|
| | |
| UNITED STATES | |
| SECURITIES AND EXCHANGE COMMISSION |
| Washington, D.C. 20549 | |
xQUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2018
¨TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to ___________
Commission File Number: 001-32720
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| | |
| Roan Resources, Inc. | |
| (Exact Name of Registrant as Specified in its Charter) | |
| |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
| Delaware | | 83-1984112 |
(State or Other Jurisdiction
of Incorporation) | | (IRS Employer
Identification No.) |
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended September 30, 2017
OR
|
| |
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _______________ to _______________
Commission File Number: 000-51719
LINN ENERGY, INC.
(Exact name of registrant as specified in its charter)
|
| |
Delaware14701 Hertz Quail Springs Pkwy
(State or other jurisdiction of incorporation or organization)Oklahoma City, OK
| | 73134 |
| (Address of Principal Executive Offices) | | (Zip Code) |
| (405) 896-8050 |
| (Registrant’s Telephone Number, including Area Code) |
| | |
81-5366183Linn Energy, Inc.
(I.R.S. Employer600 Travis Street
Identification No.)Houston, Texas 77002
|
600 Travis
Houston, Texas
(Former Name or Former Address, of principal executive offices) | 77002
(Zip Code)
|
(281) 840-4000
(Registrant’s telephone number, including area code)
If Changed Since Last Report) |
Indicate by check mark whether the registrantregistrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the precedingpast 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-212 b-2 of the Exchange Act.
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| | |
Large Accelerated Filer ¨ | | Accelerated Filer ¨ |
Large accelerated filer | ¨ | Accelerated filer | ¨ |
Non-accelerated filer | ¨ | (Do not check if a smaller reporting company) Non-Accelerated Filer x | | Smaller Reporting Company ¨ |
| | | Smaller reporting company | x |
| | Emerging growth company | Growth Company ¨ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes x No ¨
As of October 31, 2017,November 9, 2018, there were 84,099,659152,539,532 shares of Class A common stock, par value $0.001 per share, outstanding.
i
This Quarterly Report on Form 10-Q (the “Quarterly Report”) includes “forward-looking statements” within the meaning of ContentsSection 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should carefully consider the risk factors and other cautionary statements described under the heading “Risk Factors” in our Current Report on Form 8-K filed with the Securities and Exchange Commission (the “SEC”) on September 24, 2018 (the “Current Report”) and in Part II, Item 1A. “Risk Factors” of this Quarterly Report. Forward-looking statements may include statements about: our business strategy; our reserves; our drilling plans, prospects, inventories, projects and programs; our ability to replace the reserves we produce through drilling and property acquisitions; our financial strategy, liquidity and capital required for our drilling program and timing related thereto; our realized oil, natural gas and NGL prices; the timing and amount of our future production of oil, natural gas and NGLs; our competition and government regulations; our ability to obtain permits and governmental approvals; our pending legal or environmental matters; our marketing of oil, natural gas and NGLs; our leasehold or business acquisitions; our costs of developing our properties; our hedging strategy and results; general economic conditions; credit markets; uncertainty regarding our future operating results including initial production values and liquid yields in our type curve areas; the costs, terms and availability of gathering, processing, fractionation and other midstream services; and our plans, objectives, expectations and intentions that are not historical.
These forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incidental to the development, production, gathering and sale of oil, natural gas and NGLs. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described in Part II, Item 1A. “Risk Factors” of this Quarterly Report.
GLOSSARY OF OIL AND NATURAL GAS TERMS AsThe following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry and as usedindustry:
Basin. A large natural depression on the earth’s surface in this Quarterly Report on Form 10-Q, the following terms have the following meanings:which sediments generally brought by water accumulate. Bbl. Bbl. One stock tank barrel orof 42 United StatesU.S. gallons liquid volume.volume used herein in reference to crude oil, condensate or NGLs.
Bcf.Boe. One billion cubic feet.
Bcfe. One billion cubic feetbarrel of oil equivalent, determined using thecalculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
Btu. British thermal unit. Completion. Preparation of a well bore and installation of permanent equipment for production of oil, natural gas or NGLs or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned. Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7). Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas. Dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC’s Regulation S-X, Rule 4-10(a)(10). Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15). Formation. A layer of rock which has distinct characteristics that differs from nearby rock. Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned. Held by production. Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas. Liquids. Describes oil, condensate orand natural gas liquids. Btu.MBbl One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.
MBbls.. One thousand barrels of crude oil, condensate or other liquid hydrocarbons.NGLs.
MBbls/d. MBoeMBbls. One thousand Boe.
MBoe/d. One thousand Boe per day. Mcf. One thousand cubic feet.
Mcfe.Mcf. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.gas.
MMBbls.MMBtu One million barrels of oil or other liquid hydrocarbons.
MMBtu.. One million British thermal units.
MMcf.MMcf One million cubic feet.
MMcf/d. MMcf per day.
MMcfe.. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas.
Net acres. The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% working interest in 100 acres owns 50 net acres. Net production. Production that is owned by us less royalties and production due to others. NGLs or Natural gas to one Bblliquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline. NYMEX. The New York Mercantile Exchange. Operator. The individual or company responsible for the development and/or production of an oil condensate or natural gas liquids.well or lease. MMcfe/d. PlayMMcfe per day.. A geographic area with hydrocarbon potential.
MMMBtu.Production costs One billion British thermal units.. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).
NGL. ProspectNatural. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves. Reserves that can be expected to be recovered through (i) existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved properties. Properties with proved reserves. Proved reserves. Those quantities of oil, natural gas liquids,and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the hydrocarbon liquids containedestimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and natural gas.gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22). Proved undeveloped reserves or PUDs. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Realized price. The cash market price less all expected quality, transportation and demand adjustments. Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed. Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. Resources. Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations. Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies. Success rate. The percentage of wells drilled which produce hydrocarbons in commercial quantities. Unproved properties. Properties with no proved reserves. Wellbore. The hole drilled by the bit that is equipped for oil, natural gas and NGL production on a completed well. Also called well or borehole. Working interest. The right granted to the lessee of a property to develop and produce and own natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis. Workover. Operations on a producing well to restore or increase production. WTI. West Texas Intermediate.
PART I –- FINANCIAL INFORMATION | | Item 1. | Item 1. Financial Statements |
LINN ENERGY, INC.Roan Resources, Inc.
CONDENSED CONSOLIDATED BALANCE SHEETS
Condensed Consolidated Balance Sheets (Unaudited) | | | | | | | | | | | | Successor | | | Predecessor | | | September 30,
2017 | | | December 31,
2016 | | (in thousands, except share and unit amounts) | | | | | | ASSETS | | | | | | Current assets: | | | | | | Cash and cash equivalents | $ | 32,042 |
| | | $ | 694,857 |
| | Accounts receivable – trade, net | 165,045 |
| | | 198,064 |
| | Derivative instruments | 6,220 |
| | | — |
| | Restricted cash | 51,322 |
| | | 1,602 |
| | Other current assets | 85,937 |
| | | 105,310 |
| | Current assets of discontinued operations | — |
| | | 701 |
| | Total current assets | 340,566 |
| | | 1,000,534 |
| | | | | | | | Noncurrent assets: | | | | | | Oil and natural gas properties (successful efforts method) | 1,248,246 |
| | | 12,349,117 |
| | Less accumulated depletion and amortization | (53,370 | ) | | | (9,843,908 | ) | | | 1,194,876 |
| | | 2,505,209 |
| | | | | | | | Other property and equipment | 472,332 |
| | | 618,262 |
| | Less accumulated depreciation | (22,067 | ) | | | (217,724 | ) | | | 450,265 |
| | | 400,538 |
| | | | | | | | Derivative instruments | 4,582 |
| | | — |
| | Deferred income taxes | 476,419 |
| | | — |
| | Equity method investments | 461,460 |
| | | 6,200 |
| | Other noncurrent assets | 7,449 |
| | | 7,784 |
| | Noncurrent assets of discontinued operations | — |
| | | 740,326 |
| | | 949,910 |
| | | 754,310 |
| | Total noncurrent assets | 2,595,051 |
| | | 3,660,057 |
| | Total assets | $ | 2,935,617 |
| | | $ | 4,660,591 |
| | | | | | | | LIABILITIES AND EQUITY (DEFICIT) | | | | | | Current liabilities: | | | | | | Accounts payable and accrued expenses | $ | 280,797 |
| | | $ | 295,081 |
| | Derivative instruments | 547 |
| | | 82,508 |
| | Current portion of long-term debt, net | — |
| | | 1,937,729 |
| | Other accrued liabilities | 100,755 |
| | | 25,979 |
| | Current liabilities of discontinued operations | — |
| | | 321 |
| | Total current liabilities | 382,099 |
| | | 2,341,618 |
|
LINN ENERGY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS - Continued
(Unaudited)
| | | | | | | | | | | | Successor | | | Predecessor | | | September 30,
2017 | | | December 31,
2016 | | (in thousands, except share and unit amounts) | | | | | | Derivative instruments | 229 |
| | | 11,349 |
| | Other noncurrent liabilities | 260,133 |
| | | 360,405 |
| | Noncurrent liabilities of discontinued operations | — |
| | | 39,202 |
| | Liabilities subject to compromise | — |
| | | 4,305,005 |
| | | | | | | | Commitments and contingencies (Note 11) |
|
| | |
|
| | Equity (deficit): | | | | | | Predecessor units issued and outstanding (no units issued or outstanding at September 30, 2017; 352,792,474 units issued and outstanding at December 31, 2016) | — |
| | | 5,386,885 |
| | Predecessor accumulated deficit | — |
| | | (7,783,873 | ) | | Successor preferred stock ($0.001 par value, 30,000,000 shares authorized and no shares issued at September 30, 2017; no shares authorized or issued at December 31, 2016) | — |
| | | — |
| | Successor Class A common stock ($0.001 par value, 270,000,000 shares authorized and 84,667,268 shares issued at September 30, 2017; no shares authorized or issued at December 31, 2016) | 85 |
| | | — |
| | Successor additional paid-in capital | 1,926,722 |
| | | — |
| | Successor retained earnings | 349,864 |
| | | — |
| | Total common stockholders’/unitholders’ equity (deficit) | 2,276,671 |
| | | (2,396,988 | ) | | Noncontrolling interests | 16,485 |
| | | — |
| | Total equity (deficit) | 2,293,156 |
| | | (2,396,988 | ) | | Total liabilities and equity (deficit) | $ | 2,935,617 |
| | | $ | 4,660,591 |
|
| | | | | | | | | | | September 30, 2018 | | December 31, 2017 | | | (in thousands, except par value and share data) | | ASSETS | | | | | Current assets | | | | | Cash and cash equivalents | $ | 3,900 |
| | $ | 1,471 |
| | Accounts receivable | | | | | Oil, natural gas and natural gas liquid sales | 47,365 |
| | 74,527 |
| | Affiliates | 14,689 |
| | 4,695 |
| | Joint interest owners and other | 110,991 |
| | 320 |
| | Prepaid drilling advances | 49,279 |
| | — |
| | Derivative contracts | 203 |
| | 152 |
| | Other current assets | 6,412 |
| | 930 |
| | Total current assets | 232,839 |
| | 82,095 |
| | Noncurrent assets | | | | | Oil and natural gas properties, successful efforts method | 2,429,892 |
| | 1,876,951 |
| | Accumulated depreciation, depletion, amortization and impairment | (183,557 | ) | | (78,307 | ) | | Oil and natural gas properties, net | 2,246,335 |
| | 1,798,644 |
| | Other property and equipment, net | 2,935 |
| | 1,147 |
| | Deferred financing costs | 4,417 |
| | 2,710 |
| | Derivative contracts | — |
| | 996 |
| | Total assets | $ | 2,486,526 |
| | $ | 1,885,592 |
| | LIABILITIES AND EQUITY | | | | | Current liabilities | | | | | Accounts payable and accrued liabilities | $ | 198,020 |
| | $ | 10,245 |
| | Accounts payable and accrued liabilities – Affiliates | 7,748 |
| | 183,820 |
| | Revenue payable | 88,029 |
| | — |
| | Drilling advances | 57,374 |
| | — |
| | Derivative contracts | 64,261 |
| | 9,279 |
| | Asset retirement obligations | 535 |
| | — |
| | Total current liabilities | 415,967 |
| | 203,344 |
| | Noncurrent liabilities | | | | | Long-term debt | 394,639 |
| | 85,339 |
| | Deferred tax liabilities | 299,662 |
| | — |
| | Asset retirement obligations | 12,876 |
| | 10,769 |
| | Derivative contracts | 18,901 |
| | 1,371 |
| | Other | 662 |
| | — |
| | Total liabilities | 1,142,707 |
| | 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 September 30, 2018 | 153 |
| | — |
| | Preferred stock, $0.001 par value; 50,000,000 shares authorized; no shares issued and outstanding at September 30, 2018 | — |
| | — |
| | Additional paid-in capital | 1,643,431 |
| | — |
| | Accumulated deficit | (299,765 | ) | | — |
| | Members’ equity | — |
| | 1,584,769 |
| | Total equity | 1,343,819 |
| | 1,584,769 |
| | Total liabilities and equity | $ | 2,486,526 |
| | $ | 1,885,592 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
5 2
Roan Resources, Inc. Condensed Consolidated Statements of ContentsOperations (Unaudited) LINN ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
| | | | | | | | | | | | Successor | | | Predecessor | | | Three Months Ended September 30, 2017 | | | Three Months Ended September 30, 2016 | | (in thousands, except per share and per unit amounts) | | | | | | Revenues and other: | | | | | | Oil, natural gas and natural gas liquids sales | $ | 206,318 |
| | | $ | 237,986 |
| | Gains (losses) on oil and natural gas derivatives | (14,497 | ) | | | 166 |
| | Marketing revenues | 38,493 |
| | | 9,249 |
| | Other revenues | 6,368 |
| | | 19,574 |
| | | 236,682 |
| | | 266,975 |
| | Expenses: | | | | | | Lease operating expenses | 61,272 |
| | | 67,234 |
| | Transportation expenses | 34,541 |
| | | 40,986 |
| | Marketing expenses | 34,099 |
| | | 6,933 |
| | General and administrative expenses | 30,035 |
| | | 48,471 |
| | Exploration costs | 171 |
| | | 4 |
| | Depreciation, depletion and amortization | 29,657 |
| | | 87,413 |
| | Impairment of long-lived assets | — |
| | | 41,728 |
| | Taxes, other than income taxes | 12,368 |
| | | 18,003 |
| | (Gains) losses on sale of assets and other, net | (26,977 | ) | | | 2,532 |
| | | 175,166 |
| | | 313,304 |
| | Other income and (expenses): | | | | | | Interest expense, net of amounts capitalized | (223 | ) | | | (25,283 | ) | | Earnings from equity method investments | 2,575 |
| | | 222 |
| | Other, net | (4,237 | ) | | | (200 | ) | | | (1,885 | ) | | | (25,261 | ) | | Reorganization items, net | (2,605 | ) | | | (28,361 | ) | | Income (loss) from continuing operations before income taxes | 57,026 |
| | | (99,951 | ) | | Income tax expense (benefit) | 5,996 |
| | | (3,650 | ) | | Income (loss) from continuing operations | 51,030 |
| | | (96,301 | ) | | Income (loss) from discontinued operations, net of income taxes | 86,099 |
| | | (102,064 | ) | | Net income (loss) | 137,129 |
| | | (198,365 | ) | | Net income attributable to noncontrolling interests | 66 |
| | | — |
| | Net income (loss) attributable to common stockholders/unitholders | $ | 137,063 |
| | | $ | (198,365 | ) | | | | | | | | Income (loss) per share/unit attributable to common stockholders/unitholders: | | | | | | Income (loss) from continuing operations per share/unit – Basic | $ | 0.58 |
| | | $ | (0.27 | ) | | Income (loss) from continuing operations per share/unit – Diluted | $ | 0.57 |
| | | $ | (0.27 | ) | | | | | | | | Income (loss) from discontinued operations per share/unit – Basic | $ | 0.98 |
| | | $ | (0.29 | ) | | Income (loss) from discontinued operations per share/unit – Diluted | $ | 0.97 |
| | | $ | (0.29 | ) | | | | | | | | Net income (loss) per share/unit – Basic | $ | 1.56 |
| | | $ | (0.56 | ) | | Net income (loss) per share/unit – Diluted | $ | 1.54 |
| | | $ | (0.56 | ) | | | | | | | | Weighted average shares/units outstanding – Basic | 87,796 |
| | | 352,792 |
| | Weighted average shares/units outstanding – Diluted | 88,999 |
| | | 352,792 |
|
| | | | | | | | | | | | | | | | | | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | | 2018 | | 2017 | | 2018 | | 2017 | | | (in thousands, except per share amounts) | | Revenues | | | | | | | | Oil sales | $ | 74,987 |
| | $ | 16,701 |
| | $ | 197,356 |
| | $ | 45,702 |
| Natural gas sales | 10,442 |
| | 11,818 |
| | 31,900 |
| | 29,857 |
| | Natural gas sales – Affiliates | 7,617 |
| | 1,027 |
| | 17,056 |
| | 1,027 |
| Natural gas liquid sales | 12,983 |
| | 9,224 |
| | 38,127 |
| | 21,199 |
| | Natural gas liquid sales – Affiliates | 14,123 |
| | 850 |
| | 27,250 |
| | 850 |
