ý | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF | |
THE SECURITIES EXCHANGE ACT OF 1934 |
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 ý | Accelerated filer o | |
Non-accelerated filer o | Smaller reporting company o |
Abbreviation or Acronym | |
2012 Annual Report | Company's Annual Report on Form 10-K for the year ended December 31, 2012 |
Alusa | Tecnica de Engenharia Electrica - Alusa |
ASC | FASB Accounting Standards Codification |
BART | Best available retrofit technology |
Bbl | Barrel |
Bicent | Bicent Power LLC |
Big Stone Station | 475-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent ownership) |
BOE | One barrel of oil equivalent - determined using the ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf of natural gas |
BOPD | Barrels of oil per day |
Brazilian Transmission Lines | Company's equity method investment in the company owning ECTE, ENTE and ERTE (ownership interests in ENTE and ERTE were sold in the fourth quarter of 2010 and portions of the ownership interest in ECTE were sold in the third quarter of 2012 and the fourth quarters of 2011 and 2010) |
Btu | British thermal unit |
Calumet | Calumet Specialty Products Partners, L.P. |
Cascade | Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital |
CELESC | Centrais Elétricas de Santa Catarina S.A. |
CEM | Colorado Energy Management, LLC, a former direct wholly owned subsidiary of Centennial Resources (sold in the third quarter of 2007) |
CEMIG | Companhia Energética de Minas Gerais |
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 |
Colorado State District Court | Colorado Thirteenth Judicial District Court, Yuma County |
Company | MDU Resources Group, Inc. |
Coyote Creek | Coyote Creek Mining Company, LLC, a subsidiary of The North American Coal Corporation |
Coyote Station | 427-MW coal-fired electric generating facility near Beulah, North Dakota (25 percent ownership) |
Dakota Prairie Refining | Dakota Prairie Refining, LLC |
dk | Decatherm |
Dodd-Frank Act | Dodd-Frank Wall Street Reform and Consumer Protection Act |
ECTE | Empresa Catarinense de Transmissão de Energia S.A. (5.01 percent ownership interest at March 31, 2013, 2.5, 2.5 and 14.99 percent ownership interests were sold in the third quarter of 2012 and the fourth quarters of 2011 and 2010, respectively) |
ENTE | Empresa Norte de Transmissão de Energia S.A. (entire 13.3 percent ownership interest sold in the fourth quarter of 2010) |
EPA | U.S. Environmental Protection Agency |
ERTE | Empresa Regional de Transmissão de Energia S.A. (entire 13.3 percent ownership interest sold in the fourth quarter of 2010) |
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 |
Hawaiian Cement | Hawaiian Cement, an indirect wholly owned subsidiary of Knife River |
Intermountain | Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital |
JTL | JTL Group, Inc., an indirect wholly owned subsidiary of Knife River |
Knife River | Knife River Corporation, a direct wholly owned subsidiary of Centennial |
Knife River - Northwest | Knife River Corporation - Northwest, an indirect wholly owned subsidiary of Knife River |
kWh | Kilowatt-hour |
LPP | Lea Power Partners, LLC, a former indirect wholly owned subsidiary of Centennial Resources (member interests were sold in October 2006) |
LWG | Lower Willamette Group |
MBbls | Thousands of barrels |
MBOE | Thousands of BOE |
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 |
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 Department of Environmental Quality |
Montana First Judicial District Court | Montana First Judicial District Court, Lewis and Clark County |
Montana Seventeenth Judicial District Court | Montana Seventeenth Judicial District Court, Phillips County |
MTPSC | Montana Public Service Commission |
MW | Megawatt |
NDPSC | North Dakota Public Service Commission |
New York Supreme Court | Supreme Court of the State of New York, County of New York |
NGL | Natural gas liquids |
Oil | Includes crude oil and condensate |
Omimex | Omimex Canada, Ltd. |
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 |
psi | pounds per square inch |
ROD | Record of Decision |
SDPUC | South Dakota Public Utilities Commission |
SEC | U.S. Securities and Exchange Commission |
Securities Act | Securities Act of 1933, as amended |
SourceGas | SourceGas Distribution LLC |
VIE | Variable interest entity |
WBI Energy | WBI Energy, Inc., an indirect wholly owned subsidiary of WBI Holdings |
WBI Energy Midstream | WBI Energy Midstream, LLC an indirect wholly owned subsidiary of WBI Holdings (previously Bitter Creek Pipelines, LLC, name changed effective July 1, 2012) |
WBI Energy Transmission | WBI Energy Transmission, Inc., an indirect wholly owned subsidiary of WBI Holdings (previously Williston Basin Interstate Pipeline Company, name changed effective July 1, 2012) |
WBI Holdings | WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial |
WUTC | Washington Utilities and Transportation Commission |
Part I -- Financial Information | Page |
Consolidated Statements of Income -- Three Months Ended March 31, 2013 and 2012 | |
Consolidated Statements of Comprehensive Income -- Three Months Ended March 31, 2013 and 2012 | |
Consolidated Balance Sheets -- March 31, 2013 and 2012, and December 31, 2012 | |
Consolidated Statements of Cash Flows -- Three Months Ended March 31, 2013 and 2012 | |
Notes to Consolidated Financial Statements | |
Management's Discussion and Analysis of Financial Condition and Results of Operations | |
Quantitative and Qualitative Disclosures About Market Risk | |
Controls and Procedures | |
Part II -- Other Information | |
Legal Proceedings | |
Risk Factors | |
Mine Safety Disclosures | |
Exhibits | |
Signatures | |
Exhibit Index | |
Exhibits |
Three Months Ended | ||||||
March 31, | ||||||
2013 | 2012 | |||||
(In thousands, except per share amounts) | ||||||
Operating revenues: | ||||||
Electric, natural gas distribution and pipeline and energy services | $ | 424,124 | $ | 395,081 | ||
Exploration and production, construction materials and contracting, construction services and other | 507,480 | 457,726 | ||||
Total operating revenues | 931,604 | 852,807 | ||||
Operating expenses: | ||||||
Fuel and purchased power | 21,608 | 18,420 | ||||
Purchased natural gas sold | 199,187 | 185,428 | ||||
Operation and maintenance: | ||||||
Electric, natural gas distribution and pipeline and energy services | 66,101 | 68,401 | ||||
Exploration and production, construction materials and contracting, construction services and other | 394,019 | 376,146 | ||||
Depreciation, depletion and amortization | 93,561 | 85,380 | ||||
Taxes, other than income | 52,597 | 47,975 | ||||
Total operating expenses | 827,073 | 781,750 | ||||
Operating income | 104,531 | 71,057 | ||||
Earnings (loss) from equity method investments | (311 | ) | 1,253 | |||
Other income | 1,242 | 1,098 | ||||
Interest expense | 20,874 | 19,439 | ||||
Income before income taxes | 84,588 | 53,969 | ||||
Income taxes | 27,996 | 18,079 | ||||
Income from continuing operations | 56,592 | 35,890 | ||||
Loss from discontinued operations, net of tax (Note 9) | (77 | ) | (100 | ) | ||
Net income | 56,515 | 35,790 | ||||
Dividends declared on preferred stocks | 171 | 171 | ||||
Earnings on common stock | $ | 56,344 | $ | 35,619 | ||
Earnings per common share - basic: | ||||||
Earnings before discontinued operations | $ | .30 | $ | .19 | ||
Discontinued operations, net of tax | — | — | ||||
Earnings per common share - basic | $ | .30 | $ | .19 | ||
Earnings per common share - diluted: | ||||||
Earnings before discontinued operations | $ | .30 | $ | .19 | ||
Discontinued operations, net of tax | — | — | ||||
Earnings per common share - diluted | $ | .30 | $ | .19 | ||
Dividends declared per common share | $ | .1725 | $ | .1675 | ||
Weighted average common shares outstanding - basic | 188,831 | 188,811 | ||||
Weighted average common shares outstanding - diluted | 189,222 | 189,182 |
Three Months Ended | ||||||
March 31, | ||||||
2013 | 2012 | |||||
(In thousands) | ||||||
Net income | $ | 56,515 | $ | 35,790 | ||
Other comprehensive loss: | ||||||
Net unrealized loss on derivative instruments qualifying as hedges: | ||||||
Net unrealized loss on derivative instruments arising during the period, net of tax of $(3,168) and $(2,225) in 2013 and 2012, respectively | (5,849 | ) | (3,770 | ) | ||
Less: Reclassification adjustment for gain on derivative instruments included in net income, net of tax of $1,626 and $1,366 in 2013 and 2012, respectively | 2,772 | 2,329 | ||||
Net unrealized loss on derivative instruments qualifying as hedges | (8,621 | ) | (6,099 | ) | ||
Net unrealized gain (loss) on available-for-sale investments: | ||||||
Net unrealized loss on available-for-sale investments arising during the period, net of tax of $(24) and $(2) in 2013 and 2012, respectively | (44 | ) | (4 | ) | ||
Less: Reclassification adjustment for loss on available-for-sale investments included in net income, net of tax of $(19) and $(16) in 2013 and 2012, respectively | (35 | ) | (30 | ) | ||
Net unrealized gain (loss) on available-for-sale investments | (9 | ) | 26 | |||
Amortization of postretirement liability losses included in net periodic benefit cost, net of tax of $319 in 2013 | 648 | — | ||||
Foreign currency translation adjustment, net of tax of $37 and $138 in 2013 and 2012, respectively | 88 | 144 | ||||
Other comprehensive loss | (7,894 | ) | (5,929 | ) | ||
Comprehensive income | $ | 48,621 | $ | 29,861 |
March 31, 2013 | March 31, 2012 | December 31, 2012 | |||||||
(In thousands, except shares and per share amounts) | |||||||||
ASSETS | |||||||||
Current assets: | |||||||||
Cash and cash equivalents | $ | 74,149 | $ | 91,389 | $ | 49,042 | |||
Receivables, net | 635,564 | 539,589 | 678,123 | ||||||
Inventories | 334,872 | 313,341 | 317,415 | ||||||
Deferred income taxes | 29,885 | 42,239 | 22,846 | ||||||
Commodity derivative instruments | 5,936 | 26,698 | 18,304 | ||||||
Prepayments and other current assets | 68,828 | 64,897 | 42,351 | ||||||
Total current assets | 1,149,234 | 1,078,153 | 1,128,081 | ||||||
Investments | 106,846 | 113,799 | 103,243 | ||||||
Property, plant and equipment | 8,303,065 | 7,798,770 | 8,107,751 | ||||||
Less accumulated depreciation, depletion and amortization | 3,678,535 | 3,419,574 | 3,608,912 | ||||||
Net property, plant and equipment | 4,624,530 | 4,379,196 | 4,498,839 | ||||||
Deferred charges and other assets: | |||||||||
Goodwill | 636,039 | 635,389 | 636,039 | ||||||
Other intangible assets, net | 16,318 | 19,991 | 17,129 | ||||||
Other | 295,215 | 312,103 | 299,160 | ||||||
Total deferred charges and other assets | 947,572 | 967,483 | 952,328 | ||||||
Total assets | $ | 6,828,182 | $ | 6,538,631 | $ | 6,682,491 | |||
LIABILITIES AND EQUITY | |||||||||
Current liabilities: | |||||||||
Short-term borrowings | $ | 37,500 | $ | — | $ | 28,200 | |||
Long-term debt due within one year | 171,094 | 202,215 | 134,108 | ||||||
Accounts payable | 375,942 | 321,369 | 388,015 | ||||||
Taxes payable | 55,748 | 51,019 | 46,475 | ||||||
Dividends payable | 32,744 | 31,800 | 171 | ||||||
Accrued compensation | 31,382 | 28,463 | 48,448 | ||||||
Commodity derivative instruments | 7,379 | 20,183 | — | ||||||
Other accrued liabilities | 205,394 | 255,172 | 204,698 | ||||||
Total current liabilities | 917,183 | 910,221 | 850,115 | ||||||
Long-term debt | 1,618,569 | 1,213,974 | 1,610,867 | ||||||
Deferred credits and other liabilities: | |||||||||
Deferred income taxes | 802,805 | 798,669 | 755,102 | ||||||
Other liabilities | 814,643 | 842,169 | 818,159 | ||||||
Total deferred credits and other liabilities | 1,617,448 | 1,640,838 | 1,573,261 | ||||||
Commitments and contingencies | |||||||||
Equity: | |||||||||
Preferred stocks | 15,000 | 15,000 | 15,000 | ||||||
Common stockholders' equity: | |||||||||
Common stock | |||||||||
Authorized - 500,000,000 shares, $1.00 par value | |||||||||
Shares issued - 189,369,450 at March 31, 2013 and 2012 and December 31, 2012 | 189,369 | 189,369 | 189,369 | ||||||
Other paid-in capital | 1,038,970 | 1,035,800 | 1,039,080 | ||||||
Retained earnings | 1,480,784 | 1,589,985 | 1,457,146 | ||||||
Accumulated other comprehensive loss | (56,615 | ) | (52,930 | ) | (48,721 | ) | |||
Treasury stock at cost - 538,921 shares | (3,626 | ) | (3,626 | ) | (3,626 | ) | |||
Total common stockholders' equity | 2,648,882 | 2,758,598 | 2,633,248 | ||||||
Total stockholders' equity | 2,663,882 | 2,773,598 | 2,648,248 | ||||||
Noncontrolling interest | 11,100 | — | — | ||||||
Total equity | 2,674,982 | 2,773,598 | 2,648,248 | ||||||
Total liabilities and equity | $ | 6,828,182 | $ | 6,538,631 | $ | 6,682,491 |
Three Months Ended | ||||||
March 31, | ||||||
2013 | 2012 | |||||
(In thousands) | ||||||
Operating activities: | ||||||
Net income | $ | 56,515 | $ | 35,790 | ||
Loss from discontinued operations, net of tax | (77 | ) | (100 | ) | ||
Income from continuing operations | 56,592 | 35,890 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||
Depreciation, depletion and amortization | 93,561 | 85,380 | ||||
Earnings, net of distributions, from equity method investments | 1,277 | 1,181 | ||||
Deferred income taxes | 44,663 | 32,596 | ||||
Changes in current assets and liabilities, net of acquisitions: | ||||||
Receivables | 32,206 | 101,917 | ||||
Inventories | (19,126 | ) | (38,357 | ) | ||
Other current assets | (25,855 | ) | (21,556 | ) | ||
