BLACK HILLS CORP annual report, FY2014

Black Hills Corporation — FY 2014 Form 10-K

Reporting period: Year ended December 31, 2014; quarterly figures below compare the fourth quarter of 2014 with the fourth quarter of 2013. Black Hills is a U.S. energy company with regulated electric and gas utilities and non-regulated power generation, coal mining, and oil and gas operations.

Financial performance

Metric	FY 2014	FY 2013
Total revenue	$1.394 billion	$1.276 billion
Operating income	$260.5 million	$255.6 million
Net income available to common shareholders	$128.8 million	$115.0 million
Diluted EPS	$2.89	$2.59
Cash from operating activities	$323.5 million	$324.6 million
Capital expenditures	$391.3 million	$379.5 million

Operating margin was approximately 18.7%, compared with 20.0% in 2013. Cash from operations less cash property additions was approximately negative $75 million. The filing presents gross margin as a non-GAAP measure; regulated Gas Utilities gross margin rose to $236.9 million from $229.2 million, while Electric Utilities gross margin rose to $382.7 million from $371.3 million.

Fourth quarter: Revenue was $378.1 million versus $355.4 million; operating income was $70.0 million versus $71.1 million; and net income was $34.0 million versus $18.1 million. Diluted EPS was $0.76 versus $0.41. The prior-year quarter included debt-refinancing and swap-settlement costs as well as swap mark-to-market gains.

Segments and changes versus prior year

Utilities: FY net income was $101.4 million, up from $84.8 million. Gas Utilities benefited from customer growth, higher transport volumes and colder first-quarter weather. Electric Utilities gained from new investment and Cheyenne Prairie, partly offset by weak summer cooling demand; annual cooling degree days were 29% below 2013.
Power Generation: Net income increased to $28.5 million from $16.3 million, mainly reflecting higher generation revenue and lower interest expense after refinancing.
Coal Mining: Net income rose to $10.5 million from $6.3 million. Sales volume was broadly stable, while higher coal prices lifted revenue; mining in areas with higher overburden raised costs.
Oil and Gas: Net loss widened to $10.6 million from $4.2 million. Revenue was nearly flat, but operating costs and depletion increased. Production rose about 5% to 10.0 Bcfe, and proved reserves increased to 101.4 Bcfe from 86.7 Bcfe; reserve additions included estimated NGL volumes reported separately for the first time.
Consolidated interest expense fell approximately $41 million, primarily following 2013 refinancing. The 2013 comparison also included a $20 million after-tax unrealized swap gain and other refinancing-related charges; FY 2014 had no comparable items identified by management as non-core.

Financial position and liquidity

At year-end, cash and cash equivalents were $21.2 million; current assets were $454.0 million and current liabilities were $651.3 million.
Debt comprised $275 million of current maturities, $75 million of notes payable and $1.268 billion of long-term debt, net of current maturities. Stockholders’ equity was $1.376 billion. Total debt was approximately $1.618 billion.
The $500 million revolving credit facility runs through May 2019. At year-end, $75 million was borrowed and $35 million of letters of credit were outstanding, leaving $390 million available. The company reported compliance with its debt covenants.
Operating cash flow was $323.5 million; investing cash outflow was $401.1 million and financing cash inflow was $91.1 million. The company cites operating cash flow, borrowing capacity and access to debt markets as sources for operations and planned investment.
The $275 million corporate term loan was due in June 2015. Planned capital expenditures were approximately $457 million in each of 2015 and 2016, and $390.2 million in 2017. Management said it did not anticipate needing equity-market funding in the next three years, based on its current capital plan.
The board declared a quarterly dividend of $0.405 per share in January 2015, equivalent to $1.62 annualized; 2014 dividends paid were $1.56 per share.

Outlook, risks and unusual items

Management’s strategy emphasizes regulated utility investment, customer and utility acquisitions, long-term contracted power generation, and selective oil and gas development. It provided capital spending plans but no specific consolidated earnings guidance in the supplied filing text.
Cheyenne Prairie, a 132 MW natural-gas plant costing about $222 million, entered service in October 2014 on time and on budget. The company issued $160 million of 30-year first mortgage bonds to provide permanent financing. A South Dakota utility rate case remained pending, with a decision expected in the first quarter of 2015.
Management said continued low oil and gas prices could make a full-cost ceiling impairment probable in 2015. No ceiling-test write-down was recorded in 2014; the filing does not quantify a potential future charge.
The IRS challenged the company’s deferred tax treatment of a prior like-kind exchange. The filing describes a worst-case acceleration of approximately $88 million in current tax liability, plus estimated interest of about $19 million before tax effects; the company disputes the IRS position.
Claims related to the 2012 Oil Creek fire totaled $55 million. The company recorded a loss contingency and a probable insurance-recovery receivable, but said additional reasonably possible losses could not be estimated. Management did not expect the matter to materially adversely affect consolidated financial condition, results or cash flows.
Environmental and regulatory risks include proposed federal greenhouse-gas rules, possible air-emission controls, coal-ash requirements and possible unrecovered compliance costs. The company estimated $8.3 million of environmental compliance capital spending for 2015–2017, excluding plant closures and new generation. A potential Wyodak emissions-control requirement was estimated at $20 million for the company’s share and had been stayed pending appeal.
Other notable exposures include a ten-year Piceance gathering and processing contract with a 20,000 Mcf-per-day minimum payment, weather and commodity-price volatility, utility rate recovery, cyber and operational risks, and a 2015 increase in expected pension cost to $13.2 million from $8.1 million.
The independent auditor issued unqualified opinions on the financial statements and internal controls; management also reported effective internal control over financial reporting.

Most important facts for investors to verify

Whether the pending South Dakota rate case and other regulatory mechanisms support recovery of Cheyenne Prairie and future capital investment.
The refinancing or repayment plan for the $275 million term loan due June 2015, and funding capacity for the planned capital program and dividends.
Oil and gas reserve economics and impairment sensitivity to lower commodity prices, including the new NGL reporting basis and the Piceance minimum-volume commitment.
Progress and potential financial exposure in the IRS tax dispute and Oil Creek fire claims, including the scope of insurance recoveries.
Final requirements and cost recovery for greenhouse-gas, air-quality and coal-ash regulations, and the implications for coal assets and generation economics.