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| 8-K - 8-K - NORTHERN OIL & GAS, INC. | a8k-march12017.htm |
Exhibit 99.1
Northern Oil and Gas, Inc. Announces 2016 Fourth Quarter and Full Year Results
MINNETONKA, MINNESOTA - March 1, 2017 - Northern Oil and Gas, Inc. (NYSE MKT: NOG) today announced 2016 fourth quarter and full year results.
HIGHLIGHTS
• | Average 90-day initial production rate on Northern’s wells using enhanced completions increased 47% in 2016 as compared to 2015 |
• | Completed $8.9 million property acquisition in the fourth quarter that added 375 barrels of oil per day since the date of acquisition |
• | Full year 2016 capital expenditures, excluding the fourth quarter property acquisition, totaled $75.6 million or a 41.3% decrease as compared to 2015 |
• | Production totaled 1,259,274 barrels of oil equivalent (“Boe”) for the fourth quarter, averaging 13,688 Boe per day or 2% higher than last quarter, despite down-time due to weather during December |
• | Ended the year with $212.5 million of liquidity, composed of $6.5 million in cash and $206.0 million of revolving credit facility availability |
Northern’s adjusted net income for the fourth quarter was $2.4 million, or $0.04 per diluted share. GAAP net loss for the quarter was $12.3 million, or a loss of $0.20 per diluted share. Adjusted EBITDA for the fourth quarter was $35.1 million. See “Non-GAAP Financial Measures” below for additional information on these measures.
MANAGEMENT COMMENT
“Northern performed well in 2016 given the challenging commodity price environment and was free cash flow positive for the year,” commented Northern’s Interim CEO and CFO, Tom Stoelk. “Northern has seen significant improvements in well productivity due to the widespread adoption of enhanced completion techniques and focus of drilling activity in the core of the play. At the same time, average drilling and completion costs have declined, with average AFE costs of $7.0 million for wells that we elected to participate in during 2016.”
Mr. Stoelk continued, “We remain focused on returns and disciplined capital allocation, which will position us to return to growth as development activity increases in the Williston Basin.”
2017 GUIDANCE
Northern expects 2017 total annual production to equal or modestly exceed 2016 total production. Northern expects that it will add approximately 12 net wells to production during the year, based on a preliminary capital budget of $102.2 million (including acreage and development capital). Due to winter weather and the potential for road restrictions during the spring, completions are expected to be weighted to the second half of 2017. Management’s current expectations for 2017 operating metrics are as follows:
2017 | ||
Operating Expenses: | ||
Production Expenses (per Boe) | $9.00 - $9.30 | |
Production Taxes (% of Oil & Gas Sales) | 10% | |
General and Admin. Expense (per Boe) | $3.25 - $3.75 | |
Average Differential to NYMEX WTI | $7.00 - $9.00 | |
LIQUIDITY
At December 31, 2016, Northern had $144 million in outstanding borrowings under its revolving credit facility, down from $150 million at December 31, 2015. Northern’s borrowing base under the revolving credit facility was $350 million, providing year-end liquidity of $212.5 million, composed of $6.5 million in cash and $206.0 million of revolving credit facility availability.
HEDGING
Northern hedges portions of its expected production volumes to increase the predictability of its cash flow and to help maintain a strong financial position. The following table summarizes Northern’s open crude oil derivative contracts scheduled to settle after December 31, 2016.
Swaps | Collars | |||||||
Contract Period | Volume (Bbls) | Weighted Average Price (per Bbl) | Volume (Bbls) | Weighted Average Price (per Bbl) | ||||
2017: | ||||||||
1Q | 630,000 | $51.74 | 75,000 | $50.00 - $60.06 | ||||
2Q | 631,000 | $51.75 | 75,000 | $50.00 - $60.06 | ||||
3Q | 632,000 | $53.36 | 75,000 | $50.00 - $60.06 | ||||
4Q | 632,000 | $53.36 | 75,000 | $50.00 - $60.06 | ||||
2018: | ||||||||
1Q | 270,000 | $54.40 | 90,000 | $50.00 - $60.25 | ||||
2Q | 271,000 | $54.40 | 90,000 | $50.00 - $60.25 | ||||
3Q | 272,000 | $54.41 | 90,000 | $50.00 - $60.25 | ||||
4Q | - | - | 90,000 | $50.00 - $60.25 | ||||
CAPITAL EXPENDITURES & DRILLING ACTIVITY
Fourth Quarter 2016 | Full Year 2016 | |||
Capital Expenditures Incurred: | ||||
Drilling, Completion & Capitalized Workover Expense | $23.0 million | $67.2 million | ||
Acreage | $0.6 million | $4.8 million | ||
Other | $1.5 million | $3.6 million | ||
Fourth Quarter Property Acquisition | $8.9 million | $8.9 million | ||
Net Wells Added to Production | 5.1 | 10.7 | ||
Net Producing Wells (Period-End) | 213.1 | 213.1 | ||
Net Wells in Process (Period-End) | 13.4 | 13.4 | ||
Average AFE for In-Process Wells (Period-End) | $7.4 million | $7.4 million | ||
For 2016, the weighted average authorization for expenditure (or AFE) cost for wells that Northern elected to participate in (consented) was $7.0 million.
