x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF | |
THE SECURITIES EXCHANGE ACT OF 1934 | ||
For The Quarterly Period Ended | ||
OR | ||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF | |
THE SECURITIES EXCHANGE ACT OF 1934 |
Delaware | 41-0423660 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
Large accelerated filer x | Accelerated filer o |
Non-accelerated filer o | Smaller reporting company o |
2009 Annual Report | Company's Annual Report on Form 10-K for the year ended December 31, 2009 |
ASC | FASB Accounting Standards Codification |
Bbl | Barrel |
Bcf | Billion cubic feet |
Bcfe | Billion cubic feet equivalent |
BER | Montana Board of Environmental Review |
Big Stone Station | 450-MW coal-fired electric generating facility located near Big Stone City, South Dakota (22.7 percent ownership) |
Big Stone Station II | Formerly proposed coal-fired electric generating facility located near Big Stone City, South Dakota (the Company had anticipated ownership of at least 116 MW) |
Bitter Creek | Bitter Creek Pipelines, LLC, an indirect wholly owned subsidiary of WBI Holdings |
Brazilian Transmission Lines | Company’s equity method investment in |
Btu | British thermal unit |
Cascade | Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital |
CBNG | Coalbed natural gas |
CEM | Colorado Energy Management, LLC, a former direct wholly owned subsidiary of Centennial Resources (sold in the third quarter of 2007) |
Centennial | Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company |
Centennial Capital | Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial |
Centennial Resources | Centennial Energy Resources LLC, a direct wholly owned subsidiary of Centennial |
Clean Air Act | Federal Clean Air Act |
Clean Water Act | Federal Clean Water Act |
Colorado State District Court | Colorado Thirteenth Judicial District Court, Yuma County |
Company | MDU Resources Group, Inc. |
dk | Decatherm |
Dodd-Frank Act | Dodd-Frank Wall Street Reform and Consumer Protection Act |
ECTE | Empresa Catarinense de Transmissão de Energia S.A. |
EIS | Environmental Impact Statement |
ENTE | Empresa Norte de Transmissão de Energia S.A. |
EPA | U.S. Environmental Protection Agency |
ERTE | Empresa Regional de Transmissão de Energia S.A. |
Exchange Act | Securities Exchange Act of 1934, as amended |
FASB | Financial Accounting Standards Board |
Fidelity | Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings |
GAAP | Accounting principles generally accepted in the United States of America |
GHG | Greenhouse gas |
Great Plains | Great Plains Natural Gas Co., a public utility division of the Company |
Intermountain | Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital |
IPUC | Idaho Public Utilities Commission |
Knife River | Knife River Corporation, a direct wholly owned subsidiary of Centennial |
kWh | Kilowatt-hour |
LPP | Lea Power Partners, LLC, a former indirect wholly owned subsidiary of Centennial Resources (member interests were sold in October 2006) |
LTM | LTM, Inc., an indirect wholly owned subsidiary of Knife River |
LWG | Lower Willamette Group |
MBbls | Thousands of barrels |
MBI | Morse Bros., Inc., an indirect wholly owned subsidiary of Knife River |
MBOGC | Montana Board of Oil and Gas Conservation |
Mcf | Thousand cubic feet |
MDU Brasil | MDU Brasil Ltda., an indirect wholly owned subsidiary of Centennial Resources |
MDU Construction Services | MDU Construction Services Group, Inc., a direct wholly owned subsidiary of Centennial |
MDU Energy Capital | MDU Energy Capital, LLC, a direct wholly owned subsidiary of the Company |
MEIC | Montana Environmental Information Center, Inc. |
Mine Safety Act | Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006 |
MMBtu | Million Btu |
MMcf | Million cubic feet |
MMdk | Million decatherms |
Montana-Dakota | Montana-Dakota Utilities Co., a public utility division of the Company |
Montana DEQ | Montana State Department of Environmental Quality |
Montana First Judicial District Court | Montana First Judicial District Court, Lewis and Clark County |
Montana Twenty-Second Judicial District Court | Montana Twenty-Second Judicial District Court, Big Horn County |
MPX | MPX Termoceara Ltda. (49 percent ownership, sold in June 2005) |
MTPSC | Montana Public Service Commission |
MW | Megawatt |
NDPSC | North Dakota Public Service Commission |
North Dakota District Court | North Dakota South Central Judicial District Court for Burleigh County |
NPRC | Northern Plains Resource Council |
NSPS | New Source Performance Standards |
Oil | Includes crude oil, condensate and natural gas liquids |
OPUC | Oregon Public Utility Commission |
Oregon DEQ | Oregon State Department of Environmental Quality |
Prairielands | Prairielands Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI Holdings |
PRP | Potentially Responsible Party |
PSD | Prevention of Significant Deterioration |
RCRA | Resource Conservation and Recovery Act |
ROD | Record of Decision |
SDPUC | South Dakota Public Utilities Commission |
SEC | U.S. Securities and Exchange Commission |
SEC Defined Prices | The average price of natural gas and oil during the applicable 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions |
Securities Act | Securities Act of 1933, as amended |
South Dakota Federal District Court | U.S. District Court for the District of South Dakota |
South Dakota SIP | South Dakota State Implementation Plan |
TRWUA | Tongue River Water Users’ Association |
WBI Holdings | WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial |
Williston Basin | Williston Basin Interstate Pipeline Company, an indirect wholly owned subsidiary of WBI Holdings |
WUTC | Washington Utilities and Transportation Commission |
Wygen III | 100-MW coal-fired electric generating facility located near Gillette, Wyoming (25 percent ownership) |
WYPSC | Wyoming Public Service Commission |
Part I -- Financial Information | Page |
Consolidated Statements of Income -- | |
Three and | 7 |
Consolidated Balance Sheets -- | |
8 | |
Consolidated Statements of Cash Flows -- | |
9 | |
Notes to Consolidated Financial Statements | 10 |
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 | |
Risk Factors | |
Unregistered Sales of Equity Securities and Use of Proceeds | |
Other Information | 65 |
Exhibits | |
Signatures | |
Exhibit Index | |
Exhibits |
Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
(In thousands, except per share amounts) | (In thousands, except per share amounts) | |||||||||||||||||||||||||||||||
Operating revenues: | ||||||||||||||||||||||||||||||||
Electric, natural gas distribution and pipeline and energy services | $ | 272,177 | $ | 263,617 | $ | 732,422 | $ | 858,191 | $ | 223,602 | $ | 206,867 | $ | 956,025 | $ | 1,065,061 | ||||||||||||||||
Construction services, natural gas and oil production, construction materials and contracting, and other | 634,267 | 694,423 | 1,008,799 | 1,193,854 | 902,321 | 901,060 | 1,911,119 | 2,094,911 | ||||||||||||||||||||||||
Total operating revenues | 906,444 | 958,040 | 1,741,221 | 2,052,045 | 1,125,923 | 1,107,927 | 2,867,144 | 3,159,972 | ||||||||||||||||||||||||
Operating expenses: | ||||||||||||||||||||||||||||||||
Fuel and purchased power | 13,106 | 15,166 | 30,017 | 33,896 | 15,283 | 15,188 | 45,300 | 49,085 | ||||||||||||||||||||||||
Purchased natural gas sold | 97,441 | 106,401 | 331,133 | 462,897 | 51,243 | 57,598 | 382,376 | 520,495 | ||||||||||||||||||||||||
Operation and maintenance: | ||||||||||||||||||||||||||||||||
Electric, natural gas distribution and pipeline and energy services | 68,437 | 62,581 | 131,421 | 133,932 | 95,367 | 59,459 | 226,788 | 193,394 | ||||||||||||||||||||||||
Construction services, natural gas and oil production, construction materials and contracting, and other | 516,854 | 554,556 | 830,642 | 976,706 | 732,998 | 698,386 | 1,563,640 | 1,675,088 | ||||||||||||||||||||||||
Depreciation, depletion and amortization | 81,547 | 80,449 | 160,225 | 173,694 | 84,841 | 79,547 | 245,066 | 253,241 | ||||||||||||||||||||||||
Taxes, other than income | 40,397 | 38,822 | 86,192 | 91,774 | 37,229 | 37,476 | 123,421 | 129,250 | ||||||||||||||||||||||||
Write-down of natural gas and oil properties | — | — | — | 620,000 | — | — | — | 620,000 | ||||||||||||||||||||||||
Total operating expenses | 817,782 | 857,975 | 1,569,630 | 2,492,899 | 1,016,961 | 947,654 | 2,586,591 | 3,440,553 | ||||||||||||||||||||||||
Operating income (loss) | 88,662 | 100,065 | 171,591 | (440,854 | ) | 108,962 | 160,273 | 280,553 | (280,581 | ) | ||||||||||||||||||||||
Earnings from equity method investments | 2,260 | 2,078 | 4,443 | 3,864 | 2,528 | 2,290 | 6,970 | 6,154 | ||||||||||||||||||||||||
Other income | 2,686 | 2,435 | 5,188 | 4,154 | 1,740 | 2,923 | 6,929 | 7,076 | ||||||||||||||||||||||||
Interest expense | 20,490 | 20,759 | 41,006 | 41,755 | 20,944 | 20,945 | 61,950 | 62,700 | ||||||||||||||||||||||||
Income (loss) before income taxes | 73,118 | 83,819 | 140,216 | (474,591 | ) | 92,286 | 144,541 | 232,502 | (330,051 | ) | ||||||||||||||||||||||
Income taxes | 24,180 | 28,508 | 49,506 | (186,100 | ) | 31,276 | 51,957 | 80,783 | (134,143 | ) | ||||||||||||||||||||||
Net income (loss) | 48,938 | 55,311 | 90,710 | (288,491 | ) | 61,010 | 92,584 | 151,719 | (195,908 | ) | ||||||||||||||||||||||
Dividends on preferred stocks | 171 | 171 | 343 | 343 | 172 | 171 | 513 | 514 | ||||||||||||||||||||||||
Earnings (loss) on common stock | $ | 48,767 | $ | 55,140 | $ | 90,367 | $ | (288,834 | ) | $ | 60,838 | $ | 92,413 | $ | 151,206 | $ | (196,422 | ) | ||||||||||||||
Earnings (loss) per common share -- basic | $ | .26 | $ | .30 | $ | .48 | $ | (1.57 | ) | $ | .32 | $ | .50 | $ | .80 | $ | (1.07 | ) | ||||||||||||||
Earnings (loss) per common share -- diluted | $ | .26 | $ | .30 | $ | .48 | $ | (1.57 | ) | $ | .32 | $ | .50 | $ | .80 | $ | (1.07 | ) | ||||||||||||||
Dividends per common share | $ | .1575 | $ | .1550 | $ | .3150 | $ | .3100 | $ | .1575 | $ | .1550 | $ | .4725 | $ | .4650 | ||||||||||||||||
Weighted average common shares outstanding -- basic | 188,129 | 183,964 | 188,047 | 183,876 | 188,170 | 185,160 | 188,088 | 184,309 | ||||||||||||||||||||||||
Weighted average common shares outstanding -- diluted | 188,267 | 184,398 | 188,198 | 183,876 | 188,338 | 185,425 | 188,268 | 184,309 |
June 30, 2010 | June 30, 2009 | December 31, 2009 | September 30, 2010 | September 30, 2009 | December 31, 2009 | |||||||||||||||||||
(In thousands, except shares and per share amounts) | (In thousands, except shares and per share amounts) | (In thousands, except shares and per share amounts) | ||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||
Current assets: | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 65,792 | $ | 34,310 | $ | 175,114 | $ | 36,285 | $ | 61,449 | $ | 175,114 | ||||||||||||
Receivables, net | 502,454 | 559,842 | 531,980 | 585,487 | 519,572 | 531,980 | ||||||||||||||||||
Inventories | 260,163 | 285,814 | 249,804 | 261,680 | 268,677 | 249,804 | ||||||||||||||||||
Deferred income taxes | 17,755 | 2,490 | 28,145 | 25,552 | 13,050 | 28,145 | ||||||||||||||||||
Short-term investments | 250 | 1,967 | 2,833 | 250 | 1,644 | 2,833 | ||||||||||||||||||
Commodity derivative instruments | 24,932 | 62,048 | 7,761 | 26,803 | 28,421 | 7,761 | ||||||||||||||||||
Prepayments and other current assets | 97,953 | 117,381 | 66,021 | 99,466 | 77,736 | 66,021 | ||||||||||||||||||
Total current assets | 969,299 | 1,063,852 | 1,061,658 | 1,035,523 | 970,549 | 1,061,658 | ||||||||||||||||||
Investments | 142,212 | 125,361 | 145,416 | 152,577 | 137,340 | 145,416 | ||||||||||||||||||
Property, plant and equipment | 7,085,632 | 6,651,088 | 6,766,582 | 7,163,515 | 6,698,227 | 6,766,582 | ||||||||||||||||||
Less accumulated depreciation, depletion and amortization | 3,000,663 | 2,906,824 | 2,872,465 | 3,056,127 | 2,823,396 | 2,872,465 | ||||||||||||||||||
Net property, plant and equipment | 4,084,969 | 3,744,264 | 3,894,117 | 4,107,388 | 3,874,831 | 3,894,117 | ||||||||||||||||||
Deferred charges and other assets: | ||||||||||||||||||||||||
Goodwill | 634,654 | 622,131 | 629,463 | 634,633 | 629,036 | 629,463 | ||||||||||||||||||
Other intangible assets, net | 26,199 | 25,320 | 28,977 | 26,112 | 30,184 | 28,977 | ||||||||||||||||||
Other | 255,473 | 242,436 | 231,321 | 260,722 | 230,632 | 231,321 | ||||||||||||||||||
Total deferred charges and other assets | 916,326 | 889,887 | 889,761 | 921,467 | 889,852 | 889,761 | ||||||||||||||||||
Total assets | $ | 6,112,806 | $ | 5,823,364 | $ | 5,990,952 | $ | 6,216,955 | $ | 5,872,572 | $ | 5,990,952 | ||||||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||||||
Short-term borrowings | $ | 3,700 | $ | — | $ | 10,300 | $ | 4,700 | $ | — | $ | 10,300 | ||||||||||||
Long-term debt due within one year | 72,551 | 27,879 | 12,629 | 73,417 | 27,790 | 12,629 | ||||||||||||||||||
Accounts payable | 266,069 | 332,957 | 281,906 | 299,094 | 267,320 | 281,906 | ||||||||||||||||||
Taxes payable | 39,976 | 42,151 | 55,540 | 46,928 | 64,656 | 55,540 | ||||||||||||||||||
Dividends payable | 29,802 | 28,686 | 29,749 | 29,810 | 29,012 | 29,749 | ||||||||||||||||||
Accrued compensation | 35,989 | 44,141 | 47,425 | 41,648 | 49,082 | 47,425 | ||||||||||||||||||
Commodity derivative instruments | 20,160 | 57,139 | 36,907 | 25,803 | 44,903 | 36,907 | ||||||||||||||||||
Other accrued liabilities | 172,446 | 158,661 | 192,729 | 205,777 | 162,200 | 192,729 | ||||||||||||||||||
Total current liabilities | 640,693 | 691,614 | 667,185 | 727,177 | 644,963 | 667,185 | ||||||||||||||||||
Long-term debt | 1,508,714 | 1,636,592 | 1,486,677 | 1,437,171 | 1,471,833 | 1,486,677 | ||||||||||||||||||
Deferred credits and other liabilities: | ||||||||||||||||||||||||
Deferred income taxes | 627,256 | 540,952 | 590,968 | 672,155 | 547,538 | 590,968 | ||||||||||||||||||
Other liabilities | 708,403 | 544,104 | 674,475 | 718,331 | 691,961 | 674,475 | ||||||||||||||||||
Total deferred credits and other liabilities | 1,335,659 | 1,085,056 | 1,265,443 | 1,390,486 | 1,239,499 | 1,265,443 | ||||||||||||||||||
Commitments and contingencies | ||||||||||||||||||||||||
Stockholders’ equity: | ||||||||||||||||||||||||
Preferred stocks | 15,000 | 15,000 | 15,000 | 15,000 | 15,000 | 15,000 | ||||||||||||||||||
Common stockholders’ equity: | ||||||||||||||||||||||||
Common stock | ||||||||||||||||||||||||
Shares issued -- $1.00 par value, 188,672,532 at June 30, 2010, 184,508,109 at June 30, 2009 and 188,389,265 at December 31, 2009 | 188,673 | 184,508 | 188,389 | |||||||||||||||||||||
Shares issued -- $1.00 par value, 188,732,200 at September 30, 2010, 187,673,037 at September 30, 2009 and 188,389,265 at December 31, 2009 | 188,732 | 187,673 | 188,389 | |||||||||||||||||||||
Other paid-in capital | 1,020,206 | 941,773 | 1,015,678 | 1,022,469 | 1,001,313 | 1,015,678 | ||||||||||||||||||
Retained earnings | 1,407,950 | 1,270,778 | 1,377,039 | 1,439,050 | 1,334,255 | 1,377,039 | ||||||||||||||||||
Accumulated other comprehensive income (loss) | (463 | ) | 1,669 | (20,833 | ) | 496 | (18,338 | ) | (20,833 | ) | ||||||||||||||
Treasury stock at cost – 538,921 shares | (3,626 | ) | (3,626 | ) | (3,626 | ) | (3,626 | ) | (3,626 | ) | (3,626 | ) | ||||||||||||
Total common stockholders’ equity | 2,612,740 | 2,395,102 | 2,556,647 | 2,647,121 | 2,501,277 | 2,556,647 | ||||||||||||||||||
Total stockholders’ equity | 2,627,740 | 2,410,102 | 2,571,647 | 2,662,121 | 2,516,277 | 2,571,647 | ||||||||||||||||||
