WASHINGTON, D.C. 20549
MDU Resources Group, Inc.
P.O. Box 5650
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act (Check one):
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of October 28, 2011: 188,793,564 shares.
The following abbreviations and acronyms used in this Form 10-Q are defined below:
The Company is a diversified natural resource company, which was incorporated under the laws of the state of Delaware in 1924. Its principal executive offices are at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 530-1000.
Montana-Dakota, through the electric and natural gas distribution segments, generates, transmits and distributes electricity and distributes natural gas in Montana, North Dakota, South Dakota and Wyoming. Cascade distributes natural gas in Oregon and Washington. Intermountain distributes natural gas in Idaho. Great Plains distributes natural gas in western Minnesota and southeastern North Dakota. These operations also supply related value-added services.
The Company, through its wholly owned subsidiary, Centennial, owns WBI Holdings (comprised of the pipeline and energy services and the natural gas and oil production segments), Knife River (construction materials and contracting segment), MDU Construction Services (construction services segment), Centennial Resources and Centennial Capital (both reflected in the Other category). For more information on the Company's business segments, see Note 15.
MDU RESOURCES GROUP, INC.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
OVERVIEW
The Company's strategy is to apply its expertise in energy and transportation infrastructure industries to increase market share, increase profitability and enhance shareholder value through:
| · | Organic growth as well as a continued disciplined approach to the acquisition of well-managed companies and properties |
| · | The elimination of system-wide cost redundancies through increased focus on integration of operations and standardization and consolidation of various support services and functions across companies within the organization |
| · | The development of projects that are accretive to earnings per share and return on invested capital |
The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial paper facilities, revolving credit facilities and the issuance from time to time of debt and equity securities. For more information on the Company's net capital expenditures, see Liquidity and Capital Commitments.
The key strategies for each of the Company's business segments and certain related business challenges are summarized below. For a summary of the Company's business segments, see Note 15.
Key Strategies and Challenges
Electric and Natural Gas Distribution
Strategy Provide competitively priced energy and related services to customers. The electric and natural gas distribution segments continually seek opportunities for growth and expansion of their customer base through extensions of existing operations, including electric generation with a diverse resource mix that includes renewable generation, and transmission build-out, and through selected acquisitions of companies and properties at prices that will provide stable cash flows and an opportunity for the Company to earn a competitive return on investment.
Challenges Both segments are subject to extensive regulation in the state jurisdictions where they conduct operations with respect to costs and permitted returns on investment as well as subject to certain operational and environmental regulations. The ability of these segments to grow through acquisitions is subject to significant competition. In addition, the ability of both segments to grow service territory and customer base is affected by the economic environment of the markets served and competition from other energy providers and fuels. The construction of electric generating facilities and transmission lines may be subject to increasing cost and lead time, extensive permitting procedures, and federal and state legislative and regulatory initiatives, which may necessitate increases in electric energy prices. Legislative and regulatory initiatives to increase renewable energy resources and reduce GHG emissions could impact the price and demand for electricity and natural gas.
Construction Services
Strategy Provide a competitive return on investment while operating in a competitive industry by: building new and strengthening existing customer relationships; effectively controlling costs; retaining, developing and recruiting talented employees; focusing business development efforts on project areas that will permit higher margins; and properly managing risk.
Challenges This segment operates in highly competitive markets with many jobs subject to competitive bidding. Maintenance of effective operational and cost controls, retention of key personnel, managing
through downturns in the economy and effective management of working capital are ongoing challenges.
Pipeline and Energy Services
Strategy Utilize the segment's existing expertise in energy infrastructure and related services to increase market share and profitability through optimization of existing operations, internal growth, and acquisitions of energy-related assets and companies. Incremental and new growth opportunities include: access to new sources of natural gas for storage, gathering and transportation services; expansion of existing gathering, transmission and storage facilities; expansion of related energy services; and incremental expansion of pipeline capacity to allow customers access to more liquid and higher-priced markets.
Challenges Challenges for this segment include: energy price volatility; natural gas basis differentials; environmental and regulatory requirements; recruitment and retention of a skilled workforce; and competition from other natural gas pipeline and energy services companies.
Natural Gas and Oil Production
Strategy Apply technology and utilize existing exploration and production expertise, with a focus on operated properties, to increase production and reserves from existing leaseholds, and to seek additional reserves and production opportunities both in new and existing areas to further expand the segment's asset base. By optimizing existing operations and taking advantage of new and incremental growth opportunities, this segment's goal is to add value by increasing both reserves and production over the long term so as to generate competitive returns on investment.
Challenges Volatility in natural gas and oil prices; timely receipt of necessary permits and approvals; environmental and regulatory requirements; recruitment and retention of a skilled workforce; availability of drilling rigs, materials, auxiliary equipment and industry-related field services; inflationary pressure on development and operating costs; and competition from other natural gas and oil companies are ongoing challenges for this segment.
Construction Materials and Contracting
Strategy Focus on high-growth strategic markets located near major transportation corridors and desirable mid-sized metropolitan areas; strengthen long-term, strategic aggregate reserve position through purchase and/or lease opportunities; enhance profitability through cost containment, margin discipline and vertical integration of the segment's operations; and continue growth through organic and acquisition opportunities. Ongoing efforts to increase margin are being pursued through the implementation of a variety of continuous improvement programs, including corporate purchasing of equipment, parts and commodities (liquid asphalt, diesel fuel, cement and other materials), and negotiation of contract price escalation provisions. Vertical integration allows the segment to manage operations from aggregate mining to final lay-down of concrete and asphalt, with control of and access to permitted aggregate reserves being significant. A key element of the Company's long-term strategy for this business is to further expand its market presence in the higher-margin materials business (rock, sand, gravel, liquid asphalt, ready-mixed concrete and related products), complementing and expanding on the Company's expertise.
Challenges The economic downturn has adversely impacted operations, particularly in the private market. The current economic challenges have resulted in increased competition in certain construction markets and lower margins. Continued delays in the multiple year reauthorization of the federal highway bill and volatility in the cost of raw materials such as diesel, gasoline, liquid asphalt, cement and steel, continue to be a concern. This business unit expects to continue cost containment efforts and a greater emphasis on industrial, energy and public works projects.
For further information on the risks and challenges the Company faces as it pursues its growth strategies and other factors that should be considered for a better understanding of the Company's financial condition, see Item 1A – Risk Factors, as well as Part I, Item 1A – Risk Factors in the 2010 Annual Report. For further information on each segment's key growth strategies, projections and certain assumptions, see Prospective Information. For information pertinent to various commitments and contingencies, see Notes to Consolidated Financial Statements.
Earnings Overview
The following table summarizes the contribution to consolidated earnings by each of the Company's businesses.
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | (Dollars in millions, where applicable) | |
| Electric | | $ | 8.3 | | | $ | 11.3 | | | $ | 21.7 | | | $ | 22.1 | |
| Natural gas distribution | | | (11.2 | ) | | | (10.1 | ) | | | 18.2 | | | | 13.4 | |
| Construction services | | | 5.1 | | | | 6.0 | | | | 15.8 | | | | 9.0 | |
| Pipeline and energy services | | | 5.2 | | | | (7.4 | ) | | | 16.9 | | | | 10.9 | |
| Natural gas and oil production | | | 22.5 | | | | 18.7 | | | | 60.1 | | | | 65.0 | |
| Construction materials and contracting | | | 33.1 | | | | 40.3 | | | | 16.7 | | | | 25.8 | |
| Other | | | .9 | | | | 2.0 | | | | 2.0 | | | | 5.0 | |
| Earnings before discontinued operations | | $ | 63.9 | | | $ | 60.8 | | | $ | 151.4 | | | $ | 151.2 | |
| Income (loss) from discontinued operations, net of tax | | | (.1 | ) | | | — | | | | .1 | | | | — | |
| Earnings on common stock | | $ | 63.8 | | | $ | 60.8 | | | $ | 151.5 | | | $ | 151.2 | |
| Earnings per common share – basic: | | | | | | | | | | | | | | | | |
Earnings before discontinued operations | | $ | .34 | | | $ | .32 | | | $ | .80 | | | $ | .80 | |
Discontinued operations, net of tax | | | — | | | | — | | | | — | | | | — | |
| Earnings per common share – basic | | $ | .34 | | | $ | .32 | | | $ | .80 | | | $ | .80 | |
| Earnings per common share – diluted: | | | | | | | | | | | | | | | | |
Earnings before discontinued operations | | $ | .34 | | | $ | .32 | | | $ | .80 | | | $ | .80 | |
Discontinued operations, net of tax | | | — | | | | — | | | | — | | | | — | |
| Earnings per common share – diluted | | $ | .34 | | | $ | .32 | | | $ | .80 | | | $ | .80 | |
| Return on average common equity for the 12 months ended | | | | | | | | | | | 8.9 | % | | | 8.6 | % |
Three Months Ended September 30, 2011 and 2010 Consolidated earnings for the quarter ended September 30, 2011, increased $3.0 million from the comparable prior period largely due to:
| | · | Lower operation and maintenance expense, primarily related to the absence of a natural gas gathering arbitration charge of $16.5 million (after tax) in 2010 at the pipeline and energy services business |
| | · | Higher average realized oil prices and increased oil production, partially offset by lower average realized natural gas prices, higher depreciation, depletion and amortization expense and decreased natural gas production at the natural gas and oil production business |
Partially offsetting these increases were:
| | · | Lower liquid asphalt oil, asphalt and construction margins, as well as higher income taxes at the construction materials and contracting business |
| | · | Higher operation and maintenance expense and higher income taxes at the electric business |
Nine Months Ended September 30, 2011 and 2010 Consolidated earnings for the nine months ended September 30, 2011, increased $300,000 primarily due to:
| | · | Higher construction workloads and margins in the Western region, as well as higher equipment and electrical supply sales, partially offset by lower construction workloads and margins in the Mountain region at the construction services business |
| | · | Lower operation and maintenance expense, primarily related to the absence of a natural gas gathering arbitration charge of $16.5 million (after tax) in 2010, partially offset by lower storage services revenue and decreased transportation volumes at the pipeline and energy services business |
Partially offsetting these increases were lower ready-mixed concrete margins and volumes, lower other product line and liquid asphalt oil margins at the construction materials and contracting business.
