MINNEAPOLIS--(BUSINESS WIRE)--Northern Oil and Gas, Inc. (NYSE American: NOG) today announced 2017 fourth quarter and full year results and provided 2018 guidance.
HIGHLIGHTS
- Northern raises 2018 annual production guidance and now expects a 16 - 20% increase over 2017
- Year-end 2017 proved reserve volumes increased 40% year over year from 54.1 million barrels of oil equivalent (“Boe”) in 2016 to 75.8 million Boe
- The SEC PV-10 value of year-end proved reserves increased 100% year over year
- Fourth quarter production increased 22% year over year and 9.3% sequentially to 1,540,237 Boe. Production averaged 16,742 Boe per day in the fourth quarter
- Fourth quarter oil differential was $3.51 per barrel, an improvement of $2.71 per barrel compared to the third quarter
- Northern added 16.9 net wells to production during 2017 and ended the year with an additional 18.3 net wells in process
Adjusted EBITDA for the fourth quarter was $48.5 million. Northern’s adjusted net income for the fourth quarter was $6.6 million, or $0.10 per diluted share. GAAP net loss for the quarter was $23.8 million, or a loss of $0.37 per diluted share, primarily due to a non-cash mark-to-market loss on its hedge portfolio. See “Non-GAAP Financial Measures” below for additional information on these measures.
MANAGEMENT COMMENT
“Strong fourth quarter results, including 9.3% sequential production growth, provided an excellent finish to the year and outstanding momentum as we enter 2018,” commented Northern’s Interim President, Brandon Elliott. “We are seeing excellent results from wells added to production during 2017, suggesting significant upside to the value from enhanced completions that resides within the entirety of our acreage position. Our investment approach and our Williston Basin asset base, combined with the steps we are taking to strengthen our balance sheet, are setting the stage for us to accelerate our growth strategy as the natural consolidator of non-operated working interest in the Williston Basin.”
2018 GUIDANCE
Northern is raising guidance and now expects 2018 total annual production to increase by 16 - 20% over 2017 levels, based on the expectation of adding between 20 and 22 net wells to production during the year. Due to winter weather and the potential for road restrictions during the spring, net well additions are expected to be weighted to the second half of 2018. Capital expenditures are expected to total between $165 - $180 million. This budget is comprised of $152 - $167 million in drilling and completions capital assuming the addition of 20 - 22 net wells to production during the year and approximately $13 million in workover, acreage and other capitalized costs. Management’s current expectations for 2018 operating metrics are as follows:
| 2018 | ||
| Operating Expenses: | ||
| Production Expenses (per Boe) | $8.75 - $9.25 | |
| Production Taxes (% of Oil & Gas Sales) | 9.2% - 9.5% | |
| General and Administrative Expense (per Boe) | $2.00 - $2.50 | |
| Average Differential to NYMEX WTI | $3.50 - $4.50 | |
LIQUIDITY
At December 31, 2017, Northern had available liquidity of approximately $202.2 million, comprised of $102.2 million in cash on hand and $100 million of delayed draw term loan availability.
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CAPITAL EXPENDITURES & DRILLING ACTIVITY |
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Fourth Quarter |
Full Year |
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| Capital Expenditures Incurred: | ||||
| Drilling, Completion & Capitalized Workover Expense | $56.2 million | $148.8 million | ||
| Acreage | $0.6 million | $4.9 million | ||
| Other | $0.5 million | $2.3 million | ||
| Net Wells Added to Production | 7.1 | 16.9 | ||
| Net Producing Wells (Period-End) | 229.0 | |||
| Net Wells in Process (Period-End) | 18.3 | |||
| Increase in Wells in Process Year-over-Year | 4.9 | |||
| Weighted Average AFE for In-Process Wells (Period-End) | $7.6 million | |||
Capitalized costs incurred (e.g. drilling and completion costs and other capital expenditures) for the fourth quarter and full year 2017 totaled $57.3 million and $156.0 million, respectively. Capitalized costs are a function of the number of net well additions during the period as well as changes in wells in process from beginning to end of period. Capital expenditures attributable to the 4.9 increase in net wells in process are reflected in the amounts included for “Drilling, Completion & Capitalized Workover Expense” in the table above.
ELECTION ACTIVITY AND ACREAGE
Higher well productivity from enhanced completions on Northern’s acreage position drove a 100% increase in net well elections from 8.0 net wells in 2016 to 16.0 net wells in 2017. Northern consented to 93% of well proposals in 2017 compared to 77% in 2016. As a result of increased activity levels and higher consent rates during the year, Northern’s wells in process increased by 4.9 net wells to 18.3 net wells compared to year-end 2016 levels.
As of December 31, 2017, Northern controlled 143,253 net acres targeting the Bakken and Three Forks formations in the Williston Basin. As of December 31, 2017, approximately 89% of Northern’s North Dakota acreage position, and approximately 88% of Northern’s total acreage position, was developed, held by production or held by operations.
