Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Cautionary Statement Concerning Forward-Looking Statements
This Management’s Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements regarding future events and our 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 report regarding our 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 report, 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 our company’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 our current properties and any properties pending acquisition, our ability to acquire additional development opportunities, changes in our reserves estimates or the value thereof, general economic or industry conditions, nationally and/or in the communities in which our company conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, our ability to consummate any pending acquisition transactions, other risks and uncertainties related to the closing of pending acquisition transactions, our 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 our company’s operations, products and prices.
We have based any forward-looking statements on our current expectations and assumptions about future events. While our 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 our control. Accordingly, results achieved may differ materially from expected results described in these statements. You should consider carefully the statements in the section entitled “Item 1A. Risk Factors” and other sections of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018, as updated by subsequent reports we file with the SEC (including this report), which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Forward-looking statements speak only as of the date they are made. We do not undertake, and specifically disclaim, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements.
The following discussion should be read in conjunction with the unaudited Condensed Financial Statements and accompanying Notes to condensed Financial Statements appearing elsewhere in this report.
Overview
We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas properties, primarily in the Bakken and Three Forks formations within the Williston Basin in North Dakota and Montana. We believe the location, size and concentration of our acreage position in one of North America’s leading unconventional oil-resource plays provide us with drilling and development opportunities that will result in significant long-term value. Our primary focus is oil exploration and production through non-operated working interests in wells drilled and completed in spacing units that include our acreage. Using this strategy, we had participated in 5,057 gross (340.6 net) producing wells as of June 30, 2019.
Our average daily production in the second quarter of 2019 was approximately 34,965 Boe per day, of which approximately 81% was oil. Our recent acquisitions, combined with higher activity levels, have boosted our development levels and resulted in production in the second quarter of 2019 increasing by approximately 66% over the same period a year ago. During the three months ended June 30, 2019, we added 139 gross (8.1 net) wells to production. As of June 30, 2019, we have leased approximately 163,558 net acres, of which approximately 89% were developed and 100% were located in the Williston Basin of North Dakota and Montana.
Source of Our Revenues
We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market. We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil production. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.
Principal Components of Our Cost Structure
•
Oil price differentials
. The price differential between our Williston Basin well head price and the NYMEX WTI benchmark price is driven by the additional cost to transport oil from the Williston Basin via train, pipeline or truck to refineries.
•
Gain (loss) on derivative instruments, net.
We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of oil. Gain (loss) on derivative instruments, net is comprised of (i) cash gains and losses we recognize on settled derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on derivative instruments outstanding at period end.
•
Production expenses.
Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties.
•
Production taxes.
Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.
•
Depreciation, depletion, amortization and impairment.
Depreciation, depletion, amortization and impairment includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method.
•
General and administrative expenses.
General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance.
•
Interest expense.
We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We capitalize a portion of the interest paid on applicable borrowings into our full cost pool. We include interest expense that is not capitalized into the full cost pool, the amortization of deferred financing costs and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense.
•
Income tax expense.
Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
Selected Factors That Affect Our Operating Results
Our revenues, cash flows from operations and future growth depend substantially upon:
•
the timing and success of drilling and production activities by our operating partners;
•
the prices and the supply and demand for oil, natural gas and NGLs;
•
the quantity of oil and natural gas production from the wells in which we participate;
•
changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in the price of oil;
•
our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and
•
the level of our operating expenses.
In addition to the factors that affect companies in our industry generally, the location of our acreage and wells in the Williston Basin subjects our operating results to factors specific to this region. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, and the limitations of the developing infrastructure and transportation capacity in this region.
The price of oil in the Williston Basin can vary depending on the market in which it is sold and the means of transportation used to transport the oil to market. Light sweet crude from the Williston Basin has a higher value at many major refining centers because of its higher quality relative to heavier and sour grades of oil; however, because of North Dakota’s location relative to traditional oil transport centers, this higher value is generally offset to some extent by higher transportation costs. While rail transportation has historically been more expensive than pipeline transportation, Williston Basin prices have at times justified shipment by rail to markets on the gulf coast and east coast, which offer prices benchmarked to LLS/Brent. Additional pipeline infrastructure has increased takeaway capacity in the Williston Basin which has improved wellhead values in the region.
The price at which our oil production is sold typically reflects a discount to the NYMEX benchmark price. Thus, our operating results are also affected by changes in the oil price differentials between the NYMEX and the sales prices we receive for our oil production. Our oil price differential to the NYMEX benchmark price during the second quarter of 2019 was $5.29 per barrel, as compared to $5.77 per barrel in the second quarter of 2018. Fluctuations in our oil price differential are due to several factors such as takeaway capacity relative to production levels in the Williston Basin and seasonal refinery maintenance temporarily depressing crude demand.
Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in oil prices that can substantially impact the level of drilling activity in the Williston Basin. Generally, higher oil prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher. Lower oil prices have generally had the opposite effect. In addition, individual components of the cost can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, and the choice of proppant (sand or ceramic). During the first six months of 2019, the weighted average authorization for expenditure (or AFE) cost for wells we elected to participate in was $8.0 million, compared to $8.1 million for the wells we elected to participate in during 2018.
Market Conditions
The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Being primarily an oil producer, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can adversely impact oil prices. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.
Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the three and six months ended June 30, 2019 and 2018.
