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UNITED STATES
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SECURITIES AND EXCHANGE COMMISSION
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Washington, D.C. 20549
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FORM 10-K
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Large Accelerated Filer
¨
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Accelerated Filer
¨
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Non-Accelerated Filer
x
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Smaller Reporting Company
¨
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Emerging Growth Company
¨
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PART I
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PART II
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PART III
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PART IV
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•
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our business strategy;
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our reserves;
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our drilling plans, prospects, inventories, projects and programs;
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our ability to replace the reserves we produce through drilling and property acquisitions;
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our financial strategy, liquidity and capital required for our drilling program and timing related thereto;
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our realized oil, natural gas and NGL prices;
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the timing and amount of our future production of oil, natural gas and NGLs;
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our competition and government regulations;
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our ability to obtain permits and governmental approvals;
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our pending legal or environmental matters;
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our marketing of oil, natural gas and NGLs;
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our leasehold or business acquisitions;
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our costs of developing our properties;
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our hedging strategy and results;
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general economic conditions;
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credit markets;
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uncertainty regarding our future operating results including initial production values and liquid yields in our type curve areas;
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the costs, terms and availability of gathering, processing, fractionation and other midstream services; and
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our plans, objectives, expectations and intentions that are not historical.
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Generate attractive full-cycle returns through the efficient development of our extensive, low‑risk drilling inventory.
We intend to efficiently achieve industry leading rates of return by leveraging the scale of our core leasehold positions, experience from the success of our drilling program to date, technical understanding of the reservoirs, our extensive catalogue of technical information and experience of our operational teams. We intend to allocate capital in a disciplined manner to projects that we believe will produce predictable and attractive full-cycle rates of return.
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Maximize value of our asset base through constant focus on improving operating, production and capital efficiencies.
We utilize proprietary data analytics, combined with operational procedures and metrics, to evaluate well results and adjust drilling and production techniques in real time. We use this framework in an effort to maximize hydrocarbon recoveries per well by optimizing location selection, wellbore targeting, well completion designs and production techniques.
Additionally, we seek to reduce capital and operating costs of drilling and completing horizontal wells by decreasing development cycle times, optimizing the use of surface facilities, capitalizing on our knowledge of the target formations and focusing on service cost management practices.
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Maintain a high degree of operational control to facilitate efficient development and capital budgeting.
We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operational improvements and cost efficiencies. As of
December 31, 2018
, we operated approximately
71%
of our total acreage. We believe that maintaining a high degree of control of the development of our properties and of our production enables us to increase hydrocarbon recovery rates, lower capital and operating costs and improve drilling performance through optimization of our drilling, completion and production management techniques. Additionally, we believe operatorship allows us to control wellsite selection, spacing and lateral targeting and manage the pace of our development activities, which we believe can significantly enhance full-cycle returns.
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Maintain a disciplined, returns-driven strategy with a focus on maintaining financial flexibility.
We intend to maintain a conservative financial profile that will afford us flexibility through the commodity price and capital market cycles inherent in the oil and natural gas industry. We intend to generate stable production and reserves growth by funding our development program primarily with cash flow from operations, borrowings under our credit facility and capital markets offerings.
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Selectively pursue opportunities to augment our asset base through the disciplined acquisition or leasing of oil and natural gas properties
.
As one of the most active operators in Oklahoma, we believe we are well positioned to selectively pursue accretive consolidation opportunities. We believe the strength of our operational program provides a competitive advantage in the pursuit of such opportunities. We will continue to identify and evaluate acquisition and leasing opportunities around and within our concentrated acreage position, as well as other areas in Oklahoma, that meet our strategic and financial objectives.
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Large, contiguous acreage position in the core of the Merge play with significant operational control.
We are the largest leaseholder in the Merge play, with approximately
115,000
net acres as of
December 31, 2018
. We believe that the scale and concentration of our acreage position allows for efficient field development through long laterals and shared facilities, with approximately
80%
of our Merge sections capable of 1.5 mile or longer lateral development. Additionally, our acreage position is concentrated in areas that we believe demonstrate higher percentage production of oil and NGLs within the Merge play, and provides us development opportunities through multiple stacked prospective development horizons. As of
December 31, 2018
, we operated
81%
of our net acreage in the Merge and we intend to maintain operational control over the majority of our drilling inventory, as we believe this enables us to increase our production and reserves and control our development costs, and ultimately increase shareholder value.
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Long-lived inventory of locations with predictable production profiles that provide high rate-of-return development opportunities.
Through the drilling of
163
operated horizontal wells and participation in
317
non-operated horizontal wells across our acreage, we have substantially delineated our acreage and have acquired significant amounts of subsurface information. Based on this delineation and general industry Merge, SCOOP and STACK well production history, we believe that our acreage position will provide a large portfolio of drilling locations characterized by long-lived reserves, predictable production profiles and attractive return potential.
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Geographically advantaged assets with significant available midstream infrastructure and favorable regulatory climate.
Our acreage position is in close proximity or has available access to end markets for oil, natural gas and NGLs, providing us with a regional price advantage relative to other U.S. onshore oil-weighted basins. For example, our realized oil price differential to NYMEX WTI average prices in the year ended
December 31, 2018
was
$1.67
per barrel compared to a WTI-Midland oil price differential to NYMEX WTI average prices in the year ended
December 31, 2018
of
$7.29
per barrel. Oklahoma has a long history of oil and natural gas production, and therefore there is existing midstream infrastructure in place across our acreage position to support our drilling program. In addition, we believe that oilfield services availability is greater in our focus area than in other major U.S. onshore basins and that such availability is a competitive advantage in assuring the ability to access necessary development services at attractive pricing.
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Experienced operations leadership with substantial technical expertise.
We believe our operational management team provides us with a distinct competitive advantage. Our team has significant experience working together throughout the Mid-Continent and evaluating the Merge play in particular. Collectively, our Chief Executive Officer, Executive Vice President - Operations and Marketing, Executive Vice President - Geosciences and Business Development and members of our operations management team have over 90 years of experience in the oil and natural gas industry and have been involved in drilling over 1,000 horizontal wells across multiple plays in the lower 48 states. We believe their experience is instrumental in the execution of our pursuit of operational and capital efficiencies.
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Significant financial strength and flexibility.
We believe we have a strong financial position, including a low debt profile and a large production base that generates significant cash flow, allowing us to strategically allocate capital in order to enhance shareholder value. We are well-positioned to adjust our development program based on market and industry conditions, as we have minimal commitments to deliver specified volumes, no rig contracts extending beyond 12 months and approximately
84%
of our acreage is HBP as of
December 31, 2018
. We believe that our conservative capital structure, which we will seek to maintain through a disciplined approach to capital spending, and other potential financing sources will provide us with sufficient liquidity and flexibility to execute our development capital program.
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High Degree of Operational Control.
We expect that we will be able to control operations on approximately
71%
of our acreage in the Merge, SCOOP and STACK plays. For these purposes, we have assumed that we will control any unit in which we have leased a minimum of 37.5% of the acreage in the unit. Operational control of our leasehold positions allows us to control the development and production methods, as well as the pace of development on our wells.
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Contiguous Acreage Position.
A substantial portion of the sections in which we have operational control are offset to the north or south by adjacent controlled sections. Specifically, approximately
66%
of our sections in the Merge, SCOOP and STACK plays can be developed on a multi-unit basis. As a result, we are able to develop long lateral horizontal wells for the majority of our drilling program, which we believe have exhibited superior economics as compared to shorter laterals as a result of development cost efficiencies.
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Largely Held-by-Production.
Approximately
84%
of our total acreage position was HBP as of December 31, 2018. We expect this high percentage of HBP acreage to enhance capital efficiencies in our development program, as we will pursue development locations with the favorable risk-adjusted rates of return in our location selection process, as opposed to selecting locations in order to hold acreage.
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review and verification of historical production data, which data is based on actual production as reported by us;
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review of reserve estimates by our Reservoir Engineering Manager or under his direct supervision;
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review by our Executive Vice President—Operations and Marketing of all of our reported proved reserves, including the review of all significant reserve changes and all new PUDs additions;
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review by our management team of reported proved reserves and significant reserve changes;
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direct reporting responsibilities by our Reservoir Engineering Manager to our Executive Vice President—Operations and Marketing; and
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verification of property ownership by our land department.
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Proved developed reserves
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Oil (MBbls)
(1)
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18,652
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Natural gas (MMcf)
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369,677
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NGLs (MBbls)
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39,927
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Total (MBoe)
(1)
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120,192
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Proved undeveloped reserves
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Oil (MBbls)
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37,031
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Natural gas (MMcf)
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541,505
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NGLs (MBbls)
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58,485
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Total (MBoe)
(1)
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185,767
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Total proved reserves
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Oil (MBbls)
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55,683
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Natural gas (MMcf)
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911,182
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NGLs (MBbls)
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98,412
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Total (MBoe)
(1)
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305,959
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Benchmark Oil and Natural Gas prices
(2)
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Oil - WTI per Bbl
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$
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65.66
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Natural gas - Henry Hub per MMBtu
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$
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3.16
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Standardized measure (in thousands)
(3)
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$
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1,699,701
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PV-10 of proved reserves (in thousands)
(4)
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$
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2,091,509
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(1)
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Totals may not sum or recalculate due to rounding.
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(2)
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Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance adjusted for quality, transportation fees, regional price differentials, and in the case of natural gas, energy content. For oil and NGLs volumes, the average WTI posted price of
$65.66
per barrel as of
December 31, 2018
, was adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub spot price of
$3.16
per MMBtu as of
December 31, 2018
was similarly adjusted for gravity, quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are
$64.49
per barrel of oil,
$20.35
per barrel of NGLs and
$1.90
per Mcf of natural gas as of
December 31, 2018
.
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(3)
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Please see “Risk Factors— The standardized measure of our estimated reserves contained in this Annual Report and in the footnotes to our financial statements is not an accurate estimate of the current fair value of our estimated reserves.”