2017 YEAR-END RESERVES
Based on reports prepared by Ryder Scott Company, L.P., Northern’s estimated proved reserves at December 31, 2017 totaled 75.8 million barrels of oil equivalent (MMBoe), a 40% increase as compared to 54.1 MMBoe at December 31, 2016, driven by higher commodity prices and increased activity levels. Approximately 61% of Northern’s proved reserves at December 31, 2017 were categorized as proved developed and approximately 39% were classified as proved undeveloped. Crude oil represented 83% of year-end 2017 proved reserves.
| 2017 Boe | 2016 Boe | % Change | |||||||
| (in thousands) | |||||||||
| Reserve Category | |||||||||
| Proved Developed Producing | 40,050 | 35,676 | 12 | % | |||||
| Proved Developed Non-Producing | 6,295 | 2,037 | 209 | % | |||||
| Proved Undeveloped | 29,487 | 16,368 | 80 | % | |||||
| Total Proved | 75,832 | 54,081 | 40 | % | |||||
The table that follows compares Northern's proved reserves from the 2017 SEC case prepared by Ryder Scott to an alternative pricing case that utilizes a $60 flat WTI price. Other than commodity prices, all assumptions in the “$60 WTI Flat” case have been held constant with the SEC case, and as a result both cases reflect the inclusion of just 52.1 proved undeveloped net well locations due to SEC guidelines (including the 5 year PUD limitation rule) applicable to booking proved undeveloped reserves. Early next week, Northern plans to post an updated investor presentation at www.northernoil.com, which will include additional reserve information based on internal management estimates.
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Price Cases (including the 5 year PUD limitation rule) |
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| SEC Case(1) | $60 WTI Flat(2) | ||||||
| (in thousands) | |||||||
| Net Proved Reserves (December 31, 2017) | |||||||
| Developed (Boe) | 46,345 | 48,069 | |||||
| Undeveloped (Boe) | 29,487 | 32,107 | |||||
| Total Proved Reserves (Boe) | 75,832 | 80,176 | |||||
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Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%)(3) |
$ | 758,000 | $ | 1,015,881 | |||
_________________
| (1) |
Prices prescribed by SEC based on $51.34 per Bbl of oil and $2.98 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $45.90 per Bbl of oil and $3.34 per Mcf for natural gas. |
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| (2) | Prices based on $60.00 per Bbl of oil and $3.00 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $54.56 per Bbl of oil and $3.36 per Mcf for natural gas. | |
| (3) | Pre-tax PV10%, or “PV-10,” may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP measure. See “Reconciliation of PV-10” below. | |
FOURTH QUARTER 2017 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
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Three Months Ended December 31, |
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| 2017 | 2016 | % Change | |||||||||
| Net Production: | |||||||||||
| Oil (Bbl) | 1,282,122 | 1,063,535 | 21 | % | |||||||
| Natural Gas and NGLs (Mcf) | 1,548,688 | 1,174,434 | 32 | % | |||||||
| Total (Boe) | 1,540,237 | 1,259,274 | 22 | % | |||||||
| Average Daily Production: | |||||||||||
| Oil (Bbl) | 13,936 | 11,560 | 21 | % | |||||||
| Natural Gas and NGL (Mcf) | 16,834 | 12,766 | 32 | % | |||||||
| Total (Boe) | 16,742 | 13,688 | 22 | % | |||||||
| Average Sales Prices: | |||||||||||
| Oil (per Bbl) | $ | 51.79 | $ | 41.83 | 24 | % | |||||
| Effect of Gain on Settled Derivatives on Average Price (per Bbl) | (1.45 | ) | 6.65 | (122 | )% | ||||||
| Oil Net of Settled Derivatives (per Bbl) | 50.34 | 48.48 | 4 | % | |||||||
| Natural Gas and NGLs (per Mcf) | 3.92 | 2.21 | 77 | % | |||||||
| Realized Price on a Boe Basis Including all Realized Derivative Settlements | 45.85 | 43.00 | 7 | % | |||||||
| Costs and Expenses (per Boe): | |||||||||||
| Production Expenses | $ | 8.65 | $ | 9.31 | (7 | )% | |||||
| Production Taxes | 4.31 | 3.56 | 21 | % | |||||||
| General and Administrative Expense | 2.00 | 2.97 | (33 | )% | |||||||
| Depletion, Depreciation, Amortization and Accretion | 11.45 | 10.74 | 7 | % | |||||||
| Net Producing Wells at Period End | 229.0 | 213.1 | 7 | % | |||||||
Oil and Natural Gas Sales
In the fourth quarter of 2017, oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 54% as compared to the fourth quarter of 2016, driven by a 24% increase in average oil sales prices and a 22% increase in production levels. The higher average realized price per Boe, excluding the effect of settled derivatives, in the fourth quarter of 2017 as compared to the fourth quarter of 2016 was primarily driven by higher NYMEX oil and natural gas prices and a lower oil differential. Oil price differential during the fourth quarter of 2017 was $3.51 per barrel, as compared to $7.46 per barrel in the fourth quarter of 2016.
