UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2005
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from _____________ to ______________
Commission file number 1-3480
MDU Resources Group, Inc.
(Exact name of registrant as specified in its charter)
Delaware 41-0423660
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Schuchart Building
918 East Divide Avenue
P.O. Box 5650
Bismarck, North Dakota 58506-5650
(Address of principal executive offices)
(Zip Code)
(701) 222-7900
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that
the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes X. No.
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes X. No.
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of July 27, 2005: 119,740,593 shares.
INTRODUCTION
This Form 10-Q contains forward-looking statements within the meaning of
Section 21E of the Securities Exchange Act of 1934. Forward-looking
statements are all statements other than statements of historical fact,
including without limitation, those statements that are identified by the
words "anticipates," "estimates," "expects," "intends," "plans,"
"predicts" and similar expressions. In addition to the risk factors and
cautionary statements included in this Form 10-Q at Item 2 -- Management's
Discussion and Analysis of Financial Condition and Results of Operations
(MD&A) - Risk Factors and Cautionary Statements that May Affect Future
Results, the following are some other factors that should be considered
for a better understanding of the financial condition of MDU Resources
Group, Inc. (Company). These other factors may impact the Company's
financial results in future periods.
- Acquisition, disposal and impairment of assets or facilities
- Changes in operation, performance and construction of plant
facilities or other assets
- Changes in present or prospective generation
- The availability of economic expansion or development opportunities
- Population growth rates and demographic patterns
- Market demand for, and/or available supplies of, energy products and
services
- Cyclical nature of large construction projects at certain operations
- Changes in tax rates or policies
- Unanticipated project delays or changes in project costs
- Unanticipated changes in operating expenses or capital expenditures
- Labor negotiations or disputes
- Inability of the various contract counterparties to meet their
contractual obligations
- Changes in accounting principles and/or the application of such
principles to the Company
- Changes in technology
- Changes in legal or regulatory proceedings
- The ability to effectively integrate the operations of acquired
companies
- Fluctuations in natural gas and crude oil prices
- Decline in general economic environment
- Changes in governmental regulation
- Unanticipated increases in competition
- Variations in weather
The Company is a diversified natural resource company, which was
incorporated under the laws of the state of Delaware in 1924. Its
principal executive offices are at the Schuchart Building, 918 East Divide
Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone
(701) 222-7900.
Montana-Dakota Utilities Co. (Montana-Dakota), a public utility division
of the Company, through the electric and natural gas distribution
segments, generates, transmits and distributes electricity and distributes
natural gas in the northern Great Plains. Great Plains Natural Gas Co.
(Great Plains), another public utility division of the Company,
distributes natural gas in western Minnesota and southeastern North
Dakota. These operations also supply related value-added products and
services in the northern Great Plains.
The Company, through its wholly owned subsidiary, Centennial Energy
Holdings, Inc. (Centennial), owns WBI Holdings, Inc. (WBI Holdings), Knife
River Corporation (Knife River), Utility Services, Inc. (Utility
Services), Centennial Energy Resources LLC (Centennial Resources) and
Centennial Holdings Capital LLC (Centennial Capital).
WBI Holdings is comprised of the pipeline and energy services and
the natural gas and oil production segments. 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. The pipeline
and energy services segment also provides energy-related
management services, including cable and pipeline magnetization
and locating. The natural gas and oil production segment is
engaged in natural gas and oil acquisition, exploration,
development and production activities, primarily in the Rocky
Mountain region of the United States and in and around the Gulf of
Mexico.
Knife River mines aggregates and markets crushed stone, sand,
gravel and related construction materials, including ready-mixed
concrete, cement, asphalt and other value-added products, as well
as performs integrated construction services, in the central and
western United States and in the states of Alaska and Hawaii.
Utility Services specializes in electrical line construction,
pipeline construction, inside electrical wiring and cabling, and
the manufacture and distribution of specialty equipment.
Centennial Resources owns, builds and operates electric generating
facilities in the United States and has investments in domestic
and international natural resource-based projects. Electric
capacity and energy produced at its power plants are sold
primarily under mid- and long-term contracts to nonaffiliated
entities.
Centennial Capital insures various types of risks as a captive
insurer for certain of the Company's subsidiaries. The function
of the captive 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
and contract rights. These activities are reflected in the Other
category.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three and Six Months Ended June 30, 2005 and 2004
Consolidated Balance Sheets --
June 30, 2005 and 2004, and December 31, 2004
Consolidated Statements of Cash Flows --
Six Months Ended June 30, 2005 and 2004
Notes to Consolidated Financial Statements
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Controls and Procedures
Part II -- Other Information
Legal Proceedings
Unregistered Sales of Equity Securities and Use of Proceeds
Exhibits
Signatures
Exhibit Index
Exhibits
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Six Months
Ended Ended
June 30, June 30,
2005 2004 2005 2004
(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution
and pipeline and energy services $182,109 $159,368 $ 437,481 $ 391,215
Utility services, natural gas and oil
production, construction materials
and mining, independent power
production and other 588,063 493,933 936,986 777,545
770,172 653,301 1,374,467 1,168,760
Operating expenses:
Fuel and purchased power 14,547 16,370 30,733 33,095
Purchased natural gas sold 46,673 39,534 160,172 134,278
Operation and maintenance:
Electric, natural gas distribution
and pipeline and energy services 39,482 38,329 78,467 80,530
Utility services, natural gas and oil
production, construction materials
and mining, independent power
production and other 475,784 397,084 766,788 643,454
Depreciation, depletion and
amortization 51,588 51,787 104,427 101,298
Taxes, other than income 28,574 25,466 55,243 47,351
656,648 568,570 1,195,830 1,040,006
Operating income 113,524 84,731 178,637 128,754
Earnings from equity method
investments 15,404 7,723 16,718 11,148
Other income 1,505 1,847 2,656 3,216
Interest expense 13,342 15,653 26,359 29,499
Income before income taxes 117,091 78,648 171,652 113,619
Income taxes 36,918 20,018 57,059 31,410
Net income 80,173 58,630 114,593 82,209
Dividends on preferred stocks 171 172 342 342
Earnings on common stock $ 80,002 $ 58,458 $ 114,251 $ 81,867
Earnings per common share -- basic $ .68 $ .50 $ .97 $ .71
Earnings per common share -- diluted $ .67 $ .50 $ .96 $ .70
Dividends per common share $ .18 $ .17 $ .36 $ .34
Weighted average common shares
outstanding -- basic 118,348 116,559 118,089 115,609
Weighted average common shares
outstanding -- diluted 119,037 117,567 118,767 116,632
The accompanying notes are an integral part of these consolidated financial
statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, June 30, December 31,
2005 2004 2004
(In thousands, except shares
and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 57,711 $ 132,476 $ 99,377
Receivables, net 546,722 421,653 440,903
Inventories 158,886 121,920 143,880
Deferred income taxes 6,840 5,457 2,874
Prepayments and other current assets 56,859 62,304 41,144
827,018 743,810 728,178
Investments 98,563 78,067 120,555
Property, plant and equipment 4,273,670 3,744,146 3,931,428
Less accumulated depreciation,
depletion and amortization 1,440,732 1,267,014 1,358,723
2,832,938 2,477,132 2,572,705
Deferred charges and other assets:
Goodwill 214,972 200,553 199,743
Other intangible assets, net 30,297 21,105 22,269
Other 91,953 91,941 90,071
337,222 313,599 312,083
$4,095,741 $3,612,608 $3,733,521
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Long-term debt due within one year $ 26,866 $ 93,249 $ 72,046
Accounts payable 212,888 183,097 184,993
Taxes payable 26,300 23,031 28,372
Dividends payable 21,685 20,139 21,449
Other accrued liabilities 164,225 132,866 142,233
451,964 452,382 449,093
Long-term debt 1,119,719 887,721 873,441
Deferred credits and other liabilities:
Deferred income taxes 505,651 467,376 494,589
Other liabilities 244,018 232,464 235,385
749,669 699,840 729,974
Commitments and contingencies
Stockholders' equity:
Preferred stocks 15,000 15,000 15,000
Common stockholders' equity:
Common stock
Shares issued -- $1.00 par value
120,093,303 at June 30, 2005,
117,829,664 at June 30, 2004 and
118,586,065 at December 31, 2004 120,093 117,830 118,586
Other paid-in capital 898,373 843,658 863,449
Retained earnings 770,361 617,222 699,095
Accumulated other comprehensive loss (24,347) (17,419) (11,491)
Treasury stock at cost - 412,906
shares at June 30, 2005, and
359,281 shares at December 31,
2004 and June 30, 2004 (5,091) (3,626) (3,626)
Total common stockholders' equity 1,759,389 1,557,665 1,666,013
Total stockholders' equity 1,774,389 1,572,665 1,681,013
$4,095,741 $3,612,608 $3,733,521
The accompanying notes are an integral part of these consolidated
financial statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
2005 2004
(In thousands)
Operating activities:
Net income $114,593 $ 82,209
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 104,427 101,298
Earnings, net of distributions, from equity
method investments (14,619) (10,455)
Deferred income taxes 5,120 10,141
Changes in current assets and liabilities, net
of acquisitions:
Receivables (34,399) (45,143)
Inventories (12,963) (2,863)
Other current assets (16,463) (11,508)
Accounts payable 20,545 24,026
Other current liabilities (12,193) 23,814
Other noncurrent changes 9,282 809
Net cash provided by operating activities 163,330 172,328
Investing activities:
Capital expenditures (216,912) (141,868)
Acquisitions, net of cash acquired (162,274) (22,006)
Net proceeds from sale or disposition of property 11,355 10,001
Investments 657 (22,684)
Proceeds from notes receivable --- 22,000
Net cash used in investing activities (367,174) (154,557)
Financing activities:
Issuance of long-term debt 324,727 55,115
Repayment of long-term debt (123,734) (42,202)
Proceeds from issuance of common stock 4,116 54,917
Dividends paid (42,931) (39,466)
Net cash provided by financing activities 162,178 28,364
Increase (decrease) in cash and cash equivalents (41,666) 46,135
Cash and cash equivalents -- beginning of year 99,377 86,341
Cash and cash equivalents -- end of period $ 57,711 $132,476
The accompanying notes are an integral part of these consolidated
financial statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
June 30, 2005 and 2004
(Unaudited)
1. Basis of presentation
The accompanying consolidated interim financial statements were
prepared in conformity with the basis of presentation reflected
in the consolidated financial statements included in the Annual
Report to Stockholders on Form 10-K for the year ended
December 31, 2004 (2004 Annual Report), and the standards of
accounting measurement set forth in Accounting Principles Board
(APB) Opinion No. 28 and any amendments thereto adopted by the
Financial Accounting Standards Board (FASB). Interim financial
statements do not include all disclosures provided in annual
financial statements and, accordingly, these financial
statements should be read in conjunction with those appearing
in the Company's 2004 Annual Report. The information is
unaudited but includes all adjustments that are, in the opinion
of management, necessary for a fair presentation of the
accompanying consolidated interim financial statements.
2. Seasonality of operations
Some of the Company's operations are highly seasonal and
revenues from, and certain expenses for, such operations may
fluctuate significantly among quarterly periods. Accordingly,
the interim results for particular businesses, and for the
Company as a whole, may not be indicative of results for the
full fiscal year.
3. Allowance for doubtful accounts
The Company's allowance for doubtful accounts as of June 30,
2005 and 2004, and December 31, 2004, was $7.4 million, $8.0
million and $6.8 million, respectively.
4. Natural gas in underground storage
Natural gas in underground storage for the Company's regulated
operations is carried at cost using the last-in, first-out
method. The portion of the cost of natural gas in underground
storage expected to be used within one year was included in
inventories and was $7.2 million, $5.2 million and $24.9
million at June 30, 2005 and 2004, and December 31, 2004,
respectively. The remainder of natural gas in underground
storage was included in other assets and was $43.3 million,
$42.6 million, and $43.3 million at June 30, 2005 and 2004, and
December 31, 2004, respectively.
5. Inventories
Inventories, other than natural gas in underground storage for
the Company's regulated operations, consisted primarily of
aggregates held for resale of $84.2 million, $68.1 million and
$71.0 million; materials and supplies of $45.8 million, $36.0
million and $31.0 million; and other inventories of $21.7
million, $12.6 million and $17.0 million; as of June 30, 2005
and 2004, and December 31, 2004, respectively. These
inventories were stated at the lower of average cost or market.
6. Earnings per common share
Basic earnings per common share were computed by dividing
earnings on common stock by the weighted average number of
shares of common stock outstanding during the applicable
period. 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
applicable period, plus the effect of outstanding stock
options, restricted stock grants and performance share awards.
For the three and six months ended June 30, 2004, 205,305
shares with an average exercise price of $24.54, attributable
to the exercise of outstanding stock options, were excluded
from the calculation of diluted earnings per share because
their effect was antidilutive. For the three and six months
ended June 30, 2005 and 2004, no adjustments were made to
reported earnings in the computation of earnings per share.
Common stock outstanding includes issued shares less shares
held in treasury.
7. Stock-based compensation
The Company has stock option plans for directors, key employees
and employees. In 2003, the Company adopted the fair value
recognition provisions of Statement of Financial Accounting
Standards (SFAS) No. 123, "Accounting for Stock-Based
Compensation," and began expensing the fair market value of
stock options for all awards granted on or after January 1,
2003. Compensation expense recognized for awards granted on or
after January 1, 2003, for the six months ended June 30, 2005,
was $4,000 (after tax). Compensation expense recognized for
awards granted on or after January 1, 2003, for the three and
six months ended June 30, 2004, was $2,000 and $5,000,
respectively (after tax).
As permitted by SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure - an amendment of SFAS
No. 123," the Company accounts for stock options granted prior
to January 1, 2003, under APB Opinion No. 25, "Accounting for
Stock Issued to Employees." No compensation expense has been
recognized for stock options granted prior to January 1, 2003,
as the options granted had an exercise price equal to the
market value of the underlying common stock on the date of
grant.
The Company adopted SFAS No. 123 effective January 1, 2003, for
newly granted options only. The following table illustrates
the effect on earnings and earnings per common share for the
three and six months ended June 30, 2005 and 2004, as if the
Company had applied SFAS No. 123 and recognized compensation
expense for all outstanding and unvested stock options based on
the fair value at the date of grant:
Three Months Ended
June 30,
2005 2004
(In thousands, except
per share amounts)
Earnings on common stock, as
reported $ 80,002 $ 58,458
Stock-based compensation expense
included in reported earnings,
net of related tax effects --- 2
Total stock-based compensation
expense determined under fair
value method for all awards,
net of related tax effects (88) (79)
Pro forma earnings on common stock $ 79,914 $ 58,381
Earnings per common share -- basic --
as reported $ .68 $ .50
Earnings per common share -- basic --
pro forma $ .68 $ .50
Earnings per common share -- diluted --
as reported $ .67 $ .50
Earnings per common share -- diluted --
pro forma $ .67 $ .50
Six Months Ended
June 30,
2005 2004
(In thousands, except
per share amounts)
Earnings on common stock, as
reported $114,251 $ 81,867
Stock-based compensation expense
included in reported earnings,
net of related tax effects 4 5
Total stock-based compensation
expense determined under fair
value method for all awards,
net of related tax effects (125) (172)
Pro forma earnings on common stock $114,130 $ 81,700
Earnings per common share -- basic --
as reported $ .97 $ .71
Earnings per common share -- basic --
pro forma $ .97 $ .71
Earnings per common share -- diluted --
as reported $ .96 $ .70
Earnings per common share -- diluted --
pro forma $ .96 $ .70
8. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Six Months Ended
June 30,
2005 2004
(In thousands)
Interest, net of amount capitalized $ 23,184 $26,269
Income taxes paid $ 54,650 $21,295
9. Reclassifications
Certain reclassifications have been made in the financial
statements for the prior year to conform to the current
presentation. Such reclassifications had no effect on net
income or stockholders' equity as previously reported.