Accounts payable | (35,091 | ) | (29,851 | ) | ||
Other current liabilities | (7,338 | ) | (33,751 | ) | ||
Other noncurrent changes | (4,318 | ) | (8,349 | ) | ||
Net cash provided by continuing operations | 136,571 | 125,100 | ||||
Net cash provided by (used in) discontinued operations | 303 | (107 | ) | |||
Net cash provided by operating activities | 136,874 | 124,993 | ||||
Investing activities: | ||||||
Capital expenditures | (188,475 | ) | (174,429 | ) | ||
Acquisitions, net of cash acquired | — | (242 | ) | |||
Net proceeds from sale or disposition of property and other | 18,176 | 18,256 | ||||
Investments | (514 | ) | (27 | ) | ||
Net cash used in continuing operations | (170,813 | ) | (156,442 | ) | ||
Net cash provided by discontinued operations | — | — | ||||
Net cash used in investing activities | (170,813 | ) | (156,442 | ) | ||
Financing activities: | ||||||
Issuance of short-term borrowings | 9,300 | — | ||||
Issuance of long-term debt | 112,015 | — | ||||
Repayment of long-term debt | (67,123 | ) | (8,297 | ) | ||
Proceeds from issuance of common stock | — | 88 | ||||
Dividends paid | (171 | ) | (31,794 | ) | ||
Excess tax benefit on stock-based compensation | — | 26 | ||||
Contribution from noncontrolling interest | 5,000 | — | ||||
Net cash provided by (used in) continuing operations | 59,021 | (39,977 | ) | |||
Net cash provided by discontinued operations | — | — | ||||
Net cash provided by (used in) financing activities | 59,021 | (39,977 | ) | |||
Effect of exchange rate changes on cash and cash equivalents | 25 | 43 | ||||
Increase (decrease) in cash and cash equivalents | 25,107 | (71,383 | ) | |||
Cash and cash equivalents -- beginning of year | 49,042 | 162,772 | ||||
Cash and cash equivalents -- end of period | $ | 74,149 | $ | 91,389 |
March 31, 2013 | March 31, 2012 | December 31, 2012 | |||||||
(In thousands) | |||||||||
Aggregates held for resale | $ | 98,120 | $ | 85,958 | $ | 87,715 | |||
Asphalt oil | 94,332 | 82,949 | 67,480 | ||||||
Materials and supplies | 75,868 | 68,369 | 69,390 | ||||||
Merchandise for resale | 24,342 | 28,459 | 31,172 | ||||||
Natural gas in storage (current) | 12,811 | 15,475 | 29,030 | ||||||
Other | 29,399 | 32,131 | 32,628 | ||||||
Total | $ | 334,872 | $ | 313,341 | $ | 317,415 |
Three Months Ended | ||||
March 31, | ||||
2013 | 2012 | |||
(In thousands) | ||||
Weighted average common shares outstanding - basic | 188,831 | 188,811 | ||
Effect of dilutive stock options and performance share awards | 391 | 371 | ||
Weighted average common shares outstanding - diluted | 189,222 | 189,182 | ||
Shares excluded from the calculation of diluted earnings per share | — | — |
Three Months Ended | ||||||
March 31, | ||||||
2013 | 2012 | |||||
(In thousands) | ||||||
Interest, net of amount capitalized | $ | 21,857 | $ | 22,433 | ||
Income taxes paid (refunded), net | $ | (7,246 | ) | $ | 285 |
March 31, | ||||||
2013 | 2012 | |||||
(In thousands) | ||||||
Property, plant and equipment additions in accounts payable | $ | 92,236 | $ | 51,739 |
Net Unrealized Gain (Loss) on Derivative Instruments Qualifying as Hedges | Net Unrealized Gain (Loss) on Available-for-sale Investments | Postretirement Liability Adjustment | Foreign Currency Translation Adjustment | Total Accumulated Other Comprehensive Loss | |||||||||||
(In thousands) | |||||||||||||||
Balance at December 31, 2012 | $ | 6,018 | $ | 119 | $ | (54,347 | ) | $ | (511 | ) | $ | (48,721 | ) | ||
Other comprehensive income (loss) before reclassifications | (5,849 | ) | (44 | ) | — | 88 | (5,805 | ) | |||||||
Amounts reclassified from accumulated other comprehensive loss | (2,772 | ) | 35 | 648 | — | (2,089 | ) | ||||||||
Net current-period other comprehensive loss | (8,621 | ) | (9 | ) | 648 | 88 | (7,894 | ) | |||||||
Balance at March 31, 2013 | $ | (2,603 | ) | $ | 110 | $ | (53,699 | ) | $ | (423 | ) | $ | (56,615 | ) |
Three Months Ended | Location on Consolidated Statements of Income | |||
March 31, | ||||
2013 | ||||
(In thousands) | ||||
Reclassification adjustment for gain (loss) on derivative instruments included in net income | ||||
Commodity derivative instruments | $ | 4,513 | Operating revenues | |
Interest rate derivative instruments | (115 | ) | Interest expense | |
4,398 | ||||
(1,626 | ) | Income taxes | ||
2,772 | ||||
Amortization of postretirement liability losses included in net periodic benefit cost | (967 | ) | (a) | |
319 | Income taxes | |||
(648 | ) | |||
Reclassification adjustment for loss on available-for-sale investments included in net income | (54 | ) | Other income | |
19 | Income taxes | |||
(35 | ) | |||
Total reclassifications | $ | 2,089 |
Three Months Ended March 31, 2013 | Balance as of January 1, 2013* | Goodwill Acquired During the Year | Balance as of March 31, 2013* | ||||||
(In thousands) | |||||||||
Natural gas distribution | $ | 345,736 | $ | — | $ | 345,736 | |||
Pipeline and energy services | 9,737 | — | 9,737 | ||||||
Construction materials and contracting | 176,290 | — | 176,290 | ||||||
Construction services | 104,276 | — | 104,276 | ||||||
Total | $ | 636,039 | $ | — | $ | 636,039 |
Three Months Ended March 31, 2012 | Balance as of January 1, 2012* | Goodwill Acquired During the Year** | Balance as of March 31, 2012* | ||||||
(In thousands) | |||||||||
Natural gas distribution | $ | 345,736 | $ | — | $ | 345,736 | |||
Pipeline and energy services | 9,737 | — | 9,737 | ||||||
Construction materials and contracting | 176,290 | — | 176,290 | ||||||
Construction services | 103,168 | 458 | 103,626 | ||||||
Total | $ | 634,931 | $ | 458 | $ | 635,389 |
Year Ended December 31, 2012 | Balance as of January 1, 2012* | Goodwill Acquired During the Year** | Balance as of December 31, 2012* | ||||||
(In thousands) | |||||||||
Natural gas distribution | $ | 345,736 | $ | — | $ | 345,736 | |||
Pipeline and energy services | 9,737 | — | 9,737 | ||||||
Construction materials and contracting | 176,290 | — | 176,290 | ||||||
Construction services | 103,168 | 1,108 | 104,276 | ||||||
Total | $ | 634,931 | $ | 1,108 | $ | 636,039 |
March 31, 2013 | March 31, 2012 | December 31, 2012 | |||||||
(In thousands) | |||||||||
Customer relationships | $ | 21,310 | $ | 21,010 | $ | 21,310 | |||
Accumulated amortization | (12,211 | ) | (10,197 | ) | (11,701 | ) | |||
9,099 | 10,813 | 9,609 | |||||||
Noncompete agreements | 7,236 | 7,086 | 7,236 | ||||||
Accumulated amortization | (5,439 | ) | (4,921 | ) | (5,326 | ) | |||
1,797 | 2,165 | 1,910 | |||||||
Other | 10,979 | 11,442 | 10,979 | ||||||
Accumulated amortization | (5,557 | ) | (4,429 | ) | (5,369 | ) | |||
5,422 | 7,013 | 5,610 | |||||||
Total | $ | 16,318 | $ | 19,991 | $ | 17,129 |
Three Months Ended | ||||||
March 31, | ||||||
2013 | 2012 | |||||
(In thousands) | ||||||
Commodity derivatives designated as cash flow hedges: | ||||||
Amount of loss recognized in accumulated other comprehensive loss (effective portion), net of tax | $ | (6,154 | ) | $ | (4,659 | ) |
Amount of gain reclassified from accumulated other comprehensive loss into operating revenues (effective portion), net of tax | 2,843 | 2,343 | ||||
Amount of loss recognized in operating revenues (ineffective portion), before tax | (1,422 | ) | (4,251 | ) | ||
Interest rate derivatives designated as cash flow hedges: | ||||||
Amount of gain recognized in accumulated other comprehensive loss (effective portion), net of tax | 305 | 889 | ||||
Amount of loss reclassified from accumulated other comprehensive loss into interest expense (effective portion), net of tax | (71 | ) | (14 | ) | ||
Amount of loss recognized in interest expense (ineffective portion), before tax | (159 | ) | — | |||
Commodity derivatives not designated as hedging instruments: | ||||||
Amount of gain (loss) recognized in operating revenues, before tax | (4,410 | ) | 55 |
Asset Derivatives | Location on Consolidated Balance Sheets | Fair Value at March 31, 2013 | Fair Value at March 31, 2012 | Fair Value at December 31, 2012 | ||||||
(In thousands) | ||||||||||
Designated as hedges: | ||||||||||
Commodity derivatives | Commodity derivative instruments | $ | 1,623 | $ | 25,560 | $ | 18,084 | |||
Other assets - noncurrent | — | 537 | — | |||||||
1,623 | 26,097 | 18,084 | ||||||||
Not designated as hedges: | ||||||||||
Commodity derivatives | Commodity derivative instruments | 4,313 | 1,138 | 220 | ||||||
Other assets - noncurrent | 243 | 45 | — | |||||||
4,556 | 1,183 | 220 | ||||||||
Total asset derivatives | $ | 6,179 | $ | 27,280 | $ | 18,304 |
Liability Derivatives | Location on Consolidated Balance Sheets | Fair Value at March 31, 2013 | Fair Value at March 31, 2012 | Fair Value at December 31, 2012 | ||||||
(In thousands) | ||||||||||
Designated as hedges: | ||||||||||
Commodity derivatives | Commodity derivative instruments | $ | 5,994 | $ | 18,964 | $ | — | |||
Other liabilities - noncurrent | 534 | 6,098 | — | |||||||
Interest rate derivatives | Other accrued liabilities | 4,458 | 1,168 | 6,255 | ||||||
Other liabilities - noncurrent | — | 2,153 | — | |||||||
10,986 | 28,383 | 6,255 | ||||||||
Not designated as hedges: | ||||||||||
Commodity derivatives | Commodity derivative instruments | 1,385 | 1,219 | — | ||||||
Other liabilities - noncurrent | 74 | 49 | — | |||||||
1,459 | 1,268 | — | ||||||||
Total liability derivatives | $ | 12,445 | $ | 29,651 | $ | 6,255 |
March 31, 2013 | Gross Amounts Recognized on the Consolidated Balance Sheets | Gross Amounts Not Offset on the Consolidated Balance Sheets | Net | ||||||
(In thousands) | |||||||||
Assets: | |||||||||
Commodity derivatives | $ | 6,179 | $ | (3,578 | ) | $ | 2,601 | ||
Total assets | $ | 6,179 | $ | (3,578 | ) | $ | 2,601 | ||
Liabilities: | |||||||||
Commodity derivatives | $ | 7,987 | $ | (3,578 | ) | $ | 4,409 | ||
Interest rate derivatives | 4,458 | — | 4,458 | ||||||
Total liabilities | $ | 12,445 | $ | (3,578 | ) | $ | 8,867 |
March 31, 2012 | Gross Amounts Recognized on the Consolidated Balance Sheets | Gross Amounts Not Offset on the Consolidated Balance Sheets | Net | ||||||
(In thousands) | |||||||||
Assets: | |||||||||
Commodity derivatives | $ | 27,280 | $ | (15,805 | ) | $ | 11,475 | ||
Total assets | $ | 27,280 | $ | (15,805 | ) | $ | 11,475 | ||
Liabilities: | |||||||||
Commodity derivatives | $ | 26,330 | $ | (15,805 | ) | $ | 10,525 | ||
Interest rate derivatives | 3,321 | — | 3,321 | ||||||
Total liabilities | $ | 29,651 | $ | (15,805 | ) | $ | 13,846 |
December 31, 2012 | Gross Amounts Recognized on the Consolidated Balance Sheets | Gross Amounts Not Offset on the Consolidated Balance Sheets | Net | ||||||
(In thousands) | |||||||||
Assets: | |||||||||
Commodity derivatives | $ | 18,304 | $ | — | $ | 18,304 | |||
Total assets | $ | 18,304 | $ | — | $ | 18,304 | |||
Liabilities: | |||||||||
Interest rate derivatives | $ | 6,255 | $ | — | $ | 6,255 | |||
Total liabilities | $ | 6,255 | $ | — | $ | 6,255 |
March 31, 2013 | Cost | Gross Unrealized Gains | Gross Unrealized Losses | Fair Value | ||||||||
(In thousands) | ||||||||||||
Insurance contract | $ | 37,270 | $ | 16,064 | $ | — | $ | 53,334 | ||||
Mortgage-backed securities | 8,749 | 133 | (3 | ) | 8,879 | |||||||
U.S. Treasury securities | 1,301 | 39 | — | 1,340 | ||||||||
Total | $ | 47,320 | $ | 16,236 | $ | (3 | ) | $ | 63,553 |
March 31, 2012 | Cost | Gross Unrealized Gains | Gross Unrealized Losses | Fair Value | ||||||||
(In thousands) | ||||||||||||
Insurance contract | $ | 37,250 | $ | 11,454 | $ | — | $ | 48,704 | ||||
Auction rate securities | 11,400 | — | — | 11,400 | ||||||||
Mortgage-backed securities | 7,952 | 119 | (1 | ) | 8,070 | |||||||
U.S. Treasury securities | 1,968 | 49 | (1 | ) | 2,016 | |||||||
Total | $ | 58,570 | $ | 11,622 | $ | (2 | ) | $ | 70,190 |
December 31, 2012 | Cost | Gross Unrealized Gains | Gross Unrealized Losses | Fair Value | ||||||||
(In thousands) | ||||||||||||
Insurance contract | $ | 37,250 | $ | 11,648 | $ | — | $ | 48,898 | ||||
Mortgage-backed securities | 8,054 | 144 | (3 | ) | 8,195 | |||||||
U.S. Treasury securities | 1,763 | 43 | — | 1,806 | ||||||||
Total | $ | 47,067 | $ | 11,835 | $ | (3 | ) | $ | 58,899 |
Fair Value Measurements at March 31, 2013, Using | ||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Balance at March 31, 2013 | |||||||||
(In thousands) | ||||||||||||
Assets: | ||||||||||||
Money market funds | $ | — | $ | 31,281 | $ | — | $ | 31,281 | ||||
Available-for-sale securities: | ||||||||||||
Insurance contract* | — | 53,334 | — | 53,334 | ||||||||
Mortgage-backed securities | — | 8,879 | — | 8,879 | ||||||||
U.S. Treasury securities | — | 1,340 | — | 1,340 | ||||||||
Commodity derivative instruments | — | 6,179 | — | 6,179 | ||||||||
Total assets measured at fair value | $ | — | $ | 101,013 | $ | — | $ | 101,013 | ||||
Liabilities: | ||||||||||||
Commodity derivative instruments | $ | — | $ | 7,987 | $ | — | $ | 7,987 | ||||
Interest rate derivative instruments | — | 4,458 | — | 4,458 | ||||||||
Total liabilities measured at fair value | $ | — | $ | 12,445 | $ | — | $ | 12,445 |
Fair Value Measurements at March 31, 2012, Using | ||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Balance at March 31, 2012 | |||||||||
(In thousands) | ||||||||||||
Assets: | ||||||||||||
Money market funds | $ | — | $ | 9,942 | $ | — | $ | 9,942 | ||||
Available-for-sale securities: | ||||||||||||
Insurance contract* | — | 48,704 | — | 48,704 | ||||||||