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Three Months Ended June 30,
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|
|
|
2019
|
|
2018
|
Average NYMEX Prices(1)
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|
|
|
Natural Gas (per Mcf)
|
$
|
2.56
|
|
$
|
2.83
|
Oil (per Bbl)
|
$
|
59.89
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|
$
|
67.97
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|
|
|
|
|
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|
|
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|
Six Months Ended June 30,
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2019
|
|
2018
|
Average NYMEX Prices(1)
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|
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|
Natural Gas (per Mcf)
|
$
|
2.74
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|
$
|
2.96
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Oil (per Bbl)
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$
|
57.42
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$
|
65.49
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____________
(1)
Based on average NYMEX closing prices.
For the three months ended June 30, 2019, the average NYMEX pricing was $59.89 per barrel of oil or 12% lower than the average NYMEX price per barrel for the comparable period in 2018. Our realized oil price after reflecting settled derivatives was 3% higher in the second quarter of 2019 than in the second quarter of 2018 due to a 19% increase in the average price of our settled derivatives per barrel and a lower oil price differential, which was partially offset by the lower average NYMEX price per barrel.
As of June 30, 2019, we had a total volume on open commodity price swaps of 15.4 million barrels at a weighted average price of approximately $59.91 per barrel. The following table reflects the weighted average price of open commodity price swap derivative contracts as of June 30, 2019, by year with associated volumes.
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Year
|
|
Volumes (Bbl)
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Weighted
Average Price ($/Bbl)
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2019
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4,164,280
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62.96
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2020
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7,848,330
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59.31
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2021
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2,906,350
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57.96
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2022 and beyond
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500,000
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55.06
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In addition to the open commodity price swap contracts we have entered into basis swap contracts. Basis swaps fix the price differential between a published index price and the applicable local index price under which our production is sold. The following table reflects open commodity basis swap contracts as of June 30, 2019.
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Settlement Period
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Total Volumes (Bbls)
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Weighted
Average Differential ($/Bbl)
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07/01/19 – 12/31/19
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1,840,000
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(2.41)
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Results of Operations for the Three Months Ended June 30, 2019 and June 30, 2018
The following table sets forth selected operating data for the periods indicated.
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Three Months Ended June 30,
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2019
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2018
|
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% Change
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Net Production:
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|
|
|
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Oil (Bbl)
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2,562,513
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|
1,625,788
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58
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%
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Natural Gas and NGLs (Mcf)
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3,715,936
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1,736,651
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114
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%
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Total (Boe)
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3,181,835
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1,915,230
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66
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%
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Net Sales (in thousands):
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Oil Sales
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$
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139,810
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$
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101,037
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38
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%
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Natural Gas and NGL Sales
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10,037
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8,010
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25
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%
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Gain (Loss) on Settled Derivatives
|
4,734
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(12,267)
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Gain (Loss) on Mark-to-Market of Derivative Instruments
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31,857
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(29,936)
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Other Revenue
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2
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3
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Total Revenues
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186,440
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|
66,846
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|
179
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%
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|
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Average Sales Prices:
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|
|
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Oil (per Bbl)
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$
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54.56
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$
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62.20
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(12)
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%
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Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl)
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1.85
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(7.55)
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Oil Net of Settled Derivatives (per Bbl)
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56.41
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54.65
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3
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%
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Natural Gas and NGLs (per Mcf)
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2.70
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4.61
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(41)
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%
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Realized Price on a Boe Basis Including All Realized Derivative Settlements
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48.58
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50.58
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(4)
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%
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|
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Operating Expenses (in thousands):
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|
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Production Expenses
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$
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26,132
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$
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14,549
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|
80
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%
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Production Taxes
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14,033
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10,132
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|
39
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%
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General and Administrative Expenses
|
5,250
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|
3,251
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|
61
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%
|
Depletion, Depreciation, Amortization and Accretion
|
46,091
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|
22,596
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|
104
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%
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|
|
|
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|
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Costs and Expenses (per Boe):
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|
|
|
|
|
Production Expenses
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$
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8.21
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$
|
7.60
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8
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%
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Production Taxes
|
4.41
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|
5.29
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(17)
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%
|
General and Administrative Expenses
|
1.65
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|
1.70
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(3)
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%
|
Depletion, Depreciation, Amortization and Accretion
|
14.49
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|
11.80
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23
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%
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|
|
|
|
|
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Net Producing Wells at Period End
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340.6
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248.3
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|
37
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%
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Oil and Natural Gas Sales
In the second quarter of 2019, our oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 37% as compared to the second quarter of 2018, driven by a 66% increase in production, which was partially offset by a 17% decrease in realized prices, excluding the effect of settled derivatives. The lower average realized price in the second quarter of 2019 as compared to the same period in 2018 was principally driven by lower average NYMEX oil and natural gas prices. Oil price differential during the second quarter of 2019 was $5.29 per barrel, as compared to $5.77 per barrel in the second quarter of 2018.
We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells. Our substantial acquisition activities (see Note 3 to our condensed financial statements) combined with increased development activity and improved performance from enhanced completion techniques helped drive a 66% increase in production levels in the second quarter of 2019 compared to the same period in 2018.
Derivative Instruments
We enter into derivative instruments to manage the price risk attributable to future oil production. Our gain (loss) on derivative instruments, net, was a gain of $36.6 million in the second quarter of 2019, compared to a loss of $42.2 million in the second quarter of 2018. Gain (loss) on derivative instruments, net, is comprised of (i) cash gains and losses we recognize on settled derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on derivative instruments outstanding at period end.
