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 July 30, 2010: 188,167,816 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 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 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 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 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 necessit ate 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 gathering 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, all primarily in a higher price environment; 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 | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Dollars in millions, where applicable) | |
| Electric | | $ | 5.0 | | | $ | 3.2 | | | $ | 10.8 | | | $ | 8.3 | |
| Natural gas distribution | | | .1 | | | | (4.8 | ) | | | 23.4 | | | | 19.1 | |
| Construction services | | | 2.9 | | | | 6.9 | | | | 3.1 | | | | 15.6 | |
| Pipeline and energy services | | | 9.5 | | | | 10.9 | | | | 18.3 | | | | 17.3 | |
| Natural gas and oil production | | | 24.0 | | | | 20.8 | | | | 46.3 | | | | (352.5 | ) |
| Construction materials and contracting | | | 5.7 | | | | 16.0 | | | | (14.5 | ) | | | .3 | |
| Other | | | 1.6 | | | | 2.1 | | | | 3.0 | | | | 3.1 | |
| Earnings (loss) on common stock | | $ | 48.8 | | | $ | 55.1 | | | $ | 90.4 | | | $ | (288.8 | ) |
| Earnings (loss) per common share – basic | | $ | .26 | | | $ | .30 | | | $ | .48 | | | $ | (1.57 | ) |
| Earnings (loss) per common share – diluted | | $ | .26 | | | $ | .30 | | | $ | .48 | | | $ | (1.57 | ) |
| Return on average common equity for the 12 months ended | | | | | | | | | | | 10.0 | % | | | (6.9 | )% |
Three Months Ended June 30, 2010 and 2009 Consolidated earnings for the quarter ended June 30, 2010, decreased $6.3 million from the comparable prior period largely due to:
| · | Lower aggregate, ready-mixed concrete and liquid asphalt oil volumes and margins, as well as decreased construction and asphalt margins, partially offset by lower depreciation, depletion and amortization expense at the construction materials and contracting business |
| · | Lower construction workloads and margins, partially offset by lower general and administrative expense at the construction services business |
Partially offsetting these decreases were:
| · | Increased retail sales and transportation volumes, lower operation and maintenance expense, as well as higher nonregulated energy-related services at the natural gas distribution business |
| · | Higher average realized oil prices, increased oil production, lower general and administrative and lease operating expenses, partially offset by lower average realized gas prices, decreased natural gas production, higher production taxes, as well as higher depreciation, depletion and amortization expense at the natural gas and oil production business |
Six Months Ended June 30, 2010 and 2009 Consolidated earnings for the six months ended June 30, 2010, increased $379.2 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, lower depreciation, depletion and amortization expense, lower lease operating expenses, increased oil production, as well as lower general and administrative expense, partially offset by decreased natural gas production, lower average realized natural gas prices and higher production taxes at the natural gas and oil production business |
| · | Lower operation and maintenance expense, lower interest expense and higher other income at the natural gas distribution business |
Partially offsetting these increases were:
| · | Lower aggregate, ready-mixed concrete and liquid asphalt oil volumes and margins, as well as decreased construction and asphalt margins, partially offset by lower depreciation, depletion and amortization expense and lower selling, general and administrative expense at the construction materials and contracting business |
| · | Lower construction workloads and margins, partially offset by lower general and administrative expense 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 | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Dollars in millions, where applicable) | |
| Operating revenues | | $ | 45.7 | | | $ | 44.5 | | | $ | 95.4 | | | $ | 95.8 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Fuel and purchased power | | | 13.1 | | | | 15.2 | | | | 30.0 | | | | 33.9 | |
| Operation and maintenance | | | 16.2 | | | | 15.9 | | | | 31.4 | | | | 31.5 | |
| Depreciation, depletion and amortization | | | 6.1 | | | | 6.0 | | | | 11.9 | | | | 12.2 | |
| Taxes, other than income | | | 2.2 | | | | 2.3 | | | | 4.8 | | | | 4.7 | |
| | | | 37.6 | | | | 39.4 | | | | 78.1 | | | | 82.3 | |
| Operating income | | | 8.1 | | | | 5.1 | | | | 17.3 | | | | 13.5 | |
| Earnings | | $ | 5.0 | | | $ | 3.2 | | | $ | 10.8 | | | $ | 8.3 | |
| Retail sales (million kWh) | | | 615.2 | | | | 595.3 | | | | 1,365.0 | | | | 1,320.1 | |
| Sales for resale (million kWh) | | | 7.6 | | | | 22.8 | | | | 37.4 | | | | 32.5 | |
| Average cost of fuel and purchased power per kWh | | $ | .020 | | | $ | .023 | | | $ | .020 | | | $ | .024 | |
Three Months Ended June 30, 2010 and 2009 Electric earnings increased $1.8 million (52 percent) due to:
| · | Higher electric retail sales margins, primarily due to the implementation of higher rates in Wyoming |
| · | Higher retail sales volumes of 3 percent, primarily to commercial and residential customers |
Six Months Ended June 30, 2010 and 2009 Electric earnings increased $2.5 million (30 percent) due to:
| · | Increased retail sales margins and volumes of $2.1 million (after tax), as previously discussed |
| · | Higher other income of $900,000 (after tax), primarily allowance for funds used during construction related to electric generation projects |
Partially offsetting these increases was higher interest expense, resulting from higher average borrowings.