ACREAGE
As of December 31, 2016, Northern controlled 155,016 net acres targeting the Williston Basin Bakken and Three Forks formations. As of December 31, 2016, approximately 83% of Northern’s North Dakota acreage position, and approximately 80% of Northern’s total acreage position, was developed, held by production or held by operations.
2016 YEAR-END RESERVES
Based on reports prepared by Ryder Scott Company, L.P., Northern’s estimated proved reserves at December 31, 2016 totaled 54.1 million barrels of oil equivalent (MMBoe). Approximately 70% of year-end 2016 proved reserves were proved developed reserves and 86% of year-end 2016 proved reserves were crude oil. Although year-end 2016 proved reserves were 11.2 MMBoe lower than year-end 2015 proved reserves, this was primarily due to a 15.7 MMBoe decrease attributable to the lower SEC 2016 price deck compared to the SEC 2015 price deck.(1) The decrease from the lower price deck was partially offset by 3.7 MMBoe of favorable performance revisions and 8.4 MMBoe in discoveries, extensions and other additions. Due to lower commodity
prices and lower capital spending in 2016, the number of proved undeveloped net well locations included in the year-end proved reserves was reduced to 32.6 net wells in 2016 due to the 5-year rule requirements in the SEC regulations applicable to booking proved undeveloped reserves. However, see “Undeveloped Properties Inventory” below regarding Northern’s internal estimates of its undeveloped well inventory, which Northern believes significantly exceeds the number of locations included in its proved undeveloped reserves estimated by Ryder Scott.
(1) | The SEC 2016 reserve price deck was $42.75 per barrel of oil and $2.49 per MMBtu of gas. The SEC 2015 reserve price deck was $50.28 per barrel of oil and $2.58 per MMBtu of gas. |
UNDEVELOPED PROPERTIES INVENTORY
Based on internally prepared reserves at December 31, 2016, Northern estimates the number of economic net well locations in its undeveloped well inventory under various commodity price assumptions is as follows:
Pricing Assumptions After Adjustment for Transportation and Quality Differentials | Net Number of Undeveloped Economic Locations | |||
Oil (per Bbl) | Natural Gas (per MMBtu) | |||
$35.24 | $1.67 | 218 | ||
$45.24 | $1.67 | 332 | ||
$55.24 | $1.67 | 478 | ||
FOURTH QUARTER 2016 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
Three Months Ended December 31, | ||||||||||
2016 | 2015 | % Change | ||||||||
Net Production: | ||||||||||
Oil (Bbl) | 1,063,535 | 1,263,864 | (16) | |||||||
Natural Gas and NGLs (Mcf) | 1,174,434 | 1,092,022 | 8 | |||||||
Total (Boe) | 1,259,274 | 1,445,867 | (13) | |||||||
Average Daily Production: | ||||||||||
Oil (Bbl) | 11,560 | 13,738 | (16) | |||||||
Natural Gas and NGL (Mcf) | 12,766 | 11,870 | 8 | |||||||
Total (Boe) | 13,688 | 15,716 | (13) | |||||||
Average Sales Prices: | ||||||||||
Oil (per Bbl) | $ | 41.83 | $ | 29.96 | 40 | |||||
Effect of Gain on Settled Derivatives on Average Price (per Bbl) | 6.65 | 37.32 | (82 | ) | ||||||
Oil Net of Settled Derivatives (per Bbl) | 48.48 | 67.28 | (28) | |||||||
Natural Gas and NGLs (per Mcf) | 2.21 | 1.35 | 64 | |||||||
Realized Price on a Boe Basis Including all Realized Derivative Settlements | 43.00 | 59.83 | (28) | |||||||
Costs and Expenses (per Boe): | ||||||||||
Production Expenses | $ | 9.31 | $ | 8.15 | 14 | |||||
Production Taxes | 3.56 | 2.93 | 22 | |||||||
General and Administrative Expense | 2.97 | 4.02 | (26) | |||||||
Depletion, Depreciation, Amortization and Accretion | 10.74 | 16.70 | (36) | |||||||
Net Producing Wells at Period End | 213.1 | 204.3 | 4 | |||||||
Oil and Natural Gas Sales
In the fourth quarter of 2016, oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 20% as compared to the fourth quarter of 2015, driven by a 40% increase in average oil sales prices that was partially offset by a 13% decline in production levels due to inclement weather in December 2016 and lower overall capital spending in 2016. The higher average realized price per Boe, excluding the effect of settled derivatives, in the fourth quarter of 2016 as compared to the fourth quarter of 2015 was primarily driven by higher NYMEX oil and gas prices and a lower oil differential. Oil price differential during the fourth quarter of 2016 was $7.46 per barrel, as compared to $8.30 per barrel in the fourth quarter of 2015.
