Black Hills Corporation — Q3 2013 Form 10-Q
Reporting period: Three and nine months ended September 30, 2013. Financial statements are unaudited; amounts below are in U.S. dollars. Black Hills operates regulated electric and gas utilities and non-regulated power generation, coal mining, and oil and gas businesses.
Financial results and position
- Revenue: Q3 revenue was $259.9 million, up 5.3% from $246.8 million. Nine-month revenue was $920.4 million, up 7.6% from $855.0 million.
- Profit and EPS: Q3 net income was $23.1 million ($0.52 diluted EPS), down from $34.5 million ($0.78) a year earlier. Nine-month net income was $96.8 million ($2.18 diluted EPS), up from $50.8 million ($1.15). The nine-month comparison includes discontinued-operations losses in 2012.
- Operating income and margins: Operating income was $55.6 million in Q3 versus $77.8 million; the prior-year quarter included a $27.3 million gain on asset sales. Nine-month operating income rose to $184.4 million from $168.4 million. Operating margin was approximately 21.4% for Q3 and 20.0% year to date; these calculations use reported revenue.
- Cash flow: Nine-month operating cash flow was $251.8 million, compared with $269.7 million. Capital expenditures were $239.5 million, and investing cash outflow was $236.6 million. Financing cash outflow was $17.0 million. Cash ended the period at $13.6 million, versus $15.5 million at year-end 2012 and $247.2 million in September 2012.
- Debt and liquidity: At September 30, notes payable were $138.3 million, current maturities of long-term debt were $255.7 million, and long-term debt was $956.0 million. The $500 million revolving facility had $138.3 million drawn, $53.1 million in letters of credit, and $308.6 million available. The company reported a 52.0% recourse leverage ratio against a covenant limit below 65.0% and stated it was in compliance.
- Dividends: Nine-month dividends were $1.14 per share. The board declared a quarterly dividend of $0.38 per share, payable December 1, 2013.
Changes versus the prior comparable period
- Q3 earnings declined primarily because 2012 included the $27.3 million Williston Basin asset-sale gain; 2013 Oil and Gas results also reflected lower production after that asset sale. Oil and Gas segment income shifted from $17.4 million to a $1.7 million loss for Q3.
- Nine-month earnings improved despite lower Oil and Gas volumes, helped by higher utility earnings, a $29.4 million non-cash unrealized interest-rate-swap gain (versus a $2.9 million loss in 2012), and the absence of the prior-year $26.9 million non-cash oil-and-gas impairment. The 2012 period also included the asset-sale gain.
- Utilities benefited from higher rates and Cheyenne Prairie construction-financing riders. Gas Utilities’ nine-month results also benefited from colder weather: heating degree days were 33% higher than in 2012 and 8% above normal.
- Cash from investing changed from $98.3 million provided in 2012 to $236.6 million used in 2013, largely because the prior year included proceeds from asset sales. Debt was refinanced with a new $275 million term loan due June 2015.
Outlook, management commentary, risks and unusual items
- Management said cash on hand, operating cash flows, borrowing capacity, and access to debt and equity markets were expected to provide sufficient resources for operating needs, debt maturities, dividends, and planned capital expenditures. No specific earnings guidance was provided.
- Planned 2013 capital expenditures were $443.2 million; actual expenditures for the first nine months were $251.5 million. Cheyenne Prairie, a 132 MW gas-fired facility, was expected to cost about $222 million and enter service in the fourth quarter of 2014; approximately $122 million had been spent by September 30.
- Management was considering refinancing $250 million of 9% senior unsecured notes due May 2014, settling some or all de-designated interest-rate swaps, and arranging long-term financing for Cheyenne Prairie.
- Interest-rate swaps are a significant earnings and liquidity sensitivity: the $250 million notional de-designated swaps generated a $29.4 million nine-month non-cash gain but had a $58.8 million liability at quarter-end. Management noted subsequent mark-to-market changes could materially affect results. Approximately $6.0 million of cash collateral was posted.
- Seasonality and weather affect utility demand and earnings; commodity prices affect Oil and Gas cash flows. The company also cited capital-project execution, regulatory requirements, financing-market access, and natural disasters as risks. Utility cash distributions are restricted, with approximately $148.6 million of restricted net assets in the Utilities Group.
- Thirty-four landowners sued over the 2012 Oil Creek fire, seeking actual and punitive damages in unspecified amounts; the company said a loss was reasonably possible but could not estimate it, and did not expect an adverse outcome to materially affect results or financial condition. A separate state and landowner claim was approximately $8 million. Enserco sale-price disputes remained in arbitration.
- The planned sale of the 40 MW CTII generating unit to Gillette for approximately $22 million, expected in August 2014, remained subject to FERC approval and other conditions. The company also identified potential sale of its Wygen I interest as subject to approvals if the purchase option is exercised.
- Credit ratings were upgraded during 2013: Moody’s to Baa2 with a positive outlook, S&P to BBB with a stable outlook, and Fitch to BBB with a positive outlook.
Important facts for investors to verify
- How much of nine-month earnings growth came from non-cash swap gains, tax adjustments, and prior-year unusual items, and what underlying earnings trend remains?
- Progress, final cost, financing, and regulatory recovery for Cheyenne Prairie, including whether the 2014 in-service schedule is maintained.
- Refinancing plan for the $250 million 9% notes due May 2014 and any cash settlement, extension, or collateral needs relating to de-designated swaps.
- Outcome and potential financial exposure from the Oil Creek fire litigation and Enserco purchase-price arbitration.
- Oil and Gas production, commodity prices, and hedging performance following the Williston Basin asset sale.
- Cash availability, covenant headroom, subsidiary dividend restrictions, and whether planned capital spending and dividends remain supportable.