Auction rate securities | — | 11,400 | — | 11,400 | ||||||||
Mortgage-backed securities | — | 8,070 | — | 8,070 | ||||||||
U.S. Treasury securities | — | 2,016 | — | 2,016 | ||||||||
Commodity derivative instruments | — | 27,280 | — | 27,280 | ||||||||
Total assets measured at fair value | $ | — | $ | 107,412 | $ | — | $ | 107,412 | ||||
Liabilities: | ||||||||||||
Commodity derivative instruments | $ | — | $ | 26,330 | $ | — | $ | 26,330 | ||||
Interest rate derivative instruments | — | 3,321 | — | 3,321 | ||||||||
Total liabilities measured at fair value | $ | — | $ | 29,651 | $ | — | $ | 29,651 |
Fair Value Measurements at December 31, 2012, Using | ||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Balance at December 31, 2012 | |||||||||
(In thousands) | ||||||||||||
Assets: | ||||||||||||
Money market funds | $ | — | $ | 24,240 | $ | — | $ | 24,240 | ||||
Available-for-sale securities: | ||||||||||||
Insurance contract* | — | 48,898 | — | 48,898 | ||||||||
Mortgage-backed securities | — | 8,195 | — | 8,195 | ||||||||
U.S. Treasury securities | — | 1,806 | — | 1,806 | ||||||||
Commodity derivative instruments | — | 18,304 | — | 18,304 | ||||||||
Total assets measured at fair value | $ | — | $ | 101,443 | $ | — | $ | 101,443 | ||||
Liabilities: | ||||||||||||
Interest rate derivative instruments | $ | — | $ | 6,255 | $ | — | $ | 6,255 | ||||
Total liabilities measured at fair value | $ | — | $ | 6,255 | $ | — | $ | 6,255 |
Carrying Amount | Fair Value | |||||
(In thousands) | ||||||
Long-term debt at March 31, 2013 | $ | 1,789,663 | $ | 1,925,859 | ||
Long-term debt at March 31, 2012 | $ | 1,416,189 | $ | 1,578,395 | ||
Long-term debt at December 31, 2012 | $ | 1,744,975 | $ | 1,888,135 |
Three Months Ended March 31, 2013 | External Operating Revenues | Inter- segment Operating Revenues | Earnings on Common Stock | ||||||
(In thousands) | |||||||||
Electric | $ | 64,654 | $ | — | $ | 9,825 | |||
Natural gas distribution | 331,754 | — | 32,518 | ||||||
Pipeline and energy services | 27,716 | 18,718 | 2,330 | ||||||
424,124 | 18,718 | 44,673 | |||||||
Exploration and production | 115,363 | 9,812 | 20,284 | ||||||
Construction materials and contracting | 161,977 | 4,294 | (20,582 | ) | |||||
Construction services | 229,806 | 1,574 | 11,664 | ||||||
Other | 334 | 1,818 | 305 | ||||||
507,480 | 17,498 | 11,671 | |||||||
Intersegment eliminations | — | (36,216 | ) | — | |||||
Total | $ | 931,604 | $ | — | $ | 56,344 |
Three Months Ended March 31, 2012 | External Operating Revenues | Inter- segment Operating Revenues | Earnings on Common Stock | ||||||
(In thousands) | |||||||||
Electric | $ | 57,963 | $ | — | $ | 7,559 | |||
Natural gas distribution | 307,891 | — | 25,508 | ||||||
Pipeline and energy services | 29,227 | 20,409 | 2,760 | ||||||
395,081 | 20,409 | 35,827 | |||||||
Exploration and production | 88,494 | 11,328 | 12,930 | ||||||
Construction materials and contracting | 149,268 | 151 | (24,932 | ) | |||||
Construction services | 218,151 | 25 | 11,403 | ||||||
Other | 1,813 | 327 | 391 | ||||||
457,726 | 11,831 | (208 | ) | ||||||
Intersegment eliminations | — | (32,240 | ) | — | |||||
Total | $ | 852,807 | $ | — | $ | 35,619 |
Other | ||||||||||||
Postretirement | ||||||||||||
Pension Benefits | Benefits | |||||||||||
Three Months Ended March 31, | 2013 | 2012 | 2013 | 2012 | ||||||||
(In thousands) | ||||||||||||
Components of net periodic benefit cost: | ||||||||||||
Service cost | $ | 40 | $ | 345 | $ | 504 | $ | 412 | ||||
Interest cost | 4,018 | 4,554 | 940 | 1,143 | ||||||||
Expected return on assets | (5,083 | ) | (5,886 | ) | (1,107 | ) | (1,244 | ) | ||||
Amortization of prior service cost (credit) | 18 | (21 | ) | (364 | ) | (272 | ) | |||||
Amortization of net actuarial loss | 1,864 | 1,681 | 671 | 526 | ||||||||
Amortization of net transition obligation | — | — | — | 532 | ||||||||
Net periodic benefit cost, including amount capitalized | 857 | 673 | 644 | 1,097 | ||||||||
Less amount capitalized | 110 | 234 | 29 | 138 | ||||||||
Net periodic benefit cost | $ | 747 | $ | 439 | $ | 615 | $ | 959 |
March 31, 2013 | |||
(In thousands) | |||
ASSETS | |||
Current assets: | |||
Cash and cash equivalents | $ | 10,793 | |
Total current assets | 10,793 | ||
Net property, plant and equipment | 27,356 | ||
Total assets | $ | 38,149 | |
LIABILITIES | |||
Current liabilities: | |||
Accounts payable | $ | 10,948 | |
Total liabilities | $ | 10,948 |
• | 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 | ||||||
March 31, | ||||||
2013 | 2012 | |||||
(Dollars in millions, where applicable) | ||||||
Electric | $ | 9.8 | $ | 7.5 | ||
Natural gas distribution | 32.5 | 25.5 | ||||
Pipeline and energy services | 2.3 | 2.8 | ||||
Exploration and production | 20.3 | 12.9 | ||||
Construction materials and contracting | (20.6 | ) | (24.9 | ) | ||
Construction services | 11.7 | 11.4 | ||||
Other | .4 | .5 | ||||
Earnings before discontinued operations | 56.4 | 35.7 | ||||
Loss from discontinued operations, net of tax | (.1 | ) | (.1 | ) | ||
Earnings on common stock | $ | 56.3 | $ | 35.6 | ||
Earnings per common share - basic: | ||||||
Earnings before discontinued operations | $ | .30 | $ | .19 | ||
Discontinued operations, net of tax | — | — | ||||
Earnings per common share - basic | $ | .30 | $ | .19 | ||
Earnings per common share - diluted: | ||||||
Earnings before discontinued operations | $ | .30 | $ | .19 | ||
Discontinued operations, net of tax | — | — | ||||
Earnings per common share - diluted | $ | .30 | $ | .19 |
• | Increased oil production, partially offset by decreased natural gas production and higher depreciation, depletion and amortization expense at the exploration and production business |
• | Increased retail sales volumes and a gain on the sale of a nonregulated appliance service and repair business at the natural gas distribution business |
• | Higher aggregate, asphalt and construction margins at the construction materials and contracting business |
• | Increased retail sales volumes at the electric business |
Three Months Ended | ||||||
March 31, | ||||||
2013 | 2012 | |||||
(Dollars in millions, where applicable) | ||||||
Operating revenues | $ | 64.6 | $ | 58.0 | ||
Operating expenses: | ||||||
Fuel and purchased power | 21.6 | 18.4 | ||||
Operation and maintenance | 16.4 | 16.2 | ||||
Depreciation, depletion and amortization | 8.6 | 8.1 | ||||
Taxes, other than income | 2.9 | 2.7 | ||||
49.5 | 45.4 | |||||
Operating income | 15.1 | 12.6 | ||||
Earnings | $ | 9.8 | $ | 7.5 | ||
Retail sales (million kWh) | 842.6 | 769.7 | ||||
Sales for resale (million kWh) | 7.4 | 1.9 | ||||
Average cost of fuel and purchased power per kWh | $ | .024 | $ | .022 |
• | Increased retail sales volumes of 9 percent, primarily to residential and small commercial and industrial customers due to colder weather than last year, as well as increased customer growth |
• | Higher other income of $300,000 (after tax), largely allowance for funds used during construction |
Three Months Ended | ||||||
March 31, | ||||||
2013 | 2012 | |||||
(Dollars in millions, where applicable) | ||||||
Operating revenues | $ | 331.7 | $ | 307.9 | ||
Operating expenses: | ||||||
Purchased natural gas sold | 213.4 | 199.3 | ||||
Operation and maintenance | 34.1 | 35.3 | ||||
Depreciation, depletion and amortization | 12.2 | 11.2 | ||||
Taxes, other than income | 16.3 | 16.1 | ||||
276.0 | 261.9 | |||||
Operating income | 55.7 | 46.0 | ||||
Earnings | $ | 32.5 | $ | 25.5 | ||
Volumes (MMdk): | ||||||
Sales | 44.9 | 38.7 | ||||
Transportation | 38.2 | 37.9 | ||||
Total throughput | 83.1 | 76.6 | ||||
Degree days (% of normal)* | ||||||
Montana-Dakota/Great Plains | 98 | % | 77 | % | ||
Cascade | 99 | % | 101 | % | ||
Intermountain | 114 | % | 93 | % | ||
Average cost of natural gas, including transportation, per dk | $ | 4.75 | $ | 5.15 | ||
* Degree days are a measure of the daily temperature-related demand for energy for heating. |
• | Increased retail sales volumes of 16 percent, largely resulting from colder weather than last year, partially offset by weather normalization in certain jurisdictions |
• | A $2.9 million (after tax) gain on the sale of Montana-Dakota's nonregulated appliance service and repair business |
• | Lower net interest expense of $500,000 (after tax), primarily due to lower average borrowings |
Three Months Ended | |||||||
March 31, | |||||||
2013 | 2012 | ||||||
(Dollars in millions) | |||||||
Operating revenues | $ | 46.4 | $ | 49.6 | |||
Operating expenses: | |||||||
Purchased natural gas sold | 12.8 | 16.0 | |||||
Operation and maintenance | 17.2 | 17.1 | |||||
Depreciation, depletion and amortization | 7.2 | 6.2 | |||||
Taxes, other than income | 3.4 | 3.5 | |||||
40.6 | 42.8 | ||||||
Operating income | 5.8 | 6.8 | |||||
Earnings | $ | 2.3 | $ | 2.8 | |||
Transportation volumes (MMdk) | 36.8 | 32.0 | |||||
Natural gas gathering volumes (MMdk) | 9.9 | 14.2 | |||||
Customer natural gas storage balance (MMdk): | |||||||
Beginning of period | 43.7 | 36.0 | |||||
Net withdrawal | (19.0 | ) | (8.7 | ) | |||
End of period | 24.7 | 27.3 |
Three Months Ended | ||||||
March 31, | ||||||
2013 | 2012 | |||||
(Dollars in millions, where applicable) | ||||||
Operating revenues: | ||||||
Oil | $ | 97.8 | $ | 63.7 | ||
NGL | 7.5 | 9.7 | ||||
Natural gas | 19.9 | 26.4 | ||||
125.2 | 99.8 | |||||
Operating expenses: | ||||||
Operation and maintenance: | ||||||
Lease operating costs | 20.8 | 18.5 | ||||
Gathering and transportation | 4.3 | 4.3 | ||||
Other | 10.2 | 9.2 | ||||
Depreciation, depletion and amortization | 43.1 | 36.8 | ||||
Taxes, other than income: | ||||||
Production and property taxes | 11.6 | 9.5 | ||||
Other | .3 | .4 | ||||
90.3 | 78.7 | |||||
Operating income | 34.9 | 21.1 | ||||
Earnings | $ | 20.3 | $ | 12.9 | ||
Production: | ||||||
Oil (MBbls) | 1,118 | 767 | ||||
NGL (MBbls) | 201 | 190 | ||||
Natural gas (MMcf) | 6,713 | 10,047 | ||||
Total production (MBOE) | 2,438 | 2,632 | ||||
Average realized prices (including hedges): | ||||||
Oil (per Bbl) | $ | 87.42 | $ | 83.14 | ||
NGL (per Bbl) | $ | 37.33 | $ | 50.85 | ||
Natural gas (per Mcf) | $ | 2.97 | $ | 2.63 | ||
Average realized prices (excluding hedges): | ||||||
Oil (per Bbl) | $ | 89.44 | $ | 93.01 | ||
NGL (per Bbl) | $ | 37.33 | $ | 50.85 | ||
Natural gas (per Mcf) | $ | 2.86 | $ | 1.94 | ||
Average depreciation, depletion and amortization rate, per BOE | $ | 16.90 | $ | 13.32 | ||
Production costs, including taxes, per BOE: | ||||||
Lease operating costs | $ | 8.54 | $ | 7.02 | ||
Gathering and transportation | 1.76 | 1.63 | ||||
Production and property taxes | 4.74 | 3.62 | ||||
$ | 15.04 | $ | 12.27 |
• | Increased oil production of 46 percent, primarily related to drilling activity in the Bakken area, as well as the Paradox Basin |
• | Higher average realized natural gas prices of 13 percent |
• | Higher average realized oil prices of 5 percent |
• | Decreased natural gas production of 33 percent, largely related to production curtailments, normal declines and deferral of certain natural gas development activity |
• | Higher depreciation, depletion and amortization expense of $4.0 million (after tax) due to higher depletion rates, partially offset by lower volumes |
• | Lower average realized NGL prices of 27 percent |
• | Increased lease operating expenses of $1.5 million (after tax), largely related to higher costs in the Bakken area resulting from increased production volumes, partially offset by lower costs at certain natural gas properties where curtailments of production have occurred |
• | Higher production taxes of $1.3 million (after tax), primarily resulting from higher revenues |
• | Higher net interest expense of $1.0 million (after tax), primarily due to lower capitalized interest and higher average borrowings, partially offset by lower effective interest rates |
Three Months Ended | ||||||
March 31, | ||||||
2013 | 2012 | |||||
(Dollars in millions) | ||||||
Operating revenues | $ | 166.3 | $ | 149.4 | ||
Operating expenses: | ||||||
Operation and maintenance | 166.6 | 157.0 | ||||
Depreciation, depletion and amortization | 19.0 | 19.8 | ||||
Taxes, other than income | 8.5 | 8.0 | ||||
194.1 | 184.8 | |||||
Operating loss | (27.8 | ) | (35.4 | ) | ||
Loss | $ | (20.6 | ) | $ | (24.9 | ) |
Sales (000's): | ||||||
Aggregates (tons) | 2,958 | 2,493 | ||||
Asphalt (tons) | 149 | 100 | ||||
Ready-mixed concrete (cubic yards) | 480 | 468 |
• | Higher earnings of $2.8 million (after tax) resulting from higher aggregate and asphalt margins, primarily due to lower costs |
• | Increased construction margins of $1.0 million (after tax) |
• | Lower selling, general and administrative costs of $700,000 (after tax) |
Three Months Ended | ||||||
March 31, | ||||||
2013 | 2012 | |||||
(In millions) | ||||||
Operating revenues | $ | 231.4 | $ | 218.2 | ||
Operating expenses: | ||||||
Operation and maintenance | 198.4 | 187.9 | ||||
Depreciation, depletion and amortization | 3.0 | 2.8 | ||||
Taxes, other than income | 9.6 | 7.8 | ||||
211.0 | 198.5 | |||||
Operating income | 20.4 | 19.7 | ||||
Earnings | $ | 11.7 | $ | 11.4 |
Three Months Ended | ||||||
March 31, | ||||||
2013 | 2012 | |||||
(In millions) | ||||||
Other: | ||||||
Operating revenues | $ | 2.2 | $ | 2.1 | ||
Operation and maintenance | 1.3 | 1.3 | ||||
Depreciation, depletion and amortization | .5 | .5 | ||||
Intersegment transactions: | ||||||
Operating revenues | $ | 36.2 | $ | 32.2 | ||