10. New accounting standards
SAB No. 106
In September 2004, the Securities and Exchange Commission (SEC)
issued Staff Accounting Bulletin No. 106 (SAB No. 106) which is
an interpretation regarding the application of SFAS No. 143,
"Accounting for Asset Retirement Obligations" by oil and gas
producing companies following the full-cost accounting method.
SAB No. 106 clarifies that the future cash outflows associated
with settling asset retirement obligations that have been
accrued on the balance sheet should be excluded from the
computation of the present value of estimated future net
revenues for purposes of the full-cost ceiling calculation.
SAB No. 106 also states that a company is expected to disclose
in the financial statement footnotes and MD&A how the company's
calculation of the ceiling test and depreciation, depletion and
amortization are affected by the adoption of SFAS No. 143. SAB
No. 106 was effective for the Company as of January 1, 2005.
The adoption of SAB No. 106 did not have a material effect on
the Company's financial position or results of operations. The
effects of the adoption of SFAS No. 143 and SAB No. 106 as they
relate to the Company's natural gas and oil production
properties are described below.
Ceiling Test Calculation
As discussed in Note 1 of the 2004 Annual Report, the Company's
natural gas and oil production properties are subject to a
"ceiling test" that limits capitalized costs to the aggregate of
the present value of future net revenues of proved reserves
based on single point-in-time spot market prices, as mandated
under the rules of the SEC, and the cost of unproved
properties. Prior to the adoption of SFAS No. 143, the Company
calculated the full-cost ceiling by reducing its expected
future revenues from proved natural gas and oil reserves by the
estimated future expenditures to be incurred in developing and
producing such reserves, including future retirements,
discounted using a factor mandated by the rules of the SEC.
While expected future cash flows related to the asset
retirement obligations were included in the calculation of the
ceiling test, no associated asset retirement obligation was
recognized on the balance sheet.
Upon the adoption of SFAS No. 143 but prior to the effective
date of SAB No. 106, the Company continued to calculate the
full-cost ceiling as previously described. In addition, the
Company recorded the fair value of a liability for the asset
retirement obligation and capitalized the cost by increasing
the carrying amount of the related long-lived asset.
Upon the adoption of SAB No. 106, the future capitalized
discounted cash outflows associated with settling asset
retirement obligations that are accrued on the consolidated
balance sheet are excluded from the computation of the present
value of estimated future net revenues for purposes of the full-
cost ceiling calculation in accordance with SAB No. 106.
Depreciation, Depletion, and Amortization
Costs subject to amortization include: (A) all capitalized
costs, less accumulated amortization, other than the cost of
acquiring and evaluating unproved property; (B) the estimated
future expenditures (based on current costs) to be incurred in
developing proved reserves; and (C) estimated dismantlement and
abandonment costs, net of estimated salvage values.
Subsequent to the adoption of SFAS No. 143, the estimated
future dismantlement and abandonment costs described in (C)
above are included in the capitalized costs described in (A)
above at the expected future cost discounted to the present
value, to the extent that a legal obligation exists. Under
SFAS No. 143, the recognition of the asset retirement
obligation does not take into account estimated salvage values.
The liability associated with the recognition of an asset
retirement obligation is accreted over time with accretion
expense recorded in depreciation, depletion, and amortization
expense on the income statement. The Company's estimated
dismantlement and abandonment costs as described in (C) above
were adjusted to account for asset retirement obligations
accrued on the consolidated balance sheet when calculating the
depreciation, depletion and amortization rates. In addition,
estimated salvage values were included in the Company's
depreciation, depletion and amortization calculation. The
Company's estimate of future dismantlement and abandonment
costs that will be incurred as a result of future development
activities on proved reserves continues to be included in the
calculation of costs to be amortized.
Any gains or losses on the settlement of an asset retirement
obligation, if applicable, are treated as adjustments to the
capitalized costs, consistent with the full-cost accounting
method.
SFAS No. 123 (revised)
In December 2004, the FASB issued SFAS No. 123 (revised 2004),
"Share-Based Payment" (SFAS No. 123 (revised)). SFAS No. 123
(revised) revises SFAS No. 123 and requires entities to
recognize compensation expense in an amount equal to the fair
value of share-based payments granted to employees. SFAS No.
123 (revised) requires a company to record compensation expense
for all awards granted after the date of adoption of SFAS No.
123 (revised) and for the unvested portion of previously
granted awards that remain outstanding at the date of adoption.
SFAS No. 123 (revised) is effective for the Company on January 1,
2006. The Company is evaluating the effects of the adoption
of SFAS No. 123 (revised).
FIN 47
In March 2005, the FASB issued FASB Interpretation No. 47,
"Accounting for Conditional Asset Retirement Obligations - An
Interpretation of FASB Statement No. 143" (FIN 47). FIN 47
addresses the diverse accounting practices that developed with
respect to the timing of liability recognition for legal
obligations associated with the retirement of a tangible long-
lived asset when the timing and/or method of settlement of the
obligation are conditional on a future event. FIN 47 concludes
that an entity is required to recognize a liability for the
fair value of a conditional asset retirement obligation when
incurred if the liability's fair value can be reasonably
estimated. FIN 47 is effective for the Company at the end of
the fiscal year ending December 31, 2005. The Company is
evaluating the effects of the adoption of FIN 47.
EITF No. 04-6
In March 2005, the FASB ratified Emerging Issues Task Force
Issue No. 04-6, "Accounting for Stripping Costs in the Mining
Industry" (EITF No. 04-6). EITF No. 04-6 requires that post-
production stripping costs be treated as a variable inventory
production cost. As a result, such costs will be subject to
inventory costing procedures in the period they are incurred.
EITF No. 04-6 is effective for the Company on January 1, 2006.
The Company is evaluating the effects of the adoption of EITF
No. 04-6.
11. Comprehensive income
Comprehensive income is the sum of net income as reported and
other comprehensive income (loss). The Company's other
comprehensive income (loss) resulted from gains (losses) on
derivative instruments qualifying as hedges and foreign
currency translation adjustments. For more information on
derivative instruments, see Note 14 of Notes to Consolidated
Financial Statements.
Comprehensive income, and the components of other comprehensive
income (loss) and related tax effects, were as follows:
Three Months Ended
June 30,
2005 2004
(In thousands)
Net income $80,173 $58,630
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
$1,225 and $3,711 in 2005 and 2004,
respectively 1,957 (5,804)
Less: Reclassification adjustment
for loss on derivative
instruments included in net income,
net of tax of $4,522 and $1,473 in
2005 and 2004, respectively (7,223) (2,304)
Net unrealized gain (loss) on
derivative instruments qualifying
as hedges 9,180 (3,500)
Foreign currency translation
adjustment (925) (377)
8,255 (3,877)
Comprehensive income $88,428 $54,753
Six Months Ended
June 30,
2005 2004
(In thousands)
Net income $114,593 $82,209
Other comprehensive loss:
Net unrealized loss on
derivative instruments qualifying
as hedges:
Net unrealized loss on
derivative instruments arising
during the period, net of tax of
$8,467 and $6,424 in 2005 and 2004,
respectively (13,525) (10,047)
Less: Reclassification adjustment
for loss on derivative
instruments included in net income,
net of tax of $1,057 and $1,020 in
2005 and 2004, respectively (1,688) (1,595)
Net unrealized loss on
derivative instruments qualifying
as hedges (11,837) (8,452)
Foreign currency translation
adjustment (1,019) (1,438)
(12,856) (9,890)
Comprehensive income $101,737 $72,319
12. Equity method investments
The Company has a number of equity method investments including
Carib Power Management LLC (Carib Power) and Hartwell Energy
Limited Partnership (Hartwell). The Company assesses its
equity method investments for impairment whenever events or
changes in circumstances indicate that the related carrying
values may not be recoverable. None of the Company's equity
method investments have been impaired and, accordingly, no
impairment losses have been recorded in the accompanying
consolidated financial statements or related equity method
investment balances.
In February 2004, Centennial Energy Resources International,
Inc. (Centennial International), an indirect wholly owned
subsidiary of the Company, acquired 49.99 percent of Carib
Power. Carib Power, through a wholly owned subsidiary, owns a
225-megawatt natural gas-fired electric generating facility
located in Trinidad and Tobago (Trinity Generating Facility).
The Trinity Generating Facility sells its output to the
Trinidad and Tobago Electric Commission (T&TEC), the
governmental entity responsible for the transmission,
distribution and administration of electrical power to the
national electrical grid of Trinidad and Tobago. The power
purchase agreement expires in September 2029. T&TEC also is
under contract to supply natural gas to the Trinity Generating
Facility during the term of the power purchase contract. The
functional currency for the Trinity Generating Facility is the
U.S. dollar.
In September 2004, Centennial Resources, through wholly owned
subsidiaries, acquired a 50-percent ownership interest in a 310-
megawatt natural gas-fired electric generating facility located
in Hartwell, Georgia (Hartwell Generating Facility). The
Hartwell Generating Facility sells its output under a power
purchase agreement with Oglethorpe Power Corporation
(Oglethorpe) that expires in May 2019. Oglethorpe reimburses
the Hartwell Generating Facility for actual costs of fuel
acquired to operate the plant. American National Power, a
wholly owned subsidiary of International Power of the United
Kingdom, holds the remaining 50-percent ownership interest and
is the operating partner for the facility.
In June 2005, an indirect wholly owned subsidiary of the
Company completed the sale to Petrobras, the Brazilian state-
controlled energy company, of its 49 percent interest in MPX
Termoceara, Ltda. (MPX). The Company realized a gain of $15.6
million from the sale. MPX owns and operates a 220-megawatt
natural gas-fired electric generating facility (Termoceara
Generating Facility) in the Brazilian state of Ceara.
Petrobras had entered into a contract to purchase all of the
capacity and market all of the energy from the Termoceara
Generating Facility. The electric power sales contract with
Petrobras was scheduled to expire in mid-2008.
The functional currency for the Termoceara Generating Facility
was the Brazilian Real. The electric power sales contract with
Petrobras contained an embedded derivative, which derived its
value from an annual adjustment factor, which largely indexed
the contract capacity payments to the U.S. dollar. The
Company's 49 percent share of the gain from the change in fair
value of the embedded derivative in the electric power sales
contract for the three and six months ended June 30, 2004, was
$4.1 million (after tax). The Company's 49 percent share of
the foreign currency loss resulting from the decrease in value
of the Brazilian Real versus the U.S. dollar for the three and
six months ended June 30, 2004, was $1.8 million (after tax)
and $2.0 million (after tax), respectively.
In 2005, the Termoceara Generating Facility was accounted for
as an asset held for sale and as a result no depreciation,
depletion and amortization expense was recorded in 2005.
Centennial had unconditionally guaranteed a portion of certain
bank borrowings of MPX. For more information on this
guarantee, see Note 19.
At June 30, 2005, the Company's equity method investments,
including Carib Power and Hartwell, had total assets of $243.6
million, and long-term debt of $159.6 million. At December 31,
2004, MPX, Carib Power and Hartwell had total assets of $334.2
million, and long-term debt of $224.9 million. At June 30,
2004, MPX and Carib Power had total assets of $202.8 million
and long-term debt of $158.0 million. The Company's investment
in its equity method investments, including the Trinity and
Hartwell Generating Facilities, was approximately $43.4
million, including undistributed earnings of $2.6 million, at
June 30, 2005. The Company's investment in the Termoceara,
Trinity and Hartwell Generating Facilities was approximately
$65.7 million, including undistributed earnings of $26.6
million, at December 31, 2004. The Company's investment in the
Termoceara and Trinity Generating Facilities was approximately
$26.0 million, including undistributed earnings of $14.8
million, at June 30, 2004.
13. Goodwill and other intangible assets
The changes in the carrying amount of goodwill were as follows:
Balance Goodwill Balance
as of Acquired as of
Six Months January 1, During June 30,
Ended June 30, 2005 2005 the Year* 2005
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,632 12,102 74,734
Pipeline and energy
services 5,464 --- 5,464
Natural gas and oil
production --- --- ---
Construction materials
and mining 120,452 3,155 123,607
Independent power
production 11,195 (28) 11,167
Other --- --- ---
Total $199,743 $ 15,229 $214,972
Balance Goodwill Balance
as of Acquired as of
Six Months January 1, During June 30,
Ended June 30, 2004 2004 the Year* 2004
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,604 28 62,632
Pipeline and energy
services 9,494 --- 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 120,198 (2,668) 117,530
Independent power
production 7,131 3,766 10,897
Other --- --- ---
Total $199,427 $ 1,126 $200,553
Balance Goodwill Goodwill Balance
as of Acquired Impaired as of
Year Ended January 1, During During December 31,
December 31, 2004 2004 the Year* the Year 2004
(In thousands)
Electric $ --- $ --- $ --- $ ---
Natural gas
distribution --- --- --- ---
Utility services 62,604 28 --- 62,632
Pipeline and energy
services 9,494 --- (4,030) 5,464
Natural gas and oil
production --- --- --- ---
Construction materials
and mining 120,198 254 --- 120,452
Independent power
production 7,131 4,064 --- 11,195
Other --- --- --- ---
Total $199,427 $4,346 $(4,030) $199,743
__________________
* Includes purchase price adjustments related to acquisitions
acquired in a prior period.
Innovatum, Inc. (Innovatum), an indirect wholly owned subsidiary
of the Company, which specializes in cable and pipeline
magnetization and location, developed a hand-held locating device
that can detect both magnetic and plastic materials, including
unexploded ordnance. Innovatum was working with, and had
demonstrated the device to, a Department of Defense contractor and
had also met with individuals from the Department of Defense to
discuss the possibility of using the hand-held locating device in
their operations. In the third quarter of 2004, after
communications with the Department of Defense, and delays in
further testing resulting from a Department of Defense request to
enhance the hand-held locating device, Innovatum decreased its
expected future cash flows from the hand-held locating device.
This decrease, coupled with the continued downturn in the
telecommunications and energy industries, resulted in a revised
earnings forecast for Innovatum, and as a result, a goodwill
impairment loss of $4.0 million (before and after tax) was
recognized in the third quarter of 2004. Innovatum, a reporting
unit for goodwill impairment testing, is part of the pipeline and
energy services segment. The fair value of Innovatum was
estimated using the expected present value of future cash flows.