Total liabilities and stockholders’ equity | $ | 6,112,806 | $ | 5,823,364 | $ | 5,990,952 | $ | 6,216,955 | $ | 5,872,572 | $ | 5,990,952 |
Six Months Ended June 30, | Nine Months Ended September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(In thousands) | (In thousands) | |||||||||||||||
Operating activities: | ||||||||||||||||
Net income (loss) | $ | 90,710 | $ | (288,491 | ) | $ | 151,719 | $ | (195,908 | ) | ||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||
Depreciation, depletion and amortization | 160,225 | 173,694 | 245,066 | 253,241 | ||||||||||||
Earnings, net of distributions, from equity method investments | (1,899 | ) | (1,685 | ) | (2,502 | ) | (2,110 | ) | ||||||||
Deferred income taxes | 35,758 | (206,955 | ) | 71,322 | (200,240 | ) | ||||||||||
Write-down of natural gas and oil properties | — | 620,000 | — | 620,000 | ||||||||||||
Changes in current assets and liabilities, net of acquisitions: | ||||||||||||||||
Receivables | 27,149 | 149,782 | (57,074 | ) | 141,147 | |||||||||||
Inventories | (12,442 | ) | (26,574 | ) | (12,565 | ) | (7,832 | ) | ||||||||
Other current assets | (32,471 | ) | 47,837 | (32,122 | ) | 67,143 | ||||||||||
Accounts payable | (13,164 | ) | (66,260 | ) | 19,782 | (73,984 | ) | |||||||||
Other current liabilities | (45,613 | ) | 2,218 | (147 | ) | 34,188 | ||||||||||
Other noncurrent changes | (4,882 | ) | (5,141 | ) | (11,959 | ) | (6,423 | ) | ||||||||
Net cash provided by operating activities | 203,371 | 398,425 | 371,520 | 629,222 | ||||||||||||
Investing activities: | ||||||||||||||||
Capital expenditures | (237,535 | ) | (272,867 | ) | (340,221 | ) | (344,779 | ) | ||||||||
Acquisitions, net of cash acquired | (106,548 | ) | (3,764 | ) | (106,548 | ) | (6,452 | ) | ||||||||
Net proceeds from sale or disposition of property | 11,972 | 7,494 | 16,496 | 18,821 | ||||||||||||
Investments | 1,228 | (2,368 | ) | 1,106 | (560 | ) | ||||||||||
Net cash used in investing activities | (330,883 | ) | (271,505 | ) | (429,167 | ) | (332,970 | ) | ||||||||
Financing activities: | ||||||||||||||||
Issuance of short-term borrowings | 4,700 | — | ||||||||||||||
Repayment of short-term borrowings | (6,600 | ) | (105,100 | ) | (10,300 | ) | (105,100 | ) | ||||||||
Issuance of long-term debt | 82,992 | 109,400 | 17,799 | 105,000 | ||||||||||||
Repayment of long-term debt | (814 | ) | (92,024 | ) | (7,545 | ) | (252,696 | ) | ||||||||
Proceeds from issuance of common stock | 1,739 | 284 | 2,735 | 51,440 | ||||||||||||
Dividends paid | (59,545 | ) | (57,325 | ) | (89,347 | ) | (86,011 | ) | ||||||||
Tax benefit on stock-based compensation | 548 | 144 | 721 | 195 | ||||||||||||
Net cash provided by (used in) financing activities | 18,320 | (144,621 | ) | |||||||||||||
Net cash used in financing activities | (81,237 | ) | (287,172 | ) | ||||||||||||
Effect of exchange rate changes on cash and cash equivalents | (130 | ) | 297 | 55 | 655 | |||||||||||
Decrease in cash and cash equivalents | (109,322 | ) | (17,404 | ) | ||||||||||||
Increase (decrease) in cash and cash equivalents | (138,829 | ) | 9,735 | |||||||||||||
Cash and cash equivalents -- beginning of year | 175,114 | 51,714 | 175,114 | 51,714 | ||||||||||||
Cash and cash equivalents -- end of period | $ | 65,792 | $ | 34,310 | $ | 36,285 | $ | 61,449 |
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 Company's 2009 Annual Report, and the standards of accounting measurement set forth in the interim reporting guidance in the ASC and any amendments thereto adopted by the 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 2009 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 and are of a normal recurring nature. Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Incom e and therefore is excluded from the other line items within operating expenses. Management has also evaluated the impact of events occurring after |
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 |
4. |
Inventories, other than natural gas in storage for the Company’s regulated operations, were stated at the lower of average cost or market value. Natural gas in storage for the |
September 30, 2010 | September 30, 2009 | December 31, 2009 | ||||||||||
(In thousands) | ||||||||||||
Aggregates held for resale | $ | 82,622 | $ | 88,087 | $ | 80,087 | ||||||
Materials and supplies | 62,273 | 61,580 | 58,095 | |||||||||
Natural gas in storage (current) | 40,133 | 48,517 | 35,619 | |||||||||
Asphalt oil | 24,341 | 21,228 | 22,989 | |||||||||
Other | 52,311 | 49,265 | 53,014 | |||||||||
Total | $ | 261,680 | $ | 268,677 | $ | 249,804 |
The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in other assets and was $59.3 million, |
5. |
Natural gas and oil properties |
The Company uses the full-cost method of accounting for its natural gas and oil production activities. Under this method, all costs incurred in the acquisition, exploration and development of natural gas and oil properties are capitalized and amortized on the units-of-production method based on total proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of the properties with no gain or loss recognized. |
Capitalized costs are subject to a “ceiling test” that limits such costs to the aggregate of the present value of future net cash flows from proved reserves discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties less applicable income taxes. Future net revenue was estimated based on end-of-quarter spot market prices adjusted for contracted price changes prior to the fourth quarter of 2009. Effective December 31, 2009, the Modernization of Oil and Gas Reporting rules issued by the SEC changed the pricing used to estimate reserves and associated future cash flows to SEC Defined Prices. Prior to that date, if capitalized costs exceeded the full-cost ceiling at the end of any quarter, a permanent noncash write-down was required to be charged to earnings in that quarter unless subsequent price changes eliminated or reduced an indicated write-down. Effectiv e December 31, 2009, if capitalized costs exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter regardless of subsequent price changes. |
Due to low natural gas and oil prices that existed on March 31, 2009, the Company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at March 31, 2009. Accordingly, the Company was required to write down its natural gas and |
oil producing properties. The noncash write-down amounted to $620.0 million ($384.4 million after tax) for the three months ended March 31, 2009. |
The Company hedges a portion of its natural gas and oil production and the effects of the cash flow hedges were used in determining the full-cost ceiling. The Company would have recognized an additional write-down of its natural gas and oil properties of $107.9 million ($66.9 million after tax) at March 31, 2009, if the effects of cash flow hedges had not been considered in calculating the full-cost ceiling. For more information on the Company's cash flow hedges, see Note |
At |
| Earnings (loss) per common share |
Basic earnings (loss) per common share were computed by dividing earnings (loss) on common stock by the weighted average number of shares of common stock outstanding during the 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 months ended |
| Cash flow information |
Cash expenditures for interest and income taxes were as follows: |
Six Months Ended June 30, | Nine Months Ended September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(In thousands) | (In thousands) | |||||||||||||||
Interest, net of amount capitalized | $ | 39,652 | $ | 40,588 | $ | 65,712 | $ | 65,421 | ||||||||
Income taxes | $ | 36,011 | $ | 13,343 | $ | 36,962 | $ | 29,540 |
| New accounting standards |
Improving Disclosure About Fair Value Measurements In January 2010, the FASB issued guidance related to improving disclosures about fair value measurements. The guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, |
information about purchases, sales, issuances and settlements shall be presented separately. These disclosures are required for interim and annual reporting periods and were effective for the Company on January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on |
Comprehensive income (loss) |
Comprehensive income (loss) is the sum of net income (loss) as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges and foreign currency translation adjustments. For more information on derivative instruments, see Note |
Comprehensive income (loss), and the components of other comprehensive income (loss) and related tax effects, were as follows: |
Three Months Ended June 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Net income | $ | 48,938 | $ | 55,311 | ||||
Other comprehensive loss: | ||||||||
Net unrealized loss on derivative instruments qualifying as hedges: | ||||||||
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $2,588 and $(4,028) in 2010 and 2009, respectively | 4,637 | (6,571 | ) | |||||
Less: Reclassification adjustment for gain on derivative instruments included in net income, net of tax of $3,191 and $11,415 in 2010 and 2009, respectively | 5,259 | 18,625 | ||||||
Net unrealized loss on derivative instruments qualifying as hedges | (622 | ) | (25,196 | ) | ||||
Foreign currency translation adjustment, net of tax of $307 and $3,711 in 2010 and 2009, respectively | (476 | ) | 5,756 | |||||
(1,098 | ) | (19,440 | ) | |||||
Comprehensive income | $ | 47,840 | $ | 35,871 | ||||
Six Months Ended June 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Net income (loss) | $ | 90,710 | $ | (288,491 | ) | |||
Other comprehensive income (loss): | ||||||||
Net unrealized gain (loss) on derivative instruments qualifying as hedges: | ||||||||
Net unrealized gain on derivative instruments arising during the period, net of tax of $11,962 and $5,634 in 2010 and 2009, respectively | 19,932 | 9,193 | ||||||
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income (loss), net of tax of $(1,166) and $14,646 in 2010 and 2009, respectively | (1,850 | ) | 23,896 | |||||
Net unrealized gain (loss) on derivative instruments qualifying as hedges | 21,782 | (14,703 | ) | |||||
Foreign currency translation adjustment, net of tax of $(929) and $3,875 in 2010 and 2009, respectively | (1,412 | ) | 6,007 | |||||
20,370 | (8,696 | ) | ||||||
Comprehensive income (loss) | $ | 111,080 | $ | (297,187 | ) |
Three Months Ended September 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Net income | $ | 61,010 | $ | 92,584 | ||||
Other comprehensive income (loss): | ||||||||
Net unrealized loss on derivative instruments qualifying as hedges: | ||||||||
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $2,177 and $(4,632) in 2010 and 2009, respectively | 3,628 | (7,557 | ) | |||||
Less: Reclassification adjustment for gain on derivative instruments included in net income, net of tax of $3,209 and $10,022 in 2010 and 2009, respectively | 5,348 | 16,352 | ||||||
Net unrealized loss on derivative instruments qualifying as hedges | (1,720 | ) | (23,909 | ) | ||||
Foreign currency translation adjustment, net of tax of $1,730 and $2,538 in 2010 and 2009, respectively | 2,679 | 3,902 | ||||||
959 | (20,007 | ) | ||||||
Comprehensive income | $ | 61,969 | $ | 72,577 | ||||
Nine Months Ended September 30, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Net income (loss) | $ | 151,719 | $ | (195,908 | ) | |||
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 $10,351 and $(1,758) in 2010 and 2009, respectively | 17,266 | (2,869 | ) | |||||
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income (loss), net of tax of $(1,745) and $21,908 in 2010 and 2009, respectively | (2,797 | ) | 35,743 | |||||
Net unrealized gain (loss) on derivative instruments qualifying as hedges | 20,063 | (38,612 | ) | |||||
Foreign currency translation adjustment, net of tax of $801 and $6,414 in 2010 and 2009, respectively | 1,266 | 9,909 | ||||||
21,329 | (28,703 | ) | ||||||
Comprehensive income (loss) | $ | 173,048 | $ | (224,611 | ) |
Equity method investments |
Investments in companies in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for using the equity method. The Company's equity method investments at |
In August 2006, MDU Brasil acquired ownership interests in companies owning the Brazilian Transmission Lines. The interests involve the ENTE (13.3-percent ownership interest), ERTE (13.3-percent ownership interest) and ECTE (25-percent ownership interest) electric transmission lines, which are primarily in northeastern and southern Brazil. |
In the fourth quarter of 2009, multiple sales agreements were signed with three separate parties for the Company to sell its ownership interests in the Brazilian Transmission Lines. Regulatory approval for the sale has been received. The financial closing of the sale is anticipated to occur |
At |
Goodwill and other intangible assets |
The changes in the carrying amount of goodwill were as follows: |
Nine Months Ended September 30, 2010 | Balance as of January 1, 2010* | Goodwill Acquired During the Year** | Balance as of September 30, 2010* | |||||||||
(In thousands) | ||||||||||||
Electric | $ | — | $ | — | $ | — | ||||||
Natural gas distribution | 345,736 | — | 345,736 | |||||||||
Construction services | 100,127 | 2,743 | 102,870 | |||||||||
Pipeline and energy services | 7,857 | 1,880 | 9,737 | |||||||||
Natural gas and oil production | — | — | — | |||||||||
Construction materials and contracting | 175,743 | 547 | 176,290 | |||||||||
Other | — | — | — | |||||||||
Total | $ | 629,463 | $ | 5,170 | $ | 634,633 | ||||||
*Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment. **Includes purchase price adjustments that were not material related to acquisitions in a prior period. |
Six Months Ended June 30, 2010 | Balance as of January 1, 2010 | Goodwill Acquired During the Year* | Balance as of June 30, 2010 | |||||||||
(In thousands) | ||||||||||||
Electric | $ | — | $ | — | $ | — | ||||||
Natural gas distribution | 345,736 | — | 345,736 | |||||||||
Construction services | 100,127 | 2,764 | 102,891 | |||||||||
Pipeline and energy services | 7,857 | 1,880 | 9,737 | |||||||||
Natural gas and oil production | — | — | — | |||||||||
Construction materials and contracting | 175,743 | 547 | 176,290 | |||||||||
Other | — | — | — | |||||||||
Total | $ | 629,463 | $ | 5,191 | $ | 634,654 | ||||||
* Includes purchase price adjustments that were not material related to acquisitions in a prior period. |
Six Months Ended June 30, 2009 | Balance as of January 1, 2009 | Goodwill Acquired During the Year* | Balance as of June 30, 2009 | |||||||||||||||||||||
Nine Months Ended September 30, 2009 | Balance as of January 1, 2009* | Goodwill Acquired During the Year** | Balance as of September 30, 2009* | |||||||||||||||||||||
(In thousands) | (In thousands) | |||||||||||||||||||||||
Electric | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||
Natural gas distribution | 344,952 | 296 | 345,248 | 344,952 | 784 | 345,736 | ||||||||||||||||||
Construction services | 95,619 | 4,398 | 100,017 | 95,619 | 4,184 | 99,803 | ||||||||||||||||||
Pipeline and energy services | 1,159 | — | 1,159 | 1,159 | 6,595 | 7,754 | ||||||||||||||||||
Natural gas and oil production | — | — | — | — | — | — | ||||||||||||||||||
Construction materials and contracting | 174,005 | 1,702 | 175,707 | 174,005 | 1,738 | 175,743 | ||||||||||||||||||
Other | — | — | — | — | — | — | ||||||||||||||||||