FINANCIAL AND OPERATING DATA
Below are key financial and operating data for each of the Company's businesses.
Electric
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | (Dollars in millions, where applicable) | |
| Operating revenues | | $ | 61.9 | | | $ | 60.0 | | | $ | 169.8 | | | $ | 155.3 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Fuel and purchased power | | | 17.4 | | | | 15.3 | | | | 48.8 | | | | 45.3 | |
| Operation and maintenance | | | 18.1 | | | | 15.7 | | | | 52.4 | | | | 47.0 | |
| Depreciation, depletion and amortization | | | 8.1 | | | | 7.6 | | | | 24.2 | | | | 19.5 | |
| Taxes, other than income | | | 2.4 | | | | 2.2 | | | | 7.5 | | | | 7.0 | |
| | | | 46.0 | | | | 40.8 | | | | 132.9 | | | | 118.8 | |
| Operating income | | | 15.9 | | | | 19.2 | | | | 36.9 | | | | 36.5 | |
| Earnings | | $ | 8.3 | | | $ | 11.3 | | | $ | 21.7 | | | $ | 22.1 | |
| Retail sales (million kWh) | | | 718.8 | | | | 692.0 | | | | 2,128.1 | | | | 2,057.0 | |
| Sales for resale (million kWh) | | | 35.3 | | | | 13.8 | | | | 63.9 | | | | 51.1 | |
| Average cost of fuel and purchased power per kWh | | $ | .022 | | | $ | .021 | | | $ | .021 | | | $ | .021 | |
Three Months Ended September 30, 2011 and 2010 Electric earnings decreased $3.0 million (26 percent) due to:
| | · | Higher operation and maintenance expense of $1.6 million (after tax), primarily increased benefit-related costs |
| | · | Higher income taxes of $500,000, primarily related to benefits |
| | · | Lower other income of $300,000 (after tax), largely lower allowance for funds used during construction |
| | · | Increased depreciation, depletion and amortization expense of $300,000 (after tax), including the effects of higher property, plant and equipment balances |
Nine Months Ended September 30, 2011 and 2010 Electric earnings decreased $400,000 (2 percent) due to:
| | · | Higher operation and maintenance expense of $3.4 million (after tax), primarily increased benefit and payroll-related costs, as well as increased contract services |
| | · | Increased depreciation, depletion and amortization expense of $2.9 million (after tax), as previously discussed |
| | · | Lower other income of $2.2 million (after tax), largely lower allowance for funds used during construction related to electric generation projects, which were placed in service in 2010 |
| | · | Higher net interest expense of $1.5 million (after tax), including lower capitalized interest |
Partially offsetting these decreases were:
| | · | Higher electric retail sales margins, primarily due to higher rates in North Dakota, Wyoming and Montana, as well as increased sales volumes |
| | · | Lower income taxes of $3.0 million, including an income tax benefit of $1.2 million related to favorable resolution of certain income tax matters, higher production tax credits, as well as a reduction of income taxes associated with benefits |
Natural Gas Distribution
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | (Dollars in millions, where applicable) | |
| Operating revenues | | $ | 92.4 | | | $ | 94.3 | | | $ | 627.5 | | | $ | 603.5 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Purchased natural gas sold | | | 49.3 | | | | 50.1 | | | | 408.8 | | | | 394.3 | |
| Operation and maintenance | | | 34.8 | | | | 35.7 | | | | 102.5 | | | | 102.8 | |
| Depreciation, depletion and amortization | | | 11.1 | | | | 10.8 | | | | 33.4 | | | | 32.1 | |
| Taxes, other than income | | | 7.3 | | | | 7.5 | | | | 35.7 | | | | 34.5 | |
| | | | 102.5 | | | | 104.1 | | | | 580.4 | | | | 563.7 | |
| Operating income (loss) | | | (10.1 | ) | | | (9.8 | ) | | | 47.1 | | | | 39.8 | |
| Earnings (loss) | | $ | (11.2 | ) | | $ | (10.1 | ) | | $ | 18.2 | | | $ | 13.4 | |
| Volumes (MMdk): | | | | | | | | | | | | | | | | |
| Sales | | | 8.4 | | | | 7.9 | | | | 69.7 | | | | 61.6 | |
| Transportation | | | 28.0 | | | | 35.4 | | | | 87.7 | | | | 98.7 | |
| Total throughput | | | 36.4 | | | | 43.3 | | | | 157.4 | | | | 160.3 | |
| Degree days (% of normal)* | | | | | | | | | | | | | | | | |
| Montana-Dakota | | | 54 | % | | | 69 | % | | | 110 | % | | | 97 | % |
| Cascade | | | 78 | % | | | 109 | % | | | 104 | % | | | 96 | % |
| Intermountain | | | 39 | % | | | 105 | % | | | 110 | % | | | 103 | % |
| Average cost of natural gas, including transportation, per dk | | $ | 5.85 | | | $ | 6.34 | | | $ | 5.87 | | | $ | 6.40 | |
*Degree days are a measure of the daily temperature-related demand for energy for heating. | |
Three Months Ended September 30, 2011 and 2010 The natural gas distribution business experienced a seasonal loss of $11.2 million in the third quarter of 2011 compared to a loss of $10.1 million in the third quarter of 2010. The increase in the seasonal loss is due to:
| | · | Higher regulated operation and maintenance expense of $800,000 (after tax), primarily higher benefit-related costs, partially offset by the absence of operational integration costs in 2010 |
| | · | Higher income taxes of $700,000, primarily related to benefits |
| | · | Lower nonregulated energy-related services of $400,000 (after tax), largely related to the absence of pipeline project activity |
Partially offsetting these decreases were increased retail sales margins, primarily due to weather normalization and conservation adjustments.
The previous table also reflects lower revenue and lower operation and maintenance expense related to pipeline project activity.
Nine Months Ended September 30, 2011 and 2010 Earnings at the natural gas distribution business increased $4.8 million (36 percent) due to:
| | · | Increased retail sales volumes, largely resulting from colder weather than last year |
| | · | Lower income taxes of $1.3 million, primarily related to a reduction of income taxes associated with benefits |
Partially offsetting the earnings increase were:
| | · | Higher regulated operation and maintenance expense of $2.7 million (after tax), as previously discussed |
| | · | Increased depreciation, depletion and amortization expense of $800,000 (after tax), primarily resulting from higher property, plant and equipment balances |
| | · | Lower nonregulated energy-related services of $800,000 (after tax), as previously discussed |
| | · | Lower other income of $500,000 (after tax), primarily lower allowance for funds used during construction |
The previous table also reflects lower revenue and lower operation and maintenance expense related to pipeline project activity.
Construction Services
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | (In millions) | |
| Operating revenues | | $ | 226.2 | | | $ | 210.5 | | | $ | 627.6 | | | $ | 551.8 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Operation and maintenance | | | 208.0 | | | | 191.1 | | | | 571.2 | | | | 506.1 | |
| Depreciation, depletion and amortization | | | 2.8 | | | | 2.9 | | | | 8.5 | | | | 9.2 | |
| Taxes, other than income | | | 5.8 | | | | 5.8 | | | | 19.0 | | | | 18.4 | |
| | | | 216.6 | | | | 199.8 | | | | 598.7 | | | | 533.7 | |
| Operating income | | | 9.6 | | | | 10.7 | | | | 28.9 | | | | 18.1 | |
| Earnings | | $ | 5.1 | | | $ | 6.0 | | | $ | 15.8 | | | $ | 9.0 | |
Three Months Ended September 30, 2011 and 2010 Construction services earnings decreased $900,000 (16 percent) due to lower construction workloads and margins in the Mountain region, as well as lower margins in the Central region. Partially offsetting the earnings decrease were higher equipment sales and rental margins, as well as higher construction workloads and margins in the Western region.
Nine Months Ended September 30, 2011 and 2010 Construction services earnings increased $6.8 million (75 percent) due to higher construction workloads and margins in the Western region, partially offset by lower construction workloads and margins in the Mountain region and lower margins in the Central region. Also contributing to the earnings increase were higher equipment and electrical supply sales.
Pipeline and Energy Services
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | (Dollars in millions) | |
| Operating revenues | | $ | 69.1 | | | $ | 81.2 | | | $ | 215.5 | | | $ | 250.3 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Purchased natural gas sold | | | 31.8 | | | | 36.8 | | | | 99.8 | | | | 119.5 | |
| Operation and maintenance | | | 16.6 | | | | 44.2 | * | | | 52.8 | | | | 77.2 | * |
| Depreciation, depletion and amortization | | | 6.4 | | | | 6.5 | | | | 19.3 | | | | 19.4 | |
| Taxes, other than income | | | 3.4 | | | | 3.2 | | | | 10.3 | | | | 9.5 | |
| | | | 58.2 | | | | 90.7 | | | | 182.2 | | | | 225.6 | |
| Operating income (loss) | | | 10.9 | | | | (9.5 | ) | | | 33.3 | | | | 24.7 | |
| Earnings (loss) | | $ | 5.2 | | | $ | (7.4 | ) | | $ | 16.9 | | | $ | 10.9 | |
| Transportation volumes (MMdk) | | | 29.4 | | | | 33.6 | | | | 82.5 | | | | 108.4 | |
| Gathering volumes (MMdk) | | | 16.4 | | | | 19.3 | | | | 50.8 | | | | 57.7 | |
| Customer natural gas storage balance (MMdk): | | | | | | | | | | | | | | | | |
| Beginning of period | | | 31.7 | | | | 64.2 | | | | 58.8 | | | | 61.5 | |
| Net injection (withdrawal) | | | 6.8 | | | | 9.6 | | | | (20.3 | ) | | | 12.3 | |
| End of period | | | 38.5 | | | | 73.8 | | | | 38.5 | | | | 73.8 | |
*Reflects a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax). | |
Three Months Ended September 30, 2011 and 2010 Pipeline and energy services earnings increased $12.6 million largely due to lower operation and maintenance expense, primarily related to the absence of the natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax) in 2010.
