MDU Resources Group, Inc. — FY 2013 Form 10-K
Reporting period: Year ended December 31, 2013. The filing also reports fourth-quarter results; this is an annual report, not a standalone quarterly filing. MDU is a diversified company spanning regulated electric and natural gas utilities, pipeline and energy services, oil and gas exploration and production, construction materials, and construction services.
Financial performance
| Metric | FY 2013 | FY 2012 |
|---|---|---|
| Operating revenue | $4.462 billion | $4.075 billion |
| Operating income | $492.9 million | $19.2 million |
| Net income attributable to the Company | $278.6 million | $(0.8) million |
| Earnings on common stock | $278.2 million | $(1.4) million |
| Diluted EPS | $1.47 | $(0.01) |
| Cash provided by operating activities | $742.2 million | $584.7 million |
| Capital expenditures | $909.4 million | $872.9 million |
| Cash and cash equivalents at year-end | $45.2 million | $49.0 million |
| Total long-term debt, including current maturities | $1.855 billion | $1.745 billion |
Operating margin was approximately 11.0% in 2013 versus 0.5% in 2012, reflecting the prior-year oil and gas property write-down. Cash provided by operations increased $157.5 million, largely from lower working-capital requirements and higher continuing earnings. Investing activities used $782.7 million; financing activities provided $36.9 million. The Company reported $569.4 million of available capacity under credit facilities and commercial-paper programs. Equity was 60% of total capitalization at year-end.
Fourth-quarter 2013 revenue was $1.184 billion, operating income was $147.1 million, and diluted EPS was $0.48. Each 2013 quarter was profitable; quarterly EPS ranged from $0.24 to $0.48 diluted.
Material changes and segment results
- Consolidated earnings on common stock improved by $279.7 million from 2012. The key factor was the absence of 2012’s $391.8 million pretax ($246.8 million after-tax) noncash oil and gas property write-down.
- Exploration and production earnings were $94.5 million, versus a $177.3 million loss. Oil production rose 30% and realized oil and natural gas prices increased, while natural gas production declined 16%. Total production was 10.264 million BOE, up modestly from 2012.
- Electric earnings increased to $34.8 million from $30.6 million, supported by 6% higher retail sales volumes.
- Natural gas distribution earnings rose to $37.7 million from $29.4 million, reflecting higher volumes, colder weather, customer growth, and a $2.8 million after-tax gain on sale of an appliance-service business.
- Pipeline and energy services earnings fell to $7.6 million from $26.6 million, including lower litigation-related benefit, a larger coalbed-gas gathering asset impairment, and weaker storage and gathering results.
- Construction materials and contracting earnings increased to $50.9 million from $32.4 million; construction services earnings increased to $52.2 million from $38.4 million. Year-end backlogs were $456 million and $459 million, respectively, compared with $406 million and $325 million a year earlier.
- Common dividends declared were $0.695 per share, up from $0.675. The company issued 499,330 shares under its equity distribution agreement in Q4, receiving $14.6 million net.
Outlook, risks, and unusual items
- 2014 outlook: Adjusted and GAAP EPS guidance was $1.45–$1.60. Management’s long-term earnings-per-share growth goal was 7%–10% annually. Forecasts depend on assumptions, including oil prices of $90–$95 per barrel and natural gas prices of $3.75–$4.25 per Mcf.
- Investment plans: The company projected approximately $959 million of 2014 net capital expenditures, before $12 million of scheduled long-term debt retirement. Utility rate base growth was targeted at approximately 9% compounded annually over five years, supported by an approximately $1.3 billion investment program.
- Projects: The Dakota Prairie Refinery was estimated to cost approximately $350 million, with service expected in late 2014 and first-year EBITDA projected at $70–$90 million, shared equally with Calumet. An 88-MW gas turbine was expected online in Q3 2014 at an estimated cost of $77 million. A proposed 375-mile gas pipeline was estimated at $650 million, subject to customer commitments, permits, and regulatory approvals.
- Oil and gas plans: 2014 capital spending was projected at approximately $440 million. Management expected oil production to rise 10%–20% and NGL production 5%–10%, while natural gas production was expected to fall 20%–30%, largely due to 2013 divestitures. A February 2014 agreement to acquire Powder River Basin assets was valued at approximately $183 million, subject to customary adjustments and closing conditions.
- Key risks: Commodity-price volatility, reserve and impairment estimation, construction execution and cost overruns, weather and seasonality, regulatory cost recovery, environmental rules and emissions requirements, labor availability and pension obligations, competition, customer/counterparty credit, and access to capital markets. Approximately 45% of the multiemployer pension plans were reported in endangered, seriously endangered, or critical status.
- Contingencies: The company reported $29.5 million of accrued contingencies, including litigation, production-tax, royalty, and environmental matters. It stated that, after recorded accruals, it did not expect the identified matters and other probable or reasonably possible excess losses to materially affect financial position, results, or cash flows. Certain environmental and legal exposures remain difficult to estimate; a Montana mining-permit dispute could involve civil penalties of up to $3.7 million plus daily penalties.
- Unusual items: 2013 included a $9.0 million after-tax impairment of coalbed natural gas gathering assets and a $1.5 million after-tax net benefit related to gathering litigation. 2012 included the $246.8 million after-tax oil and gas write-down, a $15.0 million after-tax gathering-litigation benefit, and a $13.0 million after-tax reversal of a construction-guarantee arbitration charge, partly offset by reversal of estimated insurance recoveries.
Most important facts for investors to verify
- Whether 2014 EPS guidance and projected production, project schedules, costs, and refinery economics were achieved; these are management forecasts, not reported results.
- How much of the 2013 earnings rebound reflects recurring operating improvement versus the absence of the 2012 noncash write-down and other unusual items.
- Oil and gas reserve assumptions, commodity-price sensitivities, future development spending, and exposure to further ceiling-test write-downs.
- Funding needs for the capital program, debt maturities, interest costs, credit-facility availability, and the potential dilution from equity issuance.
- Outcomes and potential customer recovery for rate cases, environmental compliance spending, gathering litigation, royalty claims, and other contingencies.
- Execution risk and financing arrangements for the refinery, proposed pipeline, generation and transmission projects, and the Powder River Basin acquisition.