Derivative Instruments (Hedges)
Northern enters into derivative instruments to manage the price risk attributable to future oil production. Gain (loss) on derivative instruments, net is comprised of (i) cash gains and losses recognized on settled derivatives during the period, and (ii) non-cash mark-to-market gains and losses incurred on derivative instruments outstanding at period-end.
Three Months Ended December 31, | |||||||
2016 | 2015 | ||||||
(in millions) | |||||||
Derivative Instruments (Hedges): | |||||||
Cash Derivative Settlements | $ | 7.1 | $ | 47.2 | |||
Non-Cash Mark-to-Market of Derivative Instruments | (18.2) | (29.6) | |||||
Gain (Loss) on Derivative Instruments, Net | $ | (11.1 | ) | $ | 17.6 | ||
Northern’s average realized price, including all cash derivative settlements, received during the fourth quarter of 2016 was $43.00 per Boe compared to $59.83 per Boe in the fourth quarter of 2015. The gain on settled derivatives increased Northern’s average realized price per Boe by $5.62 in the fourth quarter of 2016 and by $32.62 in the fourth quarter of 2015. As a result of forward oil price changes, Northern recognized a non-cash mark-to-market derivative loss of $18.2 million in the fourth quarter of 2016, compared to a loss of $29.6 million in the fourth quarter of 2015.
Production Expenses
Production expenses were $11.7 million in the fourth quarter of 2016, compared to $11.8 million in the fourth quarter of 2015. On a per unit basis, production expenses increased to $9.31 per Boe in the fourth quarter of 2016 from $8.15 per Boe in the fourth quarter of 2015 due to a 13% decline in production levels over which fixed costs are spread. Although the total net producing well count increased by 4%, aggregate production expenses declined due to reductions in contract labor and maintenance costs.
Production Taxes
Production taxes were $4.5 million in the fourth quarter of 2016 compared to $4.2 million in the fourth quarter of 2015. As a percentage of oil and natural gas sales, production taxes were 9.5% and 10.8% in the fourth quarter of 2016 and 2015, respectively. This decrease in production tax rates as a percentage of oil and gas sales in the fourth quarter of 2016 is due to a lower oil production tax rate in North Dakota, which dropped to 10% beginning in 2016.
General and Administrative Expense
General and administrative expense was $3.7 million in the fourth quarter of 2016 compared to $5.8 million in the fourth quarter of 2015. The decrease was due to a $3.0 million reduction in compensation expenses, primarily driven by a decrease in incentive compensation, partially offset by a $0.9 million increase in legal and other professional fees.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $13.5 million in the fourth quarter of 2016 compared to $24.1 million in the fourth quarter of 2015. Depletion expense, the largest component of DD&A, was $13.4 million in the fourth quarter of 2016 compared to $24.0 million in the fourth quarter of 2015. On a per unit basis, depletion expense was $10.61 per Boe in the fourth quarter of 2016 compared to $16.59 per Boe in the fourth quarter of 2015. The year-over-year decrease was due to the impairment of oil and gas properties in 2015 and 2016, which has lowered the depletable base.
Impairment of Oil and Natural Gas Properties
No impairment of oil and gas properties was required in the fourth quarter of 2016. Northern recorded a non-cash ceiling test impairment of $167.1 million in the fourth quarter of 2015. The impairment charge affected reported net income but did not reduce cash flow.
Interest Expense
Interest expense, net of capitalized interest, was $16.2 million in the fourth quarter of 2016, compared to $16.1 million in the fourth quarter of 2015.
Income Tax Provision
Northern recognized a $1.4 million income tax benefit during the fourth quarter of 2016 as compared to no income tax benefit in the fourth quarter of 2015. In 2016, Northern utilized $1.4 million of its alternative minimum tax credit as a result of favorable tax incentives within The Protecting Americans from Tax Hikes Act of 2015.