For the second quarter of 2019, we realized a gain on settled derivatives of $4.7 million, compared to a $12.3 million loss in the second quarter of 2018. The increase in the gain on settled derivatives was primarily due to an increase in our average settlement price, and a decrease in the average NYMEX oil price, in the second quarter of 2019 compared to the same period of 2018. During the second quarter of 2019, our derivative settlements included 1.9 million barrels of oil at an average settlement price of $63.01 per barrel, while during the second quarter of 2018 our derivative settlements included 0.8 million barrels of oil at an average settlement price of $53.09 per barrel. The average NYMEX oil price for the second quarter of 2019 was $59.89 compared to $67.97 for the second quarter of 2018. Our average realized price (including all cash derivative settlements) in the second quarter of 2019 was $48.58 per Boe compared to $50.58 per Boe in the second quarter of 2018. The gain (loss) on settled derivatives increased our average realized price per Boe by $1.49 in the second quarter of 2019 and decreased our average realized price per Boe by $6.36 in the second quarter of 2018.
Mark-to-market derivative gains and losses was a gain of $31.9 million in the second quarter of 2019, compared to a loss of $29.9 million in the second quarter of 2018. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Any gains on our derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date. At June 30, 2019, all of our derivative contracts are recorded at their fair value, which was a net asset of $57.4 million, a decrease of $120.3 million from the $177.7 million net asset recorded as of December 31, 2018. The decrease in the net asset at June 30, 2019 as compared to December 31, 2018 was primarily due to changes in forward oil prices relative to prices on our open oil derivative contracts since December 31, 2018.
Production Expenses
Production expenses were $26.1 million in the second quarter of 2019, compared to $14.5 million in the second quarter of 2018. On a per unit basis, production expenses increased from $7.60 per Boe in the second quarter of 2018 to $8.21 per Boe in the second quarter of 2019. On an absolute dollar basis, the increase in our production expenses in the second quarter of 2019, as compared to the second quarter of 2018, was primarily due to a 66% increase in production, as well as a 37% increase in the total number of net producing wells, as well as an increase in processing and saltwater disposal costs.
Production Taxes
We pay production taxes based on realized oil and natural gas sales. Production taxes were $14.0 million in the second quarter of 2019 compared to $10.1 million in the second quarter of 2018. The increase is due to higher production levels (partially offset by a decrease in realized prices), which increased our oil and natural gas sales in the second quarter of 2019 as compared to the second quarter of 2018. As a percentage of oil and natural gas sales, our production taxes were 9.4% and 9.3% in the second quarter of 2019 and 2018, respectively. The increase in our production taxes as a percentage of oil and natural gas sales is due to a higher mix of oil sales as a percentage of total oil and natural gas sales.
General and Administrative Expenses
General and administrative expenses were $5.2 million in the second quarter of 2019 compared to $3.3 million in the second quarter of 2018. The increase was primarily due to a $1.1 million increase in compensation expense, partially due to the additions to our executive team late in the second quarter of 2018 as well as lower incentive compensation in the second quarter of 2018 compared to the second quarter of 2019. In addition, we had a $0.5 million increase in professional fees primarily due to the VEN Bakken Acquisition (see Note 12).
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $46.1 million in the second quarter of 2019, compared to $22.6 million in the second quarter of 2018. Depletion expense, the largest component of DD&A, increased by $23.5 million in the second quarter of 2019 compared to the second quarter of 2018. The aggregate increase in depletion expense was driven by a 66% increase in production levels and a 23% increase in the depletion rate per Boe. On a per unit basis, depletion expense was $14.43 per Boe in the second quarter of 2019 compared to $11.70 per Boe in the second quarter of 2018. The higher depletion rate per Boe was primarily driven by the impact of recent acquisitions. Depreciation, amortization and accretion was $0.2 million in both the second quarter of 2019 and 2018. The following table summarizes DD&A expense per Boe for the second quarter of 2019 and 2018:
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|
|
|
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|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
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|
|
|
|
|
|
|
2019
|
|
2018
|
|
$ Change
|
|
% Change
|
Depletion
|
$
|
14.43
|
|
$
|
11.70
|
|
$
|
2.73
|
|
23
|
%
|
Depreciation, Amortization and Accretion
|
0.08
|
|
0.10
|
|
(0.02)
|
|
(20)
|
%
|
Total DD&A Expense
|
$
|
14.51
|
|
$
|
11.80
|
|
$
|
2.71
|
|
23
|
%
|
Interest Expense
Interest expense, net of capitalized interest, was $17.8 million for the second quarter of 2019 compared to $22.4 million in the second quarter of 2018. The decrease in interest expense was primarily due to lower interest rates on our Revolving Credit Facility in place for the second quarter of 2019 compared to our term loan credit facility that was in place for the second quarter of 2018.
Debt Exchange Derivative Gain (Loss)
As a result of certain debt exchange agreements that were entered into during 2018 (see Note 10 to our condensed financial statements), we incurred debt exchange derivative liabilities during 2018. For the second quarter of 2019, we recorded a debt exchange derivative loss of $4.9 million due to a change in the fair value of these liabilities during the second quarter of 2019 (see Note 10 to our condensed financial statements). There was no debt exchange derivative gain (loss) in the second quarter of 2018, since the relevant agreements were not yet in place.
Contingent Consideration Gain (Loss)
In connection with the W Energy Acquisition and the Pivotal Acquisition in 2018 (see Note 3 to our condensed financial statements), we incurred contingent consideration liabilities during 2018. During the second quarter of 2019, we recorded a contingent consideration loss of $24.8 million due to a change in the fair value of these liabilities (see Note 10 to our condensed financial statements). There was no contingent consideration gain (loss) in the second quarter of 2018, since the relevant agreements were not yet in place.