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.
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Three Months Ended December 31, |
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| 2017 | 2016 | |||||||
| (in millions) | ||||||||
| Derivative Instruments (Hedges): | ||||||||
| Cash Derivative Settlements | $ | (1.9 | ) | $ | 7.1 | |||
| Non-Cash Mark-to-Market of Derivative Instruments | (33.6 | ) | (18.2 | ) | ||||
| Gain (Loss) on Derivative Instruments, Net | $ | (35.5 | ) | $ | (11.1 | ) | ||
Northern’s average realized price, including all cash derivative settlements, received during the fourth quarter of 2017 was $45.85 per Boe compared to $43.00 per Boe in the fourth quarter of 2016. The gain (loss) on settled derivatives decreased Northern’s average realized price per Boe by $1.21 in the fourth quarter of 2017 and increased the average realized price per Boe by $5.62 in the fourth quarter of 2016. As a result of forward oil price changes, Northern recognized a non-cash mark-to-market derivative loss of $33.6 million in the fourth quarter of 2017, compared to a loss of $18.2 million in the fourth quarter of 2016.
Production Expenses
Production expenses were $13.3 million in the fourth quarter of 2017 compared to $11.7 million in the fourth quarter of 2016. On a per unit basis, production expenses decreased to $8.65 per Boe in the fourth quarter of 2017, compared to $9.31 per Boe in the fourth quarter of 2016. On an absolute dollar basis, the increase in production expenses in the fourth quarter of 2017 as compared to the fourth quarter of 2016 was primarily due to higher processing costs and salt water disposal costs, a 22% increase in production levels, and a 7% increase in the total number of net producing wells.
Production Taxes
Production taxes were $6.6 million in the fourth quarter of 2017 compared to $4.5 million in the fourth quarter of 2016. The increase is due to higher commodity prices and higher production levels, which increased oil and natural gas sales in the fourth quarter of 2017 as compared to the fourth quarter of 2016. As a percentage of oil and natural gas sales, production taxes were 9.2% and 9.5% in the fourth quarter of 2017 and 2016, respectively. This decrease in production tax rates as a percentage of oil and natural gas sales is due to a change in sales mix, as production taxes on natural gas and NGL sales are at a lower percentage than that of crude oil sales. Crude oil sales represented 92% of oil and natural gas sales in the fourth quarter of 2017 compared to 94% in the fourth quarter of 2016.
General and Administrative Expense
General and administrative expenses were $3.1 million in the fourth quarter of 2017 compared to $3.7 million in the fourth quarter of 2016. The decrease was primarily due to a $0.9 million decrease in legal and other professional expenses, partially offset by a $0.2 million increase in compensation expenses.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $17.6 million in the fourth quarter of 2017 compared to $13.5 million in the fourth quarter of 2016. Depletion expense, the largest component of DD&A, was $17.5 million in the fourth quarter of 2017 compared to $13.4 million in the fourth quarter of 2016. The aggregate increase in depletion expense was driven by a 22% increase in production levels coupled with a 7% increase in the depletion rate per Boe. On a per unit basis, depletion expense was $11.33 per Boe in the fourth quarter of 2017 compared to $10.61 per Boe in the fourth quarter of 2016. Depreciation, amortization and accretion was $0.2 million in the fourth quarter of 2017 and 2016.
Interest Expense
Interest expense, net of capitalized interest, was $20.9 million in the fourth quarter of 2017, compared to $16.2 million in the fourth quarter of 2016. The increase in interest expense was driven primarily by an increase in average borrowings outstanding and a higher interest rate on the new term loan credit agreement that replaced Northern’s prior revolving credit facility in November 2017.
Income Tax Provision
Northern recognized a $1.6 million income tax benefit during the fourth quarter of 2017 as compared to a $1.4 million income tax benefit in the fourth quarter of 2016. In 2017 and 2016, Northern utilized $1.6 million and $1.4 million, respectively, of its alternative minimum tax credit as a result of favorable tax incentives.
Net Loss
Northern recorded a net loss of $23.8 million, or a loss of $0.37 per diluted share, for the fourth quarter of 2017, compared to a net loss of $12.3 million, or a loss of $0.20 per diluted share, for the fourth quarter of 2016. The net loss in the fourth quarter of 2017 was impacted by a non-cash loss on the mark-to-market of derivative instruments of $33.6 million that was partially offset by a $1.6 million income tax benefit.