Natural Gas Distribution
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Dollars in millions, where applicable) | |
| Operating revenues | | $ | 160.1 | | | $ | 164.1 | | | $ | 509.2 | | | $ | 647.3 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Purchased natural gas sold | | | 98.9 | | | | 107.5 | | | | 344.1 | | | | 473.5 | |
| Operation and maintenance | | | 34.4 | | | | 35.5 | | | | 67.1 | | | | 73.6 | |
| Depreciation, depletion and amortization | | | 10.7 | | | | 10.6 | | | | 21.4 | | | | 21.3 | |
| Taxes, other than income | | | 10.5 | | | | 11.3 | | | | 27.0 | | | | 34.2 | |
| | | | 154.5 | | | | 164.9 | | | | 459.6 | | | | 602.6 | |
| Operating income (loss) | | | 5.6 | | �� | | (.8 | ) | | | 49.6 | | | | 44.7 | |
| Earnings (loss) | | $ | .1 | | | $ | (4.8 | ) | | $ | 23.4 | | | $ | 19.1 | |
| Volumes (MMdk): | | | | | | | | | | | | | | | | |
| Sales | | | 15.6 | | | | 14.1 | | | | 53.7 | | | | 57.7 | |
| Transportation | | | 28.9 | | | | 23.4 | | | | 63.4 | | | | 57.4 | |
| Total throughput | | | 44.5 | | | | 37.5 | | | | 117.1 | | | | 115.1 | |
| Degree days (% of normal)* | | | | | | | | | | | | | | | | |
| Montana-Dakota | | | 96 | % | | | 119 | % | | | 98 | % | | | 106 | % |
| Cascade | | | 118 | % | | | 100 | % | | | 95 | % | | | 105 | % |
| Intermountain | | | 132 | % | | | 103 | % | | | 103 | % | | | 105 | % |
| Average cost of natural gas, including transportation, per dk | | $ | 6.33 | | | $ | 7.61 | | | $ | 6.41 | | | $ | 8.20 | |
*Degree days are a measure of the daily temperature-related demand for energy for heating. | |
Three Months Ended June 30, 2010 and 2009 Earnings at the natural gas distribution business increased $4.9 million compared to the prior year due to:
| · | Increased retail sales volumes, largely resulting from colder weather than last year in the Northwest |
| · | Lower operation and maintenance expense, largely lower bad debt expense and benefit-related costs |
| · | Increased transportation volumes of $500,000 (after tax), primarily industrial customers |
| · | Higher nonregulated energy-related services of $400,000 (after tax) |
Six Months Ended June 30, 2010 and 2009 Earnings at the natural gas distribution business increased $4.3 million (23 percent) due to:
| · | Lower operation and maintenance expense of $3.2 million (after tax), largely lower payroll and benefit-related costs and bad debt expense |
| · | Lower interest expense, primarily due to lower average borrowings and higher capitalized interest |
| · | Higher other income of $600,000 (after tax), primarily allowance for funds used during construction |
Construction Services
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (In millions) | |
| Operating revenues | | $ | 188.2 | | | $ | 220.7 | | | $ | 341.3 | | | $ | 465.5 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Operation and maintenance | | | 173.2 | | | | 199.2 | | | | 315.0 | | | | 416.4 | |
| Depreciation, depletion and amortization | | | 3.1 | | | | 3.3 | | | | 6.3 | | | | 6.7 | |
| Taxes, other than income | | | 6.1 | | | | 6.4 | | | | 12.6 | | | | 16.0 | |
| | | | 182.4 | | | | 208.9 | | | | 333.9 | | | | 439.1 | |
| Operating income | | | 5.8 | | | | 11.8 | | | | 7.4 | | | | 26.4 | |
| Earnings | | $ | 2.9 | | | $ | 6.9 | | | $ | 3.1 | | | $ | 15.6 | |
Three Months Ended June 30, 2010 and 2009 Construction services earnings decreased $4.0 million (58 percent) due to lower construction workloads and margins, primarily in the Southwest region, partially offset by lower general and administrative expense of $3.5 million (after tax), largely payroll-related.
Six Months Ended June 30, 2010 and 2009 Construction services earnings decreased $12.5 million (80 percent) due to lower construction workloads and margins, primarily in the Southwest region, partially offset by lower general and administrative expense of $6.6 million (after tax), largely payroll-related.
