1,597,872 |
|
|
$ |
1,211,656 |
|
Note:
Net capitalized costs as of December 31, 2009 and 2008, reflect noncash
write-downs of the Company’s natural gas and oil properties, as discussed in
Note 1.
Capital
expenditures, including those not subject to amortization, related to natural
gas and oil producing activities were as follows:
Years
ended December 31,
|
|
|
2009 |
* |
|
|
2008 |
* |
|
|
2007 |
* |
|
|
(In
thousands)
|
|
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
properties
|
|
$ |
3,879 |
|
|
$ |
225,610 |
|
|
$ |
426 |
|
Unproved
properties
|
|
|
8,771 |
|
|
|
107,419 |
|
|
|
17,731 |
|
Exploration
|
|
|
33,123 |
|
|
|
109,828 |
|
|
|
48,744 |
|
Development* *
|
|
|
135,202 |
|
|
|
260,098 |
|
|
|
214,433 |
|
Total
capital expenditures
|
|
$ |
180,975 |
|
|
$ |
702,955 |
|
|
$ |
281,334 |
|
*Excludes net additions to
property, plant and equipment related to the recognition of future
liabilities for asset retirement obligations associated with the plugging
and abandonment of natural gas and oil wells, as discussed in Note 10, of
$2.0 million, $3.0 million and $5.4 million for the years
ended December 31, 2009, 2008 and 2007, respectively.
**
Includes expenditures for proved undeveloped reserves of
$32.5 million, $46.7 million and $74.6 million for the
years ended December 31, 2009, 2008 and 2007,
respectively.
|
|
The
following summary reflects income resulting from the Company's operations of
natural gas and oil producing activities, excluding corporate overhead and
financing costs:
Years
ended December 31,
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
Sales
to affiliates
|
|
$ |
101,230 |
|
|
$ |
291,642 |
|
|
$ |
226,706 |
|
Sales
to external customers
|
|
|
338,425 |
|
|
|
420,488 |
|
|
|
287,557 |
|
Production
costs
|
|
|
123,148 |
|
|
|
161,401 |
|
|
|
123,924 |
|
Depreciation,
depletion and
|
|
|
|
|
|
|
|
|
|
|
|
|
amortization*
|
|
|
126,278 |
|
|
|
167,427 |
|
|
|
124,599 |
|
Write-down
of natural gas and oil properties
|
|
|
620,000 |
|
|
|
135,800 |
|
|
|
— |
|
Pretax
income
|
|
|
(429,771 |
) |
|
|
247,502 |
|
|
|
265,740 |
|
Income
tax expense
|
|
|
(164,216 |
) |
|
|
91,593 |
|
|
|
98,729 |
|
Results
of operations for
|
|
|
|
|
|
|
|
|
|
|
|
|
producing
activities
|
|
$ |
(265,555 |
) |
|
$ |
155,909 |
|
|
$ |
167,011 |
|
*
Includes accretion of discount for asset retirement obligations of
$2.7 million, $2.5 million and $2.5 million for the years
ended December 31, 2009, 2008 and 2007, respectively, as discussed in
Note 10.
|
|
The
following table summarizes the Company's estimated quantities of proved natural
gas and oil reserves at December 31, 2009, 2008 and 2007, and reconciles
the changes between these dates. Estimates of proved reserves were prepared in
accordance with guidelines established by the industry and the SEC. The
estimates are arrived at using actual historical wellhead production trends
and/or standard reservoir engineering methods utilizing available geological,
geophysical, engineering and economic data. Other factors used in the reserve
estimates are natural gas and oil prices, current estimates of well operating
and future development costs, taxes, timing of operations, and the interests
owned by the Company in the properties. These estimates are refined as new
information becomes available.
The
reserve estimates as of December 31, 2009, were calculated using SEC Defined
Prices and prior to that time, reserve estimates were calculated using spot
market prices that existed at the end of the applicable period. SEC Defined
Prices used for the December 31, 2009, reserve estimates for natural gas were
significantly lower than December 31, 2008, spot market prices. As a result, the
Company had significant negative revisions of previous estimates to its
reserves. Because SEC rules require proved reserves to be economically
producible, the price used is inherent in that determination. If the rules
regarding the prices used to calculate reserves had not been changed, the
Company believes it would not have had significant negative revisions to its
reserves due to pricing, as spot market prices on December 31, 2009, were higher
than December 31, 2008, spot market prices.
The
reserve estimates are prepared by internal engineers assigned to an asset team
by geographic area and are reviewed and approved by management. In addition, the
Company engages an independent third party to audit its proved reserves. Ryder
Scott Company, L.P. reviewed the Company’s proved reserve quantity estimates as
of December 31, 2009.