Non-GAAP Financial Measures
Adjusted Net Income for the fourth quarter of 2017 was $6.6 million (representing $0.10 per diluted share), compared to $2.4 million (representing $0.04 per diluted share) for the fourth quarter of 2016. 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 increase in Adjusted Net Income in the fourth quarter of 2017 compared to the fourth quarter of 2016 was primarily due to higher realized commodity prices and production volumes, which were partially offset by higher depletion expense.
Adjusted EBITDA for the fourth quarter of 2017 was $48.5 million, compared to Adjusted EBITDA of $35.1 million for the fourth quarter of 2016. The increase in Adjusted EBITDA in the fourth quarter of 2017 as compared to the fourth quarter of 2016 is primarily due to higher 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 2017 RESULTS
The following table sets forth selected operating and financial data for the periods indicated.
| Years Ended December 31, | |||||||||||
| 2017 | 2016 | % Change | |||||||||
| Net Production: | |||||||||||
| Oil (Bbl) | 4,537,295 | 4,325,919 | 5 | % | |||||||
| Natural Gas and NGLs (Mcf) | 5,187,886 | 4,026,899 | 29 | % | |||||||
| Total (Boe) | 5,401,943 | 4,997,069 | 8 | % | |||||||
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Average Daily Production: |
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| Oil (Bbl) | 12,431 | 11,819 | 5 | % | |||||||
| Natural Gas and NGL (Mcf) | 14,213 | 11,002 | 29 | % | |||||||
| Total (Boe) | 14,800 | 13,653 | 8 | % | |||||||
| Average Sales Prices: | |||||||||||
| Oil (per Bbl) | $ | 45.09 | $ | 35.22 | 28 | % | |||||
| Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl) | 0.83 | 14.22 | (94 | )% | |||||||
| Oil Net of Settled Derivatives (per Bbl) | 45.92 | 49.44 | (7 | )% | |||||||
| Natural Gas and NGLs (per Mcf) | 3.74 | 1.82 | 105 | % | |||||||
| Realized Price on a Boe Basis Including all Realized Derivative Settlements | 42.16 | 44.27 | (5 | )% | |||||||
| Costs and Expenses (per Boe): | |||||||||||
| Production Expenses | $ | 9.21 | $ | 9.14 | 1 | % | |||||
| Production Taxes | 3.81 | 3.10 | 23 | % | |||||||
| General and Administrative Expense | 3.51 | 2.95 | 19 | % | |||||||
| Depletion, Depreciation, Amortization and Accretion | 11.01 | 12.26 | (10 | )% | |||||||
| Net Producing Wells at Period End | 229.0 | 213.1 | 7 | % | |||||||
Oil and Natural Gas Sales
In 2017, oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 40% from 2016, driven primarily by an 8% increase in production levels and a 28% increase in average oil sales price. The higher average realized price per Boe, excluding the effect of settled derivatives, in 2017 as compared to 2016 was primarily driven by higher average NYMEX oil and gas prices, as well as a lower oil price differential. Oil price differential during 2017 averaged $5.87 per barrel, as compared to $8.25 per barrel in 2016.
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.
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Years Ended
December 31, |
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| 2017 | 2016 | |||||||
| (in millions) | ||||||||
| Derivative Instruments: | ||||||||
| Cash Derivative Settlements | $ | 3.8 | $ | 61.5 | ||||
| Non-Cash Mark-to-Market of Derivative Instruments | (18.4 | ) | (76.3 | ) | ||||
| Gain (Loss) on Derivative Instruments, Net | $ | (14.7 | ) | $ | (14.8 | ) | ||
Northern’s average realized price, including all cash derivative settlements, received during 2017 was $42.16 per Boe compared to $44.27 per Boe in 2016. The gain (loss) on settled derivatives increased Northern’s average realized price per Boe by $0.70 in 2017 and increased average realized price per Boe by $12.31 in 2016.
As a result of forward oil price changes, Northern recognized a non-cash mark-to-market derivative loss of $18.4 million in 2017 compared to a loss of $76.3 million in 2016. At December 31, 2017, all derivative contracts were recorded at their fair value, which was a net liability of $30.2 million, an increase of $18.4 million from the $11.7 million net liability recorded as of December 31, 2016.
Production Expenses
Production expenses were $49.7 million in 2017 compared to $45.7 million in 2016. On a per unit basis, production expenses were relatively flat from $9.14 per Boe in 2016 to $9.21 per Boe in 2017. On an absolute dollar basis, production expenses in 2017 were 9% higher when compared to 2016 due primarily to higher processing and maintenance costs, as well as a 7% increase in the total number of net wells.