| | (Loss) gain on derivative contracts | (36,704 | ) | | 131 | | (100,920 | ) | | 2,385 |
| | Total revenues | 83,448 |
| | 39,751 |
| | 210,769 |
| | 101,020 |
| | Operating Expenses | | | | | | | | | Production expenses | 14,737 |
| | 4,336 |
| | 30,111 |
| | 10,450 |
| | Gathering, transportation and processing | — |
| | 4,890 |
| | — |
| | 11,360 |
| | Production taxes | 6,210 |
| | 847 |
| | 10,892 |
| | 2,057 |
| | Exploration expenses | 11,646 |
| | 4,229 |
| | 30,129 |
| | 4,475 |
| | Depreciation, depletion, amortization and accretion | 37,164 |
| | 10,824 |
| | 83,630 |
| | 22,176 |
| | General and administrative | 13,177 |
| | 4,489 |
| | 40,283 |
| | 22,062 |
| | Gain on sale of oil and natural gas properties | — |
| | (838 | ) | | — |
| | (838 | ) | | Total operating expenses | 82,934 |
| | 28,777 |
| | 195,045 |
| | 71,742 |
| | Total operating income | 514 |
| | 10,974 |
| | 15,724 |
| | 29,278 |
| | Other income (expense) | | | | | | | | | Interest expense, net | (2,092) |
| | (264) |
| | (4,978) |
| | (441) |
| | Net (loss) income before income taxes | (1,578 | ) | | 10,710 |
| | 10,746 |
| | 28,837 |
| | Income tax expense | 299,662 |
| | — |
| | 299,662 |
| | — |
| | Net (loss) income | $ | (301,240 | ) | | $ | 10,710 |
| | $ | (288,916 | ) | | $ | 28,837 |
| | Earnings (loss) per share | | | | | | | | | Basic | $ | (1.97 | ) | | $ | 0.11 |
| | $ | (1.90 | ) | | $ | 0.35 |
| | Diluted | $ | (1.97 | ) | | $ | 0.11 |
| | $ | (1.90 | ) | | $ | 0.35 |
| | Weighted average number of shares outstanding | | | | | | | | | Basic | 152,540 |
| | 99,859 |
| | 152,129 |
| | 83,578 |
| | Diluted | 152,540 |
| | 99,859 |
| | 152,129 |
| | 83,578 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
6 3
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands, except per share and per unit amounts) | | | | | | | | Revenues and other: | | | | | | | | Oil, natural gas and natural gas liquids sales | $ | 529,810 |
| | | $ | 188,885 |
| | $ | 618,274 |
| | Gains (losses) on oil and natural gas derivatives | 19,258 |
| | | 92,691 |
| | (74,175 | ) | | Marketing revenues | 53,954 |
| | | 6,636 |
| | 26,861 |
| | Other revenues | 14,787 |
| | | 9,915 |
| | 71,521 |
| | | 617,809 |
| | | 298,127 |
| | 642,481 |
| | Expenses: | | | | | | | | Lease operating expenses | 156,959 |
| | | 49,665 |
| | 220,847 |
| | Transportation expenses | 85,652 |
| | | 25,972 |
| | 124,609 |
| | Marketing expenses | 43,614 |
| | | 4,820 |
| | 21,493 |
| | General and administrative expenses | 74,904 |
| | | 71,745 |
| | 184,360 |
| | Exploration costs | 1,037 |
| | | 93 |
| | 2,745 |
| | Depreciation, depletion and amortization | 101,558 |
| | | 47,155 |
| | 262,880 |
| | Impairment of long-lived assets | — |
| | | — |
| | 165,044 |
| | Taxes, other than income taxes | 37,316 |
| | | 14,877 |
| | 53,544 |
| | (Gains) losses on sale of assets and other, net | (333,371 | ) | | | 829 |
| | 6,607 |
| | | 167,669 |
| | | 215,156 |
| | 1,042,129 |
| | Other income and (expenses): | | | | | | | | Interest expense, net of amounts capitalized | (11,974 | ) | | | (16,725 | ) | | (159,476 | ) | | Earnings from equity method investments | 2,705 |
| | | 157 |
| | 511 |
| | Other, net | (5,788 | ) | | | (149 | ) | | (1,358 | ) | | | (15,057 | ) | | | (16,717 | ) | | (160,323 | ) | | Reorganization items, net | (8,547 | ) | | | 2,331,189 |
| | 457,437 |
| | Income (loss) from continuing operations before income taxes | 426,536 |
| | | 2,397,443 |
| | (102,534 | ) | | Income tax expense (benefit) | 159,451 |
| | | (166 | ) | | 2,944 |
| | Income (loss) from continuing operations | 267,085 |
| | | 2,397,609 |
| | (105,478 | ) | | Income (loss) from discontinued operations, net of income taxes | 82,845 |
| | | (548 | ) | | (1,232,141 | ) | | Net income (loss) | 349,930 |
| | | 2,397,061 |
| | (1,337,619 | ) | | Net income attributable to noncontrolling interests | 66 |
| | | — |
| | — |
| | Net income (loss) attributable to common stockholders/unitholders | $ | 349,864 |
| | | $ | 2,397,061 |
| | $ | (1,337,619 | ) | | | | | | | | | | Income (loss) per share/unit attributable to common stockholders/unitholders: | | | | | | | | Income (loss) from continuing operations per share/unit – Basic | $ | 3.00 |
| | | $ | 6.80 |
| | $ | (0.30 | ) | | Income (loss) from continuing operations per share/unit – Diluted | $ | 2.97 |
| | | $ | 6.80 |
| | $ | (0.30 | ) | | | | | | | | | | Income (loss) from discontinued operations per share/unit – Basic | $ | 0.93 |
| | | $ | (0.01 | ) | | $ | (3.49 | ) | | Income (loss) from discontinued operations per share/unit – Diluted | $ | 0.93 |
| | | $ | (0.01 | ) | | $ | (3.49 | ) | | | | | | | | | | Net income (loss) per share/unit – Basic | $ | 3.93 |
| | | $ | 6.79 |
| | $ | (3.79 | ) | | Net income (loss) per share/unit – Diluted | $ | 3.90 |
| | | $ | 6.79 |
| | $ | (3.79 | ) | | | | | | | | | | Weighted average shares/units outstanding – Basic | 88,966 |
| | | 352,792 |
| | 352,606 |
| | Weighted average shares/units outstanding – Diluted | 89,784 |
| | | 352,792 |
| | 352,606 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | Stockholders' Equity | | | | | | | Common Stock (Shares) | | Common Stock | | Additional Paid-in Capital | | Accumulated Deficit | | Members' Equity | | Total Equity | | | (in thousands) | | 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) | — |
| | — |
| | 192 |
| | — |
| | 7,868 |
| | 8,060 |
| Net loss (1) | — |
| | — |
| | — |
| | (299,765 | ) | | 10,849 |
| | (288,916 | ) | | Issuance of common stock upon Reorganization | 152,540 |
| | 153 |
| | 1,643,239 |
| | — |
| | (1,643,392 | ) | | — |
| | Balance at September 30, 2018 | 152,540 |
| | $ | 153 |
| | $ | 1,643,431 |
| | $ | (299,765 | ) | | $ | — |
| | $ | 1,343,819 |
| | | | | | | | | | | | | |
(1)Amounts are allocated to stockholders' equity and members' equity to reflect the Reorganization. See Note 10 – Equity for discussion of the Reorganization.
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
7 4
Roan Resources, Inc. Condensed Consolidated Statements of ContentsCash Flows (Unaudited)
LINN ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENT OF EQUITY (PREDECESSOR)
(Unaudited)
| | | | | | | | | | | | | | | | | | Units | | Unitholders’ Capital | | Accumulated Deficit | | Total Unitholders’ Capital (Deficit) | | | (in thousands) | | | | | | | | | | December 31, 2016 (Predecessor) | 352,792 |
| | $ | 5,386,885 |
| | $ | (7,783,873 | ) | | $ | (2,396,988 | ) | | Net income | | | — |
| | 2,397,061 |
| | 2,397,061 |
| | Other | | | (73 | ) | | — |
| | (73 | ) | February 28, 2017 (Predecessor) | 352,792 |
| | 5,386,812 |
| | (5,386,812 | ) | | — |
| | Cancellation of predecessor equity | (352,792 | ) | | (5,386,812 | ) | | 5,386,812 |
| | — |
| February 28, 2017 (Predecessor) | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | Nine Months Ended
September 30, | | | 2018 | | 2017 | | | (in thousands) | | Cash flows from operating activities | | | | | Net (loss) income | $ | (288,916 | ) | | $ | 28,837 |
| | Adjustments to reconcile net (loss) income to net cash provided by operating activities: | | | | | Depreciation, depletion, amortization and accretion | 83,630 |
| | 22,176 |
| | Unproved leasehold amortization and impairment and dry hole expense | 25,642 |
| | 4,475 |
| | Gain on sale of oil and natural gas properties | — |
| | (838 | ) | | Amortization of deferred financing costs | 571 |
| | 39 |
| | Amortization of deferred rent | 662 |
| | — |
| | Loss (gain) on derivative contracts | 100,920 |
| | (2,385 | ) | | Net cash (paid) received upon settlement of derivative contracts | (27,462 | ) | | 2,385 |
| | Equity-based compensation | 8,060 |
| | — |
| | Deferred income taxes | 299,662 |
| | — |
| | Other | (111 | ) | | (8 | ) | | Changes in operating assets and liabilities increasing (decreasing) cash: | | | | | Accounts receivable – Oil, natural gas and natural gas liquid sales | 27,162 |
| | (10,820 | ) | | Accounts receivable – Affiliates | (9,994 | ) | | (1,877 | ) | | Accounts receivable – Joint interest owners and other | (110,671 | ) | | (8,410 | ) | | Prepaid drilling advances | (55,815 | ) | | — |
| | Other current assets | (5,398 | ) | | (1,805 | ) | | Accounts payable and accrued liabilities | 37,773 |
| | 37,816 |
| | Accounts payable and accrued liabilities – Affiliates | (24,474 | ) | | 1,913 |
| | Drilling advances | 57,374 |
| | (25,363 | ) | | Revenue payable | 88,029 |
| | 13,113 |
| | Net cash provided by operating activities | 206,644 |
| | 59,248 |
| | Cash flows from investing activities | | | | | Acquisition of oil and natural gas properties | (22,935 | ) | | (42,701 | ) | | Capital expenditures for oil and natural gas properties | (485,580 | ) | | (138,152 | ) | | Acquisition of other property and equipment | (2,353 | ) | | (153 | ) | | Proceeds from sale of oil and natural gas properties | — |
| | 1,435 |
| | Purchase of investment | — |
| | (3,000 | ) | | Net cash used in investing activities | (510,868 | ) | | (182,571 | ) | | Cash flows from financing activities | | | | | Proceeds from borrowings | 309,300 |
| | 75,340 |
| | Repayment of borrowings | — |
| | (40,000 | ) | | Deferred financing costs | (2,279 | ) | | (2,340 | ) | | Deferred offering costs | (368 | ) |
| — |
| | Contributions from Citizen members | — |
| | 95,557 |
| | Distributions to Citizen members | — |
| | (11,147 | ) | | Net cash provided by financing activities | 306,653 |
| | 117,410 |
| | Net increase (decrease) in cash and cash equivalents | 2,429 |
| | (5,913 | ) | | Cash and cash equivalents, beginning of period | 1,471 |
| | 6,853 |
| | Cash and cash equivalents, end of period | $ | 3,900 |
| | $ | 940 |
|
CONDENSED CONSOLIDATED STATEMENT OF EQUITY (SUCCESSOR)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Class A Common Stock | | Additional Paid-in Capital | | Retained Earnings | | Total Common Stockholders’ Equity | | Noncontrolling Interests | | Total Equity | | | Shares | | Amount | | | | | | | (in thousands) | | | | | | | | | | | | | | | | | Issuances of successor Class A common stock | 89,230 |
| | $ | 89 |
| | $ | 2,021,142 |
| | $ | — |
| | $ | 2,021,231 |
| | $ | — |
| | $ | 2,021,231 |
| | Share-based compensation expenses | | | — |
| | 13,750 |
| | — |
| | 13,750 |
| | — |
| | 13,750 |
| February 28, 2017 (Successor) | 89,230 |
| | 89 |
| | 2,034,892 |
| | — |
| | 2,034,981 |
| | — |
| | 2,034,981 |
| | Net income | | | — |
| | — |
| | 349,864 |
| | 349,864 |
| | 66 |
| | 349,930 |
| | Issuances of successor Class A common stock | 21 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | Repurchases of successor Class A common stock | (4,584 | ) | | (4 | ) | | (156,947 | ) | | — |
| | (156,951 | ) | | — |
| | (156,951 | ) | | Share-based compensation expenses | | | — |
| | 62,381 |
| | — |
| | 62,381 |
| | — |
| | 62,381 |
| | Initial allocation of noncontrolling interests upon conversion of subsidiary units | | | — |
| | (17,605 | ) | | — |
| | (17,605 | ) | | 17,605 |
| | — |
| | Distributions to noncontrolling interests | | | — |
| | — |
| | — |
| | — |
| | (1,211 | ) | | (1,211 | ) | | Subsidiary equity transactions | | | — |
| | (25 | ) | | — |
| | (25 | ) | | 25 |
| | — |
| | Other | | | — |
| | 4,026 |
| | — |
| | 4,026 |
| | — |
| | 4,026 |
| September 30, 2017 (Successor) | 84,667 |
| | $ | 85 |
| | $ | 1,926,722 |
| | $ | 349,864 |
| | $ | 2,276,671 |
| | $ | 16,485 |
| | $ | 2,293,156 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
8 5
Roan Resources, Inc. LINN ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | Cash flow from operating activities: | | | | | | | | Net income (loss) | $ | 349,930 |
| | | $ | 2,397,061 |
| | $ | (1,337,619 | ) | | Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | | | | | | | | (Income) loss from discontinued operations | (82,845 | ) | | | 548 |
| | 1,232,141 |
| | Depreciation, depletion and amortization | 101,558 |
| | | 47,155 |
| | 262,880 |
| | Impairment of long-lived assets | — |
| | | — |
| | 165,044 |
| | Deferred income taxes | 116,446 |
| | | (166 | ) | | 831 |
| | Noncash (gains) losses on oil and natural gas derivatives | 380 |
| | | (104,263 | ) | | 931,085 |
| | Share-based compensation expenses | 25,876 |
| | | 50,255 |
| | 24,514 |
| | Amortization and write-off of deferred financing fees | 3,349 |
| | | 1,338 |
| | 11,288 |
| | (Gains) losses on sale of assets and other, net | (357,510 | ) | | | 1,069 |
| | 5,534 |
| | Reorganization items, net | — |
| | | (2,359,364 | ) | | (485,831 | ) | | Changes in assets and liabilities: | | | | | | | | (Increase) decrease in accounts receivable – trade, net | 15,549 |
| | | (7,216 | ) | | (27,857 | ) | | (Increase) decrease in other assets | 3,908 |
| | | 402 |
| | (17,111 | ) | | (Increase) decrease in restricted cash | 2,151 |
| | | (80,164 | ) | | — |
| | Increase (decrease) in accounts payable and accrued expenses | (43,213 | ) | | | 20,949 |
| | 64,252 |
| | Increase in other liabilities | 56,460 |
| | | 2,801 |
| | 21,679 |
| | Net cash provided by (used in) operating activities – continuing operations | 192,039 |
| | | (29,595 | ) | | 850,830 |
| | Net cash provided by operating activities – discontinued operations | 2,566 |
| | | 8,781 |
| | 34,362 |
| | Net cash provided by (used in) operating activities | 194,605 |
| | | (20,814 | ) | | 885,192 |
| | | | | | | | | | Cash flow from investing activities: | | | | | | | | Development of oil and natural gas properties | (136,638 | ) | | | (50,597 | ) | | (118,920 | ) | | Purchases of other property and equipment | (60,656 | ) | | | (7,409 | ) | | (25,955 | ) | | Proceeds from sale of properties and equipment and other | 703,234 |
| | | (166 | ) | | (3,321 | ) | | Net cash provided by (used in) investing activities – continuing operations | 505,940 |
| | | (58,172 | ) | | (148,196 | ) | | Net cash provided by (used in) investing activities – discontinued operations | 345,643 |
| | | (584 | ) | | 19,133 |
| | Net cash provided by (used in) investing activities | 851,583 |
| | | (58,756 | ) | | (129,063 | ) | | | | | | | | |
| | | | | | | | | | | Nine Months Ended
September 30, | | | 2018 | | 2017 | | | (in thousands) | | Supplemental disclosure of cash flow information | | | | | Cash paid for interest, net of capitalized interest | $ | 4,024 |
| | $ | 341 |
| | Supplemental disclosure of non-cash investing and financing activities | | | | | Change in accrued capital expenditures | $ | 38,593 |
| | $ | 22,456 |
| | Acquisition of oil and natural gas properties for equity | $ | 39,906 |
| | $ | 1,281,743 |
| | Distribution to Citizen Members of assets and liabilities | $ | — |
| | $ | (74,467 | ) |
LINN ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - Continued
(Unaudited)
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | Cash flow from financing activities: | | | | | | | | Proceeds from rights offerings, net | — |
| | | 514,069 |
| | — |
| | Repurchases of shares | (156,091 | ) | | | — |
| | — |
| | Proceeds from borrowings | 190,000 |
| | | — |
| | 978,500 |
| | Repayments of debt | (1,090,000 | ) | | | (1,038,986 | ) | | (913,210 | ) | | Debt issuance costs paid | (7,229 | ) | | | — |
| | (692 | ) | | Payment to holders of claims under the second lien notes | — |
| | | (30,000 | ) | | — |
| | Other | (5,181 | ) | | | (6,015 | ) | | (20,687 | ) | | Net cash provided by (used in) financing activities – continuing operations | (1,068,501 | ) | | | (560,932 | ) | | 43,911 |
| | Net cash used in financing activities – discontinued operations | — |
| | | — |
| | (1,701 | ) | | Net cash provided by (used in) financing activities | (1,068,501 | ) | | | (560,932 | ) | | 42,210 |
| | | | | | | | | | Net increase (decrease) in cash and cash equivalents | (22,313 | ) | | | (640,502 | ) | | 798,339 |
| | Cash and cash equivalents: | | | | | | | | Beginning | 54,355 |
| | | 694,857 |
| | 2,168 |
| | Ending | 32,042 |
| | | 54,355 |
| | 800,507 |
| | Less cash and cash equivalents of discontinued operations at end of period | — |
| | | — |
| | (29,647 | ) | | Ending – continuing operations | $ | 32,042 |
| | | $ | 54,355 |
| | $ | 770,860 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
9 7
Roan Resources, Inc. Notes to Unaudited Condensed Consolidated Financial Statements
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 – BasisBusiness and Organization
Roan Resources, Inc. (“Roan Inc.”) was formed in September 2018 to facilitate a reorganization and to become the holding company for Roan Resources LLC (“Roan LLC”). In September 2018, a series of Presentationtransactions were executed with Roan LLC's members which resulted in Roan LLC becoming a wholly owned subsidiary of Roan Inc. These transactions are hereafter referred to as the “Reorganization” and Roan Inc. with its subsidiaries are collectively referred to as the “Company.” See Note 10 – Equity for further discussion of the Reorganization transaction. The accompanying historical financial statements through the date of Reorganization are the financial statements of Roan LLC, our accounting predecessor. Following the Reorganization, the historical financial statements are the results of Roan Inc. When referring to
Roan LLC was initially formed by Citizen Energy II, LLC (“Citizen”) in May 2017. On August 31, 2017, the Companyexecuted a contribution agreement (the “Contribution Agreement”) by and among Roan LLC, Citizen, Linn Energy Inc. (formerly known asHoldings, LLC (“LEH”) and Linn Energy, LLC)Operating, LLC (“Successor,” “LINN Energy” or the “Company”)LOI”, the intent is to refer to LINN Energy, a newly formed Delaware corporation, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Linn Energy, Inc. is a successor issuer of Linn Energy, LLCtogether with LEH, “Linn”) pursuant to Rule 15d‑5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). When referringwhich, among other things, Citizen and Linn agreed to contribute oil and natural gas properties within an area-of-mutual-interest to the “Predecessor”Company (collectively the “Contribution”). In exchange for their contributions, Citizen and Linn each received a 50% equity interest in referencethe Company.