Estimates
of economically recoverable natural gas and oil reserves and future net revenues
therefrom are based upon a number of variable factors and assumptions. For these
reasons, estimates of economically recoverable reserves and future net revenues
may vary from actual results.
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
|
(MMcf/MBbls)
|
|
Proved
developed and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
undeveloped
reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at beginning of year
|
|
|
604,282 |
|
|
|
34,348 |
|
|
|
523,737 |
|
|
|
30,612 |
|
|
|
538,100 |
|
|
|
27,100 |
|
Production
|
|
|
(56,632 |
) |
|
|
(3,111 |
) |
|
|
(65,457 |
) |
|
|
(2,808 |
) |
|
|
(62,798 |
) |
|
|
(2,365 |
) |
Extensions
and discoveries
|
|
|
26,882 |
|
|
|
2,569 |
|
|
|
78,338 |
|
|
|
4,941 |
|
|
|
77,701 |
|
|
|
3,772 |
|
Improved
recovery
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
444 |
|
|
|
1,614 |
|
Purchases
of proved reserves
|
|
|
— |
|
|
|
— |
|
|
|
92,564 |
|
|
|
834 |
|
|
|
2 |
|
|
|
6 |
|
Sales
of reserves in place
|
|
|
(22 |
) |
|
|
(248 |
) |
|
|
— |
|
|
|
— |
|
|
|
(6 |
) |
|
|
(42 |
) |
Revisions
of previous
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
estimates
|
|
|
(126,085 |
) |
|
|
658 |
|
|
|
(24,900 |
) |
|
|
769 |
|
|
|
(29,706 |
) |
|
|
527 |
|
Balance
at end of year
|
|
|
448,425 |
|
|
|
34,216 |
|
|
|
604,282 |
|
|
|
34,348 |
|
|
|
523,737 |
|
|
|
30,612 |
|
Proved
reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
321,561 |
|
|
|
26,794 |
|
|
|
431,180 |
|
|
|
26,862 |
|
|
|
420,137 |
|
|
|
25,658 |
|
Undeveloped
|
|
|
126,864 |
|
|
|
7,422 |
|
|
|
173,102 |
|
|
|
7,486 |
|
|
|
103,600 |
|
|
|
4,954 |
|
Balance
at end of year
|
|
|
448,425 |
|
|
|
34,216 |
|
|
|
604,282 |
|
|
|
34,348 |
|
|
|
523,737 |
|
|
|
30,612 |
|
The level
of proved undeveloped reserves converted to developed in 2009 was less than
anticipated as the Company’s drilling plans were modified due to the lower price
environment experienced in 2009 and the Company’s focus to preserve capital. The
Company did not have any material proved undeveloped locations that remained
undeveloped for five years or more as of December 31, 2009.
The
Company's interests in natural gas and oil reserves are located in the United
States and in and around the Gulf of Mexico.
The
standardized measure of the Company's estimated discounted future net cash flows
of total proved reserves associated with its various natural gas and oil
interests at December 31 was as follows:
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Future
cash inflows
|
|
$ |
2,991,200 |
|
|
$ |
3,970,000 |
|
|
$ |
5,302,300 |
|
Future
production costs
|
|
|
1,095,600 |
|
|
|
1,325,600 |
|
|
|
1,415,700 |
|
Future
development costs
|
|
|
315,000 |
|
|
|
377,300 |
|
|
|
237,600 |
|
Future
net cash flows before income taxes
|
|
|
1,580,600 |
|
|
|
2,267,100 |
|
|
|
3,649,000 |
|
Future
income tax expense
|
|
|
291,000 |
|
|
|
501,200 |
|
|
|
1,179,900 |
|
Future
net cash flows
|
|
|
1,289,600 |
|
|
|
1,765,900 |
|
|
|
2,469,100 |
|
10%
annual discount for estimated timing of
|
|
|
|
|
|
|
|
|
|
|
|
|
cash
flows
|
|
|
630,800 |
|
|
|
796,100 |
|
|
|
1,107,200 |
|
Discounted
future net cash flows relating to
|
|
|
|
|
|
|
|
|
|
|
|
|
proved
natural gas and oil reserves
|
|
$ |
658,800 |
|
|
$ |
969,800 |
|
|
$ |
1,361,900 |
|
The
following are the sources of change in the standardized measure of discounted
future net cash flows by year:
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Beginning
of year
|
|
$ |
969,800 |
|
|
$ |
1,361,900 |
|
|
$ |
1,003,500 |
|
Net
revenues from production
|
|
|
(200,900 |
) |
|
|
(547,000 |
) |
|
|
(354,100 |
) |
Change
in net realization
|
|
|
(364,800 |
) |
|
|
(687,100 |
) |
|
|
527,900 |
|
Extensions
and discoveries, net of future
|
|
|
|
|
|
|
|
|
|
|
|
|
production-related
costs
|
|
|
70,500 |
|
|
|
209,600 |
|
|
|
310,300 |
|
Improved
recovery, net of future production-related costs
|
|
|
— |
|
|
|
— |
|
|
|
38,100 |
|
Purchases
of proved reserves, net of future production-related costs
|
|
|
— |
|
|
|
138,100 |
|
|
|
200 |
|
Sales
of reserves in place
|
|
|
(1,100 |
) |
|
|
— |
|
|
|
(1,300 |
) |
Changes
in estimated future development costs
|
|
|
43,600 |
|
|
|
11,000 |
|
|
|
(22,600 |
) |
Development
costs incurred during the current year
|
|
|
46,400 |
|
|
|
66,300 |
|
|
|
103,000 |
|
Accretion
of discount
|
|
|
115,900 |
|
|
|
183,800 |
|
|
|
133,700 |
|
Net
change in income taxes
|
|
|
142,800 |
|
|
|
372,300 |
|
|
|
(212,500 |
) |
Revisions
of previous estimates
|
|
|
(155,500 |
) |
|
|
(132,200 |
) |
|
|
(163,700 |
) |
Other
|
|
|
(7,900 |
) |
|
|
(6,900 |
) |
|
|
(600 |
) |
Net
change
|
|
|
(311,000 |
) |
|
|