Purchased natural gas sold | 27.0 | 29.9 | ||||
Operation and maintenance | 9.2 | 2.3 |
• | Earnings per common share for 2013, diluted, are projected in the range of $1.30 to $1.40. The Company expects the approximate percentage of 2013 earnings per common share by quarter to be: |
◦ | Second quarter – 20 percent |
◦ | Third quarter – 30 percent |
◦ | Fourth quarter – 25 percent |
• | The Company's long-term compound annual growth goals on earnings per share from operations are in the range of 7 to 10 percent. |
• | The Company continually seeks opportunities to expand through organic growth and strategic acquisitions. |
• | The Company focuses on creating value through vertical integration between its business units. For example, the pipeline and energy services business' partially owned diesel topping plant under construction in the Bakken region, will have the construction materials and services business involved in constructing the facility, the exploration and production business supplying production to the plant, the pipeline transporting natural gas to the plant, and the utility supplying electricity. |
• | The Company filed an application February 11, 2013, with the NDPSC for approval of an environmental cost recovery rider related to costs for the required environmental retrofit at the Big Stone Station, as discussed in Note 17. |
• | The Company filed an application December 21, 2012, with the SDPUC for a natural gas rate increase, as discussed in Note 17. |
• | The Company filed an application September 26, 2012, with the MTPSC for a natural gas rate increase, as discussed in Note 17. |
• | The EPA approved the South Dakota Regional Haze Program, which requires the Big Stone Station to install and operate a BART air-quality control system to reduce emissions of particulate matter, sulfur dioxide and nitrogen oxides. The |
• | The Company plans to construct and operate an 88-MW simple-cycle natural gas turbine and associated facilities, with an estimated project cost of $86 million and a projected in-service date in late 2014. It will be located on owned property that is adjacent to the Company's Heskett Generating Station near Mandan, North Dakota. The capacity is necessary to meet the requirements of the Company's integrated electric system customers and will be a partial replacement for third-party contract capacity expiring in 2015. Advance determination of prudence and a Certificate of Public Convenience and Necessity have been received from the NDPSC. |
• | Planned investments are approximately $75 million for 2013 to serve the growing electric and natural gas customer base associated with the Bakken oil development in western North Dakota and eastern Montana. |
• | Rate base growth is projected to be approximately 6 percent compounded annually over the next five years. |
• | The Company is analyzing potential projects for accommodating load growth in its industrial and agricultural sectors, with company- and customer-owned pipeline facilities designed to serve existing facilities served by fuel oil or propane, and to serve new customers. The Company is currently engaged in a 30-mile natural gas line project into the Hanford Nuclear Site in Washington. |
• | The Company is involved with a number of pipeline projects to enhance the reliability and deliverability of its system in the Pacific Northwest and Idaho. |
• | Opportunities associated with the potential development of high-voltage transmission lines and system enhancements targeted toward delivery of energy to major market areas are being pursued. |
• | On March 13, 2013, the OPUC approved an extension of Cascade's decoupling mechanism, as reported in Items 1 and 2 - Business and Properties - General in the 2012 Annual Report, until December 31, 2015. |
• | The Company has formed a limited liability company with Calumet, called Dakota Prairie Refining, to develop, build and operate a 20,000 barrel-per-day diesel topping plant in southwestern North Dakota. Construction began on the facility in late March 2013 and when complete will process Bakken crude and market the diesel within the Bakken region. Total project costs are estimated to be approximately $300 million, with a projected in-service date in late 2014. |
• | In May 2012, the Company purchased a 50 percent undivided interest in Whiting Oil and Gas Corporation's Pronghorn natural gas and oil midstream assets near Belfield, North Dakota, in the Bakken area. The Company invested approximately $100 million in 2012 including the purchase price. The Belfield natural gas processing plant has an inlet processing capacity of 35 MMcf per day. The Company will receive a full year of benefit from this acquisition in 2013. |
• | In August 2012, the Company placed in service approximately 13 miles of high-pressure transmission pipeline from the Stateline processing facilities in northwestern North Dakota to deliver natural gas into the Northern Border Pipeline, which is expected to result in increased transportation volumes for 2013. |
• | Dry natural gas gathering volumes are expected to be lower in 2013 compared to 2012 because of curtailments and the deferral of development activity by producers. |
• | The Company recently reached an agreement to construct a pipeline in 2014 to connect the planned Garden Creek II gas processing plant in northwestern North Dakota to deliver natural gas into the Northern Border Pipeline. |
• | The Company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region, which includes portions of Colorado, Montana, North Dakota and Wyoming, is expanding, most notably the Bakken area of North Dakota and eastern Montana. The Company owns an extensive natural gas pipeline system in the Bakken area. Ongoing energy development is expected to have many direct and indirect benefits to this business. |
• | The Company expects to spend approximately $400 million in capital expenditures in 2013. With improving well cost efficiencies and having essentially completed the extensive 2012 exploration program, the capital program will focus on |
• | For 2013, the Company expects a 25 to 30 percent increase in oil production, a flat to slight increase in NGL production, and a 15 to 25 percent decrease in natural gas production. The majority of the capital program is focused on growing oil production considering current relative commodity prices. The Company expects to return to some natural gas development when the commodity prices make it more profitable to do so. |
• | The Company has a total of five drilling rigs deployed on its acreage in the Bakken, Paradox and Texas areas. |
• | Bakken areas |
◦ | The Company owns a total of approximately 127,000 net acres of leaseholds in Mountrail, Stark and Richland counties. |
◦ | Capital expenditures are expected to total approximately $200 million in 2013. The Company is currently operating three rigs in the play; with improving drilling efficiencies and other factors that number could vary across the year from two to three rigs. |
• | Paradox Basin, Utah |
◦ | The Company has increased its holding to approximately 92,000 net acres and also has an option to lease another 20,000 acres. |
◦ | The Cane Creek 18-1 well was brought on line in April 2013 and is currently flowing at approximately 1,000 BOPD with a flowing tube pressure of approximately 2,000 psi. |
◦ | The Company is continuing to proceed systematically in this play, and anticipates spending $70 million of capital expenditures in 2013. As the play is fully understood, the opportunity to ramp up to full-scale development could increase the planned investment. At this point, the potential appears very significant. |
◦ | Approximately 50 to 75 future net locations have been identified. Estimated gross ultimate recovery rates per well range from 250,000 to 1 million Bbls. |
• | Texas |
◦ | The Company is targeting areas that have the potential for higher liquids content with approximately $40 million of capital planned for this year. |
• | Other opportunities |
◦ | The Company completed drilling a horizontal well during April 2013 in Sioux County, Nebraska. Completion operations will be conducted during the second quarter of 2013. Upon evaluation of this well, the Company may exercise an option to purchase a 65 percent working interest in approximately 79,000 gross acres. |
◦ | The remaining forecasted 2013 capital has been allocated to other operated and non-operated opportunities. |
• | Earnings guidance reflects estimated average NYMEX index prices for May through December in the ranges of $85.00 to $95.00 per Bbl of crude oil, and $3.75 to $4.25 per Mcf of natural gas. Estimated prices for NGL are in the range of $30.00 to $45.00 per Bbl. |
• | For the last nine months of 2013, the Company has hedged 9,000 BOPD utilizing swaps and costless collars with a weighted average price of $98.67 and $92.50/$107.03 (floor/ceiling) respectively, and 50,000 MMBtu of natural gas per day, with an additional 10,000 MMBtu per day for September through December, utilizing swaps at a weighted average price of $3.76. |
• | For the first six months of 2014, the Company has hedged 2,000 BOPD utilizing swaps with a weighted average price of $95.075, and for 2014 the Company has hedged 20,000 MMBtu of natural gas per day utilizing swaps at a weighted average price of $4.13. |
• | For 2015, the Company has hedged 10,000 MMBtu of natural gas per day utilizing a swap at $4.2825. |
• | The hedges that are in place as of April 30, 2013, are summarized in the following chart: |
Commodity | Type | Index | Period Outstanding | Forward Notional Volume (Bbl/MMBtu) | Price (Per Bbl/MMBtu) |
Crude Oil | Collar | NYMEX | 4/13 - 12/13 | 275,000 | $95.00-$117.00 |
Crude Oil | Collar | NYMEX | 4/13 - 12/13 | 275,000 | $90.00-$97.05 |
Crude Oil | Swap | NYMEX | 4/13 - 12/13 | 137,500 | $95.00 |
Crude Oil | Swap | NYMEX | 4/13 - 12/13 | 137,500 | $95.30 |
Crude Oil | Swap | NYMEX | 4/13 - 12/13 | 137,500 | $100.00 |
Crude Oil | Swap | NYMEX | 4/13 - 12/13 | 137,500 | $100.02 |
Crude Oil | Swap | NYMEX | 4/13 - 12/13 | 275,000 | $102.00 |
Crude Oil | Swap | NYMEX | 4/13 - 12/13 | 275,000 | $104.00 |
Crude Oil | Swap | NYMEX | 4/13 - 12/13 | 275,000 | $98.00 |
Crude Oil | Swap | NYMEX | 4/13 - 12/13 | 137,500 | $94.15 |
Crude Oil | Swap | NYMEX | 4/13 - 12/13 | 137,500 | $94.00 |
Crude Oil | Swap | NYMEX | 4/13 - 12/13 | 275,000 | $97.45 |
Crude Oil | Swap | NYMEX | 1/14 - 6/14 | 181,000 | $95.15 |
Crude Oil | Swap | NYMEX | 1/14 - 6/14 | 181,000 | $95.00 |
Natural Gas | Swap | NYMEX | 4/13 - 12/13 | 2,750,000 | $3.76 |
Natural Gas | Swap | NYMEX | 4/13 - 12/13 | 2,750,000 | $3.90 |
Natural Gas | Swap | NYMEX | 4/13 - 12/13 | 2,750,000 | $4.00 |
Natural Gas | Swap | NYMEX | 4/13 - 12/13 | 5,500,000 | $3.50 |
Natural Gas | Swap | NYMEX | 9/13 - 12/14 | 4,870,000 | $4.13 |
Natural Gas | Swap | NYMEX | 1/14 - 12/14 | 3,650,000 | $4.13 |
Natural Gas | Swap | NYMEX | 1/15 - 12/15 | 3,650,000 | $4.2825 |
• | Effective April 1, 2013, the Company has elected to discontinue hedge accounting, as discussed in Note 12. |
• | Approximate work backlog as of March 31, 2013, was $589 million, compared to $532 million a year ago. Private work represents 12 percent of construction backlog, up from 9 percent a year ago. Public work represents 88 percent of backlog. The backlog includes a variety of projects such as highway paving projects, airports, bridge work, reclamation and harbor expansions. |
• | The Company's approximate backlog in North Dakota was $67 million, compared to approximately $40 million a year ago. |
• | Projected revenues included in the Company's 2013 earnings guidance are in the range of $1.5 billion to $1.7 billion. |
• | The Company anticipates margins in 2013 to be higher compared to 2012. |
• | The Company continues to pursue opportunities for expansion in energy projects such as refineries, transmission, wind towers and geothermal. Initiatives are aimed at capturing additional market share and expanding into new markets. |
• | As the country's fifth-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 four labor contracts that Knife River was negotiating, as reported in Items 1 and 2 - Business and Properties - General in the 2012 Annual Report, three have been ratified. The one remaining contract is still in negotiations. |
• | Approximate work backlog as of March 31, 2013, was $465 million, compared to $333 million a year ago. The backlog includes a variety of projects such as substation and line construction, solar and other commercial, institutional and industrial projects including refinery work. |
• | Projected revenues included in the Company's 2013 earnings guidance are in the range of $900 million to $1 billion. |
• | The Company anticipates margins in 2013 to be lower compared to 2012. |
• | The Company continues to pursue opportunities for expansion in energy projects such as refineries, transmission, substations, utility services, as well as solar. Initiatives are aimed at capturing additional market share and expanding into new markets. |
• | System upgrades |
• | Routine replacements |
• | Service extensions |
• | Routine equipment maintenance and replacements |
• | Buildings, land and building improvements |
• | Pipeline, gathering and other midstream projects |
• | Further development of existing properties, acquisition of additional leasehold acreage and exploratory drilling at the exploration and production segment |