Total | $ | 615,735 | $ | 6,396 | $ | 622,131 | $ | 615,735 | $ | 13,301 | $ | 629,036 | ||||||||||||
* Includes purchase price adjustments that were not material related to acquisitions in a prior period. | ||||||||||||||||||||||||
*Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment. **Includes purchase price adjustments that were not material related to acquisitions in a prior period. | *Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment. **Includes purchase price adjustments that were not material related to acquisitions in a prior period. |
Year Ended December 31, 2009 | Balance as of January 1, 2009 | Goodwill Acquired During the Year* | Balance as of December 31, 2009 | Balance as of January 1, 2009* | Goodwill Acquired During the Year** | Balance as of December 31, 2009* | ||||||||||||||||||||
(In thousands) | (In thousands) | |||||||||||||||||||||||||
Electric | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Natural gas distribution | 344,952 | 784 | 345,736 | 344,952 | 784 | 345,736 | ||||||||||||||||||||
Construction services | 95,619 | 4,508 | 100,127 | 95,619 | 4,508 | 100,127 | ||||||||||||||||||||
Pipeline and energy services | 1,159 | 6,698 | 7,857 | 1,159 | 6,698 | 7,857 | ||||||||||||||||||||
Natural gas and oil production | — | — | — | — | — | — | ||||||||||||||||||||
Construction materials and contracting | 174,005 | 1,738 | 175,743 | 174,005 | 1,738 | 175,743 | ||||||||||||||||||||
Other | — | — | — | — | — | — | ||||||||||||||||||||
Total | $ | 615,735 | $ | 13,728 | $ | 629,463 | $ | 615,735 | $ | 13,728 | $ | 629,463 | ||||||||||||||
* Includes purchase price adjustments that were not material related to acquisitions in a prior period. | ||||||||||||||||||||||||||
*Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment. **Includes purchase price adjustments that were not material related to acquisitions in a prior period. | *Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment. **Includes purchase price adjustments that were not material related to acquisitions in a prior period. |
Other intangible assets were as follows: |
June 30, 2010 | June 30, 2009 | December 31, 2009 | September 30, 2010 | September 30, 2009 | December 31, 2009 | |||||||||||||||||||
(In thousands) | (In thousands) | |||||||||||||||||||||||
Customer relationships | $ | 24,942 | $ | 21,688 | $ | 24,942 | $ | 24,942 | $ | 24,606 | $ | 24,942 | ||||||||||||
Accumulated amortization | (10,688 | ) | (8,142 | ) | (9,500 | ) | (11,273 | ) | (8,754 | ) | (9,500 | ) | ||||||||||||
14,254 | 13,546 | 15,442 | 13,669 | 15,852 | 15,442 | |||||||||||||||||||
Noncompete agreements | 9,405 | 9,792 | 12,377 | 9,405 | 12,227 | 12,377 | ||||||||||||||||||
Accumulated amortization | (6,033 | ) | (5,942 | ) | (6,675 | ) | (6,231 | ) | (6,281 | ) | (6,675 | ) | ||||||||||||
3,372 | 3,850 | 5,702 | 3,174 | 5,946 | 5,702 | |||||||||||||||||||
Other | 12,063 | 10,679 | 10,859 | 13,217 | 11,478 | 10,859 | ||||||||||||||||||
Accumulated amortization | (3,490 | ) | (2,755 | ) | (3,026 | ) | (3,948 | ) | (3,092 | ) | (3,026 | ) | ||||||||||||
8,573 | 7,924 | 7,833 | 9,269 | 8,386 | 7,833 | |||||||||||||||||||
Total | $ | 26,199 | $ | 25,320 | $ | 28,977 | $ | 26,112 | $ | 30,184 | $ | 28,977 |
Amortization expense for amortizable intangible assets for the three and |
Derivative instruments |
The Company's policy allows the use of derivative instruments as part of an overall energy price, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. As of |
following information should be read in conjunction with Notes 1 and 7 in the Company's Notes to Consolidated Financial Statements in the 2009 Annual Report. |
Cascade and Intermountain |
At |
Certain of Cascade's derivative instruments contain credit-risk-related contingent features that permit the counterparties to require collateralization if Cascade's derivative liability positions exceed certain dollar thresholds. The dollar thresholds in certain of Cascade's agreements are determined and may fluctuate based on Cascade's credit rating on its debt. In addition, Cascade's and Intermountain's derivative instruments contain cross-default provisions that state if the entity fails to make payment with respect to certain of its indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of such entity's derivative instruments in liability positions. The aggregate fair value of Cascade and Intermountain's derivative instruments with credit-risk-related contingent features that are in a liability position at |
Fidelity |
At |
market risk associated with fluctuations in the price of natural gas and oil and basis differentials on its forecasted sales of natural gas and oil production. |
The fair value of the derivative instruments must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or liability. Changes in the fair value attributable to the effective portion of hedging instruments, net of tax, are recorded in stockholders' equity as a component of accumulated other comprehensive income (loss). At the date the natural gas and oil quantities are settled, the amounts accumulated in other comprehensive income (loss) are reported in the Consolidated Statements of Income. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded directly in earnings. The proceeds received for natural gas and oil production are generally based on market prices. |
For the three and |
Gains and losses on derivative instruments that are reclassified from accumulated other comprehensive income (loss) to current-period earnings are included in operating revenues on the Consolidated Statements of Income. For further information regarding the gains and losses on derivative instruments qualifying as cash flow hedges that were recognized in other comprehensive income (loss) and the gains and losses reclassified from accumulated other comprehensive income (loss) into earnings, see Note |
As of |
Certain of Fidelity's derivative instruments contain cross-default provisions that state if Fidelity fails to make payment with respect to certain indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of derivative instruments in liability positions. The aggregate fair value of Fidelity's derivative instruments with credit-risk-related contingent features that are in a liability position at |
The location and fair value of all of the Company’s derivative instruments in the Consolidated Balance Sheets were as follows: |
Asset Derivatives | Location on Consolidated Balance Sheets | Fair Value at June 30, 2010 | Fair Value at June 30, 2009 | Fair Value at December 31, 2009 | Location on Consolidated Balance Sheets | Fair Value at September 30, 2010 | Fair Value at September 30, 2009 | Fair Value at December 31, 2009 | ||||||||||||||||||
(In thousands) | (In thousands) | |||||||||||||||||||||||||
Designated as hedges | Commodity derivative instruments | $ | 24,932 | $ | 62,047 | $ | 7,761 | Commodity derivative instruments | $ | 26,803 | $ | 28,421 | $ | 7,761 | ||||||||||||
Other assets – noncurrent | 8,524 | 4,217 | 2,734 | Other assets – noncurrent | 8,423 | 2,894 | 2,734 | |||||||||||||||||||
33,456 | 66,264 | 10,495 | 35,226 | 31,315 | 10,495 | |||||||||||||||||||||
Not designated as hedges | Commodity derivative instruments | — | 1 | — | Commodity derivative instruments | — | — | — | ||||||||||||||||||
Other assets – noncurrent | — | 1 | — | Other assets – noncurrent | — | — | — | |||||||||||||||||||
— | 2 | — | — | — | — | |||||||||||||||||||||
Total asset derivatives | $ | 33,456 | $ | 66,266 | $ | 10,495 | $ | 35,226 | $ | 31,315 | $ | 10,495 |
Liability Derivatives | Location on Consolidated Balance Sheets | Fair Value at June 30, 2010 | Fair Value at June 30, 2009 | Fair Value at December 31, 2009 | Location on Consolidated Balance Sheets | Fair Value at September 30, 2010 | Fair Value at September 30, 2009 | Fair Value at December 31, 2009 | ||||||||||||||||||
(In thousands) | (In thousands) | |||||||||||||||||||||||||
Designated as hedges | Commodity derivative instruments | $ | 1,961 | $ | 8,440 | $ | 13,763 | Commodity derivative instruments | $ | 4,649 | $ | 10,962 | $ | 13,763 | ||||||||||||
Other liabilities – noncurrent | — | 1,538 | 114 | Other liabilities – noncurrent | 1,845 | 2,639 | 114 | |||||||||||||||||||
1,961 | 9,978 | 13,877 | 6,494 | 13,601 | 13,877 | |||||||||||||||||||||
Not designated as hedges | Commodity derivative instruments | 18,199 | 48,699 | 23,144 | Commodity derivative instruments | 21,154 | 33,941 | 23,144 | ||||||||||||||||||
Other liabilities – noncurrent | 698 | 10,786 | 4,756 | Other liabilities – noncurrent | 418 | 7,718 | 4,756 | |||||||||||||||||||
18,897 | 59,485 | 27,900 | 21,572 | 41,659 | 27,900 | |||||||||||||||||||||
Total liability derivatives | $ | 20,858 | $ | 69,463 | $ | 41,777 | $ | 28,066 | $ | 55,260 | $ | 41,777 | ||||||||||||||
Note: The fair value of the commodity derivative instruments not designated as hedges is presented net of collateral provided to the counterparties by Cascade of $8.5 million at June 30, 2009. | ||||||||||||||||||||||||||
Note: The fair value of the commodity derivative instruments not designated as hedges is presented net of collateral provided to the counterparties by Cascade of $4.4 million at September 30, 2009. | Note: The fair value of the commodity derivative instruments not designated as hedges is presented net of collateral provided to the counterparties by Cascade of $4.4 million at September 30, 2009. |
Fair value measurements |
The Company elected to measure its investments in certain fixed-income and equity securities at fair value with changes in fair value recognized in income. The Company anticipates using these investments to satisfy its obligations under its unfunded, nonqualified benefit plans for executive officers and certain key management employees, and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled |
$34.8 million, as of |
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The ASC establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs. The Company’s assets and liabilities measured at fair value on a recurring basis are as follows: |
Fair Value Measurements at June 30, 2010, Using | Fair Value Measurements at September 30, 2010, Using | |||||||||||||||||||||||||||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Collateral Provided to Counterparties | Balance at June 30, 2010 | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Collateral Provided to Counterparties | Balance at September 30, 2010 | |||||||||||||||||||||||||||||||
(In thousands) | (In thousands) | |||||||||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||||||||||
Money market funds | $ | 8,251 | $ | — | $ | — | $ | — | $ | 8,251 | $ | 2,835 | $ | — | $ | — | $ | — | $ | 2,835 | ||||||||||||||||||||
Available-for-sale securities: | ||||||||||||||||||||||||||||||||||||||||
Fixed-income securities | — | 11,400 | — | — | 11,400 | — | 11,400 | — | — | 11,400 | ||||||||||||||||||||||||||||||
Insurance contract* | — | 20,236 | — | — | 20,236 | — | 35,902 | — | — | 35,902 | ||||||||||||||||||||||||||||||
Commodity derivative instruments - current | — | 24,932 | — | — | 24,932 | — | 26,803 | — | — | 26,803 | ||||||||||||||||||||||||||||||
Commodity derivative instruments - noncurrent | — | 8,524 | — | — | 8,524 | — | 8,423 | — | — | 8,423 | ||||||||||||||||||||||||||||||
Total assets measured at fair value | $ | 8,251 | $ | 65,092 | $ | — | $ | — | $ | 73,343 | $ | 2,835 | $ | 82,528 | $ | — | $ | — | $ | 85,363 | ||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||||||||||||||
Commodity derivative instruments - current | $ | — | $ | 20,160 | $ | — | $ | — | $ | 20,160 | $ | — | $ | 25,803 | $ | — | $ | — | $ | 25,803 | ||||||||||||||||||||
Commodity derivative instruments - noncurrent | — | 698 | — | — | 698 | — | 2,263 | — | — | 2,263 | ||||||||||||||||||||||||||||||
Total liabilities measured at fair value | $ | — | $ | 20,858 | $ | — | $ | — | $ | 20,858 | $ | — | $ | 28,066 | $ | — | $ | — | $ | 28,066 | ||||||||||||||||||||
* Invested in mutual funds. | * Invested in mutual funds. | * Invested in mutual funds. |
Fair Value Measurements at June 30, 2009, Using | Fair Value Measurements at September 30, 2009, Using | |||||||||||||||||||||||||||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Collateral Provided to Counterparties | Balance at June 30, 2009 | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Collateral Provided to Counterparties | Balance at September 30, 2009 | |||||||||||||||||||||||||||||||
(In thousands) | (In thousands) | |||||||||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||||||||||
Money market funds | $ | 50,608 | $ | — | $ | — | $ | — | $ | 50,608 | ||||||||||||||||||||||||||||||
Available-for-sale securities | $ | 29,532 | $ | 11,400 | $ | — | $ | — | $ | 40,932 | 33,587 | 11,400 | — | — | 44,987 | |||||||||||||||||||||||||
Commodity derivative instruments - current | — | 62,048 | — | — | 62,048 | — | 28,421 | — | — | 28,421 | ||||||||||||||||||||||||||||||
Commodity derivative instruments - noncurrent | — | 4,218 | — | — | 4,218 | — | 2,894 | — | — | 2,894 | ||||||||||||||||||||||||||||||
Total assets measured at fair value | $ | 29,532 | $ | 77,666 | $ | — | $ | — | $ | 107,198 | $ | 84,195 | $ | 42,715 | $ | — | $ | — | $ | 126,910 | ||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||||||||||||||
Commodity derivative instruments - current | $ | — | $ | 65,604 | $ | — | $ | 8,465 | $ | 57,139 | $ | — | $ | 49,308 | $ | — | $ | 4,405 | $ | 44,903 | ||||||||||||||||||||
Commodity derivative instruments - noncurrent | — | 12,324 | — | — | 12,324 | — | 10,357 | — | — | 10,357 | ||||||||||||||||||||||||||||||
Total liabilities measured at fair value | $ | — | $ | 77,928 | $ | — | $ | 8,465 | $ | 69,463 | $ | — | $ | 59,665 | $ | — | $ | 4,405 | $ | 55,260 |
Fair Value Measurements at December 31, 2009, Using | ||||||||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Collateral Provided to Counterparties | Balance at December 31, 2009 | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
Money market funds | $ | 9,124 | $ | 151,000 | $ | — | $ | — | $ | 160,124 | ||||||||||
Available-for-sale securities | 9,078 | 37,141 | — | — | 46,219 | |||||||||||||||
Commodity derivative instruments - current | — | 7,761 | — | — | 7,761 | |||||||||||||||
Commodity derivative instruments - noncurrent | — | 2,734 | — | — | 2,734 | |||||||||||||||
Total assets measured at fair value | $ | 18,202 | $ | 198,636 | $ | — | $ | — | $ | 216,838 | ||||||||||
Liabilities: | ||||||||||||||||||||
Commodity derivative instruments - current | $ | — | $ | 36,907 | $ | — | $ | — | $ | 36,907 | ||||||||||
Commodity derivative instruments - noncurrent | — | 4,870 | — | — | 4,870 | |||||||||||||||
Total liabilities measured at fair value | $ | — | $ | 41,777 | $ | — | $ | — | $ | 41,777 |
The estimated fair value of the Company’s Level 1 money market funds is determined using the market approach and is valued at the net asset value of shares held by the Company, based on published market quotations in active markets. |
The estimated fair value of the Company’s Level 1 available-for-sale securities is determined using the market approach and is based on quoted market prices in active markets for identical equity and fixed-income securities. |