(392,100 |
) |
|
|
358,400 |
|
End
of year
|
|
$ |
658,800 |
|
|
$ |
969,800 |
|
|
$ |
1,361,900 |
|
The
estimated discounted future cash inflows from estimated future production of
proved reserves were computed using prices as previously discussed. Future
development and production costs attributable to proved reserves were computed
by applying year-end costs to be incurred in producing and further developing
the proved reserves. Future development costs estimated to be spent in each of
the next three years to develop proved undeveloped reserves as of
December 31, 2009, are $88.9 million in 2010, $69.1 million in
2011 and $41.8 million in 2012. Future income tax expenses were computed by
applying statutory tax rates, adjusted for permanent differences and tax
credits, to estimated net future pretax cash flows.
The
standardized measure of discounted future net cash flows does not purport to
represent the fair market value of natural gas and oil properties. There are
significant uncertainties inherent in estimating quantities of proved reserves
and in projecting rates of production and the timing and amount of future costs.
In addition, future realization of natural gas and oil prices over the remaining
reserve lives may vary significantly from SEC Defined Prices.
Item 9.
|
Changes
in and Disagreements With Accountants on Accounting and Financial
Disclosure
|
None.
Item 9A.
Controls and Procedures
The
following information includes the evaluation of disclosure controls and
procedures by the Company’s chief executive officer and the chief financial
officer, along with any significant changes in internal controls of the
Company.
Evaluation
of Disclosure Controls and Procedures
The term
"disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e)
of the Exchange Act. The Company’s controls and other procedures are designed to
provide reasonable assurance that information required to be disclosed in the
reports that the Company files or submits under the Exchange Act is recorded,
processed, summarized and reported within the time periods specified in the
SEC’s rules and forms. The Company’s disclosure controls and procedures include
controls and procedures designed to provide reasonable assurance that
information required to be disclosed is accumulated and communicated to
management, including the Company’s chief executive officer and chief financial
officer, to allow timely decisions regarding required disclosure. The Company’s
chief executive officer and chief financial officer have evaluated the
effectiveness of the Company’s disclosure controls and procedures and they have
concluded that, as of the end of the period covered by this report, such
controls and procedures were effective at a reasonable assurance
level.
Changes
in Internal Controls
The
Company maintains a system of internal accounting controls that is designed to
provide reasonable assurance that the Company’s transactions are properly
authorized, the Company’s assets are safeguarded against unauthorized or
improper use, and the Company’s transactions are properly recorded and reported
to permit preparation of the Company’s financial statements in conformity with
generally accepted accounting principles in the United States of America. There
were no changes in the Company’s internal control over financial reporting that
occurred during the quarter ended December 31, 2009, that have materially
affected, or are reasonably likely to materially affect, the Company’s internal
control over financial reporting.
Management's
Annual Report on Internal Control Over Financial Reporting
The
information required by this item is included in this Form 10-K at
Item 8 – Management's Report on Internal Control Over Financial
Reporting.
Attestation
Report of the Registered Public Accounting Firm
The
information required by this item is included in this Form 10-K at
Item 8 – Report of Independent Registered Public Accounting
Firm.
Item 9B.
Other Information
None.
Part III
Item 10. Directors,
Executive Officers and Corporate
Governance
|
The
information required by this item is included in the last sentence of the third
paragraph under the caption "Item 1. Election of Directors" and under the
captions "Item 1. Election of Directors – Director Nominees," "Information
Concerning Executive Officers," the first paragraph and the second, third and
fourth sentences of the second paragraph under "Corporate Governance – Audit
Committee," "Corporate Governance – Code of Conduct," the second sentence of the
last paragraph under "Corporate Governance – Board Meetings and Committees" and
"Section 16(a) Beneficial Ownership Reporting Compliance" in the Proxy
Statement, which information is incorporated herein by reference.