Pipeline and Energy Services
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Dollars in millions) | |
| Operating revenues | | $ | 80.5 | | | $ | 68.0 | | | $ | 169.1 | | | $ | 153.1 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Purchased natural gas sold | | | 35.3 | | | | 28.1 | | | | 82.8 | | | | 74.2 | |
| Operation and maintenance | | | 17.8 | | | | 11.1 | | | | 33.0 | | | | 28.8 | |
| Depreciation, depletion and amortization | | | 6.5 | | | | 6.2 | | | | 12.9 | | | | 12.3 | |
| Taxes, other than income | | | 3.2 | | | | 3.0 | | | | 6.2 | | | | 5.9 | |
| | | | 62.8 | | | | 48.4 | | | | 134.9 | | | | 121.2 | |
| Operating income | | | 17.7 | | | | 19.6 | | | | 34.2 | | | | 31.9 | |
| Earnings | | $ | 9.5 | | | $ | 10.9 | | | $ | 18.3 | | | $ | 17.3 | |
| Transportation volumes (MMdk): | | | | | | | | | | | | | | | | |
| Montana-Dakota | | | 7.3 | | | | 10.2 | | | | 14.9 | | | | 18.5 | |
| Other | | | 37.0 | | | | 33.6 | | | | 59.9 | | | | 62.4 | |
| | | | 44.3 | | | | 43.8 | | | | 74.8 | | | | 80.9 | |
| Gathering volumes (MMdk) | | | 19.3 | | | | 24.3 | | | | 38.4 | | | | 48.6 | |
Three Months Ended June 30, 2010 and 2009 Pipeline and energy services earnings decreased $1.4 million (12 percent) due to:
| · | Higher operation and maintenance expense of $3.1 million (after tax), primarily due to the absence of the settlement of the natural gas storage litigation, which lowered expense in the second quarter last year |
| · | Lower gathering volumes of $1.2 million (after tax) |
Partially offsetting the earnings decrease were higher storage services revenue of $1.9 million (after tax), as well as higher volumes transported to storage.
Six Months Ended June 30, 2010 and 2009 Pipeline and energy services earnings increased $1.0 million (6 percent) due to higher storage services revenue of $4.3 million (after tax), largely higher storage balances.
Partially offsetting this increase were:
| · | Lower gathering volumes of $2.7 million (after tax) |
| · | Higher operation and maintenance expense of $1.0 million (after tax), including higher payroll-related costs |
Natural Gas and Oil Production
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Dollars in millions, where applicable) | |
| Operating revenues: | | | | | | | | | | | | |
| Natural gas | | $ | 55.2 | | | $ | 69.2 | | | $ | 112.8 | | | $ | 150.9 | |
| Oil | | | 55.6 | | | | 35.6 | | | | 105.6 | | | | 60.0 | |
| | | | 110.8 | | | | 104.8 | | | | 218.4 | | | | 210.9 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Operation and maintenance: | | | | | | | | | | | | | | | | |
| Lease operating costs | | | 16.3 | | | | 18.0 | | | | 32.1 | | | | 38.0 | |
| Gathering and transportation | | | 5.9 | | | | 6.1 | | | | 11.8 | | | | 12.2 | |
| Other | | | 8.8 | | | | 10.7 | | | | 17.4 | | | | 21.0 | |
| Depreciation, depletion and amortization | | | 32.5 | | | | 30.2 | | | | 62.1 | | | | 72.8 | |
| Taxes, other than income: | | | | | | | | | | | | | | | | |
| Production and property taxes | | | 9.0 | | | | 5.7 | | | | 18.5 | | | | 13.2 | |
| Other | | | .1 | | | | .2 | | | | .5 | | | | .4 | |
| Write-down of natural gas and oil properties | | | — | | | | — | | | | — | | | | 620.0 | |
| | | | 72.6 | | | | 70.9 | | | | 142.4 | | | | 777.6 | |
| Operating income (loss) | | | 38.2 | | | | 33.9 | | | | 76.0 | | | | (566.7 | ) |
| Earnings (loss) | | $ | 24.0 | | | $ | 20.8 | | | $ | 46.3 | | | $ | (352.5 | ) |
| Production: | | | | | | | | | | | | | | | | |
| Natural gas (MMcf) | | | 12,809 | | | | 14,297 | | | | 25,052 | | | | 29,698 | |
| Oil (MBbls) | | | 831 | | | | 771 | | | | 1,592 | | | | 1,513 | |
| Total Production (MMcf equivalent) | | | 17,794 | | | | 18,923 | | | | 34,602 | | | | 38,775 | |
| Average realized prices (including hedges): | | | | | | | | | | | | | | | | |
| Natural gas (per Mcf) | | $ | 4.31 | | | $ | 4.84 | | | $ | 4.50 | | | $ | 5.08 | |
| Oil (per barrel) | | $ | 66.88 | | | $ | 46.21 | | | $ | 66.36 | | | $ | 39.67 | |
| Average realized prices (excluding hedges): | | | | | | | | | | | | | | | | |
| Natural gas (per Mcf) | | $ | 3.30 | | | $ | 2.40 | | | $ | 3.92 | | | $ | 3.04 | |
| Oil (per barrel) | | $ | 67.21 | | | $ | 47.46 | | | $ | 66.83 | | | $ | 40.30 | |
| Average depreciation, depletion and amortization rate, per equivalent Mcf | | $ | 1.74 | | | $ | 1.52 | | | $ | 1.71 | | | $ | 1.80 | |