The estimated fair value of the Company’s Level 2 money market funds and available-for-sale securities is determined using the market approach. The Level 2 money market funds consist of investments in short-term unsecured promissory notes and the value is based on comparable market transactions taking into consideration the credit quality of the issuer. The estimated fair value of the Company’s Level 2 |
The estimated fair value of the Company’s Level 2 commodity derivative instruments is based upon futures prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The nonperformance risk of the counterparties in addition to the Company’s nonperformance risk is also evaluated. |
Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. |
The Company’s long-term debt is not measured at fair value on the Consolidated Balance Sheets and the fair value is being provided for disclosure purposes only. The estimated fair value of the Company’s long-term debt was based on quoted market prices of the same or similar issues. The estimated fair value of the Company's long-term debt was as follows: |
Carrying Amount | Fair Value | |||||||
(In thousands) | ||||||||
Long-term debt at June 30, 2010 | $ | 1,581,265 | $ | 1,718,477 | ||||
Long-term debt at June 30, 2009 | $ | 1,664,471 | $ | 1,538,693 | ||||
Long-term debt at December 31, 2009 | $ | 1,499,306 | $ | 1,566,331 |
Carrying Amount | Fair Value | |||||||
(In thousands) | ||||||||
Long-term debt at September 30, 2010 | $ | 1,510,588 | $ | 1,679,979 | ||||
Long-term debt at September 30, 2009 | $ | 1,499,623 | $ | 1,540,656 | ||||
Long-term debt at December 31, 2009 | $ | 1,499,306 | $ | 1,566,331 |
The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values. |
Business segment data |
The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The vast majority of the Company’s operations are located within the United States. The Company also has investments in foreign countries, which largely consist of Centennial Resources’ equity method investment in the Brazilian Transmission Lines. |
The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas distribution segment distributes natural gas in those states as well as in Idaho, Minnesota, Oregon and Washington. These operations also supply related value-added products and services. |
The construction services segment specializes in constructing and maintaining electric and communication lines, gas pipelines, fire suppression systems, and external lighting and traffic signalization equipment. This segment also provides utility excavation services and inside electrical wiring, cabling and mechanical services, sells and distributes electrical materials, and manufactures and distributes specialty equipment. |
The pipeline and energy services segment provides natural gas transportation, underground storage and gathering services through regulated and nonregulated pipeline systems primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment also provides cathodic protection and other energy-related services. |
The natural gas and oil production segment is engaged in natural gas and oil acquisition, exploration, development and production activities in the Rocky Mountain and Mid-Continent regions of the United States and in and around the Gulf of Mexico. |
The construction materials and contracting segment mines aggregates and markets crushed stone, sand, gravel and related construction materials, including ready-mixed concrete, cement, asphalt, liquid asphalt and other value-added products. It also performs integrated contracting services. This segment operates in the central, southern and western United States and Alaska and Hawaii. |
The Other category includes the activities of Centennial Capital, which insures various types of risks as a captive insurer for certain of the Company’s subsidiaries. The function of the captive insurer is to fund the deductible layers of the insured companies’ general liability and automobile liability coverages. Centennial Capital also owns certain real and personal property. The Other category also includes Centennial Resources' equity method investment in the Brazilian Transmission Lines. |
The information below follows the same accounting policies as described in Note 1 of the Company’s Notes to Consolidated Financial Statements in the 2009 Annual Report. Information on the Company's businesses was as follows: |
Three Months Ended June 30, 2010 | External Operating Revenues | Inter- segment Operating Revenues | Earnings on Common Stock | |||||||||||||||||||||
Three Months Ended September 30, 2010 | External Operating Revenues | Inter- segment Operating Revenues | Earnings on Common Stock | |||||||||||||||||||||
(In thousands) | (In thousands) | |||||||||||||||||||||||
Electric | $ | 45,683 | $ | — | $ | 4,947 | $ | 59,966 | $ | — | $ | 11,259 | ||||||||||||
Natural gas distribution | 160,138 | — | 74 | 94,336 | — | (10,054 | ) | |||||||||||||||||
Pipeline and energy services | 66,356 | 14,143 | 9,541 | 69,300 | 11,940 | (7,370 | ) | |||||||||||||||||
272,177 | 14,143 | 14,562 | 223,602 | 11,940 | (6,165 | ) | ||||||||||||||||||
Construction services | 188,182 | 8 | 2,923 | 210,362 | 137 | 5,990 | ||||||||||||||||||
Natural gas and oil production | 84,406 | 26,400 | 24,035 | 79,276 | 27,739 | 18,717 | ||||||||||||||||||
Construction materials and contracting | 361,625 | — | 5,659 | 612,654 | — | 40,257 | ||||||||||||||||||
Other | 54 | 2,213 | 1,588 | 29 | 2,263 | 2,039 | ||||||||||||||||||
634,267 | 28,621 | 34,205 | 902,321 | 30,139 | 67,003 | |||||||||||||||||||
Intersegment eliminations | — | (42,764 | ) | — | — | (42,079 | ) | — | ||||||||||||||||
Total | $ | 906,444 | $ | — | $ | 48,767 | $ | 1,125,923 | $ | — | $ | 60,838 |
Three Months Ended June 30, 2009 | External Operating Revenues | Inter- segment Operating Revenues | Earnings on Common Stock | |||||||||||||||||||||
Inter- | ||||||||||||||||||||||||
External | segment | Earnings | ||||||||||||||||||||||
Three Months | Operating | Operating | on Common | |||||||||||||||||||||
Ended September 30, 2009 | Revenues | Revenues | Stock | |||||||||||||||||||||
(In thousands) | (In thousands) | |||||||||||||||||||||||
Electric | $ | 44,508 | $ | — | $ | 3,263 | $ | 51,922 | $ | — | $ | 10,148 | ||||||||||||
Natural gas distribution | 164,158 | — | (4,765 | ) | 97,443 | — | (9,299 | ) | ||||||||||||||||
Pipeline and energy services | 54,951 | 13,046 | 10,876 | 57,502 | 11,163 | 10,619 | ||||||||||||||||||
263,617 | 13,046 | 9,374 | 206,867 | 11,163 | 11,468 | |||||||||||||||||||
Construction services | 220,697 | 10 | 6,931 | 186,404 | 17 | 7,305 | ||||||||||||||||||
Natural gas and oil production | 84,291 | 20,488 | 20,779 | 92,675 | 16,752 | 24,363 | ||||||||||||||||||
Construction materials and contracting | 389,435 | — | 15,983 | 621,981 | — | 47,502 | ||||||||||||||||||
Other | — | 2,699 | 2,073 | — | 2,677 | 1,775 | ||||||||||||||||||
694,423 | 23,197 | 45,766 | 901,060 | 19,446 | 80,945 | |||||||||||||||||||
Intersegment eliminations | — | (36,243 | ) | — | — | (30,609 | ) | — | ||||||||||||||||
Total | $ | 958,040 | $ | — | $ | 55,140 | $ | 1,107,927 | $ | — | $ | 92,413 | ||||||||||||
Six Months Ended June 30, 2010 | External Operating Revenues | Inter- segment Operating Revenues | Earnings on Common Stock | |||||||||||||||||||||
Nine Months Ended September 30, 2010 | External Operating Revenues | Inter- segment Operating Revenues | Earnings on Common Stock | |||||||||||||||||||||
(In thousands) | (In thousands) | |||||||||||||||||||||||
Electric | $ | 95,379 | $ | — | $ | 10,832 | $ | 155,345 | $ | — | $ | 22,091 | ||||||||||||
Natural gas distribution | 509,162 | — | 23,416 | 603,499 | — | 13,362 | ||||||||||||||||||
Pipeline and energy services | 127,881 | 41,228 | 18,332 | 197,181 | 53,168 | 10,963 | ||||||||||||||||||
732,422 | 41,228 | 52,580 | 956,025 | 53,168 | 46,416 | |||||||||||||||||||
Construction services | 341,247 | 32 | 3,051 | 551,608 | 170 | 9,041 | ||||||||||||||||||
Natural gas and oil production | 156,066 | 62,327 | 46,246 | 235,342 | 90,066 | 64,963 | ||||||||||||||||||
Construction materials and contracting | 511,432 | — | (14,478 | ) | 1,124,086 | — | 25,779 | |||||||||||||||||
Other | 54 | 4,451 | 2,968 | 83 | 6,714 | 5,007 | ||||||||||||||||||
1,008,799 | 66,810 | 37,787 | 1,911,119 | 96,950 | 104,790 | |||||||||||||||||||
Intersegment eliminations | — | (108,038 | ) | — | — | (150,118 | ) | — | ||||||||||||||||
Total | $ | 1,741,221 | $ | — | $ | 90,367 | $ | 2,867,144 | $ | — | $ | 151,206 |
Six Months Ended June 30, 2009 | External Operating Revenues | Inter- segment Operating Revenues | Earnings (Loss) on Common Stock | |||||||||||||||||||||
Inter- | Earnings | |||||||||||||||||||||||
External | segment | (Loss) | ||||||||||||||||||||||
Nine Months | Operating | Operating | on Common | |||||||||||||||||||||
Ended September 30, 2009 | Revenues | Revenues | Stock | |||||||||||||||||||||
(In thousands) | (In thousands) | |||||||||||||||||||||||
Electric | $ | 95,755 | $ | — | $ | 8,329 | $ | 147,677 | $ | — | $ | 18,477 | ||||||||||||
Natural gas distribution | 647,313 | — | 19,114 | 744,758 | — | 9,815 | ||||||||||||||||||
Pipeline and energy services | 115,123 | 37,973 | 17,261 | 172,626 | 49,135 | 27,879 | ||||||||||||||||||
858,191 | 37,973 | 44,704 | 1,065,061 | 49,135 | 56,171 | |||||||||||||||||||
Construction services | 465,495 | 41 | 15,565 | 651,897 | 59 | 22,870 | ||||||||||||||||||
Natural gas and oil production | 155,450 | 55,451 | (352,537 | ) | 248,125 | 72,203 | (328,174 | ) | ||||||||||||||||
Construction materials and contracting | 572,909 | — | 330 | 1,194,889 | — | 47,832 | ||||||||||||||||||
Other | — | 5,398 | 3,104 | — | 8,075 | 4,879 | ||||||||||||||||||
1,193,854 | 60,890 | (333,538 | ) | 2,094,911 | 80,337 | (252,593 | ) | |||||||||||||||||
Intersegment eliminations | — | (98,863 | ) | — | — | (129,472 | ) | — | ||||||||||||||||
Total | $ | 2,052,045 | $ | — | $ | (288,834 | ) | $ | 3,159,972 | $ | — | $ | (196,422 | ) |
Acquisitions |
During the first |
The above |
Employee benefit plans |
The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. Components of net periodic benefit cost for the Company's pension and other postretirement benefit plans were as follows: |
Three Months | Pension Benefits | Other Postretirement Benefits | Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
Ended June 30, | 2010 | 2009 | 2010 | 2009 | ||||||||||||||||||||||||||||
Ended September 30, | 2010 | 2009 | 2010 | 2009 | ||||||||||||||||||||||||||||
(In thousands) | (In thousands) | |||||||||||||||||||||||||||||||
Components of net periodic benefit cost: | ||||||||||||||||||||||||||||||||
Service cost | $ | 501 | $ | 1,966 | $ | 374 | $ | 651 | $ | 792 | $ | 2,032 | $ | 313 | $ | 564 | ||||||||||||||||
Interest cost | 4,004 | 5,430 | 1,317 | 1,530 | 5,521 | 5,480 | 1,122 | 1,374 | ||||||||||||||||||||||||
Expected return on assets | (4,992 | ) | (5,673 | ) | (1,577 | ) | (1,544 | ) | (6,373 | ) | (6,266 | ) | (1,261 | ) | (1,287 | ) | ||||||||||||||||
Amortization of prior service cost (credit) | 31 | 151 | (915 | ) | (810 | ) | 42 | 151 | (762 | ) | (689 | ) | ||||||||||||||||||||
Amortization of net actuarial loss | 256 | 643 | 67 | 170 | 745 | 397 | 195 | 73 | ||||||||||||||||||||||||
Curtailment loss | — | 1,650 | — | — | ||||||||||||||||||||||||||||
Amortization of net transition obligation | — | — | 613 | 625 | — | — | 490 | 531 | ||||||||||||||||||||||||
Net periodic benefit cost, including amount capitalized | (200 | ) | 2,517 | (121 | ) | 622 | 727 | 3,444 | 97 | 566 | ||||||||||||||||||||||
Less amount capitalized | 107 | 484 | 37 | (23 | ) | 268 | (7 | ) | (1 | ) | 204 | |||||||||||||||||||||
Net periodic benefit cost | $ | (307 | ) | $ | 2,033 | $ | (158 | ) | $ | 645 | $ | 459 | $ | 3,451 | $ | 98 | $ | 362 | ||||||||||||||
Six Months | Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||||
Ended June 30, | 2010 | 2009 | 2010 | 2009 | ||||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
Components of net periodic benefit cost: | ||||||||||||||||||||||||||||||||
Service cost | $ | 1,305 | $ | 4,063 | $ | 731 | $ | 1,091 | ||||||||||||||||||||||||
Interest cost | 8,930 | 10,959 | 2,594 | 2,725 | ||||||||||||||||||||||||||||
Expected return on assets | (10,684 | ) | (12,530 | ) | (2,969 | ) | (2,817 | ) | ||||||||||||||||||||||||
Amortization of prior service cost (credit) | 69 | 302 | (1,779 | ) | (1,378 | ) | ||||||||||||||||||||||||||
Amortization of net actuarial loss | 1,228 | 817 | 455 | 355 | ||||||||||||||||||||||||||||
Amortization of net transition obligation | — | — | 1,145 | 1,063 | ||||||||||||||||||||||||||||
Net periodic benefit cost, including amount capitalized | 848 | 3,611 | 177 | 1,039 | ||||||||||||||||||||||||||||
Less amount capitalized | 383 | 765 | 84 | 23 | ||||||||||||||||||||||||||||
Net periodic benefit cost | $ | 465 | $ | 2,846 | $ | 93 | $ | 1,016 |
Nine Months | Pension Benefits | Other Postretirement Benefits | ||||||||||||||
Ended September 30, | 2010 | 2009 | 2010 | 2009 | ||||||||||||
(In thousands) | ||||||||||||||||
Components of net periodic benefit cost: | ||||||||||||||||
Service cost | $ | 2,097 | $ | 6,095 | $ | 1,044 | $ | 1,655 | ||||||||
Interest cost | 14,451 | 16,439 | 3,716 | 4,099 | ||||||||||||
Expected return on assets | (17,057 | ) | (18,796 | ) | (4,230 | ) | (4,104 | ) | ||||||||
Amortization of prior service cost (credit) | 111 | 453 | (2,541 | ) | (2,067 | ) | ||||||||||
Amortization of net actuarial loss | 1,973 | 1,214 | 650 | 428 | ||||||||||||
Curtailment loss | — | 1,650 | — | — | ||||||||||||
Amortization of net transition obligation | — | — | 1,635 | 1,594 | ||||||||||||
Net periodic benefit cost, including amount capitalized | 1,575 | 7,055 | 274 | 1,605 | ||||||||||||
Less amount capitalized | 651 | 758 | 83 | 227 | ||||||||||||
Net periodic benefit cost | $ | 924 | $ | 6,297 | $ | 191 | $ | 1,378 |
In 2009, the Company evaluated several provisions of its employee defined benefit plans for nonunion and certain union employees. As a result of this evaluation, the Company determined that, effective January 1, 2010, all benefit and service accruals of |
Effective January 1, 2010, eligibility to receive retiree medical benefits was modified at certain of the Company’s businesses. Current employees who attain age 55 with 10 years of continuous service by December 31, 2010, will be provided the current retiree medical insurance benefits or can elect the new benefit, if desired, regardless of when they retire. All other current employees must meet the new eligibility criteria of age 60 and 10 years of continuous service at the time they retire. These employees will be eligible for a specified company funded Retiree Reimbursement Account. Employees hired after December 31, 2009, are not eligible for retiree medical benefits. |
In addition to the qualified plan defined pension benefits reflected in the table, the Company 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 |
Regulatory matters and revenues subject to refund |
In November 2006, Montana-Dakota filed an application with the NDPSC requesting an advance determination of prudence of Montana-Dakota's ownership interest in Big Stone Station II. In August 2008, the NDPSC approved Montana-Dakota’s request for advance determination of prudence for ownership in the proposed Big Stone Station II for a minimum of 121.8 MW up to a maximum of 133 MW and a proportionate ownership share |