The contributions of oil and natural gas properties to Roan LLC by Citizen and Linn were determined to meet the definition of a business. However, as Roan LLC had no assets or operations prior to the Contribution, it was determined that Citizen was the acquirer for accounting purposes in accordance with ASC Topic 805, Business Combinations (“ASC 805”). As a result, the information in the accompanying financial statements and footnotes for the period prior to the emergence from bankruptcy,Contribution reflects the intent ishistorical results of Citizen. Citizen was formed in July 2014 to refer to Linn Energy, LLC,engage in the predecessor that will be dissolved following the effective dateacquisition, exploration, development, production, and sale of the Plan (as defined below) and resolution of all outstanding claims, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. The reference to “Berry” herein refers to Berry Petroleum Company, LLC, which was an indirect 100% wholly owned subsidiary of the Predecessor through February 28, 2017. Berry was deconsolidated effective December 3, 2016 (see Note 4). The reference to “LinnCo” herein refers to LinnCo, LLC, an affiliate of the Predecessor.
Nature of Business
LINN Energy is an independent oil and natural gas company thatproperties located in Central Oklahoma. Subsequent to the Contribution, the information in the accompanying financial statements and footnotes reflects the results of Roan LLC and after the Reorganization, the results of Roan Inc. See Note 4 – Acquisitions for additional discussion of the business combination of the oil and natural gas properties contributed by Linn. In conjunction with the Contribution Agreement, the Company entered into master services agreements with both Citizen and Linn (“MSAs”). See Note 12 –Transactions with Affiliates for additional discussion of the MSAs and transactions with Citizen and Linn.
The Company was formed to engage in February 2017,the acquisition, exploration, development, production, and sale of oil and natural gas reserves. The Company’s oil and natural gas properties are located in connection with the reorganizationCentral Oklahoma. The Company’s corporate headquarters is located in Oklahoma City, Oklahoma.
Note 2 – Summary of Significant Accounting Policies
For a description of the Predecessor. The Predecessor was publicly traded from January 2006Company’s significant accounting policies, refer to February 2017. As discussed further in Note 2 on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certainto the Company’s 2017 audited financial statements included in the Current Report. The accompanying condensed consolidated financial statements were prepared in conformity with accounting principles generally accepted in the United States of its direct and indirect subsidiaries, and LinnCo (collectively, the “LINN Debtors”America (“GAAP”) and Berry (collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11.
Principles of Consolidation
The condensed consolidated financial statements of the U.S. Bankruptcy Code (“Bankruptcy Code”)Company include the accounts of Roan Inc. and its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated.
Roan Resources, Inc. Notes to Unaudited Condensed Consolidated Financial Statements
Interim Financial Statements
The accompanying condensed consolidated financial statements as of December 31, 2017 were derived from the annual financial statements included in the U.S. Bankruptcy CourtCurrent Report. The unaudited interim condensed consolidated financial statements for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 casesthree and nine months ended September 30, 2018 and 2017 were administered jointly underprepared by the caption In re Linn Energy, LLC, et al., Case No. 16-60040. During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court andCompany in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017. The Company’s properties are currently located in seven operating regionsaccounting policies stated in the United States (“U.S.”), in the Hugoton Basin, the Mid-Continent, east Texas and north Louisiana (“TexLa”), the Rockies, the Permian Basin, Michigan/Illinois and south Texas.audited financial statements. In July 2017, the Company divested all of its properties located in California. The Company also owns a 50% equity interest in Roan Resources LLC, which is focused on the accelerated development of the Merge/SCOOP/STACK play in Oklahoma.
Principles of Consolidation and Reporting
The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, the Company’s unaudited condensed consolidated financial statements reflect all known adjustments necessary forto fairly state the fair presentationfinancial position of the Company and its results of operations and cash flows for the interimsuch periods. All such adjustments are of a normal, recurring nature. Certain information and note disclosures normally included in annual financial statements prepared in accordanceconformity with U.S. generally accepted accounting principles (“GAAP”)GAAP have been condensedconsolidated or omitted, under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this reportalthough the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s annual financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.
The condensed consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Noncontrolling interests represent ownership in the net assets of the Company’s consolidated subsidiary, Linn Energy Holdco LLC (“Holdco”), not attributable to LINN Energy, and are presented as a component of equity. Changes in the Company’s ownership interests in Holdco that do not result in deconsolidation are recognized in equity. See Note 13 for additional information about noncontrolling interests. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. See Note 6 for additional information about equity method investments.thereto.
Income Taxes 8
TableThe Company is a corporation and therefore a taxable entity. As a result of Contentsthe Reorganization, the Company recorded a deferred tax liability based on the change in tax status. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. See Note 13 – Income Taxesfor further information on the Company’s taxes.LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Use of Estimates
The condensed consolidatedpreparation of financial statements for previous periods include certain reclassificationsand related footnotes in conformity with GAAP requires that were made to conform to current presentation. The Company has also classifiedmanagement formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilitiesliabilities. A significant item that requires management’s estimates and assumptions is the estimate of its California properties, as well asproved oil, natural gas and NGL reserves which are used in the resultscalculation of operations and cash flowsdepletion of its California properties and Berry, as discontinued operations on its condensed consolidated financial statements. Such reclassifications have no impact on previously reported net income (loss), stockholders’/unitholders’ equity (deficit) or cash flows. See Note 4 for additional information. In addition, during the third quarter of 2017, the Company corrected its allocation of value between proved and unprovedCompany’s oil and natural gas properties initially recorded as partand impairment, if any, of fresh start accounting (see Note 3) resulting in a reclassification of approximately $459 million from proved properties to unproved properties as of February 28, 2017. As a result, during the third quarter of 2017, the Company also recorded pretax out-of-period corrections of approximately $8 million to reduce depletion expense and approximately $1 million to increase net gains on sale of assets (combined $5 million after tax), as well as approximately $8 million to increase income from discontinued operations, net of income taxes, related to errors in the first and second quarters of 2017. The Company concluded that the correction of the errors was not material to these or any previously issued financial statements.
Bankruptcy Accounting
The condensed consolidated financial statements have been prepared as if the Company will continue as a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s condensed consolidated statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy reorganization process have been classified as “liabilities subject to compromise” on the Company’s condensed consolidated balance sheet at December 31, 2016. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less.
Upon emergence from bankruptcy on February 28, 2017, the Company adopted fresh start accounting which resulted in the Company becoming a new entity for financial reporting purposes. As a result of the application of fresh start accounting and the effects of the implementation of the plan of reorganization, the condensed consolidated financial statements on or after February 28, 2017, are not comparable with the condensed consolidated financial statements prior to that date. See Note 3 for additional information.
Use of Estimates
The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletionproperties. Changes in estimated quantities of its reserves could impact the Company’s reported financial results as well as disclosures regarding the quantities and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. In addition, as part of fresh start accounting, the Company made estimates and assumptions related to its reorganization value, liabilities subject to compromise, the fair value of assetsproved oil and liabilities recorded as a result of the adoption of fresh start accounting and income taxes.
As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, whichnatural gas reserves. Although management believes to bethese estimates are reasonable, under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Recent Accounting Standards Issued 9
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”). This guidance supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. Subsequent to the issuance of ASU 2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (“ASU 2016-08”), pertaining to the presentation of revenues on a gross basis
LINN ENERGY, INC.Roan Resources, Inc.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNotes to Unaudited Condensed Consolidated Financial Statements
(Unaudited)
Recently Issued Accounting Standards
In November 2016,(revenues presented separately from associated expenses) versus a net basis. This guidance requires an entity to record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity records revenue on a net basis if its role is to arrange for another entity to provide the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) thatgoods or services to a customer. Applying the guidance in ASU 2016-08 requires significant judgment in determining the point in time when control of products transfers to customers. Effective January 1, 2018, the Company adopted ASC 606 using the modified retrospective method of transition under which the standard is intendedapplied only to address diversity in the classificationmost current period presented. Accordingly, comparative information has not been adjusted and presentation of changes in restricted cash oncontinues to be reported under the statement of cash flows. This ASU will be applied retrospectively asprevious revenue standard. See Note 3 – Revenue from Contracts with Customers for discussion of the date ofimpact upon adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and relatedadditional disclosures. The adoption of this ASU is expected to result in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and disclosure reconciling cash and cash equivalents presented on the balance sheets to cash, cash equivalents and restricted cash on the statements of cash flows.
In March 2016, the FASB issued an ASU that is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The Company adopted this ASU on January 1, 2017. The adoption of this ASU had no impact on the Company’s historical financial statements or related disclosures. Upon adoption and subsequently this ASU will result in excess tax benefits, which were previously recorded in equity on the balance sheets and classified as financing activities on the statements of cash flows, being recorded in the statements of operations and classified as operating activities on the statements of cash flows. Additionally, the Company elected to begin accounting for forfeitures as they occur.
In February 2016, the FASB issued an ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”). This update applies to any entity that is intendedenters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to increase transparencymake lease payments (the lease liability) and comparability among organizations by recognizinga right-of-use asset representing its right to use the underlying asset for the lease assets and lease liabilities onterm. While there were no major changes to the balance sheet.lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This ASUupdate will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2018, andincluding interim reporting periods within those fiscal years, (earlywith early application permitted. The Company enters into lease agreements to support its operations, such as office space, vehicles and drilling rigs. ASU 2016-02 will not impact the accounting or financial presentation of the Company’s mineral leases. The Company plans to adopt the new standard using the simplified transition method described in ASU 2018-11 Leases (Topic 842): Targeted Improvements, and therefore will apply the new standard as of January 1, 2019 and will recognize a cumulative-effect adjustment to the opening balance of retained earnings, if any, upon adoption permitted).in lieu of retrospectively applying the new standard to periods before adoption. The Company is currently evaluatingworking to complete its evaluation of the impact of ASU 2016-02 on its financial statements, accounting policies, and internal controls, including implementation of systems and processes to capture, classify and account for leases within the scope of the new guidance and to provide the related disclosures.
Note 3 – Revenue from Contracts with Customers
The Company adopted ASC 606 on January 1, 2018 using a modified retrospective approach, which only applies to contracts that were not completed as of the date of initial application. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment. The adoption does not have a material impact on the timing of the Company’s revenue recognition or its financial position, results of operations, net income, or cash flows, but does impact the Company’s presentation of revenues and expenses under the gross-versus-net presentation guidance in ASU 2016-08.
Roan Resources, Inc. Notes to Unaudited Condensed Consolidated Financial Statements
The following table shows the impact of the adoption of this ASUASC 606 on its financial statements and related disclosures. The Company expects the adoption of this ASU to impact its balance sheets resulting from an increase in both assets and liabilities relatedCompany’s current period results as compared to the Company’s leasing activities. In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements forprevious revenue from contracts with customers. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those years (early adoption permitted for fiscal years beginning after December 15, 2016, including interim periods within that year). The Company does not plan to early adopt this ASU. The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures. The Company expects to use the cumulative-effect transition method, has completed an initial review of its contracts and is developing accounting policies to address the provisions of the ASU, but has not finalized any estimates of the potential impacts.
Note 2 – Emergence From Voluntary Reorganization Under Chapter 11
On the Petition Date, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040.
On December 3, 2016, the LINN Debtors filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLCrecognition standard, ASC Topic 605, Revenue Recognition (“LAC”ASC 605”) and Berry Petroleum Company, LLC (the “Plan”). The LINN Debtors subsequently filed amended versions of the Plan with the Bankruptcy Court.
On December 13, 2016, LAC and Berry filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “Berry Plan” and together with the Plan, the “Plans”). LAC and Berry subsequently filed amended versions of the Berry Plan with the Bankruptcy Court.
On January 27, 2017, the Bankruptcy Court entered an order approving and confirming the Plans (the “Confirmation Order”). On February 28, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the respective Plans, the
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Plans became effective in accordance with their respective terms and LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities.
Plan of Reorganization
In accordance with the Plan, on the Effective Date:
The Predecessor transferred all of its assets, including equity interests in its subsidiaries, other than LAC and Berry, to Linn Energy Holdco II LLC (“Holdco II”), a newly formed subsidiary of the Predecessor and the borrower under the Credit Agreement (as amended, the “Successor Credit Facility”) entered into in connection with the reorganization, in exchange for 100% of the equity of Holdco II and the issuance of interests in the Successor Credit Facility to certain of the Predecessor’s creditors in partial satisfaction of their claims (the “Contribution”). Immediately following the Contribution, the Predecessor transferred 100% of the equity interests in Holdco II to the Successor in exchange for approximately $530 million in cash and an amount of equity securities in the Successor not to exceed 49.90% of the outstanding equity interests of the Successor, which the Predecessor distributed to certain of its creditors in satisfaction of their claims. Contemporaneously with the reorganization transactions and pursuant to the Plan, (i) LAC assigned all of its rights, title and interest in the membership interests of Berry to Berry Petroleum Corporation, (ii) all of the equity interests in LAC and the Predecessor were canceled and (iii) LAC and the Predecessor commenced liquidation, which is expected to be completed following the resolution of the respective companies’ outstanding claims.
The holders of claims under the Predecessor’s Sixth Amended and Restated Credit Agreement (“Predecessor Credit Facility”) received a full recovery, consisting of a cash paydown and their pro rata share of the $1.7 billion Successor Credit Facility. As a result, all outstanding obligations under the Predecessor Credit Facility were canceled.
Holdco II, as borrower, entered into the Successor Credit Facility with the holders of claims under the Predecessor Credit Facility, as lenders, and Wells Fargo Bank, National Association, as administrative agent, providing for a new reserve-based revolving loan with up to $1.4 billion in borrowing commitments and a new term loan in an original principal amount of $300 million. For additional information about the Successor Credit Facility, see Note 7.
The holders of the Company’s 12.00% senior secured second lien notes due December 2020 (the “Second Lien Notes”) received their pro rata share of (i) 17,678,889 shares of Class A common stock; (ii) certain rights to purchase shares of Class A common stock in the rights offerings, as described below; and (iii) $30 million in cash. The holders of the Company’s 6.50% senior notes due May 2019, 6.25% senior notes due November 2019, 8.625% senior notes due 2020, 7.75% senior notes due February 2021 and 6.50% senior notes due September 2021 (collectively, the “Unsecured Notes”) received their pro rata share of (i) 26,724,396 shares of Class A common stock; and (ii) certain rights to purchase shares of Class A common stock in the rights offerings, as described below. As a result, all outstanding obligations under the Second Lien Notes and the Unsecured Notes and the indentures governing such obligations were canceled.
The holders of general unsecured claims (other than claims relating to the Second Lien Notes and the Unsecured Notes) against the LINN Debtors (the “LINN Unsecured Claims”) received their pro rata share of cash from two cash distribution pools totaling $40 million, as divided between a $2.3 million cash distribution pool for the payment in full of allowed LINN Unsecured Claims in an amount equal to $2,500 or less (and larger claims for which the holders irrevocably agreed to reduce such claims to $2,500), and a $37.7 million cash distribution pool for pro rata distributions to all remaining allowed general LINN Unsecured Claims. As a result, all outstanding LINN Unsecured Claims were fully satisfied, settled, released and discharged as of the Effective Date.
All units of the Predecessor that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery. On the Effective Date, the Successor issued in the aggregate 89,229,892 shares of Class A common stock. No cash was raised from the issuance of the Class A common stock on account of claims held by the Predecessor’s creditors.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
The Successor entered into a registration rights agreement with certain parties, pursuant to which the Company agreed to, among other things, file a registration statement with the SEC within 60 days of the Effective Date covering the offer and resale of “Registrable Securities” (as defined therein).
By operation of the Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. The Successor formed a new board of directors, consisting of the Chief Executive Officer of the Predecessor, one director selected by the Successor and five directors selected by a six-person selection committee.
Rights Offerings
On October 25, 2016, the Company entered into a backstop commitment agreement (“Backstop Commitment Agreement”) with the parties thereto (collectively, the “Backstop Parties”). In accordance with the Plan, the Backstop Commitment Agreement and the rights offerings procedures filed in the Chapter 11 cases and approved by the Bankruptcy Court, the LINN Debtors offered eligible creditors the right to purchase Class A common stock upon emergence from the Chapter 11 cases for an aggregate purchase price of $530 million.
Under the Backstop Commitment Agreement, certain Backstop Parties agreed to purchase their pro rata share of the shares that were not duly subscribed to pursuant to the offerings at the discounted per share price set forth in the Backstop Commitment Agreement by parties other than Backstop Parties. Pursuant to the Backstop Commitment Agreement, the LINN Debtors agreed to pay the Backstop Parties on the Effective Date a commitment premium equal to 4.0% of the $530 million committed amount, of which 3.0% was paid in cash and 1.0% was paid in the form of Class A common stock at the discounted per share price set forth in the Backstop Commitment Agreement.
On the Effective Date, all conditions to the rights offerings and the Backstop Commitment Agreement were met, and the LINN Debtors completed the rights offerings and the related issuances of Class A common stock.