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(4)
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PV-10 is not a financial measure calculated or presented in accordance with GAAP and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. The following table reconciles the GAAP standardized measure of discounted future net cash flows to PV-10 at December 31, 2018 (in thousands):
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Standardized measure of discounted future net cash flows
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$
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1,699,701
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Present value of future income taxes discounted at 10%
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391,808
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PV-10 of proved reserves
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$
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2,091,509
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Balance, December 31, 2017
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151,724
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Extensions and discoveries
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127,804
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Revisions of previous estimates
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(67,260
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)
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Transfers to proved developed
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(26,501
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)
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Balance, December 31, 2018
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185,767
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Years Ended December 31,
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2018
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2017
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2016
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Production Data
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Oil (MBbls)
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4,364
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1,454
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739
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Natural gas (MMcf)
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41,890
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17,582
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6,382
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Natural gas liquids (MBbls)
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4,592
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1,524
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546
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Total volumes (MBoe)
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15,938
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5,908
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2,349
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Average daily total volumes (MBoe/d)
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43.7
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16.2
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6.4
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Average Prices - as reported
(1)
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Oil (per Bbl)
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$
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63.07
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$
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52.87
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$
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41.36
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Natural gas (per Mcf)
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$
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1.82
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$
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2.80
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$
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2.52
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Natural gas liquids (per Bbl)
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$
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19.27
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$
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26.44
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$
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15.21
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Total (per Boe)
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$
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27.59
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$
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28.16
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$
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23.40
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Average Prices - including impact of derivative contract settlements
(1)
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Oil (per Bbl)
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$
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55.87
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$
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53.57
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$
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41.36
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Natural gas (per Mcf)
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$
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1.73
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$
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2.89
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$
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2.52
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Natural gas liquids (per Bbl)
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$
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19.60
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$
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26.44
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$
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15.21
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Total (per Boe)
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$
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25.50
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$
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28.60
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$
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23.40
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Average Prices - excluding gathering, transportation and processing costs
(2)
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Oil (per Bbl)
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$
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63.11
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$
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52.87
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$
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41.36
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Natural gas (per Mcf)
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$
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2.29
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$
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2.80
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$
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2.52
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Natural gas liquids (per Bbl)
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$
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24.83
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$
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26.44
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$
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15.21
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Total (per Boe)
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$
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30.46
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$
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28.16
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$
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23.40
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Average Costs per Boe
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Production expenses
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$
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2.99
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$
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2.86
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$
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2.17
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Gathering, transportation and processing
(1)
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$
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—
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$
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3.15
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$
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2.52
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Production taxes
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$
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1.10
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$
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0.62
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$
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0.46
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General and administrative
(3)
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$
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3.82
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$
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5.31
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$
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2.38
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(1)
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Average prices and costs for the year ended
December 31, 2018
reflect the adoption of Accounting Standards Codification Topic 606
Revenue from Contracts with Customers
(“ASC 606“) on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.
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(2)
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Excludes the effects of netting gathering, transportation and processing costs under ASC 606.
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(3)
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General and administrative expenses for the years ended
December 31, 2018
and
2017
include
$0.69
per Boe and
$0.06
per Boe of equity-based compensation expense, respectively.
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Oil
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Natural Gas
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Total
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Gross
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Net
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Gross
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Net
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Gross
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Net
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||||||
Operated
|
140
|
|
|
110
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|
|
451
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|
|
339
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|
|
591
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|
|
449
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Non-operated
|
318
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|
19
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|
|
354
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|
34
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|
|
672
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|
|
53
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Total
|
458
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|
|
129
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|
|
805
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|
|
373
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|
|
1,263
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|
502
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Developed Acreage
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Undeveloped Acreage
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Total Acreage
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Gross
(1)
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Net
(2)
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Gross
(1)
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Net
(2)
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|
Gross
(1)
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Net
(2)
|
298,019
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|
144,932
|
|
85,411
|
|
27,038
|
|
383,430
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|
171,970
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(1)
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A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
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(2)
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A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
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2019
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2020
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|
2021
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|
2022
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|
2023 and Thereafter
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||||||||||
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
19,563
|
|
6,675
|
|
42,712
|
|
10,766
|
|
10,944
|
|
4,056
|
|
—
|
|
—
|
|
—
|
|
—
|
|
For the Years Ended December 31,
|
||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Exploratory Wells
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Exploratory
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Development Wells
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
(1)
|
214
|
|
|
72
|
|
|
93
|
|
|
35
|
|
|
55
|
|
|
19
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Development
|
214
|
|
|
72
|
|
|
93
|
|
|
35
|
|
|
55
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Total Wells
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
(1)
|
214
|
|
|
72
|
|
|
93
|
|
|
35
|
|
|
55
|
|
|
19
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
214
|
|
|
72
|
|
|
93
|
|
|
35
|
|
|
55
|
|
|
19
|
|
(1)
|
Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history.
|
|
Years Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Coffeyville Resources Refining & Marketing LLC
|
31
|
%
|
|
*
|
|
|
*
|
|
Sunoco Inc.
|
18
|
%
|
|
40
|
%
|
|
55
|
%
|
Blue Mountain Midstream LLC
|
15
|
%
|
|
*
|
|
|
*
|
|
EnLink Oklahoma Gas Processing, LP
|
13
|
%
|
|
39
|
%
|
|
31
|
%
|
•
|
worldwide and regional political or economic conditions impacting the global supply and demand for oil, natural gas and NGLs;
|
•
|
the level of global oil, natural gas and NGL exploration and production;
|
•
|
the level of commodity storage inventories;
|
•
|
political and economic conditions in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia;
|
•
|
actions of the Organization of the Petroleum Exporting Countries, its members and other state-controlled oil companies relating to oil price and production controls;
|
•
|
prevailing prices on local price indexes in the area in which we operate and expectations about future commodity prices;
|
•
|
the proximity, capacity, cost and availability of gathering and transportation facilities;
|
•
|
localized and global supply and demand fundamentals and transportation availability;
|
•
|
the cost of exploring for, developing and producing reserves and transporting production;
|
•
|
weather conditions and other natural disasters;
|
•
|
technological advances affecting energy consumption and production;
|
•
|
speculative trading in oil, natural gas and NGL markets;
|
•
|
the price and availability of alternative fuels; and
|
•
|
U.S. federal, state and local and non-U.S. governmental regulation and taxes.
|
•
|
the prices at which our production is sold;
|
•
|
our proved reserves;
|
•
|
the volume and types of hydrocarbons we are able to produce from existing wells;
|
•
|
our ability to acquire, locate and produce new reserves;
|
•
|
the levels of our operating expenses; and
|
•
|
our ability to borrow under our credit facility and our ability to access the capital markets.
|
•
|
increased responsibilities for our executive level personnel;
|
•
|
increased administrative burden;
|
•
|
increased capital requirements; and
|
•
|
increased organizational challenges common to large, expansive operations.
|
•
|
incur additional indebtedness;
|
•
|
incur liens;
|
•
|
enter into mergers;
|
•
|
sell assets;
|
•
|
make investments and loans;
|
•
|
make or declare dividends;
|
•
|
enter into commodity hedges exceeding a specified percentage of our expected production or proved reserves;
|
•
|
enter into interest rate hedges exceeding a specified percentage of our outstanding indebtedness; and
|
•
|
engage in transactions with affiliates.
|
•
|
compliance with regulatory requirements, including those relating to water supply, discharge and disposal of waste water and other hazardous materials, emission of GHGs and limitations on hydraulic fracturing;
|
•
|
pressure or irregularities in geological formations;
|
•
|
shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;
|
•
|
equipment failures, accidents or other unexpected operational incidents;
|
•
|
lack of available gathering facilities or delays in construction of gathering facilities;
|
•
|
lack of available capacity on interconnecting transmission pipelines;
|
•
|
adverse weather conditions;
|
•
|
environmental hazards, such as oil and natural gas leaks, oil spills, fires or explosions, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
|
•
|
declines in oil and natural gas prices;
|
•
|
limited availability of financing at acceptable terms;
|
•
|
title problems; and
|
•
|
limitations in the market for oil and natural gas.
|
•
|
production is less than the volume covered by the derivative instruments;
|
•
|
the counterparty to the derivative instrument defaults on its contractual obligations;
|
•
|
there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
|
•
|
there are issues with regard to legal enforceability of such instruments.
|
•
|
landing our wellbore in the desired drilling zone;
|
•
|
staying in the desired drilling zone while drilling horizontally through the formation;
|
•
|
running our casing the entire length of the wellbore; and
|
•
|
being able to run tools and other equipment consistently through the horizontal wellbore.
|
•
|
the ability to fracture stimulate the planned number of stages;
|
•
|
the ability to run tools the entire length of the wellbore during completion operations; and
|
•
|
the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
|
•
|
the timing and amount of capital expenditures;
|
•
|
the operator’s expertise and financial resources;
|
•
|
the approval of other participants in drilling wells;
|
•
|
the selection of technology; and
|
•
|
the rate of production of reserves, if any.
|
•
|
environmental hazards, such as unpermitted releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;
|
•
|
abnormally pressured formations;
|
•
|
mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
|
•
|
fires, explosions and ruptures of pipelines;
|
•
|
personal injuries and death;
|
•
|
natural disasters; and
|
•
|
terrorist attacks targeting oil and natural gas related facilities and infrastructure.
|
•
|
injury or loss of life;
|
•
|
damage to and destruction of property, natural resources and equipment;
|
•
|
pollution and other environmental damage;
|
•
|
regulatory investigations and penalties;
|
•
|
suspension of our operations; and
|
•
|
repair and remediation costs.
|
•
|
recoverable reserves;
|
•
|
future oil and natural gas prices and their applicable differentials;
|
•
|
operating costs; and
|
•
|
potential environmental and other liabilities.
|
•
|
permits such persons to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and
|
•
|
provides that if any of such persons or any employee, partner, member, manager, officer or director of any of such persons who is also one of our directors becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.
|
•
|
limitations on the removal of directors;
|
•
|
limitations on the ability of our stockholders to call special meetings;
|
•
|
establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;
|
•
|
providing that the board of directors is expressly authorized to adopt, or to alter or repeal our second amended and restated bylaws; and
|
•
|
establishing advance notice and certain information requirements for nominations for election to our board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.
|
(1)
|
Includes financial information from July 1, 2014 to December 31, 2014. Citizen, the predecessor of Roan LLC, was formed on July 1, 2014
|
(2)
|
As described above, Roan Inc. was formed in conjunction with the Reorganization. Roan Inc. is a corporation, and, as a result, is subject to U.S. federal, state and local income taxes. Our predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of Roan LLC and any related tax credits, for income tax purposes, flowed through to its members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of its members.
|
(3)
|
For 2017, 2016, 2015 and 2014, amounts reflect the weighted average number of shares of common stock outstanding based on retrospectively reflecting the impact of the Reorganization.
