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 27, 2010: 188,255,348 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 products and 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 14.
MDU RESOURCES GROUP, INC.
The accompanying notes are an integral part of these consolidated financial statements.
MDU RESOURCES GROUP, INC.
The accompanying notes are an integral part of these consolidated financial statements.
MDU RESOURCES GROUP, INC.
The accompanying notes are an integral part of these consolidated financial statements.
MDU RESOURCES GROUP, INC.
In October 2010, Fidelity signed an agreement to sell a 25 percent working interest in its approximately 88,000 net acres in the emerging Niobrara oil shale play in southeastern Wyoming. The transaction is expected to be completed in early December, when all conditions precedent to close the transaction are satisfied.
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 and the issuance from time to time of debt and equity securities. In the event that access to the commercial paper markets were to become unavailable, the Company may need to borrow under its credit agreements. For more information on the Company’s net capital expenditures, see Liquidity and Capital Commitments.
The key strategies for each of the Company’s business segments and certain related business challenges are summarized below. For a summary of the Company's business segments, see Note 14.
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. This segment continuously seeks opportunities to expand through strategic acquisitions.
Challenges This segment operates in highly competitive markets with many jobs subject to competitive bidding. Maintenance of effective operational and cost controls, retention of key personnel, managing through downturns in the economy and effective management of working capital are ongoing challenges.
Pipeline and Energy Services
Strategy Utilize the segment’s existing expertise in energy infrastructure and related services to increase market share and profitability through optimization of existing operations, internal growth, and acquisitions of energy-related assets and companies. Incremental and new growth opportunities include: access to new sources of natural gas for storage, gathering and transportation services; expansion of existing gathering, transmission and storage facilities; expansion of related energy services; and incremental expansion of pipeline capacity to allow customers access to more liquid and higher-priced markets.
Challenges Challenges for this segment include: energy price volatility; natural gas basis differentials; regulatory requirements; recruitment and retention of a skilled workforce; and competition from other natural gas pipeline and 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 increase both production and reserves over the long term so as to generate competitive returns on investment.
Challenges Volatility in natural gas and oil prices; ongoing environmental litigation and administrative proceedings; timely receipt of necessary permits and approvals; recruitment and retention of a skilled workforce; availability of drilling rigs, materials, auxiliary equipment and industry-related field services, and inflationary pressure on development and operating costs; 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 al lows 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 lowered margins. Delays in the 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 Part II, Item 1A – Risk Factors, as well as Part I, Item 1A – Risk Factors in the 2009 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, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Dollars in millions, where applicable) | |
| Electric | | $ | 11.3 | | | $ | 10.1 | | | $ | 22.1 | | | $ | 18.5 | |
| Natural gas distribution | | | (10.1 | ) | | | (9.3 | ) | | | 13.4 | | | | 9.8 | |
| Construction services | | | 6.0 | | | | 7.3 | | | | 9.0 | | | | 22.9 | |
| Pipeline and energy services | | | (7.4 | ) | | | 10.6 | | | | 10.9 | | | | 27.9 | |
| Natural gas and oil production | | | 18.7 | | | | 24.4 | | | | 65.0 | | | | (328.2 | ) |
| Construction materials and contracting | | | 40.3 | | | | 47.5 | | | | 25.8 | | | | 47.8 | |
| Other | | | 2.0 | | | | 1.8 | | | | 5.0 | | | | 4.9 | |
| Earnings (loss) on common stock | | $ | 60.8 | | | $ | 92.4 | | | $ | 151.2 | | | $ | (196.4 | ) |
| Earnings (loss) per common share – basic | | $ | .32 | | | $ | .50 | | | $ | .80 | | | $ | (1.07 | ) |
| Earnings (loss) per common share – diluted | | $ | .32 | | | $ | .50 | | | $ | .80 | | | $ | (1.07 | ) |
| Return on average common equity for the 12 months ended | | | | | | | | | | | 8.6 | % | | | (8.1 | )% |
Three Months Ended September 30, 2010 and 2009 Consolidated earnings for the quarter ended September 30, 2010, decreased $31.6 million from the comparable prior period largely due to:
| · | Higher operation and maintenance expense, primarily due to a natural gas gathering arbitration charge of $16.5 million (after tax) at the pipeline and energy services business |
| · | Lower liquid asphalt oil margins, as well as lower asphalt and ready-mixed concrete margins and volumes, partially offset by lower selling, general and administrative expense at the construction materials and contracting business |
| · | Lower average realized natural gas prices, increased depreciation, depletion and amortization expense, decreased natural gas production, as well as higher lease operating expenses, partially offset by higher average realized oil prices and increased oil production at the natural gas and oil production business |
Nine Months Ended September 30, 2010 and 2009 Consolidated earnings for the nine months ended September 30, 2010, increased $347.6 million primarily due to:
| · | Absence of the 2009 noncash write-down of natural gas and oil properties of $384.4 million (after tax), higher average realized oil prices and increased oil production, partially offset by lower average realized natural gas prices and decreased natural gas production at the natural gas and oil production business |
Partially offsetting this increase were:
| · | Lower liquid asphalt oil, ready-mixed concrete and asphalt margins and volumes, decreased construction margins, as well as lower aggregate volumes, partially offset by lower selling, general and administrative expense at the construction materials and contracting segment |
| · | Higher operation and maintenance expense, primarily due to a natural gas gathering arbitration charge of $16.5 million (after tax) and lower gathering volumes, partially offset by higher storage services revenue at the pipeline and energy services business |
| · | Lower construction workloads and margins in the Southwest and Central regions, partially offset by lower general and administrative expense and higher construction workloads and margins in the Mountain region at the construction services business |
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, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Dollars in millions, where applicable) | |
| Operating revenues | | $ | 60.0 | | | $ | 51.9 | | | $ | 155.3 | | | $ | 147.7 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Fuel and purchased power | | | 15.3 | | | | 15.2 | | | | 45.3 | | | | 49.1 | |
| Operation and maintenance | | | 15.7 | | | | 13.8 | | | | 47.0 | | | | 45.3 | |
| Depreciation, depletion and amortization | | | 7.6 | | | | 6.1 | | | | 19.5 | | | | 18.2 | |
| Taxes, other than income | | | 2.2 | | | | 2.2 | | | | 7.0 | | | | 7.0 | |
| | | | 40.8 | | | | 37.3 | | | | 118.8 | | | | 119.6 | |
| Operating income | | | 19.2 | | | | 14.6 | | | | 36.5 | | | | 28.1 | |
| Earnings | | $ | 11.3 | | | $ | 10.1 | | | $ | 22.1 | | | $ | 18.5 | |
| Retail sales (million kWh) | | | 692.0 | | | | 655.0 | | | | 2,057.0 | | | | 1,975.2 | |
| Sales for resale (million kWh) | | | 13.8 | | | | 11.7 | | | | 51.1 | | | | 44.1 | |
| Average cost of fuel and purchased power per kWh | | $ | .021 | | | $ | .022 | | | $ | .021 | | | $ | .023 | |
Three Months Ended September 30, 2010 and 2009 Electric earnings increased $1.2 million (11 percent) due to:
| · | Higher electric retail sales margins, primarily due to implementation of higher rates in Wyoming, as well as higher interim rates in North Dakota |
| · | Higher retail sales volumes of 6 percent, primarily to commercial and residential customers |
Partially offsetting these increases were:
| · | Lower other income of $1.4 million (after tax), primarily allowance for funds used during construction related to electric generation projects, which were placed in service in 2010 |
| · | Higher operation and maintenance expense of $1.1 million (after tax), primarily higher contract services due to storm damage; as well as expenses at Wygen III, which commenced operation in the second quarter of 2010 |
| · | Increased depreciation, depletion and amortization expense of $900,000 (after tax), including the effects of higher property, plant and equipment balances |
| · | Higher net interest expense of $700,000 (after tax), resulting from lower capitalized interest and higher average borrowings |
Nine Months Ended September 30, 2010 and 2009 Electric earnings increased $3.6 million (20 percent) due to increased electric retail sales margins and volumes, as previously discussed.