| Production costs, including taxes, per net equivalent Mcf: | | | | | | | | | | | | | | | | |
| Lease operating costs | | $ | .91 | | | $ | .95 | | | $ | .93 | | | $ | .98 | |
| Gathering and transportation | | | .33 | | | | .32 | | | | .34 | | | | .31 | |
| Production and property taxes | | | .51 | | | | .30 | | | | .53 | | | | .34 | |
| | | $ | 1.75 | | | $ | 1.57 | | | $ | 1.80 | | | $ | 1.63 | |
Three Months Ended June 30, 2010 and 2009 Natural gas and oil production earnings increased $3.2 million (16 percent) due to:
| · | Higher average realized oil prices of 45 percent |
| · | Increased oil production of 8 percent, largely related to drilling activity in the Bakken area |
| · | Lower general and administrative expense of $1.3 million (after tax) |
| · | Decreased lease operating expenses of $1.1 million (after tax) |
Partially offsetting these increases were:
| · | Lower average realized natural gas prices of 11 percent |
| · | Decreased natural gas production of 10 percent, largely related to normal production declines at existing properties, partially offset by production from the recently acquired Green River Basin properties |
| · | Higher production taxes of $1.9 million (after tax) |
| · | Higher depreciation, depletion and amortization expense of $1.4 million (after tax), due to higher depletion rates |
Six Months Ended June 30, 2010 and 2009 Natural gas and oil production earnings increased $398.8 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 6 |
| · | Higher average realized oil prices of 67 percent |
| · | Lower depreciation, depletion and amortization expense of $6.6 million (after tax), due to lower depletion rates and decreased combined production. The lower depletion rates are largely the result of the write-down of natural gas and oil properties in March 2009. |
| · | Decreased lease operating expenses of $3.7 million (after tax) |
| · | Increased oil production of 5 percent, largely related to drilling activity in the Bakken area |
| · | Lower general and administrative expense of $2.2 million (after tax) |
Partially offsetting these increases were:
| · | Decreased natural gas production of 16 percent, largely related to normal production declines, as previously discussed |
| · | Lower average realized natural gas prices of 11 percent |
| · | Higher production taxes of $3.4 million (after tax) |
Construction Materials and Contracting
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (Dollars in millions) | |
| Operating revenues | | $ | 361.6 | | | $ | 389.4 | | | $ | 511.4 | | | $ | 572.9 | |
| Operating expenses: | | | | | | | | | | | | | | | | |
| Operation and maintenance | | | 316.9 | | | | 325.7 | | | | 462.9 | | | | 498.0 | |
| Depreciation, depletion and amortization | | | 22.2 | | | | 23.8 | | | | 44.8 | | | | 47.8 | |
| Taxes, other than income | | | 9.2 | | | | 9.8 | | | | 16.5 | | | | 17.3 | |
| | | | 348.3 | | | | 359.3 | | | | 524.2 | | | | 563.1 | |
| Operating income (loss) | | | 13.3 | | | | 30.1 | | | | (12.8 | ) | | | 9.8 | |
| Earnings (loss) | | $ | 5.7 | | | $ | 16.0 | | | $ | (14.5 | ) | | $ | .3 | |
| Sales (000's): | | | | | | | | | | | | | | | | |
| Aggregates (tons) | | | 6,261 | | | | 6,486 | | | | 9,224 | | | | 9,671 | |
| Asphalt (tons) | | | 1,579 | | | | 1,530 | | | | 1,733 | | | | 1,718 | |
| Ready-mixed concrete (cubic yards) | | | 742 | | | | 792 | | | | 1,218 | | | | 1,301 | |
Three Months Ended June 30, 2010 and 2009 Earnings at the construction materials and contracting business decreased $10.3 million (65 percent) due to lower aggregate, ready-mixed concrete and liquid asphalt oil volumes and margins, as well as decreased construction and asphalt margins, which reflects the effects of the economic downturn and weather-related delays.
Partially offsetting the decreases was lower depreciation, depletion and amortization expense of $1.0 million (after tax), largely the result of lower property, plant and equipment balances.
Six Months Ended June 30, 2010 and 2009 Construction materials and contracting recognized a loss of $14.5 million compared to earnings of $300,000 for the comparable prior period due to lower aggregate, ready-mixed concrete and liquid asphalt oil volumes and margins, as well as decreased construction and asphalt margins, as previously discussed.