|
|
December 31,
|
||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
|
(in thousands)
|
||||||||||||||||||
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
6,883
|
|
|
$
|
1,471
|
|
|
$
|
6,853
|
|
|
$
|
22,814
|
|
|
$
|
1,583
|
|
Oil and natural gas properties, net
|
$
|
2,397,497
|
|
|
$
|
1,798,644
|
|
|
$
|
298,378
|
|
|
$
|
81,476
|
|
|
$
|
14,508
|
|
Total assets
|
$
|
2,749,109
|
|
|
$
|
1,885,592
|
|
|
$
|
363,083
|
|
|
$
|
113,053
|
|
|
$
|
16,618
|
|
Current liabilities
|
$
|
365,473
|
|
|
$
|
203,344
|
|
|
$
|
66,594
|
|
|
$
|
13,638
|
|
|
$
|
1,076
|
|
Long-term debt
|
$
|
514,639
|
|
|
$
|
85,339
|
|
|
$
|
20,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total equity
|
$
|
1,495,034
|
|
|
$
|
1,584,769
|
|
|
$
|
274,247
|
|
|
$
|
98,292
|
|
|
$
|
15,126
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
|
(in thousands)
|
||||||||||||||||||
Cash Flow Data
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
$
|
268,296
|
|
|
$
|
60,275
|
|
|
$
|
36,140
|
|
|
$
|
4,637
|
|
|
$
|
166
|
|
Net cash used in investing activities
|
$
|
(689,092
|
)
|
|
$
|
(212,521
|
)
|
|
$
|
(241,109
|
)
|
|
$
|
(66,181
|
)
|
|
$
|
(14,036
|
)
|
Net cash provided by financing activities
|
$
|
426,208
|
|
|
$
|
146,864
|
|
|
$
|
189,008
|
|
|
$
|
82,775
|
|
|
$
|
15,453
|
|
•
|
actual and projected reserve and production levels;
|
•
|
realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;
|
•
|
lease operating expenses; and
|
•
|
capital expenditures on our oil and natural gas properties.
|
•
|
Net loss was
$140.7 million
for the
year ended December 31, 2018
, as compared to net income of
$18.5 million
for the
year ended December 31, 2017
. The net loss was primarily due to:
|
•
|
$30.7 million
increase
in production expenses, primarily related to an increase in production volumes in 2018;
|
•
|
$86.5 million
increase
in depreciation, depletion, amortization and accretion, primarily due to increased production volumes and a higher depletion rate due to increases in capital expenditures during 2018;
|
•
|
$29.5 million
increase
in general & administrative expenses, primarily due to salaries and benefits to our employees and equity-based compensation expense during the
year ended December 31, 2018
; and
|
•
|
$356.9 million
of income tax expense during the
year ended December 31, 2018
, which includes
$304.5 million
resulting from the initial deferred tax liability recognized upon becoming a taxable entity after the Reorganization.
|
•
|
$273.4 million
increase
in oil, natural gas and NGL sales, primarily as a result of an
increase
in total production volumes during the
year ended December 31, 2018
; and
|
•
|
$78.1 million
gain on derivative contracts for the
year ended December 31, 2018
primarily as a result of lower oil prices at December 31, 2018.
|
•
|
Average daily sales volumes were
43.7
MBoe for the
year ended December 31, 2018
, an increase of
170%
compared to
16.2
MBoe during 2017.
|
•
|
Drilled or participated in
214
gross (
72
net) wells with first production during 2018.
|
•
|
1,263
gross (
502
net) producing wells online at
December 31, 2018
, including
591
gross (
449
net) operated wells.
|
|
Years Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Revenues
|
|
|
|
|
|
|||
Oil sales
(1)
|
63
|
%
|
|
46
|
%
|
|
56
|
%
|
Natural gas sales
(1)
|
17
|
%
|
|
30
|
%
|
|
29
|
%
|
Natural gas liquid sales
(1)
|
20
|
%
|
|
24
|
%
|
|
15
|
%
|
(1)
|
Revenue for the year ended
December 31, 2018
reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Average NYMEX prices
|
|
|
|
|
|
|
||||||
Oil (Bbl)
|
|
$
|
64.74
|
|
|
$
|
50.95
|
|
|
$
|
43.32
|
|
Natural gas (MMcf)
|
|
$
|
3.28
|
|
|
$
|
3.10
|
|
|
$
|
2.61
|
|
|
Years Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
Production Data
|
|
|
|
||||
Oil (MBbls)
|
4,364
|
|
|
1,454
|
|
||
Natural gas (MMcf)
|
41,890
|
|
|
17,582
|
|
||
Natural gas liquids (MBbls)
|
4,592
|
|
|
1,524
|
|
||
Total volumes (MBoe)
|
15,938
|
|
|
5,908
|
|
||
Average daily total volumes (MBoe/d)
|
43.7
|
|
|
16.2
|
|
||
Average Prices - as reported
(1)
|
|
|
|
||||
Oil (per Bbl)
|
$
|
63.07
|
|
|
$
|
52.87
|
|
Natural gas (per Mcf)
|
$
|
1.82
|
|
|
$
|
2.80
|
|
Natural gas liquids (per Bbl)
|
$
|
19.27
|
|
|
$
|
26.44
|
|
Total (per Boe)
|
$
|
27.59
|
|
|
$
|
28.16
|
|
Average Prices - including impact of derivative contract settlements
(1)
|
|
|
|
||||
Oil (per Bbl)
|
$
|
55.87
|
|
|
$
|
53.57
|
|
Natural gas (per Mcf)
|
$
|
1.73
|
|
|
$
|
2.89
|
|
Natural gas liquids (per Bbl)
|
$
|
19.60
|
|
|
$
|
26.44
|
|
Total (per Boe)
|
$
|
25.50
|
|
|
$
|
28.60
|
|
Average Prices - excluding gathering, transportation and processing costs
(2)
|
|
|
|||||
Oil (per Bbl)
|
$
|
63.11
|
|
|
$
|
52.87
|
|
Natural gas (per Mcf)
|
$
|
2.29
|
|
|
$
|
2.80
|
|
Natural gas liquids (per Bbl)
|
$
|
24.83
|
|
|
$
|
26.44
|
|
Total (per Boe)
|
$
|
30.46
|
|
|
$
|
28.16
|
|
(1)
|
Average prices for the year ended
December 31, 2018
reflect the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.
|
(2)
|
Excludes the effects of netting gathering, transportation and processing costs under ASC 606.
|
|
Years Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands)
|
||||||
Revenues
|
|
|
|
||||
Oil sales
(1)
|
$
|
275,239
|
|
|
$
|
76,876
|
|
Natural gas sales
(1)
|
76,056
|
|
|
49,211
|
|
||
Natural gas liquid sales
(1)
|
88,472
|
|
|
40,298
|
|
||
Gain (loss) on derivative contracts
|
78,054
|
|
|
(6,797
|
)
|
||
Total revenues
|
$
|
517,821
|
|
|
$
|
159,588
|
|
(1)
|
Revenue for the year ended
December 31, 2018
reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.
|
|
Years Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands, except costs per Boe)
|
||||||
Operating Expenses
|
|
|
|
||||
Production expenses
|
$
|
47,600
|
|
|
$
|
16,872
|
|
Gathering, transportation and processing
(1)
|
—
|
|
|
18,602
|
|
||
Production taxes
|
17,579
|
|
|
3,685
|
|
||
Exploration expenses
|
43,303
|
|
|
32,629
|
|
||
Depreciation, depletion, amortization and accretion
|
123,922
|
|
|
37,376
|
|
||
General and administrative
(2)
|
60,874
|
|
|
31,357
|
|
||
Gain on sale of oil and natural gas properties
|
—
|
|
|
(838
|
)
|
||
Total
|
$
|
293,278
|
|
|
$
|
139,683
|
|
Average Costs per Boe
|
|
|
|
||||
Production expenses
|
$
|
2.99
|
|
|
$
|
2.86
|
|
Gathering, transportation and processing
(1)
|
—
|
|
|
3.15
|
|
||
Production taxes
|
1.10
|
|
|
0.62
|
|
||
Exploration expenses
|
2.72
|
|
|
5.52
|
|
||
Depreciation, depletion, amortization and accretion
|
7.78
|
|
|
6.33
|
|
||
General and administrative
(2)
|
3.82
|
|
|
5.31
|
|
||
Gain on sale of oil and natural gas properties
|
—
|
|
|
(0.14
|
)
|
||
Total
|
$
|
18.41
|
|
|
$
|
23.65
|
|
(1)
|
Gathering, transportation and processing for the year ended
December 31, 2018
reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.
|
(2)
|
General and administrative expenses for the years ended
December 31, 2018
and
2017
include
$11.0 million
, or
$0.69
per Boe, and
$0.4 million
, or
$0.06
per Boe of equity-based compensation expense, respectively.
|
|
Years Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
Production Data
|
|
|
|
||||
Oil (MBbls)
|
1,454
|
|
|
739
|
|
||
Natural gas (MMcf)
|
17,582
|
|
|
6,382
|
|
||
Natural gas liquids (MBbls)
|
1,524
|
|
|
546
|
|
||
Total volumes (MBoe)
|
5,908
|
|
|
2,349
|
|
||
Average daily total volumes (MBoe/d)
|
16.2
|
|
|
6.4
|
|
||
Average Prices - as reported
|
|
|
|
||||
Oil (per Bbl)
|
$
|
52.87
|
|
|
$
|
41.36
|
|
Natural gas (per Mcf)
|
$
|
2.80
|
|
|
$
|
2.52
|
|
Natural gas liquids (per Bbl)
|
$
|
26.44
|
|
|
$
|
15.21
|
|
Total (per Boe)
|
$
|
28.16
|
|
|
$
|
23.40
|
|
Average Prices - including impact of derivative contract settlements
|
|
|
|
||||
Oil (per Bbl)
|
$
|
53.57
|
|
|
$
|
41.36
|
|
Natural gas (per Mcf)
|
$
|
2.89
|
|
|
$
|
2.52
|
|
Natural gas liquids (per Bbl)
|
$
|
26.44
|
|
|
$
|
15.21
|
|
Total (per Boe)
|
$
|
28.60
|
|
|
$
|
23.40
|
|
|
Years Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in thousands)
|
||||||
Revenues
|
|
|
|
||||
Oil sales
|
$
|
76,876
|
|
|
$
|
30,565
|
|
Natural gas sales
|
49,211
|
|
|
16,093
|
|
||
Natural gas liquid sales
|
40,298
|
|
|
8,307
|
|
||
Loss on derivative contracts
|
(6,797
|
)
|
|
—
|
|
||
Total revenues
|
$
|
159,588
|
|
|
$
|
54,965
|
|
|
Years Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in thousands, except per Boe)
|
||||||
Operating Expenses
|
|
|
|
||||
Production expenses
|
$
|
16,872
|
|
|
$
|
5,090
|
|
Gathering, transportation and processing
|
18,602
|
|
|
5,920
|
|
||
Production taxes
|
3,685
|
|
|
1,087
|
|
||
Exploration expenses
|
32,629
|
|
|
5,258
|
|
||
Depreciation, depletion, amortization and accretion
|
37,376
|
|
|
24,996
|
|
||
General and administrative
(1)
|
31,357
|
|
|
5,581
|
|
||
Gain on sale of oil and natural gas properties
|
(838
|
)
|
|
—
|
|
||
Total
|
$
|
139,683
|
|
|
$
|
47,932
|
|
Average Costs per Boe
|
|
|
|
||||
Production expenses
|
$
|
2.86
|
|
|
$
|
2.17
|
|
Gathering, transportation and processing
|
3.15
|
|
|
2.52
|
|
||
Production taxes
|
0.62
|
|
|
0.46
|
|
||
Exploration expenses
|
5.52
|
|
|
2.24
|
|
||
Depreciation, depletion, amortization and accretion
|
6.33
|
|
|
10.64
|
|
||
General and administrative
(1)
|
5.31
|
|
|
2.38
|
|
||
Gain on sale of oil and natural gas properties
|
(0.14
|
)
|
|
—
|
|
||
Total
|
$
|
23.65
|
|
|
$
|
20.41
|
|
(1)
|
General and administrative expenses for the year ended
December 31, 2017
include
$0.4 million
, or
$0.06
per Boe, of equity-based compensation expense.