Net Loss
Northern recorded a net loss of $12.3 million, or a loss of $0.20 per diluted share, for the fourth quarter of 2016, compared to a net loss of $172.3 million, or a loss of $2.84 per diluted share, for the fourth quarter of 2015. The net loss in the fourth quarter of 2016 was impacted by lower realized commodity prices and production levels and a non-cash loss on the mark-to-market of derivative instruments that was partially offset by $1.4 million in income tax benefit. The net loss in the fourth quarter of 2015 was impacted by a $167.1 million impairment charge.
Non-GAAP Financial Measures
Adjusted Net Income for the fourth quarter of 2016 was $2.4 million (representing $0.04 per diluted share), compared to $15.6 million (representing $0.25 per diluted share) for the fourth quarter of 2015. Northern defines Adjusted Net Income as net income excluding (i) (gain) loss on the mark-to-market of derivative instruments, net of tax, (ii) restructuring costs, net of tax, (iii) impairment of oil and natural gas properties, net of tax, and (iv) write-off of debt issuance costs, net of tax. The decrease in Adjusted Net Income in the fourth quarter of 2016 compared to the fourth quarter of 2015 was primarily due to lower realized commodity prices and production volumes, which were partially offset by lower depletion expense and other operating expenses.
Adjusted EBITDA for the fourth quarter of 2016 was $35.1 million, compared to Adjusted EBITDA of $67.7 million for the fourth quarter of 2015. The decrease in Adjusted EBITDA in the fourth quarter of 2016 as compared to the fourth quarter of 2015 is primarily due to lower realized commodity prices and production volumes. Northern defines Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization and accretion, (iv) (gain) loss on the mark-to-market of derivative instruments, (v) non-cash share based compensation expense, (vi) write-off of debt issuance costs and (vii) impairment of oil and natural gas properties.
Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. A reconciliation of these measures to the most directly comparable GAAP measure is included in the accompanying financial tables found later in this release. Management believes the use of these non-GAAP financial measures provides useful information to investors to gain an overall understanding of current financial performance. Specifically, management believes the non-GAAP results included herein provide useful information to both management and investors by excluding certain expenses and unrealized derivatives gains and losses that management believes are not indicative of Northern’s core operating results. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring Northern’s performance, and management believes it is providing investors with financial measures that most closely align to its internal measurement processes.
FULL YEAR 2016 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
Years Ended December 31, | |||||||||
2016 | 2015 | % Change | |||||||
Net Production: | |||||||||
Oil (Bbl) | 4,325,919 | 5,168,687 | (16) | ||||||
Natural Gas and NGLs (Mcf) | 4,026,899 | 4,651,583 | (13) | ||||||
Total (Boe) | 4,997,069 | 5,943,950 | (16) | ||||||
Average Daily Production: | |||||||||
Oil (Bbl) | 11,819 | 14,161 | (17) | ||||||
Natural Gas and NGL (Mcf) | 11,002 | 12,744 | (14) | ||||||
Total (Boe) | 13,653 | 16,285 | (16) | ||||||
Average Sales Prices: | |||||||||
Oil (per Bbl) | $ | 35.22 | $ | 37.77 | (7) | ||||
Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl) | 14.22 | 31.17 | (54) | ||||||
Oil Net of Settled Derivatives (per Bbl) | 49.44 | 68.94 | (28) | ||||||
Natural Gas and NGLs (per Mcf) | 1.82 | 1.60 | 14 | ||||||
Realized Price on a Boe Basis Including all Realized Derivative Settlements | 44.27 | 61.19 | (28) | ||||||
Costs and Expenses (per Boe): | |||||||||
Production Expenses | $ | 9.14 | $ | 8.77 | 4 | ||||
Production Taxes | 3.10 | 3.63 | (15) | ||||||
General and Administrative Expense | 2.95 | 3.20 | (8) | ||||||
Depletion, Depreciation, Amortization and Accretion | 12.26 | 23.18 | (47) | ||||||
Net Producing Wells at Period End | 213.1 | 204.3 | 4 | ||||||
Oil and Natural Gas Sales
In 2016, oil, natural gas and NGL sales, excluding the effect of settled derivatives, decreased 21% from 2015, driven primarily by a 16% decrease in production and a 7% decrease in average oil sales price. The lower average realized price per Boe, excluding the effect of settled derivatives, in 2016 as compared to 2015 was primarily driven by lower average NYMEX oil and gas prices, which were partially offset by a lower oil price differential. Oil price differential during 2016 averaged $8.25 per barrel, as compared to $9.42 per barrel in 2015.
Derivative Instruments (Hedges)
Northern enters into derivative instruments to manage the price risk attributable to future oil production. Gain (loss) on derivative instruments, net is comprised of (i) cash gains and losses recognized on settled derivatives during the period, and (ii) non-cash mark-to-market gains and losses incurred on derivative instruments outstanding at period-end.