Partially offsetting the earnings increase were:
| | · | Lower storage services revenue of $2.6 million (after tax), largely lower storage balances |
| | · | Lower gathering volumes of $1.1 million (after tax) |
| | · | Decreased transportation volumes of $800,000 (after tax), largely lower volumes transported to storage |
Nine Months Ended September 30, 2011 and 2010 Pipeline and energy services earnings increased $6.0 million (54 percent) largely due to lower operation and maintenance expense, as previously discussed.
Partially offsetting the earnings increase were:
| | · | Lower storage services revenue of $4.7 million (after tax), as previously discussed |
| | · | Decreased transportation volumes of $4.6 million (after tax), largely lower volumes transported to storage, as well as lower off-system transportation volumes |
| | · | Lower gathering volumes of $2.7 million (after tax) |
The previous table also reflects higher revenue and higher operation and maintenance expense related to energy-related service projects.
Natural Gas and Oil Production
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | (Dollars in millions, where applicable) | |
| Operating revenues: | | | | | | | | | | | | |
| Natural gas | | $ | 45.9 | | | $ | 54.9 | | | $ | 135.6 | | | $ | 167.7 | |
| Oil | | | 74.9 | | | | 52.1 | | | | 201.9 | | | | 157.7 | |
| | | | 120.8 | | | | 107.0 | | | | 337.5 | | | | 325.4 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Operation and maintenance: | | | | | | | | | | | | | | | | |
| Lease operating costs | | | 19.4 | | | | 19.4 | | | | 55.8 | | | | 51.5 | |
| Gathering and transportation | | | 6.9 | | | | 5.9 | | | | 18.1 | | | | 17.6 | |
| Other | | | 9.8 | | | | 7.5 | | | | 27.3 | | | | 24.9 | |
| Depreciation, depletion and amortization | | | 38.5 | | | | 34.1 | | | | 106.0 | | | | 96.4 | |
| Taxes, other than income: | | | | | | | | | | | | | | | | |
| Production and property taxes | | | 10.0 | | | | 8.1 | | | | 30.5 | | | | 26.6 | |
| Other | | | (.7 | ) | | | .2 | | | | (.1 | ) | | | .7 | |
| | | | 83.9 | | | | 75.2 | | | | 237.6 | | | | 217.7 | |
| Operating income | | | 36.9 | | | | 31.8 | | | | 99.9 | | | | 107.7 | |
| Earnings | | $ | 22.5 | | | $ | 18.7 | | | $ | 60.1 | | | $ | 65.0 | |
| Production: | | | | | | | | | | | | | | | | |
| Natural gas (MMcf) | | | 11,656 | | | | 12,686 | | | | 34,667 | | | | 37,738 | |
| Oil (MBbls) | | | 944 | | | | 835 | | | | 2,567 | | | | 2,427 | |
| Total Production (MMcfe) | | | 17,321 | | | | 17,696 | | | | 50,071 | | | | 52,298 | |
| Average realized prices (including hedges): | | | | | | | | | | | | | | | | |
| Natural gas (per Mcf) | | $ | 3.94 | | | $ | 4.33 | | | $ | 3.91 | | | $ | 4.44 | |
| Oil (per Bbl) | | $ | 79.28 | | | $ | 62.41 | | | $ | 78.64 | | | $ | 65.00 | |
| Average realized prices (excluding hedges): | | | | | | | | | | | | | | | | |
| Natural gas (per Mcf) | | $ | 3.44 | | | $ | 3.38 | | | $ | 3.44 | | | $ | 3.74 | |
| Oil (per Bbl) | | $ | 80.90 | | | $ | 62.12 | | | $ | 83.05 | | | $ | 65.21 | |
| Average depreciation, depletion and amortization rate, per equivalent Mcf | | $ | 2.12 | | | $ | 1.84 | | | $ | 2.02 | | | $ | 1.75 | |
| Production costs, including taxes, per equivalent Mcf: | | | | | | | | | | | | | | | | |
| Lease operating costs | | $ | 1.12 | | | $ | 1.10 | | | $ | 1.11 | | | $ | .98 | |
| Gathering and transportation | | | .40 | | | | .33 | | | | .36 | | | | .34 | |
| Production and property taxes | | | .58 | | | | .46 | | | | .61 | | | | .51 | |
| | | $ | 2.10 | | | $ | 1.89 | | | $ | 2.08 | | | $ | 1.83 | |
Three Months Ended September 30, 2011 and 2010 Natural gas and oil production earnings increased $3.8 million (20 percent) due to:
| | · | Higher average realized oil prices of 27 percent |
| | · | Increased oil production of 13 percent, largely related to drilling activity from the South Texas properties, as well as in the Bakken area |
Partially offsetting these increases were:
| | · | Lower average realized natural gas prices of 9 percent |
| | · | Higher depreciation, depletion and amortization expense of $2.7 million (after tax), due to higher depletion rates |
| | · | Decreased natural gas production of 8 percent, largely related to normal production declines at existing properties |
| | · | Higher production and property taxes of $1.2 million (after tax), largely resulting from higher oil prices excluding hedges |
| | · | Higher general and administrative expense of $900,000 (after tax), largely higher benefit and payroll-related costs |
Nine Months Ended September 30, 2011 and 2010 Natural gas and oil production earnings decreased $4.9 million (7 percent) due to:
| | · | Lower average realized natural gas prices of 12 percent |
| | · | Decreased natural gas production of 8 percent, largely related to normal production declines at certain properties, partially offset by production from the Green River Basin properties, as well as from the South Texas properties |
| | · | Higher depreciation, depletion and amortization expense of $6.1 million (after tax), as previously discussed |
| | · | Increased lease operating expenses of $2.7 million (after tax), including higher well maintenance costs |
| | · | Higher production and property taxes of $2.4 million (after tax), as previously discussed |
| | · | Higher general and administrative expense of $1.0 million (after tax), largely higher payroll-related costs |
Partially offsetting these decreases were:
| | · | Higher average realized oil prices of 21 percent |
| | · | Increased oil production of 6 percent, largely related to drilling activity in the Bakken area, as well as from the South Texas properties, partially offset by normal production declines at certain properties |
Construction Materials and Contracting
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | (Dollars in millions) | |
| Operating revenues | | $ | 619.1 | | | $ | 612.7 | | | $ | 1,138.2 | | | $ | 1,124.1 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Operation and maintenance | | | 530.7 | | | | 513.4 | | | | 1,011.8 | | | | 976.4 | |
| Depreciation, depletion and amortization | | | 21.6 | | | | 22.5 | | | | 64.2 | | | | 67.2 | |
| Taxes, other than income | | | 11.1 | | | | 10.1 | | | | 28.6 | | | | 26.6 | |
| | | | 563.4 | | | | 546.0 | | | | 1,104.6 | | | | 1,070.2 | |
| Operating income | | | 55.7 | | | | 66.7 | | | | 33.6 | | | | 53.9 | |
| Earnings | | $ | 33.1 | | | $ | 40.3 | | | $ | 16.7 | | | $ | 25.8 | |
| Sales (000's): | | | | | | | | | | | | | | | | |
| Aggregates (tons) | | | 9,196 | | | | 8,741 | | | | 18,502 | | | | 17,965 | |
| Asphalt (tons) | | | 3,462 | | | | 3,343 | | | | 5,469 | | | | 5,076 | |
| Ready-mixed concrete (cubic yards) | | | 986 | | | | 919 | | | | 2,081 | | | | 2,137 | |
Three Months Ended September 30, 2011 and 2010 Earnings at the construction materials and contracting business decreased $7.2 million (18 percent) due to:
| | · | Lower earnings of $4.6 million (after tax) resulting from lower liquid asphalt oil and asphalt margins, largely due to higher costs |
| | · | Higher income taxes of $1.0 million, primarily due to a higher effective tax rate |
| | · | Decreased construction margins of $700,000 (after tax) |
Partially offsetting the decreases was lower interest expense, primarily due to lower average interest rates.
Results include the effects of the Minnesota state government shutdown in July 2011 and weather-related delays.
Nine Months Ended September 30, 2011 and 2010 Construction materials and contracting earnings decreased $9.1 million (35 percent) due to:
| | · | Lower earnings of $5.5 million (after tax), resulting from lower ready-mixed concrete margins and volumes and lower other product line margins |
| | · | Lower earnings of $4.3 million (after tax) resulting from lower liquid asphalt oil margins, largely resulting from higher asphalt oil costs |
| | · | Decreased construction margins of $2.1 million (after tax) |
| | · | Lower gains of $1.3 million (after tax) from the sale of property, plant and equipment |
Partially offsetting these items were:
| | · | Lower income taxes of $1.8 million, primarily related to an income tax benefit related to favorable resolution of certain income tax matters |
| | · | Lower interest expense of $1.6 million (after tax), as previously discussed |
| | · | Lower selling, general and administrative expense of $1.5 million (after tax), largely lower payroll-related costs |
Results include the effects of the Minnesota state government shutdown in July 2011 and weather-related delays.