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Net cash provided by operating activities
|
$
|
268,296
|
|
|
$
|
60,275
|
|
|
$
|
36,140
|
|
Net cash used in investing activities
|
(689,092
|
)
|
|
(212,521
|
)
|
|
(241,109
|
)
|
|||
Net cash provided by financing activities
|
426,208
|
|
|
146,864
|
|
|
189,008
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
$
|
5,412
|
|
|
$
|
(5,382
|
)
|
|
$
|
(15,961
|
)
|
|
Payments Due by Period
|
||||||||||||||||||||
|
2019
|
2020
|
2021
|
2022
|
2023
|
Thereafter
|
Total
|
||||||||||||||
|
(in thousands)
|
||||||||||||||||||||
Credit Facility
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
514,639
|
|
$
|
—
|
|
$
|
—
|
|
$
|
514,639
|
|
Interest expenses related to Credit Facility
(1)
|
27,201
|
|
27,201
|
|
27,201
|
|
18,482
|
|
—
|
|
—
|
|
100,085
|
|
|||||||
Pipe and equipment purchase commitments
(2)
|
1,455
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1,455
|
|
|||||||
Office building leases
|
1,692
|
|
2,047
|
|
2,136
|
|
2,229
|
|
456
|
|
171
|
|
8,731
|
|
|||||||
Drilling rig commitments
(3)
|
15,352
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
15,352
|
|
|||||||
Total contractual obligations and commitments
|
$
|
45,700
|
|
$
|
29,248
|
|
$
|
29,337
|
|
$
|
535,350
|
|
$
|
456
|
|
$
|
171
|
|
$
|
640,262
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2020
|
|
Total
|
||||||
Oil fixed prices swaps
|
|
|
|
|
|
||||||
Volume (Bbl)
|
5,405,670
|
|
|
1,599,500
|
|
|
7,005,170
|
|
|||
Weighted-average price
|
$
|
60.05
|
|
|
$
|
63.14
|
|
|
$
|
60.76
|
|
Natural gas fixed price swaps
|
|
|
|
|
|
||||||
Volume (MMBtu)
|
43,800,000
|
|
|
12,325,000
|
|
|
56,125,000
|
|
|||
Weighted-average price
|
$
|
2.90
|
|
|
$
|
2.63
|
|
|
$
|
2.84
|
|
Natural gas basis swaps
|
|
|
|
|
|
||||||
Volume (MMBtu)
|
29,200,000
|
|
|
3,640,000
|
|
|
32,840,000
|
|
|||
Weighted-average price
|
$
|
0.60
|
|
|
$
|
0.62
|
|
|
$
|
0.60
|
|
Natural gas liquids fixed price swaps
|
|
|
|
|
|
||||||
Volume (Bbl)
|
1,095,000
|
|
|
—
|
|
|
1,095,000
|
|
|||
Weighted-average price
|
$
|
32.25
|
|
|
$
|
—
|
|
|
$
|
32.25
|
|
Exhibit No.
|
|
Description
|
|
Linn Merger Agreement, dated September 24, 2018, by and among Linn Energy, Inc., Roan Resources, Inc. and Linn Merger Sub #2, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed on September 24, 2018)
|
|
|
Roan Merger Agreement, dated September 24, 2018, by and among Roan Holdings, LLC, Roan Holdings Holdco, LLC, Roan Resources, Inc. and Linn Merger Sub #3, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed on September 24, 2018)
|
|
|
Master Reorganization Agreement, dated September 17, 2018, by and among Linn Energy, Inc., Roan Holdings, LLC, and Roan Resources LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed by Linn Energy, Inc. on September 21, 2018)
|
|
|
Separation and Distribution Agreement, dated August 7, 2018, by and between Linn Energy, Inc. and Riviera Resources, Inc. (incorporated by reference to Exhibit 2.1 to Form 8-K filed by Linn Energy, Inc. on August 10, 2018)
|
|
|
Agreement and Plan of Merger, dated July 25, 2018, by and among Linn Energy Inc., New LINN Inc. and Linn Merger Sub #1, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed by Linn Energy, Inc. on July 26, 2018)
|
|
|
Second Amended and Restated Certificate of Incorporation of Roan Resources, Inc. (incorporated by reference to Exhibit 3.1 to Form 8-K filed on September 27, 2018)
|
|
|
Second Amended and Restated Bylaws of Roan Resources, Inc. (incorporated by reference to Exhibit 3.2 to Form 8-K filed on September 27, 2018)
|
|
|
Registration Rights Agreement, dated September 24, 2018, by and among Roan Resources, Inc. and each of the other parties listed on the signature page thereto (incorporated by reference to Exhibit 4.1 to Form 8-K filed on September 24, 2018)
|
|
|
Stockholders Agreement, dated September 24, 2018, by and among Roan Resources, Inc., the Existing LINN Owners (as defined therein), Roan Holdings, LLC and any other persons signatory thereto from time to time (incorporated by reference to Exhibit 4.2 to Form 8-K filed on September 24, 2018)
|
|
|
Credit Agreement, dated September 5, 2017, by and among Citibank, N.A., as administrative agent for the Lenders (incorporated by reference to Exhibit 10.1 to Form 8-K filed on September 24, 2018)
|
|
|
Amendment No. 1 to Credit Agreement, dated April 9, 2018 (incorporated by reference to Exhibit 10.2 to Form 8-K filed on September 24, 2018)
|
|
|
Amendment No. 2 to Credit Agreement, dated May 30, 2018 (incorporated by reference to Exhibit 10.3 to Form 8-K filed on September 24, 2018)
|
|
|
Amendment No. 3 to Credit Agreement, dated September 27, 2018 (incorporated by reference to Exhibit 10.1 to Form 8-K filed on September 27, 2018)
|
|
10.5
†
|
|
Roan Resources, Inc. Amended and Restated Management Incentive Plan, dated September 24, 2018 (incorporated by reference to Exhibit 10.4 to Form 8-K filed on September 24, 2018
|
10.6
†
|
|
Form of Performance Share Unit Grant Notice and Performance Share Unit Award Agreement pursuant to the Roan Resources, Inc. Amended and Restated Management Incentive Plan (incorporated by reference to Exhibit 10.5 to Form 8-K filed on September 24, 2018)
|
|
Voting Agreement, dated September 24, 2018, by and among Roan Resources, Inc., the Existing LINN Owners (as defined therein), Roan Holdings, LLC and any other persons signatory thereto from time to time (incorporated by reference to Exhibit 10.6 to Form 8-K filed on September 24, 2018)
|
|
|
Second Amended and Restated Limited Liability Company Agreement of Roan Resources LLC (incorporated by reference to Exhibit 10.7 to Form 8-K filed on September 24, 2018)
|
|
10.9
†
|
|
Amended and Restated Employment Agreement, dated November 6, 2017, between Roan Resources, Inc. and Tony Maranto (incorporated by reference to Exhibit 10.8 to Form 8-K filed on September 24, 2018)
|
10.10
†
|
|
Employment Agreement, dated June 18, 2018, between Roan Resources LLC and David Edwards (incorporated by reference to Exhibit 10.9 to Form 8-K filed on September 24, 2018)
|
10.11
†
|
|
Employment Agreement, dated November 6, 2017, between Roan Resources LLC and Joel Pettit (incorporated by reference to Exhibit 10.10 to Form 8-K filed on September 24, 2018)
|
10.12
†
|
|
Employment Agreement, dated November 6, 2017, between Roan Resources LLC and Greg Condray (incorporated by reference to Exhibit 10.11 to Form 8-K filed on September 24, 2018)
|
10.13
†
|
|
Employment Agreement, dated September 17, 2018, between Roan Resources LLC and David Treadwell (incorporated by reference to Exhibit 10.12 to Form 8-K filed on September 24, 2018)
|
|
Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Tony Maranto (incorporated by reference to Exhibit 10.13 to Form 8-K filed on September 24, 2018)
|
|
|
Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Matthew Bonanno (incorporated by reference to Exhibit 10.14 to Form 8-K filed on September 24, 2018)
|
|
|
Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Evan Lederman (incorporated by reference to Exhibit 10.15 to Form 8-K filed on September 24, 2018)
|
|
|
Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and John Lovoi (incorporated by reference to Exhibit 10.16 to Form 8-K filed on September 24, 2018)
|
|
|
Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Paul B. Loyd Jr. (incorporated by reference to Exhibit 10.17 to Form 8-K filed on September 24, 2018)
|
|
|
Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Michael Raleigh (incorporated by reference to Exhibit 10.18 to Form 8-K filed on September 24, 2018)
|
|
|
Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Andrew Taylor (incorporated by reference to Exhibit 10.19 to Form 8-K filed on September 24, 2018)
|
|
|
Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Anthony Tripodo (incorporated by reference to Exhibit 10.20 to Form 8-K filed on September 24, 2018)
|
|
|
Tax Matters Agreement, dated August 7, 2018, by and among Linn Energy, Inc., Riviera Resources, Inc. and the Riviera Resources, Inc. Subsidiaries (incorporated by reference to Exhibit 10.1 to Form 8-K filed by Linn Energy, Inc. on August 10, 2018)
|
|
|
Transition Services Agreement, dated August 7, 2018, by and between Linn Energy, Inc. and Riviera Resources, Inc. (incorporated by reference to Exhibit 10.2 to Form 8-K filed by Linn Energy, Inc. on August 10, 2018)
|
|
|
Indemnification Agreement, dated November 5, 2018, between Roan Resources, Inc. and Joseph Mills (incorporated by reference to Exhibit 10.1 to Form 8-K filed on November 6, 2018)
|
|
10.25
†*
|
|
Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Award Agreement pursuant to the Roan Resources, Inc. Amended and Restated Management Incentive Plan
|
|
Amendment No. 4 to Credit Agreement, dated March 13, 2019 (incorporated by reference to Exhibit 10.1 to Form 8-K filed on March 13, 2019)
|
|
21.1
*
|
|
List of Subsidiaries of Roan Resources, Inc.