Item 11.
Executive Compensation
The
information required by this item is included under the caption "Executive
Compensation" in the Proxy Statement, which information is incorporated herein
by reference.
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
|
Equity
Compensation Plan Information
The
following table includes information as of December 31, 2009, with respect
to the Company's equity compensation plans:
Plan
Category
|
|
(a)
Number
of securities to be issued upon exercise of outstanding options, warrants
and rights
|
|
|
(b)
Weighted
average exercise price of outstanding options, warrants and
rights
|
|
|
(c)
Number
of securities remaining available for future issuance under equity
compensation plans (excluding securities reflected in
column (a))
|
|
Equity
compensation plans approved by stockholders (1)
|
|
|
1,087,973 |
(2) |
|
$ |
19.80 |
|
|
|
7,262,380 |
(3)(4) |
Equity
compensation plans not approved by
stockholders (5)
|
|
|
371,403 |
|
|
|
13.22 |
|
|
|
2,361,073 |
(6) |
Total
|
|
|
1,459,376 |
|
|
$ |
18.13 |
|
|
|
9,623,453 |
|
(1)
|
Consists
of the 1992 Key Employee Stock Option Plan, the Non-Employee Director
Long-Term Incentive Compensation Plan, the Long-Term Performance-Based
Incentive Plan and the Non-Employee Director Stock Compensation
Plan.
|
(2)
|
Includes
634,505 performance shares.
|
(3)
|
In
addition to being available for future issuance upon exercise of options,
357,757 shares under the Non-Employee Director Long-Term Incentive
Compensation Plan may instead be issued in connection with stock
appreciation rights, restricted stock, performance units, performance
shares or other equity-based awards, and 5,861,739 shares under the
Long-Term Performance-Based Incentive Plan may instead be issued in
connection with stock appreciation rights, restricted stock, performance
units, performance shares or other equity-based awards.
|
(4)
|
This
amount also includes 364,628 shares available for issuance under the
Non-Employee Director Stock Compensation Plan. Under this plan, in
addition to a cash retainer, nonemployee Directors are awarded
4,050 shares following the Company's annual meeting of stockholders.
Prior to January 1, 2009, the Company's Chairman of the Board of
Directors received an additional $50,000 in stock under the plan each
December as part of his retainer. A non-employee Director may acquire
additional shares under the plan in lieu of receiving the cash portion of
the Director's retainer or fees.
|
(5)
|
Consists
of the 1998 Option Award Program and the Group Genius Innovation
Plan.
|
(6)
|
In
addition to being available for future issuance upon exercise of options,
219,050 shares under the Group Genius Innovation Plan may instead be
issued in connection with stock appreciation rights, restricted stock,
restricted stock units, performance units, performance stock or other
equity-based awards.
|
The
following equity compensation plans have not been approved by the Company's
stockholders.
The
1998 Option Award Program
The 1998
Option Award Program is a broad-based plan adopted by the Board of Directors,
effective February 12, 1998. The plan permits the grant of nonqualified
stock options to employees of the Company and its subsidiaries. The maximum
number of shares that may be issued under the plan is 3,795,330. Shares granted
may be authorized but unissued shares, treasury
shares,
or shares purchased on the open market. Option exercise prices are equal to the
market value of the Company's shares on the date of the option grant. Optionees
receive dividend equivalents on their options, with any credited dividends paid
in cash to the optionee if the option vests, or forfeited if the option is
forfeited. Vested options remain exercisable for one year following termination
of employment due to death or disability and for three months following
termination of employment for any other reason.
Unvested
options are forfeited upon termination of employment. Subject to the terms and
conditions of the plan, the plan's administrative committee determines the
number of shares subject to options granted to each participant and the other
terms and conditions pertaining to such options, including vesting provisions.
All options become immediately exercisable in the event of a change in control
of the Company.
In 2001,
450 options (adjusted for the three-for-two stock splits in October 2003 and
July 2006) were granted to each of approximately 5,900 employees. No officers
received grants. These options vested on February 13, 2004. As of
December 31, 2009, options covering 371,403 shares of common stock were
outstanding under the plan and 2,142,023 shares remained available for future
grant. Options covering 1,281,904 shares had been exercised.
The
Group Genius Innovation Plan
The Group
Genius Innovation Plan was adopted by the Board of Directors, effective
May 17, 2001, to encourage employees to share ideas for new business
directions for the Company and to reward them when the idea becomes profitable.