Liabilities Subject to Compromise
The Predecessor’s condensed consolidated balance sheet as of December 31, 2016, includes amounts classified as “liabilities subject to compromise,” which represent prepetition liabilities that were allowed, or that the Company estimated would be allowed, as claims in its Chapter 11 cases. The following table summarizes the components of liabilities subject to compromise included on the condensed consolidated balance sheet:
| | | | | | | Predecessor | | | December 31, 2016 | | | (in thousands) | | | | | Accounts payable and accrued expenses | $ | 137,692 |
| | Accrued interest payable | 144,184 |
| | Debt | 4,023,129 |
| | Liabilities subject to compromise | $ | 4,305,005 |
|
Reorganization Items, Net
The Company incurred significant costs and recognized significant gains associated with the reorganization. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined. The following tables summarize the components of reorganization items included on the condensed consolidated statements of operations:
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
:
| | | | | | | | | | | | Successor | | | Predecessor | | | Three Months Ended September 30, 2017 | | | Three Months Ended September 30, 2016 | | (in thousands) | | | | | | Legal and other professional advisory fees | $ | (2,549 | ) | | | $ | (16,714 | ) | | Terminated contracts | — |
| | | (13,123 | ) | | Other | (56 | ) | | | 1,476 |
| | Reorganization items, net | $ | (2,605 | ) | | | $ | (28,361 | ) |
| | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, 2018 | | Nine Months Ended September 30, 2018 | | | Under ASC 606 | Under ASC 605 | Increase/ (decrease) | | Under ASC 606 | Under ASC 605 | Increase/ (decrease) | | | (in thousands) | | Revenues | | | | | | | | Oil sales | $ | 74,987 |
| $ | 75,062 |
| $ | (75 | ) | | $ | 197,356 |
| $ | 197,431 |
| $ | (75 | ) | | Natural gas sales | $ | 18,059 |
| $ | 21,739 |
| $ | (3,680 | ) | | $ | 48,956 |
| $ | 60,919 |
| $ | (11,963 | ) | | Natural gas liquid sales | $ | 27,106 |
| $ | 35,195 |
| $ | (8,089 | ) | | $ | 65,377 |
| $ | 83,735 |
| $ | (18,358 | ) | | | | | | | | | | Operating expenses | | | | | | | | Gathering, transportation and processing | $ | — |
| $ | 11,844 |
| $ | (11,844 | ) | | $ | — |
| $ | 30,396 |
| $ | (30,396 | ) | | | | | | | | | | Net loss | $ | (301,240 | ) | $ | (301,240 | ) | $ | — |
| | $ | (288,916 | ) | $ | (288,916 | ) | $ | — |
|
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | Gain on settlement of liabilities subject to compromise | $ | — |
| | | $ | 3,724,750 |
| | $ | — |
| | Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement | — |
| | | (1,000,000 | ) | | — |
| | Fresh start valuation adjustments | — |
| | | (591,525 | ) | | — |
| | Income tax benefit related to implementation of the Plan | — |
| | | 264,889 |
| | — |
| | Legal and other professional advisory fees | (8,565 | ) | | | (46,961 | ) | | (30,165 | ) | | Unamortized deferred financing fees, discounts and premiums | — |
| | | — |
| | (52,045 | ) | | Gain related to interest payable on Predecessor’s Second Lien Notes | — |
| | | — |
| | 551,000 |
| | Terminated contracts | — |
| | | (6,915 | ) | | (13,123 | ) | | Other | 18 |
| | | (13,049 | ) | | 1,770 |
| | Reorganization items, net | $ | (8,547 | ) | | | $ | 2,331,189 |
| | $ | 457,437 |
|
Note 3 – Fresh Start Accounting
Upon the Company’s emergence from Chapter 11 bankruptcy, it adopted fresh start accounting in accordance with the provisions of ASC 852 which resulted in the Company becoming a new entity for financial reporting purposes. In accordance with ASC 852, the Company was required to adopt fresh start accounting upon its emergence from Chapter 11 because (i) the holders of existing voting ownership interests of the Predecessor received less than 50% of the voting shares of the Successor and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims.
Upon adoption of fresh start accounting, the reorganization value derived from the enterprise value as disclosed in the Plan was allocated to the Company’s assets and liabilities based on their fair values (except for deferred income taxes) in accordance with ASC 805 “Business Combinations” (“ASC 805”). The amount of deferred income taxes recorded was determined in accordance with ASC 740 “Income Taxes” (“ASC 740”). The Effective Date fair values of the Company’s assets and liabilities differed materially from their recorded values as reflected on the historical balance sheet. The effects of the Plan and the application of fresh start accounting were reflected on the condensed consolidated balance sheet as of February 28, 2017, and the related adjustments thereto were recorded on the condensed consolidated statement of operations for the two months ended February 28, 2017.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the Company’s condensed consolidated financial statements subsequent to February 28, 2017, are not comparable to its condensed consolidated financial statements prior to February 28, 2017. References to “Successor” relate to the financial position and results of operations of the reorganized Company as of and subsequent to February 28, 2017. References to “Predecessor” relate to the financial position of the Company prior to, and results of operations through and including, February 28, 2017.
The Company’s condensed consolidated financial statements and related footnotes are presented with a black line division, which delineates the lack of comparability between amounts presented after February 28, 2017, and amounts presented on or prior to February 28, 2017. The Company’s financial results for future periods following the application of fresh start accounting will be different from historical trends and the differences may be material.
Reorganization Value
Under ASC 852, the Successor determined a value to be assigned to the equity of the emerging entity as of the date of adoption of fresh start accounting. The Plan confirmed by the Bankruptcy Court estimated an enterprise value of $2.35 billion. The Plan enterprise value was prepared using an asset based methodology, as discussed further below. The enterprise value was then adjusted to determine the equity value of the Successor of approximately $2.03 billion. Adjustments to determine the equity value are presented below (in thousands):
| | | | | | Plan confirmed enterprise value | $ | 2,350,000 |
| | Fair value of debt | (900,000 | ) | | Fair value of subsequently determined tax attributes | 621,486 |
| | Fair value of vested Class B units | (36,505 | ) | | Value of Successor’s stockholders’ equity | $ | 2,034,981 |
|
The subsequently determined tax attributes were primarily the result of the conversion from a limited liability company to a C corporation and differences in the accounting basis and tax basisMost of the Company’s oil contracts transfer physical custody and title at or near the wellhead, which is commonly when control of the oil has been transferred to the purchaser. The Company’s oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price. Any differentials incurred after the transfer of control of the oil are net against oil sales as they represent part of the transaction price of the contract. For its oil contracts, the Company generally records its sales based on the net amount received.
Natural Gas and NGL Sales
Most of the Company’s natural gas properties asis sold at the wellhead or inlet to the processor’s facility, which is commonly when control of the Effective Date.natural gas has been transferred to the purchaser. The Class B unitsnatural gas is sold under percentage of proceeds processing contracts. Under these contracts, the purchaser gathers the natural gas where it is produced and transports it via pipeline to natural gas processing plants where NGL products are incentive interest awards that were granted onextracted. The NGL products and remaining residue gas are then sold by the Effective Date by Holdco to certain memberspurchaser. Under the natural gas percentage of its management (see Note 14),proceeds contracts, the Company receives a percentage of the value for the extracted NGLs and the associated fair value was recorded asresidue gas.
For its natural gas processing contracts, the Company generally records its natural gas and NGL sales net of gathering, processing and transportation expenses based on a liability of approximately $7 million in “other accrued liabilities” and temporary equity of approximately $29 million in “redeemable noncontrolling interests” on the condensed consolidated balance sheet at February 28, 2017.principal versus agent assessment for individual contracts.
Performance Obligations
The Company’s principal assets areCompany satisfies the performance obligations under its oil and natural gas properties. The fair valuessales contracts through delivery of oilits production and natural gas properties were estimated using valuation techniques consistent with the income approach, converting future cash flowstransfer of control to a single discounted amount. Significant inputs usedcustomer. Upon delivery of production, the Company
Roan Resources, Inc. Notes to determine the fair values of properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. See below under “Fresh Start Adjustments” for additional information regarding assumptions used in the valuation of the Company's various other significant assets and liabilities.
Unaudited Condensed Consolidated Balance Sheet The adjustments included in the following fresh start condensed consolidated balance sheet reflect the effects of the transactions contemplated by the Plan and executed by the Company on the Effective Date (reflected in the column “Reorganization Adjustments”) as well as fair value and other required accounting adjustments resulting from the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine the fair values and significant assumptions.Financial Statements
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | As of February 28, 2017 | | | Predecessor | | Reorganization Adjustments (1) | | | Fresh Start Adjustments | | | Successor | | | (in thousands) | | ASSETS | | | | | | | | | | | Current assets: | | | | | | | | | | | Cash and cash equivalents | $ | 734,166 |
| | $ | (679,811 | ) | (2) | | $ | — |
| | | $ | 54,355 |
| | Accounts receivable – trade, net | 212,099 |
| | — |
| | | (7,808 | ) | (16) | | 204,291 |
| | Derivative instruments | 15,391 |
| | — |
| | | — |
| | | 15,391 |
| | Restricted cash | 1,602 |
| | 80,164 |
| (3) | | — |
| | | 81,766 |
| | Other current assets | 106,426 |
| | (15,983 | ) | (4) | | 1,780 |
| (17) | | 92,223 |
| | Total current assets | 1,069,684 |
| | (615,630 | ) | | | (6,028 | ) | | | 448,026 |
| | | | | | | | | | | | | Noncurrent assets: | | | | | | | | | | | Oil and natural gas properties (successful efforts method) | 13,269,035 |
| | — |
| | | (11,082,258 | ) | (18) | | 2,186,777 |
| | Less accumulated depletion and amortization | (10,044,240 | ) | | — |
| | | 10,044,240 |
| (18) | | — |
| | | 3,224,795 |
| | — |
| | | (1,038,018 | ) | | | 2,186,777 |
| | | | | | | | | | | | | Other property and equipment | 641,586 |
| | — |
| | | (197,653 | ) | (19) | | 443,933 |
| | Less accumulated depreciation | (230,952 | ) | | — |
| | | 230,952 |
| (19) | | — |
| | | 410,634 |
| | — |
| | | 33,299 |
| | | 443,933 |
| | | | | | | | | | | | | Derivative instruments | 4,492 |
| | — |
| | | — |
| | | 4,492 |
| | Deferred income taxes | — |
| | 264,889 |
| (5) | | 356,597 |
| (5) | | 621,486 |
| | Other noncurrent assets | 15,003 |
| | 151 |
| (6) | | 8,139 |
| (20) | | 23,293 |
| | | 19,495 |
| | 265,040 |
| | | 364,736 |
| | | 649,271 |
| | Total noncurrent assets | 3,654,924 |
| | 265,040 |
| | | (639,983 | ) | | | 3,279,981 |
| | Total assets | $ | 4,724,608 |
| | $ | (350,590 | ) | | | $ | (646,011 | ) | | | $ | 3,728,007 |
| | | | | | | | | | | | | LIABILITIES AND EQUITY (DEFICIT) | | | | | | | | | | Current liabilities: | | | | | | | | | | | Accounts payable and accrued expenses | $ | 324,585 |
| | $ | 41,266 |
| (7) | | $ | (2,351 | ) | (21) | | $ | 363,500 |
| | Derivative instruments | 7,361 |
| | — |
| | | — |
| | | 7,361 |
| | Current portion of long-term debt, net | 1,937,822 |
| | (1,912,822 | ) | (8) | | — |
| | | 25,000 |
| | Other accrued liabilities | 41,251 |
| | (1,026 | ) | (9) | | 1,104 |
| (22) | | 41,329 |
| | Total current liabilities | 2,311,019 |
| | (1,872,582 | ) | | | (1,247 | ) | | | 437,190 |
| | | | | | | | | | | | | Derivative instruments | 2,116 |
| | — |
| | | — |
| | | 2,116 |
| | Long-term debt | — |
| | 875,000 |
| (10) | | — |
| | | 875,000 |
| | Other noncurrent liabilities | 402,776 |
| | (167 | ) | (11) | | (53,239 | ) | (23) | | 349,370 |
| | Liabilities subject to compromise | 4,301,912 |
| | (4,301,912 | ) | (12) | | — |
| | | — |
| | | | | | | | | | | | | Temporary equity: | | | | | | | | | | | Redeemable noncontrolling interests | — |
| | 29,350 |
| (13) | | — |
| | | 29,350 |
|
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
one year or less. For those contracts, the Company utilized the practical expedient in ASC 606, which provides an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
| | | | | | | | | | | | | | | | | | | | | As of February 28, 2017 | | | Predecessor | | Reorganization Adjustments (1) | | | Fresh Start Adjustments | | | Successor | | Stockholders’/unitholders’ equity (deficit): | | | | | | | | | | | Predecessor units issued and outstanding | 5,386,812 |
| | (5,386,812 | ) | (14) | | — |
| | | — |
| | Predecessor accumulated deficit | (7,680,027 | ) | | 2,884,740 |
| (15) | | 4,795,287 |
| (24) | | — |
| | Successor Class A common stock | — |
| | 89 |
| (14) | | — |
| | | 89 |
| | Successor additional paid-in capital | — |
| | 7,421,704 |
| (14) | | (5,386,812 | ) | (24) | | 2,034,892 |
| | Successor retained earnings | — |
| | — |
| | | — |
| | | — |
| | Total stockholders’/unitholders’ equity (deficit) | (2,293,215 | ) | | 4,919,721 |
| | | (591,525 | ) | | | 2,034,981 |
| | Total liabilities and equity (deficit) | $ | 4,724,608 |
| | $ | (350,590 | ) | | | $ | (646,011 | ) | | | $ | 3,728,007 |
|
Reorganization Adjustments:
| | 1) | Represent amounts recorded as of the Effective Date for the implementation of the Plan, including, among other items, settlement of the Predecessor’s liabilities subject to compromise, repayment of certain of the Predecessor’s debt, cancellation of the Predecessor’s equity, issuances of the Successor’s Class A common stock, proceeds received from the Successor’s rights offerings and issuance of the Successor’s debt. |
| | 2) | Changes in cash and cash equivalents included the following: |
| | | | | | (in thousands) | | | Borrowings under the Successor’s revolving loan | $ | 600,000 |
| | Borrowings under the Successor’s term loan | 300,000 |
| | Proceeds from rights offerings | 530,019 |
| | Removal of restriction on cash balance | 1,602 |
| | Payment to holders of claims under the Predecessor Credit Facility | (1,947,357 | ) | | Payment to holders of claims under the Second Lien Notes | (30,000 | ) | | Payment of Berry’s ad valorem taxes | (23,366 | ) | | Payment of the rights offerings backstop commitment premium | (15,900 | ) | | Payment of professional fees | (13,043 | ) | | Funding of the professional fees escrow account | (41,766 | ) | | Funding of the general unsecured claims cash distribution pool | (40,000 | ) | | Changes in cash and cash equivalents | $ | (679,811 | ) |
| | 3) | Primarily reflects the transfer to restricted cash to fund the Predecessor’s professional fees escrow account and general unsecured claims cash distribution pool. |
| | 4) | Primarily reflects the write-off of the Predecessor’s deferred financing fees. |
| | 5) | Reflects deferred tax assets recorded as of the Effective Date as determined in accordance with ASC 740. The deferred tax assets were primarily the result of the conversion from a limited liability company to a C corporation and differences in the accounting basis and tax basis of the Company’s oil and natural gas properties as of the Effective Date. |
| | 6) | Reflects the capitalization of deferred financing fees related to the Successor’s revolving loan. |
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
| | 7) | Net increase in accounts payable and accrued expenses reflects: |
| | | | | | (in thousands) | | | Recognition of payables for the professional fees escrow account | $ | 41,766 |
| | Recognition of payables for the general unsecured claims cash distribution pool | 40,000 |
| | Payment of professional fees | (17,130 | ) | | Payment of Berry’s ad valorem taxes | (23,366 | ) | | Other | (4 | ) | | Net increase in accounts payable and accrued expenses | $ | 41,266 |
|
| | 8) | Reflects the settlement of the Predecessor Credit Facility through repayment of approximately $1.9 billion, net of the write-off of deferred financing fees and an increase of $25 million for the current portion of the Successor’s term loan. |
| | 9) | Reflects a decrease of approximately $8 million for the payment of accrued interest on the Predecessor Credit Facility partially offset by an increase of approximately $7 million related to noncash share-based compensation classified as a liability related to the incentive interest awards issued by Holdco to certain members of its management (see Note 14). |
| | 10) | Reflects borrowings of $900 million under the Successor Credit Facility, which includes a $600 million revolving loan and a $300 million term loan, net of $25 million for the current portion of the Successor’s term loan. |
| | 11) | Reflects a reduction in deferred tax liabilities as determined in accordance with ASC 740. |
| | 12) | Settlement of liabilities subject to compromise and the resulting net gain were determined as follows: |
| | | | | | (in thousands) | | | Accounts payable and accrued expenses | $ | 134,599 |
| | Accrued interest payable | 144,184 |
| | Debt | 4,023,129 |
| | Total liabilities subject to compromise | 4,301,912 |
| | Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement | 1,000,000 |
| | Funding of the general unsecured claims cash distribution pool | (40,000 | ) | | Payment to holders of claims under the Second Lien Notes | (30,000 | ) | | Issuance of Class A common stock to creditors | (1,507,162 | ) | | Gain on settlement of liabilities subject to compromise | $ | 3,724,750 |
|
| | 13) | Reflects redeemable noncontrolling interests classified as temporary equity related to the incentive interest awards issued by Holdco to certain members of its management. See Note 14 for additional information. |
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
| | 14) | Net increase in capital accounts reflects: |
| | | | | | (in thousands) | | | Issuance of Class A common stock to creditors | $ | 1,507,162 |
| | Issuance of Class A common stock pursuant to the rights offerings | 530,019 |
| | Payment of the rights offerings backstop commitment premium | (15,900 | ) | | Payment of issuance costs | (50 | ) | | Share-based compensation expenses | 13,750 |
| | Cancellation of the Predecessor’s units issued and outstanding | 5,386,812 |
| | Par value of Class A common stock | (89 | ) | | Change in additional paid-in capital | 7,421,704 |
| | Par value of Class A common stock | 89 |
| | Predecessor’s units issued and outstanding | (5,386,812 | ) | | Net increase in capital accounts | $ | 2,034,981 |
|
See Note 12 for additional information on the issuances of the Successor’s equity.