Partially offsetting these increases were:
| · | Higher operation and maintenance expense of $1.0 million (after tax), primarily increased materials expense and higher contract services |
| · | Higher net interest expense of $900,000 (after tax), resulting from higher average borrowings |
| · | Increased depreciation, depletion and amortization expense of $700,000 (after tax), as previously discussed |
Natural Gas Distribution
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Dollars in millions, where applicable) | |
| Operating revenues | | $ | 94.3 | | | $ | 97.4 | | | $ | 603.5 | | | $ | 744.8 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Purchased natural gas sold | | | 50.1 | | | | 55.6 | | | | 394.3 | | | | 529.0 | |
| Operation and maintenance | | | 35.7 | | | | 31.6 | | | | 102.8 | | | | 105.3 | |
| Depreciation, depletion and amortization | | | 10.8 | | | | 10.8 | | | | 32.1 | | | | 32.1 | |
| Taxes, other than income | | | 7.5 | | | | 7.3 | | | | 34.5 | | | | 41.5 | |
| | | | 104.1 | | | | 105.3 | | | | 563.7 | | | | 707.9 | |
| Operating income (loss) | | | (9.8 | ) | | | (7.9 | ) | | | 39.8 | | | | 36.9 | |
| Earnings (loss) | | $ | (10.1 | ) | | $ | (9.3 | ) | | $ | 13.4 | | | $ | 9.8 | |
| Volumes (MMdk): | | | | | | | | | | | | | | | | |
| Sales | | | 7.9 | | | | 7.5 | | | | 61.6 | | | | 65.2 | |
| Transportation | | | 35.4 | | | | 38.2 | | | | 98.7 | | | | 95.6 | |
| Total throughput | | | 43.3 | | | | 45.7 | | | | 160.3 | | | | 160.8 | |
| Degree days (% of normal)* | | | | | | | | | | | | | | | | |
| Montana-Dakota | | | 69 | % | | | 30 | % | | | 97 | % | | | 103 | % |
| Cascade | | | 109 | % | | | 80 | % | | | 96 | % | | | 105 | % |
| Intermountain | | | 105 | % | | | 103 | % | | | 103 | % | | | 104 | % |
| Average cost of natural gas, including transportation, per dk | | $ | 6.34 | | | $ | 7.39 | | | $ | 6.40 | | | $ | 8.11 | |
*Degree days are a measure of the daily temperature-related demand for energy for heating. | |
Three Months Ended September 30, 2010 and 2009 The natural gas distribution business experienced a seasonal loss of $10.1 million in the third quarter of 2010 compared to a loss of $9.3 million in the third quarter of 2009. The increase in the seasonal loss is due to:
| · | Higher operation and maintenance expense of $1.1 million (after tax), largely associated with operational integration costs, partially offset by lower bad debt expense |
| · | Decreased retail sales margins, primarily due to weather normalization and conservation adjustments, partially offset by increased retail sales volumes, largely resulting from colder weather than last year in the Northwest |
Partially offsetting these increases were higher nonregulated energy-related services of $500,000 (after tax).
Nine Months Ended September 30, 2010 and 2009 Earnings at the natural gas distribution business increased $3.6 million (36 percent) due to:
| · | Lower operation and maintenance expense of $2.0 million (after tax), largely lower bad debt expense and benefit-related costs |
| · | Lower net interest expense, primarily due to lower average borrowings and higher capitalized interest |
| · | Increased transportation volumes of $1.0 million (after tax), primarily industrial customers |
| · | Higher other income of $900,000 (after tax), primarily allowance for funds used during construction |
| · | Higher nonregulated energy-related services of $800,000 (after tax) |
Partially offsetting these increases were decreased retail sales volumes, largely resulting from warmer weather than last year in the Northwest.
Construction Services
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (In millions) | |
| Operating revenues | | $ | 210.5 | | | $ | 186.4 | | | $ | 551.8 | | | $ | 651.9 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Operation and maintenance | | | 191.1 | | | | 166.1 | | | | 506.1 | | | | 582.5 | |
| Depreciation, depletion and amortization | | | 2.9 | | | | 3.2 | | | | 9.2 | | | | 10.0 | |
| Taxes, other than income | | | 5.8 | | | | 5.2 | | | | 18.4 | | | | 21.1 | |
| | | | 199.8 | | | | 174.5 | | | | 533.7 | | | | 613.6 | |
| Operating income | | | 10.7 | | | | 11.9 | | | | 18.1 | | | | 38.3 | |
| Earnings | | $ | 6.0 | | | $ | 7.3 | | | $ | 9.0 | | | $ | 22.9 | |
Three Months Ended September 30, 2010 and 2009 Construction services earnings decreased $1.3 million (18 percent) due to lower construction workloads and margins in the Southwest region.
Partially offsetting this decrease were:
| · | Higher construction workloads and margins in the Western and Mountain regions |
| · | Lower general and administrative expense of $1.3 million (after tax), largely lower payroll-related costs and lower bad debt expense |
Nine Months Ended September 30, 2010 and 2009 Construction services earnings decreased $13.9 million (60 percent) due to lower construction workloads and margins in the Southwest and Central regions.
Partially offsetting this decrease were:
| · | Lower general and administrative expense of $7.8 million (after tax), as previously discussed |
| · | Higher construction workloads and margins in the Mountain region |
Pipeline and Energy Services
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Dollars in millions) | |
| Operating revenues | | $ | 81.2 | | | $ | 68.7 | | | $ | 250.3 | | | $ | 221.8 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Purchased natural gas sold | | | 36.8 | | | | 25.7 | | | | 119.5 | | | | 100.0 | |
| Operation and maintenance | | | 44.2 | * | | | 14.0 | | | | 77.2 | * | | | 42.8 | |
| Depreciation, depletion and amortization | | | 6.5 | | | | 6.6 | | | | 19.4 | | | | 18.8 | |
| Taxes, other than income | | | 3.2 | | | | 3.0 | | | | 9.5 | | | | 8.9 | |
| | | | 90.7 | | | | 49.3 | | | | 225.6 | | | | 170.5 | |
| Operating income (loss) | | | (9.5 | ) | | | 19.4 | | | | 24.7 | | | �� | 51.3 | |
| Earnings (loss) | | $ | (7.4 | ) | | $ | 10.6 | | | $ | 10.9 | | | $ | 27.9 | |
| Transportation volumes (MMdk) | | | 33.6 | | | | 41.2 | | | | 108.4 | | | | 122.2 | |
| Gathering volumes (MMdk) | | | 19.3 | | | | 22.7 | | | | 57.7 | | | | 71.3 | |
| Customer natural gas storage balance (MMdk): | | | | | | | | | | | | | | | | |
| Beginning balance** | | | 64.2 | | | | 41.6 | | | | 61.5 | | | | 30.6 | |
| Net injection | | | 9.6 | | | | 19.4 | | | | 12.3 | | | | 30.4 | |
| Ending balance | | | 73.8 | | | | 61.0 | | | | 73.8 | | | | 61.0 | |
* Reflects a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax). ** As of the beginning of the applicable period. | |
Three Months Ended September 30, 2010 and 2009 Pipeline and energy services recognized a loss of $7.4 million compared to earnings of $10.6 million for the comparable prior period due to:
| · | Higher operation and maintenance expense, primarily due to a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax), as discussed in Note 18 and higher legal-related costs |
| · | Decreased transportation volumes of $900,000 (after tax), largely volumes transported to storage |
| · | Lower gathering volumes of $900,000 (after tax) |
Partially offsetting the earnings decrease was higher storage services revenue of $1.6 million (after tax), largely higher storage balances.