Employees of the Company and its subsidiaries who are selected by the plan's
administrative committee are eligible to participate in the plan. Officers and
Directors are not eligible to participate. The plan permits the granting of
nonqualified stock options, stock appreciation rights, restricted stock,
restricted stock units, performance units, performance stock and other awards.
The maximum number of shares that may be issued under the plan is 223,150.
Shares granted under the plan may be authorized but unissued shares, treasury
shares or shares purchased on the open market. Restricted stockholders have
voting rights and, unless determined otherwise by the plan's administrative
committee, receive dividends paid on the restricted stock. Dividend equivalents
payable in cash may be granted with respect to options and performance shares.
The plan's administrative committee determines the number of shares or units
subject to awards, and the other terms and conditions of the awards, including
vesting provisions and the effect of employment termination. Upon a change in
control of the Company, all options and stock appreciation rights become
immediately vested and exercisable, all restricted stock becomes immediately
vested, all restricted stock units become immediately vested and are paid out in
cash, and target payout opportunities under all performance units, performance
stock, and other awards are deemed to be fully earned, with awards denominated
in stock paid out in shares and awards denominated in units paid out in cash. As
of December 31, 2009, 4,100 shares of stock had been granted to 73
employees.
The
remaining information required by this item is included under the caption
"Security Ownership" in the Proxy Statement, which information is incorporated
herein by reference.
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
The
information required by this item is included under the captions "Related Person
Transaction Disclosure," "Corporate Governance – Director Independence" and the
second sentence of the third paragraph under "Corporate Governance – Board
Meetings and Committees" in the Proxy Statement, which information is
incorporated herein by reference.
Item 14.
Principal Accountant Fees and Services
The
information required by this item is included under the caption "Accounting and
Auditing Matters" in the Proxy Statement, which information is incorporated
herein by reference.
Part IV
Item 15.
Exhibits and Financial Statement Schedules
(a) Financial
Statements, Financial Statement Schedules and
Exhibits
|
Index
to Financial Statements and Financial Statement Schedules
1.
Financial Statements
The
following consolidated financial statements required under this item are
included under Item 8 – Financial Statements and Supplementary
Data.
|
Page
|
|
|
Consolidated
Statements of Income for each of the three years in the period ended
December 31, 2009
|
74
|
|
|
Consolidated
Balance Sheets at December 31, 2009 and 2008
|
75
|
|
|
Consolidated
Statements of Common Stockholders' Equity for each of the three years in
the period ended December 31, 2009
|
76
|
|
|
Consolidated
Statements of Cash Flows for each of the three years in the period ended
December 31, 2009
|
77
|
|
|
Notes
to Consolidated Financial Statements
|
78
|
2.
Financial Statement Schedules
MDU
Resources Group, Inc.
|
Schedule II
- Consolidated Valuation and Qualifying Accounts
|
Years
Ended December 31, 2009, 2008 and 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions
|
|
|
|
|
|
Balance
at
|
|
Charged
to
|
|
|
|
|
|
Balance
|
|
|
Beginning
|
|
Costs
and
|
|
|
|
|
|
at
End
|
Description
|
|
of
Year
|
|
Expenses
|
|
Other*
|
|
Deductions**
|
|
of
Year
|
|
|
(In
thousands)
|
Allowance
for doubtful accounts:
|
|
|
|
|
|
|
|
|
2009
|
|
$13,691
|
|
$12,152
|
|
$1,412
|
|
$10,606
|
|
$16,649
|
2008
|
|
14,635
|
|
12,191
|
|
2,115
|
|
15,250
|
|
13,691
|
2007
|
|
7,725
|
|
8,799
|
|
5,533
|
|
7,422
|
|
14,635
|
*Allowance for doubtful accounts
for companies acquired and recoveries.
|
** Uncollectible
accounts written off.
|
All other
schedules are omitted because of the absence of the conditions under which they
are required, or because the information required is included in the Company's
Consolidated Financial Statements and Notes thereto.
3.