| | 15) | Net decrease in accumulated deficit reflects: |
| | | | | | (in thousands) | | | Recognition of gain on settlement of liabilities subject to compromise | $ | 3,724,750 |
| | Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement | (1,000,000 | ) | | Recognition of professional fees | (37,680 | ) | | Write-off of deferred financing fees | (16,728 | ) | | Recognition of deferred income taxes | 264,889 |
| | Total reorganization items, net | 2,935,231 |
| | Share-based compensation expenses | (50,255 | ) | | Other | (236 | ) | | Net decrease in accumulated deficit | $ | 2,884,740 |
|
Fresh Start Adjustments:
| | 16) | Reflects a change in accounting policy from the entitlements method to the sales method for natural gas production imbalances. |
| | 17) | Reflects the recognition of intangible assets for the current portion of favorable leases, partially offset by decreases for well equipment inventory and the write-off of historical intangible assets. |
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
| | 18) | Reflects a decrease of oil and natural gas properties, based on the methodology discussed above, and the elimination of accumulated depletion and amortization. The following table summarizes the components of oil and natural gas properties as of the Effective Date: |
| | | | | | | | | | | | Successor | | | Predecessor | | | Fair Value | | | Historical Book Value | | (in thousands) | | | | | | Proved properties | $ | 1,727,834 |
| | | $ | 12,258,835 |
| | Unproved properties | 458,943 |
| | | 1,010,200 |
| | | 2,186,777 |
| | | 13,269,035 |
| | Less accumulated depletion and amortization | — |
| | | (10,044,240 | ) | | | $ | 2,186,777 |
| | | $ | 3,224,795 |
|
| | 19) | Reflects a decrease of other property and equipment and the elimination of accumulated depreciation. The following table summarizes the components of other property and equipment as of the Effective Date: |
| | | | | | | | | | | | Successor | | | Predecessor | | | Fair Value | | | Historical Book Value | | (in thousands) | | | | | | Natural gas plants and pipelines | $ | 342,924 |
| | | $ | 426,914 |
| | Office equipment and furniture | 39,211 |
| | | 106,059 |
| | Buildings and leasehold improvements | 32,817 |
| | | 66,023 |
| | Vehicles | 16,980 |
| | | 30,760 |
| | Land | 7,747 |
| | | 3,727 |
| | Drilling and other equipment | 4,254 |
| | | 8,103 |
| | | 443,933 |
| | | 641,586 |
| | Less accumulated depreciation | — |
| | | (230,952 | ) | | | $ | 443,933 |
| | | $ | 410,634 |
|
In estimating the fair value of other property and equipment, the Company used a combination of cost and market approaches. A cost approach was used to valueFor the Company’s natural gas plants and pipelinesNGL sales contracts that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606 which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and other operating assets, based on current replacement costsdisclosure of the assets less depreciation based on the estimated economic useful lives of the assets and age of the assets. A market approach was usedtransaction price allocated to value the Company’s vehicles and land, using recent transactions of similar assets to determine the fair value from a market participant perspective.
| | 20) | Reflects the recognition of intangible assets for the noncurrent portion of favorable leases, as well as increases in equity method investments and carbon credit allowances. Assets and liabilities for out-of-market contracts were valued based on market terms as of February 28, 2017, and will be amortized over the remaining life of the respective lease. The Company’s equity method investments were valued based on a market approach using a market EBITDA multiple. Carbon credit allowances were valued using a market approach based on trading prices for carbon credits on February 28, 2017. |
| | 21) | Primarily reflects the write-off of deferred rent partially offset by an increase in carbon emissions liabilities. |
| | 22) | Reflects an increase of the current portion of asset retirement obligations. |
| | 23) | Primarily reflects a decrease of approximately $49 million for asset retirement obligations and approximately $5 million for deferred rent, partially offset by an increase of approximately $1 million for carbon emissions liabilities. The fair value of asset retirement obligations were estimated using valuation techniques that convert future cash flows to a single |
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
remaining performance obligations is not required.
discounted amount. Significant inputs to the valuation include estimates of: (i) plugContract Balances
The Company recognizes sales of oil, natural gas, and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors;NGLs at a point in time when it satisfies a performance obligation and (iv) a credit-adjusted risk-free interest rate. Carbon emissions liabilities were valued using a market approach based on trading prices for carbon credits on February 28, 2017. | | 24) | Reflects the cumulative impact of the fresh start accounting adjustments discussed above and the elimination of the Predecessor’s accumulated deficit. |
Note 4 – Discontinued Operations, Other Divestitures and Roan Contribution
Discontinued Operations
On July 31, 2017,at that point the Company completedhas an unconditional right to receive payment. Accordingly, these contracts do not give rise to contract assets or contract liabilities under ASC 606. The Company had accounts receivable related to revenue from contracts with customers of approximately $62.1 million as of September 30, 2018, which represent this unconditional right to receive payment.
Prior Period Performance Obligations
To record revenues for oil, natural gas and NGLs, the saleCompany estimates the amount of its interest in properties locatedproduction delivered at the end of each month and the prices expected to be received for those sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the San Joaquin Basin in California to Berry Petroleum Company, LLC (the “San Joaquin Basin Sale”). Cash proceedsmonth payment is received from the sale of these properties were approximately $253 million, net of costs to sell of approximately $4 million, andcustomer. For the Company recognized a net gain of approximately $120 million. The gain is included in “income (loss) from discontinued operations, net of income taxes” on the condensed consolidated statements of operations. On July 21, 2017, the Company completed the sale of its interest in properties located in the Los Angeles Basin in California to Bridge Energy LLC (the “Los Angeles Basin Sale”). Cash proceeds received from the sale of these properties were approximately $93 million, net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $2 million. The gain is included in “income (loss) from discontinued operations, net of income taxes” on the condensed consolidated statements of operations. The Company will receive an additional $7 million contingent payment if certain operational requirements are satisfied within one year.
As a result of the Company’s strategic exit from California (completed by the San Joaquin Basin Sale and Los Angeles Basin Sale), the Company classified the assets and liabilities, results of operations and cash flows of its California properties as discontinued operations on its condensed consolidated financial statements.
On December 3, 2016, LINN Energy filed an amended plan of reorganization that excluded Berry (see Note 2). As a result of its loss of control of Berry, LINN Energy concluded that it was appropriate to deconsolidate Berry effective on the aforementioned date and classified it as discontinued operations.
The following table presents carrying amounts of the assets and liabilities of the Company’s California properties classified as discontinued operations on the condensed consolidated balance sheet: | | | | | | | Predecessor | | | December 31, 2016 | | (in thousands) | | | Assets: | | | Oil and natural gas properties | $ | 728,190 |
| | Other property and equipment | 11,402 |
| | Other | 1,435 |
| | Total assets of discontinued operations | $ | 741,027 |
| | Liabilities: | | | Asset retirement obligations | $ | 38,042 |
| | Other | 1,481 |
| | Total liabilities of discontinued operations | $ | 39,523 |
|
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
All balances of discontinued operations on the condensed consolidated balance sheet relate to the Company’s California properties, as Berry was deconsolidated effective December 3, 2016.
The following tables present summarized financial results of the Company’s California properties and Berry classified as discontinued operations on the condensed consolidated statements of operations:
| | | | | | | | | | | | Successor | | | Predecessor | | | Three Months Ended September 30, 2017 | | | Three Months Ended September 30, 2016 | | (in thousands) | | | | | | Revenues and other | $ | 6,048 |
| | | $ | 133,163 |
| | Expenses | (11,113 | ) | | | 132,387 |
| | Other income and (expenses) | (750 | ) | | | (14,891 | ) | | Reorganization items, net | — |
| | | (87,915 | ) | | Income (loss) from discontinued operations before income taxes | 16,411 |
| | | (102,030 | ) | | Income tax expense | 6,347 |
| | | 34 |
| | Income (loss) from discontinued operations, net of income taxes | $ | 10,064 |
| | | $ | (102,064 | ) |
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | Revenues and other | $ | 33,684 |
| | | $ | 14,891 |
| | $ | 369,112 |
| | Expenses | 19,231 |
| | | 13,758 |
| | 1,507,867 |
| | Other income and (expenses) | (3,541 | ) | | | (1,681 | ) | | (54,361 | ) | | Reorganization items, net | — |
| | | — |
| | (38,829 | ) | | Income (loss) from discontinued operations before income taxes | 10,912 |
| | | (548 | ) | | (1,231,945 | ) | | Income tax expense | 4,102 |
| | | — |
| | 196 |
| | Income (loss) from discontinued operations, net of income taxes | $ | 6,810 |
| | | $ | (548 | ) | | $ | (1,232,141 | ) |
In addition, for the three months and seven months ended September 30, 2017, the Company recognized a net gain on the sale of the California properties of approximately $76 million (net of income tax expense of approximately $46 million).
Results of operations of Berry are only included in the three months and nine months ended September 30, 2016, as Berry2018, revenue recognized related to performance obligations satisfied in prior reporting periods was deconsolidated effective December 3, 2016. Other income and (expenses) include an allocation of interest expense for the California properties of approximately $1 million and $2 million for the three months ended September 30, 2017, and September 30, 2016, respectively, and approximately $4 million, $2 million and $6 million for the seven months ended September 30, 2017, the two months ended February 28, 2017, and the nine months ended September 30, 2016, respectively, which represents interest on debt that was required to be repaid as a result of the sales.
Berry Transition Services and Separation Agreement
On the Effective Date, Berry entered into a Transition Services and Separation Agreement (the “TSSA”) with LINN Energy and certain of its subsidiaries to facilitate the separation of Berry’s operations from LINN Energy’s operations. Pursuant to the TSSA, LINN Energy continued to provide, or caused to be provided, certain administrative, management, operating, and other services and support to Berry during a transitional period following the Effective Date (the “Transition Services”).not material.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTSNote 4 – Continued
(Unaudited)
Acquisitions
Under the TSSA, Berry reimbursed LINN Energy for anyLinn Acquisition
As noted in Note 1 – Business and all reasonable, third-party out-of-pocket costs and expenses, without markup, actually incurred by LINN Energy, to the extent documented,Organization, in connection with providing the Transition Services. Additionally, Berry paid to LINN Energy a management fee of $6 million per month, prorated for partial months, during the periodContribution, Roan LLC acquired from the Effective Date through the last day of the second full calendar month after the Effective Date (the “Transition Period”)Linn certain oil and paid $2.7 million per month, prorated for partial months, from the first day following the Transition Period through the last day of the second full calendar month thereafter (the “Accounting Period”). During the Accounting Period, the scope of the Transition Services was reduced to specified accounting and administrative functions. The Transition Period ended April 30, 2017, and the Accounting Period ended June 30, 2017. Other Divestitures
On September 12, 2017, August 1, 2017, and July 31, 2017, the Company completed the sales of its interest in certainnatural gas properties located in south TexasCentral Oklahoma (the “South Texas Assets Sales”“Linn Acquisition”). Combined cash proceeds received from the sale of these properties were approximately $49 million, net of costs to sell of approximately $1 million, and the Company recognized a combined net gain of approximately $14 million.
On August 23, 2017, July 28, 2017, and May 9, 2017, the Company completed the sales of its interest in certain properties located in Texas and New Mexico (the “Permian Assets Sales”). Combined cash proceeds received from the sale of these properties were approximately $31 million and the Company recognized a combined net gain of approximately $29 million.
On June 30, 2017, the Company completed the sale of its interest in properties located in the Salt Creek Field in Wyoming to Denbury Resources Inc. (the “Salt Creek Assets Sale”). Cash proceeds received from the sale of these properties were approximately $75 million, net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $33 million.
On May 31, 2017, the Company completed the sale of its interest in properties located in western Wyoming to Jonah Energy LLC (the “Jonah Assets Sale”). Cash proceeds received from the sale of these properties were approximately $560 million, net of costs to sell of approximately $6 million, and the Company recognized a net gain of approximately $272 million.
The divestitures discussed above are not presented as discontinued operations because they do not represent a strategic shift that will have a major effect on the Company’s operations and financial results. The gains on these divestitures are included in “gains (losses) on sale of assets and other, net” on the condensed consolidated statements of operations.
Divestitures – Pending
On October 20, 2017, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its interest in properties located in the Williston Basin for a contract price of $285 million, subject to closing adjustments.
On October 3, 2017, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its interest in properties located in Wyoming for a contract price of $200 million, subject to closing adjustments.
The sales are anticipated to close on November 30, 2017, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
Roan Contribution
On August 31, 2017, the Company, through certain of its subsidiaries, completed the transaction in which LINN Energy and Citizen Energy II, LLC (“Citizen”) each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan Resources LLC (“Roan” and the contribution, the “Roan Contribution”), focused on the accelerated development of the Merge/SCOOP/STACK play. In exchange for their respective contributions, LINN Energythe contributed oil and Citizen eachnatural gas properties, Linn received a 50% equity interest in Roan subjectLLC valued at approximately $1.3 billion based on the value of the business. Accordingly, the fair value of the Company was primarily comprised of the fair value of these contributed oil and natural gas properties. See Note 10 – Equity for further discussion of the equity issued to customary post-closing adjustments. AsLinn.
Roan Resources, Inc. Notes to Unaudited Condensed Consolidated Financial Statements
Because the Linn Acquisition was determined to be a business combination as the acquired oil and natural gas properties met the definition of a business, the acquired assets and liabilities were recorded at fair value as of August 31, 2017, the dateacquisition date. The following assumptions were used to determine the fair value of the Roan Contribution, the Company recognized its equity investment at a carryover basis of approximately $452 million. In connection with the Roan Contribution, the Company paid approximately $17 million in advisory fees, which are included in “gains (losses) on sale of assetsoil and other, net” on the condensed consolidated statements of operations. See Note 6 for additional information about the Company’s equity method investment in Roan.natural gas properties:
| | | | | 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 |
The following table summarizes the purchase price and allocation of the fair values of assets acquired and liabilities assumed (in thousands):
| | | | | | 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 |
|
The following unaudited pro forma combined results of operations is provided for the three and nine months ended September 30, 2017 as though the Linn Acquisition had been completed as of the earliest period presented at the time of the acquisition. The pro forma combined results of operations have been prepared by adjusting the historical results of the Company to include the historical results of the assets acquired in the Linn Acquisition.
Roan Resources, Inc. Notes to Unaudited Condensed Consolidated Financial Statements
These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Linn Acquisition or any estimated costs incurred to integrate the Linn Acquisition. | | | | | | | | | | | Three Months Ended
September 30, 2017 | | Nine Months Ended
September 30, 2017 | | | (in thousands) | | Revenue | $ | 55,119 |
| | $ | 156,593 |
| | Net income | $ | 17,052 |
| | $ | 55,253 |
|
Acquisitions of Unproved Properties
During the year ended December 31, 2017, the Company acquired, from unrelated third parties, interests in approximately 23,400 net acres of leasehold in separately negotiated transactions for aggregate cash consideration of $49.7 million, all of which were accounted for as asset acquisitions and recorded as additions to unproved oil and natural gas properties.
As discussed in Note 12 –Transactions with Affiliates, Citizen and Linn acquired acreage during 2017 on behalf of Roan LLC for $63.0 million, which was included in accounts payable and accrued liabilities – affiliates at December 31, 2017. In March 2018, Roan LLC paid Linn $22.9 million in cash and issued equity units to both Citizen and Linn to settle the amount due. LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Note 5 – Oil and Natural Gas Properties Oil and Natural Gas Capitalized Costs
As a result of the application of fresh start accounting, the Company recorded its oil and natural gas properties at fair value as of the Effective Date. The fair values ofCompany’s oil and natural gas properties are estimated using valuation techniques consistent within the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved and unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.continental United States. The fair value was estimated using inputs characteristic of a Level 3 fair value measurement. Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:
| | | | | | | | | | | | Successor | | | Predecessor | | | September 30, 2017 | | | December 31, 2016 | | (in thousands) | | | | | | Proved properties | $ | 1,188,652 |
| | | $ | 11,350,257 |
| | Unproved properties | 59,594 |
| | | 998,860 |
| | | 1,248,246 |
| | | 12,349,117 |
| | Less accumulated depletion and amortization | (53,370 | ) | | | (9,843,908 | ) | | | $ | 1,194,876 |
| | | $ | 2,505,209 |
|
Impairment of Proved Properties
The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate thatinclude the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value.following:
Based on the analysis described above, for the three months and nine months ended September 30, 2016, the Company recorded impairment charges of approximately $42 million and $165 million, respectively, associated with proved oil and natural gas properties in the Mid-Continent and Rockies regions due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the condensed consolidated statements of operations.
| | | | | | | | | | | September 30, 2018 | | December 31, 2017 | | | (in thousands) | | Oil and natural gas properties | | | | | Proved | $ | 1,276,950 |
| | $ | 750,492 |
| | Unproved | 1,152,942 |
| | 1,126,459 |
| | Less: accumulated depreciation, depletion, amortization and impairment | (183,557 | ) | | (78,307 | ) | | Oil and natural gas properties, net | $ | 2,246,335 |
| | $ | 1,798,644 |
|
The Company recorded no impairment charges for the nine months ended September 30, 2017. Note 6 – Equity Method Investments
On August 31, 2017, the Company completed the transaction in which LINN Energy and Citizen each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan, focuseddepletion expense on the accelerated development of the Merge/SCOOP/STACK play. See Note 4 for additional information.
The Company uses the equity method of accounting for its investment in Roan. The Company’s equity earnings (losses) consists of its share of Roan’s earnings or losses and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets. At both September 30, 2017, and August 31, 2017 (the date of the Roan Contribution), the Company owned 50% of Roan’s outstanding units. The percentage ownership in Roan is subject to customary post-closing adjustments.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
At September 30, 2017, the carrying amount of the Company’s investment in Roan of approximately $454 million was less than the Company’s ownership interest in Roan’s underlying net assets by approximately $344 million. The difference is attributable to proved and unproved oil and natural gas properties and is amortized over the lives of the related assets. Such amortization is included in the equity earnings (losses) from the Company’s investment in Roan.
Impairment testing on the Company’s investment in Roan is performed when events or circumstances warrant such testing and considers whether there is an inability to recover the carrying value of the investment that is other than temporary. No impairments occurred with respect to the Company’s investment in Roan for the one month ended September 30, 2017.
Following is summarized statement of operations information for Roan.