Nine Months Ended September 30, 2010 and 2009 Pipeline and energy services earnings decreased $17.0 million (61 percent) due to:
| · | Higher operation and maintenance expense, largely resulting from a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax), as previously discussed, as well as the absence of the settlement of the natural gas storage litigation, which lowered expense last year |
| · | Lower gathering volumes of $3.5 million (after tax) |
Partially offsetting these decreases was higher storage services revenue of $5.8 million (after tax), largely higher storage balances.
Natural Gas and Oil Production
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Dollars in millions, where applicable) | |
| Operating revenues: | | | | | | | | | | | | |
| Natural gas | | $ | 54.9 | | | $ | 67.3 | | | $ | 167.7 | | | $ | 218.2 | |
| Oil | | | 52.1 | | | | 42.1 | | | | 157.7 | | | | 102.1 | |
| | | | 107.0 | | | | 109.4 | | | | 325.4 | | | | 320.3 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Operation and maintenance: | | | | | | | | | | | | | | | | |
| Lease operating costs | | | 19.4 | | | | 16.3 | | | | 51.5 | | | | 54.2 | |
| Gathering and transportation | | | 5.9 | | | | 6.1 | | | | 17.6 | | | | 18.3 | |
| Other | | | 7.5 | | | | 7.9 | | | | 24.9 | | | | 29.0 | |
| Depreciation, depletion and amortization | | | 34.1 | | | | 29.1 | | | | 96.4 | | | | 101.9 | |
| Taxes, other than income: | | | | | | | | | | | | | | | | |
| Production and property taxes | | | 8.1 | | | | 8.1 | | | | 26.6 | | | | 21.2 | |
| Other | | | .2 | | | | .1 | | | | .7 | | | | .6 | |
| Write-down of natural gas and oil properties | | | — | | | | — | | | | — | | | | 620.0 | |
| | | | 75.2 | | | | 67.6 | | | | 217.7 | | | | 845.2 | |
| Operating income (loss) | | | 31.8 | | | | 41.8 | | | | 107.7 | | | | (524.9 | ) |
| Earnings (loss) | | $ | 18.7 | | | $ | 24.4 | | | $ | 65.0 | | | $ | (328.2 | ) |
| Production: | | | | | | | | | | | | | | | | |
| Natural gas (MMcf) | | | 12,686 | | | | 13,657 | | | | 37,738 | | | | 43,355 | |
| Oil (MBbls) | | | 835 | | | | 807 | | | | 2,427 | | | | 2,320 | |
| Total Production (MMcf equivalent) | | | 17,696 | | | | 18,502 | | | | 52,298 | | | | 57,277 | |
| Average realized prices (including hedges): | | | | | | | | | | | | | | | | |
| Natural gas (per Mcf) | | $ | 4.33 | | | $ | 4.93 | | | $ | 4.44 | | | $ | 5.03 | |
| Oil (per Bbl) | | $ | 62.41 | | | $ | 52.13 | | | $ | 65.00 | | | $ | 44.00 | |
| Average realized prices (excluding hedges): | | | | | | | | | | | | | | | | |
| Natural gas (per Mcf) | | $ | 3.38 | | | $ | 2.34 | | | $ | 3.74 | | | $ | 2.82 | |
| Oil (per Bbl) | | $ | 62.12 | | | $ | 55.00 | | | $ | 65.21 | | | $ | 45.42 | |
| Average depreciation, depletion and amortization rate, per equivalent Mcf | | $ | 1.84 | | | $ | 1.47 | | | $ | 1.75 | | | $ | 1.69 | |
| Production costs, including taxes, per net equivalent Mcf: | | | | | | | | | | | | | | | | |
| Lease operating costs | | $ | 1.10 | | | $ | .88 | | | $ | .98 | | | $ | .95 | |
| Gathering and transportation | | | .33 | | | | .33 | | | | .34 | | | | .32 | |
| Production and property taxes | | | .46 | | | | .43 | | | | .51 | | | | .37 | |
| | | $ | 1.89 | | | $ | 1.64 | | | $ | 1.83 | | | $ | 1.64 | |
Three Months Ended September 30, 2010 and 2009 Natural gas and oil production earnings decreased $5.7 million (23 percent) due to:
| · | Lower average realized natural gas prices of 12 percent |
| · | Higher depreciation, depletion and amortization expense of $3.1 million (after tax), largely due to higher depletion rates |
| · | Decreased natural gas production of 7 percent, largely related to normal production declines at existing properties, partially offset by production from the Green River Basin properties, which were acquired in April of this year |
| · | Increased lease operating expenses of $2.0 million (after tax) |
Partially offsetting these decreases were:
| · | Higher average realized oil prices of 20 percent |
| · | Increased oil production of 3 percent, largely related to drilling activity in the Bakken area and the previously mentioned Green River Basin properties, partially offset by normal production declines at certain existing properties |
Nine Months Ended September 30, 2010 and 2009 Natural gas and oil production earnings increased $393.2 million due to:
| · | Absence of the 2009 noncash write-down of natural gas and oil properties of $384.4 million (after tax), as discussed in Note 5 |
| · | Higher average realized oil prices of 48 percent |
| · | Increased oil production of 5 percent, as previously discussed |
| · | Lower depreciation, depletion and amortization expense of $3.5 million (after tax), primarily due to decreased combined production |
| · | Lower general and administrative expense of $2.5 million (after tax) |
| · | Decreased lease operating expenses of $1.7 million (after tax) |
Partially offsetting these increases were:
| · | Lower average natural gas prices of 12 percent |
| · | Decreased natural gas production of 13 percent, as previously discussed |
| · | Higher production taxes of $3.4 million (after tax), largely resulting from higher natural gas and oil prices excluding hedges |
Construction Materials and Contracting
| | | Three Months Ended | | | Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Dollars in millions) | |
| Operating revenues | | $ | 612.7 | | | $ | 622.0 | | | $ | 1,124.1 | | | $ | 1,194.9 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Operation and maintenance | | | 513.4 | | | | 506.6 | | | | 976.4 | | | | 1,004.6 | |
| Depreciation, depletion and amortization | | | 22.5 | | | | 23.4 | | | | 67.2 | | | | 71.2 | |
| Taxes, other than income | | | 10.1 | | | | 11.5 | | | | 26.6 | | | | 28.8 | |
| | | | 546.0 | | | | 541.5 | | | | 1,070.2 | | | | 1,104.6 | |
| Operating income | | | 66.7 | | | | 80.5 | | | | 53.9 | | | | 90.3 | |
| Earnings | | $ | 40.3 | | | $ | 47.5 | | | $ | 25.8 | | | $ | 47.8 | |
| Sales (000's): | | | | | | | | | | | | | | | | |
| Aggregates (tons) | | | 8,741 | | | | 9,345 | | | | 17,965 | | | | 19,016 | |
| Asphalt (tons) | | | 3,343 | | | | 3,443 | | | | 5,076 | | | | 5,161 | |
| Ready-mixed concrete (cubic yards) | | | 919 | | | | 1,021 | | | | 2,137 | | | | 2,322 | |
Three Months Ended September 30, 2010 and 2009 Earnings at the construction materials and contracting business decreased $7.2 million (15 percent) due to lower liquid asphalt oil margins, as well as lower asphalt and ready-mixed concrete margins and volumes, which reflects the effects of the economic downturn and competition.