Other and Intersegment Transactions
Amounts presented in the preceding tables will not agree with the Consolidated Statements of Income due to the Company's other operations and the elimination of intersegment transactions. The amounts relating to these items are as follows:
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | (In millions) | |
| Other: | | | | | | | | | | | | |
| Operating revenues | | $ | 2.6 | | | $ | 2.3 | | | $ | 7.9 | | | $ | 6.8 | |
| Operation and maintenance | | | 1.6 | | | | 1.9 | | | | 6.5 | | | | 5.6 | |
| Depreciation, depletion and amortization | | | .4 | | | | .4 | | | | 1.2 | | | | 1.2 | |
| Taxes, other than income | | | .1 | | | | .1 | | | | .1 | | | | .1 | |
| Intersegment transactions: | | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 39.9 | | | $ | 42.1 | | | $ | 139.3 | | | $ | 150.1 | |
| Purchased natural gas sold | | | 31.0 | | | | 35.7 | | | | 112.3 | | | | 131.4 | |
| Operation and maintenance | | | 8.9 | | | | 6.4 | | | | 27.0 | | | | 18.7 | |
For further information on intersegment eliminations, see Note 15.
PROSPECTIVE INFORMATION
The following information highlights the key growth strategies, projections and certain assumptions for the Company and its subsidiaries and other matters for certain of the Company's businesses. Many of these highlighted points are "forward-looking statements." There is no assurance that the Company's projections, including estimates for growth and changes in earnings, will in fact be achieved. Please refer to assumptions contained in this section, as well as the various important factors listed in Part II, Item 1A – Risk Factors, as well as Part I, Item 1A – Risk Factors in the 2010 Annual Report. Changes in such assumptions and factors could cause actual future results to differ materially from the Company's growth and earnings projections.
MDU Resources Group, Inc.
| · | Earnings per common share for 2011, diluted, are projected in the range of $1.05 to $1.15. |
| · | Although near term market conditions are uncertain, the Company’s long-term compound annual growth goals on earnings per share from operations are in the range of 7 percent to 10 percent. |
| · | The Company continually seeks opportunities to expand through strategic acquisitions and organic growth opportunities. |
Electric and natural gas distribution
| · | In August 2010, the Company filed an application with the MTPSC for an electric rate increase, as discussed in Note 17. |
| · | On July 7, 2011, the Company filed for an advance determination of prudence with the NDPSC on the construction of an 88-MW simple cycle natural gas turbine and associated facilities, as discussed in Note 17. |
| · | 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 currently served by fuel oil or propane, and to serve new customers. |
| · | Currently the Company is involved with a number of pipeline projects to enhance the reliability and deliverability of its system in the Pacific Northwest. |
| · | The Company is pursuing opportunities associated with the potential development of high-voltage transmission lines and system enhancements targeted towards delivery of renewable energy from the wind rich regions that lie within its traditional electric service territory to major market areas. The Company has a contract to develop a 30-mile high-voltage power line in southeast North Dakota to move power to the electric grid from a proposed 150-MW wind farm. The proposed project totals approximately $20 million and includes substation upgrades. Construction is underway and the project is expected to be completed by mid 2012. |
| · | The South Dakota Board of Minerals and Environment has approved rules implementing the South Dakota Regional Haze Program that upon approval by the EPA will require 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 as early as practicable, but not later than five years after EPA’s approval of the state program. The state program was submitted January 21, 2011. The Company’s share of the cost of this air quality control system could exceed $100 million. The Company believes continuing to operate Big Stone Station with the upgrade is the best option; however, it will continue to review alternatives. The Company intends to seek recovery of costs related to the above matter in electric rates charged to customers. On May 20, 2011, the Company filed for an advance determination of prudence with the NDPSC requesting advance determination that the air quality control system is reasonable and prudent, as discussed in Note 17. |
Construction services
| · | Work backlog as of September 30, 2011, was approximately $331 million, compared to $317 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. |
| · | The Company anticipates margins in 2011 to be comparable to 2010 levels. |
| · | The Company is pursuing expansion in high-voltage transmission and substation construction, renewable resource construction, governmental facilities, refinery turnaround projects and utility service work. |
Pipeline and energy services
| · | The Company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region, which includes portions of Colorado, Wyoming, Montana and North Dakota, is expanding, most notably the Bakken of North Dakota and eastern Montana. It 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. |
| · | Installation of additional compression at the Charbonneau station was completed and placed into service in September 2011, providing additional firm capacity for producers in the Bakken production area. With some additional modifications, this project has the potential of adding a total of 27 MMcf of firm capacity. |
| · | Construction has begun on approximately 12 miles of high pressure transmission pipeline providing takeaway capacity from the Garden Creek processing facility being constructed in northwestern North Dakota. The pipeline project is expected to be completed before year-end 2011. |
| · | Preparations are underway for the construction of approximately 13 miles of high pressure transmission pipeline from the Stateline I and II processing facilities in northwestern North Dakota to deliver gas into the Northern Border Pipeline. The project is expected to be completed by mid 2012. |
| · | The Company has three natural gas storage fields including the largest storage field in North America located near Baker, Montana. It continues to seek interest in its storage services and is pursuing a project to increase its firm deliverability from the Baker Storage field by 125 MMcf per day. Commitment on approximately 30 percent of the total potential project has been received. The additional firm deliverability is expected to be available in November 2011. |
Natural gas and oil production
| · | Capital expenditures in 2011 are expected to be approximately $300 million. The Company continues its focus on returns by allocating a growing portion of its capital investment into the production of oil in the current commodity price environment. Its capital program reflects further exploitation of existing properties, acquisition of additional leasehold acreage, and exploratory drilling. The 2011 planned capital expenditure total does not include potential acquisitions of producing properties. |
| · | For 2011, because of recent improved results in the Bakken and South Texas areas, the Company has increased its forecasted production and now expects a 4 percent to 7 percent increase in oil production offset by a 7 percent to 10 percent decrease in natural gas production. The projected decline in natural gas production is primarily the result of the deferral of certain gas development activity because of sustained low natural gas prices. |
| · | The Company has a total of 5 drilling rigs deployed on its acreage in the Bakken, Niobrara, South Texas and Big Horn areas. Expectations are to add another rig in the fourth quarter of 2011. By year-end 2012, the Company expects to have approximately 10 rigs deployed on its acreage. |
| · | Bakken – Mountrail County, North Dakota |
| | o | The Company owns approximately 16,000 net acres of leaseholds targeting the middle Bakken and Three Forks formations. The drilling of 15 operated and participation in various non-operated wells is expected for this year with approximately $60 million of capital expenditures. Plans include drilling 17 wells or more annually in 2012 and 2013. |
| | o | Over 50 future gross well sites have been identified. Estimated gross ultimate recovery per well is 250,000 to 500,000 Bbls. |
| · | Bakken – Stark County, North Dakota |
| | o | The Company holds approximately 50,000 net exploratory leasehold acres, targeting the Three Forks formation. The Company has commenced drilling and expects to drill 3 operated wells on this acreage over the next several months and to participate in various non-operated wells with capital of approximately $30 million this year. |
| | o | Based on well results, the Company plans to drill 6 or more wells annually beginning in 2012. |
| | o | Based on 640-acre spacing, the acreage holds over 140 potential gross well sites. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls. |
| · | Bakken – Richland County, Montana |
| | o | The Company holds approximately 20,000 net exploratory leasehold acres, targeting the Three Forks formation. |
| | o | Approximately 100 potential gross well sites have been identified on this acreage. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls. |
| | o | Expect to spud first appraisal well in early 2012. |
| · | Niobrara – southeastern Wyoming |
| | o | The Company holds approximately 65,000 net exploratory leasehold acres in this emerging oil play. Appraisal well drilling has begun with a total of 4 wells planned during the next several months. |
| | o | If successful, the Company plans to initiate a drilling program of approximately 8 wells annually starting in 2012. |
| | o | The Company also expects to participate in various non-operated wells in the Niobrara. |
| | o | Although this is an emerging exploratory play, the Company estimates it has as many as 200 potential future gross wells on this acreage based on 640-acre spacing. Estimated gross ultimate recovery rates per well are 200,000 to 300,000 Bbls. |
| · | Paradox Basin – Cane Creek Federal Unit, Utah |
| | o | The Company holds approximately 75,000 net exploratory leasehold acres. |
| | o | The Company expects to drill 2 wells in the next six months. |
| | o | Potential future gross wells are estimated at 70. Estimated gross ultimate recovery rates per well are 250,000 to 500,000 Bbls. |
| | o | The Company is targeting areas that have the potential for higher liquids content with approximately $50 million of capital planned for this year. |
| | o | Plans are to drill approximately 12 wells in total this year in South Texas. |