Exhibits
3(a)
|
Restated
Certificate of Incorporation of the Company, as amended, dated
May 17, 2007, filed as Exhibit 3.1 to Form 8-A/A, filed on
June 27, 2007, in File No. 1-3480*
|
|
|
3(b)
|
Company
Bylaws, as amended and restated, on November 12,
2009**
|
|
|
4(a)
|
Indenture
of Mortgage, dated as of May 1, 1939, as restated in the Forty-Fifth
Supplemental Indenture, dated as of April 21, 1992, and the
Forty-Sixth through Fiftieth Supplements thereto between the Company and
the New York Trust Company (The Bank of New York, successor Corporate
Trustee) and A. C. Downing (Douglas J. MacInnes, successor
Co-Trustee), filed as Exhibit 4(a) to Form S-3, in Registration
No. 33-66682; and Exhibits 4(e), 4(f) and 4(g) to Form S-8, in
Registration No. 33-53896; and Exhibit 4(c)(i) to Form S-3,
in Registration No. 333-49472; and Exhibit 4(e) to
Form S-8, in Registration No. 333-112035*
|
|
|
4(b)
|
Indenture,
dated as of December 15, 2003, between the Company and The Bank of
New York, as trustee, filed as Exhibit 4(f) to Form S-8 on
January 21, 2004, in Registration
No. 333-112035*
|
|
|
4(c)
|
First
Supplemental Indenture, dated as of November 17, 2009, between the Company
and The Bank of New York Mellon, as trustee**
|
|
|
4(d)
|
Centennial
Energy Holdings, Inc. Master Shelf Agreement, dated April 29, 2005,
among Centennial Energy Holdings, Inc. and the Prudential Insurance
Company of America, filed as Exhibit 4(a) to Form 10-Q for the
quarter ended June 30, 2005, filed on August 3, 2005, in File
No. 1-3480*
|
|
|
4(e)
|
Letter
Amendment No. 1 to Amended and Restated Master Shelf Agreement, dated
May 17, 2006, among Centennial Energy Holdings, Inc., The Prudential
Insurance Company of America, and certain investors described in the
Letter Amendment filed as Exhibit 4(a) to Form 10-Q for the
quarter ended June 30, 2006, filed on August 4, 2006, in File
No. 1-3480*
|
|
|
4(f)
|
MDU
Resources Group, Inc. Credit Agreement, dated June 21, 2005, among
MDU Resources Group, Inc., Wells Fargo Bank, National Association, as
Administrative Agent, and The Other Financial Institutions Party thereto,
filed as Exhibit 4(b) to Form 10-Q for the quarter ended
June 30, 2005, filed on August 3, 2005, in File
No. 1-3480*
|
|
|
4(g)
|
First
Amendment, dated June 30, 2006, to Credit Agreement, dated
June 21, 2005, among MDU Resources Group, Inc., Wells Fargo Bank,
National Association, as administrative agent, and certain lenders
described in the credit agreement, filed as Exhibit 4(b) to
Form 10-Q for the quarter ended June 30, 2006, filed on
August 4, 2006, in File
No. 1-3480*
|
4(h)
|
Centennial
Energy Holdings, Inc. Credit Agreement, dated December 13, 2007,
among Centennial Energy Holdings, Inc., U.S. Bank National Association, as
Administrative Agent, and The Other Financial Institutions party thereto,
filed as Exhibit 4(j) to Form 10-K for the year ended
December 31, 2007, filed on February 20, 2008, in File
No. 1-3480*
|
|
|
4(i)
|
Consent
dated November 9, 2009, under Centennial Energy Holdings, Inc. Credit
Agreement, among Centennial Energy Holdings, Inc., U.S. Bank National
Association, as Administrative Agent, and The Other Financial Institutions
party thereto**
|
|
|
4(j)
|
MDU
Energy Capital, LLC Master Shelf Agreement, dated as of August 9,
2007, among MDU Energy Capital, LLC and the Prudential Insurance Company
of America, filed as Exhibit 4 to Form 8-K dated August 16,
2007, filed on August 16, 2007, in File
No. 1-3480*
|
|
|
4(k)
|
Indenture
dated as of August 1, 1992, between Cascade Natural Gas Corporation
and The Bank of New York relating to Medium-Term Notes, filed by Cascade
Natural Gas Corporation as Exhibit 4 to Form 8-K dated
August 12, 1992, in File No. 1-7196*
|
|
|
4(l)
|
First
Supplemental Indenture dated as of October 25, 1993, between Cascade
Natural Gas Corporation and The Bank of New York relating to Medium-Term
Notes and the 7.5% Notes due November 15, 2031, filed by Cascade
Natural Gas Corporation as Exhibit 4 to Form 10-Q for the
quarter ended June 30, 1993, in File
No. 1-7196*
|
|
|
4(m)
|
Second
Supplemental Indenture, dated January 25, 2005, between Cascade
Natural Gas Corporation and The Bank of New York, as trustee, filed by
Cascade Natural Gas Corporation as Exhibit 4.1 to Form 8-K dated
January 25, 2005, filed on January 26, 2005, in File
No. 1-7196*
|
|
|
4(n)
|
Third
Supplemental Indenture dated as of March 8, 2007, between Cascade
Natural Gas Corporation and The Bank of New York Trust Company, N.A., as
Successor Trustee, filed by Cascade Natural Gas Corporation as
Exhibit 4.1 to Form 8-K dated March 8, 2007, filed on
March 8, 2007, in File No. 1-7196*
|
|
|
4(o)
|
Amendment
No. 1 to Master Shelf Agreement, dated October 1, 2008, among
MDU Energy Capital, LLC, Prudential Investment Management, Inc., The
Prudential Insurance Company of America, and the holders of the notes
thereunder, filed as Exhibit 4(b) to Form 10-Q for the quarter