• | Power generation and transmission opportunities, including certain costs for additional electric generating capacity |
• | Environmental upgrades |
• | The diesel topping plant at the pipeline and energy services segment |
• | Other growth opportunities |
Company | Facility | Facility Limit | Amount Outstanding | Expiration Date | |||||||||
(In millions) | |||||||||||||
MDU Resources Group, Inc. | Commercial paper/ Revolving credit agreement | (a) | $ | 125.0 | $ | 72.0 | (b) | 10/4/17 | |||||
Cascade Natural Gas Corporation | Revolving credit agreement | $ | 50.0 | (c) | $ | 17.0 | 12/27/13 | ||||||
Intermountain Gas Company | Revolving credit agreement | $ | 65.0 | (d) | $ | 20.5 | 8/11/13 | ||||||
Centennial Energy Holdings, Inc. | Commercial paper/ Revolving credit agreement | (e) | $ | 500.0 | $ | 229.0 | (b) | 6/8/17 | |||||
(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. (d) Certain provisions allow for increased borrowings, up to a maximum of $80 million. (e) The $500 million commercial paper program is supported by a revolving credit agreement with various banks totaling $500 million (provisions allow for increased borrowings, at the option of Centennial on stated conditions, up to a maximum of $650 million). There were no amounts outstanding under the credit agreement. |
(Forward notional volume and fair value in thousands) | |||||||||
Weighted Average Fixed Price (Per Bbl/MMBtu) | Forward Notional Volume (Bbl/MMBtu) | Fair Value | |||||||
Oil swap agreements maturing in 2013 | $ | 98.67 | 1,925 | $ | 3,633 | ||||
Oil swap agreements maturing in 2014 | $ | 95.08 | 362 | $ | 482 | ||||
Natural gas swap agreements maturing in 2013 | $ | 3.76 | 14,970 | $ | (5,464 | ) | |||
Natural gas swap agreements maturing in 2014 | $ | 4.13 | 7,300 | $ | (709 | ) | |||
Natural gas swap agreement maturing in 2015 | $ | 4.28 | 3,650 | $ | (74 | ) | |||
Weighted Average Floor/Ceiling Price (Per Bbl) | Forward Notional Volume (Bbl) | Fair Value | |||||||
Oil collar agreements maturing in 2013 | $92.50/$107.03 | 550 | $ | 324 |
(Notional amount and fair value in thousands) | ||||||||
Weighted Average Fixed Interest Rate | Notional Amount | Fair Value | ||||||
Interest rate swap agreements with mandatory termination dates in 2013 | 3.23 | % | $ | 40,000 | $ | (4,458 | ) |
MDU RESOURCES GROUP, INC. | |||
DATE: | May 7, 2013 | 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 |
Exhibit No. | ||
3 | Company Bylaws, as amended and restated, on March 4, 2013 | |
+10(a) | MDU Resources Group, Inc. Executive Incentive Compensation Plan, as amended March 4, 2013, and Rules and Regulations, as amended March 4, 2013 | |
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 | |
95 | Mine Safety Disclosures | |
101 | The following materials from MDU Resources Group, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements, tagged in summary and detail |
Bylaws of | ||
MDU RESOURCES | ||
GROUP, INC. |
Page No. | |||
OFFICES | 1 | ||
1.01 Registered Office | 1 | ||
1.02 Other Offices | 1 | ||
MEETINGS OF STOCKHOLDERS | 1 | ||
2.01 Place of Meetings | 1 | ||
2.02 Annual Meetings | 1 | ||
2.03 Notice of Annual Meeting | 2 | ||
2.04 Stockholders List | 2 | ||
2.05 Notice of Special Meeting | 2 | ||
2.06 Quorum; Adjournment; and Organization | 2 | ||
2.07 Voting Rights | 3 | ||
2.08 Nominations for Director | 3 | ||
2.09 Business at Meetings of Stockholders | 7 | ||
DIRECTORS | 9 | ||
3.01 Authority of Directors | 9 | ||
3.02 Qualifications | 9 | ||
3.03 Place of Meetings | 9 | ||
3.04 Annual Meetings | 9 | ||
3.05 Regular Meetings | 9 | ||
3.06 Special Meetings | 9 | ||
3.07 Quorum | 10 | ||
3.08 Participation of Directors by Conference Telephone | 10 | ||
3.09 Written Action of Directors | 10 | ||
3.10 Committees | 10 | ||
3.11 Reports of Committees | 10 | ||
3.12 Compensation of Directors | 11 | ||
3.13 Chairman of the Board | 11 | ||
NOTICES | 11 | ||
4.01 Notices | 11 | ||
4.02 Waiver | 11 | ||
OFFICERS | 11 | ||
5.01 Election, Qualifications | 11 | ||
5.02 Additional Officers | 12 | ||
5.03 Salaries | 12 | ||
5.04 Term | 12 |
5.05 Chief Executive Officer | 12 | ||
5.06 The President | 12 | ||
5.07 The Vice Presidents | 12 | ||
5.08 The Secretary and Assistant Secretaries | 12 | ||
5.09 Treasurer and Assistant Treasurers | 13 | ||
5.10 General Counsel | 13 | ||
5.11 Authority and Duties | 14 | ||
5.12 Execution of Instruments | 14 | ||
5.13 Execution of Proxies | 14 | ||
CERTIFICATES OF STOCK | 14 | ||
6.01 Certificates | 14 | ||
6.02 Signatures | 14 | ||
6.03 Special Designation on Certificates | 15 | ||
6.04 Lost Certificates | 15 | ||
6.05 Transfers of Stock | 15 | ||
6.06 Record Date | 15 | ||
6.07 Registered Stockholders | 15 | ||
GENERAL PROVISIONS | 16 | ||
7.01 Dividends | 16 | ||
7.02 Checks | 16 | ||
7.03 Fiscal Year | 16 | ||
7.04 Seal | 16 | ||
7.05 Inspection of Books and Records | 16 | ||
7.06 Amendments | 16 | ||
7.07 Indemnification of Officers, Directors, Employees and Agents | 17 | ||
7.08 Severability | 18 |
I. | DEFINITIONS |
1. | The “Administrator” shall be the Compensation Committee of the Board of Directors of MDUR with respect to employees subject to Section 16 of the Securities Exchange Act of 1934, as amended. With respect to employees who are not subject to Section 16, the Chief Executive Officer of MDUR, with respect to MDUR employees, and the chief executive officer of each business segment, in conjunction with the Chief Executive Officer of MDUR, with respect to the business segment’s employees, shall be the Administrator. |
2. | "Change in Control" shall mean the occurrence of any of the following transactions or events: (a) any person (which shall not include MDUR, any subsidiary of MDUR or any employee benefit plan of MDUR or of any subsidiary of MDUR) ("Person") or group (as that term is defined in Treasury Regulation Section 1.409A-3(i)(5)(v)(B)), acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person or Persons) ownership of stock of MDUR possessing 30% or more of the total voting power of the stock of MDUR; (b) any Person or group (as that term is defined in Treasury Regulation Section 1.409A-3(i)(5)(v)(B)), acquires ownership of the stock of MDUR that, together with stock held by such Person or group, constitutes more |
3. | The “Code” shall mean the Internal Revenue Code of 1986, as amended. |
4. | The “Compensation Committee” shall be the Compensation Committee of the Board of Directors of MDUR. |
5. | "MDUR" shall refer to MDU Resources Group, Inc. alone and shall not refer to any of its business segments, divisions or subsidiaries. |
6. | The "Moody's Rate" is defined as the average of (i) the number that results from adding the daily Moody’s U.S. Long-Term Corporate Bond Yield |
7. | "Participants" for any Plan Year shall be those executives who have been approved by the Administrator as eligible for participation in the Plan for such Plan Year. |
8. | "Payment Date" shall be the date set by the Administrator for payment of awards pursuant to Section X of the Plan, other than those awards deferred pursuant to Section X of the Plan and Section VII of these Rules and Regulations. |
9. | The "Plan" shall refer to the Executive Incentive Compensation Plan, as it has been and may be amended. |
10. | The "Plan Year" shall be the calendar year. |
11. | “Retirement” means the later of the day the Participant attains age 55 or the day the Participant ceases to be an employee of MDUR or any of its business segments, divisions or subsidiaries. |
12. | “Service Year” means the Plan Year during which the services giving rise to the incentive award are performed. |
13. | “Specified Employee” means an employee who, as of the date the employee separates from service, is a “specified employee” (as that term is used in Section 409A(a)(2)(B) of the Code), as determined under MDUR's policy for determining specified employees. |
II. | ADMINISTRATION |
1. | The Compensation Committee shall have the full power to construe and interpret the Plan and to establish and to amend these Rules and Regulations for its administration. |
2. | The Administrator shall not participate in a decision as to the Administrator’s eligibility for, or award of, an incentive award payment. |
3. | For each Plan Year, the Administrator shall approve a list of eligible executives and notify those so approved that they are eligible to participate in the Plan for such Plan Year. |
4. | No later than 90 days after the beginning of each Plan Year, the Administrator shall approve the Plan’s performance measures, performance targets and target incentive award levels for each salary grade covered by the Plan for the Plan Year. |
5. | The Administrator shall have final discretion to determine actual award payment levels, method of payment, and whether or not payments shall be made for any Plan Year. However, unless the Plan's performance goals are met for the Plan Year, no award shall be made for that Plan Year. Performance targets modified pursuant to Section III of the Plan will be deemed performance targets for purposes of determining whether or not these targets have been met. |
1. | The Administrator shall establish the percentage attainment of performance measures. The Administrator may establish more or fewer performance measures as it deems necessary. |
2. | The performance measures may be set by reference to earnings, return on invested capital or any other measure or combination of measures deemed appropriate by the Administrator. They may be established for MDUR or any of its business segments, divisions or subsidiaries. The Administrator may assign different performance measures and/or different weights to performance measures for each Participant. |
3. | The Administrator shall cause to be prepared a list of individuals to whom the Plan performance measures will be applied and shall identify the applicable performance measures for each Participant, which may vary among Participants. |
4. | The Administrator may set threshold, target and/or maximum award levels for some or all of the performance measures, and those levels shall be included on the list referred to in paragraph 3 above. |
5. | The Administrator will retain the authority to determine whether or not the actual attainment of these measures has been made. |
1. | Target incentive awards will be a percentage of each Participant’s Salary, as defined in the Plan. |
2. | Target incentive awards shall be set by the Administrator annually and will be included on the list referred to above. |
1. | The target incentive fund is the sum of the individual target incentive awards for all eligible Participants. |
2. | Once individual incentive targets have been determined, a target incentive fund shall be established and accrued ratably by MDUR and each of its business segments, divisions and/or subsidiaries, as applicable. The incentive fund and accruals may be adjusted during the year. |
3. | As soon as practicable following the close of each Plan Year, the Chief Executive Officer of MDUR will cause to be prepared an analysis showing performance in relation to the performance measures. The Administrator will review the analysis and determine, in its sole discretion, the amount of the actual incentive fund. |
4. | In determining the actual incentive fund, any recommendations of the Chief Executive Officer of MDUR or the Administrator will be considered. |
1. | The Administrator shall have the sole discretion to determine each individual Participant's award. |
2. | Each individual Participant’s award will be based upon the level of performance achieved relative to the established performance measures, as determined by a percentage from 0 percent to a maximum of 250 percent, as determined by the Administrator. |
1. | On the date the Administrator determines the awards to be made to individual Participants, it shall also establish the Payment Date. |
2. | Except as provided below or in the Plan or as the Administrator otherwise determines, in order to receive an award under the Plan, a Participant must remain in the employment of the Participant’s employer for the entire Service Year. |
3. | If a Participant terminates employment with MDUR pursuant to Section 5.01 of MDUR’s Bylaws, which provides for mandatory retirement for certain officers on their 65th birthday (or terminates employment with a business segment, division and/or subsidiary of MDUR pursuant to a similar company Bylaw provision), and if the Participant’s 65th birthday occurs during the Service Year, determination of whether the performance measures have been met will be made at the end of the Service Year, and to the extent met, payment of the award will be made to the Participant, prorated. Proration of awards shall be based upon the number of full months elapsed from and including January to and including the month in which the Participant’s 65th birthday occurs. |
4. | Payment of the awards shall be made in cash. Payments shall be made on the Payment Date unless the Participant has deferred, in whole or in part, the receipt of the award by making an election on the deferral form attached hereto, prior to the beginning of the Service Year. Deferral elections may not be changed or revoked after the Service Year begins. |