| | o | The Company has identified 50 future potential gross well sites. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls. |
| | o | The Company holds approximately 80,000 net exploratory leasehold acres in the Heath Shale oil prospect in Montana. Plans include drilling 2 appraisal wells over the next six months. |
| | o | The Company continues to pursue acquisitions of additional leaseholds. Approximately $50 million of capital has been allocated to leasehold acquisitions this year, focusing on expansion of existing positions and new opportunities. |
| · | Earnings guidance reflects estimated natural gas and oil prices for November and December as follows: |
| Index* | Price Per Mcf/Bbl |
| Natural gas: | |
NYMEX | $3.50 to $4.00 |
Ventura | $3.50 to $4.00 |
CIG | $3.25 to $3.75 |
| Crude Oil: | |
NYMEX | $84.00 to $88.00 |
| * Ventura is an index pricing point related to Northern Natural Gas Co.'s system; CIG is an index pricing point related to Colorado Interstate Gas Co.'s system. |
| · | For the last three months of 2011, the Company has hedged approximately 45 percent to 50 percent of its estimated natural gas production and 60 percent to 65 percent of its estimated oil production. For 2012, it has hedged 25 percent to 30 percent of its estimated natural gas production and 45 percent to 50 percent of its estimated oil production. The hedges that are in place as of October 31, 2011, are summarized in the following chart: |
| Commodity | Type | Index | Period Outstanding | Forward Notional Volume (MMBtu/Bbl) | Price (Per MMBtu/Bbl) |
| Natural Gas | Swap | HSC | 10/11 - 12/11 | 340,400 | $8.00 |
| Natural Gas | Swap | NYMEX | 10/11 - 12/11 | 1,012,000 | $6.1027 |
| Natural Gas | Swap | NYMEX | 10/11 - 12/11 | 920,000 | $5.4975 |
| Natural Gas | Swap | NYMEX | 10/11 - 12/11 | 920,000 | $4.58 |
| Natural Gas | Swap | NYMEX | 10/11 - 12/11 | 920,000 | $4.70 |
| Natural Gas | Swap | NYMEX | 10/11 - 12/11 | 920,000 | $4.75 |
| Natural Gas | Swap | NYMEX | 10/11 | 310,000 | $4.775 |
| Natural Gas | Swap | Ventura | 10/11 | 310,000 | $4.365 |
| Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 3,477,000 | $6.27 |
| Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 1,830,000 | $5.005 |
| Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 915,000 | $5.005 |
| Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 915,000 | $5.0125 |
| Natural Gas | Swap | Ventura | 1/12 - 12/12 | 3,660,000 | $4.87 |
| Crude Oil | Collar | NYMEX | 10/11 - 12/11 | 138,000 | $80.00-$94.00 |
| Crude Oil | Collar | NYMEX | 10/11 - 12/11 | 92,000 | $80.00-$89.00 |
| Crude Oil | Collar | NYMEX | 10/11 - 12/11 | 46,000 | $77.00-$86.45 |
| Crude Oil | Collar | NYMEX | 10/11 - 12/11 | 46,000 | $75.00-$88.00 |
| Crude Oil | Swap | NYMEX | 10/11 - 12/11 | 92,000 | $81.35 |
| Crude Oil | Swap | NYMEX | 10/11 - 12/11 | 46,000 | $85.85 |
| Crude Oil | Put Option | NYMEX | 10/11 - 12/11 | 92,000 | $80.00* |
| Crude Oil | Call Option | NYMEX | 10/11 - 12/11 | 92,000 | $103.00* |
| Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 366,000 | $80.00-$87.80 |
| Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 366,000 | $80.00-$94.50 |
| Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 366,000 | $80.00-$98.36 |
| Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 183,000 | $85.00-$102.75 |
| Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 183,000 | $85.00-$103.00 |
| Crude Oil | Swap | NYMEX | 1/12 - 12/12 | 183,000 | $100.10 |
| Crude Oil | Swap | NYMEX | 1/12 - 12/12 | 183,000 | $100.00 |
| Crude Oil | Swap | NYMEX | 1/12 - 12/12 | 366,000 | $110.30 |
| Crude Oil | Collar | NYMEX | 1/13 - 12/13 | 182,500 | $95.00-$117.00 |
| Crude Oil | Collar | NYMEX | 1/13 - 12/13 | 182,500 | $95.00-$117.00 |
| Natural Gas | Basis Swap | CIG | 10/11 - 12/11 | 1,012,000 | $0.395 |
| Natural Gas | Basis Swap | Ventura | 10/11 - 12/11 | 920,000 | $0.15 |
| Natural Gas | Basis Swap | Ventura | 10/11 - 12/11 | 460,000 | $0.15 |
| Natural Gas | Basis Swap | Ventura | 10/11 - 12/11 | 230,000 | $0.16 |
| Natural Gas | Basis Swap | Ventura | 10/11 - 12/11 | 920,000 | $0.16 |
| Natural Gas | Basis Swap | Ventura | 10/11 - 12/11 | 1,150,000 | $0.155 |
| Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 2,745,000 | $0.405 |
| Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 732,000 | $0.41 |
* Deferred premium of $4.00. Put option was purchased. Call option was sold. Notes: · Ventura is an index pricing point related to Northern Natural Gas Co.'s system; CIG is an index pricing point related to Colorado Interstate Gas Co.'s system; HSC is the Houston Ship Channel hub in southeast Texas which connects to several pipelines. · For all basis swaps, Index prices are below NYMEX prices and are reported as a positive amount in the Price column. |
Construction materials and contracting
| · | Work backlog as of September 30, 2011, was approximately $448 million, with 91 percent of construction backlog being public work and private representing 9 percent. In the Company’s peak earnings year of 2006, private backlog represented 40 percent of construction backlog. Backlog a year ago was $464 million. Examples of projects in work backlog include several highway paving projects, airports, bridge work, reclamation and harbor expansion projects. |
| · | The Company is part of a joint venture that was selected as the low bidder on the Port of Long Beach expansion. Its share of the project for this phase is expected to exceed $25 million. The Company has green fielded an operation in Williston, North Dakota and was awarded a $33 million highway project in the Bakken area of North Dakota. It also expects to place a new asphalt oil terminal into service by year-end 2011 in Wyoming. The Company is the primary cement provider in Hawaii and has the opportunity to supply a portion of the ready-mixed concrete and aggregate related to a multi-phased light rail project. |
| · | Overall 2011 volumes are expected to be comparable to 2010. |
| · | The Company continues to pursue work related to energy projects, such as wind towers, transmission projects, geothermal and refineries. It is also pursuing opportunities for expansion of its existing business lines including initiatives aimed at capturing additional market share and expansion into new markets. |
| · | As the country’s 5th 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 nine labor contracts that Knife River was negotiating, as reported in Items 1 and 2 – Business and Properties – General in the 2010 Annual Report, seven have been ratified. The two remaining contracts are still in negotiations. |
NEW ACCOUNTING STANDARDS
For information regarding new accounting standards, see Note 7, which is incorporated by reference.
CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES
The Company's critical accounting policies involving significant estimates include impairment testing of natural gas and oil production properties, impairment testing of long-lived assets and intangibles, revenue recognition, pension and other postretirement benefits, and income taxes. There were no material changes in the Company's critical accounting policies involving significant estimates from those reported in the 2010 Annual Report. For more information on critical accounting policies involving significant estimates, see Part II, Item 7 in the 2010 Annual Report.
LIQUIDITY AND CAPITAL COMMITMENTS
At September 30, 2011, the Company had cash and cash equivalents of $118.7 million and available capacity of $621.7 million under the outstanding credit facilities of the Company and its subsidiaries.
Cash flows
Operating activities The changes in cash flows from operating activities generally follow the results of operations as discussed in Financial and Operating Data and also are affected by changes in working capital.
Cash flows provided by operating activities in the first nine months of 2011 increased $40.1 million from the comparable period in 2010. The increase was largely due to lower working capital requirements of $29.8 million, largely at the electric and natural gas distribution businesses. In addition, excluding working capital, the Company experienced higher cash flows from operating activities, primarily at the natural gas and oil production business.
Investing activities Cash flows used in investing activities in the first nine months of 2011 decreased $103.4 million from the comparable period in 2010. The decrease was largely due to lower cash used for acquisitions of $106.4 million, primarily at the natural gas and oil production business.
Financing activities Cash flows used in financing activities in the first nine months of 2011 increased $107.7 million from the comparable period in 2010 largely resulting from higher repayment of long-term debt and short-term borrowings, as well as lower issuance of long-term debt.
Defined benefit pension plans
There were no material changes to the Company's qualified noncontributory defined benefit pension plans from those reported in the 2010 Annual Report. For further information, see Note 16 and Part II, Item 7 in the 2010 Annual Report.
Capital expenditures
Net capital expenditures for the first nine months of 2011 were $323.0 million and are estimated to be approximately $515 million for 2011. Estimated capital expenditures include:
| | · | Routine equipment maintenance and replacements |
| | · | Buildings, land and building improvements |
| | · | Pipeline and gathering projects |
| | · | Further development of existing properties, acquisition of additional leasehold acreage and exploratory drilling at the natural gas and oil production segment |
| | · | Power generation opportunities, including certain costs for additional electric generating capacity |
| | · | Other growth opportunities |
The Company continues to evaluate potential future acquisitions and other growth opportunities; however, they are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimated 2011 capital expenditures referred to previously. The Company expects the 2011 estimated capital expenditures to be funded in their entirety with cash flow generated from operations.
Capital resources
Certain debt instruments of the Company and its subsidiaries, including those discussed later, contain restrictive covenants and cross-default provisions. In order to borrow under the respective credit agreements, the Company and its subsidiaries must be in compliance with the applicable covenants and certain other conditions, all of which the Company and its subsidiaries, as applicable, were in compliance with at September 30, 2011. In the event the Company and its subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued. For additional information on the covenants, certain other conditions and cross-default provisions, see Part II, Item 8 – Note 9, in the 2010 Annual Report.