Production Taxes
Northern pays production taxes based on realized oil and natural gas sales. These costs were $20.6 million in 2017 compared to $15.5 million in 2016. The $5.1 million increase in production taxes in 2017 compared to 2016 is due to higher commodity prices and higher production levels, which increased oil and natural gas sales in 2017 as compared to 2016. As a percentage of oil and natural gas sales, average production tax rates were 9.2% in 2017 compared to 9.7% in 2016. This decrease in production tax rates as a percentage of oil and natural gas sales is due to a change in sales mix, as production taxes on natural gas and NGL sales are at a lower percentage than that of crude oil sales. Crude oil sales represented 91% of oil and natural gas sales in 2017 compared to 95% in 2016.
General and Administrative Expense
General and administrative expense was $19.0 million for 2017 compared to $14.8 million for 2016. The increase in 2017 compared to 2016 was due in part to a $3.6 million charge in the third quarter of 2017 in connection with a settlement agreement with our former chief executive officer, pursuant to which we agreed to pay him $750,000 in cash and issue him 3,000,000 shares of our common stock. In addition, legal and professional expense was $1.3 million higher in 2017 compared to 2016, partially offset by a $0.2 million decrease in cash compensation expense due primarily to reduced incentive compensation.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $59.5 million in 2017 compared to $61.2 million in 2016. Depletion expense, the largest component of DD&A, was $10.89 per Boe in 2017 compared to $12.13 per Boe in 2016. The aggregate decrease in depletion expense for 2017 compared to 2016 was driven by a 10% decrease in the depletion rate per Boe, partially offset by an 8% increase in production levels. The 2017 depletion rate per Boe was lower due to the impairment of oil and natural gas properties throughout 2016, which lowered the depletable base.
Impairment of Oil and Natural Gas Properties
Northern did not have any impairment of proved oil and gas properties in 2017. As a result of low prevailing commodity prices during 2016 and their effect on the proved reserve values of properties, Northern recorded a non-cash ceiling test impairment of $237.0 million in 2016. The impairment charge affected our reported net income but did not reduce our cash flow.
Interest Expense
Interest expense, net of capitalized interest, was $70.3 million in 2017 compared to $64.5 million in 2016. The increase in interest expense for 2017 as compared to 2016 was primarily due to an increase in average borrowings outstanding between periods, a lower amount of capitalized interest cost and a higher interest rate on the new term loan credit agreement that was completed in November 2017 as compared to borrowings under our prior revolving credit facility (which was repaid with proceeds from the term loan credit agreement).
Income Tax
The income tax benefit recognized during 2017 was $1.6 million as compared to an income tax benefit of $1.4 million in 2016. The effective tax rate in 2017 was 14.6% compared to an effective tax rate of 0.5% in 2016. In 2017 and 2016, the tax benefits recognized related to the utilization of its alternative minimum tax credit as a result of favorable tax incentives. Northern recorded a valuation allowance against certain of its net deferred tax assets due to uncertainty regarding realization in 2017 and 2016.
Net Loss
Northern recorded a net loss of $9.2 million, or approximately $0.15 per diluted share, for 2017, compared to a net loss of $293.5 million, or approximately $4.80 per diluted share, for 2016. In 2017, the net loss was impacted by a loss on the extinguishment of debt, legal settlement with the Company’s former chief executive officer, and a non-cash loss on the mark-to-market of derivative instruments. In 2016, the net loss was impacted by the non-cash impairment of oil and natural gas properties 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 (loss) 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, (iv) write-off of debt issuance costs, net of tax, (v) loss on the extinguishment of debt, net of tax, and (vi) certain legal settlements, net of tax. Adjusted Net Income for 2017 was $8.5 million (representing $0.14 per diluted share) as compared to Adjusted Net Income for 2016 of $12.2 million (representing $0.20 per diluted share). The decrease in Adjusted Net Income in 2017 compared to 2016 was primarily due to lower realized commodity prices, and higher general and administrative expenses, production expenses and interest costs, which were partially offset by lower depletion expense and higher 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, (vii) loss on the extinguishment of debt, and (viii) impairment of oil and natural gas properties. Adjusted EBITDA for 2017 was $144.7 million, compared to Adjusted EBITDA of $148.5 million in 2016. The decrease in Adjusted EBITDA in 2017 as compared to 2016 is primarily due to lower realized commodity prices and increased general and administrative expenses, partially offset by higher production volumes.
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.