Years Ended December 31, | |||||||
2016 | 2015 | ||||||
(in millions) | |||||||
Derivative Instruments (Hedges): | |||||||
Cash Derivative Settlements | $ | 61.5 | $ | 161.1 | |||
Non-Cash Mark-to-Market of Derivative Instruments | (76.3 | ) | (88.7 | ) | |||
Gain (Loss) on Derivative Instruments, Net | $ | (14.8 | ) | $ | 72.4 | ||
Northern’s average realized price, including all cash derivative settlements, received during 2016 was $44.27 per Boe compared to $61.19 per Boe in 2015. The gain on settled derivatives increased Northern’s average realized price per Boe by $12.31 in 2016 and increased average realized price per Boe by $27.10 in 2015.
As a result of forward oil price changes, Northern recognized a non-cash mark-to-market derivative loss of $76.3 million in 2016 compared to a loss of $88.7 million in 2015. At December 31, 2016, all derivative contracts were recorded at their fair value, which was a net liability of $11.7 million, a decrease of $76.3 million from the $64.6 million net asset recorded as of December 31, 2015.
Production Expenses
Production expenses decreased from $52.1 million in 2015 to $45.7 million in 2016. On a per unit basis, production expenses increased 4% from $8.77 per Boe in 2015 to $9.14 per Boe in 2016. The higher cost on a per unit basis in 2016 is primarily due to lower production levels over which fixed costs are spread. On an absolute dollar basis, production expenses in 2016 were 12% lower when compared to 2015 due primarily to lower contract labor and maintenance costs and reduced variable costs on lower production levels, which was partially offset by a 4% increase in the total number of net wells.
Production Taxes
Northern pays production taxes based on realized crude oil and natural gas sales. These costs were $15.5 million in 2016 compared to $21.6 million in 2015. The $6.1 million decrease in production taxes in 2016 compared to 2015 was primarily due to the decline in oil, natural gas and NGL sales, excluding the effect of settled derivatives. As a percentage of oil and natural gas sales, production taxes were 9.7% in 2016 compared to 10.6% in 2015.
General and Administrative Expense
General and administrative expense was $14.8 million for 2016 compared to $19.0 million for 2015. General and administrative expenses in 2016 as compared to 2015 were lower due primarily to $5.9 million in lower compensation expenses, which was due in large part to the termination of the employment of the company’s former chief executive officer, which resulted in the reversal of $3.2 million in compensation expenses. Additionally, compensation expenses in 2016 as compared to 2015 were lower due to workforce reductions that occurred in 2015. Partially offsetting the lower compensation expenses in 2016 was a $1.9 million increase in legal and other professional fees.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $61.2 million in 2016 compared to $137.8 million in 2015. Depletion expense, the largest component of DD&A, was $12.13 per Boe in 2016 compared to $23.07 per Boe in 2015. The aggregate decrease in depletion expense for 2016 compared to 2015 was driven by a 47% decrease in the depletion rate per Boe, as well as a 16% decrease in production levels. The 2016 depletion rate per Boe was lower due to the impairment of oil and gas properties, which lowered the depletable base.
Impairment of Oil and Natural Gas Properties
As a result of low prevailing commodity prices and their effect on the proved reserve values of properties in 2016, Northern recorded a non-cash ceiling test impairment of $237.0 million in 2016 compared to $1.2 billion in 2015. The impairment charge affected reported net income but did not reduce cash flow.
Interest Expense
Interest expense, net of capitalized interest, was $64.5 million in 2016 compared to $58.4 million in 2015. The increase in interest expense for 2016 as compared to 2015 was primarily due to an increase in average borrowings outstanding between periods and a lower amount of capitalized interest cost. In May 2015, Northern issued $200 million of 8% senior unsecured notes.
Income Tax Provision
The income tax benefit recognized during 2016 was $1.4 million as compared to an income tax benefit of $202.4 million in 2015. The effective tax rate in 2016 was 0.5% compared to an effective tax rate of 17.2% in 2015. The lower effective tax rate in 2016 and 2015 relates to the $341.3 million valuation allowance placed on the net deferred tax asset due to uncertainty regarding their realization. In 2016, Northern utilized $1.4 million of its alternative minimum tax credit as a result of favorable tax incentives within The Protecting Americans from Tax Hikes Act of 2015.
Net Loss
Northern recorded a net loss of $293.5 million, or approximately $4.80 per diluted share, for 2016, compared to a net loss of $975.4 million, or approximately $16.08 per diluted share, for 2015. Net losses in 2016 and 2015 were impacted by the non-cash impairment of oil and natural gas properties, the valuation allowance placed on the net deferred tax asset, and a non-cash loss on the mark-to-market of derivative instruments.