|
23.1
*
|
|
Consent of PricewaterhouseCoopers LLP
|
23.2
*
|
|
Consent of DeGolyer and MacNaughton
|
31.1
*
|
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
31.2
*
|
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
32.1
*
|
|
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
32.2
*
|
|
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
99.1
*
|
|
Report of DeGolyer and MacNaughton
|
Date:
|
April 1, 2019
|
By:
|
/s/ Tony C. Maranto
|
Name:
|
Tony C. Maranto
|
Title:
|
Chairman, Chief Executive Officer and President
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Tony C. Maranto
|
|
Chairman, President and Chief Executive Officer
|
|
April 1, 2019
|
Tony C. Maranto
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ David M. Edwards
|
|
Chief Financial Officer
|
|
April 1, 2019
|
David M. Edwards
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/ Amber N. Bonney
|
|
Vice President and Chief Accounting Officer
|
|
April 1, 2019
|
Amber N. Bonney
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
/s/ Matthew Bonanno
|
|
Director
|
|
April 1, 2019
|
Matthew Bonanno
|
|
|
|
|
|
|
|
|
|
/s/ Evan Lederman
|
|
Director
|
|
April 1, 2019
|
Evan Lederman
|
|
|
|
|
|
|
|
|
|
/s/ John V. Lovoi
|
|
Director
|
|
April 1, 2019
|
John V. Lovoi
|
|
|
|
|
|
|
|
|
|
/s/ Paul B. Loyd Jr.
|
|
Director
|
|
April 1, 2019
|
Paul B. Loyd Jr.
|
|
|
|
|
|
|
|
|
|
/s/ Michael P. Raleigh
|
|
Director
|
|
April 1, 2019
|
Michael P. Raleigh
|
|
|
|
|
|
|
|
|
|
/s/ Andrew Taylor
|
|
Director
|
|
April 1, 2019
|
Andrew Taylor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Anthony Tripodo
|
|
Director
|
|
April 1, 2019
|
Anthony Tripodo
|
|
|
|
|
|
|
|
|
|
/s/ Joseph A. Mills
|
|
Director
|
|
April 1, 2019
|
Joseph A. Mills
|
|
|
|
|
|
|
|
|
|
Page
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands, except par value and share data)
|
||||||
ASSETS
|
|
|
|
||||
Current assets
|
|
|
|
||||
Cash and cash equivalents
|
$
|
6,883
|
|
|
$
|
1,471
|
|
Accounts receivable
|
|
|
|
||||
Oil, natural gas and natural gas liquid sales
|
55,564
|
|
|
74,527
|
|
||
Affiliates
|
9,669
|
|
|
4,695
|
|
||
Joint interest owners and other, net
|
133,387
|
|
|
320
|
|
||
Prepaid drilling advances
|
28,977
|
|
|
—
|
|
||
Derivative contracts
|
82,180
|
|
|
152
|
|
||
Prepaid expenses
|
2,644
|
|
|
651
|
|
||
Other current assets
|
4,011
|
|
|
279
|
|
||
Total current assets
|
323,315
|
|
|
82,095
|
|
||
Noncurrent assets
|
|
|
|
||||
Oil and natural gas properties, successful efforts method
|
2,628,333
|
|
|
1,876,951
|
|
||
Accumulated depreciation, depletion, amortization and impairment
|
(230,836
|
)
|
|
(78,307
|
)
|
||
Oil and natural gas properties, net
|
2,397,497
|
|
|
1,798,644
|
|
||
Derivative contracts
|
20,638
|
|
|
996
|
|
||
Other
|
7,659
|
|
|
3,857
|
|
||
Total assets
|
$
|
2,749,109
|
|
|
$
|
1,885,592
|
|
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities
|
|
|
|
||||
Accounts payable
|
$
|
49,746
|
|
|
$
|
—
|
|
Accrued liabilities
|
176,494
|
|
|
10,245
|
|
||
Accounts payable and accrued liabilities – Affiliates
|
8,577
|
|
|
183,820
|
|
||
Revenue payable
|
97,963
|
|
|
—
|
|
||
Drilling advances
|
31,058
|
|
|
—
|
|
||
Derivative contracts
|
845
|
|
|
9,279
|
|
||
Asset retirement obligations
|
790
|
|
|
—
|
|
||
Total current liabilities
|
365,473
|
|
|
203,344
|
|
||
Noncurrent liabilities
|
|
|
|
||||
Long-term debt
|
514,639
|
|
|
85,339
|
|
||
Deferred tax liabilities, net
|
356,862
|
|
|
—
|
|
||
Asset retirement obligations
|
16,058
|
|
|
10,769
|
|
||
Derivative contracts
|
141
|
|
|
1,371
|
|
||
Other
|
902
|
|
|
—
|
|
||
Total liabilities
|
1,254,075
|
|
|
300,823
|
|
||
Commitments and contingencies (Note 14)
|
|
|
|
|
|
||
Equity
|
|
|
|
||||
Common stock, $0.001 par value; 800,000,000 shares authorized; 152,539,532 shares issued and outstanding at December 31, 2018
|
153
|
|
|
—
|
|
||
Preferred stock, $0.001 par value; 50,000,000 shares authorized; no shares issued and outstanding at December 31, 2018
|
—
|
|
|
—
|
|
||
Additional paid-in capital
|
1,646,401
|
|
|
—
|
|
||
Accumulated deficit
|
(151,520
|
)
|
|
—
|
|
||
Members’ equity
|
—
|
|
|
1,584,769
|
|
||
Total equity
|
1,495,034
|
|
|
1,584,769
|
|
||
Total liabilities and equity
|
$
|
2,749,109
|
|
|
$
|
1,885,592
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands, except per share data)
|
||||||||||
Revenues
|
|
|
|
|
|
||||||
Oil sales
|
$
|
275,239
|
|
|
$
|
76,876
|
|
|
$
|
30,565
|
|
Natural gas sales
|
46,966
|
|
|
46,303
|
|
|
16,093
|
|
|||
Natural gas sales – Affiliates
|
29,090
|
|
|
2,908
|
|
|
—
|
|
|||
Natural gas liquid sales
|
51,467
|
|
|
35,217
|
|
|
8,307
|
|
|||
Natural gas liquid sales – Affiliates
|
37,005
|
|
|
5,081
|
|
|
—
|
|
|||
Gain (loss) on derivative contracts
|
78,054
|
|
|
(6,797
|
)
|
|
—
|
|
|||
Total revenues
|
517,821
|
|
|
159,588
|
|
|
54,965
|
|
|||
Operating Expenses
|
|
|
|
|
|
||||||
Production expenses
|
47,600
|
|
|
16,872
|
|
|
5,090
|
|
|||
Gathering, transportation and processing
|
—
|
|
|
18,602
|
|
|
5,920
|
|
|||
Production taxes
|
17,579
|
|
|
3,685
|
|
|
1,087
|
|
|||
Exploration expenses
|
43,303
|
|
|
32,629
|
|
|
5,258
|
|
|||
Depreciation, depletion, amortization and accretion
|
123,922
|
|
|
37,376
|
|
|
24,996
|
|
|||
General and administrative
|
60,874
|
|
|
31,357
|
|
|
5,581
|
|
|||
Gain on sale of oil and natural gas properties
|
—
|
|
|
(838
|
)
|
|
—
|
|
|||
Total operating expenses
|
293,278
|
|
|
139,683
|
|
|
47,932
|
|
|||
Total operating income
|
224,543
|
|
|
19,905
|
|
|
7,033
|
|
|||
Other income (expense)
|
|
|
|
|
|
||||||
Interest expense, net
|
(8,352)
|
|
|
(1,461)
|
|
|
(86)
|
|
|||
Other income
|
—
|
|
|
13
|
|
|
—
|
|
|||
Net income before income taxes
|
216,191
|
|
|
18,457
|
|
|
6,947
|
|
|||
Income tax expense
|
356,862
|
|
|
—
|
|
|
—
|
|
|||
Net (loss) income
|
$
|
(140,671
|
)
|
|
$
|
18,457
|
|
|
$
|
6,947
|
|
Earnings (loss) per share
|
|
|
|
|
|
||||||
Basic
|
$
|
(0.92
|
)
|
|
$
|
0.18
|
|
|
$
|
0.11
|
|
Diluted
|
$
|
(0.92
|
)
|
|
$
|
0.18
|
|
|
$
|
0.11
|
|
Weighted average number of shares outstanding
|
|
|
|
|
|
||||||
Basic
|
152,232
|
|
|
100,473
|
|
|
62,394
|
|
|||
Diluted
|
152,232
|
|
|
100,473
|
|
|
62,394
|
|
|
Stockholders’ Equity
|
|
|
|
|
|||||||||||||||||
|
Common Stock (Shares)
|
|
Common Stock
|
|
Additional Paid-in Capital
|
|
Accumulated Deficit
|
|
Members’ Equity
|
|
Total Equity
|
|||||||||||
|
(in thousands)
|
|||||||||||||||||||||
Balance at December 31, 2015
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
98,292
|
|
|
$
|
98,292
|
|
Contributions from Citizen Members
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
169,008
|
|
|
169,008
|
|
|||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,947
|
|
|
6,947
|
|
|||||
Balance at December 31, 2016
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
274,247
|
|
|
274,247
|
|
|||||
Contributions from Citizen Members