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, 2017.
| Swaps | ||||
| Contract Period | Volume (Bbls) | Weighted Average Price (per Bbl) | ||
| 2018: | ||||
| 1Q | 860,400 | $53.42 | ||
| 2Q | 829,000 | $53.09 | ||
| 3Q | 753,000 | $53.42 | ||
| 4Q | 643,000 | $53.54 | ||
| 2019: | ||||
| 1Q | 621,000 | $53.01 | ||
| 2Q | 600,600 | $52.89 | ||
| 3Q | 524,400 | $52.30 | ||
| 4Q | 469,200 | $52.22 | ||
| 2020: | ||||
| 1Q | 327,600 | $50.49 | ||
| 2Q | 309,400 | $50.41 | ||
| 3Q | 303,600 | $50.37 | ||
| 4Q | 303,600 | $50.37 | ||
FOURTH QUARTER 2017 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 Friday, February 23, 2018 at 9:30 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: 3458237 - Northern Oil and Gas, Inc. Fourth Quarter and Year-End 2017 Conference Call
Replay Dial-In Number: (855) 859-2056 (US/Canada) and (404) 537-3406 (International)
Replay Access Code: 3458237 - Replay will be available through March 2, 2018
UPCOMING CONFERENCE SCHEDULE
47th Annual Scotia Howard Weil Energy Conference
March 25 - 28, 2018, New Orleans LA
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: Northern’s ability to consummate any transaction with its bondholders, including the final terms of any such transaction, which could result in the issuance of a significant amount of equity, 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, including as a condition to any transaction with its bondholders, 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. Northern does not undertake any duty to update or revise any forward-looking statements any forward-looking statements, except as may be required by the federal securities laws.
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NORTHERN OIL AND GAS, INC. |
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STATEMENTS OF OPERATIONS |
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Three Months Ended
December 31, |
Years Ended
December 31, |
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| 2017 | 2016 | 2017 | 2016 | |||||||||||||
| REVENUES | ||||||||||||||||
| Oil and Gas Sales | $ | 72,476,191 | $ | 47,076,502 | $ | 223,963,010 | $ | 159,690,883 | ||||||||
| Gain (Loss) on Derivative Instruments, Net | (35,477,317 | ) | (11,141,233 | ) | (14,666,655 | ) | (14,818,734 | ) | ||||||||
| Other Revenue | 3,407 | 8,359 | 23,314 | 31,347 | ||||||||||||
| Total Revenues | 37,002,281 | 35,943,628 | 209,319,669 | 144,903,496 | ||||||||||||
| OPERATING EXPENSES | ||||||||||||||||
| Production Expenses | 13,315,460 | 11,718,227 | 49,732,861 | 45,680,110 | ||||||||||||
| Production Taxes | 6,638,456 | 4,480,705 | 20,604,256 | 15,513,608 | ||||||||||||
| General and Administrative Expense | 3,076,000 | 3,735,671 | 18,987,801 | 14,757,641 | ||||||||||||
| Depletion, Depreciation, Amortization and Accretion | 17,631,875 | 13,523,186 | 59,500,155 | 61,244,158 | ||||||||||||
| Impairment of Oil and Natural Gas Properties | — | — | — | 237,012,834 | ||||||||||||
| Total Expenses | 40,661,791 | 33,457,789 | 148,825,073 | 374,208,351 | ||||||||||||
| INCOME (LOSS) FROM OPERATIONS | (3,659,510 | ) | 2,485,839 | 60,494,596 | (229,304,855 | ) | ||||||||||
| OTHER INCOME (EXPENSE) | ||||||||||||||||
| Interest Expense, Net of Capitalization | (20,881,740 | ) | (16,195,176 | ) | (70,286,341 | ) | (64,485,623 | ) | ||||||||
| Write-off of Debt Issuance Costs | — | — | (95,135 | ) | (1,089,507 | ) | ||||||||||
| Loss on the Extinguishment of Debt | (992,950 | ) | — | (992,950 | ) | — | ||||||||||
| Other Income (Expense) | 115,497 | (23,240 | ) | 116,042 | (15,902 | ) | ||||||||||
| Total Other Income (Expense) | (21,759,193 | ) | (16,218,416 | ) | (71,258,384 | ) | (65,591,032 | ) | ||||||||
| LOSS BEFORE INCOME TAXES | (25,418,703 | ) | (13,732,577 | ) | (10,763,788 | ) | (294,895,887 | ) | ||||||||
| — | ||||||||||||||||
| INCOME TAX BENEFIT | (1,570,016 | ) | (1,402,179 | ) | (1,570,016 | ) | (1,402,179 | ) | ||||||||
| NET LOSS | $ | (23,848,687 | ) | $ | (12,330,398 | ) | $ | (9,193,772 | ) | $ | (293,493,708 | ) | ||||
| Net Loss Per Common Share – Basic | $ | (0.37 | ) | $ | (0.20 | ) | $ | (0.15 | ) | $ | (4.80 | ) | ||||
| Net Loss Per Common Share – Diluted | $ | (0.37 | ) | $ | (0.20 | ) | $ | (0.15 | ) | $ | (4.80 | ) | ||||
| Weighted Average Shares Outstanding – Basic | 64,672,781 | 61,310,458 | 62,408,855 | 61,173,547 | ||||||||||||
