Northern Oil & Gas, Inc. — FY 2014 Form 10-K
Reporting period: Fiscal year ended December 31, 2014; filed February 27, 2015. The filing reports full-year results, with quarterly data also showing a significant fourth-quarter derivative valuation gain.
Business context
Northern is an independent oil and gas producer focused primarily on non-operated working interests in the Bakken and Three Forks formations of the Williston Basin in North Dakota and Montana. At year-end, it held 185,018 net acres and interests in 2,338 gross (185.7 net) producing wells. The company participated in completing 589 gross (41.6 net) wells during 2014.
Financial and operating results
| Metric | FY 2014 | FY 2013 |
|---|---|---|
| Oil and gas sales | $431.6 million | $369.2 million |
| Total revenue, including derivative mark-to-market | $595.0 million | $335.8 million |
| Operating income | $305.2 million | $118.0 million |
| Net income | $163.7 million | $53.1 million |
| Diluted EPS | $2.69 | $0.85 |
| Operating cash flow | $274.3 million | $222.8 million |
| Investing cash flow | $(477.0) million | $(358.5) million |
- Production rose 29% to 5.76 million Boe. Average realized price, including settled derivative effects, fell 8% to $73.51/Boe; oil price differential to NYMEX widened to $13.67/barrel from $8.68.
- Production expense was $9.66/Boe versus $9.35; DD&A was $29.99/Boe versus $27.79. Interest expense increased to $42.1 million from $32.7 million.
- The $171.3 million unrealized mark-to-market derivative gain was a major driver of reported revenue and net income; derivatives were not designated for hedge accounting. Adjusted net income, a non-GAAP measure, declined to $57.5 million ($0.95 diluted share) from $66.4 million ($1.06).
- Net cash used in investing exceeded operating cash flow by approximately $202.8 million. Year-end cash was $9.3 million.
- Year-end total debt was approximately $806.1 million: $298 million drawn on the revolving facility and about $508.1 million in 8% senior notes. The company reported $252 million of remaining facility availability, against a $550 million borrowing base. Debt to total capitalization was reported at 51%.
- Current assets were $226.0 million and current liabilities $285.7 million. Current assets include $128.9 million of derivative assets. The balance sheet also reports $85.9 million of trade receivables, net of allowance.
Reserves and changes versus prior year
- Proved reserves increased 20% to 100.7 MMBoe; 88% were oil and 51% were proved developed. Proved developed reserves grew 44%, while proved undeveloped reserves grew only 2% to 49.7 MMBoe.
- Reserve growth reflected drilling and completions, but PUD revisions were negative 13.0 MMBoe, primarily due to lower price assumptions, higher operating costs and reduced planned development. Reserve replacement was reported at 388% of 2014 production.
- Pre-tax PV-10 was $1.70 billion; the GAAP standardized measure of discounted future net cash flows was $1.41 billion. These are reserve-based estimates, not market valuations, and exclude the value of commodity derivatives.
- Oil and gas property capital expenditures were $476.9 million, up from $360.1 million in 2013. Total reported revenue rose 77%, but oil and gas sales grew 17%; the difference principally reflects the derivative mark-to-market swing from a $21.3 million loss in 2013 to a $171.3 million gain in 2014.
Outlook, risks and unusual items
- Management budgeted approximately $140 million of 2015 capital expenditures: $120 million for drilling and completion and $20 million for acreage, workovers and other items. It said it would be more selective on capital deployment and reduce commitments where possible amid low commodity prices.
- Management expected sufficient liquidity for budgeted spending and operating costs over the next 12 months, using operating cash flow, cash and bank borrowings. It also cautioned that acquisitions or increased drilling could require additional capital; funding for the next 24 months was less certain.
- Year-end oil hedges covered 3.96 million barrels for 2015 at a weighted average $89.43/barrel and 0.90 million barrels for 2016 at $90.00/barrel. Lower prices can still reduce unhedged revenue and lenders’ reserve-based borrowing capacity.
- The company warned that lower trailing-average commodity prices could trigger a noncash full-cost ceiling-test write-down in 2015. No ceiling impairment was recorded at December 31, 2014, using SEC prices based on the prior 12 months.
- Management’s five-year PUD development plan called for 137.7 net wells at an estimated $1.2 billion, including 6.7 net wells in 2015. The 2015 operating budget is substantially below that multiyear estimate.
- Key risks include commodity-price volatility, reliance on third-party operators, transportation constraints and price differentials, reserve-estimation uncertainty, lease expirations, borrowing-base reductions, debt covenants, environmental and hydraulic-fracturing regulation, and possible impairment. Approximately 22,029 net undeveloped acres were potentially expiring in 2015.
- Routine litigation was not expected by management to materially affect results. A North Dakota quiet-title case could require reversal of approximately $1.7 million of accrued revenue, net of taxes, if decided adversely; the company said it was defending its interest. 2014 G&A included $0.6 million of dispute-settlement expense.
- The filing reports effective disclosure controls and internal control over financial reporting; Deloitte issued unqualified opinions on the financial statements and internal controls.
Most important facts for investors to verify
- How much reported earnings and revenue depend on noncash derivative valuation changes, versus realized operating performance and cash generation.
- The company’s borrowing-base and covenant headroom after subsequent commodity-price movements and lender redeterminations.
- Whether the 2015 capital budget, well participation and PUD development plans remain achievable under the lower-price environment.
- The sensitivity of reserves, PV-10 and full-cost ceiling-test impairment to prices, operating costs, reserve revisions and development timing.
- Hedge volumes, counterparties, settlement terms and exposure to production shortfalls or changes in regional price differentials.
- Progress on lease extensions and development of acreage facing expiration, and the outcome of the quiet-title action.