Partially offsetting the decreases was lower depreciation, depletion and amortization expense of $1.9 million (after tax), largely the result of lower property, plant and equipment balances, as well as lower selling, general and administrative expense of $1.2 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 | | | Six Months Ended | |
| | | June 30, | | | June 30, | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | | (In millions) | |
| Other: | | | | | | | | | | | | |
| Operating revenues | | $ | 2.3 | | | $ | 2.7 | | | $ | 4.5 | | | $ | 5.4 | |
| Operation and maintenance | | | 1.8 | | | | 1.9 | | | | 3.7 | | | | 5.2 | |
| Depreciation, depletion and amortization | | | .4 | | | | .3 | | | | .8 | | | | .6 | |
| Taxes, other than income | | | .1 | | | | .1 | | | | .1 | | | | .1 | |
| Intersegment transactions: | | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 42.8 | | | $ | 36.2 | | | $ | 108.1 | | | $ | 98.9 | |
| Purchased natural gas sold | | | 36.8 | | | | 29.2 | | | | 95.8 | | | | 84.8 | |
| Operation and maintenance | | | 6.0 | | | | 7.0 | | | | 12.3 | | | | 14.1 | |
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 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 $1.35. The Company expects the percentage of 2010 earnings per common share by quarter to be in the following approximate ranges: |
| o | Third quarter – 30 percent to 35 percent |
| o | Fourth quarter – 20 percent to 25 percent |
| · | 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. |
| · | The Company has a 25 MW ownership interest in Wygen III, which commenced commercial operation on April 1, 2010. The WYPSC approved an increase, primarily related to the costs of Wygen III, in the amount of $2.7 million annually, or 13.1 percent, effective May 1, 2010. |
| · | In April 2010, the Company filed an application with the NDPSC for an electric rate increase, as discussed in Note 18. |
| · | The Company plans to file an application with the MTPSC for an electric rate increase in the third quarter of 2010. The request will include an increase related to the investment in infrastructure upgrades, recovery of the investment in renewable generation and the costs associated with the Big Stone Station II. |
| · | The Company is developing a landfill methane gas recovery project in Billings, Montana to supplement the Company’s gas supply portfolio. The project is expected to begin production in the fourth quarter 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 $25 million project also 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. |
| · | In June 2010, the Company placed into service a 10.5 MW expansion of its Diamond Willow wind farm in Montana, and the new 19.5 MW Cedar Hills wind farm in southwest North Dakota. |
Construction services
| · | Work backlog as of June 30, 2010, was approximately $389 million, compared to $507 million at June 30, 2009, which included backlog related to the Fontainebleau project of $182 million. The Fontainebleau project was removed from backlog in the third quarter of 2009 after Fontainebleau’s bankruptcy filing. Absent the Fontainebleau-related backlog, levels are $64 million higher than one year ago. Backlog at March 31, 2010, was $400 million. |
| · | Examples of new projects included in work backlog are solar projects in the Las Vegas area and substation related work. |
| · | The Company anticipates margins in 2010 to be lower than 2009 levels. |
| · | The Company is aggressively 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 32 percent for the second quarter compared to one year ago. |
| · | With its highly skilled technical workforce, this group is prepared to take advantage of government stimulus spending on transmission infrastructure. |
Pipeline and energy services
| · | An incremental expansion to the Grasslands Pipeline of 75,000 Mcf per day went into service August 31, 2009. The firm capacity of the Grasslands Pipeline is at its ultimate full capacity of 213,000 Mcf per day. |
| · | 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 continues to see strong interest in its storage services. It has three natural gas storage fields, including the largest storage field in North America located near Baker, Montana. The Company 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, subject to regulatory approval, with a projected in-service date of November 2011. |
Natural gas and oil production
| · | The Company expects to spend approximately $380 million in capital expenditures for 2010, approximately double the level of capital invested in 2009. This 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. |
| · | Earlier this year, the Company acquired exploratory acreage of approximately 40,000 net acres in the North Dakota Bakken area, bringing its total acreage position in this oil play to more than 56,000 net acres. For the 40,000 net acres held in Stark County, the Heart River project, plans include drilling three exploratory wells this year to evaluate the acreage targeting the Three Forks formation. Lease terms extend up to five years including renewal options available to the Company. A total of 60 potential drilling sites have been identified in this area based on 640-acre spacing. |
| · | The Company also acquired approximately 80,000 net exploratory acres in the emerging Niobrara oil play in Laramie and Goshen Counties in southeastern Wyoming. The Company plans to begin drilling exploratory wells in the area in 2011. Assuming 640-acre spacing, the Company has 120 potential drilling sites available on this acreage. Lease terms are generally five years with most having five-year renewal options available to the Company. Although this emerging play is still |
developing in terms of resource potential, early results by other producers in the play appear promising.