Partially offsetting the decreases was lower selling, general and administrative expense of $3.0 million (after tax).
Nine Months Ended September 30, 2010 and 2009 Construction materials and contracting earnings decreased $22.0 million (46 percent) due to lower liquid asphalt oil, ready-mixed concrete and asphalt margins and volumes, decreased construction margins, as well as lower aggregate volumes, which reflects the effects of the economic downturn and competition.
Partially offsetting the decreases was lower selling, general and administrative expense of $4.2 million (after tax).
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, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (In millions) | |
| Other: | | | | | | | | | | | | |
| Operating revenues | | $ | 2.3 | | | $ | 2.7 | | | $ | 6.8 | | | $ | 8.1 | |
| Operation and maintenance | | | 1.9 | | | | 2.3 | | | | 5.6 | | | | 7.5 | |
| Depreciation, depletion and amortization | | | .4 | | | | .3 | | | | 1.2 | | | | 1.0 | |
| Taxes, other than income | | | .1 | | | | .1 | | | | .1 | | | | .2 | |
| Intersegment transactions: | | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 42.1 | | | $ | 30.6 | | | $ | 150.1 | | | $ | 129.5 | |
| Purchased natural gas sold | | | 35.7 | | | | 23.7 | | | | 131.4 | | | | 108.5 | |
| Operation and maintenance | | | 6.4 | | | | 6.9 | | | | 18.7 | | | | 21.0 | |
For further information on intersegment eliminations, see Note 14.
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 2009 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 2010, diluted, are projected in the range of $1.10 to $1.25, excluding the third quarter $16.5 million after-tax arbitration charge and a potential gain on the sale of the Brazilian Transmission Lines, which is expected to be completed this year. (Including the arbitration charge and the potential gain on the pending Brazilian Transmission Lines sale, guidance for 2010 is also $1.10 to $1.25 per common share.) |
| · | 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
| · | The Company continues to realize efficiencies and enhanced service levels through its efforts to standardize operations, share services and consolidate back-office functions among its four utility companies. |
| · | In April 2010, the Company filed an application with the NDPSC for an electric rate increase, as discussed in Note 17. |
| · | In August 2010, the Company filed an application with the MTPSC for an electric rate increase, as discussed in Note 17. |
| · | The Company is developing a landfill methane gas recovery project in Billings, Montana to supplement the Company’s gas supply portfolio. The project is expected to begin production in December of 2010, and upon total phase-in to recover up to 2,500 dk per day. |
| · | The Company is analyzing potential projects for accommodating load growth and replacing purchased power contracts with company-owned generation. The Company is reviewing the construction of natural gas-fired combustion and wind generation. |
| · | The Company is pursuing opportunities associated with the potential development of 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 metropolitan areas. The Company has signed 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 being built by enXco for Xcel Energy. The project will total approximately $20 million and will include substation upgrades. Pending regulatory approval, construction is expected to begin in 2011. Customers will not bear any of the costs associated with the project as costs will be recovered through an approved interconnect tariff. |
| · | The South Dakota Board of Minerals and Environment has approved rules implementing the South Dakota Regional Haze Program that will require the Big Stone Station to install and operate a best available retrofit technology (BART) air quality control system to reduce emissions of particulate matter, sulfur dioxide, and nitrogen oxides as early as January 2016. The Company’s share of the cost of this air quality control system will likely exceed $100 million. The Company will assess alternative responses to the rules including installation of the pollution control equipment, retirement of the plant, and repowering it with other fuels. The Company intends to seek recovery of costs related to the above matter in electric rates charged to customers. |
Construction services
| · | Work backlog as of September 30, 2010, was approximately $317 million, $53 million higher than the September 30, 2009, backlog of $264 million. The backlog includes a variety of projects such as substation and line construction, solar and other commercial, industrial and institutional projects. |
| · | The Company anticipates margins in 2010 to be lower than 2009 levels. |
| · | The Company is pursuing expansion in high-voltage transmission and substation construction, renewable resource construction and military installation services. In late 2009, the Company was awarded the engineering, procurement and construction contract to build the 214-mile Montana |
| | Alberta Tie Line between Lethbridge, Alberta and Great Falls, Montana. In late June 2010, the Company received a notice to proceed with construction on the project. |
| · | The Company continues to focus on costs and efficiencies to enhance margins. Selling, general and administrative expenses are down 30 percent for the trailing 12 months through September 30, 2010, compared to the annual expenses in 2008, the peak earnings year for this segment. |
| · | With its highly skilled technical workforce, this group is prepared to take advantage of government stimulus spending on transmission infrastructure. |
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 Shale of North Dakota and eastern Montana. Ongoing energy development is expected to have many direct and indirect benefits to its business. |
| · | The Company continues to pursue the expansion of its existing natural gas pipeline capacity by 30,000 Mcf per day in the Bakken production area in northwestern North Dakota. This expansion project is targeted for late 2011. |
| · | The Company has three natural gas storage fields including the largest storage field in North America located near Baker, Montana. The Company continues to see strong interest in its storage services and is pursuing a project to increase its firm deliverability from the Baker Storage field by 125,000 Mcf per day and related transportation capacity. The Company has received commitment on approximately 30 percent of the total potential project and is moving forward on that phase with a projected in-service date of November 2011, subject to regulatory approval. |
Natural gas and oil production
| · | The Company expects to spend approximately $365 million in capital expenditures in 2010, excluding property sales. This is approximately double the level of capital invested in 2009 and reflects further exploitation of existing properties, leasehold acquisitions in the Bakken and Niobrara oil shale plays and the acquisition of producing natural gas properties located in the Green River Basin. The capital expenditures forecasted reflect a shift from certain natural gas development activities to oil shale leasehold acquisitions, which will affect short-term production growth. |
| · | In 2010, the Company acquired more than 50,000 net exploratory acres in the North Dakota Bakken area, bringing its total acreage position in this oil play to more than 67,000 net acres. The newly acquired acreage, the Heart River project, is located in Stark County. Plans include drilling three exploratory wells this year to evaluate this acreage targeting the Three Forks formation. Initial lease terms extend up to five years and include renewal options available to the Company. |