of the associated transmission electric resources. The intervenors in the proceeding appealed the NDPSC order to the North Dakota District Court which affirmed the order of the NDPSC. The intervenors then appealed the North Dakota District Court order to the North Dakota Supreme Court. The Big Stone Station II participants subsequently decided not to proceed with the project and in December 2009, Montana-Dakota filed an application with the NDPSC for a determination that |
In August 2009, Montana-Dakota filed an application with the WYPSC for an electric rate increase. Montana-Dakota requested a total increase of $6.2 million annually or approximately 31 percent above current rates. The rate increase request was necessitated by Montana-Dakota’s purchase of an ownership interest in Wygen III. On January 14, 2010, Montana-Dakota filed a supplement to the application to reflect the inclusion of bonus tax depreciation on Wygen III, reducing its request to a $5.1 million annual increase or approximately 25 percent above current rates. A hearing was held February 23 through February 25, 2010. A stipulation and agreement between Montana-Dakota and the Wyoming Office of Consumer Advocate was filed with the WYPSC on March 5, 2010, that provides a $3.3 million annual increase to be phased-in over a three-year period beginning May 1, 2010. The WYPSC held a hearing on the stipulation on March 22, 2010, and held additional deliberations on April 14, 2010, wherein the WYPSC decided on each issue in the case and Montana-Dakota was directed to file a compliance filing. Montana-Dakota submitted the compliance filing on April 23, 2010, reflecting an increase of $2.7 million annually or approximately 13.1 percent. On April 27, 2010, the WYPSC approved the compliance filing with rates effective May 1, 2010. On June 25, 2010, Montana-Dakota filed a Petition for Rehearing on the return on equity specified in the WYPSC’s order. On July 14, 2010, the WYPSC |
On April 19, 2010, Montana-Dakota filed an application with the NDPSC for an electric rate increase. Montana-Dakota requested a total increase of $15.4 million annually or approximately 14 percent above current rates. The requested increase includes the investment in infrastructure upgrades, recovery of the investment in renewable generation and the costs associated with Big Stone Station II. On June 16, 2010, the NDPSC approved an interim increase of $7.6 million effective with service rendered June 18, 2010. On June 16, 2010, Montana-Dakota and the NDPSC Advocacy Staff filed a partial settlement agreement agreeing to an overall rate of return and a sharing of earnings over a specified |
return on equity. On July 6, 2010, Montana-Dakota filed an amendment to its application to exclude the deferred generation development costs associated with Big Stone Station II because of a |
On August 12, 2010, Montana-Dakota filed an application with the MTPSC for an electric rate increase. Montana-Dakota requested a total increase of $5.5 million annually or approximately 13 percent above current rates. The requested increase includes the investment in infrastructure upgrades, recovery of the investment in renewable generation, the costs associated with Big Stone Station II and the significant loss of wholesale sales margins. Montana-Dakota requested an interim increase of $3.1 million or approximately 7.4 percent, which is pending before the MTPSC. A hearing has been set for February 28, 2011. |
18. | Contingencies |
Litigation |
Coalbed Natural Gas Operations Fidelity’s CBNG operations are and have been the subject of numerous lawsuits in Montana and Wyoming. The current cases involve the permitting and use of water produced in connection with Fidelity’s CBNG development in the Powder River Basin. Some of these cases challenge the issuance of discharge permits by the Montana DEQ and approval of other water management tools by the MBOGC. |
In April 2006, the Northern Cheyenne Tribe filed a complaint in Montana Twenty-Second Judicial District Court against the Montana DEQ seeking to set aside Fidelity’s direct discharge and treatment permits. The Northern Cheyenne Tribe claimed the Montana DEQ violated the Clean Water Act and the Montana Water Quality Act by failing to include in the permits conditions requiring application of the best practicable control technology currently available and by failing to impose a nondegradation policy like the one the BER adopted soon after the permit was issued. In addition, the Northern Cheyenne Tribe claimed that the actions of the Montana DEQ violated the Montana State Constitution’s guarantee of a clean and healthful environment, that the Montana DEQ’s related environmental assessment was invalid, that the Montana DEQ was required, but failed, to prepare an EIS and that the Montana DEQ failed to consider other alternatives to the issuance of the permits. Fidelity, the NPRC, and the TRWUA were granted leave to intervene in this proceeding. In January 2009, the Montana Twenty-Second Judicial District Court decided the case in favor of Fidelity and the Montana DEQ in all |
which time Fidelity may continue to operate under its current permits. On June 2, 2010, Fidelity filed a motion with the Montana Supreme Court requesting the court to allow the Montana DEQ an additional 90 days to complete its reevaluation of Fidelity’s discharge permits. On June 29, 2010, the Montana Supreme Court granted a one-time extension allowing the Montana DEQ until November 14, 2010, to complete the permitting process. |
In October 2003, Tongue & Yellowstone Irrigation District, NPRC and MEIC filed a lawsuit in Montana First Judicial District Court challenging the MBOGC’s ROD adopting the 2003 Final EIS which analyzed CBNG development in Montana. The primary legal issue before the court was whether the ROD authorized the “wasting” of ground water in violation of the Montana State Constitution and the public trust doctrine. Specifically, the plaintiffs contended that various water management tools, including Fidelity’s direct discharge permits, allowed for the waste of water. On March 5, 2010, the Montana First Judicial District Court issued an order holding that Fidelity’s direct discharge permits did not violate the Montana State |
Fidelity will continue to vigorously defend its interests in all CBNG-related litigation in which it is involved. |
Electric Operations In June 2008, the Sierra Club filed a complaint in the South Dakota Federal District Court against Montana-Dakota and the two other co-owners of the Big Stone Station. The complaint alleged certain violations of the PSD and NSPS provisions of the Clean Air Act and certain violation of the South Dakota SIP. The action further alleged that the Big Stone Station was modified and operated without obtaining the appropriate permits, without meeting certain emissions limits and NSPS requirements and without installing appropriate emission control technology, all allegedly in violation of the Clean Air Act and the South Dakota SIP. The Sierra Club alleged that these actions contributed to air pollution and visibility impairment and have increased the risk of adverse health effects and environmental damage. The Sierra Club sought declaratory and injunctive relief to bring the co-owners of the Big Stone Station into compliance with the Clean Air Act and the South Dakota SIP and to require them to remedy the alleged violations. The Sierra Club also sought unspecified civil penalties, including a beneficial mitigation project. The Company believes the claims are without merit and that Big Stone Station has been and is being operated in compliance with the Clean Air Act and the South Dakota SIP. In March 2009, the District Court granted the motion of the co-owners to dismiss the complaint. The Sierra Club filed a motion requesting the District Court to reconsider its ruling on a portion of the order dismissing the complaint which was denied on July 22, 2009. On July 30, 2009, the Sierra Club appealed from the orders dismissing the case and denying the motion for reconsideration to the United States Court of Appeals for the Eighth Circuit. The United States |
the State of South Dakota filed a brief as amicus curiae supporting the Big Stone Station owners’ position in the appeal. |
Guarantee Obligation Under a Construction Contract Centennial guaranteed CEM's obligations under a construction contract with LPP for a 550-MW combined-cycle electric generating facility near Hobbs, New Mexico. Centennial Resources sold CEM in July 2007 to Bicent Power LLC, which provided a $10 million bank letter of credit to Centennial in support of the guarantee obligation, which expired November 1, 2010. In February 2009, Centennial received a Notice and Demand from LPP under the guaranty agreement alleging that CEM did not meet certain of its obligations under the construction contract and demanding that Centennial indemnify LPP against all losses, damages, claims, costs, charges and expenses arising from CEM’s alleged failures. In December 2009, LPP submitted a demand for arbitration of its dispute with CEM to the American Arbitration Association. The demand seeks compensatory damages of $146 million plus damages for increased operating, capital and construction costs related to a water treatment facility for the generating facility. LPP’s notice of demand for arbitration also demanded performance of the guarantee by Centennial. In June 2010, CEM and Bicent Power LLC made a demand on |
Construction Materials LTM is a defendant in litigation pending in Oregon Circuit Court regarding the concrete floors in an industrial food processing facility located in Jackson County, Oregon. The plaintiffs assert claims against LTM, which supplied the concrete for the floors, and others that the concrete floors of the facility are defective and must be removed and replaced for suitable repair. Damages, including disruption of the food processing operations, have been estimated by the plaintiffs to be approximately $26.5 million. Discovery is currently being conducted by the parties. A trial date has been scheduled for April 5, 2011. LTM believes the concrete it supplied met the specifications for the concrete floor and that any defects are a result of the specificati ons provided by the owner or its representatives or the fault of others. |
In 2009, LTM provided pavement work under a subcontract for reconstruction at the Klamath Falls Airport owned by the City of Klamath Falls, Oregon. On October 15, 2010, the City of Klamath Falls filed a complaint against the project’s general contractor alleging the work performed by LTM is defective. Damages, including removal and replacement of the paved runway, are estimated by the plaintiff as $6.0 million to $11.0 million. LTM believes its work met the specifications of the subcontract and expects to receive and accept the tender of defense of the claim. |
Natural Gas Gathering Operations On January 11, 2010, SourceGas Distribution LLC filed an application with the Colorado State District Court to compel Bitter Creek to arbitrate a dispute regarding operating pressures under a natural gas gathering contract on one of Bitter Creek’s pipeline systems in Montana. Bitter Creek resisted the application and sought a declaratory order interpreting the gathering contract. On May 28, 2010, the Colorado State District Court granted the application and ordered Bitter Creek into arbitration. An arbitration hearing was held August 23 – 31, 2010. On October 15, 2010, Bitter Creek was notified that the arbitration panel issued an award in favor of SourceGas Distribution LLC for approximately $ 26.6 million. As a result, Bitter Creek, which is included in the pipeline and energy services segment, recorded a $26.6 million charge ($16.5 million after tax) in the third quarter of 2010, which is recorded in operation and maintenance expense on the Consolidated Statement of Income. Bitter Creek is assessing all legal remedies available to challenge the outcome of the award. |
The Company also is involved in other legal actions in the ordinary course of its business. Although the outcomes of any such legal actions cannot be predicted, management believes that the outcomes with respect to these other legal proceedings will not have a material adverse effect upon the Company’s financial position or results of operations. |
Environmental matters |
Portland Harbor Site In December 2000, MBI was named by the EPA as a PRP in connection with the cleanup of a riverbed site adjacent to a commercial property site acquired by MBI from Georgia-Pacific West, Inc. in 1999. The riverbed site is part of the Portland, Oregon, Harbor Superfund Site. The EPA wants responsible parties to share in the cleanup of sediment contamination in the Willamette River. To date, costs of the overall remedial investigation and feasibility study of the harbor site are being recorded, and initially paid, through an administrative consent order by the LWG, a group of several entities, which does not include MBI or Georgia-Pacific West, Inc. Investigative costs are indicated to be in excess of $70 million. It is not possible to estimate the cost of a corrective action plan until the remedial investigation and fe asibility study have been completed, the EPA has decided on a strategy and a ROD has been published. Corrective action will be taken after the development of a proposed plan and ROD on the harbor site is issued. MBI also received notice in January 2008 that the Portland Harbor Natural Resource Trustee Council intends to perform an injury assessment to natural resources resulting from the release of hazardous substances at the Harbor Superfund Site. The Trustee Council indicates the injury determination is appropriate to facilitate early settlement of damages and restoration for natural resource injuries. It is not possible to estimate the costs of natural resource damages until an assessment is completed and allocations are undertaken. |
Based upon a review of the Portland Harbor sediment contamination evaluation by the Oregon DEQ and other information available, MBI does not believe it is a Responsible Party. In addition, MBI has notified Georgia-Pacific West, Inc., that it intends to seek indemnity for liabilities incurred in relation to the above matters pursuant to the terms of their sale agreement. MBI has entered into an agreement tolling the statute of limitations in connection with the LWG’s potential claim for contribution to the costs of the remedial investigation and feasibility study. By letter in March 2009, LWG stated its intent to file suit against MBI and others to recover LWG’s investigation costs to the extent MBI cannot |
demonstrate its non-liability for the contamination or is unwilling to participate in an alternative dispute resolution process that has been established to address the matter. At this time, MBI has |
The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above referenced administrative action. |
Manufactured Gas Plant Sites There are three claims against Cascade for cleanup of environmental contamination at manufactured gas plant sites operated by Cascade’s predecessors. |