ended September 30, 2008, filed on November 5, 2008, in File
No. 1-3480*
|
|
|
+10(a)
|
1992
Key Employee Stock Option Plan, as revised, filed as Exhibit 10(a) to
Form 10-K for the year ended December 31, 2006, filed on
February 21, 2007, in File No. 1-3480*
|
|
|
+10(b)
|
Supplemental
Income Security Plan, as amended and restated November 12,
2009**
|
|
|
+10(c)
|
Directors'
Compensation Policy, as amended May 14, 2009, filed as
Exhibit 10(a) to Form 10-Q for the quarter ended June 30,
2009, filed on August 7, 2009, in File
No. 1-3480*
|
+10(d)
|
Deferred
Compensation Plan for Directors, as amended May 15, 2008, filed as
Exhibit 10(a) to Form 10-Q for the quarter ended June 30,
2008, filed on August 7, 2008, in File
No. 1-3480*
|
|
|
+10(e)
|
Non-Employee
Director Stock Compensation Plan, as amended May 15, 2008, filed as
Exhibit 10(d) to Form 10-Q for the quarter ended June 30,
2008, filed on August 7, 2008, in File
No. 1-3480*
|
|
|
+10(f)
|
Non-Employee
Director Long-Term Incentive Compensation Plan, as amended
November 12, 2009**
|
|
|
+10(g)
|
1998
Option Award Program, as amended November 12,
2009**
|
|
|
+10(h)
|
Group
Genius Innovation Plan, as amended November 12,
2009**
|
|
|
+10(i)
|
WBI
Holdings, Inc. Executive Incentive Compensation Plan, as amended
January 31, 2008, and Rules and Regulations, as amended
November 11, 2009**
|
|
|
+10(j)
|
Knife
River Corporation Executive Incentive Compensation Plan, as amended
January 31, 2008, and Rules and Regulations, as amended
November 16, 2009**
|
|
|
+10(k)
|
Long-Term
Performance-Based Incentive Plan, as amended November 12,
2009**
|
|
|
+10(l)
|
MDU
Resources Group, Inc. Executive Incentive Compensation Plan, as amended
November 15, 2007, and Rules and Regulations, as amended
November 11, 2009**
|
|
|
+10(m)
|
Montana-Dakota
Utilities Co. Executive Incentive Compensation Plan, as amended
November 15, 2007, and Rules and Regulations, as amended
November 11, 2009**
|
|
|
+10(n)
|
Form
of Change of Control Employment Agreement, as amended May 15, 2008,
filed as Exhibit 10.1 to Form 8-K dated May 15, 2008, filed
on May 20, 2008, in File No. 1-3480*
|
|
|
+10(o)
|
MDU
Resources Group, Inc. Executive Officers with Change of Control Employment
Agreements Chart, as of December 31, 2008, filed as Exhibit 10(p) to
Form 10-K for the year ended December 31, 2008, filed on
February 13, 2009, in File No. 1-3480*
|
|
|
+10(p)
|
Supplemental
Executive Retirement Plan for John G. Harp, dated December 4, 2006,
filed as Exhibit 10(ag) to Form 10-K for the year ended
December 31, 2006, filed on February 21, 2007, in File
No. 1-3480*
|
|
|
+10(q)
|
Employment
Letter for John G. Harp, dated July 20, 2005, filed as
Exhibit 10(ah) to Form 10-K for the year ended December 31,
2006, filed on February 21, 2007, in File
No. 1-3480*
|
|
|
+10(r)
|
Form
of Performance Share Award Agreement under the Long-Term Performance-Based
Incentive Plan, as amended August 13, 2008, filed as
Exhibit 10.1 to Form 8-K dated August 13, 2008, filed on
August 19, 2008, in File
No. 1-3480*
|
+10(s)
|
MDU
Construction Services Group, Inc. Executive Incentive Compensation Plan,
as amended January 31, 2008, and Rules and Regulations, as amended
February 16, 2009, filed as Exhibit 10(c) to Form 10-Q for
the quarter ended March 31, 2009, filed on May 6, 2009, in File
No. 1-3480*
|
|
|
+10(t)
|
John
G. Harp 2009 additional incentive opportunity, filed as Exhibit 10(f)
to Form 10-Q for the quarter ended March 31, 2009, filed on
May 6, 2009, in File No. 1-3480*
|
|
|
+10(u)
|
Form
of 2009 Annual Incentive Award Agreement under the Long-Term
Performance-Based Incentive Plan, filed as Exhibit 10(g) to
Form 10-Q for the quarter ended March 31, 2009, filed on
May 6, 2009, in File No. 1-3480*
|
|
|
+10(v)
|
MDU
Resources Group, Inc. 401(k) Retirement Plan, as restated June 1, 2009,
filed as Exhibit 10(b) to Form 10-Q for the quarter ended
June 30, 2009, filed on August 7, 2009, in File
No. 1-3480*
|
|
|
+10(w)
|
Instrument
of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan,
dated December 2, 2009**
|
|
|
+10(x)
|
Instrument of Amendment to the MDU
Resources Group, Inc. 401(k) Retirement Plan, dated December 30,
2009** |
|
|
12
|
Computation
of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and
Preferred Stock Dividends**
|
|
|
21
|
Subsidiaries
of MDU Resources Group, Inc.**
|
|
|
23(a)
|
Consent
of Independent Registered Public Accounting Firm**
|
|
|
23(b)
|
Consent
of Ryder Scott Company, L.P.**
|
|
|
31(a)
|
Certification
of Chief Executive Officer filed pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002**
|
|
|
31(b)
|
Certification
of Chief Financial Officer filed pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002**
|
|
|
32
|
Certification
of Chief Executive Officer and Chief Financial Officer furnished pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002**
|
|
|
99(a)
|
Sales
Agency Financing Agreement entered into between MDU Resources Group, Inc.