Summarized Roan Resources LLC Statement of Operations Information
| | | | | | | One Month Ended September 30, 2017 | | | (in thousands) | | | | | Revenues | $ | 16,819 |
| | Expenses | 12,145 |
| | Other income and (expenses) | (160 | ) | | Net income | $ | 4,514 |
|
Note 7 – Debt
The following summarizes the Company’s outstanding debt:
| | | | | | | | | | | Successor | | | Predecessor | | September 30, 2017 | | | December 31, 2016 | (in thousands, except percentages) | | | | | Revolving credit facility | $ | — |
| | | $ | — |
| Predecessor credit facility (1)
| — |
| | | 1,654,745 |
| Predecessor term loan (1)
| — |
| | | 284,241 |
| 6.50% senior notes due May 2019 | — |
| | | 562,234 |
| 6.25% senior notes due November 2019 | — |
| | | 581,402 |
| 8.625% senior notes due April 2020 | — |
| | | 718,596 |
| 12.00% senior secured second lien notes due December 2020 | — |
| | | 1,000,000 |
| 7.75% senior notes due February 2021 | — |
| | | 779,474 |
| 6.50% senior notes due September 2021 | — |
| | | 381,423 |
| Net unamortized deferred financing fees | — |
| | | (1,257 | ) | Total debt, net | — |
| | | 5,960,858 |
| Less current portion, net (2)
| — |
| | | (1,937,729 | ) | Less liabilities subject to compromise (3)
| — |
| | | (4,023,129 | ) | Long-term debt | $ | — |
| | | $ | — |
|
| | (1)
| Variable interest rate of 5.50%at December 31, 2016.
|
| | (2)
| Due to covenant violations, the Predecessor’s credit facility and term loan were classified as current at December 31, 2016. |
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
| | (3)
| The Predecessor’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016. On the Effective Date, pursuant to the terms of the Plan, all outstanding amounts under these debt instruments were canceled. |
Fair Value
The Company’s debt is recorded at the carrying amount on the condensed consolidated balance sheets. The carrying amounts of the credit facilities and term loans approximate fair value because the interest rates are variable and reflective of market rates. The Company used a market approach to determine the fair value of the Predecessor’s Second Lien Notes and senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement.
| | | | | | | | | | | Predecessor | | | December 31, 2016 | | | Carrying Value | | Fair Value | | | (in thousands) | | | | | | | Senior secured second lien notes | $ | 1,000,000 |
| | $ | 863,750 |
| | Senior notes, net | 3,023,129 |
| | 1,179,224 |
|
Revolving Credit Facility
On August 4, 2017, the Company entered into a credit agreement with Holdco II, as borrower, Royal Bank of Canada, as administrative agent, and the lenders and agents party thereto, providing for a new senior secured reserve-based revolving loan facility (the “Revolving Credit Facility”) with $500 million in borrowing commitments and an initial borrowing base of $500 million.
As of September 30, 2017, there were no borrowings outstanding under the Revolving Credit Facility and there was approximately $455 million of available borrowing capacity (which includes a $45 million reduction for outstanding letters of credit). The maturity date is August 4, 2020.
Redetermination of the borrowing base under the Revolving Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October, with the first scheduled borrowing base redetermination to occur on March 15, 2018. At the Company’s election, interest on borrowings under the Revolving Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin ranging from 2.50% to 3.50% per annum or the alternate base rate (“ABR”) plus an applicable margin ranging from 1.50% to 2.50% per annum, depending on utilization of the borrowing base. Interest is generally payable in arrears quarterly for loans bearing interest based at the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR, or if such interest period is longer than three months, at the end of the three month intervals during such interest period. The Company is required to pay a commitment fee to the lenders under the Revolving Credit Facility, which accrues at a rate per annum of 0.50% on the average daily unused amount of the available revolving loan commitments of the lenders.
The obligations under the Revolving Credit Facility are secured by mortgages covering approximately 85% of the total value of the proved reserves of thecapitalized oil and natural gas properties of the Company$36.7 million and certain of its subsidiaries, along with liens on substantially all personal property of the Company and certain of its subsidiaries, and are guaranteed by the Company, Holdco and certain of Holdco II’s subsidiaries, subject to customary exceptions. Under the Revolving Credit Facility, the Company is required to maintain (i) a maximum total net debt to last twelve months EBITDA ratio of 4.0 to 1.0, and (ii) a minimum adjusted current ratio of 1.0 to 1.0.
The Revolving Credit Facility also contains affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, mergers, consolidations and sales of assets, paying
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
dividends or other distributions in respect of, or repurchasing or redeeming, the Company’s capital stock, making certain investments and transactions with affiliates.
The Revolving Credit Facility contains events of default and remedies customary for credit facilities of this nature. Failure to comply with the financial and other covenants in the Revolving Credit Facility would allow the lenders, subject to customary cure rights, to require immediate payment of all amounts outstanding under the Revolving Credit Facility.
In September 2017, the Company entered into an amendment to the Revolving Credit Facility to provide for, among other things, an increase in the size of the letter of credit subfacility from $25 million to $50 million.
Successor Credit Facility
On the Effective Date, pursuant to the terms of the Plan, the Company entered into the Successor Credit Facility with Holdco II as borrower and Wells Fargo Bank, National Association, as administrative agent, providing for: 1) a reserve-based revolving loan with an initial borrowing base of $1.4 billion and 2) a term loan in an original principal amount of $300 million. On May 31, 2017, the Company entered into the First Amendment and Consent to Credit Agreement, pursuant to which among other modifications: 1) the term loan was paid in full and terminated using cash proceeds from the Jonah Assets Sale, and 2) the borrowing base for the revolving loan was reduced to $1 billion with additional agreed upon reductions for the Company’s other announced sales. In connection with the entry into the Revolving Credit Facility, the Successor Credit Facility was terminated and repaid in full.
Predecessor’s Credit Facility, Second Lien Notes and Senior Notes
On the Effective Date, pursuant to the terms of the Plan, all outstanding obligations under the Predecessor’s credit facility, Second Lien Notes and senior notes were canceled. See Note 2 for additional information.
Predecessor Covenant Violations
The Company’s filing of the Bankruptcy Petitions described in Note 2 constituted an event of default that accelerated the obligations under the Predecessor’s credit facility, Second Lien Notes and senior notes. For the two months ended February 28, 2017, contractual interest, which was not recorded, on the Second Lien Notes and senior notes was approximately $57 million. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of an event of default.
Note 8 – Derivatives
Commodity Derivatives
Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials.
The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 9 for fair value disclosures about oil and natural gas commodity derivatives.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
The following table presents derivative positions for the periods indicated as of September 30, 2017: | | | | | | | | | | | | | | | October 1 – December 31, 2017 | | 2018 | | 2019 | | Natural gas positions: | | | | | | | Fixed price swaps (NYMEX Henry Hub): | | | | | | | Hedged volume (MMMBtu) | 31,280 |
| | 47,815 |
| | 11,315 |
| | Average price ($/MMBtu) | $ | 3.18 |
| | $ | 3.01 |
| | $ | 2.97 |
| | Oil positions: | | | | | | | Fixed price swaps (NYMEX WTI): | | | | | | | Hedged volume (MBbls) | 1,104 |
| | 548 |
| | — |
| | Average price ($/Bbl) | $ | 52.13 |
| | $ | 54.07 |
| | $ | — |
| | Collars (NYMEX WTI): | | | | | | | Hedged volume (MBbls) | — |
| | 1,825 |
| | 1,825 |
| | Average floor price ($/Bbl) | $ | — |
| | $ | 50.00 |
| | $ | 50.00 |
| | Average ceiling price ($/Bbl) | $ | — |
| | $ | 55.50 |
| | $ | 55.50 |
|
During the seven months ended September 30, 2017, the Company entered into commodity derivative contracts consisting of oil swaps for January 2018 through December 2018 and natural gas swaps for January 2018 through December 2019. The Company did not enter into any commodity derivative contracts during the two months ended February 28, 2017.
In October 2017, the Company entered into commodity derivative contracts consisting of natural gas swaps for January 2018 through December 2018. Including these new hedges, as of October 31, 2017, the Company had natural gas swaps of approximately 69,715 MMMBtu at an average price of approximately $3.02 per MMBtu for 2018.
The natural gas derivatives are settled based on the closing price of NYMEX Henry Hub natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing price of NYMEX WTI crude oil for each day of the delivery month.
Balance Sheet Presentation
The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets. The following table summarizes the fair value of derivatives outstanding on a gross basis:
| | | | | | | | | | | | Successor | | | Predecessor | | | September 30, 2017 | | | December 31, 2016 | | (in thousands) | | | | | | Assets: | | | | | | Commodity derivatives | $ | 27,897 |
| | | $ | 19,369 |
| | Liabilities: | | | | | | Commodity derivatives | $ | 17,871 |
| | | $ | 113,226 |
|
By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Company’s counterparties are participants in the Revolving Credit Facility or were participants in the Successor Credit Facility or Predecessor Credit Facility. The Revolving Credit Facility is secured by certain of the Company’s and its subsidiaries’ oil, natural gas and NGL reserves and personal property; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties.
The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $28 million at September 30, 2017. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.
Gains and Losses on Derivatives
Gains and losses on derivatives were net losses of approximately $14$10.7 million for the three months ended September 30, 2017,2018 and net gains of approximately $19 million and $93 million for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively. Gains and losses on derivatives were net gains of approximately $166,000 and net losses of approximately $74 million for the three months and nine months ended September 30, 2016, respectively. Gains and losses on derivatives are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.”
The Company received net cash settlements of approximately $12 million and $20 million for the three months and seven months ended September 30, 2017, respectively, and paid net cash settlements of approximately $12$82.4 million for the two months ended February 28, 2017. The Company received net cash settlements of approximately $857and $22.0 million for the nine months ended September 30, 2016. The Company had no cash settlements during2018 and 2017, respectively.
For the three and nine months ended September 30, 2016. Note 9 – Fair Value Measurements2018, the Company recorded amortization expense on a Recurring Basis
The Company accounts for its commodity derivatives at fair value (see Note 8) on a recurring basis. The Company determines the fair value of itsunproved oil and natural gas derivatives utilizing pricing models that use a varietyproperties of techniques, including market quotes$11.2 million and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data$25.6 million, respectively, which is reflected in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads, are applied to the Company’s commodity derivatives.
Fair Value Hierarchy
In accordance with applicable accounting standards, the Company has categorized its financial instruments into a three-level fair value hierarchy basedexploration expense on the priorityaccompanying condensed consolidated statements of inputs tooperations. There was no such expense recorded for the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1)three and the lowest priority to unobservable inputs (Level 3).nine months ended September 30, 2017. Unproved leasehold
LINN ENERGY, INC.Notes to Unaudited Condensed Consolidated Financial Statements
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
The following presentsamortization for the fair value hierarchythree and nine months ended September 30, 2018 reflects consideration of the Company’s drilling plans and the lease terms of its existing unproved properties. For the three and nine months ended September 30, 2017, the Company recorded impairment expense on its unproved oil and natural gas properties of $4.2 million and $4.5 million, respectively, for assetsleases which expired. No impairment of proved oil and liabilities measured at fair value on a recurring basis:natural gas properties was recorded for the three and nine months ended September 30, 2018.
| | | | | | | | | | | | | | | Successor | | | September 30, 2017 | | | Level 2 | | Netting (1) | | Total | | | (in thousands) | | Assets: | | | | | | | Commodity derivatives | $ | 27,897 |
| | $ | (17,095 | ) | | $ | 10,802 |
| | Liabilities: | | | | | | | Commodity derivatives | $ | 17,871 |
| | $ | (17,095 | ) | | $ | 776 |
|
| | | | | | | | | | | | | | | Predecessor | | | December 31, 2016 | | | Level 2 | | Netting (1) | | Total | | | (in thousands) | | Assets: | | | | | | | Commodity derivatives | $ | 19,369 |
| | $ | (19,369 | ) | | $ | — |
| | Liabilities: | | | | | | | Commodity derivatives | $ | 113,226 |
| | $ | (19,369 | ) | | $ | 93,857 |
|
| | (1)
| Represents counterparty netting under agreements governing such derivatives. |
Note 106 – Asset Retirement Obligations
The following is a reconciliation of the changes in the Company’s asset retirement obligation (“ARO”) for the nine months ended September 30, 2018 (in thousands):
| | | | | | Asset retirement obligation, December 31, 2017 | $ | 10,769 |
| | Liabilities incurred or acquired | 1,815 |
| | Revisions in estimated cash flows | 318 |
| | Liabilities settled | (111 | ) | | Accretion expense | 620 |
| | Asset retirement obligation, September 30, 2018 | 13,411 |
| | Less: current portion of obligations | 535 |
| | Asset retirement obligation – long term | $ | 12,876 |
|
Note 7 – Long-Term Debt
In September 2017, the Company entered into a $750.0 million credit agreement with an initial borrowing base of $200.0 million and maturity on September 5, 2022 (as amended, the “2017 Credit Facility”). In September 2018, the redetermination resulted in an increase to the borrowing base to $675.0 million. Redetermination of the borrowing base of the 2017 Credit Facility occurs semiannually on or about October 1 and April 1. As of September 30, 2018, the Company had $394.6 million of outstanding borrowings and no letters of credit outstanding under the 2017 Credit Facility. The 2017 Credit Facility is secured by substantially all of the assets of the Company.
The Company hasamended the obligation2017 Credit Facility in September 2018 to plugincrease the borrowing base as noted above as well as to allow for permitted additional debt of up to $500 million before any reduction in the borrowing base would occur, to reduce the applicable margin for both London Interbank Offered Rate (“LIBOR”) and abandonalternate base rate (“ABR”) loans by 0.25% for each utilization level, and to reduce the commitment fee rate for the two lowest utilization levels to 0.375%.
Roan Resources, Inc. Notes to Unaudited Condensed Consolidated Financial Statements
Amounts borrowed under the 2017 Credit Facility bear interest at LIBOR or the ABR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the 2017 Credit Facility. Additionally, the 2017 Credit Facility provides for a commitment fee, which is payable at the end of each calendar quarter. The pricing grid below shows the applicable margin for LIBOR rate or ABR loans as well as the commitment fee depending on the Utilization Level (as defined in the credit agreement): | | | | | | | Utilization Level | Utilization | LIBOR Margin | Applicable Margin | Commitment Fee | | Level I | <25% | 2.00% | 1.00% | 0.375% | | Level II | >25% but <50% | 2.25% | 1.25% | 0.375% | | Level III | >50% but <75% | 2.50% | 1.50% | 0.500% | | Level IV | >75% but <90% | 2.75% | 1.75% | 0.500% | | Level V | >90% | 3.00% | 2.00% | 0.500% |
The 2017 Credit Facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, the Company is prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon the Company’s internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, the Company is required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per its most recent reserve report.
The 2017 Credit Facility also contains financial covenants requiring the Company to comply with a leverage ratio of the Company’s consolidated debt to consolidated EBITDAX (as defined in the credit agreement) for the period of four fiscal quarters then ended of not more than 4.00 to 1.00 and a current ratio of the Company’s consolidated current assets to consolidated current liabilities (as defined in the credit agreement to exclude non-cash assets and liabilities under ASC Topic 815 Derivatives and Hedging and ASC Topic 410 Asset Retirement and Environmental Obligations) as of the fiscal quarter ended of not less than 1.00 to 1.00.
As of September 30, 2018, the Company was in compliance with the covenants under the 2017 Credit Facility.
Prior to the 2017 Credit Facility, Citizen had a two-year, $500.0 million credit facility (“Citizen 2017 Credit Facility”) with an initial borrowing base of $82.5 million. In August 2017, the Citizen 2017 Credit Facility was terminated and the outstanding balance of $20.3 million was repaid. Note 8 – Derivative Instruments
The Company utilizes fixed price swaps and basis swaps to manage the price risk associated with the sale of its oil and natural gas wellsproduction. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and related equipmentthe referenced settlement price. Basis swaps are settled monthly based on differences between a fixed price differential and the applicable market price differential, or Panhandle Eastern Pipeline. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied
Roan Resources, Inc. Notes to Unaudited Condensed Consolidated Financial Statements
by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume.
The following table reflects the Company’s open commodity contracts at September 30, 2018:
| | | | | | | | | | | | | | | | | | | 2018 | | 2019 | | 2020 | | Total | | Oil fixed price swaps | | | | | | | | | Volume (Bbl) | 1,233,180 |
|
| 5,540,670 |
|
| 1,599,500 |
|
| 8,373,350 |
| | Weighted-average price | $ | 57.09 |
|
| $ | 59.86 |
|
| $ | 63.14 |
|
| $ | 60.08 |
| | Natural gas fixed price swaps | | | | | | | | | Volume (MMBtu) | 8,004,000 |
|
| 29,200,000 |
|
| 12,325,000 |
|
| 49,529,000 |
| | Weighted-average price | $ | 2.94 |
|
| $ | 2.86 |
|
| $ | 2.63 |
|
| $ | 2.81 |
| | Natural gas basis swaps | | | | | | | | | Volume (MMBtu) | 4,600,000 |
|
| 21,900,000 |
|
| 3,640,000 |
|
| 30,140,000 |
| | Weighted-average price | $ | 0.54 |
|
| $ | 0.58 |
|
| $ | 0.62 |
|
| $ | 0.58 |
|
The Company nets the fair value of derivative instruments by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. See Note 9 – Fair Value Measurementsfor further information regarding the fair value measurement of the Company’s derivatives. As the Company has elected to not account for commodity derivative instruments as hedging instruments, gains or losses resulting from the change in fair value along with the gains or losses resulting in settlement of derivative contracts are reflected in (loss) gain on derivative contracts included in the consolidated statement of operations.
The following table presents the Company’s (loss) gain on derivative contracts and net cash (paid) received upon settlement of its derivative contracts for the three and nine months ended September 30, 2018 and 2017: | | | | | | | | | | | | | | | | | | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | | 2018 | | 2017 | | 2018 | | 2017 | | | (in thousands) | | (Loss) gain on derivative contracts | $ | (36,704 | ) | | $ | 131 |
| | $ | (100,920 | ) | | $ | 2,385 |
| | Net cash (paid) received upon settlement of derivative contracts | $ | (13,551 | ) | | $ | 2,255 |
| | $ | (27,462 | ) | | $ | 2,385 |
| | Net cash received upon settlement of derivative contracts prior to contractual maturity | $ | — |
| | 2,255 |
| | $ | 377 |
| | $ | 2,255 |
|
Note 9 – Fair Value Measurements
The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy: Level 1— Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
Roan Resources, Inc. Notes to Unaudited Condensed Consolidated Financial Statements
Level 2— Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date.
Level 3— Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company recognizes transfers between fair value hierarchy levels as of the end of production operations. Estimated asset retirement coststhe reporting period in which the event or change in circumstances causing the transfer occurred. During the three and nine months ended September 30, 2018, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Company's recurring fair value measurements are recognized as liabilities with an increase toperformed for its commodity derivatives. Commodity Derivative Instruments Commodity derivative contracts are stated at fair value in the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities are included in “other accrued liabilities” and “other noncurrent liabilities” on theaccompanying condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletionThe Company adjusts the valuations from the valuation model for nonperformance risk and amortization” on the condensed consolidated statements of operations.for counterparty risk. The fair valuevalues of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. These inputs require significant judgments and estimates by the Company’s management atcommodity derivative instruments are classified as Level 2 measurements as they are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the timefull term of the valuationinstruments. These include market price curves, contract terms and are the most sensitiveprices, credit risk adjustments, implied market volatility and subject to change.discount factors.