The first claim is for soil and groundwater contamination at a site in Oregon and was received in 1995. There are PRPs in addition to Cascade that may be liable for cleanup of the contamination. Some of these PRPs have shared in the investigation costs. It is expected that these and other PRPs will share in the cleanup costs. Several alternatives for cleanup have been identified, with preliminary cost estimates ranging from approximately $500,000 to $11.0 million. An ecological risk assessment draft report was submitted to the Oregon DEQ in June 2009. The assessment showed no unacceptable risk to the aquatic ecological receptors present in the shoreline along the site and concluded that no further ecological investigation is necessary. The report is being reviewed by the Oregon DEQ. It is anticipated the Oregon DEQ will recommend a cleanup alternative for the site after it completes its review of the report. I t is not known at this time what share of the cleanup costs will actually be borne by Cascade. |
The second claim is for contamination at a site in Washington and was received in 1997. A preliminary investigation has found soil and groundwater at the site contain contaminants requiring further investigation and cleanup. EPA conducted a Targeted Brownfields Assessment of the site and released a report summarizing the results of that assessment in August 2009. The assessment confirms that contaminants have affected soil and groundwater at the site, as well as sediments in the adjacent Port Washington Narrows. Alternative remediation options have been identified with preliminary cost estimates ranging from $340,000 to $6.4 million. Data developed through the assessment and previous investigations indicates the contamination likely derived from multiple, different sources and multiple current and former owners of properties and businesses in the vicinity of the site may be responsible for the contamination. C ascade received notice in April 2010, that the Washington Department of Ecology has determined that Cascade is a PRP for release of hazardous substances at the site. On October 18, 2010, Cascade received notice from the United States Coast Guard that a hazardous substance appearing to be manufactured gas plant waste was released into the waterway from an abandoned pipe located on the shoreline in the vicinity of the former manufactured gas plant. Cascade subsequently received an administrative order from the United States Coast Guard requiring Cascade to remove the abandoned pipe and conduct other associated time-critical actions. Cascade agreed to remove the pipe and perform the other time-critical actions pursuant to a work plan approved by the United States Coast Guard. It is expected that subsequent remedial action at the site will be conducted under the oversight of the EPA. Cascade has reserved $6.4 million for remediation of this site. On April 9, 2010, Cascade filed a petition with the WUTC for authority to defer the costs, which are included in other noncurrent assets, incurred in relation to the environmental remediation of this site until the next general rate case. The |
WUTC approved the petition on September 16, 2010, subject to conditions set forth in the order. |
The third claim is also for contamination at a site in Washington. Cascade received notice from a party in May 2008 that Cascade may be a PRP, along with other parties, for contamination from a manufactured gas plant owned by Cascade and its predecessor from about 1946 to 1962. The notice indicates that current estimates to complete investigation and cleanup of the site exceed $8.0 million. Other PRPs have reached an agreed order and work plan with the Washington Department of Ecology for completion of a remedial investigation and feasibility study for the site. The remediation investigation and feasibility study report are expected to be completed by late 2011. There is currently not enough information available to estimate the potential liability to Cascade associated with this claim. |
To the extent these claims are not covered by insurance, Cascade will seek recovery through the OPUC and WUTC of remediation costs in its natural gas rates charged to customers. |
Guarantees |
In connection with the sale of MPX in June 2005 to Petrobras, an indirect wholly owned subsidiary of the Company has agreed to indemnify Petrobras for 49 percent of any losses that Petrobras may incur from certain contingent liabilities specified in the purchase agreement. Centennial has agreed to |
Centennial guaranteed CEM's obligations under a construction |
In connection with the pending sale of the Brazilian Transmission Lines, as discussed in Note |
Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company. These guarantees are related to construction contracts, natural gas transportation and sales agreements, gathering contracts, a conditional purchase agreement and certain other guarantees. At |
Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies, natural gas transportation agreements and other agreements that guarantee the performance of other subsidiaries of the Company. At |
WBI Holdings has an outstanding guarantee to Williston Basin. This guarantee is related to a natural gas transportation and storage agreement that guarantees the performance of Prairielands. At |
In addition, Centennial and Knife River have issued guarantees to third parties related to the Company’s routine purchase of maintenance items, materials and lease obligations for which no fixed maximum amounts have been specified. These guarantees have no scheduled maturity date. In the event a subsidiary of the Company defaults under its obligation in relation to the purchase of certain maintenance items, materials or lease obligations, Centennial or Knife River would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these maintenance items and materials were reflected on the Consolidated Balance Sheet at |
In the normal course of business, Centennial has purchased surety bonds related to construction contracts and reclamation obligations of its subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the |
future. As of |
19. | Subsequent event |
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
· | Organic growth as well as a continued disciplined approach to the acquisition of well-managed companies and properties |
· | The elimination of system-wide cost redundancies through increased focus on integration of operations and standardization and consolidation of various support services and functions across companies within the organization |
· | The development of projects that are accretive to earnings per share and return on invested capital |
Three Months Ended | Six Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | September 30, | September 30, | |||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
(Dollars in millions, where applicable) | (Dollars in millions, where applicable) | |||||||||||||||||||||||||||||||
Electric | $ | 5.0 | $ | 3.2 | $ | 10.8 | $ | 8.3 | $ | 11.3 | $ | 10.1 | $ | 22.1 | $ | 18.5 | ||||||||||||||||
Natural gas distribution | .1 | (4.8 | ) | 23.4 | 19.1 | (10.1 | ) | (9.3 | ) | 13.4 | 9.8 | |||||||||||||||||||||
Construction services | 2.9 | 6.9 | 3.1 | 15.6 | 6.0 | 7.3 | 9.0 | 22.9 | ||||||||||||||||||||||||
Pipeline and energy services | 9.5 | 10.9 | 18.3 | 17.3 | (7.4 | ) | 10.6 | 10.9 | 27.9 | |||||||||||||||||||||||
Natural gas and oil production | 24.0 | 20.8 | 46.3 | (352.5 | ) | 18.7 | 24.4 | 65.0 | (328.2 | ) | ||||||||||||||||||||||
Construction materials and contracting | 5.7 | 16.0 | (14.5 | ) | .3 | 40.3 | 47.5 | 25.8 | 47.8 | |||||||||||||||||||||||
Other | 1.6 | 2.1 | 3.0 | 3.1 | 2.0 | 1.8 | 5.0 | 4.9 | ||||||||||||||||||||||||
Earnings (loss) on common stock | $ | 48.8 | $ | 55.1 | $ | 90.4 | $ | (288.8 | ) | $ | 60.8 | $ | 92.4 | $ | 151.2 | $ | (196.4 | ) | ||||||||||||||
Earnings (loss) per common share – basic | $ | .26 | $ | .30 | $ | .48 | $ | (1.57 | ) | $ | .32 | $ | .50 | $ | .80 | $ | (1.07 | ) | ||||||||||||||
Earnings (loss) per common share – diluted | $ | .26 | $ | .30 | $ | .48 | $ | (1.57 | ) | $ | .32 | $ | .50 | $ | .80 | $ | (1.07 | ) | ||||||||||||||
Return on average common equity for the 12 months ended | 10.0 | % | (6.9 | )% | 8.6 | % | (8.1 | )% |
· | Higher operation and maintenance expense, primarily due to a natural gas gathering arbitration charge of $16.5 million (after tax) at the pipeline and energy services business |
· | Lower |
· |
· | Absence of the 2009 noncash write-down of natural gas and oil properties of $384.4 million (after tax), higher average realized oil prices |
· | Lower |
· | Higher operation and maintenance expense, primarily due to a natural gas gathering arbitration charge of $16.5 million (after tax) and lower gathering volumes, partially offset by higher storage services revenue at the pipeline and energy services business |
· | Lower construction workloads and margins in the Southwest and Central regions, partially offset by lower general and administrative expense and higher construction workloads and margins in the Mountain region at the construction services business |
Three Months Ended | Six Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | September 30, | September 30, | |||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
(Dollars in millions, where applicable) | (Dollars in millions, where applicable) | |||||||||||||||||||||||||||||||
Operating revenues | $ | 45.7 | $ | 44.5 | $ | 95.4 | $ | 95.8 | $ | 60.0 | $ | 51.9 | $ | 155.3 | $ | 147.7 | ||||||||||||||||
Operating expenses: | ||||||||||||||||||||||||||||||||
Fuel and purchased power | 13.1 | 15.2 | 30.0 | 33.9 | 15.3 | 15.2 | 45.3 | 49.1 | ||||||||||||||||||||||||
Operation and maintenance | 16.2 | 15.9 | 31.4 | 31.5 | 15.7 | 13.8 | 47.0 | 45.3 | ||||||||||||||||||||||||
Depreciation, depletion and amortization | 6.1 | 6.0 | 11.9 | 12.2 | 7.6 | 6.1 | 19.5 | 18.2 | ||||||||||||||||||||||||
Taxes, other than income | 2.2 | 2.3 | 4.8 | 4.7 | 2.2 | 2.2 | 7.0 | 7.0 | ||||||||||||||||||||||||
37.6 | 39.4 | 78.1 | 82.3 | 40.8 | 37.3 | 118.8 | 119.6 | |||||||||||||||||||||||||
Operating income | 8.1 | 5.1 | 17.3 | 13.5 | 19.2 | 14.6 | 36.5 | 28.1 | ||||||||||||||||||||||||
Earnings | $ | 5.0 | $ | 3.2 | $ | 10.8 | $ | 8.3 | $ | 11.3 | $ | 10.1 | $ | 22.1 | $ | 18.5 | ||||||||||||||||
Retail sales (million kWh) | 615.2 | 595.3 | 1,365.0 | 1,320.1 | 692.0 | 655.0 | 2,057.0 | 1,975.2 | ||||||||||||||||||||||||
Sales for resale (million kWh) | 7.6 | 22.8 | 37.4 | 32.5 | 13.8 | 11.7 | 51.1 | 44.1 | ||||||||||||||||||||||||
Average cost of fuel and purchased power per kWh | $ | .020 | $ | .023 | $ | .020 | $ | .024 | $ | .021 | $ | .022 | $ | .021 | $ | .023 |
· | Higher electric retail sales margins, primarily due to |
· | Higher retail sales volumes of |
· | Lower other income of $1.4 million (after tax), primarily allowance for funds used during construction related to electric generation projects, which were placed in service in 2010 |
· | Higher operation and maintenance expense of $1.1 million (after tax), primarily higher contract services due to storm damage; as well as expenses at Wygen III, which commenced operation in the second quarter of 2010 |
· | Increased depreciation, depletion and amortization expense of $900,000 (after tax), including the effects of higher property, plant and equipment balances |
· | Higher net interest expense of $700,000 (after tax), resulting from lower capitalized interest and higher average borrowings |
· | Higher operation and maintenance expense of $1.0 million (after tax), primarily increased materials expense and higher contract services |
· | Higher net interest expense of $900,000 (after tax), resulting from higher average borrowings |
· | Increased depreciation, depletion and amortization expense of $700,000 (after tax), as previously discussed |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(Dollars in millions, where applicable) | ||||||||||||||||
Operating revenues | $ | 94.3 | $ | 97.4 | $ | 603.5 | $ | 744.8 | ||||||||
Operating expenses: | ||||||||||||||||
Purchased natural gas sold | 50.1 | 55.6 | 394.3 | 529.0 | ||||||||||||
Operation and maintenance | 35.7 | 31.6 | 102.8 | 105.3 | ||||||||||||
Depreciation, depletion and amortization | 10.8 | 10.8 | 32.1 | 32.1 | ||||||||||||
Taxes, other than income | 7.5 | 7.3 | 34.5 | 41.5 | ||||||||||||
104.1 | 105.3 | 563.7 | 707.9 | |||||||||||||
Operating income (loss) | (9.8 | ) | (7.9 | ) | 39.8 | 36.9 | ||||||||||
Earnings (loss) | $ | (10.1 | ) | $ | (9.3 | ) | $ | 13.4 | $ | 9.8 | ||||||
Volumes (MMdk): | ||||||||||||||||
Sales | 7.9 | 7.5 | 61.6 | 65.2 | ||||||||||||
Transportation | 35.4 | 38.2 | 98.7 | 95.6 | ||||||||||||
Total throughput | 43.3 | 45.7 | 160.3 | 160.8 | ||||||||||||
Degree days (% of normal)* | ||||||||||||||||
Montana-Dakota | 69 | % | 30 | % | 97 | % | 103 | % | ||||||||
Cascade | 109 | % | 80 | % | 96 | % | 105 | % | ||||||||
Intermountain | 105 | % | 103 | % | 103 | % | 104 | % | ||||||||
Average cost of natural gas, including transportation, per dk | $ | 6.34 | $ | 7.39 | $ | 6.40 | $ | 8.11 | ||||||||
*Degree days are a measure of the daily temperature-related demand for energy for heating. |
· | Higher operation and maintenance expense of $1.1 million (after tax), largely associated with operational integration costs, partially offset by lower bad debt expense |
· | Decreased retail sales margins, primarily due to weather normalization and conservation adjustments, partially offset by increased retail sales volumes, largely resulting from colder weather than last year in the Northwest |
· |
· | Lower net interest expense, primarily due to lower average borrowings and higher capitalized interest |
· | Increased transportation volumes of $1.0 million (after tax), primarily industrial customers |
· | Higher other income of $900,000 (after tax), primarily allowance for funds used during construction |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(Dollars in millions, where applicable) | ||||||||||||||||
Operating revenues | $ | 160.1 | $ | 164.1 | $ | 509.2 | $ | 647.3 | ||||||||
Operating expenses: | ||||||||||||||||
Purchased natural gas sold | 98.9 | 107.5 | 344.1 | 473.5 | ||||||||||||
Operation and maintenance | 34.4 | 35.5 | 67.1 | 73.6 | ||||||||||||
Depreciation, depletion and amortization | 10.7 | 10.6 | 21.4 | 21.3 | ||||||||||||
Taxes, other than income | 10.5 | 11.3 | 27.0 | 34.2 | ||||||||||||
154.5 | 164.9 | 459.6 | 602.6 | |||||||||||||
Operating income (loss) | 5.6 | �� | (.8 | ) | 49.6 | 44.7 | ||||||||||
Earnings (loss) | $ | .1 | $ | (4.8 | ) | $ | 23.4 | $ | 19.1 | |||||||
Volumes (MMdk): | ||||||||||||||||
Sales | 15.6 | 14.1 | 53.7 | 57.7 | ||||||||||||
Transportation | 28.9 | 23.4 | 63.4 | 57.4 | ||||||||||||
Total throughput | 44.5 | 37.5 | 117.1 | 115.1 | ||||||||||||
Degree days (% of normal)* | ||||||||||||||||
Montana-Dakota | 96 | % | 119 | % | 98 | % | 106 | % | ||||||||
Cascade | 118 | % | 100 | % | 95 | % | 105 | % | ||||||||
Intermountain | 132 | % | 103 | % | 103 | % | 105 | % | ||||||||
Average cost of natural gas, including transportation, per dk | $ | 6.33 | $ | 7.61 | $ | 6.41 | $ | 8.20 | ||||||||
*Degree days are a measure of the daily temperature-related demand for energy for heating. |
· | Higher nonregulated energy-related services of |
Three Months Ended | Six Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | September 30, | September 30, | |||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
(In millions) | (In millions) | |||||||||||||||||||||||||||||||
Operating revenues | $ | 188.2 | $ | 220.7 | $ | 341.3 | $ | 465.5 | $ | 210.5 | $ | 186.4 | $ | 551.8 | $ | 651.9 | ||||||||||||||||
Operating expenses: | ||||||||||||||||||||||||||||||||