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
95,557
|
|
|
95,557
|
|
|||||
Distributions to Citizen Members
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(85,614
|
)
|
|
(85,614
|
)
|
|||||
Acquisition of oil and natural gas properties in exchange for equity units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,281,743
|
|
|
1,281,743
|
|
|||||
Equity-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
379
|
|
|
379
|
|
|||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18,457
|
|
|
18,457
|
|
|||||
Balance at December 31, 2017
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,584,769
|
|
|
1,584,769
|
|
|||||
Acquisition of oil and natural gas properties in exchange for equity units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
39,906
|
|
|
39,906
|
|
|||||
Equity-based compensation
(1)
|
—
|
|
|
—
|
|
|
3,162
|
|
|
—
|
|
|
7,868
|
|
|
11,030
|
|
|||||
Net (loss) income
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
(151,520
|
)
|
|
10,849
|
|
|
(140,671
|
)
|
|||||
Issuance of common stock upon Reorganization
|
152,540
|
|
|
153
|
|
|
1,643,239
|
|
|
—
|
|
|
(1,643,392
|
)
|
|
—
|
|
|||||
Balance at December 31, 2018
|
152,540
|
|
|
$
|
153
|
|
|
$
|
1,646,401
|
|
|
$
|
(151,520
|
)
|
|
$
|
—
|
|
|
$
|
1,495,034
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Cash flows from operating activities
|
|
|
|
|
|
||||||
Net (loss) income
|
$
|
(140,671
|
)
|
|
$
|
18,457
|
|
|
$
|
6,947
|
|
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
|
|
|
|
|
|
|
|||||
Depreciation, depletion, amortization and accretion
|
123,922
|
|
|
37,376
|
|
|
24,996
|
|
|||
Unproved leasehold amortization and impairment
|
36,046
|
|
|
25,377
|
|
|
5,258
|
|
|||
Gain on sale of oil and natural gas properties
|
—
|
|
|
(838
|
)
|
|
—
|
|
|||
Amortization of deferred financing costs
|
853
|
|
|
175
|
|
|
—
|
|
|||
Amortization of deferred rent
|
902
|
|
|
—
|
|
|
—
|
|
|||
(Gain) loss on derivative contracts
|
(78,054
|
)
|
|
6,797
|
|
|
—
|
|
|||
Net cash (paid) received upon settlement of derivative contracts
|
(33,279
|
)
|
|
2,705
|
|
|
—
|
|
|||
Equity-based compensation
|
11,030
|
|
|
379
|
|
|
—
|
|
|||
Deferred income taxes
|
356,862
|
|
|
—
|
|
|
—
|
|
|||
Other
|
2,971
|
|
|
(11
|
)
|
|
(41
|
)
|
|||
Changes in operating assets and liabilities increasing (decreasing) cash:
|
|
|
|
|
|
|
|||||
Accounts receivable – Oil, natural gas and natural gas liquid sales
|
18,963
|
|
|
(62,170
|
)
|
|
(12,473
|
)
|
|||
Accounts receivable – Affiliates
|
(4,974
|
)
|
|
(4,695
|
)
|
|
—
|
|
|||
Accounts receivable – Joint interest owners and other
|
(136,367
|
)
|
|
(8,729
|
)
|
|
(35,398
|
)
|
|||
Prepaid drilling advances
|
(28,977
|
)
|
|
—
|
|
|
—
|
|
|||
Prepaid expenses
|
(1,992
|
)
|
|
(2,312
|
)
|
|
(1,221
|
)
|
|||
Other current assets
|
(2,584
|
)
|
|
(2
|
)
|
|
3
|
|
|||
Accounts payable
|
16,733
|
|
|
—
|
|
|
6,006
|
|
|||
Accrued liabilities
|
21,536
|
|
|
47,801
|
|
|
8,403
|
|
|||
Accounts payable and accrued liabilities – Affiliates
|
(23,645
|
)
|
|
31,121
|
|
|
—
|
|
|||
Drilling advances
|
31,058
|
|
|
(25,363
|
)
|
|
22,760
|
|
|||
Revenue payable
|
97,963
|
|
|
(5,793
|
)
|
|
10,900
|
|
|||
Net cash provided by operating activities
|
268,296
|
|
|
60,275
|
|
|
36,140
|
|
|||
Cash flows from investing activities
|
|
|
|
|
|
||||||
Acquisition of oil and natural gas properties
|
(22,935
|
)
|
|
(42,701
|
)
|
|
(144,774
|
)
|
|||
Capital expenditures for oil and natural gas properties
|
(673,465
|
)
|
|
(167,122
|
)
|
|
(96,335
|
)
|
|||
Acquisition of other property and equipment
|
(3,237
|
)
|
|
(1,332
|
)
|
|
—
|
|
|||
Proceeds from sale of oil and natural gas properties
|
10,545
|
|
|
1,435
|
|
|
—
|
|
|||
Other
|
—
|
|
|
(2,801
|
)
|
|
—
|
|
|||
Net cash used in investing activities
|
(689,092
|
)
|
|
(212,521
|
)
|
|
(241,109
|
)
|
|||
Cash flows from financing activities
|
|
|
|
|
|
||||||
Proceeds from borrowings
|
429,300
|
|
|
105,339
|
|
|
20,000
|
|
|||
Repayment of borrowings
|
—
|
|
|
(40,000
|
)
|
|
—
|
|
|||
Deferred financing costs
|
(2,279
|
)
|
|
(2,885
|
)
|
|
—
|
|
|||
Deferred offering costs
|
(813
|
)
|
|
—
|
|
|
—
|
|
|||
Contributions from Citizen members
|
—
|
|
|
95,557
|
|
|
169,008
|
|
|||
Distributions to Citizen members
|
—
|
|
|
(11,147
|
)
|
|
—
|
|
|||
Net cash provided by financing activities
|
426,208
|
|
|
146,864
|
|
|
189,008
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
5,412
|
|
|
(5,382
|
)
|
|
(15,961
|
)
|
|||
Cash and cash equivalents, beginning of year
|
1,471
|
|
|
6,853
|
|
|
22,814
|
|
|||
Cash and cash equivalents, end of year
|
$
|
6,883
|
|
|
$
|
1,471
|
|
|
$
|
6,853
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Supplemental disclosure of cash flow information
|
|
|
|
|
|
||||||
Cash paid for interest, net of capitalized interest
|
$
|
7,029
|
|
|
$
|
1,036
|
|
|
$
|
86
|
|
Supplemental disclosure of non-cash investing and financing activities
|
|
|
|
|
|
||||||
Change in accrued capital expenditures
|
$
|
65,699
|
|
|
$
|
147,142
|
|
|
$
|
4,922
|
|
Acquisition of oil and natural gas properties for equity
|
$
|
39,906
|
|
|
$
|
1,281,743
|
|
|
$
|
—
|
|
Distribution to Citizen Members of assets and liabilities
|
$
|
—
|
|
|
$
|
(74,467
|
)
|
|
$
|
—
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands)
|
||||||
Accrued capital expenditures
|
$
|
151,965
|
|
|
$
|
7,252
|
|
Accrued production expenses
|
10,879
|
|
|
—
|
|
||
Accrued general and administrative expenses
|
7,450
|
|
|
2,696
|
|
||
Other
|
6,200
|
|
|
297
|
|
||
Total accrued liabilities
|
$
|
176,494
|
|
|
$
|
10,245
|
|
|
Years Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Coffeyville Resources Refining & Marketing LLC
|
31
|
%
|
|
*
|
|
|
*
|
|
Sunoco Inc.
|
18
|
%
|
|
40
|
%
|
|
55
|
%
|
Blue Mountain Midstream LLC
|
15
|
%
|
|
*
|
|
|
*
|
|
EnLink Oklahoma Gas Processing, LP
|
13
|
%
|
|
39
|
%
|
|
31
|
%
|
|
Year Ended December 31, 2018
|
||||||||||
|
Under ASC 606
|
|
Under ASC 605
|
|
Increase/ (decrease)
|
||||||
|
(in thousands)
|
||||||||||
Revenues
|
|
|
|
|
|
||||||
Oil sales
|
$
|
275,239
|
|
|
$
|
275,399
|
|
|
$
|
(160
|
)
|
Natural gas sales
|
$
|
76,056
|
|
|
$
|
96,086
|
|
|
$
|
(20,030
|
)
|
Natural gas liquid sales
|
$
|
88,472
|
|
|
$
|
114,021
|
|
|
$
|
(25,549
|
)
|
|
|
|
|
|
|
||||||
Operating expenses
|
|
|
|
|
|
||||||
Gathering, transportation and processing
|
$
|
—
|
|
|
$
|
45,739
|
|
|
$
|
(45,739
|
)
|
|
|
|
|
|
|
||||||
Net loss
|
$
|
(140,671
|
)
|
|
$
|
(140,671
|
)
|
|
$
|
—
|
|
Discount rate
|
9.50
|
%
|
Reserve risk factor
(1)
|
35%-100%
|
|
Oil price
|
three years NYMEX WTI forward curve
|
|
Natural gas price
|
three years NYMEX Henry Hub forward curve
|
|
NGL price
|
39% of oil price
|
|
Price escalation
(2)
|
2.00
|
%
|
(1)
Possible reserves had a reserve risk factor of 35%, probable reserves had a reserve risk factor of 75%, and proved undeveloped reserves had a reserve risk factor of 90%.