LINN ENERGY, INC.Notes to Unaudited Condensed Consolidated Financial Statements
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
The following table presents a reconciliationthe amounts and classifications of the Company’s asset retirement obligationsderivative assets and liabilities as of September 30, 2018 and December 31, 2017, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands): | | | | | | Asset retirement obligations at December 31, 2016 (Predecessor) | $ | 402,162 |
| | Liabilities added from drilling | 146 |
| | Accretion expense | 4,024 |
| | Settlements | (618 | ) | | Asset retirement obligations at February 28, 2017 (Predecessor) | $ | 405,714 |
| Fresh start adjustment (1) | (48,317 | ) | | Asset retirement obligations at February 28, 2017 (Successor) | $ | 357,397 |
| | Liabilities added from drilling | 510 |
| | Liabilities associated with assets sold | (96,349 | ) | | Accretion expense | 11,233 |
| | Settlements | (5,406 | ) | | Asset retirement obligations at September 30, 2017 (Successor) | $ | 267,385 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | September 30, 2018 | | | Level 1 | | Level 2 | | Level 3 | | Gross Fair Value | | Netting | | Carrying Value | | Assets | | | | | | | | | | | | | Current commodity derivatives | $ | — |
| | $ | 4,282 |
| | $ | — |
| | $ | 4,282 |
| | $ | (4,079 | ) | | $ | 203 |
| | Noncurrent commodity derivatives | — |
| | 908 |
| | — |
| | 908 |
| | (908 | ) | | — |
| | Total assets | $ | — |
| | $ | 5,190 |
| | $ | — |
| | $ | 5,190 |
| | $ | (4,987 | ) | | $ | 203 |
| | Liabilities | | | | | | | | | | | | | Current commodity derivatives | $ | — |
| | $ | (68,340 | ) | | $ | — |
| | $ | (68,340 | ) | | $ | 4,079 |
| | $ | (64,261 | ) | | Noncurrent commodity derivatives | — |
| | (19,809 | ) | | — |
| | (19,809 | ) | | 908 |
| | (18,901 | ) | | Total liabilities | $ | — |
| | $ | (88,149 | ) | | $ | — |
| | $ | (88,149 | ) | | $ | 4,987 |
| | $ | (83,162 | ) | | | | | | | | | | | | | | | | 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 | ) |
| | (1)
Non-Recurring Fair Value Measurements
The Company’s non‑recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations and the determination of the grant date fair value of the Company’s performance share units. The fair value of assets and liabilities acquired through business combinations is calculated using a discounted‑cash flow approach using level 3 inputs. The fair value of assets or liabilities associated with purchase price allocations is on a non‑recurring basis and is not measured in periods after initial recognition. The grant date fair value of the Company’s performance share units is determined using a Monte Carlo simulation model and is classified as a Level 3 measurement. Please refer to Note 4 – Acquisitions and Note 11 – Equity Compensation for additional discussion.
Other Financial Instruments
The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables, and long-term debt. The carrying values of cash and cash equivalents, accounts payable, revenue payable, and accounts receivable approximate fair values due to the short-term maturities
Roan Resources, Inc. Notes to Unaudited Condensed Consolidated Financial Statements
of these instruments and the carrying value of long-term debt approximates fair value as the applicable interest rates are variable and reflective of market rates. | As a result of the application of fresh start accounting, the Successor recorded its asset retirement obligations at fair value as of the Effective Date. |
Note 10 – Equity In September 2018 and in conjunction with the Reorganization, the Company issued 152.5 million shares of its Class A common stock to the members of Roan LLC in exchange for their equity interest in Roan LLC. The Reorganization was accounted for as a reverse recapitalization with Roan Inc. as the accounting acquirer and therefore did not result in any change in the accounting basis for the underlying assets. Net income before taxes and equity-based compensation were allocated ratably to the members of Roan LLC and the stockholders of Roan Inc. for the period before and after the Reorganization, respectively. For comparative purposes, the issuance of the shares to the members of Roan LLC at the time of the Reorganization was reflected on a retroactive basis with the units outstanding during each period presented. For the period of September 1, 2017 through the date of the Reorganization, Roan LLC was governed by the Amended and Restated Limited Liability Company Agreement of Roan Resources LLC. In connection with the Contribution in August 2017, Roan LLC issued 1.5 billion membership units representing capital interests in Roan LLC (the "LLC Units") for a 50% equity interest in Roan LLC, to Linn in exchange for the contribution of oil and natural gas properties. See Note 4 – Acquisitions for additional discussion of the Linn Acquisition. Additionally, Roan LLC issued 1.5 billion LLC Units, which represented a 50% equity interest, to Citizen in exchange for the contribution of oil and natural gas properties. The fair value of the LLC Units issued to Citizen was the same as that of the LLC Units issued to Linn.
As discussed in Note 4 – Acquisitions, Citizen and Linn acquired acreage during 2017 on Roan LLC’s behalf. In March 2018, Roan LLC issued 19.2 million LLC Units to each Citizen and Linn for the additional leasehold acreage. For the period January 1, 2017 through August 31, 2017, Citizen’s operations were governed by the provisions of the Citizen Amended and Restated Operating Agreement (the “Citizen Operating Agreement”), effective February 29, 2016, and Citizen had two classes of membership interests outstanding, Class A and Class B. Class A represented capital interests in Citizen and Class B represented interests in profits, losses and distributions. Distributions were made to the Class A and Class B members pro rata in accordance with their membership interests; however, once the Class A members received an internal rate of return threshold of 9% prior to distributions to any other class of interest, the Class B members received a percentage of distributions in excess of their membership interests based on the terms of the Citizen Operating Agreement. Note 11 – Equity Compensation
The Company has adopted the Roan Resources, Inc. Amended and Restated Management Incentive Plan (the “Plan”), which provides for grants of options, stock appreciation rights, restricted stock unit, stock awards, dividend equivalents, other stock-based awards, cash awards and substitute awards.
Prior to the Reorganization, Roan LLC granted performance share units to certain of its employees under the Roan LLC Management Incentive Plan. The performance share units were converted into awards of performance share units under the Plan, hereafter referred to as the “PSUs,” and are subject to the terms of the Plan and individual award agreements. The amount of PSUs that can be earned range from 0% to 200% based on the Company’s market value on December 31, 2020 (“Performance Period End Date”). The Company’s market value on the Performance Period End Date will be determined by reference to the volume-weighted average price of the Company’s Class A common stock for the 30 consecutive trading days immediately preceding the Performance Period End Date. Each earned PSU will be settled through the
Roan Resources, Inc. Notes to Unaudited Condensed Consolidated Financial Statements
issuance of one share of the Company’s Class A common stock. Other than the security in which the PSUs are settled, no terms of the PSUs were modified in connection with the conversion of the PSUs.
The following table summarizes information related to the total number of PSUs awarded as of September 30, 2018: | | | | | | | | | | | | | | Number of
PSUs | | Weighted
Average Fair
Value | | Total Fair
Value ($ in thousands) | | PSUs outstanding at December 31, 2017 | 16,350,000 |
| | $ | 1.41 |
| | $ | 23,054 |
| | PSUs granted | 6,825,000 |
| | $ | 1.88 |
| | $ | 12,810 |
| | PSUs vested | — |
| | $ | — |
| | $ | — |
| Conversion (1) | (22,016,250 | ) | | $ | — |
| | $ | — |
| | PSUs outstanding at September 30, 2018 | 1,158,750 |
| | $ | 30.95 |
| | $ | 35,864 |
|
(1) PSUs were converted on a basis of 0.05 to 1.0. There was no change to the deemed fair value of the awards based on assessment of modification.
Compensation expense associated with the PSUs for the three and nine months ended September 30, 2018 was $2.9 million and $8.1 million, respectively, and is included in general and administrative expenses on the accompanying condensed consolidated statements of operations. Unrecognized expense as of September 30, 2018 for all outstanding PSU awards was $27.4 million and will be recognized over a weighted-average remaining period of 2.25 years. Under the treasury stock method, the PSUs are antidilutive for the weighted average share calculation and therefore are excluded from dilutive weighted average shares in the accompanying condensed consolidated statements of operations.
The grant date fair value of the PSUs was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units earned and estimated Company value on the Performance Period End Date. The grant date fair value of the PSUs is expensed on a straight-line basis from the grant date to the Performance Period End Date.
The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense for the PSUs granted during the following periods: | | | | | | | | | | Six Months Ended June 30, 2018 | Three Months Ended September 30, 2018 | | Company enterprise value (in billions) | $ | 4.56 |
| $ | 4.19 |
| | Equity volatility | 34.0 | % | 36.0 | % | | Weighted average risk-free interest rate | 1.96 | % | 2.54 | % |
Note 12 –Transactions with Affiliates
Management Service Agreements
Under the MSAs, Citizen and Linn provided certain services in respect to the oil and natural gas properties they contributed to the Company. Such services included serving as operator of the oil and natural gas properties contributed, land administration, marketing, information technology and accounting services. As a result of Citizen and Linn continuing to serve as operator of the contributed assets and contracting directly with vendors for goods and services for operations, Citizen and Linn collected amounts due from joint interest
Roan Resources, Inc. Notes to Unaudited Condensed Consolidated Financial Statements
owners for their share of costs and billed the Company for its share of costs. The services provided under the MSAs ended in April 2018 when the Company took over as operator for the oil and natural gas properties contributed by Citizen and Linn.
For the nine months ended September 30, 2018, the Company incurred approximately $10.0 million in charges related to the services provided under the MSAs, which are recorded in general and administrative expenses in the accompanying condensed consolidated statements of operations. Since the MSA ended in April 2018, there were no such charges related to the MSA in the three months ended September 30, 2018.
Through April 2018, Citizen and Linn billed the Company for its share of operating costs in accordance with the MSAs. At December 31, 2017, the Company had $55.5 million and $46.5 million due to Linn and Citizen, respectively, included in accounts payable and accrued liabilities – affiliates in the accompanying condensed consolidated balance sheets. At December 31, 2017, the Company had $19.0 million due to Linn and Citizen for revenue suspense associated with the oil and natural gas properties contributed to the Company included in accounts payable and accrued liabilities – affiliates in the accompanying condensed consolidated balance sheets.
Acquisition of Acreage
As provided for in the Contribution Agreement, Citizen and Linn acquired additional acreage within an area of mutual interest on behalf of the Company. As of December 31, 2017, the additional acreage acquired totaled $63.0 million and the Company reflected the amount due to Citizen and Linn in accounts payable and accrued liabilities – affiliates. See Note 4 – Acquisitions and Note 10 – Equity for further discussion of the settlement of the payable due to Citizen and Linn related to the additional acquired acreage.
Natural Gas Dedication Agreement
The Company has a gas dedication agreement with Blue Mountain Midstream LLC (“Blue Mountain”), a subsidiary of Riviera Resources, Inc. (“Riviera”), which has directors and shareholders in common with the Company. Amounts due from Blue Mountain at September 30, 2018 and December 31, 2017 are reflected as accounts receivable – affiliates in the accompanying condensed consolidated balance sheets and represent accrued revenue for the Company’s portion of the production sold to Blue Mountain. Sales to Blue Mountain are reflected as natural gas sales – affiliates and NGL sales – affiliates in the accompanying condensed consolidated statements of operations. See further discussion of this gas dedication agreement in Note 14 – Commitments and Contingencies.
Corporate Office Lease
During 2018, the Company entered into a lease for office space in Oklahoma City, Oklahoma that is owned by a subsidiary of Riviera under a lease with an initial term of 5 years. The Company paid $0.4 million during the nine months ended September 30, 2018 under this lease. Total remaining payments under the lease are $8.3 million.
Tax Matters Agreement
In conjunction with the Reorganization, the Company entered into a tax matters agreement (“TMA”) with Riviera. See Note 13 – Income Taxesfor further discussion of the TMA and the related payable to Riviera.
Roan Resources LLC
Notes to Financial Statements
Note 13 – Income Taxes
As discussed in Note 1 – Business and Organization, the Company was formed in September 2018 in connection with the Reorganization. The Company’s accounting 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 federal income tax purposes, were deemed to pass to the members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of the members.
A deferred tax liability was recorded as a result of the Reorganization based on the Company being taxable as a corporation under the Internal Revenue Code of 1986, as amended. The initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization was reflected in income tax expense based on the deferred tax liability resulting from the change in tax status. Due to the nontaxable nature of the Reorganization, there were no adjustments to the tax basis or other tax attributes in the measurement of the deferred taxes except to the extent any gain was recognized by the other parties to the Reorganization.
The Company records its quarterly tax provision based on an estimate of the annual effective tax rate expected to apply to continuing operations for the various jurisdictions in which it operates. The tax effects of certain items, such as tax rate changes, significant unusual or infrequent items, and certain changes in the assessment of the realizability of deferred taxes, are recognized as discrete items in the period in which they occur and are excluded from the estimated annual effective tax rate.
The Company’s effective combined U.S. federal and state income tax rate for the nine months ended September 30, 2018 excluding discrete items was 25.5%. During the third quarter of 2018, the Company recognized income tax expense of $299.7 million, primarily representing the initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization.
In conjunction with the Reorganization, the Company entered into a TMA with Riviera. The TMA, in part, provides for indemnification of the Company and entitlement of refunds by Riviera of certain taxes related to Linn Energy, Inc. prior to the spinoff of assets from Linn Energy, Inc. to Riviera. As a result of the TMA and an estimated overpayment of federal taxes by Linn Energy, Inc., the Company has recorded a $7.7 million income tax receivable and a payable of $7.7 million to Riviera at September 30, 2018. The receivable is included in accounts receivable - other and the payable is included in accounts payable and accrued liabilities - affiliates in the accompanying condensed consolidated balance sheets.
The Company’s deferred tax liabilities as of September 30, 2018 include the following (in thousands): | | | | | | Deferred income tax assets (liabilities): | | | Oil and natural gas properties | $ | (322,911 | ) | | Derivative contracts | 22,530 |
| | Other | 719 |
| | Deferred tax liabilities, net | $ | (299,662 | ) |
Roan Resources, Inc. Notes to Unaudited Condensed Consolidated Financial Statements
Note 1114 – Commitments and Contingencies On May 11, 2016,
Litigation
In the Debtors filed Bankruptcy Petitions for relief under Chapter 11ordinary course of business, the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040. On January 27, 2017, the Bankruptcy Court entered the Confirmation Order. Consummation of the Plan wasCompany may at times be subject to certain conditions set forth in the Plan. On the Effective Date, all of the conditions were satisfied or waivedclaims and the Plan became effective and was implemented in accordance with its terms. The LINN Debtors Chapter 11 cases will remain pending until the final resolution of all outstanding claims. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates. However, the Companylegal actions. Management believes it is and will continue to be until the final resolution of all claims, subject to certain contested matters and adversary proceedings stemming from the Chapter 11 proceedings.
In March 2017, Wells Fargo Bank, National Association (“Wells Fargo”), the administrative agent under the Predecessor Credit Facility, filed a motion in the Bankruptcy Court seeking payment of post-petition default interest of approximately $31 million. The Company has vigorously disputed that Wells Fargo is entitled to any default interest based on the plain language of the Plan and Confirmation Order. A hearing was held on April 27, 2017, and on November 13, 2017, the Bankruptcy Court ruledremote that the secured lenders are not entitled to paymentimpact of post-petition default interest. The ruling is subject to appeal by Wells Fargo.
The Company is not currently a party to any litigation or pending claims that it believes wouldsuch matters will have a material adverse effect on its overall business,the Company’s financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
During the nine months ended September 30, 2017, and the nine months ended September 30, 2016, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.flows.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Environmental Matters
Note 12 – Equity (Deficit)
Shares IssuedThe Company is subject to various federal, state and Outstanding
As of September 30, 2017, there were 84,667,268 shares of Class A common stock issuedlocal laws and outstanding. An additional 622,839 vested but not issued restricted stock units and 2,986,554 unvested restricted stock units were outstanding under the Company’s Omnibus Incentive Plan. As of September 30, 2017, the Company’s consolidated subsidiary, Holdco, had 778,898 vested Class A-2 units and 2,336,693 unvested Class A-2 units, which may be converted into shares of Class A common stock pursuantregulations relating to the termsprotection of the Limited Liability Company Operating Agreementenvironment. These laws, which are often changing, regulate the discharge of Holdco (the “Holdco LLC Agreement”). See Note 14 for additional information related tomaterials into the restricted stock unitsenvironment and Class A-2 units.
Cancellation of Units and Issuance of Class A Common Stock
In accordance with the Plan, on the Effective Date:
All units in the Predecessor that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery;
17,678,889 shares of Class A common stock were issued pro rata to holders of the Second Lien Notes with claims allowed under the Plan;
26,724,396 shares of Class A common stock were issued pro rata to holders of Unsecured Notes with claims allowed under the Plan;
471,110 shares of Class A common stock were issued to commitment parties under the Backstop Commitment Agreement in respect of premium due thereunder;
2,995,691 shares of Class A common stock were issued to commitment parties under the Backstop Commitment Agreement in connection with their backstop obligation thereunder; and
41,359,806 shares of Class A common stock were issued to participants in the rights offerings extended bymay require the Company to certain holders of claims arising underremove or mitigate the Second Lien Notes and the Unsecured Notes (including, in each case, certainenvironmental effects of the commitment parties partydisposal or release of petroleum or chemical substances at various sites. The Company has established procedures for the ongoing evaluation of its operations to the Backstop Commitment Agreement).
With the exception of shares of Class A common stock issuedidentify potential environmental exposures and to commitment parties pursuant to their obligations under the Backstop Commitment Agreement, shares of Class A common stock were issued under the Plan pursuant to an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), under Section 1145 of the Bankruptcy Code. Shares of Class A common stock issued to commitment parties pursuant to their obligations under the Backstop Commitment Agreement were issued pursuant to an exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) thereof.
As of the Effective Date, there were 89,229,892 shares of Class A common stock, par value $0.001 per share, issuedcomply with regulatory policies and outstanding.