5. | In the event a Participant has elected to defer receipt of all or a portion of the award, MDUR or one of its business segments, divisions or subsidiaries, as applicable shall set up an account in the Participant's name. The amount of the Participant's award to the extent deferred will be credited to the Participant's account on the Payment Date. |
6. | The balance credited to an account of a Participant who has elected to defer receipt of an award will be an unsecured, unfunded obligation of MDUR or one of its business segments, divisions or subsidiaries, as applicable. |
7. | Interest shall accrue on the balance credited to a Participant's account from the date the balance is credited. The rate of interest for each Plan Year shall be the Moody’s Rate. |
8. | Interest shall be compounded and credited to the account monthly. |
9. | A Participant may elect to defer any percentage, not to exceed l00, of an annual award. |
10. | A Participant electing to defer any part of an award must elect one of the following dates on which (a) payment will be made, if payment will be made in a lump sum or (b) payments will commence, if payment will be made in monthly installments: |
(1) | Between January 1 and March 10 next following termination of employment with MDUR, its business segments, divisions and subsidiaries, as applicable; or |
(2) | Between January 1 and March 10 of the fifth year following the year in which the award would have been paid had it not been deferred. |
11. | A Participant may elect to receive the deferred amounts accumulated in the Participant's account in monthly installments, not to exceed 120. In the event the Participant elects to receive the amounts in the Participant's account in more than one installment, interest shall continue to accrue on the balance remaining in their account at the applicable rate or rates determined annually by the Compensation Committee. |
12. | Notwithstanding anything contained in the Plan or these Rules and Regulations to the contrary, if a Specified Employee's employment terminates, to the extent required by Section 409A(a)(2)(B) of the Code, except as otherwise provided in paragraph 13 below of this Section VII of these Rules and Regulations, payment of any deferred amounts under the Plan that are to be paid during the 6-month period following the Specified Employee's termination of employment shall not be paid or provided until the first business day after the date that is 6 months following the Specified Employee's termination of employment. Any payment that is made pursuant to the prior sentence shall include the cumulative amount of any amounts that could not be paid during the 6-month period following the Specified Employee's termination of employment. To the extent payments are deferred pursuant to the prior sentence, such deferred amounts shall continue to accrue interest pursuant to Section VII of these Rules and Regulations until payment occurs. |
13. | In the event of the death of a Participant in whose name a deferred account has been set up, MDUR or one of its business segments, divisions or subsidiaries, as applicable, shall, within 90 days thereafter, pay to the Participant's estate or the designated beneficiary the entire amount in the deferred account. |
14. | In the event of a "Change in Control" then any award deferred by each Participant shall become immediately payable to the Participant. In the event the Participant files suit to collect a deferred award then all of the Participant's court costs, other expenses of litigation, and attorneys' fees shall be paid by MDUR or one of its business segments, divisions or subsidiaries, as applicable, in the event the Participant prevails upon any of the Participant's claims for payment. |
(Print Name) | (Signature) | |
(Date) |
Twelve Months Ended March 31, 2013 | Year Ended December 31, 2012 | |||||||||
(In thousands of dollars) | ||||||||||
Earnings Available for Fixed Charges: | ||||||||||
Net Income (a) | $ | 5,858 | $ | (14,939 | ) | |||||
Income Taxes | (21,229 | ) | (31,146 | ) | ||||||
(15,371 | ) | (46,085 | ) | |||||||
Rents (b) | 14,705 | 13,716 | ||||||||
Interest (c) | 85,866 | 83,781 | ||||||||
Total Earnings Available for Fixed Charges | $ | 85,200 | $ | 51,412 | ||||||
Preferred Dividend Requirements | $ | 685 | $ | 685 | ||||||
Ratio of Income Before Income Taxes to Net Income | N/M | 308 | % | |||||||
Preferred Dividend Factor on Pretax Basis | 685 | 2,110 | ||||||||
Fixed Charges (d) | 101,759 | 100,516 | ||||||||
Combined Fixed Charges and Preferred Stock Dividends | $ | 102,444 | $ | 102,626 | ||||||
Ratio of Earnings to Fixed Charges | — | (e) | — | (e) | ||||||
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends | — | (e) | — | (e) |
(a) | Net income excludes undistributed income for equity investees. |
(b) | Represents interest portion of rents estimated at 33 1/3%. |
(c) | Represents interest, amortization of debt discount and expense on all indebtedness and amortization of interest capitalized, and excludes amortization of gains or losses on reacquired debt (which, under the Federal Energy Regulatory Commission Uniform System of Accounts, is classified as a reduction of, or increase in, interest expense in the Consolidated Statements of Income) and interest capitalized. |
(d) | Represents rents (as defined above), interest, amortization of debt discount and expense on all indebtedness, and excludes amortization of gains or losses on reacquired debt (which, under the Federal Energy Regulatory Commission Uniform System of Accounts, is classified as a reduction of, or increase in, interest expense in the Consolidated Statements of Income). |
(e) | Due to the $246.8 million after-tax noncash write-downs of oil and natural gas properties in 2012, earnings were insufficient by $17.2 million and $51.2 million to cover fixed charges for the 12 months ended March 31, 2013 and December 31, 2012, respectively. If the $246.8 million after-tax noncash write-downs were excluded, the ratio of earnings to fixed charges and the ratio of earnings to combined fixed charges and preferred stock dividends would have been 4.7 times and 4.6 times for the twelve months ended March 31, 2013, respectively, and would both have been 4.4 times for the twelve months ended December 31, 2012. |
1. | I have reviewed this quarterly report on Form 10-Q of MDU Resources Group, Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
1. | I have reviewed this quarterly report on Form 10-Q of MDU Resources Group, Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
1. | Citations issued under Section 104 of the Mine Safety Act for violations that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health 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 have not been totally abated within the time period allowed by the citation or subsequent extensions. |
3. | Citations or orders issued under Section 104(d) of the Mine Safety Act. Citations or orders 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 standards. 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. |
MSHA Identification Number | Section 104 S&S Citations (#) | Total Dollar Value of MSHA Assessments Proposed ($) | Legal Actions Pending as of Last Day of Period (#) | Legal Actions Initiated During Period (#) | Legal Actions Resolved During Period (#) | ||||||
04-00081 | — | $ | — | 4 | — | — | |||||
04-01698 | — | 1,000 | 3 | — | 2 | ||||||
04-05140 | — | — | 3 | — | — | ||||||
10-02089 | — | 100 | — | — | 1 | ||||||
21-00462 | — | — | 1 | — | — | ||||||
21-03133 | — | 100 | — | — | — | ||||||
21-03416 | — | 200 | — | — | — | ||||||
21-03560 | — | 100 | — | — | — | ||||||
24-02022 | 1 | 290 | 1 | 1 | — | ||||||
24-02414 | — | 100 | 1 | 1 | — | ||||||
35-00495 | — | 390 | — | — | — | ||||||
35-02968 | — | 500 | — | — | — | ||||||
35-03022 | 1 | — | — | — | — | ||||||
35-03449 | — | — | — | — | 5 | ||||||
35-03478 | — | 300 | — | — | — | ||||||
35-03581 | — | 200 | — | — | — | ||||||
35-03667 | 1 | 100 | 3 | — | — | ||||||
41-02639 | — | — | — | — | 1 | ||||||
41-03931 | — | 100 | — | — | — | ||||||
48-01383 | — | 2,369 | 4 | 4 | — | ||||||
51-00036 | 5 | 6,801 | 4 | 4 | — | ||||||
51-00171 | — | 100 | — | — | — | ||||||
51-00195 | — | 100 | — | — | — | ||||||
51-00241 | — | 100 | — | — | — | ||||||
8 | $ | 12,950 | 24 | 10 | 9 |
• | Contests of Citations and Orders - A contest proceeding may be filed with the Commission by operators, miners or miners' representatives to challenge the issuance of a citation or order issued by MSHA. |
• | Contests of Proposed Penalties (Petitions for Assessment of Penalties) - A contest of a proposed penalty is an administrative proceeding before the Commission challenging a civil penalty that MSHA has proposed for the alleged violation contained in a citation or order. |
• | Complaints for Compensation - A complaint for compensation may be filed with the Commission by miners entitled to compensation when a mine is closed by certain withdrawal orders issued by MSHA. The purpose of the proceeding is to determine the amount of compensation, if any, due miners idled by the orders. |
• | Complaints of Discharge, Discrimination or Interference - A discrimination proceeding is a case that involves a miner's allegation that he or she has suffered a wrong by the operator because he or she engaged in some type of activity protected under the Mine Act, such as making a safety complaint. |
• | Applications for Temporary Relief - Applications for temporary relief from any modification or termination of any order or from any order issued under section 104 of the Mine Act. |
• | Appeals of Judges' Decisions or Orders to the Commission - A filing with the Commission for discretionary review of a judge's decision or order by a person who has been adversely affected or aggrieved by such decision or order. |
MSHA Identification Number | Contests of Citations and Orders | Contests of Proposed Penalties | Complaints for Compensation | Complaints of Discharge, Discrimination or Interference | Applications for Temporary Relief | Appeals of Judges' Decisions or Orders to the Commission | ||||||
04-00081 | — | — | — | — | — | 4 | ||||||
04-01698 | — | 3 | — | — | — | — | ||||||
04-05140 | 3 | — | — | — | — | — | ||||||
21-00462 | 1 | — | — | — | — | — | ||||||
24-02022 | 1 | — | — | — | — | — | ||||||
24-02414 | 1 | — | — | — | — | — | ||||||
35-03667 | — | 3 | — | — | — | — | ||||||
48-01383 | — | 4 | — | — | — | — | ||||||
51-00036 | — | 4 | — | — | — | — | ||||||
6 | 14 | — | — | — | 4 |
Earnings per common share (Details)
In Thousands, unless otherwise specified |
3 Months Ended | |
---|---|---|
Mar. 31, 2013
|
Mar. 31, 2012
|
|
Earnings per common share [Abstract] | ||
Weighted average common shares outstanding - basic | 188,831 | 188,811 |
Effect of dilutive stock options and performance share awards | 391 | 371 |
Weighted average common shares outstanding - diluted | 189,222 | 189,182 |
Shares excluded from the calculation of diluted earnings per share | 0 | 0 |
Derivative instruments (Details 3) (USD $)
In Thousands, unless otherwise specified |
Mar. 31, 2013
|
Dec. 31, 2012
|
Mar. 31, 2012
|
---|---|---|---|
Derivatives, Fair Value [Line Items] | |||
Derivative asset, fair value, gross asset | $ 6,179 | $ 18,304 | $ 27,280 |
Derivative liability fair value gross liability | 12,445 | 6,255 | 29,651 |
Designated as hedging instrument [Member]
|
|||
Derivatives, Fair Value [Line Items] | |||
Derivative instruments in hedges, assets, at fair value | 1,623 | 18,084 | 26,097 |
Derivative instruments in hedges, liabilities, at fair value | 10,986 | 6,255 | 28,383 |
Not designated as hedging instrument [Member]
|
|||
Derivatives, Fair Value [Line Items] | |||
Other derivatives not designated as hedging instruments assets at fair value | 4,556 | 220 | 1,183 |
Other derivatives not designated as hedging instruments liabilities at fair value | 1,459 | 0 | 1,268 |
Interest rate swap [Member] | Designated as hedging instrument [Member] | Other accrued liabilities [Member]
|
|||
Derivatives, Fair Value [Line Items] | |||
Derivative instruments in hedges, liabilities, at fair value | 4,458 | 6,255 | 1,168 |
Interest rate swap [Member] | Designated as hedging instrument [Member] | Other liabilities noncurrent [Member]
|
|||
Derivatives, Fair Value [Line Items] | |||
Derivative instruments in hedges, liabilities, at fair value | 0 | 0 | 2,153 |
Commodity contract [Member] | Designated as hedging instrument [Member] | Commodity derivative instruments - current assets [Member]
|
|||
Derivatives, Fair Value [Line Items] | |||
Derivative instruments in hedges, assets, at fair value | 1,623 | 18,084 | 25,560 |
Commodity contract [Member] | Designated as hedging instrument [Member] | Other assets noncurrent [Member]
|
|||
Derivatives, Fair Value [Line Items] | |||
Derivative instruments in hedges, assets, at fair value | 0 | 0 | 537 |
Commodity contract [Member] | Designated as hedging instrument [Member] | Commodity derivative instruments - current liabilities [Member]
|
|||
Derivatives, Fair Value [Line Items] | |||
Derivative instruments in hedges, liabilities, at fair value | 5,994 | 0 | 18,964 |
Commodity contract [Member] | Designated as hedging instrument [Member] | Other liabilities noncurrent [Member]
|
|||
Derivatives, Fair Value [Line Items] | |||
Derivative instruments in hedges, liabilities, at fair value | 534 | 0 | 6,098 |
Commodity contract [Member] | Not designated as hedging instrument [Member] | Commodity derivative instruments - current assets [Member]