Operation and maintenance | 173.2 | 199.2 | 315.0 | 416.4 | 191.1 | 166.1 | 506.1 | 582.5 | ||||||||||||||||||||||||
Depreciation, depletion and amortization | 3.1 | 3.3 | 6.3 | 6.7 | 2.9 | 3.2 | 9.2 | 10.0 | ||||||||||||||||||||||||
Taxes, other than income | 6.1 | 6.4 | 12.6 | 16.0 | 5.8 | 5.2 | 18.4 | 21.1 | ||||||||||||||||||||||||
182.4 | 208.9 | 333.9 | 439.1 | 199.8 | 174.5 | 533.7 | 613.6 | |||||||||||||||||||||||||
Operating income | 5.8 | 11.8 | 7.4 | 26.4 | 10.7 | 11.9 | 18.1 | 38.3 | ||||||||||||||||||||||||
Earnings | $ | 2.9 | $ | 6.9 | $ | 3.1 | $ | 15.6 | $ | 6.0 | $ | 7.3 | $ | 9.0 | $ | 22.9 |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(Dollars in millions) | ||||||||||||||||
Operating revenues | $ | 80.5 | $ | 68.0 | $ | 169.1 | $ | 153.1 | ||||||||
Operating expenses: | ||||||||||||||||
Purchased natural gas sold | 35.3 | 28.1 | 82.8 | 74.2 | ||||||||||||
Operation and maintenance | 17.8 | 11.1 | 33.0 | 28.8 | ||||||||||||
Depreciation, depletion and amortization | 6.5 | 6.2 | 12.9 | 12.3 | ||||||||||||
Taxes, other than income | 3.2 | 3.0 | 6.2 | 5.9 | ||||||||||||
62.8 | 48.4 | 134.9 | 121.2 | |||||||||||||
Operating income | 17.7 | 19.6 | 34.2 | 31.9 | ||||||||||||
Earnings | $ | 9.5 | $ | 10.9 | $ | 18.3 | $ | 17.3 | ||||||||
Transportation volumes (MMdk): | ||||||||||||||||
Montana-Dakota | 7.3 | 10.2 | 14.9 | 18.5 | ||||||||||||
Other | 37.0 | 33.6 | 59.9 | 62.4 | ||||||||||||
44.3 | 43.8 | 74.8 | 80.9 | |||||||||||||
Gathering volumes (MMdk) | 19.3 | 24.3 | 38.4 | 48.6 |
· | Higher |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(Dollars in millions, where applicable) | ||||||||||||||||
Operating revenues: | ||||||||||||||||
Natural gas | $ | 55.2 | $ | 69.2 | $ | 112.8 | $ | 150.9 | ||||||||
Oil | 55.6 | 35.6 | 105.6 | 60.0 | ||||||||||||
110.8 | 104.8 | 218.4 | 210.9 | |||||||||||||
Operating expenses: | ||||||||||||||||
Operation and maintenance: | ||||||||||||||||
Lease operating costs | 16.3 | 18.0 | 32.1 | 38.0 | ||||||||||||
Gathering and transportation | 5.9 | 6.1 | 11.8 | 12.2 | ||||||||||||
Other | 8.8 | 10.7 | 17.4 | 21.0 | ||||||||||||
Depreciation, depletion and amortization | 32.5 | 30.2 | 62.1 | 72.8 | ||||||||||||
Taxes, other than income: | ||||||||||||||||
Production and property taxes | 9.0 | 5.7 | 18.5 | 13.2 | ||||||||||||
Other | .1 | .2 | .5 | .4 | ||||||||||||
Write-down of natural gas and oil properties | — | — | — | 620.0 | ||||||||||||
72.6 | 70.9 | 142.4 | 777.6 | |||||||||||||
Operating income (loss) | 38.2 | 33.9 | 76.0 | (566.7 | ) | |||||||||||
Earnings (loss) | $ | 24.0 | $ | 20.8 | $ | 46.3 | $ | (352.5 | ) | |||||||
Production: | ||||||||||||||||
Natural gas (MMcf) | 12,809 | 14,297 | 25,052 | 29,698 | ||||||||||||
Oil (MBbls) | 831 | 771 | 1,592 | 1,513 | ||||||||||||
Total Production (MMcf equivalent) | 17,794 | 18,923 | 34,602 | 38,775 | ||||||||||||
Average realized prices (including hedges): | ||||||||||||||||
Natural gas (per Mcf) | $ | 4.31 | $ | 4.84 | $ | 4.50 | $ | 5.08 | ||||||||
Oil (per barrel) | $ | 66.88 | $ | 46.21 | $ | 66.36 | $ | 39.67 | ||||||||
Average realized prices (excluding hedges): | ||||||||||||||||
Natural gas (per Mcf) | $ | 3.30 | $ | 2.40 | $ | 3.92 | $ | 3.04 | ||||||||
Oil (per barrel) | $ | 67.21 | $ | 47.46 | $ | 66.83 | $ | 40.30 | ||||||||
Average depreciation, depletion and amortization rate, per equivalent Mcf | $ | 1.74 | $ | 1.52 | $ | 1.71 | $ | 1.80 | ||||||||
Production costs, including taxes, per net equivalent Mcf: | ||||||||||||||||
Lease operating costs | $ | .91 | $ | .95 | $ | .93 | $ | .98 | ||||||||
Gathering and transportation | .33 | .32 | .34 | .31 | ||||||||||||
Production and property taxes | .51 | .30 | .53 | .34 | ||||||||||||
$ | 1.75 | $ | 1.57 | $ | 1.80 | $ | 1.63 |
· | Lower general and administrative expense of $1.3 million (after tax), largely lower payroll-related costs and lower bad debt expense |
· | Lower general and administrative expense of $7.8 million (after tax), as previously discussed |
· | Higher construction workloads and margins in the Mountain region |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(Dollars in millions) | ||||||||||||||||
Operating revenues | $ | 81.2 | $ | 68.7 | $ | 250.3 | $ | 221.8 | ||||||||
Operating expenses: | ||||||||||||||||
Purchased natural gas sold | 36.8 | 25.7 | 119.5 | 100.0 | ||||||||||||
Operation and maintenance | 44.2 | * | 14.0 | 77.2 | * | 42.8 | ||||||||||
Depreciation, depletion and amortization | 6.5 | 6.6 | 19.4 | 18.8 | ||||||||||||
Taxes, other than income | 3.2 | 3.0 | 9.5 | 8.9 | ||||||||||||
90.7 | 49.3 | 225.6 | 170.5 | |||||||||||||
Operating income (loss) | (9.5 | ) | 19.4 | 24.7 | �� | 51.3 | ||||||||||
Earnings (loss) | $ | (7.4 | ) | $ | 10.6 | $ | 10.9 | $ | 27.9 | |||||||
Transportation volumes (MMdk) | 33.6 | 41.2 | 108.4 | 122.2 | ||||||||||||
Gathering volumes (MMdk) | 19.3 | 22.7 | 57.7 | 71.3 | ||||||||||||
Customer natural gas storage balance (MMdk): | ||||||||||||||||
Beginning balance** | 64.2 | 41.6 | 61.5 | 30.6 | ||||||||||||
Net injection | 9.6 | 19.4 | 12.3 | 30.4 | ||||||||||||
Ending balance | 73.8 | 61.0 | 73.8 | 61.0 | ||||||||||||
* Reflects a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax). ** As of the beginning of the applicable period. |
· | Higher operation and maintenance expense, primarily due to a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax), as discussed in Note 18 and higher legal-related costs |
· | Decreased |
· | Lower gathering volumes of $900,000 (after tax) |
· | Higher operation and maintenance expense, largely resulting from a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax), as previously discussed, as well as the absence of the settlement of the natural gas storage litigation, which lowered expense last year |
· | Lower gathering volumes of $3.5 million (after tax) |
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(Dollars in millions, where applicable) | ||||||||||||||||
Operating revenues: | ||||||||||||||||
Natural gas | $ | 54.9 | $ | 67.3 | $ | 167.7 | $ | 218.2 | ||||||||
Oil | 52.1 | 42.1 | 157.7 | 102.1 | ||||||||||||
107.0 | 109.4 | 325.4 | 320.3 | |||||||||||||
Operating expenses: | ||||||||||||||||
Operation and maintenance: | ||||||||||||||||
Lease operating costs | 19.4 | 16.3 | 51.5 | 54.2 | ||||||||||||
Gathering and transportation | 5.9 | 6.1 | 17.6 | 18.3 | ||||||||||||
Other | 7.5 | 7.9 | 24.9 | 29.0 | ||||||||||||
Depreciation, depletion and amortization | 34.1 | 29.1 | 96.4 | 101.9 | ||||||||||||
Taxes, other than income: | ||||||||||||||||
Production and property taxes | 8.1 | 8.1 | 26.6 | 21.2 | ||||||||||||
Other | .2 | .1 | .7 | .6 | ||||||||||||
Write-down of natural gas and oil properties | — | — | — | 620.0 | ||||||||||||
75.2 | 67.6 | 217.7 | 845.2 | |||||||||||||
Operating income (loss) | 31.8 | 41.8 | 107.7 | (524.9 | ) | |||||||||||
Earnings (loss) | $ | 18.7 | $ | 24.4 | $ | 65.0 | $ | (328.2 | ) | |||||||
Production: | ||||||||||||||||
Natural gas (MMcf) | 12,686 | 13,657 | 37,738 | 43,355 | ||||||||||||
Oil (MBbls) | 835 | 807 | 2,427 | 2,320 | ||||||||||||
Total Production (MMcf equivalent) | 17,696 | 18,502 | 52,298 | 57,277 | ||||||||||||
Average realized prices (including hedges): | ||||||||||||||||
Natural gas (per Mcf) | $ | 4.33 | $ | 4.93 | $ | 4.44 | $ | 5.03 | ||||||||
Oil (per Bbl) | $ | 62.41 | $ | 52.13 | $ | 65.00 | $ | 44.00 | ||||||||
Average realized prices (excluding hedges): | ||||||||||||||||
Natural gas (per Mcf) | $ | 3.38 | $ | 2.34 | $ | 3.74 | $ | 2.82 | ||||||||
Oil (per Bbl) | $ | 62.12 | $ | 55.00 | $ | 65.21 | $ | 45.42 | ||||||||
Average depreciation, depletion and amortization rate, per equivalent Mcf | $ | 1.84 | $ | 1.47 | $ | 1.75 | $ | 1.69 | ||||||||
Production costs, including taxes, per net equivalent Mcf: | ||||||||||||||||
Lease operating costs | $ | 1.10 | $ | .88 | $ | .98 | $ | .95 | ||||||||
Gathering and transportation | .33 | .33 | .34 | .32 | ||||||||||||
Production and property taxes | .46 | .43 | .51 | .37 | ||||||||||||
$ | 1.89 | $ | 1.64 | $ | 1.83 | $ | 1.64 |
· | Lower average realized natural gas prices of |
· | Higher depreciation, depletion and amortization expense of $3.1 million (after tax), largely due to higher depletion rates |
· | Decreased natural gas production of |
· |
· | Higher average realized oil prices of 20 percent |
· |
· | Absence of the 2009 noncash write-down of natural gas and oil properties of $384.4 million (after tax), as discussed in Note |
· | Higher average realized oil prices of |
· | Increased oil production of 5 percent, as previously discussed |
· | Lower depreciation, depletion and amortization expense of |
· | Lower general and administrative expense of |
· | Decreased lease operating expenses of $1.7 million (after tax) |
· |
· |
· | Higher production taxes of $3.4 million (after tax), largely resulting from higher natural gas and oil prices excluding hedges |
Three Months Ended | Six Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | September 30, | September 30, | |||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
(Dollars in millions) | (Dollars in millions) | |||||||||||||||||||||||||||||||
Operating revenues | $ | 361.6 | $ | 389.4 | $ | 511.4 | $ | 572.9 | $ | 612.7 | $ | 622.0 | $ | 1,124.1 | $ | 1,194.9 | ||||||||||||||||
Operating expenses: | ||||||||||||||||||||||||||||||||
Operation and maintenance | 316.9 | 325.7 | 462.9 | 498.0 | 513.4 | 506.6 | 976.4 | 1,004.6 | ||||||||||||||||||||||||
Depreciation, depletion and amortization | 22.2 | 23.8 | 44.8 | 47.8 | 22.5 | 23.4 | 67.2 | 71.2 | ||||||||||||||||||||||||
Taxes, other than income | 9.2 | 9.8 | 16.5 | 17.3 | 10.1 | 11.5 | 26.6 | 28.8 | ||||||||||||||||||||||||
348.3 | 359.3 | 524.2 | 563.1 | 546.0 | 541.5 | 1,070.2 | 1,104.6 | |||||||||||||||||||||||||
Operating income (loss) | 13.3 | 30.1 | (12.8 | ) | 9.8 | |||||||||||||||||||||||||||
Earnings (loss) | $ | 5.7 | $ | 16.0 | $ | (14.5 | ) | $ | .3 | |||||||||||||||||||||||
Operating income | 66.7 | 80.5 | 53.9 | 90.3 | ||||||||||||||||||||||||||||
Earnings | $ | 40.3 | $ | 47.5 | $ | 25.8 | $ | 47.8 | ||||||||||||||||||||||||
Sales (000's): | ||||||||||||||||||||||||||||||||
Aggregates (tons) | 6,261 | 6,486 | 9,224 | 9,671 | 8,741 | 9,345 | 17,965 | 19,016 | ||||||||||||||||||||||||
Asphalt (tons) | 1,579 | 1,530 | 1,733 | 1,718 | 3,343 | 3,443 | 5,076 | 5,161 | ||||||||||||||||||||||||
Ready-mixed concrete (cubic yards) | 742 | 792 | 1,218 | 1,301 | 919 | 1,021 | 2,137 | 2,322 |
Three Months Ended | Six Months Ended | Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||
June 30, | June 30, | September 30, | September 30, | |||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||
(In millions) | (In millions) | |||||||||||||||||||||||||||||||
Other: | ||||||||||||||||||||||||||||||||
Operating revenues | $ | 2.3 | $ | 2.7 | $ | 4.5 | $ | 5.4 | $ | 2.3 | $ | 2.7 | $ | 6.8 | $ | 8.1 | ||||||||||||||||
Operation and maintenance | 1.8 | 1.9 | 3.7 | 5.2 | 1.9 | 2.3 | 5.6 | 7.5 | ||||||||||||||||||||||||
Depreciation, depletion and amortization | .4 | .3 | .8 | .6 | .4 | .3 | 1.2 | 1.0 | ||||||||||||||||||||||||
Taxes, other than income | .1 | .1 | .1 | .1 | .1 | .1 | .1 | .2 | ||||||||||||||||||||||||
Intersegment transactions: | ||||||||||||||||||||||||||||||||
Operating revenues | $ | 42.8 | $ | 36.2 | $ | 108.1 | $ | 98.9 | $ | 42.1 | $ | 30.6 | $ | 150.1 | $ | 129.5 | ||||||||||||||||
Purchased natural gas sold | 36.8 | 29.2 | 95.8 | 84.8 | 35.7 | 23.7 | 131.4 | 108.5 | ||||||||||||||||||||||||
Operation and maintenance | 6.0 | 7.0 | 12.3 | 14.1 | 6.4 | 6.9 | 18.7 | 21.0 |
· | Earnings per common share for 2010, diluted, are projected in the range of $1.10 to |
· |
· | The Company continually seeks opportunities to expand through strategic acquisitions and organic growth opportunities. |
· | The Company continues to realize efficiencies and enhanced service levels through its efforts to standardize operations, share services and consolidate back-office functions among its four utility companies. |
· | In April 2010, the Company filed an application with the NDPSC for an electric rate increase, as discussed in Note |
· |
· | The Company is developing a landfill methane gas recovery project in Billings, Montana to supplement the Company’s gas supply portfolio. The project is expected to begin production in |
· | The Company is analyzing potential projects for accommodating load growth and replacing purchased power contracts with company-owned generation. The Company is reviewing the construction of natural gas-fired combustion and wind generation. |
· | The Company is pursuing opportunities associated with the potential development of |
· |
· | Work backlog as of |
· | The Company anticipates margins in 2010 to be lower than 2009 levels. |
· | The Company is |
Alberta Tie Line between Lethbridge, Alberta and Great Falls, Montana. In late June 2010, the Company received a notice to proceed with construction on the project. |
· | The Company continues to focus on costs and efficiencies to enhance margins. Selling, general and administrative expenses are down |
· | With its highly skilled technical workforce, this group is prepared to take advantage of government stimulus spending on transmission infrastructure. |
· | The Company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region, which includes portions of Colorado, Wyoming, Montana and North Dakota, is expanding, most notably the Bakken Shale of North Dakota and eastern Montana. Ongoing energy development is expected to have many direct and indirect benefits to its business. |
· | The Company continues to pursue the expansion of its existing natural gas pipeline capacity by 30,000 Mcf per day in the Bakken production area in northwestern North Dakota. This expansion project is targeted for late 2011. |
· | The Company |
· | The Company expects to spend approximately |
· |
· |
· |
· | Because of reduced capital spending in 2009 and the redirecting of forecasted 2010 capital expenditures, along with delays in obtaining well completion/frac services, |
· | Earnings guidance reflects estimated natural gas prices for |
Index* | Price Per Mcf |
Ventura | $ |
NYMEX | $ |
CIG | $ |
* Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system. |
· | Earnings guidance reflects estimated NYMEX crude oil prices for |
· | For the last |
· |
Commodity | Type | Index | Period Outstanding | Forward Notional Volume (MMBtu/Bbl) | Price (Per MMBtu/Bbl) |
Natural Gas | Swap | HSC | 10/10 - 12/10 | 404,800 | $8.08 |
Natural Gas | Swap | NYMEX | 10/10 - 12/10 | 920,000 | $6.18 |
Natural Gas | Swap | NYMEX | 10/10 - 12/10 | 460,000 | $6.40 |
Natural Gas | Collar | NYMEX | 10/10 - 12/10 | 460,000 | $5.63-$6.00 |
Natural Gas | Swap | NYMEX | 10/10 - 12/10 | 460,000 | $5.855 |
Natural Gas | Swap | NYMEX | 10/10 - 12/10 | 460,000 | $6.045 |
Natural Gas | Swap | NYMEX | 10/10 - 12/10 | 460,000 | $6.045 |
Natural Gas | Swap | CIG | 10/10 - 12/10 | 920,000 | $5.03 |
Natural Gas | Swap | HSC | 10/10 | 62,000 | $5.57 |
Natural Gas | Swap | NYMEX | 10/10 | 248,000 | $5.645 |
Natural Gas | Swap | Ventura | 10/10 - 12/10 | 460,000 | $5.95 |
Natural Gas | Swap | NYMEX | 10/10 - 12/10 | 1,012,000 | $5.54 |
Natural Gas | Collar | NYMEX | 10/10 - 3/11 | 910,000 | $5.62-$6.50 |
Natural Gas | Swap | HSC | 1/11 - 12/11 | 1,350,500 | $8.00 |
Natural Gas | Swap | NYMEX | 1/11 - 12/11 | 4,015,000 | $6.1027 |
Natural Gas | Swap | NYMEX | 1/11 - 12/11 | 3,650,000 | $5.4975 |
Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 3,477,000 | $6.27 |
Crude Oil | Collar | NYMEX | 10/10 - 12/10 | 92,000 | $60.00-$75.00 |
Crude Oil | Swap | NYMEX | 10/10 - 12/10 | 92,000 | $73.20 |
Crude Oil | Collar | NYMEX | 10/10 - 12/10 | 92,000 | $70.00-$86.00 |
Crude Oil | Swap | NYMEX | 10/10 - 12/10 | 92,000 | $83.05 |
Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 547,500 | $80.00-$94.00 |
Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 365,000 | $80.00-$89.00 |
Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 182,500 | $77.00-$86.45 |
Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 182,500 | $75.00-$88.00 |
Crude Oil | Swap | NYMEX | 1/11 - 12/11 | 365,000 | $81.35 |
Crude Oil | Swap | NYMEX | 1/11 - 12/11 | 182,500 | $85.85 |
Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 366,000 | $80.00-$87.80 |
Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 366,000 | $80.00-$94.50 |
Natural Gas | Basis Swap | Ventura | 10/10 - 12/10 | 920,000 | $0.25 |
Natural Gas | Basis Swap | Ventura | 10/10 - 12/10 | 230,000 | $0.245 |
Natural Gas | Basis Swap | Ventura | 10/10 - 12/10 | 1,150,000 | $0.25 |
Natural Gas | Basis Swap | Ventura | 10/10 - 12/10 | 460,000 | $0.225 |
Natural Gas | Basis Swap | Ventura | 10/10 - 12/10 | 230,000 | $0.23 |
Natural Gas | Basis Swap | Ventura | 10/10 - 12/10 | 690,000 | $0.23 |
Natural Gas | Basis Swap | CIG | 10/10 - 12/10 | 1,012,000 | $0.385 |
Natural Gas | Basis Swap | Ventura | 1/11 - 3/11 | 450,000 | $0.135 |
Natural Gas | Basis Swap | CIG | 1/11 - 12/11 | 4,015,000 | $0.395 |
Natural Gas | Basis Swap | Ventura | 1/11 - 12/11 | 3,650,000 | $0.15 |
Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 2,745,000 | $0.405 |
Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 732,000 | $0.41 |
Notes: · Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system; HSC is the Houston Ship Channel hub in southeast Texas which connects to several pipelines. · For all basis swaps, Index prices are below NYMEX prices and are reported as a positive amount in the Price column. |
Commodity | Type | Index | Period Outstanding | Forward Notional Volume (MMBtu/Bbl) | Price (Per MMBtu/Bbl) |
Natural Gas | Swap | HSC | 7/10 - 12/10 | 809,600 | $8.08 |
Natural Gas | Swap | NYMEX | 7/10 - 12/10 | 1,840,000 | $6.18 |
Natural Gas | Swap | NYMEX | 7/10 - 12/10 | 920,000 | $6.40 |
Natural Gas | Collar | NYMEX | 7/10 - 12/10 | 920,000 | $5.63-$6.00 |
Natural Gas | Swap | NYMEX | 7/10 - 12/10 | 920,000 | $5.855 |
Natural Gas | Swap | NYMEX | 7/10 - 12/10 | 920,000 | $6.045 |
Natural Gas | Swap | NYMEX | 7/10 - 12/10 | 920,000 | $6.045 |
Natural Gas | Swap | CIG | 7/10 - 12/10 | 1,840,000 | $5.03 |
Natural Gas | Swap | HSC | 7/10 - 10/10 | 246,000 | $5.57 |
Natural Gas | Swap | NYMEX | 7/10 - 10/10 | 984,000 | $5.645 |
Natural Gas | Swap | Ventura | 7/10 - 12/10 | 920,000 | $5.95 |
Natural Gas | Swap | NYMEX | 7/10 - 12/10 | 2,024,000 | $5.54 |
Natural Gas | Collar | NYMEX | 7/10 - 3/11 | 1,370,000 | $5.62-$6.50 |
Natural Gas | Swap | HSC | 1/11 - 12/11 | 1,350,500 | $8.00 |
Natural Gas | Swap | NYMEX | 1/11 - 12/11 | 4,015,000 | $6.1027 |
Natural Gas | Swap | NYMEX | 1/11 - 12/11 | 3,650,000 | $5.4975 |
Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 3,477,000 | $6.27 |
Crude Oil | Collar | NYMEX | 7/10 - 12/10 | 184,000 | $60.00-$75.00 |
Crude Oil | Swap | NYMEX | 7/10 - 12/10 | 184,000 | $73.20 |
Crude Oil | Collar | NYMEX | 7/10 - 12/10 | 184,000 | $70.00-$86.00 |
Crude Oil | Swap | NYMEX | 7/10 - 12/10 | 184,000 | $83.05 |
Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 547,500 | $80.00-$94.00 |
Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 365,000 | $80.00-$89.00 |
Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 182,500 | $77.00-$86.45 |
Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 182,500 | $75.00-$88.00 |
Natural Gas | Basis Swap | Ventura | 7/10 - 12/10 | 1,840,000 | $0.25 |
Natural Gas | Basis Swap | Ventura | 7/10 - 12/10 | 460,000 | $0.245 |
Natural Gas | Basis Swap | Ventura | 7/10 - 12/10 | 2,300,000 | $0.25 |
Natural Gas | Basis Swap | Ventura | 7/10 - 12/10 | 920,000 | $0.225 |
Natural Gas | Basis Swap | Ventura | 7/10 - 12/10 | 460,000 | $0.23 |
Natural Gas | Basis Swap | Ventura | 7/10 - 12/10 | 1,380,000 | $0.23 |
Natural Gas | Basis Swap | CIG | 7/10 - 12/10 | 2,024,000 | $0.385 |
Natural Gas | Basis Swap | Ventura | 1/11 - 3/11 | 450,000 | $0.135 |
Natural Gas | Basis Swap | CIG | 1/11 - 12/11 | 4,015,000 | $0.395 |
Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 2,745,000 | $0.405 |
Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 732,000 | $0.41 |
Notes: · Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system; HSC is the Houston Ship Channel hub in southeast Texas which connects to several pipelines. · For all basis swaps, Index prices are below NYMEX prices and are reported as a positive amount in the Price column. |
· | Work backlog as of |
· | Examples of |
· |
· | The Company continues to pursue work related to energy projects, such as wind towers, transmission projects, geothermal and refineries. It is also pursuing opportunities for expansion of its existing business lines including initiatives aimed at capturing additional market share and expansion into new markets. |
· | The Company has a strong emphasis on operational efficiencies and cost reduction. Selling, general and administrative expenses are down |
· |
· | As the country’s 6th largest sand and gravel producer, the Company will continue to strategically manage its 1.1 billion tons of aggregate reserves in all its markets, as well as take further advantage of being vertically integrated. |
· | Of the five labor contracts that Knife River was negotiating, as reported in Items 1 and 2 – Business and Properties – General in the 2009 Annual Report, four have been ratified. The one remaining contract is still in negotiations. |
· | The acquisition of producing natural gas properties located in the Green River Basin in southwest Wyoming |
· | System upgrades |
· | Routine replacements |
· | Service extensions |
· | Routine equipment maintenance and replacements |
· | Buildings, land and building improvements |
· | Pipeline and gathering projects |
· | Further development of existing properties, |
· | Power generation opportunities, including certain costs for additional electric generating capacity |
· | Other growth opportunities |
Company | Facility | Facility Limit | Amount Outstanding | Letters of Credit | Expiration Date | Facility | Facility Limit | Amount Outstanding | Letters of Credit | Expiration Date | (Dollars in millions) | |||||||||||||||||||||||||||
MDU Resources Group, Inc. | Commercial paper/Revolving credit agreement | (a) | $ | 125.0 | $ | — | (b) | $ | — | 6/21/11 | Commercial paper/Revolving credit agreement | (a) | $ | 125.0 | $ | 4.7 | (b) | $ | — | 6/21/11 | ||||||||||||||||||
MDU Energy Capital, LLC | Master shelf agreement | $ | 175.0 | $ | 165.0 | $ | — | 8/14/10 | (c)(d) | |||||||||||||||||||||||||||||
Cascade Natural Gas Corporation | Revolving credit agreement | $ | 50.0 | (e) | $ | — | $ | 1.9 | (f) | 12/28/12 | (g) | Revolving credit agreement | $ | 50.0 | (c) | $ | — | $ | 1.9 | (d) | 12/28/12 | (e) | ||||||||||||||||
Intermountain Gas Company | Revolving credit agreement | $ | 65.0 | (h) | $ | 3.7 | $ | — | 8/31/10 | (i) | Revolving credit agreement | $ | 65.0 | (f) | $ | 17.8 | $ | — | 8/11/13 | |||||||||||||||||||
Centennial Energy Holdings, Inc. | Commercial paper/Revolving credit agreement | (j) | $ | 400.0 | $ | 83.0 | (b) | $ | 25.8 | (f) | 12/13/12 | Commercial paper/Revolving credit agreement | (g) | $ | 400.0 | $ | — | (b) | $ | 25.8 | (d) | 12/13/12 | ||||||||||||||||
Williston Basin Interstate Pipeline Company | Uncommitted long-term private shelf agreement | $ | 125.0 | $ | 87.5 | $ | — | 12/23/11 | (c) | Uncommitted long-term private shelf agreement | $ | 125.0 | $ | 87.5 | $ | — | 12/23/11 | (h) |
(a) | The $125 million commercial paper program is supported by a revolving credit agreement with various banks totaling $125 million (provisions allow for increased borrowings, at the option of the Company on stated conditions, up to a maximum of $150 million). There were no amounts outstanding under the credit agreement. |
(b) | Amount outstanding under commercial paper program. |
(c) | |
Certain provisions allow for increased borrowings, up to a maximum of $75 million. | |
The outstanding letters of credit, as discussed in Note | |
Provisions allow for an extension of up to two years upon consent of the banks. | |
Certain provisions allow for increased borrowings, up to a maximum of | |
The $400 million commercial paper program is supported by a revolving credit agreement with various banks totaling $400 million (provisions allow for increased borrowings, at the option of Centennial on stated conditions, up to a maximum of $450 million). There were no amounts outstanding under the credit agreement. | |
(h) | Represents expiration of the ability to borrow additional funds under the agreement. |
(Forward notional volume and fair value in thousands) | (Forward notional volume and fair value in thousands) | (Forward notional volume and fair value in thousands) | ||||||||||||||||||||||
Weighted Average Fixed Price (Per MMBtu/Bbl) | Forward Notional Volume (MMBtu/Bbl) | Fair Value | Weighted Average Fixed Price (Per MMBtu/Bbl) | Forward Notional Volume (MMBtu/Bbl) | Fair Value | |||||||||||||||||||
Fidelity | ||||||||||||||||||||||||
Natural gas swap agreements maturing in 2010 | $ | 5.93 | 12,344 | $ | 15,252 | $ | 5.94 | 5,867 | $ | 12,108 | ||||||||||||||
Natural gas swap agreements maturing in 2011 | $ | 6.14 | 9,016 | $ | 7,372 | $ | 6.14 | 9,016 | $ | 15,399 | ||||||||||||||
Natural gas swap agreement maturing in 2012 | $ | 6.27 | 3,477 | $ | 2,008 | $ | 6.27 | 3,477 | $ | 4,123 | ||||||||||||||
Natural gas basis swap agreements maturing in 2010 | $ | .27 | 9,384 | $ | 162 | $ | .27 | 4,692 | $ | (962 | ) | |||||||||||||
Natural gas basis swap agreements maturing in 2011 | $ | .37 | 4,465 | $ | 328 | $ | .27 | 8,115 | $ | 16 | ||||||||||||||
Natural gas basis swap agreements maturing in 2012 | $ | .41 | 3,477 | $ | 285 | $ | .41 | 3,477 | $ | 136 | ||||||||||||||
Oil swap agreements maturing in 2010 | $ | 78.13 | 368 | $ | 437 | $ | 78.13 | 184 | $ | (564 | ) | |||||||||||||
Oil swap agreements maturing in 2011 | $ | 81.35 | 365 | $ | (1,266 | ) | ||||||||||||||||||
Cascade | ||||||||||||||||||||||||
Natural gas swap agreements maturing in 2010 | $ | 8.02 | 2,425 | $ | (9,382 | ) | $ | 8.24 | 1,644 | $ | (7,733 | ) | ||||||||||||
Natural gas swap agreements maturing in 2011 | $ | 8.10 | 2,270 | $ | (7,601 | ) | $ | 8.10 | 2,270 | $ | (9,739 | ) | ||||||||||||
Intermountain | ||||||||||||||||||||||||
Natural gas swap agreement maturing in 2010 | $ | 4.96 | 1,661 | $ | (1,485 | ) | $ | 4.96 | 419 | $ | (641 | ) | ||||||||||||
Natural gas swap agreement maturing in 2011 | $ | 4.96 | 2,889 | $ | (429 | ) | $ | 4.96 | 2,889 | $ | (3,107 | ) | ||||||||||||
Weighted Average Floor/Ceiling Price (Per MMBtu/Bbl) | Forward Notional Volume (MMBtu/Bbl) | Fair Value | Weighted Average Floor/Ceiling Price (Per MMBtu/Bbl) | Forward Notional Volume (MMBtu/Bbl) | Fair Value | |||||||||||||||||||
Fidelity | ||||||||||||||||||||||||
Natural gas collar agreements maturing in 2010 | $5.63/$6.25 | 1,840 | $ | 1,474 | $5.63/$6.25 | 920 | $ | 1,566 | ||||||||||||||||
Natural gas collar agreement maturing in 2011 | $5.62/$6.50 | 450 | $ | 345 | $5.62/$6.50 | 450 | $ | 604 | ||||||||||||||||
Oil collar agreements maturing in 2010 | $65.00/$80.50 | 368 | $ | (874 | ) | $65.00/$80.50 | 184 | $ | (747 | ) | ||||||||||||||
Oil collar agreements maturing in 2011 | $78.86/$90.64 | 1,278 | $ | 4,706 | $78.86/$90.64 | 1,278 | $ | (557 | ) | |||||||||||||||
Oil collar agreements maturing in 2012 | $80.00/$87.80 | 366 | $ | (1,124 | ) | |||||||||||||||||||
Intermountain | ||||||||||||||||||||||||
Natural gas collar agreement maturing in 2011 | $4.25/$4.92 | 963 | $ | (352 | ) |
Period | (a) Total Number of Shares (or Units) Purchased (1) | (b) Average Price Paid per Share (or Unit) | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (2) | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (2) |
April 1 through April 30, 2010 | — | |||
May 1 through May 31, 2010 | 36,450 | $19.52 | ||
June 1 through June 30, 2010 | — | |||
Total | 36,450 |
1. | Citations issued under section 104(a) of the Mine Safety Act that could significantly and substantially contribute to the cause and effect of a coal or other mine safety hazard. |
2. | Orders issued under section 104(b) of the Mine Safety Act. Orders are issued under this section when citations issued under section 104(a) have not been totally abated within the time period allowed by the citation or subsequent extensions. |
3. | Citations issued under section 104(d) of the Mine Safety Act. Citations are issued under this section when it has been determined that the violation is caused by an unwarrantable failure of the mine operator to comply with the standard. An unwarrantable failure occurs when the mine operator is deemed to have engaged in aggravated conduct constituting more than ordinary negligence. |
4. | Citations issued under Section 110(b)(2) of the Mine Safety Act for flagrant violations. Violations are considered flagrant for repeat or reckless failures to make reasonable efforts to eliminate a known violation of a mandatory health and safety standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury. |
5. | Imminent danger orders issued under Section 107(a) of the Mine Safety Act. An imminent danger is defined as the existence of any condition or practice in a coal or other mine which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated. |
6. | Notice received under Section 104(e) of the Mine Safety Act of a pattern of violations or the potential to have such a pattern of violations that could significantly and substantially contribute to the cause and effect of mine health and safety standards. |
Mine Location | Section 104(a) Citations Issued | Proposed Assessments Levied (Dollars) | ||||||
Northern California | 2 | $ | — | |||||
Southern California | — | 100 | ||||||
Montana | — | 500 | ||||||
Wyoming | — | 300 | ||||||
Idaho/Washington | 3 | — | ||||||
Texas | — | 1,889 | ||||||
Western Oregon | — | 1,855 | ||||||
Central Oregon | — | 100 | ||||||
Southern Oregon | — | 525 | ||||||
Iowa | 1 | 862 | ||||||
Northern Minnesota | 2 | 1,000 | ||||||
North Dakota | — | 300 | ||||||
Total | 8 | $ | 7,431 |
MDU RESOURCES GROUP, INC. | |||
DATE: | BY: | /s/ Doran N. Schwartz | |
Doran N. Schwartz | |||
Vice President and Chief Financial Officer | |||
BY: | /s/ Nicole A. Kivisto | ||
Nicole A. Kivisto | |||
Vice President, Controller and | |||
Chief Accounting Officer |
3(a) | Restated Certificate of Incorporation of the Company, as amended, dated May 13, 2010 |
3(b) | Company Bylaws, as amended and restated, on August 12, 2010 |
+10(a) | Directors’ Compensation Policy, as amended August 12, 2010 |
+10(b) | Non-Employee Director Stock Compensation Plan, as amended August 12, 2010 |
+10(c) | Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated |
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 |
101 | The following materials from MDU Resources Group, Inc.’s Quarterly Report on Form 10-Q for the quarter ended |