Other intangible assets were as follows:
June 30, June 30, December 31,
2005 2004 2004
(In thousands)
Amortizable intangible assets:
Acquired contracts $ 18,707 $14,636 $ 15,041
Accumulated amortization (6,519) (3,036) (5,013)
12,188 11,600 10,028
Noncompete agreements 11,784 10,275 10,575
Accumulated amortization (8,310) (8,024) (8,186)
3,474 2,251 2,389
Other 14,698 6,656 9,535
Accumulated amortization (914) (362) (534)
13,784 6,294 9,001
Unamortizable intangible
assets 851 960 851
Total $ 30,297 $ 21,105 $ 22,269
The unamortizable intangible assets were recognized in
accordance with SFAS No. 87, "Employers' Accounting for
Pensions," which requires that if an additional minimum
liability is recognized an equal amount shall be recognized as
an intangible asset, provided that the asset recognized shall
not exceed the amount of unrecognized prior service cost. The
unamortizable intangible asset will be eliminated or adjusted
as necessary upon a new determination of the amount of
additional liability.
Amortization expense for amortizable intangible assets for the
three and six months ended June 30, 2005 was $1.2 million and
$2.1 million, respectively. Amortization expense for
amortizable intangible assets for the three and six months
ended June 30, 2004, and for the year ended December 31, 2004,
was $702,000, $1.3 million and $3.8 million, respectively.
Estimated amortization expense for amortizable intangible
assets is $5.9 million in 2005, $6.0 million in 2006, $4.5
million in 2007, $4.0 million in 2008, $3.9 million in 2009 and
$7.2 million thereafter.
14. Derivative instruments
From time to time, the Company utilizes 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 following information should be read in conjunction
with Notes 1 and 5 in the Company's Notes to Consolidated
Financial Statements in the 2004 Annual Report.
As of June 30, 2005, Fidelity Exploration & Production Company
(Fidelity), an indirect wholly owned subsidiary of the Company,
held derivative instruments designated as cash flow hedging
instruments.
Hedging activities
Fidelity utilizes natural gas and oil price swap and collar
agreements to manage a portion of the market risk associated
with fluctuations in the price of natural gas and oil on its
forecasted sales of natural gas and oil production. Each of
the natural gas and oil price swap and collar agreements was
designated as a hedge of the forecasted sale of natural gas and
oil production.
For the three and six months ended June 30, 2005 and 2004, the
amount of hedge ineffectiveness, which was included in
operating revenues, was immaterial. For the three and six
months ended June 30, 2005 and 2004, Fidelity did not exclude
any components of the derivative instruments' gain or loss from
the assessment of hedge effectiveness and there were no
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 the line item in
which the hedged item is recorded. As of June 30, 2005, the
maximum term of Fidelity's swap and collar agreements, in which
it is hedging its exposure to the variability in future cash
flows for forecasted transactions, is 18 months. Fidelity
estimates that over the next 12 months net losses of
approximately $13.7 million 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.
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. Prior to the fourth quarter
of 2004, the Company reported six reportable segments
consisting of electric, natural gas distribution, utility
services, pipeline and energy services, natural gas and oil
production and construction materials and mining. The
independent power production and other operations did not
individually meet the criteria to be considered a reportable
segment. In the fourth quarter of 2004, the Company separated
independent power production as a reportable business segment
due to the significance of its operations. The Company's
operations are now conducted through seven reportable segments
and all prior period information has been restated to reflect
this change.
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 investments in
natural resource-based projects.
The electric segment generates, transmits and distributes
electricity, and the natural gas distribution segment
distributes natural gas. These operations also supply related
value-added products and services in the northern Great Plains.
The utility services segment specializes in electrical line
construction, pipeline construction, inside electrical wiring
and cabling, and the manufacture and distribution of 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. The pipeline and energy services segment also
provides energy-related management services, including cable
and pipeline magnetization and locating.
The natural gas and oil production segment is engaged in
natural gas and oil acquisition, exploration, development and
production activities, primarily in the Rocky Mountain region
of the United States and in and around the Gulf of Mexico.
The construction materials and mining segment mines aggregates
and markets crushed stone, sand, gravel and related
construction materials, including ready-mixed concrete, cement,
asphalt and other value-added products, as well as performs
integrated construction services, in the central and western
United States and in the states of Alaska and Hawaii.
The independent power production segment owns, builds and
operates electric generating facilities in the United States
and has investments in domestic and international natural
resource-based projects. Electric capacity and energy produced
at its power plants are sold primarily under mid- and long-term
contracts to nonaffiliated entities.
The information below follows the same accounting policies as
described in Note 1 in the Company's Notes to Consolidated
Financial Statements in the 2004 Annual Report. Information on
the Company's businesses was as follows:
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Three Months
Ended June 30, 2005
Electric $ 41,052 $ --- $ 1,755
Natural gas distribution 54,691 --- (1,283)
Pipeline and energy
services 86,366 15,055 8,737
182,109 15,055 9,209
Utility services 136,911 (19) 3,659
Natural gas and oil
production 43,487 54,255 29,949
Construction materials
and mining 394,015 --- 18,421
Independent power
production 13,650 --- 18,582
Other --- 1,367 182
588,063 55,603 70,793
Intersegment eliminations --- (70,658) ---
Total $ 770,172 $ --- $ 80,002
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Three Months
Ended June 30, 2004
Electric $ 39,834 $ --- $ 735
Natural gas distribution 47,461 --- (1,097)
Pipeline and energy
services 72,073 13,423 4,434
159,368 13,423 4,072
Utility services 97,226 --- (2,294)
Natural gas and oil
production 39,038 45,181 26,136
Construction materials
and mining 347,026 200 20,345
Independent power
production 10,643 --- 10,136
Other --- 919 63
493,933 46,300 54,386
Intersegment eliminations --- (59,723) ---
Total $ 653,301 $ --- $ 58,458
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Six Months
Ended June 30, 2005
Electric $ 85,371 $ --- $ 4,888
Natural gas distribution 199,665 --- 3,539
Pipeline and energy
services 152,445 41,803 11,963
437,481 41,803 20,390
Utility services 250,621 132 5,617
Natural gas and oil
production 81,797 103,025 58,754
Construction materials
and mining 581,102 7 9,885
Independent power
production 23,466 --- 19,339
Other --- 2,735 266
936,986 105,899 93,861
Intersegment eliminations --- (147,702) ---
Total $1,374,467 $ --- $114,251
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Six Months
Ended June 30, 2004
Electric $ 86,824 $ --- $ 4,143
Natural gas distribution 175,779 --- 1,228
Pipeline and energy
services 128,612 41,036 7,117
391,215 41,036 12,488
Utility services 197,477 --- (4,195)
Natural gas and oil
production 76,544 88,644 51,395
Construction materials
and mining 486,473 200 8,464
Independent power
production 17,051 --- 13,399
Other --- 1,837 316
777,545 90,681 69,379
Intersegment eliminations --- (131,717) ---
Total $1,168,760 $ --- $ 81,867
Earnings (loss) from electric, natural gas distribution and
pipeline and energy services are substantially all from
regulated operations. Earnings (loss) from utility services,
natural gas and oil production, construction materials and
mining, independent power production, and other are all from
nonregulated operations.
16. Acquisitions
During the first six months of 2005, the Company acquired
utility services businesses in Nevada and construction materials
and mining businesses in Idaho and Oregon, and natural gas and
oil properties in south Texas, none of which was individually
material. The total purchase consideration for these businesses
and properties and purchase price adjustments with respect to
certain other acquisitions acquired prior to 2005, including the
Company's common stock and cash, was $192.9 million.
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. Final
fair market values are pending the completion of the review of
the relevant assets, liabilities and issues identified 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.
17. Employee benefit plans
The Company has noncontributory defined benefit pension plans
and other postretirement benefit plans for certain eligible
employees. The Company recognized the effects of the Medicare
Prescription Drug, Improvement and Modernization Act of 2003
(2003 Medicare Act) during the second quarter of 2004.
Components of net periodic benefit cost for the Company's
pension and other postretirement benefit plans were as follows:
Other
Pension Postretirement
Three Months Benefits Benefits
Ended June 30, 2005 2004 2005 2004
(In thousands)
Components of net periodic
benefit cost:
Service cost $2,121 $ 1,984 $ 546 $ 312
Interest cost 4,152 4,011 1,039 850
Expected return on
assets (5,063) (5,100) (1,042) (979)
Amortization of prior
service cost 256 283 --- 72
Recognized net actuarial
(gain) loss 483 (8) (38) (27)
Amortization of net
transition obligation
(asset) (11) (62) 525 550
Net periodic benefit cost 1,938 1,108 1,030 778
Less amount capitalized 185 117 115 80
Net periodic benefit cost $1,753 $ 991 $ 915 $ 698
Other
Pension Postretirement
Six Months Benefits Benefits
Ended June 30, 2005 2004 2005 2004
(In thousands)
Components of net periodic
benefit cost:
Service cost $4,168 $ 3,833 $1,031 $ 896
Interest cost 8,308 7,952 2,136 2,173
Expected return on
assets (9,973) (10,187) (2,025)(1,972)
Amortization of prior
service cost 512 561 --- 72
Recognized net actuarial
(gain) loss 692 239 (77) (82)
Amortization of net
transition obligation
(asset) (22) (125) 1,063 1,076
Net periodic benefit cost 3,685 2,273 2,128 2,163
Less amount capitalized 357 191 206 182
Net periodic benefit cost $3,328 $ 2,082 $1,922 $1,981
In addition to the qualified plan defined pension benefits
reflected in the table above, the Company also has an unfunded,
nonqualified benefit plan for executive officers and certain
key management employees that generally provides 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's net periodic benefit cost for this plan for the three
and six months ended June 30, 2005, was $1.4 million and $3.3
million, respectively. The Company's net periodic benefit cost
for this plan for the three and six months ended June 30, 2004,
was $2.3 million and $3.8 million, respectively.
18. Regulatory matters and revenues subject to refund
On March 24, 2005, Montana-Dakota filed an application with the
South Dakota Public Utilities Commission (SDPUC) for the East
River service area for a natural gas rate increase. Montana-
Dakota requested a total increase of $850,000 annually or 12.8
percent above current rates. A final order from the SDPUC is
expected in late 2005.
In September 2004, Great Plains filed an application with the
Minnesota Public Utilities Commission (MPUC) for a natural gas
rate increase. Great Plains had requested a total increase of
$1.4 million annually or approximately 4.0 percent above
current rates. Great Plains also requested an interim increase
of $1.4 million annually. In November 2004, the MPUC issued an
Order authorizing an interim increase of $1.4 million annually
effective with service rendered on or after January 10, 2005,
subject to refund. A final order from the MPUC is expected in
early 2006.
A liability has been provided for a portion of the revenues
that have been collected subject to refund with respect to
Great Plains' pending regulatory proceeding. Great Plains
believes that the liability is adequate based on its assessment
of the ultimate outcome of the proceeding.
In December 1999, Williston Basin Interstate Pipeline Company
(Williston Basin), an indirect wholly owned subsidiary of the
Company, filed a general natural gas rate change application
with the Federal Energy Regulatory Commission (FERC).
Williston Basin began collecting such rates effective June 1,
2000, subject to refund. In May 2001, the Administrative Law
Judge (ALJ) issued an Initial Decision on Williston Basin's
natural gas rate change application. The Initial Decision
addressed numerous issues relating to the rate change
application, including matters relating to allowable levels of
rate base, return on common equity, and cost of service, as
well as volumes established for purposes of cost recovery, and
cost allocation and rate design. In July 2003, the FERC issued
its Order on Initial Decision. The Order on Initial Decision
affirmed the ALJ's Initial Decision on many of the issues
including rate base and certain cost of service items as well
as volumes to be used for purposes of cost recovery, and cost
allocation and rate design. However, there were other issues
as to which the FERC differed with the ALJ including return on
common equity and the correct level of corporate overhead
expense. In August 2003, Williston Basin requested rehearing
of a number of issues including determinations associated with
cost of service, throughput, and cost allocation and rate
design, as discussed in the FERC's Order on Initial Decision.
In May 2004, the FERC issued an Order on Rehearing. The Order
on Rehearing denied rehearing on all of the issues addressed by
Williston Basin in its August 2003 request for rehearing except
for the issue of the proper rate to utilize for transmission
system negative salvage expenses. In addition, the FERC
remanded the issues regarding certain service and annual demand
quantity restrictions to an ALJ for resolution. In June 2004,
Williston Basin requested clarification of a few of the issues
addressed in the Order on Rehearing including determinations
associated with cost of service and cost allocation, as
discussed in the FERC's Order on Rehearing. In June 2004,
Williston Basin also made its filing to comply with the
requirements of the various FERC orders in this proceeding.
Williston Basin participated in a hearing before the ALJ in
early January 2005, regarding certain service and annual demand
quantity restrictions remanded to the ALJ by the FERC in its
Order on Rehearing. On April 8, 2005, the ALJ issued an
Initial Decision on the matters remanded by the FERC. In the
Initial Decision, the ALJ decided that Williston Basin had not
supported its position regarding the service and annual demand
quantity restrictions. Williston Basin filed its Brief on
Exceptions regarding these issues with the FERC on May 9, 2005,
and its Brief Opposing Exceptions to issues raised by Northern
States Power Company on May 31, 2005. On April 19, 2005, the
FERC issued its Order on Compliance Filing and Motion for
Refunds. In this Order, the FERC approved Williston Basin's
refund rates and established rates to be effective April 19,
2005. Williston Basin filed its compliance filing complying
with the requirements of this Order regarding rates and issued
refunds totaling approximately $18.5 million to its customers
on May 19, 2005. Williston Basin filed its Refund Report,
detailing the $18.5 million in refunds it issued to its
customers, with the FERC on June 1, 2005. As a result of the
Order, Williston Basin recorded a $5.0 million (after tax)
benefit from the resolution of the rate proceeding.
19. Contingencies
Litigation
In June 1997, Jack J. Grynberg (Grynberg) filed suit under the
Federal False Claims Act against Williston Basin and Montana-
Dakota and filed over 70 similar suits against natural gas
transmission companies and producers, gatherers, and processors
of natural gas. Grynberg, acting on behalf of the United
States under the Federal False Claims Act, alleged improper
measurement of the heating content and volume of natural gas
purchased by the defendants resulting in the underpayment of
royalties to the United States. In April 1999, the United
States Department of Justice decided not to intervene in these
cases. In response to a motion filed by Grynberg, the Judicial
Panel on Multidistrict Litigation consolidated all of these
cases in the United States District Court for the District of
Wyoming (Wyoming Federal District Court).
In June 2004, following preliminary discovery, Williston Basin
and Montana-Dakota joined with other defendants and filed a
Motion to Dismiss on the ground that the information upon which
Grynberg based his complaint was publicly disclosed prior to
the filing of his complaint and further, that he is not the
original source of such information. The Motion to Dismiss is
additionally based on the ground that Grynberg disclosed the
filing of the complaint prior to the entry of a court order
allowing such disclosure and that Grynberg failed to provide
adequate information to the government prior to filing suit.
The Motion to Dismiss was heard on March 17 and 18, 2005, by
the Special Master appointed by the Wyoming Federal District
Court. The Special Master, in his Written Report dated May 13,
2005, recommended the dismissal of Williston Basin and Montana-
Dakota. The Written Report will be considered for adoption by
the Wyoming Federal District Court.