| Weighted Average Shares Outstanding – Diluted | 64,672,781 | 61,310,458 | 62,408,855 | 61,173,547 | ||||||||||||
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NORTHERN OIL AND GAS, INC. |
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BALANCE SHEETS |
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| December 31, 2017 | December 31, 2016 | ||||||
| ASSETS | |||||||
| Current Assets: | |||||||
| Cash and Cash Equivalents | $ | 102,183,191 | $ | 6,486,098 | |||
| Accounts Receivable, Net | 46,851,682 | 35,840,042 | |||||
| Advances to Operators | 604,977 | 1,577,204 | |||||
| Prepaid and Other Expenses | 2,333,288 | 1,584,129 | |||||
| Derivative Instruments | — | 4,517 | |||||
| Income Tax Receivable | 785,016 | 1,402,179 | |||||
| Total Current Assets | 152,758,154 | 46,894,169 | |||||
| Property and Equipment | |||||||
| Oil and Natural Gas Properties, Full Cost Method of Accounting | |||||||
| Proved | 2,585,490,133 | 2,428,595,048 | |||||
| Unproved | 1,699,344 | 2,623,802 | |||||
| Other Property and Equipment | 981,303 | 977,349 | |||||
| Total Property and Equipment | 2,588,170,780 | 2,432,196,199 | |||||
| Less – Accumulated Depreciation, Depletion and Impairment | (2,114,951,189 | ) | (2,055,987,766 | ) | |||
| Total Property and Equipment, Net | 473,219,591 | 376,208,433 | |||||
| Deferred Income Taxes | 785,000 | — | |||||
| Other Noncurrent Assets, Net | 5,490,934 | 8,430,359 | |||||
| Total Assets | $ | 632,253,679 | $ | 431,532,961 | |||
| LIABILITIES AND STOCKHOLDERS’ DEFICIT | |||||||
| Current Liabilities: | |||||||
| Accounts Payable | $ | 93,152,297 | $ | 56,146,847 | |||
| Accrued Expenses | 6,339,425 | 6,094,938 | |||||
| Accrued Interest | 4,836,112 | 4,682,894 | |||||
| Derivative Instruments | 18,681,891 | 10,001,564 | |||||
| Asset Retirement Obligations | 565,521 | 517,423 | |||||
| Total Current Liabilities | 123,575,246 | 77,443,666 | |||||
| Long-term Debt, Net | 979,324,222 | 832,625,125 | |||||
| Derivative Instruments | 11,496,929 | 1,738,329 | |||||
| Asset Retirement Obligations | 8,562,607 | 6,990,877 | |||||
| Other Noncurrent Liabilities | 135,225 | 156,632 | |||||
| TOTAL LIABILITIES | 1,123,094,229 | 918,954,629 | |||||
| COMMITMENTS AND CONTINGENCIES (NOTE 8) | |||||||
| STOCKHOLDERS’ DEFICIT | |||||||
| Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding | — | — | |||||
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Common Stock, Par Value $.001; 142,500,000 Authorized (12/31/2017 –
66,791,633 Shares Outstanding and 12/31/2016 – 63,259,781 Shares Outstanding) |
66,792 | 63,260 | |||||
| Additional Paid-In Capital | 449,666,390 | 443,895,032 | |||||
| Retained Deficit | (940,573,732 | ) | (931,379,960 | ) | |||
| Total Stockholders’ Deficit | (490,840,550 | ) | (487,421,668 | ) | |||
| TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT | $ | 632,253,679 | $ | 431,532,961 | |||
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Reconciliation of Adjusted Net Income |
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Three Months Ended
December 31, |
Years Ended
December 31, |
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| 2017 | 2016 | 2017 | 2016 | |||||||||||||
| (in thousands, except share and per common share data) | ||||||||||||||||
| Net Loss | $ | (23,849 | ) | $ | (12,330 | ) | $ | (9,194 | ) | $ | (293,494 | ) | ||||
| Add: | ||||||||||||||||
| Impact of Selected Items: | ||||||||||||||||
| (Gain) Loss on the Mark-to-Market of Derivative Instruments | 33,614 | 18,212 | 18,443 | 76,347 | ||||||||||||
| Impairment of Oil and Natural Gas Properties | — | — | — | 237,013 | ||||||||||||
| Write-off of Debt Issuance Costs | — | — | 95 | 1,090 | ||||||||||||
| Loss on the Extinguishment of Debt | 993 | — | 993 | — | ||||||||||||
| Legal Settlements | — | — | 3,589 | — | ||||||||||||
| Selected Items, Before Income Taxes (Benefit) | 34,607 | 18,212 | 23,121 | 314,449 | ||||||||||||
| Income Tax (Benefit) of Selected Items(1) | (4,119 | ) | (3,491 | ) | (5,388 | ) | (8,723 | ) | ||||||||
| Selected Items, Net of Income Taxes (Benefit) | 30,487 | 14,721 | 17,733 | 305,726 | ||||||||||||
| Adjusted Net Income | $ | 6,639 | $ | 2,391 | $ | 8,539 | $ | 12,233 | ||||||||
| Weighted Average Shares Outstanding – Basic | 64,672,781 | 61,310,458 | 62,408,855 | 61,173,547 | ||||||||||||