|
|||
Derivatives, Fair Value [Line Items] | |||
Other derivatives not designated as hedging instruments assets at fair value | 4,313 | 220 | 1,138 |
Commodity contract [Member] | Not designated as hedging instrument [Member] | Other assets noncurrent [Member]
|
|||
Derivatives, Fair Value [Line Items] | |||
Other derivatives not designated as hedging instruments assets at fair value | 243 | 0 | 45 |
Commodity contract [Member] | Not designated as hedging instrument [Member] | Commodity derivative instruments - current liabilities [Member]
|
|||
Derivatives, Fair Value [Line Items] | |||
Other derivatives not designated as hedging instruments liabilities at fair value | 1,385 | 0 | 1,219 |
Commodity contract [Member] | Not designated as hedging instrument [Member] | Other liabilities noncurrent [Member]
|
|||
Derivatives, Fair Value [Line Items] | |||
Other derivatives not designated as hedging instruments liabilities at fair value | $ 74 | $ 0 | $ 49 |
Fair value measurements (Tables)
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Mar. 31, 2013
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Fair Value Disclosures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Available-for-sale securities | Details of available-for-sale securities were as follows:
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Assets and liabilities measured at fair value on a recurring basis | The Company's assets and liabilities measured at fair value on a recurring basis are as follows:
* The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 28 percent in common stock of small-cap companies, 28 percent in common stock of large-cap companies and 15 percent in fixed-income and other investments.
* The insurance contract invests approximately 29 percent in common stock of mid-cap companies, 29 percent in common stock of small-cap companies, 29 percent in common stock of large-cap companies and 13 percent in fixed-income and other investments.
* The insurance contract invests approximately 28 percent in common stock of mid-cap companies, 28 percent in common stock of small-cap companies, 29 percent in common stock of large-cap companies and 15 percent in fixed-income and other investments. |
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Fair value of long term debt outstanding | The estimated fair value of the Company's Level 2 long-term debt was as follows:
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Litigation (Details) (USD $)
|
Mar. 31, 2013
|
Mar. 31, 2012
|
Dec. 31, 2011
|
Aug. 31, 2011
Litigation related to construction materials [Member]
|
Mar. 31, 2013
Natural gas gathering operations [Member]
|
Jun. 30, 2012
Natural gas gathering operations [Member]
|
Oct. 31, 2010
Natural gas gathering operations [Member]
|
Sep. 30, 2010
Natural gas gathering operations [Member]
|
Jan. 13, 2012
Guarantee obligation under construction contract [Member]
|
Dec. 31, 2009
Guarantee obligation under construction contract [Member]
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---|---|---|---|---|---|---|---|---|---|---|
Loss Contingencies [Line Items] | ||||||||||
Potential liabilities related to litigation and environmental matters | $ 33,300,000 | $ 70,700,000 | $ 22,500,000 | |||||||
Amount of compensatory damages in LPP's notice of demand | 149,700,000 | |||||||||
Arbitration award | 26,600,000 | 22,000,000 | ||||||||
Estimated damages in pending litigation, low estimate | 16,100,000 | |||||||||
Estimated damages in pending litigation, high estimate | 22,600,000 | |||||||||
Loss contingency, estimate of possible loss | 3,700,000 | |||||||||
Additional amount per day of potential penalties | 5,000 | |||||||||
Amount of expense (benefit) recorded in operation and maintenance expense related to natural gas gathering contract dispute, before tax | (24,100,000) | 26,600,000 | ||||||||
Amount of expense (benefit) recorded in operation and maintenance expense related to natural gas gathering contract dispute, after tax | (15,000,000) | 16,500,000 | ||||||||
Revised damage calculation | $ 1,000,000 |
Contingencies
|
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2013
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Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Contingencies | Contingencies The Company is party to claims and lawsuits arising out of its business and that of its consolidated subsidiaries. The Company accrues a liability for those contingencies when the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Company does not accrue liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is probable or reasonably possible and which are material, the Company discloses the nature of the contingency and, where feasible, an estimate of the possible loss. The Company had accrued liabilities of $33.3 million, $70.7 million and $22.5 million for contingencies, including litigation and environmental matters, as of March 31, 2013 and 2012, and December 31, 2012, respectively, which includes amounts that may have been accrued for matters discussed in Litigation and Environmental matters within this note. Litigation 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. In February 2009, Centennial received a Notice and Demand from LPP under the guarantee 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 seeking compensatory damages of $149.7 million. An arbitration award was issued January 13, 2012, awarding LPP $22.0 million. Centennial subsequently received a demand from LPP for payment of the arbitration award plus interest and attorneys' fees. An accrual related to the guarantee as a result of the arbitration award was recorded in discontinued operations on the Consolidated Statement of Income in the fourth quarter of 2011. CEM filed a petition with the New York Supreme Court to vacate the arbitration award in favor of LPP. On October 19, 2012, Centennial moved to intervene in the New York Supreme Court action to vacate the arbitration award and also filed a complaint with the New York Supreme Court seeking a declaration that LPP is not entitled to indemnification from Centennial under the guaranty for the arbitration award. The New York Supreme Court granted CEM's petition to vacate the arbitration award on November 20, 2012, and entered a written order to that effect on April 11, 2013. Due to the vacation of the arbitration award, the Company no longer believes the loss related to this matter to be probable and thus the liability that was previously recorded in 2011 was reversed in the fourth quarter of 2012. Centennial anticipates LPP will appeal the order. We believe that it is reasonably possible that a loss related to this matter could result if LPP is successful in its appeal, the arbitration award is affirmed and LPP continues to assert its demand against Centennial under the guarantee for payment of the arbitration award, attorneys' fees and interest. For more information regarding discontinued operations, see Note 9. Construction Materials Until the fall of 2011 when it discontinued active mining operations at the pit, JTL operated the Target Range Gravel Pit in Missoula County, Montana under a 1975 reclamation contract pursuant to the Montana Opencut Mining Act. In September 2009, the Montana DEQ sent a letter asserting JTL was in violation of the Montana Opencut Mining Act by conducting mining operations outside a permitted area. JTL filed a complaint in Montana First Judicial District Court in June 2010, seeking a declaratory order that the reclamation contract is a valid permit under the Montana Opencut Mining Act. The Montana DEQ filed an answer and counterclaim to the complaint in August 2011, alleging JTL was in violation of the Montana Opencut Mining Act and requesting imposition of penalties of not more than $3.7 million plus not more than $5,000 per day from the date of the counterclaim. The Company believes the operation of the Target Range Gravel Pit was conducted under a valid permit; however, the imposition of civil penalties is reasonably possible. The Company filed an application for amendment of its opencut mining permit and intends to resolve this matter through settlement or continuation of the Montana First Judicial District Court litigation. Natural Gas Gathering Operations In January 2010, SourceGas filed an application with the Colorado State District Court to compel WBI Energy Midstream to arbitrate a dispute regarding operating pressures under a natural gas gathering contract on one of WBI Energy Midstream's pipeline gathering systems in Montana. WBI Energy Midstream resisted the application and sought a declaratory order interpreting the gathering contract. In May 2010, the Colorado State District Court granted the application and ordered WBI Energy Midstream into arbitration. An arbitration hearing was held in August 2010. In October 2010, the arbitration panel issued an award in favor of SourceGas for approximately $26.6 million. As a result, WBI Energy Midstream, 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. On April 20, 2011, the Colorado State District Court confirmed the arbitration award as a court judgment. WBI Energy Midstream filed an appeal from the Colorado State District Court's order and judgment to the Colorado Court of Appeals. The Colorado Court of Appeals issued a decision on May 24, 2012, reversing the Colorado State District Court order compelling arbitration, vacating the final award and remanding the case to the Colorado State District Court to determine SourceGas's claims and WBI Energy Midstream's counterclaims. As a result of the Colorado Court of Appeals decision, in the second quarter of 2012, WBI Energy Midstream changed its estimated loss related to this matter. This resulted in a reduction of expense of $24.1 million ($15.0 million after tax). On August 2, 2012, SourceGas filed a petition for writ of certiorari with the Colorado Supreme Court for review of the Colorado Court of Appeals decision. WBI Energy Midstream anticipates that if the Colorado Supreme Court were to grant a writ of certiorari and remand the matter to the Colorado State District Court, SourceGas will assert claims similar to those asserted in the arbitration proceeding. In a related matter, Omimex filed a complaint against WBI Energy Midstream in Montana Seventeenth Judicial District Court in July 2010 alleging WBI Energy Midstream breached a separate gathering contract with Omimex as a result of the increased operating pressures demanded by SourceGas on the same natural gas gathering system. In December 2011, Omimex filed an amended complaint alleging WBI Energy Midstream breached obligations to operate its gathering system as a common carrier under United States and Montana law. WBI Energy Midstream removed the action to the United States District Court for the District of Montana. Expert reports submitted by Omimex contended its damages as a result of the increased operating pressures were $16.1 million to $22.6 million, however, the experts have since revised their calculation of Omimex's damages to $1.0 million. The Company believes the claims asserted by Omimex are without merit and an award is not deemed probable. The Company intends to vigorously defend against the claims. A trial on the matter is scheduled for July 2013. The Company also is involved in other legal actions in the ordinary course of its business. After taking into account liabilities accrued for the foregoing matters, management believes that the outcomes with respect to the above and other legal proceedings will not have a material effect upon the Company's financial position, results of operations or cash flows. Environmental matters Portland Harbor Site In December 2000, Knife River - Northwest 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 Knife River - Northwest 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 Knife River - Northwest or Georgia-Pacific West, Inc. Investigative costs are indicated to be in excess of $70 million. It is not possible to estimate the cost of a corrective action plan until the remedial investigation and feasibility study have been completed, the EPA has decided on a strategy and a ROD has been published. Corrective action will be taken after the development of a proposed plan and ROD on the harbor site is issued. Knife River - Northwest 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 Portland Harbor Natural Resource 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, Knife River - Northwest does not believe it is a Responsible Party. In addition, Knife River - Northwest 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. Knife River - Northwest 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 Knife River - Northwest and others to recover LWG's investigation costs to the extent Knife River - Northwest 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, Knife River - Northwest has agreed to participate in the alternative dispute resolution process. The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above referenced administrative action. Manufactured Gas Plant Sites There are three claims against Cascade for cleanup of environmental contamination at manufactured gas plant sites operated by Cascade's predecessors. The first claim is for contamination at a site in Eugene, Oregon which 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. The Oregon DEQ is preparing a staff