The following table summarizes the outstanding credit facilities of the Company and its subsidiaries at September 30, 2011:
| Company | Facility | | | Facility Limit | | | | Amount Outstanding | | | | Letters of Credit | | | Expiration Date | |
| (Dollars in millions) |
| MDU Resources Group, Inc. | Commercial paper/Revolving credit agreement | (a) | | $ | 100.0 | | | | $ | — | | (b) | | $ | — | | | 5/26/15 | |
| Cascade Natural Gas Corporation | Revolving credit agreement | | | $ | 50.0 | | (c) | | $ | — | | | | $ | 1.9 | | (d) | 12/28/12 | (e) |
| Intermountain Gas Company | Revolving credit agreement | | | $ | 65.0 | | (f) | | $ | 4.0 | | | | $ | — | | | 8/11/13 | |
| Centennial Energy Holdings, Inc. | Commercial paper/Revolving credit agreement | (g) | | $ | 400.0 | | | | $ | — | | (b) | | $ | 24.9 | | (d) | 12/13/12 | |
| Williston Basin Interstate Pipeline Company | Uncommitted long-term private shelf agreement | | | $ | 125.0 | | | | $ | 87.5 | | | | $ | — | | | 12/23/11 | (h) |
| (a) | The $125 million commercial paper program is supported by a revolving credit agreement with various banks totaling $100 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) | The outstanding letters of credit, as discussed in Note 18, reduce amounts available under the credit agreement. |
| (e) | Provisions allow for an extension of up to two years upon consent of the banks. |
| (f) | Certain provisions allow for increased borrowings, up to a maximum of $80 million. |
| (g) | The $400 million commercial paper program is supported by a revolving credit agreement with various banks totaling $400 million (provisions allow for increased borrowings, at the option of Centennial on stated conditions, up to a maximum of $450 million). There were no amounts outstanding under the credit agreement. |
| (h) | Represents expiration of the ability to borrow additional funds under the agreement. |
The Company's and Centennial's respective commercial paper programs are supported by revolving credit agreements. While the amount of commercial paper outstanding does not reduce available capacity under the respective revolving credit agreements, the Company and Centennial do not issue
commercial paper in an aggregate amount exceeding the available capacity under their credit agreements.
The following includes information related to the preceding table.
MDU Resources Group, Inc. On May 26, 2011, the Company entered into a new revolving credit agreement, which replaced the revolving credit agreement that expired on June 21, 2011. The credit agreement contains customary covenants and provisions, including covenants of the Company not to permit, as of the end of any fiscal quarter, (A) the ratio of funded debt to total capitalization (determined on a consolidated basis) to be greater than 65 percent or (B) the ratio of funded debt to capitalization (determined with respect to the Company alone, excluding its subsidiaries) to be greater than 65 percent. Other covenants include limitations on the sale of certain assets and on the making of certain loans and investments. The credit agreement does not contain any cross-default provisions.
The Company's revolving credit agreement supports its commercial paper program. The commercial paper borrowings are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings. The Company's objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Downgrades in the Company's credit ratings have not limited, nor are currently expected to limit, the Company's ability to access the capital markets. If the Company were to experience a further downgrade of its credit ratings, it may need to borrow under its credit agreement and may experience an increase in overall interest rates with respect to its cost of borrowings.
Prior to the maturity of the credit agreement, the Company expects that it will negotiate the extension or replacement of this agreement. If the Company is unable to successfully negotiate an extension of, or replacement for, the credit agreement, or if the fees on this facility become too expensive, which the Company does not currently anticipate, the Company would seek alternative funding.
The Company's coverage of fixed charges including preferred stock dividends was 4.1 times for the 12 months ended September 30, 2011 and December 31, 2010.
Common stockholders' equity as a percent of total capitalization was 66 percent and 64 percent at September 30, 2011 and December 31, 2010, respectively. This ratio is calculated as the Company's common stockholders' equity, divided by the Company's total capital. Total capital is the Company's total debt, including short-term borrowings and long-term debt due within one year, plus stockholders' equity. This ratio indicates how a company is financing its operations, as well as its financial strength.
The Company currently has a shelf registration statement on file with the SEC, under which the Company may issue and sell any combination of common stock and debt securities. The Company may sell all or a portion of such securities if warranted by market conditions and the Company's capital requirements. Any offer and sale of such securities will be made only by means of a prospectus meeting the requirements of the Securities Act and the rules and regulations thereunder. The Company's board of directors currently has authorized the issuance and sale of up to an aggregate of $1.0 billion worth of such securities. The Company's board of directors reviews this authorization on a periodic basis and the aggregate amount of securities authorized may be increased in the future.
Centennial Energy Holdings, Inc. Centennial's revolving credit agreement supports its commercial paper program. The Centennial commercial paper borrowings are classified as long-term debt as Centennial intends to refinance these borrowings on a long-term basis through continued Centennial commercial paper borrowings. Centennial's objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Downgrades in Centennial's credit
ratings have not limited, nor are currently expected to limit, Centennial's ability to access the capital markets. If Centennial were to experience a further downgrade of its credit ratings, it may need to borrow under its credit agreement and may experience an increase in overall interest rates with respect to its cost of borrowings.
Prior to the maturity of the Centennial credit agreement, Centennial expects that it will negotiate the extension or replacement of this agreement, which provides credit support to access the capital markets. In the event Centennial is unable to successfully negotiate this agreement, or in the event the fees on this facility become too expensive, which Centennial does not currently anticipate, it would seek alternative funding.
Off balance sheet arrangements
In connection with the sale of the Brazilian Transmission Lines, 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.
Centennial continues to guarantee CEM's obligations under a construction contract for a 550-MW combined-cycle electric generating facility near Hobbs, New Mexico. For further information, see Note 18.
Contractual obligations and commercial commitments
There are no material changes in the Company's contractual obligations relating to long-term debt, estimated interest payments, operating leases, purchase commitments and minimum funding requirements for its defined benefit plans for 2011 from those reported in the 2010 Annual Report.
For more information on the Company's uncertain tax positions, see Note 14.
For more information on contractual obligations and commercial commitments, see Part II, Item 7 in the 2010 Annual Report.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to the impact of market fluctuations associated with commodity prices, interest rates and foreign currency. The Company has policies and procedures to assist in controlling these market risks and utilizes derivatives to manage a portion of its risk.
Commodity price risk
Fidelity utilizes derivative instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil and basis differentials on forecasted sales of natural gas and oil production. Cascade utilizes, and Intermountain periodically utilizes, derivative instruments to manage a portion of their regulated natural gas supply portfolio in order to manage fluctuations in the price of natural gas. For more information on derivative instruments and commodity price risk, see Part II, Item 7A in the 2010 Annual Report, and Notes 8 and 12.
The following table summarizes derivative agreements entered into by Fidelity and Cascade as of September 30, 2011. These agreements call for Fidelity to receive fixed prices and pay variable prices and for Cascade to receive variable prices and pay fixed prices.
| | (Forward notional volume and fair value in thousands) | |
| | | | | | | | | | | |
| | | | Weighted Average Fixed Price (Per MMBtu/Bbl) | | | Forward Notional Volume (MMBtu/Bbl) | | | Fair Value | |
| Fidelity | | | | | | | | | | |
| Natural gas swap agreements maturing in 2011 | | | $ | 5.25 | | | | 5,652 | | | $ | 8,266 | |
| Natural gas swap agreements maturing in 2012 | | | $ | 5.37 | | | | 10,797 | | | $ | 12,052 | |
| Natural gas basis swap agreements maturing in 2011 | | | $ | .21 | | | | 4,692 | | | $ | (1,256 | ) |
| Natural gas basis swap agreements maturing in 2012 | | | $ | .41 | | | | 3,477 | | | $ | (624 | ) |
| Oil swap agreements maturing in 2011 | | | $ | 82.85 | | | | 138 | | | $ | 479 | |
| Oil swap agreements maturing in 2012 | | | $ | 105.18 | | | | 732 | | | $ | 17,575 | |
| | | | | | | | | | | | | | |
| Cascade | | | | | | | | | | | | | |
| Natural gas swap agreements maturing in 2011 | | | $ | 6.67 | | | | 371 | | | $ | (1,145 | ) |
| Natural gas swap agreement maturing in 2012 | | | $ | 4.47 | | | | 305 | | | $ | (160 | ) |
| | | | | | | | | | | | | | |
| | | | Weighted Average Floor/Ceiling Price (Per Bbl) | | | Forward Notional Volume (Bbl) | | | Fair Value | |
| Fidelity | | | | | | | | | | | | | |
| Oil collar agreements maturing in 2011 | | | | $78.86/$90.64 | | | | 322 | | | $ | 1,093 | |
| Oil collar agreements maturing in 2012 | | | | $81.25/$95.88 | | | | 1,464 | | | $ | 8,433 | |
| Oil collar agreements maturing in 2013 | | | | $95.00/$117.00 | | | | 365 | | | $ | 6,008 | |
| | | | | | | | | | | | | | |
| | Deferred Premium | | Weighted Average Floor (Per Bbl) | | | Forward Notional Volume (Bbl) | | | Fair Value | |
| Fidelity | | | | | | | | | | | | | |
| Oil put agreement maturing in 2011 | $4.00 | | $ | 80.00 | | | | 92 | | | $ | 127 | |
| Oil call agreement maturing in 2011 | $4.00 | | $ | 103.00 | | | | 92 | | | $ | 336 | |
Interest rate risk
There were no material changes to interest rate risk faced by the Company from those reported in the 2010 Annual Report. For more information, see Part II, Item 7A in the 2010 Annual Report.
Centennial entered into interest rate swap agreements to manage a portion of its interest rate exposure on the forecasted issuance of long-term debt. The agreements call for Centennial to receive payments
from or make payments to counterparties based on the difference between fixed and variable rates as specified by the interest rate swap agreements. For more information on derivative instruments, see Notes 8 and 12.