In the event the Motion to Dismiss is not granted, it is
expected that further discovery will follow. Williston Basin
and Montana-Dakota believe Grynberg will not prevail in the
suit or recover damages from Williston Basin and/or Montana-
Dakota because insufficient facts exist to support the
allegations. Williston Basin and Montana-Dakota believe
Grynberg's claims are without merit and intend to vigorously
contest this suit.
Grynberg has not specified the amount he seeks to recover.
Williston Basin and Montana-Dakota are unable to estimate their
potential exposure and will be unable to do so until discovery
is completed.
Fidelity has been named as a defendant in, and/or certain of
its operations are or have been the subject of, more than a
dozen lawsuits filed in connection with its coalbed natural gas
development in the Powder River Basin in Montana and Wyoming.
These lawsuits were filed in federal and state courts in
Montana between June 2000 and November 2004 by a number of
environmental organizations, including the Northern Plains
Resource Council (NPRC) and the Montana Environmental
Information Center, as well as the Tongue River Water Users'
Association and the Northern Cheyenne Tribe. Portions of two
of the lawsuits have been transferred to the Wyoming Federal
District Court. The lawsuits involve allegations that Fidelity
and/or various government agencies are in violation of state
and/or federal law, including the Federal Clean Water Act, the
National Environmental Policy Act (NEPA), the Federal Land
Management Policy Act, the National Historic Preservation Act
(NHPA) and the Montana Environmental Policy Act. The cases
involving alleged violations of the Federal Clean Water Act
have been resolved without a finding that Fidelity is in
violation of the Federal Clean Water Act. There presently are
no claims pending for penalties, fines or damages under the
Federal Clean Water Act. The suits that remain extant include
a variety of claims that state and federal government agencies
violated various environmental laws that impose procedural
requirements and the lawsuits seek injunctive relief,
invalidation of various permits and unspecified damages.
In suits filed in the United States District Court for the
District of Montana (Montana Federal District Court), the NPRC
and the Northern Cheyenne Tribe asserted that further
development by Fidelity and others of coalbed natural gas in
Montana should be enjoined until the Bureau of Land Management
(BLM) completes a Supplemental Environmental Impact Statement
(SEIS). The Montana Federal District Court, in February 2005,
entered a ruling requiring the BLM to complete a SEIS. The
Montana Federal District Court later entered an order that
would have allowed limited coalbed natural gas production in
the Powder River Basin in Montana pending the BLM's preparation
of the SEIS. The plaintiffs appealed the decision to the
United States Ninth Circuit Court of Appeals (Ninth Circuit).
The Montana Federal District Court declined to enter an
injunction requested by the NPRC and the Northern Cheyenne
Tribe that would have enjoined production pending the appeal.
In late May 2005, the Ninth Circuit granted the request of the
NPRC and the Northern Cheyenne Tribe and, pending further order
from the Ninth Circuit, enjoined the BLM from approving any
coalbed natural gas production projects in the Powder River
Basin in Montana. That court also enjoined Fidelity from
drilling any additional federally permitted wells in its
Montana Coal Creek Project and from constructing infrastructure
to produce and transport coalbed natural gas from the Coal
Creek Project's existing federal wells.
In related actions in the Montana Federal District Court, the
NPRC and the Northern Cheyenne Tribe asserted (among other
things) that the actions of the BLM in approving Fidelity's
applications for permits and the plan of development for the
Tongue River-Badger Hills Project in Montana (Badger Hills
Project) did not comply with applicable Federal laws, including
the NHPA and the NEPA. The NPRC also asserted that the
Environmental Assessment that supported the BLM's prior
approval of the Badger Hills Project was invalid. On June 6,
2005, the Montana Federal District Court issued orders in these
cases enjoining operations on Fidelity's Badger Hills Project
pending the BLM's consultation with the Northern Cheyenne Tribe
as to satisfaction of the applicable requirements of NHPA and a
further environmental analysis under NEPA. Fidelity has sought
and obtained stays of the injunctive relief from the Montana
Federal District Court and production from Fidelity's Badger
Hills Project continues.
Fidelity is vigorously defending all coalbed-related lawsuits
and related actions in which it is involved, including the
recent Ninth Circuit and Montana Federal District Court
injunctions. In those cases where damage claims have been
asserted, Fidelity is unable to quantify the damages sought and
will be unable to do so until after the completion of
discovery. If the plaintiffs are successful in these lawsuits,
the ultimate outcome of the actions could have a material
effect on Fidelity's existing coalbed natural gas operations
and/or the future development of this resource in the affected
regions.
Montana-Dakota has joined with two electric generators in
appealing a finding by the North Dakota Department of Health
(ND Health Department) in September 2003 that the ND Health
Department may unilaterally revise operating permits previously
issued to electric generating plants. Although it is doubtful
that any revision of Montana-Dakota's operating permits by the
ND Health Department would reduce the amount of electricity its
plants could generate, the finding, if allowed to stand, could
increase costs for sulfur dioxide removal and/or limit Montana-
Dakota's ability to modify or expand operations at its North
Dakota generation sites. Montana-Dakota and the other electric
generators filed their appeal of the order in October 2003, in
the Burleigh County District Court in Bismarck, North Dakota.
Proceedings have been stayed pending discussions with the U.S.
Environmental Protection Agency (EPA), the ND Health Department
and the other electric generators.
The Company is also 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
In December 2000, Morse Bros., Inc. (MBI), an indirect wholly
owned subsidiary of the Company, was named by the EPA as a
Potentially Responsible Party in connection with the cleanup of
a commercial property site, acquired by MBI in 1999, and part
of the Portland, Oregon, Harbor Superfund Site. Sixty-eight
other parties were also named in this administrative action.
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 of the harbor site for
both the EPA and the Oregon State Department of Environmental
Quality (DEQ) are being recorded, and initially paid, through
an administrative consent order by the Lower Willamette Group
(LWG), a group of 10 entities, which does not include MBI. The
LWG estimates the overall remedial investigation and
feasibility study will cost approximately $10 million. It is
not possible to estimate the cost of a corrective action plan
until the remedial investigation and feasibility study has been
completed, the EPA has decided on a strategy, and a record of
decision has been published. While the remedial investigation
and feasibility study for the harbor site has commenced, it is
expected to take several years to complete. The development of
a proposed plan and record of decision on the harbor site is
not anticipated to occur until 2006, after which a cleanup plan
will be undertaken.
Based upon a review of the Portland Harbor sediment
contamination evaluation by the DEQ and other information
available, MBI does not believe it is a Responsible Party. In
addition, MBI has notified Georgia-Pacific West, Inc., the
seller of the commercial property site to MBI, that it intends
to seek indemnity for any and all liabilities incurred in
relation to the above matters, pursuant to the terms of their
sale agreement.
The Company believes it is not probable that it will incur any
material environmental remediation costs or damages in relation
to the above administrative action.
In August 2004, Colorado Power Partners (CPP) and BIV
Generation Company, LLC (BIV), indirect wholly owned
subsidiaries of the Company, were each issued a draft
Compliance Order on Consent (Compliance Orders) by the Colorado
Department of Public Health and Environment (CDPHE). The
Compliance Orders were issued in connection with excess
emission periods of nitrogen oxides and carbon monoxide at the
Company's electric generating facilities in Brush, Colorado,
occurring mainly during start-up and shut-down periods. In
June 2005, CPP, BIV and the CDPHE agreed upon the Compliance
Orders. The terms of the Compliance Orders for CPP and BIV
include administrative penalties of $9,900 and $10,600, and
noncompliance/economic benefit penalties of $7,700 and $8,300,
respectively. In addition, the terms of the Compliance Orders
include an agreement for CPP and BIV to make a non-tax
deductible donation for a Supplemental Environmental Project
(SEP) in Morgan County, Colorado with total expenditures of not
less than $39,600 and $42,400, respectively. If the parties
cannot come to an agreement on the SEP to be funded within 120
days of the Compliance Order, CPP and BIV shall pay $39,600 and
$42,400, respectively, as administrative penalties.
Guarantees
Centennial had unconditionally guaranteed a portion of certain
bank borrowings of MPX in connection with the Company's equity
method investment in the Termoceara Generating Facility, as
discussed in Note 12. The Company, through an indirect wholly
owned subsidiary, owned 49 percent of MPX. The guarantee to
MPX's creditors expired on July 25, 2005, as the outstanding
bank borrowings were repaid on that date. At June 30, 2005,
the aggregate amount of borrowings outstanding subject to these
guarantees was $29.6 million. These guarantees are not
reflected on the Consolidated Balance Sheets.
In connection with the sale of MPX to Petrobras an indirect
wholly-owned subsidiary of the Company has agreed to indemnify
Petrobras for 49 percent of any losses which 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.
In addition, WBI Holdings has guaranteed certain of Fidelity's
natural gas and oil price swap and collar agreement
obligations. Fidelity's obligations at June 30, 2005, were
$11.3 million. There is no fixed maximum amount guaranteed in
relation to the natural gas and oil price swap and collar
agreements, as the amount of the obligation is dependent upon
natural gas and oil commodity prices. The amount of hedging
activity entered into by the subsidiary is limited by corporate
policy. The guarantees of the natural gas and oil price swap
and collar agreements at June 30, 2005, expire in 2005 and
2006; 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. The amount outstanding by Fidelity was reflected
on the Consolidated Balance Sheets at June 30, 2005. 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
natural gas transportation and sales agreements, electric power
supply agreements, insurance policies and certain other
guarantees. At June 30, 2005, the fixed maximum amounts
guaranteed under these agreements aggregated $99.3 million.
The amounts of scheduled expiration of the maximum amounts
guaranteed under these agreements aggregate $15.0 million in
2005; $27.4 million in 2006; $2.2 million in 2007; $200,000 in
2008; $900,000 in 2009; $30.0 million in 2010; $12.0 million in
2012; $2.1 million in 2028; $500,000, which is subject to
expiration 30 days after the receipt of written notice and $9.0
million, which has no scheduled maturity date. A guarantee for
an unfixed amount estimated at $300,000 at June 30, 2005, has
no scheduled maturity date. The amount outstanding by
subsidiaries of the Company under the above guarantees was
$528,000 and was reflected on the Consolidated Balance Sheets
at June 30, 2005. 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.
Fidelity and WBI Holdings have outstanding guarantees to
Williston Basin. These guarantees are related to natural gas
transportation and storage agreements that guarantee the
performance of Prairielands Energy Marketing, Inc.
(Prairielands), an indirect wholly owned subsidiary of the
Company. At June 30, 2005, the fixed maximum amounts
guaranteed under these agreements aggregated $22.9 million.
Scheduled expiration of the maximum amounts guaranteed under
these agreements aggregate $2.9 million in 2008 and $20.0
million in 2009. In the event of Prairielands' default in its
payment obligations, the subsidiary issuing the guarantee for
that particular obligation would be required to make payments
under its guarantee. The amount outstanding by Prairielands
under the above guarantees was $1.5 million, which was not
reflected on the Consolidated Balance Sheet at June 30, 2005,
because these intercompany transactions are eliminated in
consolidation.
In addition, Centennial has issued guarantees to third parties
related to the Company's routine purchase of maintenance items
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,
Centennial would be required to make payments under these
guarantees. Any amounts outstanding by subsidiaries of the
Company for these maintenance items were reflected on the
Consolidated Balance Sheet at June 30, 2005.
As of June 30, 2005, Centennial was contingently liable for the
performance of certain of its subsidiaries under approximately
$614 million of surety bonds. These bonds are principally for
construction contracts and reclamation obligations of these
subsidiaries entered into in the normal course of business.
Centennial indemnifies the respective surety bond companies
against any exposure under the bonds. The purpose of
Centennial's indemnification is to allow the subsidiaries to
obtain bonding at competitive rates. In the event a subsidiary
of the Company does not fulfill its obligations in relation to
its bonded contract or obligation, Centennial may be required
to make payments under its indemnification. A large portion of
these contingent commitments 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.
The surety bonds were not reflected on the Consolidated Balance
Sheets.
20. Related party transactions
In 2004, Bitter Creek Pipelines, LLC (Bitter Creek), an
indirect wholly owned subsidiary of the Company, entered into
two natural gas gathering agreements with Nance Petroleum
Corporation (Nance Petroleum), a wholly owned subsidiary of St.
Mary Land & Exploration Company (St. Mary). Robert L. Nance,
an executive officer and shareholder of St. Mary, is also a
member of the Board of Directors of the Company. The natural
gas gathering agreements with Nance Petroleum were effective
upon completion of certain high and low pressure gathering
facilities, which occurred in mid-December 2004. Bitter
Creek's capital expenditures related to the completion of the
gathering lines and the expansion of its gathering facilities
to accommodate the natural gas gathering agreements were $1.1
million and $2.1 million for the three and six months ended
June 30, 2005, respectively, and are estimated for the next
three years to be $3.2 million in 2005, $2.2 million in 2006
and $3.3 million in 2007. The natural gas gathering agreements
are each for a term of 15 years and month-to-month thereafter.
Bitter Creek's revenues from these contracts were $287,000 and
$539,000 for the three and six months ended June 30, 2005,
respectively, and estimated revenues from these contracts for
the next three years are $1.8 million in 2005, $4.3 million in
2006 and $6.0 million in 2007. The amount due from Nance
Petroleum at June 30, 2005, was $98,000.
Montana-Dakota entered into an agreement to purchase natural
gas from Nance Petroleum for the period April 1, 2005 to
October 31, 2005. Montana-Dakota estimates that it will
purchase between $2.0 million to $2.5 million of natural gas
from Nance Petroleum during this period. Montana-Dakota's
expenses under this agreement for the three and six months
ended June 30, 2005, were $760,000. The amount due to Nance
Petroleum at June 30, 2005, was $251,000.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
OVERVIEW
This subsection of MD&A is an overview of the important factors that
management focuses on in evaluating the Company's businesses, the
Company's financial condition and operating performance, the
Company's overall business strategy and the earnings of the Company
for the period covered by this report. This subsection is not
intended to be a substitute for reading the entire MD&A section.
Reference is made to the various important factors listed under the
heading Risk Factors and Cautionary Statements that May Affect
Future Results, as well as other factors that are listed in the
Introduction in relation to any forward-looking statement.
Business and Strategy Overview
Prior to the fourth quarter of 2004, the Company reported six
reportable segments consisting of electric, natural gas
distribution, utility services, pipeline and energy services,
natural gas and oil production and construction materials and
mining. The independent power production and other operations did
not individually meet the criteria to be considered a reportable
segment. In the fourth quarter of 2004, the Company separated
independent power production as a reportable business segment due to
the significance of its operations. The Company's operations are
now conducted through seven reportable segments and all prior period
information has been restated to reflect this change.
The vast majority of the Company's operations are located within the
United States. The Company also has investments in foreign
countries, which consist of investments in natural resource-based
projects, as discussed in Note 12 of Notes to Consolidated Financial
Statements.
The electric segment includes the electric generation, transmission
and distribution operations of Montana-Dakota. The natural gas
distribution segment includes the natural gas distribution
operations of Montana-Dakota and Great Plains Natural Gas Co. The
electric and natural gas distribution segments also supply related
value-added products and services in the northern Great Plains.