Income Tax Benefit
During the second quarter of 2019 and 2018, no income tax expense (benefit) was recorded on the income (loss) before income taxes, due to the valuation allowance placed on our net deferred tax asset because of the uncertainty regarding its realization. For further discussion of our valuation allowance, see Note 9 to our condensed financial statements.
We intend to continue to maintain a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. However, sufficient positive evidence may become available to allow us to reach a conclusion that a portion of the valuation allowance will no longer be needed. Release of any portion of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense for the period the release is recorded.
Results of Operations for the Six Months Ended June 30, 2019 and June 30, 2018
The following table sets forth selected operating data for the periods indicated.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
|
2019
|
|
2018
|
|
% Change
|
Net Production:
|
|
|
|
|
|
Oil (Bbl)
|
5,103,745
|
|
2,980,390
|
|
71
|
%
|
Natural Gas and NGLs (Mcf)
|
7,151,720
|
|
3,326,165
|
|
115
|
%
|
Total (Boe)
|
6,295,698
|
|
3,534,751
|
|
78
|
%
|
|
|
|
|
|
|
Net Sales (in thousands):
|
|
|
|
|
|
Oil Sales
|
$
|
263,423
|
|
$
|
180,180
|
|
46
|
%
|
Natural Gas and NGL Sales
|
19,107
|
|
15,748
|
|
21
|
%
|
Gain (Loss) on Settled Derivatives
|
17,280
|
|
(20,397)
|
|
(185)
|
%
|
Loss on Mark-to-Market of Derivative Instruments
|
(120,311)
|
|
(42,077)
|
|
186
|
%
|
Other Revenue
|
7
|
|
6
|
|
16
|
%
|
Total Revenues
|
179,506
|
|
133,459
|
|
35
|
%
|
|
|
|
|
|
|
Average Sales Prices:
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
51.65
|
|
$
|
60.52
|
|
(15)
|
%
|
Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl)
|
3.39
|
|
(6.84)
|
|
(150)
|
%
|
Oil Net of Settled Derivatives (per Bbl)
|
55.04
|
|
53.68
|
|
3
|
%
|
Natural Gas and NGLs (per Mcf)
|
2.67
|
|
4.73
|
|
(44)
|
%
|
Realized Price on a Boe Basis Including All Realized Derivative Settlements
|
47.65
|
|
49.71
|
|
(4)
|
%
|
|
|
|
|
|
|
Operating Expenses (in thousands):
|
|
|
|
|
|
Production Expenses
|
$
|
50,799
|
|
$
|
27,037
|
|
88
|
%
|
Production Taxes
|
26,553
|
|
18,054
|
|
47
|
%
|
General and Administrative Expenses
|
11,300
|
|
4,918
|
|
130
|
%
|
Depletion, Depreciation, Amortization and Accretion
|
91,225
|
|
41,227
|
|
121
|
%
|
|
|
|
|
|
|
Costs and Expenses (per Boe):
|
|
|
|
|
|
Production Expenses
|
$
|
8.07
|
|
$
|
7.65
|
|
5
|
%
|
Production Taxes
|
4.22
|
|
5.11
|
|
(17)
|
%
|
General and Administrative Expenses
|
1.79
|
|
1.39
|
|
29
|
%
|
Depletion, Depreciation, Amortization and Accretion
|
14.49
|
|
11.66
|
|
24
|
%
|
|
|
|
|
|
|
Net Producing Wells at Period End
|
340.6
|
|
248.3
|
|
37
|
%
|
Oil and Natural Gas Sales
In the first six months of 2019, our oil, natural gas and NGL sales, excluding the effect of settled derivatives, increased 44% as compared to the first six months of 2018, driven by a 78% increase in production, which was partially offset by a 19% decrease in realized prices, excluding the effect of settled derivatives. The lower average realized price in the first six months of 2019 as compared to the same period in 2018 was principally driven by lower average NYMEX oil and natural gas prices and a higher oil price differential. Oil price differential during the first six months of 2019 was $5.77 per barrel, as compared to $4.97 per barrel in the second quarter of 2018.
We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells. During 2018, our substantial acquisition activities (see Note 3 to our condensed financial statements) combined with increased development activity and improved performance from enhanced completion techniques helped drive a 78% increase in production levels in the first six months of 2019 compared to the same period in 2018.
Derivative Instruments
We enter into derivative instruments to manage the price risk attributable to future oil production. Our gain (loss) on derivative instruments, net, was a loss of $103.0 million in the first six months of 2019, compared to a loss of $62.5 million in the first six months of 2018. Gain (loss) on derivative instruments, net, is comprised of (i) cash gains and losses we recognize on settled derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on derivative instruments outstanding at period end.
For the first six months of 2019, we realized a gain on settled derivatives of $17.3 million, compared to a $20.4 million loss in the first six months of 2018. The increase in the gain on settled derivatives was primarily due to an increase in our average settlement price, and a decrease in the average NYMEX oil price, in the first six months of 2019 compared to the same period of 2018. During the first six months of 2019, our derivative settlements included 3.7 million barrels of oil at an average settlement price of $62.95 per barrel, while during the first six months of 2018 our derivative settlements included 1.7 million barrels of oil at an average settlement price of $53.26 per barrel. The average NYMEX oil price for the first six months of 2019 was $57.42 compared to $65.49 for the first six months of 2018. Our average realized price (including all cash derivative settlements) in the first six months of 2019 was $47.65 per Boe compared to $49.71 per Boe in the first six months of 2018. The gain (loss) on settled derivatives increased our average realized price per Boe by $2.74 in the first six months of 2019 and decreased our average realized price per Boe by $5.77 in the first six months of 2018.