The following table summarizes derivative instruments entered into by Centennial as of September 30, 2011. The agreements call for Centennial to receive variable rates and pay fixed rates.
| (Notional amount and fair value in thousands) | |
| | | | | | | | | | |
| | | Weighted Average Fixed Interest Rate | | | Notional Amount | | | Fair Value | |
| Centennial | | | | | | | | | |
| Interest rate swap agreement with mandatory termination date in 2012 | | | 3.15 | % | | $ | 10,000 | | | $ | (612 | ) |
| Interest rate swap agreements with mandatory termination dates in 2013 | | | 3.22 | % | | $ | 50,000 | | | $ | (2,879 | ) |
Foreign currency risk
The Company's equity method investment in ECTE is exposed to market risks from changes in foreign currency exchange rates between the U.S. dollar and the Brazilian Real. For further information, see Part II, Item 8 – Note 4 in the 2010 Annual Report.
At September 30, 2011 and 2010, and December 31, 2010, the Company had no outstanding foreign currency hedges.
ITEM 4. CONTROLS AND PROCEDURES
The following information includes the evaluation of disclosure controls and procedures by the Company's chief executive officer and the chief financial officer, along with any significant changes in internal controls of the Company.
Evaluation of disclosure controls and procedures
The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. The Company's disclosure controls and other procedures are designed to provide reasonable assurance that information required to be disclosed in the reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The Company's disclosure controls and procedures include controls and procedures designed to provide reasonable assurance that information required to be disclosed is accumulated and communicated to management, including the Company's chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure. The Company's management, with the participation of the Company's chief executive officer and chief financial officer, has evaluated the effectiveness of the Company's disclosure controls and procedures. Based upon that evaluation, the chief executive officer and the chief financial officer have concluded that, as of the end of the period covered by this report, such controls and procedures were effective at a reasonable assurance level.
Changes in internal controls
No change in the Company's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarter ended September 30, 2011, that has
materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information regarding legal proceedings, see Note 18, which is incorporated by reference.
ITEM 1A. RISK FACTORS
This Form 10-Q contains forward-looking statements within the meaning of Section 21E of the Exchange Act. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words "anticipates," "estimates," "expects," "intends," "plans," "predicts" and similar expressions.
The Company is including the following factors and cautionary statements in this Form 10-Q to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Prospective Information. All these subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, also are expressly qualified by these factors and cautionary statements.
Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management's examination of historical operating trends, data contained in the Company's records and other data available from third parties. Nonetheless, the Company's expectations, beliefs or projections may not be achieved or accomplished.
Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.
There are no material changes in the Company's risk factors from those reported in Part I, Item 1A – Risk Factors in the 2010 Annual Report other than the risk related to environmental laws and regulations; the risk associated with electric generation operation that could be adversely impacted by global climate change initiatives to reduce GHG emissions; and the risk related to increased costs related to obligations under multiemployer pension plans. These factors and the other matters discussed herein are important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in the forward-looking statements included elsewhere in this document.
Environmental and Regulatory Risks
The Company's operations are subject to environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the Company to environmental liabilities.
The Company is subject to environmental laws and regulations affecting many aspects of its present and future operations, including air quality, water quality, waste management and other environmental considerations. These laws and regulations can result in increased capital, operating and other costs, delays as a result of litigation and administrative proceedings, and compliance, remediation, containment, monitoring and reporting obligations, particularly with regard to laws relating to power plant operations and natural gas and oil development. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Public officials and entities, as well as private individuals and organizations, may seek injunctive relief or other remedies to enforce applicable environmental laws and regulations. The Company cannot predict the outcome (financial or operational) of any related litigation or administrative proceedings that may arise.
Existing environmental laws and regulations may be revised and new laws and regulations seeking to protect the environment may be adopted or become applicable to the Company. These laws and regulations could require the Company to limit the use or output of certain facilities, restrict the use of certain fuels, install pollution control equipment or initiate pollution control technologies, remediate environmental contamination, remove or reduce environmental hazards, or prevent or limit the development of resources. Revised or additional laws and regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on the Company's results of operations and cash flows.
The EPA has issued draft regulations that outline several possible approaches for coal combustion residuals management under the RCRA. One approach, designating coal ash as a hazardous waste, would significantly change and increase the costs of managing coal ash at five plants that supply electricity to customers of Montana-Dakota. This designation also could significantly increase costs for Knife River, which beneficially uses fly ash as a cement replacement in ready-mixed concrete and road base applications.
The EPA also has proposed rules to reduce mercury and other toxic air emissions from coal- and oil-fired electric utility steam generating units. As proposed, air pollution control retrofits, such as baghouses, would need to be installed at company-owned electric generation facilities in order to comply with the rule's emissions limits. Montana-Dakota is evaluating the impact of the proposed rule on its electric generation resources.
Hydraulic fracturing is an important common practice used by the Company that involves injecting water, sand and chemicals under pressure into rock formations to stimulate natural gas and oil production. The EPA is developing a study to review the potential effects of hydraulic fracturing on underground sources of drinking water; the results of that study have the potential to impact the likelihood or scope of future legislation or regulation. Other legislative initiatives and regulatory studies, proceedings or initiatives at federal or state agencies focused on the hydraulic fracturing process could result in additional compliance, reporting and disclosure requirements. While not materially impacted by current regulation, future legislation or regulation could cause the Company to experience increased compliance and operating costs, as well as delay or inhibit its ability to develop its natural gas and oil reserves.
Global climate change initiatives to reduce GHG emissions could adversely impact the Company's electric generation operations.
Concern that GHG emissions are contributing to global climate change has led to international, federal and state legislative and regulatory proposals to reduce or mitigate the effects of GHG emissions. The EPA finalized its endangerment finding for GHG emissions in late 2009, and its GHG "Tailoring" Rule in 2010. Starting in 2011, the GHG Tailoring Rule requires new large emission sources, such as coal-fired electric generating facilities, and existing large emission sources that make modifications that increase GHG emissions to obtain permits and conduct best available control technology evaluations to limit the amount of GHG emission from these sources.
The primary GHG emitted from the Company's operations is carbon dioxide from combustion of fossil fuels at Montana-Dakota's electric generating facilities, particularly its coal-fired electric generating facilities. Approximately 70 percent of Montana-Dakota's owned generating capacity and more than 90 percent of the electricity it generates is from coal-fired plants. Montana-Dakota also owns approximately 100 MW of natural gas- and oil-fired peaking plants.
While the future of GHG regulation is uncertain, Montana-Dakota's electric generating facilities may be subject to climate change laws or regulations within the next few years. Implementation of treaties, legislation or regulations to reduce GHG emissions could affect Montana-Dakota's electric utility operations by requiring expanded energy conservation efforts or increased development of renewable energy sources, as well as other mandates that could significantly increase capital expenditures and operating costs. If Montana-Dakota does not receive timely and full recovery of GHG emission compliance costs from its customers, then such costs could have an adverse impact on the results of its operations.
Due to the uncertain availability of technologies to control GHG emissions and the unknown obligations that potential GHG emission legislation or regulations may create, the Company cannot determine the financial impact on its operations.
Other Risks
An increase in costs related to obligations under multiemployer pension plans could have a material negative effect on the Company's results of operations and cash flows.
Various operating subsidiaries of the Company participate in approximately 70 multiemployer pension plans for employees represented by certain unions. The Company is required to make contributions to these plans in amounts established under numerous collective bargaining agreements between the operating subsidiaries and those unions.
The Company may be obligated to increase its contributions to underfunded plans that are classified as being in endangered, seriously endangered, or critical status as defined by the Pension Protection Act of 2006. Plans classified as being in one of these statuses are required to adopt rehabilitation plans or funding improvement plans to improve their funded status through increased contributions, reduced benefits or a combination of the two. Based on available information, the Company believes that slightly less than 50 percent of the multiemployer plans to which it contributes are currently in endangered, seriously endangered or critical status.
The Company may also be required to increase its contributions to multiemployer plans where the other participating employers in such plans withdraw from the plan and are not able to contribute an amount sufficient to fund the unfunded liabilities associated with their participants in the plans. The amount and timing of any increase in the Company's required contributions to multiemployer pension plans may
also depend upon one or more of the following factors including the outcome of collective bargaining, actions taken by trustees who manage the plans, the industry for which contributions are made, future determinations that additional plans reach endangered, seriously endangered or critical status, government regulations and the actual return on assets held in the plans, among others. The Company may experience increased operating expenses as a result of the required contributions to multiemployer pension plans, which may have a material adverse effect on the Company's results of operations, financial position or cash flows.
In addition, pursuant to ERISA, as amended by MPPAA, the Company could incur a partial or complete withdrawal liability upon withdrawing from a plan, exiting a market in which it does business with a union workforce or upon termination of a plan to the extent these plans are underfunded.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 5. OTHER INFORMATION
MINE SAFETY INFORMATION
This mine safety information is reported pursuant to the Dodd-Frank Act. The Dodd-Frank Act requires reporting of the following types of citations or orders:
| | 1. | Citations issued under Section 104(a) 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(a) 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. |
During the three months ended September 30, 2011, none of the Company's operating subsidiaries received citations or orders under the following sections of the Mine Safety Act: 104(b), 104(d), 107(a), 110(b)(2) or 104(e). In addition, the Company did not have any mining-related fatalities during this period. The Company has 64 contests pending before administrative law judges of the Federal Mine
Safety and Health Review Commission that involve all types of citations. Of the contests pending, 10 were initiated during the three months ended September 30, 2011.