The utility services segment includes all the operations of Utility
Services, Inc., which specializes in electrical line construction,
pipeline construction, inside electrical wiring and cabling, and the
manufacture and distribution of specialty equipment.
The pipeline and energy services segment includes WBI Holdings'
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. The pipeline and energy services segment also
provides energy-related management services, including cable and
pipeline magnetization and locating.
The natural gas and oil production segment includes WBI Holdings'
natural gas and oil acquisition, exploration, development and
production operations, primarily in the Rocky Mountain region of the
United States and in and around the Gulf of Mexico.
The construction materials and mining segment includes the results
of Knife River, which mines aggregates and markets crushed stone,
sand, gravel and related construction materials, including ready-
mixed concrete, cement, asphalt and other value-added products, as
well as performs integrated construction services, in the central
and western United States and in the states of Alaska and Hawaii.
The independent power production operations of Centennial Resources
own, build and operate electric generating facilities in the United
States and have investments in domestic and international natural
resource-based projects. Electric capacity and energy produced at
its power plants are sold primarily under mid- and long-term
contracts to nonaffiliated entities.
Earnings (loss) from electric, natural gas distribution and pipeline
and energy services are substantially all from regulated operations.
Earnings (loss) from utility services, natural gas and oil
production, construction materials and mining, independent power
production, and other are all from nonregulated operations.
The Company's strategy is to apply its expertise in energy and
transportation infrastructure industries to increase market share
through internal growth along with acquisition of well-managed
companies and properties, and development of projects that enhance
shareholder value and are accretive to earnings per share and
returns on invested capital.
The Company has capabilities to fund its growth and operations
through various sources, including internally generated funds,
commercial paper credit facilities and through the issuance of long-
term debt and the Company's equity securities. Net capital
expenditures are estimated to be approximately $700 million for
2005.
The Company faces certain challenges and risks as it pursues its
growth strategies, including, but not limited to the following:
- The natural gas and oil production business experiences
fluctuations in natural gas and oil prices. These prices are
volatile and subject to significant change at any time. The Company
hedges a portion of its natural gas and oil production in order to
mitigate the effects of price volatility.
- Economic volatility both domestically and in the foreign
countries where the Company does business affects the Company's
operations as well as the demand for its products
and services and, as a result, may have a negative impact on
the Company's future revenues.
- Fidelity continues to seek additional reserve and production
growth, both in areas of existing activity and in other regions,
through acquisition, exploration, development and production of
natural gas and oil resources, including the development and
production of its coalbed natural gas properties in the Powder River
Basin. In this context, Fidelity has been named as a defendant in,
and/or certain of its operations are the subject of, more than a
dozen lawsuits filed in connection with its coalbed natural gas
development program. Some of these actions have been successfully
resolved and Fidelity is actively defending the others. If the
plaintiffs are successful in the outstanding lawsuits, the ultimate
outcome of the actions could have a material effect on Fidelity's
existing coalbed natural gas operations and/or the future
development of its coalbed natural gas properties in this region.
For further information on certain factors that should be considered
for a better understanding of the Company's financial condition, see
the various important factors listed under the heading Risk Factors
and Cautionary Statements that May Affect Future Results, as well as
other factors that are listed in the Introduction.
For information pertinent to various commitments and contingencies,
see Notes to Consolidated Financial Statements.
Earnings Overview
The following table summarizes the contribution to consolidated
earnings by each of the Company's businesses.
Three Months Six Months
Ended Ended
June 30, June 30,
2005 2004 2005 2004
(Dollars in millions, where applicable)
Electric $ 1.8 $ .7 $ 4.9 $ 4.2
Natural gas distribution (1.3) (1.1) 3.5 1.2
Utility services 3.7 (2.3) 5.6 (4.2)
Pipeline and energy services 8.7 4.4 12.0 7.1
Natural gas and oil production 29.9 26.2 58.8 51.4
Construction materials and mining 18.4 20.4 9.9 8.5
Independent power production 18.6 10.1 19.3 13.4
Other .2 .1 .3 .3
Earnings on common stock $80.0 $ 58.5 $114.3 $81.9
Earnings per common
share - basic $ .68 $ .50 $ .97 $ .71
Earnings per common
share - diluted $ .67 $ .50 $ .96 $ .70
Return on average common equity
for the 12 months ended 14.4% 13.3%
________________________________
Three Months Ended June 30, 2005 and 2004
Consolidated earnings for the second quarter ended June 30, 2005,
increased $21.5 million largely due to:
- A $15.6 million benefit from the sale of the Termoceara
Generating Facility, partially offset by the absence in 2005 of the
2004 operating results from the Termoceara Generating Facility at
the independent power production business
- Increased outside electrical line construction and inside
electrical workloads and margins at the utility services business
- A $5.0 million (after tax) benefit from the resolution of a
rate proceeding, as discussed in Note 18 of Notes to Consolidated
Financial Statements at the pipeline and energy services business
- Higher natural gas prices of 19 percent and higher oil prices
of 29 percent at the natural gas and oil production business
Partially offsetting the increase was the absence of the favorable
resolution of federal and related state income tax matters, which
resulted in a benefit of $5.9 million (after tax), including
interest, for the three months ended June 30, 2004.
Six Months Ended June 30, 2005 and 2004
Consolidated earnings for the six months ended June 30, 2005,
increased $32.4 million largely due to:
- Increased outside electrical line construction and inside
electrical workloads and margins at the utility services business
- Higher natural gas prices of 14 percent and higher oil prices
of 28 percent at the natural gas and oil production business
- A $15.6 million benefit from the sale of the Termoceara
Generating Facility, partially offset by the absence in 2005 of the
2004 operating results from the Termoceara Generating Facility at
the independent power production business
- A $5.0 million (after tax) benefit from the resolution of a
rate proceeding, as previously discussed
Partially offsetting the increase was the absence of the favorable
resolution of federal and related state income tax matters realized
in 2004.
FINANCIAL AND OPERATING DATA
The following tables contain key financial and operating statistics
for each of the Company's businesses.
Electric
Three Months Six Months
Ended Ended
June 30, June 30,
2005 2004 2005 2004
(Dollars in millions, where applicable)
Operating revenues $ 41.1 $ 39.8 $ 85.4 $ 86.8
Operating expenses:
Fuel and purchased power 14.5 16.4 30.7 33.1
Operation and maintenance 14.9 14.6 28.7 29.6
Depreciation, depletion and
amortization 5.2 5.0 10.4 10.0
Taxes, other than income 2.1 2.0 4.3 4.2
36.7 38.0 74.1 76.9
Operating income $ 4.4 $ 1.8 $ 11.3 $ 9.9
Retail sales (million kWh) 554.7 505.3 1,159.2 1,126.5
Sales for resale (million kWh) 115.3 170.0 313.3 397.2
Average cost of fuel and
purchased power per kWh $ .021 $ .022 $ .020 $ .020
Three Months Ended June 30, 2005 and 2004
Electric earnings increased $1.1 million due to:
- Increased retail sales margins, largely the result of a 10
percent increase in retail sales volumes
- Increased sales for resale margins of $400,000 (after tax),
due to lower fuel costs which were partially offset by a 32 percent
decrease in sales for resale volumes
- Lower interest expense of $300,000 (after tax)
The increase in earnings was partially offset by the absence of the
favorable resolution of federal and related state income tax matters
realized in 2004 of $1.2 million (after tax), including interest.
Six Months Ended June 30, 2005 and 2004
Electric earnings increased $700,000 due to:
- Decreased operation and maintenance expense of $600,000 (after
tax)
- Higher retail sales margins, largely due to higher volumes
- Higher sales for resale margins, primarily the result of higher
average realized prices of 11 percent and lower purchased power-
related costs, offset in part by decreased sales for resale volumes
of 21 percent
- Lower net interest expense of $500,000 (after tax)
Partially offsetting the increase in earnings was the absence of the
favorable resolution of federal and related state income tax matters
realized in 2004 of $1.2 million (after tax), including interest.
Natural Gas Distribution
Three Months Six Months
Ended Ended
June 30, June 30,
2005 2004 2005 2004
(Dollars in millions, where applicable)
Operating revenues:
Sales $ 53.6 $ 46.5 $ 197.3 $ 173.5
Transportation and other 1.1 1.0 2.4 2.3
54.7 47.5 199.7 175.8
Operating expenses:
Purchased natural gas sold 41.6 35.4 162.1 141.0
Operation and maintenance 11.3 11.3 23.2 25.1
Depreciation, depletion and
amortization 2.3 2.3 4.8 4.7
Taxes, other than income 1.4 1.4 3.0 2.9
56.6 50.4 193.1 173.7
Operating income (loss) $ (1.9) $ (2.9) $ 6.6 $ 2.1
Volumes (MMdk):
Sales 5.3 5.4 21.2 21.7
Transportation 3.0 2.6 6.9 6.5
Total throughput 8.3 8.0 28.1 28.2
Degree days (% of normal)* 92% 98% 93% 96%
Average cost of natural gas,
including transportation
thereon, per dk $ 7.82 $ 6.58 $ 7.66 $ 6.49
_____________________
* Degree days are a measure of the daily temperature-related demand
for energy for heating.
Three Months Ended June 30, 2005 and 2004
The natural gas distribution business experienced a seasonal loss of
$1.3 million in the second quarter compared to a loss of $1.1
million in the second quarter of 2004. The decrease in earnings of
$200,000 was largely due to:
- The absence of the favorable resolution of federal and related
state income tax matters realized in 2004 of $1.1 million (after
tax), including interest, partially offset by
- Higher retail sales margins, primarily due to rate increases
effective in North Dakota, Minnesota, South Dakota and Montana
Six Months Ended June 30, 2005 and 2004
The natural gas distribution business experienced an increase in
earnings of $2.3 million due to:
- Higher average realized rates, largely as a result of rate
increases in North Dakota, Minnesota, South Dakota and Montana
- Decreased operation and maintenance expenses of $1.2 million
(after tax)
The increase was partially offset by the absence of the favorable
resolution of federal and related state income tax matters realized
in 2004 of $1.1 million (after tax), including interest.
Utility Services
Three Months Six Months
Ended Ended
June 30, June 30,
2005 2004 2005 2004
(In millions)
Operating revenues $ 136.9 $ 97.2 $ 250.8 $ 197.5
Operating expenses:
Operation and maintenance 122.6 93.5 223.7 188.9
Depreciation, depletion
and amortization 3.1 2.5 5.9 5.2
Taxes, other than income 4.3 3.7 10.1 8.5
130.0 99.7 239.7 202.6
Operating income (loss) $ 6.9 $ (2.5) $ 11.1 $ (5.1)
Three Months Ended June 30, 2005 and 2004
Utility services realized $3.7 million in earnings for the second
quarter compared to a $2.3 million loss in the comparable prior
period. The increase is due to:
- Increased outside electrical line construction workloads and
margins
- Higher inside electrical workloads and margins
- Higher equipment sales and rentals
- Earnings from acquisitions made during the second quarter 2005
which contributed less than 10 percent to the increase
Six Months Ended June 30, 2005 and 2004
Utility services realized $5.6 million in earnings for the first six
months of 2005 compared to a $4.2 million loss in the comparable
prior period. The increase is due to:
- Increased outside electrical line construction workloads and
margins
- Higher inside electrical workloads and margins
- Higher equipment sales and rentals
- Lower general and administrative expenses of $600,000 (after
tax), largely lower payroll-related costs
- Earnings from businesses acquired during the second quarter
2005
Pipeline and Energy Services
Three Months Six Months
Ended Ended
June 30, June 30,
2005 2004 2005 2004
(Dollars in millions)
Operating revenues:
Pipeline $ 22.5 $ 22.7 $ 42.3 $ 45.7
Energy services 78.9 62.8 151.9 123.9
101.4 85.5 194.2 169.6
Operating expenses:
Purchased natural gas sold 71.4 59.2 136.9 116.5
Operation and maintenance 13.3 12.5 26.6 25.9
Depreciation, depletion
and amortization (1.5) 4.7 3.1 9.2
Taxes, other than income 2.0 1.9 4.1 3.8
85.2 78.3 170.7 155.4
Operating income $ 16.2 $ 7.2 $ 23.5 $ 14.2
Transportation volumes (MMdk):
Montana-Dakota 7.7 7.6 15.4 15.9
Other 19.6 20.4 33.5 34.5
27.3 28.0 48.9 50.4
Gathering volumes (MMdk) 19.7 19.8 39.7 39.3
Three Months Ended June 30, 2005 and 2004
Pipeline and energy services experienced an increase in earnings of
$4.3 million due to:
- The benefit from the resolution of a rate proceeding of $5.0
million (after tax) which included a reduction to depreciation,
depletion and amortization expense. For further information see
Note 18 of Notes to Consolidated Financial Statements.