|
||
(2)
Prices were escalated at the end of the forward curve
|
Consideration given
|
|
||
Equity units
|
$
|
1,281,743
|
|
Allocation of purchase price
|
|
||
Inventory
|
$
|
205
|
|
Proved oil and natural gas properties
|
214,647
|
|
|
Unproved oil and natural gas properties
|
1,086,600
|
|
|
Total assets acquired
|
1,301,452
|
|
|
Asset retirement obligations
|
(7,547
|
)
|
|
Revenue suspense
|
(12,162
|
)
|
|
Total fair value of net assets acquired
|
$
|
1,281,743
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands)
|
||||||
Oil and natural gas properties
|
|
|
|
||||
Proved
|
$
|
1,538,379
|
|
|
$
|
750,492
|
|
Unproved
|
1,089,954
|
|
|
1,126,459
|
|
||
Less: accumulated depreciation, depletion, amortization and impairment
|
(230,836
|
)
|
|
(78,307
|
)
|
||
Oil and natural gas properties, net
|
$
|
2,397,497
|
|
|
$
|
1,798,644
|
|
|
Years Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands)
|
||||||
Asset retirement obligation, beginning balance
|
$
|
10,769
|
|
|
$
|
2,245
|
|
Liabilities incurred or acquired
(1)
|
3,347
|
|
|
8,118
|
|
||
Revisions in estimated cash flows
(2)
|
2,018
|
|
|
42
|
|
||
Liabilities settled
|
(139
|
)
|
|
—
|
|
||
Accretion expense
|
853
|
|
|
364
|
|
||
Asset retirement obligation, ending balance
|
16,848
|
|
|
10,769
|
|
||
Less: current portion of obligations
|
790
|
|
|
—
|
|
||
Asset retirement obligation - long term
|
$
|
16,058
|
|
|
$
|
10,769
|
|
2019
|
$
|
—
|
|
2020
|
—
|
|
|
2021
|
—
|
|
|
2022
|
514,639
|
|
|
|
$
|
514,639
|
|
|
2019
|
|
2020
|
|
Total
|
||||||
Oil fixed price swaps
|
|
|
|
|
|
||||||
Volume (Bbl)
|
5,405,670
|
|
|
1,599,500
|
|
|
7,005,170
|
|
|||
Weighted-average price
|
$
|
60.05
|
|
|
$
|
63.14
|
|
|
$
|
60.76
|
|
Natural gas fixed price swaps
|
|
|
|
|
|
||||||
Volume (MMBtu)
|
43,800,000
|
|
|
12,325,000
|
|
|
56,125,000
|
|
|||
Weighted-average price
|
$
|
2.90
|
|
|
$
|
2.63
|
|
|
$
|
2.84
|
|
Natural gas basis swaps
|
|
|
|
|
|
||||||
Volume (MMBtu)
|
29,200,000
|
|
|
3,640,000
|
|
|
32,840,000
|
|
|||
Weighted-average price
|
$
|
0.60
|
|
|
$
|
0.62
|
|
|
$
|
0.60
|
|
Natural gas liquids fixed price swaps
|
|
|
|
|
|
||||||
Volume (Bbl)
|
1,095,000
|
|
|
—
|
|
|
1,095,000
|
|
|||
Weighted-average price
|
$
|
32.25
|
|
|
$
|
—
|
|
|
$
|
32.25
|
|
|
Years Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands)
|
||||||
Gain (loss) on derivative contracts
|
$
|
78,054
|
|
|
$
|
(6,797
|
)
|
Net cash (paid) received upon settlement of derivative contracts
(1)
|
$
|
(33,279
|
)
|
|
$
|
2,705
|
|
(1)
|
Includes
$1.3 million
of cash received upon settlement of derivative contracts prior to their contractual maturity for the year ended December 31,
2017
.
|
|
December 31, 2018
|
||||||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Gross Fair Value
|
|
Netting
|
|
Carrying Value
|
||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current commodity derivatives
|
$
|
—
|
|
|
$
|
85,728
|
|
|
$
|
—
|
|
|
$
|
85,728
|
|
|
$
|
(3,548
|
)
|
|
$
|
82,180
|
|
Noncurrent commodity derivatives
|
—
|
|
|
21,565
|
|
|
—
|
|
|
21,565
|
|
|
(927
|
)
|
|
20,638
|
|
||||||
Total assets
|
$
|
—
|
|
|
$
|
107,293
|
|
|
$
|
—
|
|
|
$
|
107,293
|
|
|
$
|
(4,475
|
)
|
|
$
|
102,818
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current commodity derivatives
|
$
|
—
|
|
|
$
|
(4,393
|
)
|
|
$
|
—
|
|
|
$
|
(4,393
|
)
|
|
$
|
3,548
|
|
|
$
|
(845
|
)
|
Noncurrent commodity derivatives
|
—
|
|
|
(1,068
|
)
|
|
—
|
|
|
(1,068
|
)
|
|
927
|
|
|
(141
|
)
|
||||||
Total liabilities
|
$
|
—
|
|
|
$
|
(5,461
|
)
|
|
$
|
—
|
|
|
$
|
(5,461
|
)
|
|
$
|
4,475
|
|
|
$
|
(986
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
December 31, 2017
|
||||||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Gross Fair Value
|
|
Netting
|
|
Carrying Value
|
||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current commodity derivatives
|
$
|
—
|
|
|
$
|
2,856
|
|
|
$
|
—
|
|
|
$
|
2,856
|
|
|
$
|
(2,704
|
)
|
|
$
|
152
|
|
Noncurrent commodity derivatives
|
—
|
|
|
2,182
|
|
|
—
|
|
|
2,182
|
|
|
(1,186
|
)
|
|
996
|
|
||||||
Total assets
|
$
|
—
|
|
|
$
|
5,038
|
|
|
$
|
—
|
|
|
$
|
5,038
|
|
|
$
|
(3,890
|
)
|
|
$
|
1,148
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current commodity derivatives
|
$
|
—
|
|
|
$
|
(11,983
|
)
|
|
$
|
—
|
|
|
$
|
(11,983
|
)
|
|
$
|
2,704
|
|
|
$
|
(9,279
|
)
|
Noncurrent commodity derivatives
|
—
|
|
|
(2,557
|
)
|
|
—
|
|
|
(2,557
|
)
|
|
1,186
|
|
|
(1,371
|
)
|
||||||
Total liabilities
|
$
|
—
|
|
|
$
|
(14,540
|
)
|
|
$
|
—
|
|
|
$
|
(14,540
|
)
|
|
$
|
3,890
|
|
|
$
|
(10,650
|
)
|
|
Number of
PSUs |
|
Weighted
Average Fair Value |
|
Total Fair
Value ($ in thousands) |
|||||
Outstanding at December 31, 2016
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Granted
|
16,350,000
|
|
|
1.41
|
|
|
23,054
|
|
||
Vested
|
—
|
|
|
—
|
|
|
—
|
|
||
Outstanding at December 31, 2017
|
16,350,000
|
|
|
$
|
1.41
|
|
|
$
|
23,054
|
|
Granted
|
6,825,000
|
|
|
1.88
|
|
|
12,810
|
|
||
Vested
|
—
|
|
|
—
|
|
|
—
|
|
||
Conversion
(1)
|
(22,016,250
|
)
|
|
—
|
|
|
—
|
|
||
Outstanding at December 31, 2018
|
1,158,750
|
|
|
$
|
30.95
|
|
|
$
|
35,864
|
|
Company enterprise value (in billions)
|
$4.19 - $4.56
|
Equity volatility
|
34.0% - 36.0%
|
Weighted average risk-free interest rate
|
1.96% - 2.54%
|
|
Number of
Restricted Stock Units |
|
Weighted
Average Fair Value |
|
Total Fair Value ($ in thousands)
|
|||||
Outstanding at December 31, 2017
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Granted
|
11,800
|
|
|
16.95
|
|
|
200
|
|
||
Vested
|
—
|
|
|
—
|
|
|
—
|
|
||
Forfeited
|
—
|
|
|
—
|
|
|
—
|
|
||
Outstanding at December 31, 2018
|
11,800
|
|
|
$
|
16.95
|
|
|
$
|
200
|
|
Current income tax expense
|
|
||
Federal
|
$
|
—
|
|
State
|
—
|
|
|
|
—
|
|
|
Deferred income tax expense
|
|
||
Federal
|
277,794
|
|
|
State
|
79,068
|
|
|
|
356,862
|
|
|
Provision for income taxes
|
$
|
356,862
|
|
Deferred income tax assets
|
|
||
Net operating losses
|
$
|
42,013
|
|
Other
|
4,409
|
|
|
|
46,422
|
|
|
Deferred income tax liabilities
|
|
||
Oil and natural gas properties
|
(377,362
|
)
|
|
Derivative contracts
|
(25,922
|
)
|
|
|
(403,284
|
)
|
|
Deferred tax liabilities, net
|
$
|
(356,862
|
)
|
|
Amount
|
|
Percent
|
|||
|
(in thousands)
|
|
|
|||
Income (loss) at U.S. federal statutory rate
|
$
|
45,400
|
|
|
21.0
|
%
|
Net effect of state income taxes
|
9,173
|
|
|
4.2
|
%
|
|
Change in tax status
|
304,455
|
|
|
140.8
|
%
|
|
Other
|
(2,166
|
)
|
|
(1.0
|
)%
|
|
Income tax provision / Effective rate
|
$
|
356,862
|
|
|
165.0
|
%
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
|
Total
|
||||||||||||||
Office building leases
|
$
|
1,692
|
|
|
$
|
2,047
|
|
|
$
|
2,136
|
|
|
$
|
2,229
|
|
|
$
|
456
|
|
|
$
|
171
|
|
|
$
|
8,731
|
|
Pipe and equipment purchase commitments
(1)
|
1,455
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,455
|
|
|||||||
Drilling rig commitments
(2)
|
15,352
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15,352
|
|
|||||||
Total
|
$
|
18,499
|
|
|
$
|
2,047
|
|
|
$
|
2,136
|
|
|
$
|
2,229
|
|
|
$
|
456
|
|
|
$
|
171
|
|
|
$
|
25,538
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in thousands)
|
||||||
Oil and natural gas properties
|
|
|
|
||||
Proved properties
|
$
|
1,538,379
|
|
|
$
|
750,492
|
|
Unproved properties
|
1,089,954
|
|
|
1,126,459
|
|
||
Total oil and natural gas properties
|
2,628,333
|
|
|
1,876,951
|
|
||
Accumulated depreciation, depletion, amortization and impairment
|
(230,836
|
)
|
|
(78,307
|
)
|
||
Oil and natural gas properties, net
|
$
|
2,397,497
|
|
|
$
|
1,798,644
|
|
|
December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Acquisition costs of properties
|
|
|
|
|
|
||||||
Proved properties
|
$
|
5,655
|
|
|
$
|
214,647
|
|
|
$
|
1,079
|
|
Unproved properties
|
42,738
|
|
|
1,018,978
|
|
|
93,705
|
|
|||
Development costs
|
719,198
|
|
|
390,991
|
|
|
152,284
|
|
|||
Exploratory
(1)
|
7,257
|
|
|
8,538
|
|
|
—
|
|
|||
Total costs incurred
|
$
|
774,848
|
|
|
$
|
1,633,154
|
|
|
$
|
247,068
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Oil, natural gas and NGL sales
|
$
|
439,767
|
|
|
$
|
166,385
|
|
|
$
|
54,965
|
|
Production expenses
|
47,600
|
|
|
16,872
|
|
|
5,090
|
|
|||
Production taxes
|
17,579
|
|
|
3,685
|
|
|
1,087
|
|
|||
Exploration expenses
|
43,303
|
|
|
28,154
|
|
|
—
|
|
|||
Gathering, transportation and processing
(1)
|
—
|
|
|
18,602
|
|
|
5,920
|
|
|||
Depreciation, depletion, amortization, and accretion
|
123,062
|
|
|
37,376
|
|
|
24,996
|
|
|||
Impairment
|
—
|
|
|
4,475
|
|
|
5,258
|
|
|||
Income tax expense
(2)
|
13,103
|
|
|
—
|
|
|
—
|
|
|||
Results of operations
|
$
|
195,120
|
|
|
$
|
57,221
|
|
|
$
|
12,614
|
|
(1)
|
Gathering, transportation and processing for the year ended
December 31, 2018
reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.