| · | The Company continues to pursue additional leasehold and reserve acquisitions which are not included in the current forecast. |
| · | Because of reduced capital spending in 2009 and the redirecting of forecasted 2010 capital expenditures, along with delays in obtaining well completion/frac services, primarily in Texas, the Company expects its 2010 combined natural gas and oil production to be approximately 3 percent to 6 percent below 2009 levels. |
| · | Earnings guidance reflects estimated natural gas prices for August through December as follows: |
| Index* | Price Per Mcf |
| Ventura | $4.25 to $4.75 |
| NYMEX | $4.50 to $5.00 |
| CIG | $4.00 to $4.50 |
| * 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 August through December in the range of $70 to $75 per barrel. |
| · | For the last six 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 30 percent to 35 percent of its estimated oil production. For 2012, the Company has hedged 5 percent to 10 percent of its estimated natural gas production. The hedges that are in place as of August 2, 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 | 7/10 - 12/10 | 809,600 | $8.08 |
| Natural Gas | Swap | NYMEX | 7/10 - 12/10 | 1,840,000 | $6.18 |
| Natural Gas | Swap | NYMEX | 7/10 - 12/10 | 920,000 | $6.40 |
| Natural Gas | Collar | NYMEX | 7/10 - 12/10 | 920,000 | $5.63-$6.00 |
| Natural Gas | Swap | NYMEX | 7/10 - 12/10 | 920,000 | $5.855 |
| Natural Gas | Swap | NYMEX | 7/10 - 12/10 | 920,000 | $6.045 |
| Natural Gas | Swap | NYMEX | 7/10 - 12/10 | 920,000 | $6.045 |
| Natural Gas | Swap | CIG | 7/10 - 12/10 | 1,840,000 | $5.03 |
| Natural Gas | Swap | HSC | 7/10 - 10/10 | 246,000 | $5.57 |
| Natural Gas | Swap | NYMEX | 7/10 - 10/10 | 984,000 | $5.645 |
| Natural Gas | Swap | Ventura | 7/10 - 12/10 | 920,000 | $5.95 |
| Natural Gas | Swap | NYMEX | 7/10 - 12/10 | 2,024,000 | $5.54 |
| Natural Gas | Collar | NYMEX | 7/10 - 3/11 | 1,370,000 | $5.62-$6.50 |
| Natural Gas | Swap | HSC | 1/11 - 12/11 | 1,350,500 | $8.00 |
| Natural Gas | Swap | NYMEX | 1/11 - 12/11 | 4,015,000 | $6.1027 |
| Natural Gas | Swap | NYMEX | 1/11 - 12/11 | 3,650,000 | $5.4975 |
| Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 3,477,000 | $6.27 |
| Crude Oil | Collar | NYMEX | 7/10 - 12/10 | 184,000 | $60.00-$75.00 |
| Crude Oil | Swap | NYMEX | 7/10 - 12/10 | 184,000 | $73.20 |
| Crude Oil | Collar | NYMEX | 7/10 - 12/10 | 184,000 | $70.00-$86.00 |
| Crude Oil | Swap | NYMEX | 7/10 - 12/10 | 184,000 | $83.05 |
| Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 547,500 | $80.00-$94.00 |
| Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 365,000 | $80.00-$89.00 |
| Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 182,500 | $77.00-$86.45 |
| Crude Oil | Collar | NYMEX | 1/11 - 12/11 | 182,500 | $75.00-$88.00 |
| Natural Gas | Basis Swap | Ventura | 7/10 - 12/10 | 1,840,000 | $0.25 |
| Natural Gas | Basis Swap | Ventura | 7/10 - 12/10 | 460,000 | $0.245 |
| Natural Gas | Basis Swap | Ventura | 7/10 - 12/10 | 2,300,000 | $0.25 |
| Natural Gas | Basis Swap | Ventura | 7/10 - 12/10 | 920,000 | $0.225 |
| Natural Gas | Basis Swap | Ventura | 7/10 - 12/10 | 460,000 | $0.23 |
| Natural Gas | Basis Swap | Ventura | 7/10 - 12/10 | 1,380,000 | $0.23 |
| Natural Gas | Basis Swap | CIG | 7/10 - 12/10 | 2,024,000 | $0.385 |
| Natural Gas | Basis Swap | Ventura | 1/11 - 3/11 | 450,000 | $0.135 |
| Natural Gas | Basis Swap | CIG | 1/11 - 12/11 | 4,015,000 | $0.395 |
| Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 2,745,000 | $0.405 |
| Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 732,000 | $0.41 |
Notes: · Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system; HSC is the Houston Ship Channel hub in southeast Texas which connects to several pipelines. · For all basis swaps, Index prices are below NYMEX prices and are reported as a positive amount in the Price column. |
Construction materials and contracting
| · | Work backlog as of June 30, 2010, was approximately $677 million, $109 million higher than the March 31, 2010, backlog of $568 million. Backlog a year ago was $707 million. Private project backlog has decreased, however public work has increased over prior year levels. |
| · | Examples of new large projects included in work backlog are several highway paving projects, a reclamation project, and an L.A. harbor deepening project. |
| · | All of the markets served by the construction materials segment are seeing positive impacts related to the federal stimulus spending and the Company is well positioned to take advantage of this funding in the asphalt paving and liquid asphalt oil product lines. Federal transportation stimulus of $7.9 billion was directed to states where the Company operates. Of that amount, 41 percent was spent as of late July 2010, with the remaining $4.7 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 35 percent for the trailing 12 months through June 30, 2010, compared to the annual expenses in 2006, the peak earnings year for this segment. |
| · | The Company expects volumes and margins to be lower in 2010 compared to 2009 as a result of the economic downturn. Liquid asphalt volumes were at record levels in 2009. |
| · | The Company has planned green field expansions for the liquid asphalt oil business this year. |
| · | 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 9, 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
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 six months of 2010 decreased $195.1 million from the comparable period in 2009 due to higher working capital requirements of $183.5 million, including decreased cash provided from receivables, largely at the construction services and natural
gas and oil production businesses along with lower cash provided from net natural gas costs recoverable through rate adjustments at the natural gas distribution business.