- Higher gathering rates of $1.3 million (after tax)
Partially offsetting the increase were:
- The absence of the favorable resolution of federal and related
state income tax matters realized in 2004 of $1.6 million (after
tax), including interest
- Decreased transportation and storage rates in 2005, the result
of lower rates effective July 1, 2004
Six Months Ended June 30, 2005 and 2004
Pipeline and energy services experienced an increase in earnings of
$4.9 million due to:
- The benefit from the resolution of a rate proceeding of $5.0
million (after tax), as previously discussed
- Higher gathering rates of $2.5 million (after tax)
- Decreased operation and maintenance expenses, largely payroll-
related expenses
Partially offsetting the increase in earnings were:
- Lower transportation and storage rates in 2005 of $2.4 million
(after tax), the result of lower rates effective July 1, 2004
- The absence of the favorable resolution of federal and related
state income tax matters realized in 2004 of $1.6 million (after
tax), including interest
Natural Gas and Oil Production
Three Months Six Months
Ended Ended
June 30, June 30,
2005 2004 2005 2004
(Dollars in millions, where applicable)
Operating revenues:
Natural gas $ 80.3 $ 68.5 $ 152.8 $ 134.9
Oil 17.3 14.9 31.8 29.1
Other .1 .8 .2 1.2
97.7 84.2 184.8 165.2
Operating expenses:
Purchased natural gas sold .1 .7 .2 1.1
Operation and maintenance:
Lease operating costs 9.8 8.6 17.7 16.8
Gathering and
transportation 2.8 2.7 5.6 5.2
Other 6.4 5.9 11.9 11.9
Depreciation, depletion
and amortization 21.2 17.9 38.3 34.5
Taxes, other than income:
Production and property
taxes 7.5 5.7 13.5 10.4
Other .1 .1 .3 .3
47.9 41.6 87.5 80.2
Operating income $ 49.8 $ 42.6 $ 97.3 $ 85.0
Production:
Natural gas (MMcf) 14,627 14,796 29,054 29,302
Oil (000's of barrels) 406 450 773 907
Average realized prices
(including hedges):
Natural gas (per Mcf) $ 5.49 $ 4.63 $ 5.26 $ 4.60
Oil (per barrel) $ 42.60 $ 33.09 $ 41.21 $ 32.12
Average realized prices
(excluding hedges):
Natural gas (per Mcf) $ 5.71 $ 4.78 $ 5.37 $ 4.73
Oil (per barrel) $ 47.81 $ 35.75 $ 46.06 $ 34.03
Production costs, including
taxes, per net equivalent Mcf:
Lease operating costs $ .57 $ .49 $ .52 $ .48
Gathering and
transportation .17 .15 .17 .15
Production and property
taxes .44 .33 .40 .30
$ 1.18 $ .97 $ 1.09 $ .93
Three Months Ended June 30, 2005 and 2004
The natural gas and oil production business experienced an increase
in earnings of $3.7 million due to:
- Higher average realized natural gas prices of 19 percent
- Higher average realized oil prices of 29 percent
Partially offsetting the increase were:
- Higher depreciation, depletion and amortization expense of $2.0
million (after tax) due to higher rates, largely driven by a recent
acquisition
- Decreased oil production volumes of 10 percent, due in part to
normal production declines, offset in part by production from an
acquisition made in the second quarter of 2005
- Decreased natural gas production of 1 percent, primarily due to
normal production declines and timing-related delays affecting
coalbed natural gas drilling activity as a result of ongoing
environmental litigation, largely offset by increased production
from natural gas properties in the Rocky Mountain region and
production from an acquisition made in the second quarter of 2005
Six Months Ended June 30, 2005 and 2004
Natural gas and oil production earnings increased $7.4 million due
to:
- Higher average realized natural gas prices of 14 percent
- Higher average realized oil prices of 28 percent
Partially offsetting the increase were:
- Decreased oil production of 15 percent, primarily due to normal
production declines, offset in part by production from an
acquisition made in the second quarter of 2005
- Higher depreciation, depletion and amortization expense of $2.4
million (after tax) due to higher rates
- Lower natural gas production of 1 percent, primarily due to
normal production declines and timing-related delays affecting
coalbed natural gas drilling activity as a result of ongoing
environmental litigation, largely offset by increased production
from natural gas properties in the Rocky Mountain region and
production from an acquisition made in the second quarter of 2005
Construction Materials and Mining
Three Months Six Months
Ended Ended
June 30, June 30,
2005 2004 2005 2004
(Dollars in millions)
Operating revenues $ 394.0 $ 347.2 $ 581.1 $ 486.7
Operating expenses:
Operation and maintenance 330.0 286.6 500.5 419.7
Depreciation, depletion
and amortization 19.0 17.0 37.2 33.2
Taxes, other than income 10.5 9.6 18.4 16.1
359.5 313.2 556.1 469.0
Operating income $ 34.5 $ 34.0 $ 25.0 $ 17.7
Sales (000's):
Aggregates (tons) 11,023 11,187 16,929 15,994
Asphalt (tons) 2,139 2,346 2,500 2,648
Ready-mixed concrete
(cubic yards) 1,224 1,239 1,884 1,813
Three Months Ended June 30, 2005 and 2004
Construction materials and mining had $18.4 million in earnings for
the second quarter of 2005 compared to $20.4 million in the
comparable prior period. The $2.0 million decrease in earnings was
due to:
- The absence in 2005 of the 2004 favorable resolution of federal
and related state income tax matters of $1.2 million (after tax),
including interest
- Increased depreciation, depletion and amortization expenses of
$1.0 million (after tax) due to higher property, plant and equipment
balances
- The effects of unfavorable weather on asphalt and construction
volumes and margins
Partially offsetting the decline were increased ready-mixed concrete
margins.
Six Months Ended June 30, 2005 and 2004
Earnings at the construction materials and mining business increased
$1.4 million due to:
- Increased ready-mixed concrete volumes and margins
- Higher cement volumes
- Earnings from companies acquired since the comparable prior
period, which contributed approximately 6 percent of earnings
Partially offsetting the increase were:
- Higher depreciation, depletion and amortization expenses, the
result of higher property, plant and equipment balances
- Lower asphalt volumes and margins due largely to effects of
weather and higher fuel prices
- The absence in 2005 of the 2004 favorable resolution of federal
and related state income tax matters of $1.2 million (after tax),
including interest
Independent Power Production
Three Months Six Months
Ended Ended
June 30, June 30,
2005 2004 2005 2004
(Dollars in millions)
Operating revenues $ 13.7 $ 10.6 $ 23.5 $ 17.1
Operating expenses:
Operation and maintenance 7.3 2.8 13.7 6.8
Depreciation, depletion and
amortization 2.2 2.3 4.7 4.4
Taxes, other than income .7 1.1 1.4 1.1
10.2 6.2 19.8 12.3
Operating income $ 3.5 $ 4.4 $ 3.7 $ 4.8
Net generation capacity - kW* 279,600 279,600 279,600 279,600
Electricity produced and sold
(thousand kWh)* 90,762 84,148 128,012 115,503
_____________________
* Excludes equity method investments.
NOTE: The earnings from the Company's equity method investments are
not reflected in the above table.
Three Months Ended June 30, 2005 and 2004
Independent power production experienced an increase in earnings of
$8.5 million, largely due to:
- A $15.6 million benefit from the sale of the Termoceara
Generating Facility, partially offset by the absence in 2005 of the
2004 operating results from the Termoceara Generating Facility
- Earnings from a domestic electric-generating facility acquired
since the comparable prior period
Six Months Ended June 30, 2005 and 2004
Independent power production experienced an increase in earnings of
$5.9 million, largely due to:
- A $15.6 million benefit from the sale of the Termoceara
Generating Facility, partially offset by the absence in 2005 of the
2004 operating results from the Termoceara Generating Facility
- Earnings from equity method investments acquired since the
comparable prior period
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:
Three Months Six Months
Ended Ended
June 30, June 30,
2005 2004 2005 2004
(In millions)
Other:
Operating revenues $ 1.4 $ 1.0 $ 2.7 $ 1.8
Operation and maintenance 1.2 .8 2.4 1.5
Depreciation, depletion and
amortization .1 .1 .1 .1
Taxes, other than income --- --- .1 ---
Intersegment transactions:
Operating revenues $ 70.7 $ 59.7 $ 147.7 $ 131.7
Purchased natural gas sold 66.4 55.8 139.0 124.3
Operation and maintenance 4.3 3.9 8.7 7.4
For further information on intersegment eliminations, see Note 15
of Notes to Consolidated Financial Statements.
RISK FACTORS AND CAUTIONARY STATEMENTS THAT MAY AFFECT FUTURE
RESULTS
The Company is including the following factors and cautionary
statements in this Form 10-Q to make applicable and to take
advantage of the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf of, the Company. Forward-looking statements
include statements concerning plans, objectives, goals, strategies,
future events or performance, and underlying assumptions (many of
which are based, in turn, upon further assumptions) and other
statements that are other than statements of historical facts. From
time to time, the Company may publish or otherwise make available
forward-looking statements of this nature, including statements
contained within Prospective Information. All these subsequent
forward-looking statements, whether written or oral and whether made
by or on behalf of the Company, are also expressly qualified by
these factors and cautionary statements.
Forward-looking statements involve risks and uncertainties, which
could cause actual results or outcomes to differ materially from
those expressed. The Company's expectations, beliefs and
projections are expressed in good faith and are believed by the
Company to have a reasonable basis, including without limitation,
management's examination of historical operating trends, data
contained in the Company's records and other data available from
third parties. Nonetheless, the Company's expectations, beliefs or
projections may not be achieved or accomplished.
Any forward-looking statement contained in this document speaks only
as of the date on which the statement is made, and the Company
undertakes no obligation to update any forward-looking statement or
statements to reflect events or circumstances that occur after the
date on which the statement is made or to reflect the occurrence of
unanticipated events. New factors emerge from time to time, and it
is not possible for management to predict all of the factors, nor
can it assess the effect of each factor on the Company's business or
the extent to which any factor, or combination of factors, may cause
actual results to differ materially from those contained in any
forward-looking statement.
Following are some specific factors that should be considered for a
better understanding of the Company's financial condition. These
factors and the other matters discussed herein are important factors
that could cause actual results or outcomes for the Company to
differ materially from those discussed in the forward-looking
statements included elsewhere in this document.
Economic Risks
The Company's natural gas and oil production and pipeline and energy
services businesses are dependent on factors, including commodity
prices and commodity price basis differentials, which cannot be
predicted or controlled.
These factors include: price fluctuations in natural gas and crude
oil prices; fluctuations in commodity price basis differentials;
availability of economic supplies of natural gas; drilling successes
in natural gas and oil operations; the timely receipt of necessary
permits and approvals; the ability to contract for or to secure
necessary drilling rig contracts and to retain employees to drill
for and develop reserves; the ability to acquire natural gas and oil
properties; and other risks incidental to the operations of natural
gas and oil wells. Significant changes in these factors could
negatively affect the results of operations and financial condition
of the Company's natural gas and oil production and pipeline and
energy services businesses.
The construction and operation of power generation facilities may
involve unanticipated changes or delays that could negatively impact
the Company's business and its results of operations.
The construction and operation of power generation facilities
involves many risks, including start-up risks, breakdown or failure
of equipment, competition, inability to obtain required governmental
permits and approvals, and inability to negotiate acceptable
acquisition, construction, fuel supply, off-take, transmission or
other material agreements, as well as the risk of performance below
expected levels of output or efficiency. Such unanticipated events
could negatively impact the Company's business and its results of
operations.
The Company's utility services business operates in highly
competitive markets characterized by low margins in a number of
service lines and geographic areas.
This business' ability to continue its return to profitability on a
sustained basis will depend upon improved capital spending for
electric construction services and continuing success in
management's ability to refocus the business on more profitable
markets, reduce operating costs and implement process improvements
in project management.
Economic volatility affects the Company's operations as well as the
demand for its products and services and, as a result, may have a
negative impact on the Company's future revenues.
The global demand for natural resources, interest rates,
governmental budget constraints, and the ongoing threat of terrorism
can create volatility in the financial markets. A soft economy
could negatively affect the level of public and private expenditures
on projects and the timing of these projects which, in turn, would
negatively affect the demand for the Company's products and
services.
The Company relies on financing sources and capital markets. If the
Company is unable to obtain financing in the future, the Company's
ability to execute its business plans, make capital expenditures or
pursue acquisitions that the Company may otherwise rely on for
future growth could be impaired.
The Company relies on access to both short-term borrowings,
including the issuance of commercial paper, and long-term capital
markets as a source of liquidity for capital requirements not
satisfied by its cash flow from operations. If the Company is not
able to access capital at competitive rates, the ability to
implement its business plans may be adversely affected. Market
disruptions or a downgrade of the Company's credit ratings may
increase the cost of borrowing or adversely affect its ability to
access one or more financial markets. Such disruptions could
include:
- A severe prolonged economic downturn
- The bankruptcy of unrelated industry leaders in the same line
of business
- A deterioration in capital market conditions
- Volatility in commodity prices
- Terrorist attacks
- Fluctuations in the value of the dollar on currency exchanges
Environmental and Regulatory Risks
Some of the Company's operations are subject to extensive
environmental laws and regulations that may increase costs of
operations, impact or limit business plans, or expose the Company to
environmental liabilities.
The Company is subject to extensive environmental laws and
regulations affecting many aspects of its present and future
operations including air quality, water quality, waste management
and other environmental considerations. These laws and regulations
can result in increased capital, operating and other costs, and
delays as a result of ongoing litigation and compliance,
remediation, containment and monitoring obligations, particularly
with regard to laws relating to power plant emissions and coalbed
natural gas development. These laws and regulations generally
require the Company to obtain and comply with a wide variety of
environmental licenses, permits, inspections and other approvals.
Public officials and entities, as well as private individuals and
organizations, may seek injunctive relief or other remedies to
enforce applicable environmental laws and regulations. The Company
cannot predict the outcome (financial or operational) of any related
litigation that may arise.
Existing environmental regulations may be revised and new
regulations seeking to protect the environment may be adopted or
become applicable to the Company. Revised or additional
regulations, which result in increased compliance costs or
additional operating restrictions, particularly if those costs are
not fully recoverable from customers, could have a material effect
on the Company's results of operations.
One of the Company's subsidiaries is subject to litigation in
connection with its coalbed natural gas development activities.
These proceedings have caused delays in coalbed natural gas drilling
activity in 2005, and the ultimate outcome of the actions could have
a material effect on existing coalbed natural gas operations and/or
the future development of its coalbed natural gas properties.
Fidelity has been named as a defendant in, and/or certain of its
operations are the subject of, a number of lawsuits filed in
connection with its coalbed natural gas development in the Powder
River Basin in Montana and Wyoming. Injunctive orders issued by the
Ninth Circuit and the Montana Federal District Court have occasioned
reductions in Fidelity's estimated total 2005 natural gas production
levels. If the plaintiffs are successful in these lawsuits, the
ultimate outcome of the actions could have a material effect on
Fidelity's existing coalbed natural gas operations and/or the future
development of its coalbed natural gas properties.
The Company is subject to extensive government regulations that may
delay and/or have a negative impact on its business and its results
of operations.
The Company is subject to regulation by federal, state and local
regulatory agencies with respect to, among other things, allowed
rates of return, financings, industry rate structures, and recovery
of purchased power and purchased gas costs. These governmental
regulations significantly influence the Company's operating
environment and may affect its ability to recover costs from its
customers. The Company is unable to predict the impact on operating
results from the future regulatory activities of any of these
agencies.
Changes in regulations or the imposition of additional regulations
could have an adverse impact on the Company's results of operations.
Risks Relating to Foreign Operations
The value of the Company's investments in foreign operations may
diminish due to political, regulatory and economic conditions in
countries where the Company does business.
The Company is subject to political, regulatory and economic
conditions in foreign countries where the Company does business.
Significant changes in the political, regulatory or economic
environment in these countries could negatively affect the value of
the Company's investments located in these countries.
Other Risks
Competition is increasing in all of the Company's businesses.
All of the Company's businesses are subject to increased
competition. The independent power production industry includes
many strong and capable competitors, some of which have greater
resources and more experience in the operation, acquisition and
development of power generation facilities. Utility services'
competition is based primarily on price and reputation for quality,
safety and reliability. The construction materials products are
marketed under highly competitive conditions and are subject to such
competitive forces as price, service, delivery time and proximity to
the customer. The electric utility and natural gas industries are
also experiencing increased competitive pressures as a result of
consumer demands, technological advances, deregulation, greater
availability of natural gas-fired generation and other factors.
Pipeline and energy services competes with several pipelines for
access to natural gas supplies and gathering, transportation and
storage business. The natural gas and oil production business is
subject to competition in the acquisition and development of natural
gas and oil properties as well as in the sale of its production
output. The increase in competition could negatively affect the
Company's results of operations and financial condition.
Weather conditions can adversely affect the Company's operations and
revenues.
The Company's results of operations can be affected by changes in
the weather. Weather conditions directly influence the demand for
electricity and natural gas, affect the wind-powered operation at
the independent power production business, affect the price of
energy commodities, affect the ability to perform services at the
utility services and construction materials and mining businesses
and affect ongoing operation and maintenance and construction and
drilling activities for the pipeline and energy services and natural
gas and oil production businesses. In addition, severe weather can
be destructive, causing outages, reduced natural gas and oil
production, and/or property damage, which could require additional
costs to be incurred. As a result, adverse weather conditions could
negatively affect the Company's results of operations and financial
condition.