|
(2)
|
Income tax expense is calculated using results from the period after the Reorganization when the Company became a taxable entity and the Company’s effective tax rate of
24.3%
.
|
|
Oil (MBbls)
|
|
Natural Gas (MMcf)
|
|
NGLs (MBbls)
|
|
Total (MBoe)
|
||||
Proved reserves at December 31, 2015
|
387
|
|
|
8,517
|
|
|
678
|
|
|
2,484
|
|
Purchases of reserves
|
22
|
|
|
333
|
|
|
33
|
|
|
111
|
|
Extensions and discoveries
|
2,632
|
|
|
33,218
|
|
|
2,956
|
|
|
11,124
|
|
Revisions of previous estimates
|
598
|
|
|
4,145
|
|
|
398
|
|
|
1,687
|
|
Production
|
(740
|
)
|
|
(6,382
|
)
|
|
(546
|
)
|
|
(2,350
|
)
|
Proved reserves at December 31, 2016
|
2,900
|
|
|
39,831
|
|
|
3,519
|
|
|
13,057
|
|
Purchases of reserves
|
9,843
|
|
|
163,638
|
|
|
16,870
|
|
|
53,986
|
|
Extensions and discoveries
|
30,554
|
|
|
486,510
|
|
|
61,599
|
|
|
173,238
|
|
Revisions of previous estimates
|
(3,583
|
)
|
|
20,844
|
|
|
(260
|
)
|
|
(369
|
)
|
Production
|
(2,294
|
)
|
|
(24,953
|
)
|
|
(2,150
|
)
|
|
(8,603
|
)
|
Proved reserves at December 31, 2017
|
37,420
|
|
|
685,869
|
|
|
79,578
|
|
|
231,309
|
|
Purchases of reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions and discoveries
|
34,714
|
|
|
451,750
|
|
|
48,791
|
|
|
158,797
|
|
Revisions of previous estimates
|
(12,087
|
)
|
|
(184,547
|
)
|
|
(25,365
|
)
|
|
(68,209
|
)
|
Production
|
(4,364
|
)
|
|
(41,890
|
)
|
|
(4,592
|
)
|
|
(15,938
|
)
|
Proved reserves at December 31, 2018
|
55,683
|
|
|
911,182
|
|
|
98,412
|
|
|
305,959
|
|
|
December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Proved Developed Reserves
|
|
|
|
|
|
|||
Oil (MBbls)
|
18,652
|
|
|
12,352
|
|
|
2,900
|
|
Natural gas (MMcf)
|
369,677
|
|
|
259,193
|
|
|
39,831
|
|
NGL (MBbls)
|
39,927
|
|
|
24,034
|
|
|
3,519
|
|
Total (MBoe)
|
120,192
|
|
|
79,585
|
|
|
13,057
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|||
Oil (MBbls)
|
37,031
|
|
|
25,068
|
|
|
—
|
|
Natural gas (MMcf)
|
541,505
|
|
|
426,676
|
|
|
—
|
|
NGL (MBbls)
|
58,485
|
|
|
55,544
|
|
|
—
|
|
Total (MBoe)
|
185,767
|
|
|
151,724
|
|
|
—
|
|
Total Proved Reserves
|
|
|
|
|
|
|||
Oil (MBbls)
|
55,683
|
|
|
37,420
|
|
|
2,900
|
|
Natural gas (MMcf)
|
911,182
|
|
|
685,869
|
|
|
39,831
|
|
NGL (MBbls)
|
98,412
|
|
|
79,578
|
|
|
3,519
|
|
Total (MBoe)
|
305,959
|
|
|
231,309
|
|
|
13,057
|
|
|
December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Future cash inflows
|
$
|
7,325,386
|
|
|
$
|
5,270,465
|
|
|
$
|
271,428
|
|
Future production costs
|
(1,773,779
|
)
|
|
(1,664,724
|
)
|
|
(102,817
|
)
|
|||
Future development costs
|
(1,294,565
|
)
|
|
(745,769
|
)
|
|
—
|
|
|||
Future income tax expense
(1)
|
(797,247
|
)
|
|
—
|
|
|
—
|
|
|||
Future net cash flows
|
3,459,795
|
|
|
2,859,972
|
|
|
168,611
|
|
|||
Discount to present value at 10% annual rate
|
(1,760,094
|
)
|
|
(1,664,303
|
)
|
|
(50,339
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
1,699,701
|
|
|
$
|
1,195,669
|
|
|
$
|
118,272
|
|
(1)
|
Roan Inc. is a corporation, and as a result, is subject to U.S. federal, state and local income taxes. Our accounting predecessor, Roan LLC, passed through its taxable income to its owners for income tax purposes and thus was not subject to U.S. federal or state income taxes.
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in thousands)
|
||||||||||
Standardized measure of discounted future net cash flows at the beginning of the period
|
$
|
1,195,669
|
|
|
$
|
118,272
|
|
|
$
|
18,910
|
|
Sales of oil and natural gas, net of production costs
|
(374,588
|
)
|
|
(124,526
|
)
|
|
(42,868
|
)
|
|||
Acquisition of reserves
|
—
|
|
|
279,026
|
|
|
462
|
|
|||
Extensions and discoveries, net of future development costs
|
1,126,713
|
|
|
877,846
|
|
|
104,581
|
|
|||
Previously estimated development costs incurred during the period
|
124,822
|
|
|
148,505
|
|
|
—
|
|
|||
Net changes in prices and production costs
|
172,928
|
|
|
36,233
|
|
|
18,256
|
|
|||
Changes in estimated future development costs
|
(13,160
|
)
|
|
(17,970
|
)
|
|
—
|
|
|||
Revisions of previous quantity estimates
|
(281,054
|
)
|
|
(5,676
|
)
|
|
15,573
|
|
|||
Accretion of discount
|
119,567
|
|
|
11,827
|
|
|
1,891
|
|
|||
Net change in income taxes
(1)
|
(391,808
|
)
|
|
—
|
|
|
—
|
|
|||
Net changes in timing of production and other
|
20,612
|
|
|
(127,868
|
)
|
|
1,467
|
|
|||
Standardized measure of discounted future net cash flows at the end of the period
|
$
|
1,699,701
|
|
|
$
|
1,195,669
|
|
|
$
|
118,272
|
|
(1)
|
Roan Inc. is a corporation, and as a result, is subject to U.S. federal, state and local income taxes. Our accounting predecessor, Roan LLC, passed through its taxable income to its owners for income tax purposes and thus was not subject to U.S. federal or state income taxes.
|
|
2018
|
||||||||||||||
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
||||||||
|
(in thousands, except per share amounts)
|
||||||||||||||
Total revenues
|
$
|
91,356
|
|
|
$
|
35,965
|
|
|
$
|
83,448
|
|
|
$
|
307,052
|
|
Income (loss) from operations
|
$
|
36,880
|
|
|
$
|
(21,670
|
)
|
|
$
|
514
|
|
|
$
|
208,819
|
|
Net income (loss)
|
$
|
35,081
|
|
|
$
|
(22,757
|
)
|
|
$
|
(301,240
|
)
|
|
$
|
148,245
|
|
Earnings (loss) per share
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.23
|
|
|
$
|
(0.15
|
)
|
|
$
|
(1.97
|
)
|
|
$
|
0.97
|
|
Diluted
|
$
|
0.23
|
|
|
$
|
(0.15
|
)
|
|
$
|
(1.97
|
)
|
|
$
|
0.97
|
|
Weighted average number of shares outstanding
(1)
|
151,294
|
|
|
152,540
|
|
|
152,540
|
|
|
152,540
|
|
(1)
|
For first and second quarter of 2018, amounts reflect the weighted average number of shares of common stock outstanding based on retrospectively reflecting the impacting of the Reorganization.
|
|
2017
|
||||||||||||||
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
||||||||
|
(in thousands, except per share amounts)
|
||||||||||||||
Total revenues
|
$
|
30,979
|
|
|
$
|
30,290
|
|
|
$
|
39,751
|
|
|
$
|
58,568
|
|
Income (loss) from operations
|
$
|
16,437
|
|
|
$
|
1,867
|
|
|
$
|
10,974
|
|
|
$
|
(9,373
|
)
|
Net income (loss)
|
$
|
16,310
|
|
|
$
|
1,817
|
|
|
$
|
10,710
|
|
|
$
|
(10,380
|
)
|
Earnings (loss) per share
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.22
|
|
|
$
|
0.02
|
|
|
$
|
0.11
|
|
|
$
|
(0.07
|
)
|
Diluted
|
$
|
0.22
|
|
|
$
|
0.02
|
|
|
$
|
0.11
|
|
|
$
|
(0.07
|
)
|
Weighted average number of shares outstanding
(1)
|
75,303
|
|
|
75,303
|
|
|
99,859
|
|
|
150,607
|
|
Director:
|
|
Date of Grant:
|
|
Total Number of Restricted Stock Units:
|
|
Vesting Schedule:
|
Subject to
Section 2(b)
of the Agreement, the Plan and the other terms and conditions set forth herein, the RSUs shall vest on the first anniversary of the Date of Grant, so long as you continuously provide services to the Company or an Affiliate, as applicable, from the Date of Grant through such vesting date.
|
|
|
|
Name
|
|
Jurisdiction
|
Roan Resources LLC
|
|
Delaware
|
Roan Holdings Holdco, LLC
|
|
Delaware
|
Linn Energy, Inc.
|
|
Delaware
|
|
Very truly yours,
|
|
/s/ DeGolyer and MacNaughton
|
Texas Registered Engineering Firm F-716
|
|
1.
|
I have reviewed this Annual Report on Form 10-K of Roan Resources, Inc. (the "registrant");
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:
|
(a)
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
1.
|
I have reviewed this Annual Report on Form 10-K of Roan Resources, Inc. (the "registrant");
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:
|
(a)
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
(1)
|
the Report fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
(1)
|
the Report fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
1.
|
That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to Roan dated February 5, 2019, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.
|
2.
|
That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 35 years of experience in oil and gas reservoir studies and reserves evaluations.
|