Investing activities Cash flows used in investing activities in the first six months of 2010 increased $59.4 million from the comparable period in 2009 due to an increase in acquisition-related capital expenditures of $102.8 million, largely due to the acquisition of natural gas properties located in the Green River Basin, offset in part by decreased ongoing capital expenditures of $35.3 million, largely at the pipeline and energy services and natural gas and oil production businesses.
Financing activities Cash flows provided by financing activities in the first six months of 2010 increased $162.9 million from the comparable period in 2009 due to lower repayment of short-term borrowings and long-term debt of $98.5 million and $91.2 million, respectively, offset in part by lower issuance of long-term debt of $26.4 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 17 and Part II, Item 7 in the 2009 Annual Report.
Capital expenditures
Net capital expenditures for the first six months of 2010 were $335.5 million and are estimated to be approximately $625 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 and leasehold acquisitions 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 June 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 June 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 | | | | $ | — | | (b) | | $ | — | | | 6/21/11 | |
| MDU Energy Capital, LLC | Master shelf agreement | | | $ | 175.0 | | | | $ | 165.0 | | | | $ | — | | | 8/14/10 | (c)(d) |
| Cascade Natural Gas Corporation | Revolving credit agreement | | | $ | 50.0 | | (e) | | $ | — | | | | $ | 1.9 | | (f) | 12/28/12 | (g) |
| Intermountain Gas Company | Revolving credit agreement | | | $ | 65.0 | | (h) | | $ | 3.7 | | | | $ | — | | | 8/31/10 | (i) |
| Centennial Energy Holdings, Inc. | Commercial paper/Revolving credit agreement | (j) | | $ | 400.0 | | | | $ | 83.0 | | (b) | | $ | 25.8 | | (f) | 12/13/12 | |
| Williston Basin Interstate Pipeline Company | Uncommitted long-term private shelf agreement | | | $ | 125.0 | | | | $ | 87.5 | | | | $ | — | | | 12/23/11 | (c) |
| (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) | Represents expiration of the ability to borrow additional funds under the agreement. |
| (d) | Or such time as the agreement is terminated by either of the parties thereto. |
| (e) | Certain provisions allow for increased borrowings, up to a maximum of $75 million. |
| (f) | The outstanding letters of credit, as discussed in Note 19, reduce amounts available under the credit agreement. |
| (g) | Provisions allow for an extension of up to two years upon consent of the banks. |
| (h) | Certain provisions allow for increased borrowings, up to a maximum of $70 million. |
| (i) | Intermountain plans to negotiate the extension or replacement of this agreement prior to its expiration. |
| (j) | 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. |
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 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 in crease 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 4.5 times for the 12 months ended June 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 62 percent and 63 percent at June 30, 2010 and December 31, 2009, respectively.
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 has issued a total of approximately 3.2 million shares of stock under the Sales Agency Financing Agreement through June 30, 2010, resulting in total net p roceeds 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.
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 19.
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 19.
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 June 30, 2010, increased $26.7 million or 22 percent from December 31, 2009. At June 30, 2010, the Company’s contractual obligations related to operating leases totaled $150.7 million. The scheduled commitment amounts (for the twelve months ended June 30, of each year listed) total $28.4 million in 2011; $22.7 million in 2012; $18.5 million in 2013; $13.0 million in 2014; $6.5 million in 2015; and $61.6 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 10 and 13.