Non-GAAP Financial Measures
Northern defines Adjusted Net Income as net income excluding (i) (gain) loss on the mark-to-market of derivative instruments, net of tax, (ii) restructuring costs, net of tax, (iii) impairment of oil and natural gas properties, net of tax and (iv) write-off of debt issuance costs, net of tax. Adjusted Net Income for 2016 was $12.2 million (representing approximately $0.20 per diluted share) as compared to Adjusted Net Income for 2015 of $47.6 million (representing approximately $0.78 per diluted share). The decrease in Adjusted Net Income in 2016 compared to 2015 was primarily due to lower realized commodity prices and production volumes, as well as higher interest costs, which were partially offset by lower depletion expense and other operating expenses.
Northern defines Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization, and accretion, (iv) (gain) loss on the mark-to-market of derivative instruments, (v) non-cash share based compensation expense, (vi) write-off of debt issuance costs and (vii) impairment of oil and natural gas properties. Adjusted EBITDA for 2016 was $148.5 million, compared to Adjusted EBITDA of $277.3 million for 2015. The decrease in Adjusted EBITDA in 2016 as compared to 2015 is primarily due to lower production levels and lower realized commodity prices.
Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. A reconciliation of these measures to the most directly comparable GAAP measure is included in the accompanying financial tables found later in this release.
FOURTH QUARTER 2016 EARNINGS RELEASE CONFERENCE CALL
In conjunction with Northern’s release of its financial and operating results, investors, analysts and other interested parties are invited to listen to a conference call with management on Thursday, March 2, 2017 at 10:00 a.m. Central Time.
Those wishing to listen to the conference call may do so via the company’s website, www.northernoil.com, or by phone as follows:
Dial-In Number: (855) 638-5677 (US/Canada) and (262) 912-4762 (International)
Conference ID: 73314817 - Northern Oil and Gas, Inc. Fourth Quarter and Year-End 2016 Earnings Call
Replay Dial-In Number: (855) 859-2056 (US/Canada) and (404) 537-3406 (International)
Replay Access Code: 73314817 - Replay will be available through March 9, 2017
UPCOMING CONFERENCE SCHEDULE
45th Annual Scotia Howard Weil Energy Conference
March 26 - March 29, 2017, New Orleans, LA
IPAA Oil and Gas Investment Symposium
April 3 - April 4, 2017, New York, NY
ABOUT NORTHERN OIL AND GAS
Northern Oil and Gas, Inc. is an exploration and production company with a core area of focus in the Williston Basin Bakken and Three Forks play in North Dakota and Montana.
More information about Northern Oil and Gas, Inc. can be found at www.NorthernOil.com.
SAFE HARBOR
This press release contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical facts included in this release regarding Northern’s financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.
Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond Northern’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: changes in crude oil and natural gas prices, the pace of drilling and completions activity on Northern’s properties, Northern’s ability to acquire additional development opportunities, changes in Northern’s reserves estimates or the value thereof, general economic or industry conditions, nationally and/or in the communities in which Northern conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, Northern’s ability to raise or access capital, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting Northern’s operations, products, services and prices.
Northern has based these forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond Northern’s control.
CONTACT:
Brandon Elliott, CFA
Executive Vice President,
Corporate Development and Strategy
952-476-9800
belliott@northernoil.com
SOURCE Northern Oil and Gas, Inc.
NORTHERN OIL AND GAS, INC.