| · | Also in 2010, the Company acquired approximately 88,000 net exploratory acres in the emerging Niobrara oil play in Laramie and Goshen Counties in southeastern Wyoming. In October 2010, an agreement was signed to sell a 25 percent working interest in this acreage, reducing the Company’s portfolio risk and capital requirements, bringing its acreage position to approximately 66,000 net acres. The Company plans to begin drilling exploratory wells in the area in 2011. Lease terms are generally five years with most having five-year renewal options available to the Company. |
| · | On a combined basis for the Heart River project and Niobrara areas, a potential of over 175 total drill sites exist assuming 640-acre spacing. Although these areas are both emerging plays, early results by other producers in these areas appear promising. |
| · | Because of reduced capital spending in 2009 and the redirecting of forecasted 2010 capital expenditures, along with delays in obtaining well completion/frac services, the Company expects its 2010 combined natural gas and oil production to be approximately 6 percent below 2009 levels. |
| · | Earnings guidance reflects estimated natural gas prices for November and December as follows: |
| Index* | Price Per Mcf |
| Ventura | $3.50 to $4.00 |
| NYMEX | $3.75 to $4.25 |
| CIG | $3.25 to $3.75 |
| * Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system. |
| · | Earnings guidance reflects estimated NYMEX crude oil prices for November and December in the range of $75 to $80 per barrel. |
| · | For the last three months of 2010, the Company has hedged approximately 50 percent to 55 percent of its estimated natural gas production and 40 percent to 45 percent of its estimated oil production. For 2011, the Company has hedged 15 percent to 20 percent of its estimated natural gas production and 45 percent to 50 percent of its estimated oil production. For 2012, the Company has hedged 5 percent to 10 percent of its estimated natural gas production and 15 percent to 20 percent of its estimated oil production. The hedges that are in place as of October 27, 2010, are summarized in the following chart: |
| Commodity | Type | Index | Period Outstanding | Forward Notional Volume (MMBtu/Bbl) | Price (Per MMBtu/Bbl) |
| Natural Gas | Swap | HSC | 10/10 - 12/10 | 404,800 | $8.08 |
| Natural Gas | Swap | NYMEX | 10/10 - 12/10 | 920,000 | $6.18 |
| Natural Gas | Swap | NYMEX | 10/10 - 12/10 | 460,000 | $6.40 |
| Natural Gas | Collar | NYMEX | 10/10 - 12/10 | 460,000 | $5.63-$6.00 |
| Natural Gas | Swap | NYMEX | 10/10 - 12/10 | 460,000 | $5.855 |
| Natural Gas | Swap | NYMEX | 10/10 - 12/10 | 460,000 | $6.045 |
| Natural Gas | Swap | NYMEX | 10/10 - 12/10 | 460,000 | $6.045 |
| Natural Gas | Swap | CIG | 10/10 - 12/10 | 920,000 | $5.03 |
| Natural Gas | Swap | HSC | 10/10 | 62,000 | $5.57 |
| Natural Gas | Swap | NYMEX | 10/10 | 248,000 | $5.645 |
| Natural Gas | Swap | Ventura | 10/10 - 12/10 | 460,000 | $5.95 |
| Natural Gas | Swap | NYMEX | 10/10 - 12/10 | 1,012,000 | $5.54 |
| Natural Gas | Collar | NYMEX | 10/10 - 3/11 | 910,000 | $5.62-$6.50 |
| Natural Gas | Swap | HSC | 1/11 - 12/11 | 1,350,500 | $8.00 |
| Natural Gas | Swap | NYMEX | 1/11 - 12/11 | 4,015,000 | $6.1027 |
| Natural Gas | Swap | NYMEX | 1/11 - 12/11 | 3,650,000 | $5.4975 |
| Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 3,477,000 | $6.27 |
| Crude Oil | Collar | NYMEX | 10/10 - 12/10 | 92,000 | $60.00-$75.00 |
| Crude Oil | Swap | NYMEX | 10/10 - 12/10 | 92,000 | $73.20 |
| Crude Oil | Collar | NYMEX | 10/10 - 12/10 | 92,000 | $70.00-$86.00 |
| Crude Oil | Swap | NYMEX | 10/10 - 12/10 | 92,000 | $83.05 |
| Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 547,500 | $80.00-$94.00 |
| Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 365,000 | $80.00-$89.00 |
| Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 182,500 | $77.00-$86.45 |
| Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 182,500 | $75.00-$88.00 |
| Crude Oil | Swap | NYMEX | 1/11 - 12/11 | 365,000 | $81.35 |
| Crude Oil | Swap | NYMEX | 1/11 - 12/11 | 182,500 | $85.85 |
| Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 366,000 | $80.00-$87.80 |
| Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 366,000 | $80.00-$94.50 |
| Natural Gas | Basis Swap | Ventura | 10/10 - 12/10 | 920,000 | $0.25 |
| Natural Gas | Basis Swap | Ventura | 10/10 - 12/10 | 230,000 | $0.245 |
| Natural Gas | Basis Swap | Ventura | 10/10 - 12/10 | 1,150,000 | $0.25 |
| Natural Gas | Basis Swap | Ventura | 10/10 - 12/10 | 460,000 | $0.225 |
| Natural Gas | Basis Swap | Ventura | 10/10 - 12/10 | 230,000 | $0.23 |
| Natural Gas | Basis Swap | Ventura | 10/10 - 12/10 | 690,000 | $0.23 |
| Natural Gas | Basis Swap | CIG | 10/10 - 12/10 | 1,012,000 | $0.385 |
| Natural Gas | Basis Swap | Ventura | 1/11 - 3/11 | 450,000 | $0.135 |
| Natural Gas | Basis Swap | CIG | 1/11 - 12/11 | 4,015,000 | $0.395 |
| Natural Gas | Basis Swap | Ventura | 1/11 - 12/11 | 3,650,000 | $0.15 |
| Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 2,745,000 | $0.405 |
| Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 732,000 | $0.41 |
Notes: · Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system; HSC is the Houston Ship Channel hub in southeast Texas which connects to several pipelines. · For all basis swaps, Index prices are below NYMEX prices and are reported as a positive amount in the Price column. |
Construction materials and contracting
| · | Work backlog as of September 30, 2010, was approximately $464 million, with 94 percent of construction backlog being public work and private representing 6 percent. In the Company’s peak earnings year of 2006, private backlog represented 40 percent of construction backlog. Total backlog at September 30, 2009, was $494 million. |
| · | Examples of projects in work backlog include several highway paving projects, airports, bridge work, reclamation and an L.A. harbor deepening project. |
| · | Federal transportation stimulus of $7.9 billion was directed to states where the Company operates. Of that amount, 52 percent was spent as of early October 2010, with the majority of the remaining $3.8 billion to be spent during the remainder of 2010 and 2011. |
| · | The Company continues to pursue work related to energy projects, such as wind towers, transmission projects, geothermal and refineries. It is also pursuing opportunities for expansion of its existing business lines including initiatives aimed at capturing additional market share and expansion into new markets. |
| · | The Company has a strong emphasis on operational efficiencies and cost reduction. Selling, general and administrative expenses are down 34 percent for the trailing 12 months through September 30, 2010, compared to the annual expenses in 2006, the peak earnings year for this segment. |
| · | As a result of the economic downturn, the Company expects overall volumes and margins to be lower in 2010 compared to 2009, at which time liquid asphalt earnings were at record levels. |
| · | As the country’s 6th largest sand and gravel producer, the Company will continue to strategically manage its 1.1 billion tons of aggregate reserves in all its markets, as well as take further advantage of being vertically integrated. |
| · | Of the five labor contracts that Knife River was negotiating, as reported in Items 1 and 2 – Business and Properties – General in the 2009 Annual Report, four have been ratified. The one remaining contract is still in negotiations. |
NEW ACCOUNTING STANDARDS
For information regarding new accounting standards, see Note 8, which is incorporated by reference.
CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES
The Company’s critical accounting policies involving significant estimates include impairment testing of long-lived assets and intangibles, impairment testing of natural gas and oil production properties, revenue recognition, purchase accounting, asset retirement obligations, 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 2009 Annual Report. For more information on critical accounting policies involving significant estimates, see Part II, Item 7 in the 2009 Annual Report.
LIQUIDITY AND CAPITAL COMMITMENTS
At September 30, 2010, the Company had cash and cash equivalents of $36.3 million and available capacity of $627.3 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 2010 decreased $257.7 million from the comparable period in 2009, largely due to higher working capital requirements of $242.8 million, including decreased cash provided from receivables largely at the construction services business; lower cash provided from net natural gas costs recoverable through rate adjustments at the natural gas distribution business; and increased cash used for income taxes.
Investing activities Cash flows used in investing activities in the first nine months of 2010 increased $96.2 million from the comparable period in 2009 due to an increase in acquisition-related capital expenditures of $100.1 million, largely due to the acquisition of natural gas properties located in the Green River Basin.
Financing activities Cash flows used in financing activities in the first nine months of 2010 decreased $205.9 million from the comparable period in 2009, largely due to lower repayment of short-term borrowings and long-term debt of $94.8 million and $245.2 million, respectively, offset in part by lower issuance of long-term debt of $87.2 million and lower issuance of common stock of $48.7 million.
Defined benefit pension plans
There were no material changes to the Company’s qualified noncontributory defined benefit pension plans from those reported in the 2009 Annual Report. For further information, see Note 16 and Part II, Item 7 in the 2009 Annual Report.
Capital expenditures
Net capital expenditures for the first nine months of 2010 were $438.6 million and are estimated to be approximately $555 million for 2010. Estimated capital expenditures include:
| · | The acquisition of producing natural gas properties located in the Green River Basin in southwest Wyoming |
| · | Routine equipment maintenance and replacements |
| · | Buildings, land and building improvements |
| · | Pipeline and gathering projects |
| · | Further development of existing properties, leasehold acquisitions and proceeds from leasehold sales 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 2010 capital expenditures referred to previously. It is anticipated that all of the funds required for capital expenditures will be met from
various sources, including internally generated funds; the Company's credit facilities, as described below; and through the issuance of long-term debt and the Company's equity securities.
Capital resources
Certain debt instruments of the Company and its subsidiaries, including those discussed below, contain restrictive covenants and cross-default provisions. In order to borrow under the respective credit agreements, the Company and its subsidiaries must be in compliance with the applicable covenants and certain other conditions, all of which the Company and its subsidiaries, as applicable, were in compliance with at September 30, 2010. 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 2009 Annual Report.
The following table summarizes the outstanding credit facilities of the Company and its subsidiaries at September 30, 2010:
| Company | Facility | | | Facility Limit | | | | Amount Outstanding | | | | Letters of Credit | | | Expiration Date | |
| (Dollars in millions) |
| MDU Resources Group, Inc. | Commercial paper/Revolving credit agreement | (a) | | $ | 125.0 | | | | $ | 4.7 | | (b) | | $ | — | | | 6/21/11 | |
| 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) | | $ | 17.8 | | | | $ | — | | | 8/11/13 | |
| Centennial Energy Holdings, Inc. | Commercial paper/Revolving credit agreement | (g) | | $ | 400.0 | | | | $ | — | | (b) | | $ | 25.8 | | (d) | 12/13/12 | |
| Williston Basin Interstate Pipeline Company | Uncommitted long-term private shelf agreement | | | $ | 125.0 | | | | $ | 87.5 | | | | $ | — | | | 12/23/11 | (h) |
| (a) | The $125 million commercial paper program is supported by a revolving credit agreement with various banks totaling $125 million (provisions allow for increased borrowings, at the option of the Company on stated conditions, up to a maximum of $150 million). There were no amounts outstanding under the credit agreement. |
| (b) | Amount outstanding under commercial paper program. |
| (c) | Certain provisions allow for increased borrowings, up to a maximum of $75 million. |
| (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. |
In order to maintain the Company’s and Centennial’s respective commercial paper programs in the amounts indicated above, both the Company and Centennial must have revolving credit agreements in place at least equal to the amount of their commercial paper programs. While the amount of commercial paper outstanding does not reduce available capacity under the respective revolving credit agreements, the Company and Centennial do not issue commercial paper in an aggregate amount exceeding the available capacity under their credit agreements.
The following includes information related to the above table.
MDU Resources Group, Inc. The Company’s revolving credit agreement supports its commercial paper program. The commercial paper borrowings at September 30, 2010, are classified as short-term 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 4.0 times for the 12 months ended September 30, 2010. Due to the $384.4 million after-tax noncash write-down of natural gas and oil properties in the first quarter of 2009, earnings were insufficient by $228.7 million to cover fixed charges for the 12 months ended December 31, 2009. If the $384.4 million after-tax noncash write-down is excluded, the coverage of fixed charges including preferred stock dividends would have been 4.6 times for the 12 months ended December 31, 2009. Common stockholders' equity as a percent of total capitalization was 64 percent and 63 percent at September 30, 2010 and December 31, 2009, respectively. This ratio is calculat ed 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 coverage of fixed charges including preferred stock dividends, that excludes the effect of the after-tax noncash write-down of natural gas and oil properties is a non-GAAP financial measure. The Company believes that this non-GAAP financial measure is useful because the write-down excluded is not indicative of the Company’s cash flows available to meet its fixed charges obligations. The presentation of this additional information is not meant to be considered a substitute for financial measures prepared in accordance with GAAP.
In September 2008, the Company entered into a Sales Agency Financing Agreement with Wells Fargo Securities, LLC with respect to the issuance and sale of up to 5 million shares of the Company’s common stock. The common stock may be offered for sale, from time to time, in accordance with the terms and conditions of the agreement, which terminates on May 28, 2011. Proceeds from the sale of shares of common stock under the agreement have been and are expected to be used for corporate development purposes and other general corporate purposes. The Company did not issue any shares of stock in 2010 under the Sales Agency Financing Agreement. The Company had previously issued a total of approximately 3.2 million shares of stock under the Sales Agency Financing Agreement through September 30, 2010, res ulting in total net proceeds of $63.1 million.
The Company currently has authorization to issue and sell up to $1.0 billion of securities pursuant to a registration statement on file with the SEC. The Company may sell all or a portion of such securities if warranted by market conditions and the Company's capital requirements. Any offer and sale of such securities will be made only by means of a prospectus meeting the requirements of the Securities Act and the rules and regulations thereunder.
Intermountain Gas Company On August 11, 2010, Intermountain entered into a new revolving credit agreement. The credit agreement contains customary covenants and provisions, including covenants of Intermountain not to permit, as of the end of any fiscal quarter, the ratio of funded debt to total capitalization (determined on a consolidated basis) 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.
Intermountain's credit agreement contains cross-default provisions. These provisions state that if (i) Intermountain fails to make any payment with respect to any indebtedness or guarantee in excess of $10 million, (ii) any other event occurs that would permit the holders of indebtedness or the beneficiaries of guarantees to become payable, or (iii) certain conditions result in an early termination date under any swap contract that is in excess of $10 million, then Intermountain shall be in default under the revolving credit agreement.
Centennial Energy Holdings, Inc. Centennial’s revolving credit agreement supports its commercial paper program. The Centennial commercial paper borrowings are classified as long-term debt as Centennial intends to refinance these borrowings on a long-term basis through continued Centennial commercial paper borrowings. Centennial’s 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 cre dit agreement and may experience an increase in overall interest rates with respect to its cost of borrowings.
