Black Hills Corporation — Q2 2014 Form 10-Q
Reporting period: Quarter and six months ended June 30, 2014. Black Hills operates regulated electric and gas utilities and non-regulated power generation, coal mining, and oil and gas businesses. Amounts below are in U.S. dollars; financial statement figures are in millions unless noted.
Financial performance and liquidity
- Q2 revenue: $283.2 million, up 1.2% from $279.8 million. Operating income was $46.6 million, down 5.0%; net income was $19.8 million, down 35.1%. Diluted EPS was $0.44 versus $0.69.
- Six-month revenue: $743.4 million, up 12.6% from $660.5 million. Operating income rose 5.7% to $136.2 million, while net income fell 7.8% to $67.9 million. Diluted EPS was $1.52 versus $1.66.
- Profitability drivers: Q2 results included no interest-rate-swap mark-to-market gain, compared with a $18.8 million pre-tax gain in Q2 2013. The comparable six-month 2013 period included a $26.2 million pre-tax gain. Refinancing reduced consolidated interest expense by approximately $5.5 million in Q2 and $11 million year to date.
- Cash flow, six months: Operating cash flow was $173.8 million, down from $197.4 million. Capital spending was $177.3 million, versus $147.2 million, and investing cash outflow was $180.3 million. Dividends paid were $34.8 million, or $0.78 per share.
- Balance sheet at June 30: Cash was $14.7 million; current assets were $344.1 million and current liabilities were $653.3 million. Notes payable were $132.7 million, current maturities of long-term debt $275.0 million, and long-term debt $1,122.0 million. Total debt including notes payable was approximately $1.53 billion.
- Available liquidity: The $500 million revolving credit facility had $132.7 million borrowed, $20.3 million in letters of credit, and $347 million available. The facility was extended to May 29, 2019. The company reported compliance with its financial covenant; its 54% recourse leverage ratio was below the 65% limit.
- Shareholder return: The board declared a $0.39-per-share quarterly dividend payable September 1, 2014, equivalent to $1.56 annually.
Material changes and segment results
- Utilities revenue increased $79.5 million year to date, primarily reflecting higher gas sales and colder winter weather. Utilities net income increased $8.1 million to $52.7 million for the first half.
- Gas Utilities first-half net income rose to $26.7 million from $21.7 million, supported by higher winter heating demand. Q2 net income declined to $2.0 million from $3.2 million as weather was milder year over year.
- Power Generation first-half net income increased to $15.3 million from $10.7 million, reflecting higher delivered volumes and prices and lower interest expense. Coal Mining net income rose to $4.5 million from $3.0 million.
- Oil and Gas reported a first-half net loss of $3.7 million versus $2.0 million. Revenue increased, but higher depletion, operating costs, and interest expense more than offset the improvement. Q2 loss narrowed to $1.7 million from $2.0 million.
- Corporate activities shifted from $17.4 million of first-half income in 2013 to a $0.8 million loss in 2014, principally because the prior-year period included the non-cash swap gain. The related de-designated swaps were settled in November 2013.
Outlook, management commentary, and risks
- Management stated that cash on hand, operating cash flow, borrowing capacity, and access to debt and equity financing were expected to be sufficient for operating needs, debt maturities, dividends, and planned capital spending. The filing does not provide a specific earnings guidance range.
- Cheyenne Prairie, a jointly owned 132 MW natural-gas facility, was expected to cost approximately $222 million and enter service in October 2014, at or below budget. Approximately $196 million had been spent by June 30. The utilities had agreements to issue $160 million of 30-year first mortgage bonds at coupons of 4.43% and 4.53%, with closing anticipated October 1, subject to customary conditions.
- Planned capital expenditures were $449.3 million for 2014, $391.3 million for 2015, and $346.9 million for 2016. Management noted that acquisitions and other growth opportunities could change spending.
- Regulatory proceedings could affect future revenue: Cheyenne Light received approval for annual electric and gas increases totaling $9.2 million effective October 1, 2014. Rate requests by Black Hills Power, Kansas Gas, and Colorado Electric remained pending at the filing date.
- The Oil Creek fire litigation remains a material contingency. The company recorded a liability for estimated probable settlement and litigation costs and a receivable for probable insurance recoveries; the amounts are not clearly stated in the provided filing text. Claims then totaled approximately $50 million. Additional losses were reasonably possible but not reasonably estimable; management did not expect the outcome to materially adversely affect consolidated results, financial condition, or cash flows.
- New environmental regulation is a risk: the EPA’s proposed Clean Power Plan could affect coal and gas generation and the coal mine. The rule was not final, and the company said it could not yet predict the operational impact. The filing also notes commodity-price, interest-rate, seasonal, and counterparty risks.
- Natural-gas gathering commitments in the Piceance Basin require minimum deliveries of 20,000 Mcf per day under a ten-year agreement. Management believed dedicated reserves and projected volumes would materially satisfy the commitment.
- Gas and electric utility results are seasonal. Management cautioned that interim results are not necessarily indicative of full-year results. The company reported effective disclosure controls and no material change in internal control over financial reporting.
Most important facts for investors to verify
- Whether Cheyenne Prairie reached service on schedule and within budget, and whether the planned $160 million bond issuance closed on expected terms.
- Progress and final outcomes of pending utility rate cases and the timing of approved or requested revenue increases.
- The accrued Oil Creek fire liability, insurance recovery receivable, remaining coverage, and any developments in claims or litigation.
- How the $275 million term loan due June 2015 was refinanced or repaid, and whether the company maintained covenant compliance and adequate revolver availability.
- Whether operating cash flow and capital spending support the planned investment program and dividend, particularly given the seasonal working-capital needs.
- Effects of weather, fuel and commodity prices, generation outages, and environmental rules on segment performance and future cash flows.