NORTHERN OIL & GAS, INC. annual report, FY2015

Northern Oil & Gas, Inc. — FY 2015 Form 10-K

Reporting period: Fiscal year ended December 31, 2015. The filing also provides unaudited quarterly results; fourth-quarter revenue was $56.9 million and net loss was $172.3 million. Northern is a non-operating oil and gas producer focused on Bakken and Three Forks properties in the Williston Basin of North Dakota and Montana.

Key financial and operating metrics

Metric	FY 2015	Prior comparable period
Total revenue, including derivative gains	$275.1 million	$595.0 million in 2014
Oil and gas sales, excluding derivative gains	$202.6 million	$431.6 million in 2014
Operating income (loss)	$(1,119.4) million	$305.2 million in 2014
Net income (loss)	$(975.4) million	$163.7 million in 2014
Adjusted net income (non-GAAP)	$47.6 million	$57.5 million in 2014
Adjusted EBITDA (non-GAAP)	$277.3 million	$309.6 million in 2014
Cash from operating activities	$247.0 million	$274.3 million in 2014
Cash used in investing activities	$(288.9) million	$(477.0) million in 2014
Cash and cash equivalents at year-end	$3.4 million	$9.3 million in 2014
Total debt at year-end	$847.8 million carrying value	$806.1 million in 2014

Unless otherwise stated, dollar amounts are U.S. dollars. Revenue and earnings figures are GAAP; adjusted net income and adjusted EBITDA are company-defined non-GAAP measures.

• Production: 5.94 million Boe, up 3% year over year; average production was 16,285 Boe per day. Oil represented approximately 87% of production.
• Realized pricing: Average oil price before settled derivatives fell 52% to $37.77 per barrel. Including settled derivatives, realized price was $61.19 per Boe, down 17% from 2014. The company recorded $161.1 million of cash gains on settled derivatives.
• Margins and costs: Production expense was $8.77 per Boe, compared with $9.66 in 2014. GAAP results were dominated by the impairment charge; the filing does not present a single comparable operating-margin figure.
• Liquidity: Working capital surplus was $50.7 million, versus a $59.7 million deficit in 2014. The $550 million credit-facility borrowing base had $150 million drawn and $400 million available. Management described total liquidity, including facility availability, as approximately $403.4 million.
• Debt: Year-end debt comprised $150 million drawn on the revolving facility and $697.8 million carrying value of 8% senior notes; the notes had $700 million aggregate principal. The revolver matures in September 2018 and the notes in June 2020. Interest expense was $58.4 million, up from $42.1 million in 2014.
• Reserves: Proved reserves were 65.3 million Boe, down 35% from 100.7 million Boe in 2014. Approximately 65% were proved developed and 87% were oil. SEC-price PV-10 was $575.7 million; the standardized measure was $574.8 million.

Material changes versus 2014

• Total revenue fell 54%, principally reflecting lower commodity prices and a smaller derivative gain. Oil and gas sales excluding derivative gains declined 53%; production increased 3%.
• Northern recorded a $1.164 billion non-cash full-cost ceiling impairment, compared with none in 2014. This drove the reported net loss and reduced property values and stockholders’ equity, but did not directly reduce cash flow.
• Capital spending fell 76% to $289.1 million of cash expenditures. The company completed 292 gross (18.6 net) wells, down from 589 gross (41.6 net) in 2014.
• Debt increased by approximately $41.7 million on a carrying-value basis. The company issued $200 million principal of additional 8% notes in 2015 and reduced revolver borrowings by $148 million net during the year.
• Year-end stockholders’ equity of $770.9 million in 2014 became a deficit of $197.6 million in 2015, primarily following the impairment and resulting loss.
• Proved undeveloped reserves fell from 49.7 million to 23.1 million Boe, chiefly from lower-price assumptions and revisions to expected development.

Outlook, commentary, and risks

• The board approved a 2016 capital expenditure budget of up to $99.8 million. Spending is discretionary and may be reduced or deferred based on prices, cash flow, costs, returns, and financing availability. Management said it intended to prioritize liquidity and develop within available cash flows if low prices persisted.
• Management believed operating cash flow and revolver availability would be sufficient for budgeted spending and operating needs over the next 12 months, while warning that lower prices could reduce the borrowing base and capital spending. The borrowing base was subject to lender redetermination, including scheduled reviews in April and October.
• Year-end oil swaps covered 1.8 million barrels for 2016 at a weighted average price of $77.50 per barrel; no barrels were hedged for 2017 or later. Derivatives were not designated for hedge accounting, so fair-value changes affected reported earnings. The year-end derivative asset was $64.6 million, versus $153.3 million net a year earlier.
• The company’s 2016 PUD plan included 12.5 net wells; the longer-term plan called for 48.8 net PUD wells through 2020 at an estimated $328.4 million. Development depends on operator activity, economics, capital availability, and lease retention.
• Key risks include volatile oil and gas prices; further non-cash impairments; lender-driven borrowing-base reductions and covenant compliance; high leverage and interest costs; dependence on third-party operators; reserve-estimate uncertainty; transportation constraints and price differentials; and environmental, hydraulic-fracturing, and climate-related regulation.
• Other notable items: a $232.3 million valuation allowance was recorded against deferred tax assets; federal NOL carryforwards were estimated at $524.9 million. A North Dakota quiet-title judgment adverse to the company led to a $1.7 million revenue reduction. The company reported ordinary-course litigation and stated it did not expect other such matters to materially affect its financial position, results, or cash flows.
• Management reported effective disclosure controls and internal control over financial reporting; the independent auditor issued unqualified opinions on the 2015 financial statements and internal controls. No formal production or earnings guidance is stated in the provided filing text.

Important facts for investors to verify

1. Subsequent borrowing-base redeterminations, covenant headroom, and liquidity under sustained low commodity prices.
2. The cash-flow assumptions and reserve revisions underlying the $1.164 billion impairment, and the potential for further ceiling-test write-downs.
3. Realized oil prices, transportation differentials, production trends, and actual cash proceeds from 2016 hedges as contracts settle.
4. Whether planned capital spending and PUD development can be funded while replacing natural production declines and retaining expiring acreage.
5. Debt terms, interest burden, refinancing needs, and the market value of the senior notes relative to carrying value.
6. Operator and receivable concentration, including collection risks and exposure to financial distress among operating partners.