PROSPECTIVE INFORMATION
The following information includes highlights of the key growth
strategies, projections and certain assumptions for the Company and
its subsidiaries and other matters for each 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 increases in revenues and
earnings, will in fact be achieved. Reference is made to
assumptions contained in this section, as well as the various
important factors listed under the heading Risk Factors and
Cautionary Statements that May Affect Future Results, and other
factors that are listed in the Introduction. Changes in such
assumptions and factors could cause actual future results to differ
materially from targeted growth, revenue and earnings projections.
MDU Resources Group, Inc.
- Earnings per common share for 2005, diluted, are projected in
the range of $1.90 to $2.10, an increase from prior guidance of
$1.80 to $2.00.
- The Company expects the percentage of 2005 earnings per common
share, diluted, by quarter to be in the following approximate
ranges:
- Third quarter - 30 percent to 35 percent
- Fourth quarter - 18 percent to 23 percent
- The Company's long-term compound annual growth goals on
earnings per share from operations are in the range of 7 percent to
10 percent.
- The Company anticipates investing approximately $700 million in
capital expenditures during 2005.
Electric
- The expected earnings in 2005 are anticipated to be slightly
lower than 2004.
- This segment is involved in the review of potential power
projects to replace capacity associated with expiring purchased
power contracts and to provide for future growth. Those projects
include participation in a proposed 600-megawatt (MW) coal-fired
facility to be located in northeastern South Dakota and construction
of a 175-MW lignite coal-fired facility (Vision 21) to be located in
southwestern North Dakota. The costs of building and/or acquiring
the additional generating capacity needed by the utility are
expected to be recovered in rates.
- Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct its electric operations in all
of the municipalities it serves where such franchises are required.
Montana-Dakota intends to protect its service area and seek renewal
of all expiring franchises.
- On October 25, 2004, Montana-Dakota issued a request for
proposal for 70 megawatts to 100 megawatts of firm capacity and
associated energy for the period of November 1, 2006 through
December 31, 2010. Montana-Dakota is currently in the process of
evaluating the responses. A decision is expected to be made late
2005.
Natural gas distribution
- The expected earnings for this segment for 2005 are projected
to be significantly higher than the earnings for 2004.
- In September 2004, a natural gas rate case was filed with the
MPUC requesting an increase of $1.4 million annually, or 4.0
percent. An interim increase of $1.4 million annually was approved
by the MPUC effective January 10, 2005, subject to refund. A final
order is expected in early 2006.
- In March 2005, a natural gas rate case was filed with the SDPUC
for the East River service area requesting an increase of $850,000
annually, or 12.8 percent. A final order is expected in late 2005.
- Montana-Dakota and Great Plains have obtained and hold valid
and existing franchises authorizing them to conduct their natural
gas operations in all of the municipalities they serve where such
franchises are required. Montana-Dakota and Great Plains intend to
protect their service areas and seek renewal of all expiring
franchises.
Utility services
- Revenues are expected to be in the range of $550 million to
$600 million in 2005.
- The Company anticipates margins to increase substantially in
2005 as compared to 2004 levels.
- Work backlog as of June 30, 2005, was approximately $358
million, compared to $217 million at June 30, 2004.
Pipeline and energy services
- In 2005, total natural gas gathering and transportation
throughput is expected to be down approximately 5 percent from the
record levels achieved in 2004.
- Firm capacity for the Grasslands Pipeline is currently 90,000
Mcf per day with expansion possible to 200,000 Mcf per day.
- The labor contract that Williston Basin was negotiating, as
reported in Items 1 and 2 - Business and Properties - General in the
Company's 2004 Annual Report, remains in negotiations.
Natural gas and oil production
- The Company is expecting to drill approximately 300 wells in
2005.
- In 2005, the Company expects combined natural gas and oil
production to approximate the record levels achieved in 2004,
assuming continued production from existing wells at its Badger
Hills Project in southeastern Montana. The Badger Hills Project has
been the subject of two related actions filed in the Montana Federal
District Court, in connection with which the Montana Federal
District Court issued orders enjoining operations on the project.
Subsequently, the Montana Federal District Court issued temporary
stays of the injunction orders in these cases, thereby permitting
continued production at the project pending further developments in
the cases. Currently, this segment's net combined natural gas and
oil production is approximately 200,000 Mcf equivalent to 210,000
Mcf equivalent per day.
- Estimates of natural gas prices in the Rocky Mountain region
for August through December 2005 reflected in earnings guidance are
in the range of $4.75 to $5.25 per Mcf. The Company's estimates for
natural gas prices on the NYMEX for August through December 2005
reflected in earnings guidance are in the range of $5.75 to $6.25
per Mcf. During 2004, more than three-fourths of this segment's
natural gas production was priced using Rocky Mountain or other non-
NYMEX prices.
- Estimates of NYMEX crude oil prices for July through December
2005 reflected in earnings guidance are in the range of $45 to $50
per barrel.
- The Company has hedged a portion of its natural gas and oil
production. The hedges that are in place as of July 20, 2005, for
production in the last six months of 2005 and the twelve months of
2006 are summarized below:
Commodity Index* Period Forward Price Swap or
Outstanding Notional Costless
Volume Collar
(MMBtu)/(Bbl) Floor-Ceiling
(Per MMBtu/Bbl)
Natural Gas Ventura 7/05 - 12/05 920,000 $5.00
Natural Gas Ventura 7/05 - 12/05 920,000 $4.75-$5.25
Natural Gas Ventura 7/05 - 12/05 1,840,000 $5.41-$6.80
Natural Gas Ventura 7/05 - 12/05 1,840,000 $5.00-$5.865
Natural Gas CIG 7/05 - 12/05 1,840,000 $5.25-$6.47
Natural Gas Ventura 7/05 - 12/05 920,000 $5.15
Natural Gas NYMEX 7/05 - 12/05 920,000 $6.50-$8.70
Natural Gas Ventura 7/05 - 12/05 1,840,000 $5.56
Natural Gas Ventura 7/05 - 12/05 920,000 $5.50-$7.18
Natural Gas CIG 11/05 - 12/05 549,000 $7.0500
Natural Gas NYMEX 8/05 - 12/05 1,530,000 $7.50-$8.40
Natural Gas Ventura 1/06 - 12/06 1,825,000 $6.00-$7.60
Natural Gas Ventura 1/06 - 12/06 3,650,000 $6.6550
Natural Gas CIG 1/06 - 03/06 900,000 $7.1600
Natural Gas CIG 1/06 - 03/06 810,000 $7.0500
Natural Gas Ventura 1/06 - 12/06 1,825,000 $6.75-$7.71
Natural Gas Ventura 1/06 - 12/06 1,825,000 $6.75-$7.77
Natural Gas Ventura 1/06 - 12/06 1,825,000 $7.00-$8.85
Natural Gas NYMEX 1/06 - 12/06 1,825,000 $7.75-$8.50
Natural Gas Ventura 1/06 - 12/06 1,825,000 $7.76
Natural Gas CIG 4/06 - 12/06 1,375,000 $6.50-$6.98
Crude Oil NYMEX 7/05 - 12/05 82,800 $32.00-$36.50
Crude Oil NYMEX 7/05 - 12/05 92,000 $43.00-$52.05
Crude Oil NYMEX 7/05 - 12/05 63,770 $39.00-$47.20
Crude Oil NYMEX 7/05 - 12/05 92,000 $30.70
Crude Oil NYMEX 1/06 - 12/06 182,500 $43.00-$54.15
* 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.
Construction materials and mining
- The Company anticipates improved earnings in 2005 as compared
to 2004 with an expected return to normal weather conditions in
Texas, improved construction volumes and margins and earnings from
acquisitions.
- Aggregate, asphalt and ready-mixed concrete volumes in 2005 are
expected to be comparable to 2004 levels.
- Revenues in 2005 are expected to be approximately 5 percent to
10 percent higher than 2004 levels.
- The Company expects that the replacement funding legislation
for the Transportation Equity Act for the 21st Century (TEA-21) will
be equal to or higher than previous funding levels.
- Work backlog as of June 30, 2005, was approximately $740
million, compared to $545 million at June 30, 2004.
- The labor contract that Knife River was negotiating, as
reported in Items 1 and 2 - Business and Properties - General in the
Company's 2004 Annual Report, has been ratified.
Independent power production
- Earnings for 2005 are expected to be somewhat lower than 2004
earnings primarily due to benefits realized in 2004 from foreign
currency gains and the effects of the embedded derivative in the
Brazilian electric power sales contract, as well as the absence of
ongoing earnings resulting from the Termoceara Generating Facility
sale.
- The Company is constructing a 116-MW coal-fired electric
generating facility near Hardin, Montana. A power sales agreement
with Powerex Corp., a subsidiary of BC Hydro, has been secured for
the entire output of the plant for a term expiring October 31, 2008,
with the purchaser having an option for a two-year extension. The
projected on-line date for this plant is late 2005.
NEW ACCOUNTING STANDARDS
SAB No. 106
In September 2004, the SEC issued SAB No. 106 which is an
interpretation regarding the application of SFAS No. 143 by oil and
gas producing companies following the full-cost accounting method.
SAB No. 106 was effective for the Company as of January 1, 2005.
The adoption of SAB No. 106 did not have a material effect on the
Company's financial position or results of operations.
SFAS No. 123 (revised)
In December 2004, the FASB issued SFAS No. 123 (revised). SFAS No.
123 (revised) revises SFAS No. 123 and requires entities to
recognize compensation expense in an amount equal to the fair value
of share-based payments granted to employees. SFAS No. 123
(revised) requires a company to record compensation expense for all
awards granted after the date of adoption of SFAS No. 123 (revised)
and for the unvested portion of previously granted awards that
remain outstanding at the date of adoption. SFAS No. 123 (revised)
is effective for the Company on January 1, 2006. The Company is
evaluating the effects of the adoption of SFAS No. 123 (revised).
FIN 47
In March 2005, the FASB issued FIN 47. FIN 47 addresses the diverse
accounting practices that developed with respect to the timing of
liability recognition for legal obligations associated with the
retirement of a tangible long-lived asset when the timing and/or
method of settlement of the obligation are conditional on a future
event. FIN 47 is effective for the Company at the end of the fiscal
year ending December 31, 2005. The Company is evaluating the
effects of the adoption of FIN 47.
EITF No. 04-6
In March 2005, the FASB ratified EITF No. 04-6. EITF No. 04-6
requires that post-production stripping costs be treated as a
variable inventory production cost. EITF No. 04-6 is effective
for the Company on January 1, 2006. The Company is evaluating the
effects of the adoption of EITF No. 04-6.
For further information on SAB No. 106, SFAS No. 123 (revised), FIN
47 and EITF No. 04-6, see Note 10 of Notes to Consolidated Financial
Statements.
CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES
The Company's critical accounting policies involving significant
estimates include impairment testing of long-lived assets and
intangibles, impairment testing of natural gas and oil production
properties, revenue recognition, purchase accounting, asset
retirement obligations, and pension and other postretirement
benefits. There were no material changes in the Company's critical
accounting policies involving significant estimates from those
reported in the 2004 Annual Report. For more information on
critical accounting policies involving significant estimates, see
Part II, Item 7 in the 2004 Annual Report.
LIQUIDITY AND CAPITAL COMMITMENTS
Cash flows
Operating activities
Cash flows provided by operating activities in the first six months
of 2005 decreased by $9.0 million from the comparable 2004 period,
largely the result of a decrease in working capital of $43.8 million
due in part to increased income tax payments. Partially offsetting
the decrease was an increase in net income of $32.4 million.
Investing activities
Cash flows used in investing activities in the first six months of
2005 increased $212.6 million compared to the comparable 2004
period, primarily due to an increase in net capital expenditures
(capital expenditures; acquisitions, net of cash acquired; and net
proceeds from the sale or disposition of property) of $214.0 million
due largely to acquisitions in the second quarter of 2005, the
construction of a 116-megawatt coal-fired electric generating
facility near Hardin, Montana and higher ongoing capital
expenditures. Net capital expenditures exclude the noncash
transactions related to acquisitions, including the issuance of the
Company's equity securities. The noncash transactions were $30.6
million and $32.6 million for the six months ended June 30, 2005 and
2004, respectively.
Financing activities
Cash flows provided by financing activities in the first six months
of 2005 increased by $133.8 million compared to the comparable 2004
period, largely the result of an increase in the issuance of long-
term debt due in part to acquisitions in the second quarter of 2005
and the construction of a 116-megawatt coal-fired electric
generating facility near Hardin, Montana. The increase was
partially offset by an increase in the repayment of long-term debt
of $81.5 million, partially due to the redemption of $20.9 million
in Pollution Control Refunding Revenue bonds, and a $50.8 million
decrease in the issuance of common stock as the result of proceeds
received from an underwritten public offering in 2004.
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, 2004, certain Pension Plans' accumulated benefit
obligations exceeded these plans' assets by approximately
$3.7 million. Pretax pension expense (income) reflected in the
years ended December 31, 2004, 2003 and 2002, was $4.1 million,
$153,000, and ($2.4) million, respectively. The Company's pension
expense is currently projected to be approximately $6.5 million to
$7.5 million in 2005. A reduction in the Company's assumed discount
rate for Pension Plans along with declines in the equity markets
experienced in 2002 and 2001 have combined to largely produce the
increase in these costs. Funding for the Pension Plans is
actuarially determined. The minimum required contributions for
2004, 2003 and 2002 were approximately $1.2 million, $1.6 million,
and $1.2 million, respectively.
For further information on the Company's Pension Plans, see Note 17
of Notes to Consolidated Financial Statements.
Capital expenditures
Net capital expenditures for the first six months of 2005 were
$398.4 million. Net capital expenditures, including the issuance of
the Company's equity securities in connection with acquisitions, are
estimated to be approximately $700 million for the year 2005.
Estimated capital expenditures include those for:
- Potential future acquisitions
- System upgrades
- Routine replacements
- Service extensions
- Routine equipment maintenance and replacements
- Buildings, land and building improvements
- Pipeline and gathering expansion projects
- Further enhancement of natural gas and oil production and
reserve growth
- Power generation opportunities, including certain costs for
additional electric generating capacity and for a 116-megawatt coal-
fired development project, as previously discussed
- Other growth opportunities
Approximately 31 percent of estimated 2005 net capital expenditures
are associated with completed and potential future acquisitions.
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 estimated 2005 capital
expenditures referred to previously. It is anticipated that all of
the funds required for capital expenditures will be met from various
sources, including internally generated funds; commercial paper
credit facilities at Centennial and MDU Resources Group, Inc., 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, all
of which the Company and its subsidiaries were in compliance with at
June 30, 2005.
MDU Resources Group, Inc.
The Company has a revolving credit agreement with various banks
totaling $100 million (with provision for an increase, at the option
of the Company on stated conditions, up to a maximum of $125
million) at June 30, 2005. There were no amounts outstanding under
the credit agreement at June 30, 2005. The credit agreement
supports the Company's $75 million commercial paper program. There
were no amounts outstanding under the Company's commercial paper
program at June 30, 2005. The commercial paper borrowings
classified as long-term debt are intended to be refinanced on a long-
term basis through continued MDU Resources commercial paper
borrowings and as further supported by the credit agreement, which
expires in June 2010.