Mark-to-market derivative gains and losses was a loss of $120.3 million in the first six months of 2019, compared to a loss of $42.1 million in the first six months of 2018. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Any gains on our derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date. At June 30, 2019, all of our derivative contracts are recorded at their fair value, which was a net asset of $57.4 million, a decrease of $120.3 million from the $177.7 million net asset recorded as of December 31, 2018. The decrease in the net asset at June 30, 2019 as compared to December 31, 2018 was primarily due to changes in forward oil prices relative to prices on our open oil derivative contracts since December 31, 2018.
Production Expenses
Production expenses were $50.8 million in the first six months of 2019, compared to $27.0 million in the first six months of 2018. On a per unit basis, production expenses increased from $7.65 per Boe in the first six months of 2018 to $8.07 per Boe in the first six months of 2019. On an absolute dollar basis, the increase in our production expenses in the first six months of 2019, as compared to the first six months of 2018, was primarily due to a 78% increase in production, as well as a 37% increase in the total number of net producing wells, as well as an increase in processing and saltwater disposal costs.
Production Taxes
We pay production taxes based on realized oil and natural gas sales. Production taxes were $26.6 million in the first six months of 2019 compared to $18.1 million in the first six months of 2018. The increase is due to higher production levels (partially offset by a decrease in realized prices), which increased our oil and natural gas sales in the first six months of 2019 as compared to the first six months of 2018. As a percentage of oil and natural gas sales, our production taxes were 9.4% and 9.2% in the first six months of 2019 and 2018, respectively. The increase in our production taxes as a percentage of oil and natural gas sales is due to a greater portion of our oil and natural gas sales consisting of oil sales.
General and Administrative Expenses
General and administrative expenses were $11.3 million in the first six months of 2019 compared to $4.9 million in the first six months of 2018. The increase was primarily due to a $4.9 million increase in compensation expense, partially due to a $1.2 million reversal of non-cash stock-based compensation in the first quarter of 2018 in connection with the resignation of a former officer. The remaining $3.7 million increase in compensation expense was due to the additions to our executive team that occurred late in the second quarter of 2018, and the timing of our 2018 and 2019 performance-based equity awards. In addition, we had a $0.7 million increase in professional fees primarily due to the VEN Bakken Acquisition (see Note 12).
Depletion, Depreciation, Amortization and Accretion
DD&A was $91.2 million in the first six months of 2019, compared to $41.2 million in the first six months of 2018. Depletion expense, the largest component of DD&A, increased by $50.0 million in the first six months of 2019 compared to the first six months of 2018. The aggregate increase in depletion expense was driven by a 78% increase in production levels and a 25% increase in the depletion rate per Boe. On a per unit basis, depletion expense was $14.43 per Boe in the first six months of 2019 compared to $11.56 per Boe in the first six months of 2018. The higher depletion rate per Boe was primarily driven by the impact of recent acquisitions. Depreciation, amortization and accretion was $0.5 million and $0.4 million for the first six months of 2019 and 2018, respectively. The following table summarizes DD&A expense per Boe for the first six months of 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
$ Change
|
|
% Change
|
Depletion
|
$
|
14.43
|
|
$
|
11.56
|
|
$
|
2.87
|
|
25
|
%
|
Depreciation, Amortization and Accretion
|
0.07
|
|
0.10
|
|
(0.03)
|
|
(30)
|
%
|
Total DD&A Expense
|
$
|
14.50
|
|
$
|
11.66
|
|
$
|
2.84
|
|
24
|
%
|
Interest Expense
Interest expense, net of capitalized interest, was $37.3 million for the first six months of 2019 compared to $45.5 million in the first six months of 2018. The decrease in interest expense was primarily due to lower interest rates on our Revolving Credit Facility in place for the first six months of 2019 compared to our term loan credit facility that was in place for the first six months of 2018.
Debt Exchange Derivative Gain (Loss)
As a result of certain debt exchange agreements that were entered into during 2018 (see Note 10 to our condensed financial statements), we incurred debt exchange derivative liabilities during 2018. For the first six months of 2019, we recorded a debt exchange derivative gain of $1.4 million due to a change in the fair value of these liabilities during the first six months of 2019 (see Note 10 to our condensed financial statements). There was no debt exchange derivative gain (loss) in the first six months of 2018, since the relevant agreements were not yet in place.
Contingent Consideration Gain (Loss)
In connection with the W Energy Acquisition and the Pivotal Acquisition in 2018 (see Note 3 to our condensed financial statements), we incurred contingent consideration liabilities during 2018. During the first six months of 2019, we recorded a contingent consideration loss of $23.4 million due to changes in the fair value of these liabilities (see Note 10 to our condensed financial statements). There was no contingent consideration gain (loss) in the first six months of 2018, because the relevant agreements were not yet in place.
Income Tax Benefit
During the first six months of 2019 and 2018, no income tax expense (benefit) was recorded on the income (loss) before income taxes due to uncertainty regarding the realization of our deferred tax assets. For further discussion of our valuation allowance, see Note 9 to our condensed financial statements.