STATEMENTS OF OPERATIONS
Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
REVENUES | |||||||||||||||
Oil and Gas Sales | $ | 47,076,502 | $ | 39,340,256 | $ | 159,690,883 | $ | 202,638,640 | |||||||
Gain (Loss) on Derivative Instruments, Net | (11,141,233 | ) | 17,563,910 | (14,818,734 | ) | 72,382,907 | |||||||||
Other Revenue | 8,359 | 8,863 | 31,347 | 35,866 | |||||||||||
Total Revenues | 35,943,628 | 56,913,029 | 144,903,496 | 275,057,413 | |||||||||||
OPERATING EXPENSES | |||||||||||||||
Production Expenses | 11,718,227 | 11,776,670 | 45,680,110 | 52,107,984 | |||||||||||
Production Taxes | 4,480,705 | 4,233,511 | 15,513,608 | 21,566,634 | |||||||||||
General and Administrative Expense | 3,735,671 | 5,817,991 | 14,757,641 | 19,042,004 | |||||||||||
Depletion, Depreciation, Amortization and Accretion | 13,523,186 | 24,140,489 | 61,244,158 | 137,769,812 | |||||||||||
Impairment of Oil and Natural Gas Properties | — | 167,143,533 | 237,012,834 | 1,163,959,246 | |||||||||||
Total Expenses | 33,457,789 | 213,112,194 | 374,208,351 | 1,394,445,680 | |||||||||||
INCOME (LOSS) FROM OPERATIONS | 2,485,839 | (156,199,165 | ) | (229,304,855 | ) | (1,119,388,267 | ) | ||||||||
OTHER INCOME (EXPENSE) | |||||||||||||||
Interest Expense, Net of Capitalization | (16,195,176 | ) | (16,081,987 | ) | (64,485,623 | ) | (58,360,387 | ) | |||||||
Write-off of Debt Issuance Costs | — | — | (1,089,507 | ) | — | ||||||||||
Other Income (Expense) | (23,240 | ) | (32,218 | ) | (15,902 | ) | (30,091 | ) | |||||||
Total Other Income (Expense) | (16,218,416 | ) | (16,114,205 | ) | (65,591,032 | ) | (58,390,478 | ) | |||||||
(LOSS) BEFORE INCOME TAXES | (13,732,577 | ) | (172,313,370 | ) | (294,895,887 | ) | (1,177,778,745 | ) | |||||||
INCOME TAX BENEFIT | (1,402,179 | ) | (50 | ) | (1,402,179 | ) | (202,424,204 | ) | |||||||
NET LOSS | $ | (12,330,398 | ) | $ | (172,313,320 | ) | $ | (293,493,708 | ) | $ | (975,354,541 | ) | |||
Net Loss Per Common Share – Basic | $ | (0.20 | ) | $ | (2.84 | ) | $ | (4.80 | ) | $ | (16.08 | ) | |||
Net Loss Per Common Share – Diluted | $ | (0.20 | ) | $ | (2.84 | ) | $ | (4.80 | ) | $ | (16.08 | ) | |||
Weighted Average Shares Outstanding – Basic | 61,310,458 | 60,727,536 | 61,173,547 | 60,652,447 | |||||||||||
Weighted Average Shares Outstanding – Diluted | 61,310,458 | 60,727,536 | 61,173,547 | 60,652,447 | |||||||||||
NORTHERN OIL AND GAS, INC.
BALANCE SHEETS
December 31, 2016 | December 31, 2015 | ||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and Cash Equivalents | $ | 6,486,098 | $ | 3,390,389 | |||
Accounts Receivable, Net | 35,840,042 | 58,230,113 | |||||
Advances to Operators | 1,577,204 | 1,689,879 | |||||
Prepaid and Other Expenses | 1,584,130 | 892,867 | |||||
Derivative Instruments | 4,516 | 64,611,558 | |||||
Income Tax Receivable | 1,402,179 | — | |||||
Total Current Assets | 46,894,169 | 128,814,806 | |||||
Property and Equipment | |||||||
Oil and Natural Gas Properties, Full Cost Method of Accounting | |||||||
Proved | 2,428,595,048 | 2,336,757,089 | |||||
Unproved | 2,623,802 | 10,007,529 | |||||
Other Property and Equipment | 977,349 | 1,837,469 | |||||
Total Property and Equipment | 2,432,196,199 | 2,348,602,087 | |||||
Less – Accumulated Depreciation, Depletion and Impairment | (2,055,987,766 | ) | (1,759,281,704 | ) | |||
Total Property and Equipment, Net | 376,208,433 | 589,320,383 | |||||
Deferred Income Taxes | — | — | |||||
Other Noncurrent Assets, Net | 8,430,359 | 15,810,259 | |||||
Total Assets | $ | 431,532,961 | $ | 733,945,448 | |||
LIABILITIES AND STOCKHOLDERS’ DEFICIT | |||||||
Current Liabilities: | |||||||
Accounts Payable | $ | 56,146,847 | $ | 65,319,170 | |||
Accrued Expenses | 6,094,938 | 7,893,975 | |||||
Accrued Interest | 4,682,894 | 4,713,232 | |||||
Derivative Instruments | 10,001,564 | — | |||||
Asset Retirement Obligations | 517,423 | 188,770 | |||||
Total Current Liabilities | 77,443,666 | 78,115,147 | |||||
Long-term Debt, Net | 832,625,125 | 847,804,829 | |||||
Derivative Instruments | 1,738,329 | — | |||||
Asset Retirement Obligations | 6,990,877 | 5,627,586 | |||||
