Black Hills Corporation — Q1 2011 Form 10-Q
Reporting period: Three months ended March 31, 2011. Black Hills is a diversified U.S. energy company with regulated electric and gas utilities and non-regulated oil and gas, power generation, coal mining and energy marketing operations. Results are seasonal, particularly for gas utilities, and are not necessarily indicative of the full year.
Financial performance and position
| Metric | Q1 2011 | Q1 2010 |
|---|---|---|
| Operating revenue | $403.3 million | $426.5 million |
| Operating income | $55.7 million | $69.7 million |
| Net income | $26.9 million | $31.4 million |
| Diluted EPS | $0.68 | $0.81 |
| Operating cash flow | $111.3 million | $88.9 million |
| Capital expenditures (cash PP&E additions) | $122.5 million | $81.3 million |
| Dividends per share | $0.365 | $0.360 |
- Revenue declined about 5% and net income about 14% year over year. Operating margin was approximately 13.8% of revenue, versus 16.3% in Q1 2010.
- Operating cash flow increased $22.4 million, but cash PP&E additions exceeded operating cash flow by $11.3 million. Cash and cash equivalents were $44.0 million at quarter-end, up from $32.4 million at year-end 2010.
- At March 31, 2011, notes payable were $287.0 million, current maturities of long-term debt $4.3 million, and long-term debt $1.185 billion. Total debt on these reported balances was approximately $1.476 billion. Stockholders’ equity was $1.113 billion.
- The $500 million revolving credit facility had $187 million drawn and $51 million of letters of credit outstanding, leaving approximately $262 million of available capacity. The separate Enserco facility had $147 million of letters of credit and no cash borrowings. The company reported covenant compliance; its recourse leverage ratio was 57.8% against a 65% limit.
Material changes versus Q1 2010
- Utilities’ net income was nearly flat at $29.5 million versus $29.4 million. Electric Utilities earnings rose $0.4 million; Gas Utilities earnings fell $0.2 million. Rate increases implemented in 2010 supported utility margins, partly offset by lower sales volumes and other costs.
- Non-regulated Energy shifted to a $3.5 million loss from $7.1 million of income. Oil and Gas reported a $0.7 million loss versus $2.3 million income; Coal Mining a $1.3 million loss versus $1.3 million income; and Energy Marketing a $2.6 million loss versus $2.2 million income. Power Generation earnings were broadly comparable.
- Oil and Gas results were pressured by lower average realized prices: gas was $4.65/Mcf versus $5.91, and oil was $66.83/Bbl versus $74.39. Higher oil volumes partly offset price declines.
- Coal Mining costs increased substantially, reflecting longer haul distances, higher stripping, drilling and blasting, maintenance, fuel and staffing costs. Management said contract price escalators had not kept pace with actual cost increases and expected continued pressure on 2011 results.
- Energy Marketing gross margin declined to $2.5 million from $9.8 million, principally from weaker gas and oil marketing margins. Coal marketing, begun in 2010, partly offset the decline.
- The 2011 quarter included a $3.6 million after-tax non-cash mark-to-market gain on certain interest-rate swaps. Q1 2010 included a $2.0 million after-tax non-cash loss on those swaps and a $1.7 million after-tax asset-sale gain. The 2011 swap gain is not a recurring operating result.
Outlook, risks and unusual items
- Management planned approximately $462.2 million of 2011 capital expenditures. Two gas-fired generation projects—180 MW for Colorado Electric, expected to cost about $227 million, and 200 MW at Colorado IPP, expected to cost about $260 million—were under construction, with completion and service expected by year-end 2011. Spending through March 31 was approximately $212.9 million and $203.1 million, respectively.
- Management expected to fund capital needs with operating cash flow, revolving borrowings and long-term financing, and intended to settle its equity forward physically in Q4 2011. Physical settlement would deliver 4,413,519 shares for approximately $123.4 million. Management said the debt-to-capitalization ratio could temporarily exceed its 50%–55% target range during construction.
- On April 28, 2011, Colorado Electric requested a $40.2 million annual revenue increase, including recovery of generation and infrastructure costs; the proposed effective date was January 1, 2012. This was a post-quarter filing and remained pending.
- The board declared a quarterly dividend of $0.365 per share payable June 1, 2011; future dividends depend on financial condition, capital needs, covenants and business prospects. A $100 million corporate term loan was due in December 2011.
- Key exposures include commodity, interest-rate and foreign-exchange movements; counterparty performance and collateral needs; access to capital and covenant compliance; regulatory outcomes; construction timing and cost; environmental and emissions rules; and possible oil and gas reserve impairments. Dodd-Frank implementation could affect derivatives and related liquidity requirements.
- Management reported no material new or terminated legal proceedings during the quarter, but stated that costs in excess of recorded provisions could not be reasonably determined and could materially affect results or financial position. No material changes to previously disclosed risk factors were reported.
- The 2010 comparative revenue and fuel-cost figures were restated to correct an intercompany-elimination error that overstated each by $15.8 million. The correction did not affect gross margin, net income, assets, cash flow or EPS.
Investor verification priorities
- Assess whether utility rate recovery and construction milestones support the planned Colorado generation investment and proposed rate increase.
- Track non-regulated segment performance, particularly coal cost recovery, oil and gas realized prices and Energy Marketing margins.
- Review cash funding, available revolver capacity, the December 2011 term-loan maturity and planned equity-forward settlement against the capital program.
- Separate recurring earnings from interest-rate swap mark-to-market gains and monitor potential cash settlements on the de-designated swaps.
- Confirm covenant headroom, subsidiary dividend restrictions, and the extent to which derivative collateral or counterparty changes could affect liquidity.