We intend to continue maintaining a full valuation allowance on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of these allowances. However, sufficient positive evidence may become available to allow us to reach a conclusion that a portion of the valuation allowance will no longer be needed. Release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense for the period the release is recorded.
Non-GAAP Financial Measures
We define Adjusted Net Income (Loss) as net income (loss) excluding (i) (gain) loss on the mark-to-market of derivative instruments, net of tax, (ii) impairment of other current assets, net of tax, (iii) loss on the extinguishment of debt, net of tax, (iv) debt exchange derivative (gain) loss, net of tax, (v) contingent consideration (gain) loss, net of tax, and (vi) certain acquisition transaction costs, net of tax. Our Adjusted Net Income for the second quarter of 2019 was $45.5 million or $0.12 per diluted share, compared to $18.0 million or $0.09 per diluted share for the second quarter of 2018. Our Adjusted Net Income for the first six months of 2019 was $62.4 million or $0.16 per diluted share, compared to $29.4 million or $0.22 per diluted share for the first six months of 2018. For both periods, the increase in Adjusted Net Income is primarily due to significantly higher production volumes as a result of our acquisitions and organic growth and lower interest costs, which was partially offset by lower realized commodity prices (after the effect of settled derivatives) and increased per unit production expenses.
We define Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization and accretion, (iv) impairment of other current assets, (v) non-cash stock-based compensation expense, (vi) loss on the extinguishment of debt, (vii) debt exchange derivative (gain) loss, (viii) contingent consideration (gain) loss, and (ix) (gain) loss on the mark-to-market of derivative instruments. Adjusted EBITDA for the second quarter of 2019 was $110.8 million, compared to Adjusted EBITDA of $70.5 million for the second quarter of 2018. Adjusted EBITDA for the first six months of 2019 was $215.6 million, compared to Adjusted EBITDA of $126.5 million for the first six months of 2018. In both periods, the increase in Adjusted EBITDA is primarily due to significantly higher production volumes as a result of our acquisitions and organic growth, which was partially offset by increased per unit production expenses and lower realized commodity prices (after the effect of settled derivatives).
Management believes the use of these non-GAAP financial measures provide useful information to investors to gain an overall understanding of our current financial performance. Specifically, management believes the non-GAAP financial measures included herein provide useful information to both management and investors by excluding certain items that our management believes are not indicative of our core operating results. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring our performance, and we believe that we are providing investors with financial measures that most closely align to our internal measurement processes. We consider these non-GAAP measures to be useful in evaluating our core operating results as they provide useful information regarding our essential revenue generating activities and direct operating expenses (resulting in cash expenditures) needed to perform these revenue generating activities. Our management also believes, based on feedback provided by the investment community, that the non-GAAP financial measures are necessary to allow the investment community to construct its valuation models to better compare our results with our competitors and market sector.
These measures should be considered in addition to our results of operations prepared in accordance with GAAP. In addition, these non-GAAP financial measures are not based on any comprehensive set of accounting rules or principles. We believe that non-GAAP financial measures have limitations in that they do not reflect all of the amounts associated with our results of operations as determined in accordance with GAAP and that these measures should only be used to evaluate our results of operations in conjunction with the corresponding GAAP financial measures.
Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. A reconciliation of these measures to GAAP is included below:
Reconciliation of Adjusted Net Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
|
|
Six Months Ended
June 30,
|
|
|
(In thousands, except share and per share data)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Net Income (Loss)
|
$
|
44,399
|
|
$
|
(96,547)
|
|
$
|
(62,762)
|
|
$
|
(93,582)
|
Add:
|
|
|
|
|
|
|
|
Impact of Selected Items:
|
|
|
|
|
|
|
|
(Gain) Loss on the Mark-to-Market of Derivative Instruments
|
(31,857)
|
|
29,936
|
|
120,311
|
|
42,077
|
|
|
|
|
|
|
|
|
Impairment of Other Current Assets
|
2,694
|
|
—
|
|
2,694
|
|
—
|
|
|
|
|
|
|
|
|
Loss on the Extinguishment of Debt
|
425
|
|
90,833
|
|
425
|
|
90,833
|
Debt Exchange Derivative (Gain) Loss
|
4,873
|
|
—
|
|
(1,413)
|
|
—
|
Contingent Consideration (Gain) Loss
|
24,763
|
|
—
|
|
23,371
|
|
—
|
Acquisition Transaction Costs
|
513
|
|
—
|
|
513
|
|
—
|
Selected Items, Before Income Taxes
|
1,411
|
|
120,769
|
|
145,901
|
|
132,910
|
Income Tax of Selected Items(1)
|
(346)
|
|
(6,180)
|
|
(20,696)
|
|
(9,912)
|
Selected Items, Net of Income Taxes
|
1,065
|
|
114,589
|
|
125,205
|
|
122,998
|
|
|
|
|
|
|
|
|
Adjusted Net Income
|
$
|
45,465
|
|
$
|
18,042
|
|
$
|
62,443
|
|
$
|
29,417
|
|
|
|
|
|
|
|
|
Weighted Average Shares Outstanding – Basic
|
378,368,462
|
|
196,140,610
|
|
374,927,630
|
|
131,039,552
|
Weighted Average Shares Outstanding – Diluted
|
378,724,511
|
|
196,413,013
|
|
375,736,820
|
|
131,248,726
|
|
|
|
|
|
|
|
|
Net Income (Loss) Per Common Share – Basic
|
$
|
0.12
|
|
$
|
(0.49)
|
|
$
|
(0.17)
|
|
$
|
(0.71)
|
Add:
|
|
|
|
|
|
|
|
Impact of Selected Items, Net of Income Taxes
|
—
|
|
0.58
|
|
0.33
|
|
0.93
|
Adjusted Net Income Per Common Share – Basic
|
$
|
0.12
|
|
$
|
0.09
|
|
$
|
0.16
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
Net Income (Loss) Per Common Share – Diluted
|
$
|
0.12
|
|
$
|
(0.49)
|
|
$
|
(0.17)
|
|
$
|
(0.71)
|
Add:
|
|
|
|
|
|
|
|
Impact of Selected Items, Net of Income Taxes
|
—
|
|
0.58
|
|
0.33
|
|
0.93
|
Adjusted Net Income Per Common Share – Diluted
|
$
|
0.12
|
|
$
|
0.09
|
|
$
|
0.16
|
|
$
|
0.22
|
______________
(1)
For the three months ended June 30, 2019, this represents a tax impact using an estimated tax rate of 24.5%, which does not include an adjustment for a change in valuation allowance. For the six months ended June 30, 2019, this represents a tax impact using an estimated tax rate of 24.5%, and includes a $15.1 million adjustment for an increase in valuation allowance. For the three and six months ended June 30, 2018, this represents a tax impact using an estimated tax rate of 24.5%, which includes an adjustment of $23.4 million and $22.7 million, respectively, for a reduction in valuation allowance.