The following table summarizes derivative agreements entered into by Fidelity, Cascade and Intermountain as of June 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 | | $ | 5.93 | | | | 12,344 | | | $ | 15,252 | |
| Natural gas swap agreements maturing in 2011 | | $ | 6.14 | | | | 9,016 | | | $ | 7,372 | |
| Natural gas swap agreement maturing in 2012 | | $ | 6.27 | | | | 3,477 | | | $ | 2,008 | |
| Natural gas basis swap agreements maturing in 2010 | | $ | .27 | | | | 9,384 | | | $ | 162 | |
| Natural gas basis swap agreements maturing in 2011 | | $ | .37 | | | | 4,465 | | | $ | 328 | |
| Natural gas basis swap agreements maturing in 2012 | | $ | .41 | | | | 3,477 | | | $ | 285 | |
| Oil swap agreements maturing in 2010 | | $ | 78.13 | | | | 368 | | | $ | 437 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Cascade | | | | | | | | | | | | |
| Natural gas swap agreements maturing in 2010 | | $ | 8.02 | | | | 2,425 | | | $ | (9,382 | ) |
| Natural gas swap agreements maturing in 2011 | | $ | 8.10 | | | | 2,270 | | | $ | (7,601 | ) |
| | | | | | | | | | | | | |
| Intermountain | | | | | | | | | | | | |
| Natural gas swap agreement maturing in 2010 | | $ | 4.96 | | | | 1,661 | | | $ | (1,485 | ) |
| Natural gas swap agreement maturing in 2011 | | $ | 4.96 | | | | 2,889 | | | $ | (429 | ) |
| | | | | | | | | | | | | |
| | | Weighted Average Floor/Ceiling Price (Per MMBtu/Bbl) | | | Forward Notional Volume (MMBtu/Bbl) | | | Fair Value | |
| Fidelity | | | | | | | | | | | | |
| Natural gas collar agreements maturing in 2010 | | | $5.63/$6.25 | | | | 1,840 | | | $ | 1,474 | |
| Natural gas collar agreement maturing in 2011 | | | $5.62/$6.50 | | | | 450 | | | $ | 345 | |
| Oil collar agreements maturing in 2010 | | | $65.00/$80.50 | | | | 368 | | | $ | (874 | ) |
| Oil collar agreements maturing in 2011 | | | $78.86/$90.64 | | | | 1,278 | | | $ | 4,706 | |
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 June 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 June 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 June 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 19, 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 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.
Environmental and Regulatory Risks
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 co sts at its fossil fuel-fired generating facilities. The most prominent federal legislative proposals are based on “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 subject to ongoing litigation and administrative proceedings in connection with its CBNG development. These proceedings have caused delays in CBNG drilling activity, and 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.
Fidelity’s operations are and have been the subject of numerous lawsuits filed in connection with its CBNG development in the Montana and Wyoming Powder River Basin. If the plaintiffs are successful in the current lawsuits, the ultimate outcome of the actions could have a material negative effect on Fidelity's 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. The Montana DEQ has until November 14, 2010, to complete the permitting process, during which time Fidelity may continue to operate under its current permits. Fidelity will not be able to assess the impact to its operations until the final permits are issued.
In a separate proceeding in Montana state court, plaintiffs challenged the ROD adopted by the MBOGC in 2003 and alleged that various water management tools, including Fidelity’s water discharge permits, allow for the “wasting” of water in violation of the Montana State Constitution. On
March 5, 2010, the Montana First Judicial District Court determined that the water management tools used by Fidelity did not waste water in violation of the constitution. Once judgment is entered, the parties will have 60 days to appeal to the Montana Supreme Court. If these permits are set aside, Fidelity's CBNG operations in Montana could be significantly and adversely affected.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table includes information with respect to the Company’s purchase of equity securities:
ISSUER PURCHASES OF EQUITY SECURITIES
| Period | (a) Total Number of Shares (or Units) Purchased (1) | (b) Average Price Paid per Share (or Unit) | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (2) | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs (2) |
| April 1 through April 30, 2010 | — | | | |
| May 1 through May 31, 2010 | 36,450 | $19.52 | | |
| June 1 through June 30, 2010 | — | | | |
| Total | 36,450 | | | |
(1) Represents shares of common stock purchased on the open market in connection with annual stock grants made to the Company’s non-employee directors.
(2) Not applicable. The Company does not currently have in place any publicly announced plans or programs to purchase equity securities.
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: August 6, 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.
| +10(a) | Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated May 28, 2010 |
| | |
| +10(b) | Agreement for Termination of Change of Control Employment Agreement, dated June 15, 2010, by and between MDU Resources Group, Inc. and Terry D. Hildestad |
| | |
| +10(c) | Form of Notice of Expiration of Coverage Period – Change of Control Employment Agreement, dated June 15, 2010, sent by MDU Resources Group, Inc. to William E. Schneider, John G. Harp, Steven L. Bietz, David L. Goodin, William R. Connors, Mark A. Del Vecchio, Nicole A. Kivisto, Cynthia J. Norland, Paul K. Sandness, Doran N. Schwartz and John P. Stumpf |
| | |
| 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 June 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.