report which will recommend a cleanup alternative for the site. It is not known at this time what share of the cleanup costs will actually be borne by Cascade; however, Cascade anticipates its proportional share could be approximately 50 percent. Cascade has accrued $1.3 million for remediation of this site. In January 2013, the OPUC approved Cascade's application to defer environmental remediation costs at the Eugene site for a period of 12 months starting November 30, 2012. The second claim is for contamination at a site in Bremerton, Washington which 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. In April 2010, the Washington Department of Ecology issued notice it considered Cascade a PRP for hazardous substances at the site. In May 2012, the EPA added the site to the National Priorities List. Cascade has entered into an administrative settlement agreement and consent order with the EPA regarding the scope and schedule for a remedial investigation and feasibility study for the site. Cascade has accrued $6.7 million for the remedial investigation and feasibility study and $6.4 million for remediation of this site. In April 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 in September 2010, subject to conditions set forth in the order. The third claim is for contamination at a site in Bellingham, 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. A report documenting the initial phase of the remedial investigation was completed in June 2011. There is currently not enough information available to estimate the potential liability to Cascade associated with this claim although Cascade believes its proportional share of any liability will be relatively small in comparison to other PRPs. The plant manufactured gas from coal between approximately 1890 and 1946. In 1946, shortly after Cascade's predecessor acquired the plant, it converted the plant to a propane-air gas facility. There are no documented wastes or by-products resulting from the mixing or distribution of propane-air gas. Cascade has received notices from certain of its insurance carriers that they will participate in defense of Cascade for these contamination claims subject to full and complete reservations of rights and defenses to insurance coverage. 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. The accruals related to these matters are reflected in regulatory assets. Halawa Quarry The State of Hawaii Department of Health issued a Notice of Violation to Hawaiian Cement dated August 31, 2012, alleging violations of Hawaii's Water Pollution statute at Hawaiian Cement's Halawa Quarry by failure to comply with the quarry's National Pollutant Discharge Elimination System permit by failing to design, construct and maintain a facility to contain or treat the volume of all process wastewater and storm water that would result from a 10-year, 24-hour rainfall event. The Notice of Violation also alleged Hawaiian Cement violated the quarry's permit by discharging pollution, including levels of pH and total suspended solids in excess of the permit limits, on three occasions in January, June and December 2011. The Notice of Violation sought development and implementation of corrective action plans and unspecified administrative penalties. Hawaiian Cement resolved the Notice of Violation through a negotiated settlement which included payment of a monetary penalty of $100,000 as well as development and implementation of corrective action plans, the final cost of which are not expected to be material. Guarantees Centennial guaranteed CEM's obligations under a construction contract. For more information, see Litigation in this note. In connection with the sale of the Brazilian Transmission Lines, as discussed in Note 10, Centennial has agreed to guarantee payment of any indemnity obligations of certain of the Company's indirect wholly owned subsidiaries who are the sellers in three purchase and sale agreements for periods ranging up to 10 years from the date of sale. The guarantees were required by the buyers as a condition to the sale of the Brazilian Transmission Lines. WBI Holdings has guaranteed certain of Fidelity's oil and natural gas swap and collar agreement obligations. There is no fixed maximum amount guaranteed in relation to the oil and natural gas swap and collar agreements as the amount of the obligation is dependent upon oil and natural gas commodity prices. The amount of hedging activity entered into by the subsidiary is limited by corporate policy. The guarantees of the oil and natural gas swap and collar agreements at March 31, 2013, expire in the years ranging from 2013 to 2015; however, Fidelity continues to enter into additional hedging activities and, as a result, WBI Holdings from time to time may issue additional guarantees on these hedging obligations. The amount outstanding by Fidelity was $4.5 million and was reflected on the Consolidated Balance Sheet at March 31, 2013. In the event Fidelity defaults under its obligations, WBI Holdings would be required to make payments under its guarantees. Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company. These guarantees are related to construction contracts, natural gas transportation and sales agreements, gathering contracts and certain other guarantees. At March 31, 2013, the fixed maximum amounts guaranteed under these agreements aggregated $74.6 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $17.4 million in 2013; $38.4 million in 2014; $300,000 in 2015; $100,000 in 2016; $600,000 in 2018; $300,000 in 2019; $13.5 million, which is subject to expiration on a specified number of days after the receipt of written notice; and $4.0 million, which has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $200,000 and was reflected on the Consolidated Balance Sheet at March 31, 2013. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee. Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies and other agreements, some of which are guaranteed by other subsidiaries of the Company. At March 31, 2013, the fixed maximum amounts guaranteed under these letters of credit, aggregated $32.3 million. In 2013 and 2014, $3.3 million and $29.0 million, respectively, of letters of credit are scheduled to expire. There were no amounts outstanding under the above letters of credit at March 31, 2013. WBI Holdings has an outstanding guarantee to WBI Energy Transmission. This guarantee is related to a natural gas transportation and storage agreement that guarantees the performance of Prairielands. At March 31, 2013, the fixed maximum amount guaranteed under this agreement was $5.0 million and is scheduled to expire in 2014. In the event of Prairielands' default in its payment obligations, WBI Holdings would be required to make payment under its guarantee. The amount outstanding by Prairielands under the above guarantee was $900,000. The amount outstanding under this guarantee was not reflected on the Consolidated Balance Sheet at March 31, 2013, because this intercompany transaction was eliminated in consolidation. In addition, Centennial, Knife River and MDU Construction Services have issued guarantees to third parties related to the 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 these obligations, Centennial, Knife River and MDU Construction Services would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these guarantees were reflected on the Consolidated Balance Sheet at March 31, 2013. In the normal course of business, Centennial has surety bonds related to construction contracts and reclamation obligations of its subsidiaries, as well as an arbitration award. 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 March 31, 2013, approximately $639 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet. Variable interest entities The Company evaluates its arrangements and contracts with other entities to determine if they are VIEs and if so, if the Company is the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest, and results of activities of a VIE in its consolidated financial statements. A VIE should be consolidated if a party with an ownership, contractual, or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE's most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE's assets, liabilities, and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated. The Company's evaluation of whether it qualifies as the primary beneficiary of a VIE is highly complex and involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE's economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties, and the purpose of the arrangement. Dakota Prairie Refining, LLC On February 7, 2013, WBI Energy and Calumet formed a limited liability company, Dakota Prairie Refining, and entered into an operating agreement to develop, build and operate a diesel topping plant in southwestern North Dakota. WBI Energy and Calumet each have a fifty percent ownership interest in Dakota Prairie Refining. WBI Energy's and Calumet's capital commitments under the agreement are $150 million and $75 million, respectively. Dakota Prairie Refining entered into a term loan for project debt financing of $75 million on April 22, 2013. The agreement provides for allocation of profits and losses consistent with ownership interests; however, deductions attributable to project financing debt will be allocated to Calumet. Calumet's future cash distributions from Dakota Prairie Refining will be decreased by the principal and interest to be paid on the project debt, while the cash distributions to WBI Energy will not be decreased. Pursuant to the agreement, Centennial agreed to guarantee Dakota Prairie Refining's obligation under the term loan. For more information on the guarantee, see Note 19. Dakota Prairie Refining has been determined to be a VIE, and the Company has determined that it is the primary beneficiary as it has an obligation to absorb losses that could be potentially significant to the VIE through WBI Energy's equity investment and Centennial's guarantee of the third-party term loan. Accordingly, the Company consolidates Dakota Prairie Refining in its financial statements and records a noncontrolling interest for Calumet's ownership interest. Construction on the diesel topping plant began in early 2013 and the plant is not yet operational. The assets of Dakota Prairie Refining shall be used solely for the benefit of Dakota Prairie Refining. The total assets and liabilities of Dakota Prairie Refining reflected on the Company's Consolidated Balance Sheets were as follows:
Fuel Contract On October 10, 2012, the Coyote Station entered into a new coal supply agreement with Coyote Creek that will replace a coal supply agreement that expires in May 2016. The new agreement provides for the purchase of coal necessary to supply the coal requirements of the Coyote Station, of which the Company is a 25.0 percent owner, for the period May 2016 through December 2040. The new coal supply agreement creates a variable interest in Coyote Creek due to the transfer of all operating and economic risk to the Coyote Station owners as the agreement is structured so the price of the coal will cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of Coyote Creek as they would be required to buy the assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of Coyote Creek in that they are required to buy the entity at the end of the contract term at equity value. Although the Company has determined that Coyote Creek is a VIE, the Company has concluded that it is not the primary beneficiary of Coyote Creek because the authority to direct the activities of the entity is shared by the four unrelated owners of the Coyote Station with no primary beneficiary existing. As a result, Coyote Creek is not required to be consolidated in the Company's financial statements. At March 31, 2013, Coyote Creek was not yet operational. The assets and liabilities of Coyote Creek and exposure to loss as a result of the Company's involvement with the VIE at March 31, 2013, is not material. |
Accounts receivable and allowance for doubtful accounts (Details) (USD $)
In Millions, unless otherwise specified |
Mar. 31, 2013
|
Dec. 31, 2012
|
Mar. 31, 2012
|
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Accounts receivable and allowance for doubtful accounts [Abstract] | |||
Receivables past due 90 days or more | $ 39.6 | $ 34.3 | $ 34.6 |
Allowance for doubtful accounts receivable | $ 10.8 | $ 10.8 | $ 12.2 |
Fair value measurements (Details 3) (USD $)
In Thousands, unless otherwise specified |
Mar. 31, 2013
|
Dec. 31, 2012
|
Mar. 31, 2012
|
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Carrying (reported) amount, fair value disclosure [Member]
|
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Fair value, balance sheet grouping, financial statement captions [Line Items] | |||
Long-term debt | $ 1,789,663 | $ 1,744,975 | $ 1,416,189 |
Estimate of fair value, fair value disclosure [Member]
|
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Fair value, balance sheet grouping, financial statement captions [Line Items] | |||
Long-term debt | $ 1,925,859 | $ 1,888,135 | $ 1,578,395 |
Seasonality of operations
|
3 Months Ended |
---|---|
Mar. 31, 2013
|
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Seasonality of operations [Abstract] | |
Seasonality of operations | 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. |