Reconciliation of Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
|
|
Six Months Ended
June 30,
|
|
|
(In thousands)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Net Income (Loss)
|
$
|
44,399
|
|
$
|
(96,547)
|
|
$
|
(62,762)
|
|
$
|
(93,582)
|
Add:
|
|
|
|
|
|
|
|
Interest Expense
|
17,778
|
|
22,403
|
|
37,327
|
|
45,510
|
Income Tax Provision (Benefit)
|
—
|
|
—
|
|
—
|
|
—
|
Depreciation, Depletion, Amortization and Accretion
|
46,091
|
|
22,596
|
|
91,225
|
|
41,227
|
Impairment of Other Current Assets
|
2,694
|
|
—
|
|
2,694
|
|
—
|
Non-Cash Stock-Based Compensation
|
1,643
|
|
1,324
|
|
4,394
|
|
438
|
|
|
|
|
|
|
|
|
Loss on the Extinguishment of Debt
|
425
|
|
90,833
|
|
425
|
|
90,833
|
Debt Exchange Derivative (Gain) Loss
|
4,873
|
|
—
|
|
(1,413)
|
|
—
|
Contingent Consideration (Gain) Loss
|
24,763
|
|
—
|
|
(23,371)
|
|
—
|
|
|
|
|
|
|
|
|
(Gain) Loss on the Mark-to-Market of Derivative Instruments
|
(31,857)
|
|
29,936
|
|
120,311
|
|
42,077
|
Adjusted EBITDA
|
$
|
110,810
|
|
$
|
70,546
|
|
$
|
215,572
|
|
$
|
126,504
|
Liquidity and Capital Resources
Overview
Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, proceeds from equity and debt financings, credit facility borrowings, and cash settlements of derivative contracts. Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.
In October 2018, we completed a series of refinancing transactions, including (i) entry into a new revolving credit facility (the “Revolving Credit Facility”) with Royal Bank of Canada and the lenders from time to time party thereto and (ii) issuances of additional 8.50% senior secured second lien notes due 2023 (the “Second Lien Notes”).
As of June 30, 2019, we had (i) long-term debt consisting of $173.0 million of borrowings under our Revolving Credit Facility and $688.5 million aggregate principal amount of Second Lien Notes, and (ii) $254.8 million in liquidity, consisting of $252.0 million of borrowing base availability under our Revolving Credit Facility and $2.8 million of cash on hand.
One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 81% and 85% of our total production volumes in the second quarter of 2019 and 2018, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices. We seek to maintain a robust hedging program to mitigate volatility in the price of crude oil with respect to a portion of our expected oil production. In 2018, we hedged approximately 64% of our crude oil production and for the three months ended June 30, 2019, we hedged approximately 75% of our crude oil production. For a summary as of June 30, 2019, of our open commodity swap contracts for future periods, see “Item 3. Quantitative and Qualitative Disclosures about Market Risk” below.
With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.
In April 2019, we entered into a purchase and sale agreement with VEN Bakken, LLC (“Seller”), pursuant to which we agreed to acquire certain oil and gas properties and interests. Seller is a wholly-owned subsidiary of Flywheel Bakken, LLC, a portfolio company of the Kayne Private Energy Income Funds. The transaction closed on July 1, 2019, subsequent to the end of the second quarter. Upon closing, we paid Seller $170.1 million in cash, 5,602,147 shares of common stock and $130.0 million in principal amount of a newly issued 6.0% Senior Unsecured Promissory Note due 2022.
Our increase in production and higher commodity prices have increased our cash flow from operations, which exceeded our cash spend for drilling and development activities by $58.2 million for the six months ended June 30, 2019, excluding cash paid for the acquisition of oil and natural gas properties. With higher production and the impact of recent acquisitions, we anticipate that we will continue to generate a cash flow surplus in future periods (excluding cash paid for any acquisitions).
Our recent capital commitments have been to fund drilling in the Williston Basin and to fund acquisitions of acreage and oil and gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility. Our capital expenditures could be curtailed if our cash flows decline from expected levels. Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future.
Working Capital
Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, collection of receivables, expenditures related to our development and production operations and the impact of our outstanding derivative instruments.