Information related to citations and assessments under the Mine Safety Act during the three months ended September 30, 2011, is shown in the following table. Proposed assessments listed could have arisen from citations issued in prior periods. In addition, assessments may not have yet been proposed for citations issued during the period for which data is reported and could relate to citations not reportable under the Dodd-Frank Act. Amounts shown as outstanding as of September 30, 2011, include amounts assessed for all citations issued under the Mine Safety Act, including those not reportable under the Dodd-Frank Act.
| Mine | State | | Section 104(a) Citations Issued | | | Citations Contested | | | Proposed Assessments Levied | | | Outstanding as of September 30, 2011 | |
| Birchwood | AK | | | 1 | | | | 1 | | | $ | 262 | | | $ | 262 | |
| Hallwood Plant | CA | | | — | | | | — | | | | — | | | | 1,404 | |
| Orland Plant | CA | | | — | | | | — | | | | — | | | | 317 | |
| Pebbly Beach Quarry | CA | | | 1 | | | | — | | | | 885 | | | | 2,550 | |
| Halawa Valley | HI | | | — | | | | — | | | | — | | | | 18,800 | |
| Puunene Quarry | HI | | | — | | | | — | | | | — | | | | 660 | |
| Waikapu Quarry | HI | | | — | | | | — | | | | 972 | | | | 972 | |
| Waimea Quarry | HI | | | — | | | | — | | | | 93 | | | | — | |
| Becker Portable Plant | IA | | | — | | | | — | | | | 200 | | | | — | |
| Amyx Pit | ID | | | — | | | | — | | | | 100 | | | | — | |
| Bang Pit | MN | | | — | | | | — | | | | 600 | | | | — | |
| Fitzgerald Pit | MN | | | — | | | | — | | | | 200 | | | | — | |
| Sauk Rapids | MN | | | — | | | | — | | | | 100 | | | | — | |
| Alva | ND | | | — | | | | — | | | | 200 | | | | — | |
| Dralle Pit | ND | | | — | | | | 3 | | | | 300 | | | | 400 | |
| Pioneer | ND | | | — | | | | 5 | | | | 570 | | | | — | |
| Weinmann Pit | ND | | | — | | | | 1 | | | | 408 | | | | 6,708 | |
| 140 Pit | OR | | | — | | | | — | | | | 176 | | | | — | |
| Advance Aggregate | OR | | | — | | | | — | | | | 762 | | | | — | |
| Drycreek Landfill | OR | | | — | | | | — | | | | 100 | | | | — | |
| Gazley Pit | OR | | | — | | | | — | | | | 100 | | | | — | |
| Lone Pine Portable | OR | | | — | | | | — | | | | — | | | | 100 | |
| Paetsch Pit | OR | | | — | | | | — | | | | — | | | | 112 | |
| Quality Rock | OR | | | — | | | | — | | | | 21,840 | | | | 21,840 | |
| Salem-Reed Pit | OR | | | 1 | | | | — | | | | — | | | | 478 | |
| Stayton | OR | | | — | | | | — | | | | 100 | | | | — | |
| Waterview | OR | | | 1 | | | | — | | | | 961 | | | | — | |
| Weddle Pit | OR | | | — | | | | — | | | | 100 | | | | 100 | |
| Sky High Pit | TX | | | — | | | | — | | | | — | | | | 723 | |
| Star Pit #1 | WY | | | — | | | | — | | | | — | | | | 500 | |
| VR Pit | WY | | | — | | | | — | | | | — | | | | 100 | |
| Total | | | | 4 | | | | 10 | | | $ | 29,029 | | | $ | 56,026 | |
The Dodd-Frank Act also requires information to be disclosed about each citation contested before the Federal Mine Safety and Health Review Commission during the time period covered by the periodic report. Please refer to the following table for the required information since enactment of the Dodd-Frank Act through September 30, 2011.
| Mine | State | | Month Citation Issued | | Contest Initiated By | | Category of Violation | | Proposed Assessments Levied (Dollars) | * | | Month Citation Closed | ** | | Result of Contest | ** |
| Birchwood | AK | | | 8/2011 | *** | Operator | | | 104 | (a) | | $ | 162 | | | | — | | | | — | |
| Hallwood Plant | CA | | | 4/2011 | | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Hallwood Plant | CA | | | 4/2011 | | Operator | | | 104 | (a) | | | 1,304 | | | | — | | | | — | |
| Orland Plant | CA | | | 4/2011 | | Operator | | | 104 | (a) | | | 117 | | | | 8/2011 | | | Vacated | |
| Orland Plant | CA | | | 4/2011 | | Operator | | | 104 | (a) | | | 100 | | | | 8/2011 | | | Vacated | |
| Orland Plant | CA | | | 4/2011 | | Operator | | | 104 | (a) | | | 100 | | | | 8/2011 | | | Vacated | |
| Orland Plant | CA | | | 4/2011 | | Operator | | | 104 | (a) | | | 117 | | | | — | | | | — | |
| Orland Plant | CA | | | 4/2011 | | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Orland Plant | CA | | | 4/2011 | | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Orland Plant | CA | | | 4/2011 | | Operator | | | 104 | (a) | | | — | | | | — | | | | — | |
| Orland Plant | CA | | | 4/2011 | | Operator | | | 104 | (a) | | | — | | | | — | | | | — | |
| Pebbly Beach | CA | | | 5/2011 | | Operator | | | 104 | (a) | | | 1,000 | | | | — | | | | — | |
| Pebbly Beach | CA | | | 5/2011 | | Operator | | | 104 | (a) | | | 1,000 | | | | — | | | | — | |
| Pebbly Beach | CA | | | 5/2011 | | Operator | | | 104 | (a) | | | 555 | | | | — | | | | — | |
| Pebbly Beach | CA | | | 5/2011 | | Operator | | | 107 | (a) | | | — | | | | — | | | | — | |
| Rockville 3 | MN | | | 11/2010 | | Operator | | | 104 | (d) | | | 2,400 | | | | — | | | | — | |
| Dralle Pit | ND | | | 6/2011 | *** | Operator | | | 104 | (a) | | | 108 | | | | — | | | | — | |
| Dralle Pit | ND | | | 6/2011 | *** | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Dralle Pit | ND | | | 6/2011 | *** | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Pioneer | ND | | | 6/2011 | *** | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Pioneer | ND | | | 6/2011 | *** | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Pioneer | ND | | | 6/2011 | *** | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Pioneer | ND | | | 6/2011 | *** | Operator | | | 104 | (a) | | | 162 | | | | — | | | | — | |
| Pioneer | ND | | | 6/2011 | *** | Operator | | | 104 | (a) | | | 108 | | | | — | | | | — | |
| Weinmann Pit | ND | | | 6/2011 | *** | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Lone Pine | OR | | | 7/2010 | | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Paetsch Pit | OR | | | 12/2010 | | Operator | | | 104 | (a) | | | 112 | | | | — | | | | — | |
| Paetsch Pit | OR | | | 1/2011 | | Operator | | | 104 | (b) | | | — | | | | — | | | | — | |
| Quality Rock | OR | | | 11/2010 | | Operator | | | 104 | (d) | | | 12,900 | | | | — | | | | — | |
| Quality Rock | OR | | | 11/2010 | | Operator | | | 104 | (d) | | | 4,500 | | | | — | | | | — | |
| Quality Rock | OR | | | 11/2010 | | Operator | | | 104 | (d) | | | 4,440 | | | | — | | | | — | |
| Salem-Reed Pit | OR | | | 2/2011 | | Operator | | | 104 | (a) | | | 108 | | | | — | | | | — | |
| Salem-Reed Pit | OR | | | 2/2011 | | Operator | | | 104 | (a) | | | 162 | | | | — | | | | — | |
| Salem-Reed Pit | OR | | | 2/2011 | | Operator | | | 104 | (a) | | | 108 | | | | — | | | | — | |
| Salem-Reed Pit | OR | | | 2/2011 | | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Sky High Pit | TX | | | 1/2011 | | Operator | | | 104 | (a) | | | 224 | | | | — | | | | — | |
| Star Pit #1 | WY | | | 3/2011 | | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Star Pit #1 | WY | | | 3/2011 | | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Star Pit #1 | WY | | | 4/2011 | | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Star Pit #1 | WY | | | 4/2011 | | Operator | | | 104 | (a) | | | 100 | | | | — | | | | — | |
| Star Pit #1 | WY | 4/2011 | | Operator | 104(a) | 100 | | — | | — | |
| VR Pit | WY | 11/2010 | | Operator | 104(a) | 100 | | — | | — | |
| * | Assessments may not have yet been proposed for citations issued during the period for which the data is reported. |
| ** | Results of citations contested will be reported as one of the following: Vacated – the citation was dropped; Reduced – the severity of the violation and/or the proposed assessment amount was reduced; or No Change – the citation was enforced as issued. |
| *** | Contest initiated during the three months ended September 30, 2011. |
ITEM 6. EXHIBITS
See the index to exhibits immediately preceding the exhibits filed with this report.
SIGNATURES
Pursuant to the requirements of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| | | MDU RESOURCES GROUP, INC. |
| | | | |
| | | | |
| | | | |
DATE: November 4, 2011 | | 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 INDEX
Exhibit No.
| +10(a) | MDU Resources Group, Inc. 401(k) Retirement Plan, as restated March 1, 2011 |
| | |
| +10(b) | Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated September 9, 2011 |
| | |
| 12 | Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends |
| | |
| 31(a) | Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
| | |
| 31(b) | Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
| | |
| 32 | Certification of Chief Executive Officer and Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
| | |
| 101 | The following materials from MDU Resources Group, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Cash Flows and (iv) the Notes to Consolidated Financial Statements, tagged in summary and detail |
+ Management contract, compensatory plan or arrangement.
MDU Resources Group, Inc. agrees to furnish to the SEC upon request any instrument with respect to long-term debt that MDU Resources Group, Inc. has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.
