NORTHERN OIL & GAS, INC. quarterly report, Q3 FY2015

Northern Oil and Gas, Inc. — Q3 2015 Form 10-Q

Reporting period: Quarter and nine months ended September 30, 2015. Northern is a non-operating oil and gas producer focused on the Bakken and Three Forks formations in North Dakota and Montana. It held approximately 169,020 net acres, about 70% developed, and reported average Q3 production of 15,844 Boe per day, approximately 87% oil.

Financial performance and position

Metric	Q3 2015	Q3 2014	Nine months 2015	Nine months 2014
Oil and gas sales	$49.8 million	$119.2 million	$163.3 million	$337.1 million
Total revenue, including derivative gains	$101.2 million	$180.8 million	$218.1 million	$337.5 million
Operating income (loss)	$(307.2) million	$103.6 million	$(963.2) million	$127.4 million
Net income (loss)	$(323.2) million	$58.0 million	$(803.0) million	$60.2 million
Operating cash flow	Not presented for quarter	Not presented for quarter	$174.8 million	$209.4 million

Q3 oil and gas sales fell 58% year over year, reflecting a 57% decline in realized prices before settled derivatives and a 4% decline in production. Nine-month production rose 9%, but sales excluding settled derivatives fell 52% as prices declined.
Q3 realized price including settled derivative settlements was $63.62 per Boe, down 14% year over year; nine-month realized price was $61.63 per Boe, down 19%.
Reported results include non-cash ceiling-test impairments of $354.4 million in Q3 and $996.8 million for the nine months, driven by low commodity prices. The impairments reduced earnings and asset carrying values, but not cash flow. The filing does not present a conventional gross-margin figure.
Q3 adjusted EBITDA, a non-GAAP measure, was $71.7 million versus $81.4 million; nine-month adjusted EBITDA was $209.6 million versus $228.0 million. Adjusted net income was $14.6 million for Q3 and $32.1 million for nine months, down from $15.6 million and $44.7 million, respectively.
Nine-month investing cash outflow was $233.2 million, principally for oil and gas properties; financing provided $56.1 million. Cash declined $2.3 million to $7.0 million. Operating cash flow was below the prior-year period.
At September 30, cash was $7.0 million, working capital was positive $32.8 million, total debt was $867.7 million, and stockholders’ equity was a deficit of $28.3 million. The balance sheet reported total assets of $1.00 billion.
Debt included $170 million outstanding on the revolving facility and $700 million principal amount of 8% senior notes due 2020 (carrying value $697.7 million). The facility borrowing base was reaffirmed at $550 million in October, leaving $380 million of availability after the reported revolver balance. The company reported covenant compliance at quarter-end.

Material changes versus comparable periods

Lower commodity prices drove steeply lower sales and a $996.8 million year-to-date impairment; there was no comparable impairment in 2014. NYMEX oil averaged $46.50 per barrel in Q3 2015 versus $97.25 a year earlier.
Q3 production declined 4% year over year as lower completion activity and declines from existing wells outweighed additions. Nine-month production increased 9%, supported by a larger beginning well-in-process inventory and new wells.
The 2015 capital expenditure budget was approximately $140 million, 74% below 2014 actual expenditures. Nine-month cash spending on drilling, completion, acreage and other capital items was $233.4 million; capitalized costs incurred were lower, at $105.4 million.
Interest expense rose to $42.3 million for the nine months from $30.9 million, reflecting increased borrowings, the May 2015 notes issuance and lower capitalized interest. Total debt increased from $806.1 million at year-end 2014 to $867.7 million.
The company recorded a $170.0 million valuation allowance against net deferred tax assets, citing cumulative losses and commodity-price uncertainty; no allowance was recorded at December 31, 2014.

Outlook, risks, and unusual items

Management said available revolver capacity, anticipated cash reserves and operating cash flow should fund budgeted capital expenditures and operating expenses for at least the next 12 months. Significant acquisitions or increased drilling could require additional capital; availability and terms are not assured.
Management expected continued property write-downs if low prices persist, until the trailing 12-month average prices used in the ceiling test stabilize or recover. Future impairment also depends on production, reserves, development costs and other assumptions.
At September 30, open oil swaps covered approximately 990,000 barrels for 2015 at a weighted average $89.82 per barrel and 1.8 million barrels for 2016 at $77.50. Total open swaps were 2.8 million barrels. These derivatives support cash-flow predictability but can limit participation in price increases; fair value was a net asset of $94.2 million. A portion of contracts had counterparty extension options.
Commodity-price volatility, unhedged production, reserve-based borrowing-base redeterminations, interest rates, Williston Basin transportation capacity and weather are material risks. Management noted that sustained low prices could reduce cash flow, borrowing capacity and access to capital.
September restructuring included workforce reductions and closure of the Denver office. Costs were $0.5 million, with substantially all one-time costs expected by March 31, 2016; management did not expect a material cash-flow or earnings effect.
A North Dakota quiet-title action could require reversal of approximately $1.7 million in revenue, net of accrued taxes, if judgment is adverse; the company said it is vigorously defending its lease interest. Other ordinary-course proceedings were not expected by management to materially affect financial position, results or cash flows.
Management reported effective disclosure controls as of September 30, 2015 and no material change in internal control over financial reporting during the quarter.

Important facts for investors to verify

Whether subsequent ceiling-test impairments, reserve revisions or lower commodity prices further affect asset values, earnings and borrowing capacity.
Hedge volumes, realized settlements, fair-value changes, contract extension options and the proportion of future production left unhedged.
Liquidity and covenant headroom after borrowing-base redeterminations, including the timing of capital spending and accounts payable.
The assumptions supporting the $170.0 million deferred-tax valuation allowance and any future changes in realizability.
Progress and possible financial effect of the quiet-title litigation, and completion of restructuring actions.
Non-GAAP adjusted EBITDA and adjusted net income reconciliations alongside GAAP results; these measures exclude significant impairment and derivative mark-to-market effects.