At June 30, 2019, we had a working capital deficit of $99.7 million, compared to a deficit of $3.1 million at December 31, 2018. Current assets decreased by $95.3 million and current liabilities increased by $1.2 million at June 30, 2019, compared to December 31, 2018. The decrease in current assets is primarily due to a decrease in our derivative instruments of $83.3 million due to the change in fair value as a result of oil price projections. The change in current liabilities is due to a $38.3 million increase in our accounts payable primarily due to an increase in development activity and net wells, which was partially offset by a $21.1 million decrease in contingent consideration liabilities in connection with our Pivotal and W Energy Acquisitions (see Note 3 to our condensed financial statements), and a reduction in the debt exchange derivative liabilities of $15.4 million (see Note 10 to our condensed financial statements).
Cash Flows
Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts. Our cash flows from operations also are impacted by changes in working capital. Any payments due to counterparties under our derivative contracts are generally funded by proceeds received from the sale of our production. Production receipts, however, lag payments to the counterparties. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. As of June 30, 2019, we had entered into derivative swap contracts hedging 4.2 million barrels of oil for the remainder of 2019 at an average price of $62.96 per barrel, 7.8 million barrels of oil in 2020 at an average price of $59.31 per barrel, 2.9 million barrels of oil in 2021 at an average price of $57.96 per barrel, 0.5 million barrels of oil in 2022 at an average price of $55.06 per barrel.
Our cash flows for the six months ended June 30, 2019 and 2018 are presented below:
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Six Months Ended
June 30,
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2019
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2018
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(in thousands, unaudited)
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Net Cash Provided by Operating Activities
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$
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198,300
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$
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63,617
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Net Cash Used for Investing Activities
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(191,141)
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(159,679)
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Net Cash (Used for) Provided by Financing Activities
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(6,723)
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194,804
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Net Change in Cash
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$
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436
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$
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98,741
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Cash Flows from Operating Activities
Net cash provided by operating activities for the six months ended June 30, 2019 was $198.3 million, compared to $63.6 million in the same period of the prior year. This increase was due to higher production levels and lower interest costs partially offset by lower realized prices (including the effect of settled derivatives). Net cash provided by operating activities is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our statements of cash flows) in the six months ended June 30, 2019 was an increase of $17.2 million compared to a decrease of $20.2 million in the same period of the prior year.
Cash Flows from Investing Activities
Cash flows used in investing activities during the six months ended June 30, 2019 and 2018 were $191.1 million and $159.7 million, respectively. The increase in cash used in investing activities for the first six months of 2019 as compared to the same period of 2018 was attributable to higher development spending and acquisitions. Additionally, the amount of capital expenditures included in accounts payable (and thus not included in cash flows from investing activities) was $151.1 million and $80.1 million at June 30, 2019 and 2018, respectively, as a result of increased activity in the Williston Basin.
Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred. As a result, our actual cash spending is not always reflective of current levels of development activity. For instance, during the six months ended June 30, 2019, our capitalized costs incurred for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to $180.7 million, while the actual cash spend in this regard amounted to $159.5 million.
Development and acquisition activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the six months ended June 30, 2019 and 2018 are summarized in the following table:
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Six Months Ended
June 30,
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2019
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2018
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(in millions, unaudited)
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Drilling and Development Capital Expenditures
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$
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139.6
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$
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110.4
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Acquisition of Oil and Natural Gas Properties
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19.4
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49.0
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Other Capital Expenditures
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0.5
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0.3
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Total
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$
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159.5
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$
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159.7
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Cash Flows from Financing Activities
Net cash used for financing activities was $6.7 million during the six months ended June 30, 2019, compared to cash provided by financing activities of $194.8 million during the six months ended June 30, 2018. For the six months ended June 30, 2019, cash used for financing activities was primarily related to $15.1 million of common stock repurchases, $10.5 million in repurchases of Second Lien Notes and $13.4 million for settlements related to our contingent consideration and debt exchange derivative liabilities, which were partially offset by $33.0 million of net borrowings under the Revolving Credit Facility. For the six months ended June 30, 2018, cash provided by financing activities was primarily related to the issuance of common stock of $141.7 million and borrowings under our prior term loan credit agreement of $60.0 million.
Revolving Credit Facility
In October 2018, we entered into a $750.0 million Revolving Credit Facility with Royal Bank of Canada, as administrative agent, and the lenders from time to time party thereto. The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to our oil and gas properties. As of June 30, 2019, the Revolving Credit Facility had a borrowing base of $425.0 million and we had $173.0 million in borrowings outstanding under the facility, leaving $252.0 million in available borrowing capacity. See Note 4 to our condensed financial statements for further details regarding the Revolving Credit Facility.
Second Lien Notes due 2023
As of June 30, 2019, we had $688.5 million in outstanding principal amount of our 8.500% senior secured second lien notes due 2023. See Note 4 to our condensed financial statements for further details regarding the Second Lien Notes.
Effects of Inflation and Pricing
The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.
Contractual Obligations and Commitments
Please see our disclosure of contractual obligations and commitments as of December 31, 2018, included in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.
Significant Accounting Policies
Our critical accounting policies involving significant estimates include impairment testing of natural gas and crude oil production properties, asset retirement obligations, revenue recognition, derivative instruments and hedging activity, and income taxes. There were no material changes in our critical accounting policies involving significant estimates from those reported in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.
A description of our critical accounting policies was provided in Note 2 to our financial statements provided in Part II, Item 8 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.