and Wells Fargo Securities, LLC, filed as Exhibit 1 to Form 8-K
dated September 5, 2008, filed on September 5, 2008, in File
No. 1-3480*
|
|
|
99(b)
|
Ryder
Scott Company, L.P. report dated January 22, 2010
**
|
101
|
The
following materials from MDU Resources Group, Inc.’s Annual Report on Form
10-K for the year ended December 31, 2009, formatted in XBRL (eXtensible
Business Reporting Language): (i) the Consolidated Statements of Income,
(ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of
Common Stockholders’ Equity, (iv) the Consolidated Statements of Cash
Flows, (v) the Notes to Consolidated Financial Statements, tagged as
blocks of text and (vi) Schedule II – Consolidated Valuation and
Qualifying Accounts, tagged as a block of
text
|
————————————————————————
*Incorporated herein by reference as
indicated.
** Filed herewith.
+ Management contract, compensatory plan or
arrangement.
MDU
Resources Group, Inc. agrees to furnish to the SEC upon request any instrument
with respect to long-term debt that MDU Resources Group, Inc. has not filed as
an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of
Regulation S-K.
Signatures
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
|
|
|
MDU
Resources Group, Inc.
|
|
|
|
|
Date:
|
February
17, 2010
|
By:
|
/s/
Terry D. Hildestad
|
|
|
|
Terry
D. Hildestad
(President
and Chief Executive Officer)
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant in the
capacities and on the date indicated.
Signature
|
Title
|
Date
|
|
|
|
/s/
Terry D. Hildestad
|
Chief
Executive Officer and Director
|
February
17, 2010
|
Terry
D. Hildestad
(President
and Chief Executive Officer)
|
|
|
|
|
|
/s/
Doran N. Schwartz
|
Chief
Financial Officer
|
February
17, 2010
|
Doran
N. Schwartz
(Vice
President and Chief Financial Officer)
|
|
|
|
|
|
/s/
Nicole A. Kivisto
|
Chief
Accounting Officer
|
February
17, 2010
|
Nicole
A. Kivisto
(Vice
President, Controller and Chief Accounting Officer)
|
|
|
|
|
|
/s/
Harry J. Pearce
|
Director
|
February
17, 2010
|
Harry
J. Pearce
|
|
|
(Chairman
of the Board)
|
|
|
|
|
|
/s/
Thomas Everist
|
Director
|
February
17, 2010
|
Thomas
Everist
|
|
|
|
|
|
/s/
Karen B. Fagg
|
Director
|
February
17, 2010
|
Karen
B. Fagg
|
|
|
|
|
|
/s/
A. Bart Holaday
|
Director
|
February
17, 2010
|
A.
Bart Holaday
|
|
|
|
|
|
/s/
Dennis W. Johnson
|
Director
|
February
17, 2010
|
Dennis
W. Johnson
|
|
|
|
|
|
/s/
Thomas C. Knudson
|
Director
|
February
17, 2010
|
Thomas
C. Knudson
|
|
|
|
|
|
/s/
Richard H. Lewis
|
Director
|
February
17, 2010
|
Richard
H. Lewis
|
|
|
|
|
|
/s/
Patricia L. Moss
|
Director
|
February
17, 2010
|
Patricia
L. Moss
|
|
|
|
|
|
/s/
Sister Thomas Welder
|
Director
|
February
17, 2010
|
Sister
Thomas Welder
|
|
|
|
|
|
/s/
John K. Wilson
|
Director
|
February
17, 2010
|
John
K. Wilson
|
|
|