Other Noncurrent Liabilities | 156,632 | — | |||||
TOTAL LIABILITIES | 918,954,629 | 931,547,562 | |||||
COMMITMENTS AND CONTINGENCIES (NOTE 8) | |||||||
STOCKHOLDERS’ DEFICIT | |||||||
Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding | — | — | |||||
Common Stock, Par Value $.001; 142,500,000 Authorized (12/31/2016 – 63,259,781 Shares Outstanding and 12/31/2015 – 63,120,384 Shares Outstanding) | 63,260 | 63,120 | |||||
Additional Paid-In Capital | 443,895,032 | 440,221,018 | |||||
Retained Deficit | (931,379,960 | ) | (637,886,252 | ) | |||
Total Stockholders’ Deficit | (487,421,668 | ) | (197,602,114 | ) | |||
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT | $ | 431,532,961 | $ | 733,945,448 | |||
Reconciliation of Adjusted Net Income
Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
(in thousands, except share and per common share data) | |||||||||||||||
Net Loss | $ | (12,330 | ) | (172,313 | ) | $ | (293,494 | ) | $ | (975,355 | ) | ||||
Add: | |||||||||||||||
Impact of Selected Items: | |||||||||||||||
Loss on the Mark-to-Market of Derivative Instruments | 18,212 | 29,599 | 76,347 | 88,716 | |||||||||||
Restructuring Costs | — | — | — | 523 | |||||||||||
Impairment of Oil and Natural Gas Properties | — | 167,144 | 237,013 | 1,163,959 | |||||||||||
Write-off of Debt Issuance Costs | — | — | 1,089,507 | — | |||||||||||
Selected Items, Before Income Taxes | 18,212 | 196,743 | 314,450 | 1,253,198 | |||||||||||
Income Tax of Selected Items(1) | (3,491 | ) | (8,821 | ) | (8,723 | ) | (230,259 | ) | |||||||
Selected Items, Net of Income Taxes | 14,721 | 187,922 | 305,727 | 1,022,939 | |||||||||||
Adjusted Net Income | $ | 2,391 | $ | 15,609 | $ | 12,233 | $ | 47,584 | |||||||
Weighted Average Shares Outstanding – Basic | 61,310,458 | 60,727,536 | 61,173,547 | 60,652,447 | |||||||||||
Weighted Average Shares Outstanding – Diluted | 61,823,433 | 61,394,762 | 61,824,749 | 60,887,698 | |||||||||||
Net Loss Per Common Share – Basic | $ | (0.20 | ) | $ | (2.84 | ) | $ | (4.80 | ) | $ | (16.08 | ) | |||
Add: | |||||||||||||||
Impact of Selected Items, Net of Income Taxes | 0.24 | 3.10 | 5.00 | 16.86 | |||||||||||
Adjusted Net Income Per Common Share – Basic | $ | 0.04 | $ | 0.26 | $ | 0.20 | $ | 0.78 | |||||||
Net Loss Per Common Share – Diluted | $ | (0.20 | ) | $ | (2.81 | ) | $ | (4.75 | ) | $ | (16.02 | ) | |||
Add: | |||||||||||||||
Impact of Selected Items, Net of Income Taxes | 0.24 | 3.06 | 4.95 | 16.80 | |||||||||||
Adjusted Net Income Per Common Share – Diluted | $ | 0.04 | $ | 0.25 | $ | 0.20 | $ | 0.78 | |||||||
_______________
(1) | For the years ended 2016 and 2015 columns, this represents tax impact using an estimated tax rate of 37.4% for 2016 and 36.9% for 2015, respectively, and includes adjustments for changes in our valuation allowance of $109.0 million for 2016 and $232.3 million for 2015, respectively. For the three months ended 2016 and 2015 columns, this represents a tax impact using an estimated tax rate of 46.6% and 36.1% , respectively, and includes adjustments for changes in our valuation allowance of $5.0 million and $62.2 million for the three months ended 2016 and 2015, respectively. |
Reconciliation of Adjusted EBITDA
Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
(in thousands) | |||||||||||||||
Net Loss | $ | (12,330 | ) | $ | (172,313 | ) | $ | (293,494 | ) | $ | (975,355 | ) | |||
Add: | |||||||||||||||
Interest Expense | 16,195 | 16,082 | 64,486 | 58,360 | |||||||||||
Income Tax Provision (Benefit) | (1,402 | ) | — | (1,402 | ) | (202,424 | ) | ||||||||
Depreciation, Depletion, Amortization and Accretion | 13,523 | 24,140 | 61,244 | 137,770 | |||||||||||
Impairment of Oil and Natural Gas Properties | — | 167,144 | 237,013 | 1,163,959 | |||||||||||
Non-Cash Share Based Compensation | 873 | 3,052 | 3,182 | 6,273 | |||||||||||
Write-off of Debt Issuance Costs | — | — | 1,090 | — | |||||||||||
Loss on the Mark-to-Market of Derivative Instruments | 18,212 | 29,599 | 76,347 | 88,716 | |||||||||||
Adjusted EBITDA | $ | 35,071 | $ | 67,704 | $ | 148,466 | $ | 277,299 | |||||||