Prior to the maturity of the Centennial credit agreement, Centennial expects that it will negotiate the extension or replacement of this agreement, which provides credit support to access the capital markets. In the event Centennial is unable to successfully negotiate this agreement, or in the event the fees on this facility become too expensive, which Centennial does not currently anticipate, it would seek alternative funding.
Off balance sheet arrangements
In connection with the sale of MPX in June 2005 to Petrobras, an indirect wholly owned subsidiary of the Company has agreed to indemnify Petrobras for 49 percent of any losses that Petrobras may incur from certain contingent liabilities specified in the purchase agreement. For further information, see Note 18.
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, purchase commitments and uncertain tax positions from those reported in the 2009 Annual Report.
The Company’s contractual obligations relating to operating leases at September 30, 2010, increased $15.8 million or 13 percent from December 31, 2009. At September 30, 2010, the Company’s contractual obligations related to operating leases totaled $139.8 million. The scheduled commitment amounts (for the twelve months ended September 30, of each year listed) total $27.7 million in 2011; $21.8 million in 2012; $17.9 million in 2013; $11.6 million in 2014; $5.6 million in 2015; and $55.2 million thereafter.
For more information on contractual obligations and commercial commitments, see Part II, Item 7 in the 2009 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 and Intermountain utilize derivative instruments to manage a portion of their regulated natural gas supply portfolio in order to manage fluctuations in the price of natural gas. For more information on derivative instruments and commodity price risk, see Part II, Item 7A in the 2009 Annual Report, and Notes 9 and 12.
The following table summarizes derivative agreements entered into by Fidelity, Cascade and Intermountain as of September 30, 2010. These agreements call for Fidelity to receive fixed prices and pay variable prices, and for Cascade and Intermountain to receive variable prices and pay fixed prices.
| (Forward notional volume and fair value in thousands) | |
| | | | | | | | | | |
| | | Weighted Average Fixed Price (Per MMBtu/Bbl) | | | Forward Notional Volume (MMBtu/Bbl) | | | Fair Value | |
| Fidelity | | | | | | | | | |
| Natural gas swap agreements maturing in 2010 | | $ | 5.94 | | | | 5,867 | | | $ | 12,108 | |
| Natural gas swap agreements maturing in 2011 | | $ | 6.14 | | | | 9,016 | | | $ | 15,399 | |
| Natural gas swap agreement maturing in 2012 | | $ | 6.27 | | | | 3,477 | | | $ | 4,123 | |
| Natural gas basis swap agreements maturing in 2010 | | $ | .27 | | | | 4,692 | | | $ | (962 | ) |
| Natural gas basis swap agreements maturing in 2011 | | $ | .27 | | | | 8,115 | | | $ | 16 | |
| Natural gas basis swap agreements maturing in 2012 | | $ | .41 | | | | 3,477 | | | $ | 136 | |
| Oil swap agreements maturing in 2010 | | $ | 78.13 | | | | 184 | | | $ | (564 | ) |
| Oil swap agreements maturing in 2011 | | $ | 81.35 | | | | 365 | | | $ | (1,266 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Cascade | | | | | | | | | | | | |
| Natural gas swap agreements maturing in 2010 | | $ | 8.24 | | | | 1,644 | | | $ | (7,733 | ) |
| Natural gas swap agreements maturing in 2011 | | $ | 8.10 | | | | 2,270 | | | $ | (9,739 | ) |
| | | | | | | | | | | | | |
| Intermountain | | | | | | | | | | | | |
| Natural gas swap agreement maturing in 2010 | | $ | 4.96 | | | | 419 | | | $ | (641 | ) |
| Natural gas swap agreement maturing in 2011 | | $ | 4.96 | | | | 2,889 | | | $ | (3,107 | ) |
| | | | | | | | | | | | | |
| | | Weighted Average Floor/Ceiling Price (Per MMBtu/Bbl) | | | Forward Notional Volume (MMBtu/Bbl) | | | Fair Value | |
| Fidelity | | | | | | | | | | | | |
| Natural gas collar agreements maturing in 2010 | | | $5.63/$6.25 | | | | 920 | | | $ | 1,566 | |
| Natural gas collar agreement maturing in 2011 | | | $5.62/$6.50 | | | | 450 | | | $ | 604 | |
| Oil collar agreements maturing in 2010 | | | $65.00/$80.50 | | | | 184 | | | $ | (747 | ) |
| Oil collar agreements maturing in 2011 | | | $78.86/$90.64 | | | | 1,278 | | | $ | (557 | ) |
| Oil collar agreements maturing in 2012 | | | $80.00/$87.80 | | | | 366 | | | $ | (1,124 | ) |
| | | | | | | | | | | | | |
| Intermountain | | | | | | | | | | | | |
| Natural gas collar agreement maturing in 2011 | | | $4.25/$4.92 | | | | 963 | | | $ | (352 | ) |
Interest rate risk
There were no material changes to interest rate risk faced by the Company from those reported in the 2009 Annual Report. For more information, see Part II, Item 7A in the 2009 Annual Report.
At September 30, 2010 and 2009, and December 31, 2009, the Company had no outstanding interest rate hedges.
Foreign currency risk
MDU Brasil’s equity method investments in the Brazilian Transmission Lines are exposed to market risks from changes in foreign currency exchange rates between the U.S. dollar and the Brazilian Real. For further information, see Part II, Item 8 – Note 4 in the 2009 Annual Report.
At September 30, 2010 and 2009, and December 31, 2009, 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) of the Exchange Act. The Company’s controls and other procedures are designed to provide reasonable assurance that information required to be disclosed in the reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Company’s disclosure controls and procedures include controls and procedures designed to provide reasonable assurance that information required to be disclosed is accumulated and communicated to management, including the Company’s chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure. The Company’s chief executiv e officer and chief financial officer have evaluated the effectiveness of the Company’s disclosure controls and procedures and they have concluded that, as of the end of the period covered by this report, such controls and procedures were effective at a reasonable assurance level.
Changes in internal controls
The Company maintains a system of internal accounting controls that is designed to provide reasonable assurance that the Company’s transactions are properly authorized, the Company’s assets are safeguarded against unauthorized or improper use, and the Company’s transactions are properly recorded and reported to permit preparation of the Company’s financial statements in conformity with generally accepted accounting principles in the United States of America. There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended September 30, 2010, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information regarding legal proceedings, see Note 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 a nd 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 2009 Annual Report other than the risk related to economic volatility; the risk related to environmental laws and regulations; the risk associated with electric generation operations that could be adversely impacted by global climate change initiatives to reduce GHG emissions; and the risk related to litigation and administrative proceedings in connection with CBNG development activities. These factors and the other matters discussed herein are important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in the forward-looking statements included elsewhere in this document.
Economic Risks
Economic volatility affects the Company's operations, as well as the demand for its products and services and the value of its investments and investment returns and, as a result, may have a negative impact on the Company's future revenues and cash flows.
The global demand for natural resources, interest rates, governmental budget constraints and the ongoing threat of terrorism can create volatility in the financial markets. The current economic slowdown has negatively affected the level of public and private expenditures on projects and the timing of these projects which, in turn, has negatively affected the demand for the Company’s
products and services, primarily at the Company’s construction businesses. The level of demand for construction products and services will likely continue to be adversely impacted by the downturn in the industries the Company serves, as well as in the economy in general. State and federal budget issues may continue to negatively affect the funding available for infrastructure spending. This continued economic volatility could have a material adverse effect on the Company's results of operations, cash flows and asset values.