The Company's goal is to maintain acceptable credit ratings in order
to access the capital markets through the issuance of commercial
paper. If the Company were to experience a minor downgrade of its
credit ratings, it would not anticipate any change in its ability to
access the capital markets. However, in such event, the Company
would expect a nominal basis point increase in overall interest
rates with respect to its cost of borrowings. If the Company were
to experience a significant downgrade of its credit ratings, which
it does not currently anticipate, it may need to borrow under its
credit agreement.
To the extent the Company needs to borrow under its credit
agreement, it would be expected to incur increased annualized
interest expense on its variable rate debt. This was not applicable
at June 30, 2005, as there were no variable rate borrowings.
Prior to the maturity of the credit agreement, the Company plans to
negotiate the extension or replacement of this agreement, which
provides credit support to access the capital markets. In the event
the Company is unable to successfully negotiate the credit
agreement, or in the event the fees on this facility became too
expensive, which it does not currently anticipate, the Company would
seek alternative funding. One source of alternative funding might
involve the securitization of certain Company assets.
In order to borrow under the Company's credit agreement, the Company
must be in compliance with the applicable covenants and certain
other conditions, including covenants 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 twelve-month period ended each fiscal
quarter, to be less than 2.5 to 1. Other covenants include
limitation on sale of assets and limitation on investments. The
Company was in compliance with these covenants and met the required
conditions at June 30, 2005. In the event the Company does not
comply with the applicable covenants and other conditions,
alternative sources of funding may need to be pursued, as previously
described.
There are no credit facilities that contain cross-default provisions
between the Company and any of its subsidiaries.
The Company's issuance of first mortgage debt is subject to certain
restrictions imposed under the terms and conditions of its Indenture
of Mortgage. Generally, those restrictions require the Company to
fund $1.43 of unfunded property or use $1.00 of refunded bonds for
each dollar of indebtedness incurred under the Indenture and, in
some cases, to certify to the trustee that annual earnings (pretax
and before interest charges), as defined in the Indenture, equal at
least two times its annualized first mortgage bond interest costs.
Under the more restrictive of the tests, as of June 30, 2005, the
Company could have issued approximately $350 million of additional
first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 5.4 times and 4.7 times for the twelve months ended
June 30, 2005, and December 31, 2004, respectively. Additionally,
the Company's first mortgage bond interest coverage was 9.3 times
and 7.1 times for the twelve months ended June 30, 2005, and
December 31, 2004, respectively. Common stockholders' equity as a
percent of total capitalization (net of long-term debt due within
one year) was 61 percent and 65 percent at June 30, 2005, and
December 31, 2004, respectively.
Centennial Energy Holdings, Inc.
Centennial has three revolving credit agreements with various banks
and institutions that support $331.4 million of Centennial's
$350 million commercial paper program. There were no outstanding
borrowings under the Centennial credit agreements at June 30, 2005.
Under the Centennial commercial paper program, $300.8 million was
outstanding at June 30, 2005. 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 and as further supported by
the Centennial credit agreements. One of these credit agreements is
for $300 million and expires on August 17, 2007, and another
agreement is for $21.4 million (previously $25 million) and expires
on April 30, 2007. Pursuant to this credit agreement, on the last
business day of April 2006, the line of credit will be reduced by
$3.6 million. Centennial intends to negotiate the extension or
replacement of these agreements prior to their maturities, and is
currently in the process of negotiating the extension of the $300
million credit facility. The third agreement is an uncommitted line
for $10 million, which was effective on January 25, 2005, and may be
terminated by the bank at any time.
Centennial has an uncommitted long-term master shelf agreement
that allows for borrowings of up to $450 million. Under the terms
of the master shelf agreement, $388 million was outstanding at
June 30, 2005. The ability to request additional borrowings under
this master shelf agreement will expire in April 2008. To meet
potential future financing needs, Centennial may pursue other
financing arrangements, including private and/or public financing.
Centennial's goal is to maintain acceptable credit ratings in order
to access the capital markets through the issuance of commercial
paper. If Centennial were to experience a minor downgrade of its
credit ratings, it would not anticipate any change in its ability to
access the capital markets. However, in such event, Centennial
would expect a nominal basis point increase in overall interest
rates with respect to its cost of borrowings. If Centennial were to
experience a significant downgrade of its credit ratings, which it
does not currently anticipate, it may need to borrow under its
committed bank lines.
To the extent Centennial needs to borrow under its committed bank
lines, it would be expected to incur increased annualized interest
expense on its variable rate debt of approximately $451,000 (after
tax) based on June 30, 2005, variable rate borrowings. Based on
Centennial's overall interest rate exposure at June 30, 2005, this
change would not have a material effect on the Company's results of
operations or cash flows.
Prior to the maturity of the Centennial credit agreements,
Centennial plans to negotiate the extension or replacement of these
agreements, which provide credit support to access the capital
markets. In the event Centennial was unable to successfully
negotiate these agreements, or in the event the fees on such
facilities became too expensive, which Centennial does not currently
anticipate, it would seek alternative funding. One source of
alternative funding might involve the securitization of certain
Centennial assets.
In order to borrow under Centennial's credit agreements and the
Centennial uncommitted long-term master shelf agreement, Centennial
and certain of its subsidiaries must be in compliance with the
applicable covenants and certain other conditions including,
covenants not to permit, as of the end of any fiscal quarter, the
ratio of total debt to total capitalization to be greater than 60
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, for the twelve-month period ended
each fiscal quarter, to be less than 2.25 to 1 (for the credit
agreements) and 1.75 to 1 (for the master shelf agreement). Other
covenants include minimum consolidated net worth, limitation on
priority debt, limitation on sale of assets and limitation on loans
and investments. Centennial and such subsidiaries were in
compliance with these covenants and met the required conditions at
June 30, 2005. In the event Centennial or such subsidiaries do not
comply with the applicable covenants and other conditions,
alternative sources of funding may need to be pursued as previously
described.
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 practice limit
the amount of subsidiary indebtedness.
Williston Basin Interstate Pipeline Company
Williston Basin has an uncommitted long-term master shelf agreement
that allows for borrowings of up to $100 million. Under the terms
of the master shelf agreement, $55.0 million was outstanding at June
30, 2005. The ability to request additional borrowings under this
master shelf agreement expires on December 20, 2005.
In order to borrow under Williston Basin's uncommitted long-term
master shelf agreement, it must be in compliance with the applicable
covenants and certain other conditions including, covenants 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, limitation on sale of
assets and limitation on investments. Williston Basin was in
compliance with these covenants and met the required conditions at
June 30, 2005. In the event Williston Basin does not comply with the
applicable covenants and other conditions, alternative sources of
funding may need to be pursued.
Off balance sheet arrangements
Centennial had unconditionally guaranteed a portion of certain bank
borrowings of MPX in connection with the Company's equity method
investment in the Termoceara Generating Facility, as discussed in
Note 12. The Company, through an indirect wholly owned subsidiary,
owned 49 percent of MPX. The guarantee to MPX's creditors expired
on July 25, 2005, as the outstanding bank borrowings were repaid on
that date. At June 30, 2005, the aggregate amount of borrowings
outstanding subject to these guarantees was $29.6 million.
As of June 30, 2005, Centennial was contingently liable for the
performance of certain of its subsidiaries under approximately $614
million of surety bonds. These bonds are principally for
construction contracts and reclamation obligations of these
subsidiaries entered into in the normal course of business.
Centennial indemnifies the respective surety bond companies against
any exposure under the bonds. The purpose of Centennial's
indemnification is to allow the subsidiaries to obtain bonding at
competitive rates. In the event a subsidiary of the Company does
not fulfill its obligations in relation to its bonded contract or
obligation, Centennial may be required to make payments under its
indemnification. A large portion of these contingent commitments 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. The surety bonds were not reflected on the
Consolidated Balance Sheets.
Contractual obligations and commercial commitments
There are no material changes in the Company's contractual
obligations relating to operating leases and purchase commitments
from those reported in the 2004 Annual Report.
The Company's long-term debt at June 30, 2005, increased $201.1
million or 21 percent from December 31, 2004 due in part to
acquisitions in the second quarter of 2005 and the construction of a
116-megawatt coal-fired electric generating facility near Hardin,
Montana. At June 30, 2005, the Company's long-term debt and
estimated interest payments (for the twelve months ended June 30, of
each year listed in the table below) were as follows:
2006 2007 2008 2009 2010 Thereafter Total
(In millions)
Long-term debt $26.9 $482.8 $131.3 $86.3 $36.8 $382.5 $1,146.6
Estimated interest
payments* 60.3 46.8 36.6 29.1 25.1 103.7 301.6
$87.2 $529.6 $167.9 $115.4 $61.9 $486.2 $1,448.2
*Estimated interest payments are calculated based on the
applicable rates and payment dates.
For more information on contractual obligations and commercial
commitments, see Part II, Item 7 in the 2004 Annual Report.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to the impact of market fluctuations
associated with commodity prices and interest rates. The Company
has policies and procedures to assist in controlling these market
risks and utilizes derivatives to manage a portion of its risk.
Commodity price risk
Fidelity utilizes natural gas and oil price swap and collar
agreements to manage a portion of the market risk associated with
fluctuations in the price of natural gas and oil on its forecasted
sales of natural gas and oil production. For more information on
commodity price risk, see Part II, Item 7A in the 2004 Annual
Report, and Notes 11 and 14 of Notes to Consolidated Financial
Statements.
The following table summarizes hedge agreements entered into by
Fidelity as of June 30, 2005. These agreements call for Fidelity to
receive fixed prices and pay variable prices.
(Notional amount and fair value in thousands)
Weighted Forward
Average Notional
Fixed Price Volume
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas swap
agreements maturing
in 2005 $ 5.54 4,229 $ (5,908)
Natural gas swap
agreements maturing
in 2006 $ 7.04 7,185 $ (4,542)
Weighted
Average Forward
Floor/Ceiling Notional
Price Volume
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar
agreements maturing
in 2005 $ 5.68/$6.88 9,810 $ (5,709)
Natural gas collar
agreements maturing
in 2006 $ 6.85/$8.09 9,125 $ (3,014)
Weighted Forward
Average Notional
Fixed Price Volume
(Per barrel) (In barrels) Fair Value
Oil swap agreement
maturing in 2005 $ 30.70 92 $ (2,523)
Weighted
Average Forward
Floor/Ceiling Notional
Price Volume
(Per barrel) (In barrels) Fair Value
Oil collar agreements
maturing in 2005 $38.11/$45.36 239 $ (3,202)
Oil collar agreement
maturing in 2006 $43.00/$54.15 183 $ (1,450)
Interest rate risk
There were no material changes to interest rate risk faced by the
Company from those reported in the 2004 Annual Report. For more
information on interest rate risk, see Part II, Item 7A in the 2004
Annual Report.
Foreign currency risk
The Company's investment, through an indirect wholly owned
subsidiary, in the Termoceara Generating Facility was sold as
discussed in Note 12 of Notes to Consolidated Financial Statements
and, as a result, the Company no longer has any material exposure to
foreign currency exchange risk.
ITEM 4. 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 Securities Exchange Act of 1934
(Exchange Act). These rules refer to the controls and other
procedures of a company that are designed to ensure that information
required to be disclosed by a company in the reports it files under
the Exchange Act is recorded, processed, summarized and reported
within required time periods. 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.
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 period covered by
this report that have materially affected, or are reasonably likely
to materially affect, the Company's internal control over financial
reporting.
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information regarding legal proceedings, see Note 19 of Notes to
Consolidated Financial Statements, which is incorporated by
reference.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Between April 1, 2005 and June 30, 2005, the Company issued
1,271,389 shares of Common Stock, $1.00 par value, and the
Preference Share Purchase Rights appurtenant thereto, as part of the
consideration paid by the Company for all of the issued and
outstanding capital stock with respect to businesses acquired during
this period. The Common Stock and Rights issued by the Company in
these transactions were issued in a private transaction exempt from
registration under the Securities Act of 1933 pursuant to Section
4(2) thereof, Rule 506 promulgated thereunder, or both. The classes
of persons to whom these securities were sold were either accredited
investors or other persons to whom such securities were permitted to
be offered under the applicable exemption.
The following table includes information with respect to the
issuer's purchase of equity securities:
ISSUER PURCHASES OF EQUITY SECURITIES
(a) (b) (c) (d)
Maximum Number (or
Total Total Number of Approximate Dollar
Number of Average Shares (or Units) Value) of Shares (or
Shares Price Purchased as Part Units) that May Yet
(or Units) Paid of Publicly Be Purchased Under
Purchased per Share Announced Plans the Plans or
Period (or Unit) or Programs (3) Programs (3)
April 1 through
April 30, 2005 34,655(1) $26.97
May 1 through
May 31, 2005 53,625(2) $27.33
June 1 through
June 30, 2005
Total 88,280
(1) Represents 13,055 shares of common stock withheld by the Company
to pay taxes in connection with the vesting of shares granted
pursuant to a compensation plan and 21,600 shares of common stock
purchased on the open market in connection with annual stock grants
made to the Company's non-employee directors.
(2) Represents shares of common stock withheld by the Company to pay
taxes in connection with vesting of restricted shares.
(3) Not applicable. The Company does not currently have in place
any publicly announced plans or programs to purchase equity
securities.
ITEM 6. EXHIBITS
4(a) Centennial Energy Holdings, Inc. Master Shelf Agreement,
dated April 29, 2005, among Centennial Energy Holdings, Inc.
and The Prudential Insurance Company of America
4(b) 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
10(a) Purchase and Sale Agreement between Fidelity and Smith
Production Inc., dated April 19, 2005 (Flores)
10(b) Purchase and Sale Agreement between Fidelity and Smith
Production Inc., dated April 19, 2005 (Tabasco and Texas
Gardens)
10(c) First Amendment to the Purchase and Sale Agreements between
Fidelity and Smith Production Inc., dated April 19, 2005
10(d) Second Amendment to the Purchase and Sale Agreement between
Fidelity and Smith Production Inc., dated April 19, 2005
10(e) Directors' Compensation Policy, as amended on May 12, 2005
12 Computation of Ratio of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock
Dividends
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
SIGNATURES
Pursuant to the requirements 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: August 3, 2005 BY: /s/ Warren L. Robinson
Warren L. Robinson
Executive Vice President
and Chief Financial Officer
BY: /s/ Vernon A. Raile
Vernon A. Raile
Senior Vice President
and Chief Accounting Officer
EXHIBIT INDEX
Exhibit No.
4(a) Centennial Energy Holdings, Inc. Master Shelf Agreement,
dated April 29, 2005, among Centennial Energy Holdings,
Inc. and The Prudential Insurance Company of America
4(b) 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
10(a) Purchase and Sale Agreement between Fidelity and Smith Production
Inc., dated April 19, 2005 (Flores)
10(b) Purchase and Sale Agreement between Fidelity and Smith Production
Inc., dated April 19, 2005 (Tabasco and Texas Gardens)
10(c) First Amendment to the Purchase and Sale Agreements between
Fidelity and Smith Production Inc., dated April 19, 2005
10(d) Second Amendment to the Purchase and Sale Agreement between
Fidelity and Smith Production Inc., dated April 19, 2005
10(e) Directors' Compensation Policy, as amended on May 12, 2005
12 Computation of Ratio of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock
Dividends
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