| Weighted Average Shares Outstanding – Diluted | 65,077,695 | 61,823,433 | 62,769,234 | 61,824,749 | ||||||||||||
| Net Loss Per Common Share – Basic | $ | (0.37 | ) | $ | (0.20 | ) | $ | (0.15 | ) | $ | (4.80 | ) | ||||
| Add: | ||||||||||||||||
| Impact of Selected Items, Net of Income Taxes (Benefit) | 0.47 | 0.24 | 0.29 | 5.00 | ||||||||||||
| Adjusted Net Income Per Common Share – Basic | $ | 0.10 | $ | 0.04 | $ | 0.14 | $ | 0.20 | ||||||||
| Net Loss Per Common Share – Diluted | $ | (0.37 | ) | $ | (0.20 | ) | $ | (0.15 | ) | $ | (4.75 | ) | ||||
| Add: | ||||||||||||||||
| Impact of Selected Items, Net of Income Taxes (Benefit) | 0.47 | 0.24 | 0.29 | 4.95 | ||||||||||||
| Adjusted Net Income Per Common Share – Diluted | $ | 0.10 | $ | 0.04 | $ | 0.14 | $ | 0.20 | ||||||||
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| (1) | For the years ended 2017 and 2016 columns, this represents tax impact using an estimated tax rate of 39.1% for 2017 and 37.4% for 2016, respectively, and includes adjustments for changes in our valuation allowance of $3.7 million for 2017, excluding the impact for the Tax Cuts and Jobs Act that was enacted on December 22, 2017 and $341.3 million for 2016, respectively. For the three months ended 2017 and 2016 columns, this represents a tax impact using an estimated tax rate of 38.8% and 46.6%, respectively, and includes adjustments for changes in our valuation allowance of $9.3 million, excluding the impact for the Tax Cuts and Jobs Act and $5.0 million for the three months ended 2017 and 2016, respectively. | |
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Reconciliation of Adjusted EBITDA |
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Three Months Ended
December 31, |
Years Ended
December 31, |
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| 2017 | 2016 | 2017 | 2016 | |||||||||||||
| (in thousands) | ||||||||||||||||
| Net Loss | $ | (23,849 | ) | $ | (12,330 | ) | $ | (9,194 | ) | $ | (293,494 | ) | ||||
| Add: | ||||||||||||||||
| Interest Expense | 20,882 | 16,195 | 70,286 | 64,486 | ||||||||||||
| Income Tax Benefit | (1,570 | ) | (1,402 | ) | (1,570 | ) | (1,402 | ) | ||||||||
| Depreciation, Depletion, Amortization and Accretion | 17,632 | 13,523 | 59,500 | 61,244 | ||||||||||||
| Impairment of Oil and Natural Gas Properties | — | — | — | 237,013 | ||||||||||||
| Non-Cash Share Based Compensation | 841 | 873 | 6,107 | 3,182 | ||||||||||||
| Write-off of Debt Issuance Costs | — | — | 95 | 1,090 | ||||||||||||
| Loss on the Extinguishment of Debt | 993 | — | 993 | — | ||||||||||||
| Loss on the Mark-to-Market of Derivative Instruments | 33,614 | 18,212 | 18,443 | 76,347 | ||||||||||||
| Adjusted EBITDA | $ | 48,542 | $ | 35,071 | $ | 144,660 | $ | 148,466 | ||||||||
Reconciliation of PV-10
PV-10 may be considered a non-GAAP financial measure and is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.
The following table provides the estimated pre-tax PV10% value as of December 31, 2017, of our proved reserves under the SEC case and the $60 WTI Flat case described elsewhere in this press release, and also reconciles these amounts to the standardized measure of discounted future net cash flows.
| SEC Case(1) | $60 WTI Flat(2) | |||||||
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Standardized Measure Reconciliation (in thousands) |
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Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%) |
$ | 758,000 | $ | 1,015,881 | ||||
| Future Income Taxes, Discounted at 10%(3) | (4,014 | ) | (34,808 | ) | ||||
| Standardized Measure of Discounted Future Net Cash Flows | $ | 753,986 | $ | 981,073 | ||||
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| (1) |
Prices prescribed by SEC based on $51.34 per Bbl of oil and $2.98 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $45.90 per Bbl of oil and $3.34 per Mcf for natural gas. |
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| (2) | Prices based on $60.00 per Bbl of oil and $3.00 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $54.56 per Bbl of oil and $3.36 per Mcf for natural gas. | |
| (3) | The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows. As a result of available net operating loss carryforwards and the remaining tax basis of our assets at December 31, 2017, our future income taxes were significantly reduced. | |
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