Changing market conditions could negatively affect the market value of assets held in the Company’s pension and other postretirement benefit plans and may increase the amount and accelerate the timing of required funding contributions.
Environmental and Regulatory Risks
Some of the Company's operations are subject to extensive environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the Company to environmental liabilities.
The Company is subject to extensive environmental laws and regulations affecting many aspects of its present and future operations including air quality, water quality, waste management and other environmental considerations. These laws and regulations can result in increased capital, operating and other costs, and delays as a result of ongoing litigation and administrative proceedings and compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to power plant emissions 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 injunct ive 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, require the installation of pollution control equipment or the initiation of 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, which 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. For example, 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.
The Company's electric generation operations could be adversely impacted by global climate change initiatives to reduce GHG emissions.
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 including the EPA’s proposed endangerment finding for GHGs which could lead to regulation of GHG under the Clean Air Act. 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 which comprise approximately 70 percent of Montana-Dakota’s generating capacity. More than 90 percent of the electricity generated by Montana-Dakota is
from coal-fired plants. Montana-Dakota also owns approximately 100 MW of natural gas- and oil-fired peaking plants. While there are many uncertainties regarding the future of GHG regulation, Montana-Dakota’s electric generating facilities may be subject to regulation under 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 the expansion of energy conservation efforts and/or the increased development of renewable energy sources, as well as instituting other mandates that could significantly increase the capital expenditures and operating costs at its fossil fuel-fired generating facilities. The most prominent federal legislative proposals are based o n “cap and trade” programs which place a limit on GHG emissions from major emission sources such as the electric generating industry. The impact of a cap and trade program on Montana-Dakota would be determined by considerations such as the overall GHG emissions cap level, the scope and timeframe by which the cap level is decreased, the extent to which GHG offsets are allowed, whether allowances are given to new and existing emission sources, and the indirect impact on natural gas, coal and other fuel prices. Montana-Dakota’s ability to recover costs incurred to comply with new regulations and programs will also be important in determining the financial impact on the Company.
Due to the uncertainty of technologies available to control GHG emissions and the unknown nature of compliance obligations with potential GHG emission legislation or regulations, the Company cannot determine the financial impact on its operations. If Montana-Dakota does not receive timely and full recovery of the costs of complying with GHG emission legislation and regulations from its customers, then such requirements could have an adverse impact on the results of its operations.
One of the Company's subsidiaries is and has been subject to numerous litigation and administrative proceedings in connection with its CBNG development. These proceedings have caused delays in CBNG drilling activity and resulted in more restrictive discharge limitations. There is the possibility that the Company will be the subject of similar future proceedings. The ultimate outcome of the actions could have a material negative effect on existing CBNG operations and/or the future development of its CBNG properties.
The BER in March 2006 issued a decision in a rulemaking proceeding, initiated by the NPRC, that amends the non-degradation policy applicable to water discharged in connection with CBNG operations. The amended policy includes additional limitations on factors deemed harmful, thereby restricting water discharges even further than under previous standards. Due in part to this amended policy, in May 2006, the Northern Cheyenne Tribe commenced litigation in Montana state court challenging two five-year water discharge permits that the Montana DEQ granted to Fidelity in February 2006 and which are critical to Fidelity's ability to manage water produced under present and future CBNG operations. Although the Montana state district court decided the case in favor of Fidelity, the Montana Supreme Court reversed the state distri ct court’s decision on May 18, 2010, and ordered the Montana DEQ to reevaluate Fidelity’s permit applications under the appropriate predischarge treatment standards. On October 15, 2010, the Montana DEQ issued a final discharge permit to Fidelity, which will be effective for five years beginning November 14, 2010. The permit requires Fidelity to treat all discharges and reduces the amount of water Fidelity may discharge to 1,700 gallons per minute. The impact of this reduction is insignificant to Fidelity’s current production but may impact or limit Fidelity’s future drilling program. In an effort to minimize any such impacts, Fidelity is pursuing alternative methods to manage some of the water produced in conjunction with its CBNG development.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 5. OTHER INFORMATION
Mine Safety Information
The recently enacted Dodd-Frank Act requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Mine Safety 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 that could significantly and substantially contribute to the cause and effect of a coal or other mine safety hazard. |
| | 2. | Orders issued under section 104(b) of the Mine Safety Act. Orders are issued under this section when citations issued under section 104(a) have not been totally abated within the time period allowed by the citation or subsequent extensions. |
| | 3. | Citations issued under section 104(d) of the Mine Safety Act. Citations are issued under this section when it has been determined that the violation is caused by an unwarrantable failure of the mine operator to comply with the standard. An unwarrantable failure occurs when the mine operator is deemed to have engaged in aggravated conduct constituting more than ordinary negligence. |
| | 4. | Citations issued under Section 110(b)(2) of the Mine Safety Act for flagrant violations. Violations are considered flagrant for repeat or reckless failures to make reasonable efforts to eliminate a known violation of a mandatory health and safety standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury. |
| | 5. | Imminent danger orders issued under Section 107(a) of the Mine Safety Act. An imminent danger is defined as the existence of any condition or practice in a coal or other mine which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated. |
| | 6. | Notice received under Section 104(e) of the Mine Safety Act of a pattern of violations or the potential to have such a pattern of violations that could significantly and substantially contribute to the cause and effect of mine health and safety standards. |
For the three months ended September 30, 2010, none of our operating subsidiaries received citations or orders under the following sections of the Mine Safety Act: 104(b), 104(d), 110(b)(2), 107(a) or 104(e). In addition, the Company did not have any mining related fatalities during the quarter. The Company has 114 contests pending before administrative law judges of the Federal Mine Safety and Health Review Commission that involve all types of citations. Five of these contests were initiated during the three months ended September 30, 2010.
The citations issued and proposed assessments levied under the Mine Safety Act for the three months ended September 30, 2010, were as follows:
| Mine Location | | Section 104(a) Citations Issued | | | Proposed Assessments Levied (Dollars) | |
| Northern California | | | 2 | | | $ | — | |
| Southern California | | | — | | | | 100 | |
| Montana | | | — | | | | 500 | |
| Wyoming | | | — | | | | 300 | |
| Idaho/Washington | | | 3 | | | | — | |
| Texas | | | — | | | | 1,889 | |
| Western Oregon | | | — | | | | 1,855 | |
| Central Oregon | | | — | | | | 100 | |
| Southern Oregon | | | — | | | | 525 | |
| Iowa | | | 1 | | | | 862 | |
| Northern Minnesota | | | 2 | | | | 1,000 | |
| North Dakota | | | — | | | | 300 | |
| Total | | | 8 | | | $ | 7,431 | |
The proposed assessments listed above could have arisen from citations issued in prior periods.
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 3, 2010 | | 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.
| 3(a) | Restated Certificate of Incorporation of the Company, as amended, dated May 13, 2010 |
| | |
| 3(b) | Company Bylaws, as amended and restated, on August 12, 2010 |
| | |
| +10(a) | Directors’ Compensation Policy, as amended August 12, 2010 |
| | |
| +10(b) | Non-Employee Director Stock Compensation Plan, as amended August 12, 2010 |
| | |
| +10(c) | Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated September 2, 2010 |
| | |
| 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, 2010, 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 as blocks of text |
+ 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.