Share Repurchase Program
On June 1, 2017, the Company’s Board of Directors announced that it had authorized the repurchase of up to $75 million of the Company’s outstanding shares of Class A common stock. On June 28, 2017, the Company’s Board of Directors announced that it had authorized an increase in the previously announced share repurchase program to up to a total of $200 million of the Company’s outstanding shares of Class A common stock. Any share repurchases are subject to restrictions in the Revolving Credit Facility. During the period from June 2017 throughprocedures. At September 2017,30, 2018, the Company repurchased an aggregatehad no environmental matters requiring specific disclosure or requiring the recognition of 4,607,598 shares of Class A common stock at an average price of $34.06 per share for a total cost of approximately $157 million.liability.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Natural Gas Dedication Agreements
On October 4, 2017, the Company’s Board of Directors announced that it had authorized an additional increase in the previously announced share repurchase program to up to a total of $400 million of the Company’s outstanding shares of a Class A common stock. In October 2017, the Company repurchased 590,118 shares of Class A common stock at an average price of $38.09 per share for a total cost of approximately $22 million. At October 31, 2017, approximately $221 million was available for share repurchases under the program.
Dividends/Distributions
Under the Predecessor’s limited liability company agreement, unitholders were entitled to receive a distribution of available cash, which included cash on hand plus borrowings less any reserves established by the Predecessor’s Board of Directors to provide for the proper conduct of the Predecessor’s business (including reserves for future capital expenditures, acquisitions and anticipated future credit needs) or to fund distributions, if any, over the next four quarters. In October 2015, the Predecessor’s Board of Directors determined to suspend payment of the Predecessor’s distribution. The Successor is not currently paying a cash dividend; however, the Board of Directors periodically reviews the Company’s liquidity position to evaluate whether or not to pay a cash dividend. Any future payment of cash dividends would be subject to the restrictions in the Revolving Credit Facility.
Note 13 – Noncontrolling Interests
Noncontrolling interests represent ownership in the net assets of the Company’s consolidated subsidiary, Holdco, not attributable to LINN Energy. On the Effective Date, Holdco granted incentive interest awards to certain members of its management in the form of Class B units (see Note 14). In accordance with the terms of the Holdco LLC Agreement, on July 31, 2017, all of the Class B units were converted to Class A-2 units of Holdco. At both September 30, 2017, and July 31, 2017 (the date of the conversion), the noncontrolling Class A-2 units represented approximately 0.88% of Holdco’s total outstanding units.
Note 14 – Share-Based Compensation
The Company had no equity awards outstanding as of December 31, 2016. In accordancehas dedicated its natural gas production from the oil and natural gas properties contributed by Citizen under an agreement with the Plan, in February 2017,a third party. Under this dedication agreement, the Company implementedis required to deliver its natural gas production from the Linn Energy, Inc. 2017 Omnibus Incentive Plan (the “Omnibus Incentive Plan”) pursuant to which employees and consultants of the Company and its affiliates are eligible to receive stock options, restricted stock, performance awards, other stock-based awards and other cash-based awards. The Committee (ascontract area, as defined in the Omnibus Incentive Plan) has broad authority underagreement, through November 2030. There is no specified volume or volume penalty in the Omnibus Incentive Plan to, among other things: (i) select participants; (ii) determine the types of awards that participants receive and the number of shares that are subject to such awards; and (iii) establish the terms and conditions of awards, including the price (if any) to be paid for the shares or the award. As of the Effective Date, an aggregate of 6,444,381 shares of Class A common stock were reserved for issuance under the Omnibus Incentive Plan (the “Share Reserve”). Additional shares of Class A common stock may be issued in excess of the Share Reserve for the sole purpose of satisfying any conversion of Class A‑2 units of Holdco into shares of Class A common stock pursuant to the Holdco LLC Agreement, and the conversion procedures set forth therein. If any stock option or other stock-based award granted under the Omnibus Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of Class A common stock underlying any unexercised award shall again be available for the purpose of awards under the Omnibus Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of Class A common stock awarded under the Omnibus Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards under the Omnibus Incentive Plan. Any award under the Omnibus Incentive Plan settled in cash shall not be counted against the maximum share limitation.agreement.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
As is customary in incentive plans of this nature, each share limitFor the oil and the number and kind of shares available under the Omnibus Incentive Plan and any outstanding awards, as well as the exercise or purchase prices of awards, and performance targets under certain types of performance-based awards, are subject to adjustment in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Company’s stockholders.
Restricted Stock Units
On the Effective Date,natural gas properties contributed by Linn, the Company grantedassumed Linn’s dedication agreement with Blue Mountain. The agreement with Blue Mountain requires the Company to certain employees 2,478,606 restricted stock units (the “Emergence Awards”). The portion ofdeliver its natural gas production from the Share Reserve that does not constitute the Emergence Awards, plus any subsequent awards forfeited before vesting (the “Remaining Share Reserve”), will be fully granted within the 36-month period immediately following the Effective Date (with such 36-month anniversary, the “Final Allocation Date”). If a Change in Control (ascontract area, as defined in the Omnibus Incentive Plan) occurs beforeagreement, through November 2030. There is no specified volume or volume penalty in the Final Allocation Date, the Company will allocate the entire Remaining Share Reserve onagreement.
Volume Commitment
Under an agreement with a fully-vested basis to actively employed employees (pro-rata based upon each such employee’s relative awards) upon the consummation of the Change in Control. During the seven months ended September 30, 2017, the Company granted to certain employees 1,324,750 restricted stock units from the Remaining Share Reserve. The restricted stock units vest over three years. Upon a participant’s termination of employment and/or service (as applicable),third party, the Company has a requirement to deliver a minimum volume of natural gas from a specified area, as defined in the right (but notagreement. In the obligation)event that the Company is unable to repurchase all ormeet this natural gas volume delivery commitment, it would incur deficiency fees on any portion of the shares of Class A common stock acquired pursuant to an award at a price equal to the fair market value (as determined under the Omnibus Incentive Plan) of the shares of Class A common stock to be repurchased, measuredundelivered volumes as of November 2021. If the dateCompany was unable to deliver any additional natural gas volumes, it would owe deficiency fees of the Company’s repurchase notice.
Holdco Incentive Interest Plan
On the Effective Date, Holdco granted incentive interest awards to certain members of its management in the form of 3,470,051 Class B units, which are intended to qualify as “profits interests” for U.S. income tax purposes. The Class B units vested 25% on the Effective Date and the remaining amount vest ratably over the following three years. In accordance with the terms of the Holdco LLC Agreement, on July 31, 2017, all of the Class B units were converted to Class A-2 units of Holdco. The Class A-2 units will continue to vest over three years.
Accounting for Share-Based Compensation
The Company recognizes expense for share-based compensation over the requisite service period in an amount equal to the fair value of share-based awards granted. The fair value of share-based awards, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company has no outstanding liability awards$8.6 million as of September 30, 2017. The Company has made a policy decision to recognize compensation expense for service-based awards2018. Based on a straight-line basis over the requisite service period for the entire award. Beginning in 2017, the Company accounts for forfeitures as they occur.
The Company’s restricted stock units are equity-classified on the condensed consolidated balance sheet. The Company’s incentive interest awards in the form of Class B units were liability-classified on the condensed consolidated balance sheet through July 31, 2017 (the date of the conversion to Class A-2 units) and are subsequently equity-classified. The fair value of the Company’s restricted stock units was determined based on the fair value of the Company’s shares on the date of grant and the fair value of the incentive interest awards in the form of Class B units (Class A-2 units upon conversion) was initially determined based on the estimated amount to settle the awards and the fair value of the awards at the date of the conversion became the measurement basis from that point forward.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Share-Based Compensation Expenses
A summary of share-based compensation expenses included on the condensed consolidated statements of operations is presented below:
| | | | | | | | | | | | Successor | | | Predecessor | | | Three Months Ended September 30, 2017 | | | Three Months Ended September 30, 2016 | | (in thousands) | | | | | | General and administrative expenses | $ | 6,277 |
| | | $ | 4,832 |
| | Lease operating expenses | — |
| | | 1,129 |
| | Total share-based compensation expenses | $ | 6,277 |
| | | $ | 5,961 |
| | Income tax benefit | $ | 3,157 |
| | | $ | 2,203 |
|
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | General and administrative expenses | $ | 25,876 |
| | | $ | 50,255 |
| | $ | 19,238 |
| | Lease operating expenses | — |
| | | — |
| | 5,276 |
| | Total share-based compensation expenses | $ | 25,876 |
| | | $ | 50,255 |
| | $ | 24,514 |
| | Income tax benefit | $ | 6,712 |
| | | $ | 5,170 |
| | $ | 9,058 |
|
Note 15 – Earnings Per Share/Unit
Basic earnings per share/unit is computed by dividing net earnings attributable to common stockholders/unitholders by the weighted average number of shares/units outstanding during the period. Diluted earnings per share/unit is computed by adjusting the average number of shares/units outstanding for the dilutive effect, if any, of potential common shares/units.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
The following tables provide a reconciliation of the numerators and denominators of the basic and diluted per share/unit computations for net income (loss):
| | | | | | | | | | | | | | Successor | | | Three Months Ended September 30, 2017 | | | Income | | Shares | | Per Share | | | (in thousands, except per share data) | | | | | | | | | Basic: | | | | | | | Income from continuing operations | $ | 50,964 |
| | 87,796 |
| | $ | 0.58 |
| | Income from discontinued operations, net of income taxes | 86,099 |
| | 87,796 |
| | 0.98 |
| | Net income attributable to common stockholders | $ | 137,063 |
| | 87,796 |
| | $ | 1.56 |
| | | | | | | | | Effect of Dilutive Securities: | | | | | | | Dilutive effect of restricted stock units | $ | — |
| | 1,203 |
| | | | Dilutive effect of unvested Class A-2 units of Holdco | $ | (31 | ) | | — |
| | | | |
|
| | | | | | Diluted: | | | | | | | Income from continuing operations | $ | 50,933 |
| | 88,999 |
| | $ | 0.57 |
| | Income from discontinued operations | 86,099 |
| | 88,999 |
| | 0.97 |
| | Net income attributable to common stockholders | $ | 137,032 |
| | 88,999 |
| | $ | 1.54 |
|
| | | | | | | | | | | | | | Predecessor | | | Three Months Ended September 30, 2016 | | | Loss | | Units | | Per Unit | | | (in thousands, except per unit data) | | | | | | | | | Basic and Diluted: | | | | | | | Loss from continuing operations | $ | (96,301 | ) | | 352,792 |
| | $ | (0.27 | ) | | Loss from discontinued operations, net of income taxes | (102,064 | ) | | 352,792 |
| | (0.29 | ) | | Net loss attributable to common unitholders | $ | (198,365 | ) | | 352,792 |
| | $ | (0.56 | ) |
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
| | | | | | | | | | | | | | Successor | | | Seven Months Ended September 30, 2017 | | | Income | | Shares | | Per Share | | | (in thousands, except per share data) | | | | | | | | | Basic: | | | | | | | Income from continuing operations | $ | 267,019 |
| | 88,966 |
| | $ | 3.00 |
| | Income from discontinued operations, net of income taxes | 82,845 |
| | 88,966 |
| | 0.93 |
| | Net income attributable to common stockholders | $ | 349,864 |
| | 88,966 |
| | $ | 3.93 |
| | | | | | | | | Effect of Dilutive Securities: | | | | | | | Dilutive effect of restricted stock units | $ | — |
| | 818 |
| | | | Dilutive effect of unvested Class A-2 units of Holdco | $ | (31 | ) | | — |
| | | | | | | | | | | Diluted: | | | | | | | Income from continuing operations | $ | 266,988 |
| | 89,784 |
| | $ | 2.97 |
| | Income from discontinued operations | 82,845 |
| | 89,784 |
| | 0.93 |
| | Net income attributable to common stockholders | $ | 349,833 |
| | 89,784 |
| | $ | 3.90 |
|
| | | | | | | | | | | | | | Predecessor | | | Two Months Ended February 28, 2017 | | | Income (Loss) | | Units | | Per Unit | | | (in thousands, except per unit data) | | | | | | | | | Basic and Diluted: | | | | | | | Income from continuing operations | $ | 2,397,609 |
| | 352,792 |
| | $ | 6.80 |
| | Loss from discontinued operations, net of income taxes | (548 | ) | | 352,792 |
| | (0.01 | ) | | Net income attributable to common unitholders | $ | 2,397,061 |
| | 352,792 |
| | $ | 6.79 |
|
| | | | | | | | | | | | | | Predecessor | | | Nine Months Ended September 30, 2016 | | | Loss | | Units | | Per Unit | | | (in thousands, except per unit data) | | | | | | | | | Basic and Diluted: | | | | | | | Loss from continuing operations | $ | (105,478 | ) | | 352,606 |
| | $ | (0.30 | ) | | Loss from discontinued operations, net of income taxes | (1,232,141 | ) | | 352,606 |
| | (3.49 | ) | | Net loss attributable to common unitholders | $ | (1,337,619 | ) | | 352,606 |
| | $ | (3.79 | ) |
The diluted earnings per unit calculation excludes approximately 8,000 restricted stock units that were anti-dilutive for the seven months ended September 30, 2017, and approximately 1 million unit options and warrants that were anti-dilutive for each of the three months and nine months ended September 30, 2016. There were no anti-dilutive restricted stock units for the three
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
months ended September 30, 2017. There were no potential common units outstanding during the two months ended February 28, 2017.
Note 16 – Income Taxes
Effective February 28, 2017, upon consummation of the Plan, the Successor became a C corporation subject to federal and state income taxes. Prior to the consummation of the Plan, the Predecessor was a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits were passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor.
The effective income tax rates were approximately 11% and 37% for the three months and seven months ended September 30, 2017, respectively, and zero for the two months ended February 28, 2017. The deferred tax effects of the Company’s change to a C corporation are included in income from continuing operations for the two months ended February 28, 2017. Amounts recognized as income taxes are included in “income tax expense (benefit),” as well as discontinued operations, on the condensed consolidated statements of operations.
Note 17 – Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows
“Other current assets” reported on the condensed consolidated balance sheets include the following:
| | | | | | | | | | | | Successor | | | Predecessor | | | September 30, 2017 | | | December 31, 2016 | | (in thousands) | | | | | | Prepaids | $ | 53,702 |
| | | $ | 70,116 |
| | Receivable from related party | 18,262 |
| | | — |
| | Inventories | 11,251 |
| | | 15,097 |
| | Deferred financing fees | — |
| | | 16,809 |
| | Other | 2,722 |
| | | 3,288 |
| | Other current assets | $ | 85,937 |
| | | $ | 105,310 |
|
“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:
| | | | | | | | | | | | Successor | | | Predecessor | | | September 30, 2017 | | | December 31, 2016 | | (in thousands) | | | | | | Accrued compensation | $ | 25,057 |
| | | $ | 16,443 |
| | Asset retirement obligations (current portion) | 7,361 |
| | | 9,361 |
| | Deposits | 8,153 |
| | | — |
| | Income taxes payable | 56,333 |
| | | — |
| | Other | 3,851 |
| | | 175 |
| | Other accrued liabilities | $ | 100,755 |
| | | $ | 25,979 |
|
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | Cash payments for interest, net of amounts capitalized | $ | 15,140 |
| | | $ | 17,651 |
| | $ | 117,794 |
| | Cash payments for income taxes | $ | 275 |
| | | $ | — |
| | $ | 4,427 |
| | Cash payments for reorganization items, net | $ | 10,802 |
| | | $ | 21,571 |
| | $ | 5,728 |
| | | | | | | | | | Noncash investing activities: | | | | | | | | Accrued capital expenditures | $ | 42,388 |
| | | $ | 22,191 |
| | $ | 24,817 |
|
For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. At September 30, 2017, “restricted cash” on the condensed consolidated balance sheet consists of approximately $38 million that will be used to settle certain claims in accordance with the Plan (which is the remainder of approximately $80 million transferred to restricted cash in February 2017 to fund such items), approximately $8 million related to deposits and approximately $5 million for other items. At December 31, 2016, “restricted cash” on the condensed consolidated balance sheet represents amounts restricted related to utility services providers. In addition, restricted cash of approximately $8 million is included in “other noncurrent assets” on the condensed consolidated balance sheet at December 31, 2016, and represents cash deposited by the Company into a separate account designated for asset retirement obligations in accordance with contractual agreements.
At December 31, 2016, net outstanding checks of approximately $6 million were reclassified and included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet. The change in net outstanding checks is presented as cash flows from financing activities and included in “other” on the condensed consolidated statements of cash flows.
Note 18 – Related Party Transactions
Roan Resources LLC
On August 31, 2017, the Company completed the transaction in which LINN Energy and Citizen each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan. In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan, subject to customary post-closing adjustments. See Note 4 for additional information. Also on such date, Roan entered into a Master Services Agreement (the “MSA”) with Linn Operating, LLC (“Linn Operating”), a subsidiary of LINN Energy, pursuant to which Linn Operating will provide certain operating, administrative and other services in respect of the assets contributed to Roan during a transitional period.
Under the MSA, Roan will reimburse Linn Operating for certain costs and expenses incurred by Linn Operating in connection with providing the services, and Roan will pay to Linn Operating a service fee of $1.25 million per month, prorated for partial months. The termination of the MSA will be the earliest of: (a) mutual agreement of the parties; (b) upon 30 days’ prior written notice from Roan to Linn Operating; (c) upon five days’ prior written notice from Linn Operating to Roan of a material default by Roan under the MSA, provided Linn Operating must have provided prior written notice to Roan of such material default providing Roan 10 days to cure such material default and such material default has not been cured by the end of the 10 day time period; and (d) eight months from the date of the MSA.
In addition to the service fee, for the one month ended September 30, 2017, the Company recognized marketing revenues of approximately $1 million associated with charges incurred by Roan from its properties. The Company has accounts receivable due from Roan of approximately $2 million included in “accounts receivable – trade, net” and accounts payable due to Roan of
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
approximately $1 million included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet at September 30, 2017. In addition, approximately $18 million due from Roan associated with capital spending is included in “other current assets” on the Company’s condensed consolidated balance sheet at September 30, 2017.
Berry Petroleum Company, LLC
Berry, a former subsidiary of the Predecessor, was deconsolidated effective December 3, 2016 (see Note 4). The employees of Linn Operating, Inc. (“LOI”), a subsidiary of the Predecessor, provided services and support to Berry in accordance with an agency agreement and power of attorney between Berry and LOI. Upon deconsolidation, transactions between the Predecessor and Berry were no longer eliminated in consolidation and were treated as related party transactions. These transactions include, but are not limited to, management fees paid to the Company by Berry. On the Effective Date, Berry emerged from bankruptcy as a stand-alone, unaffiliated entity.
For the two months ended February 28, 2017, and the three months and the nine months ended September 30, 2016, Berry incurred management fees of approximately $6 million, $14 million and $56 million, respectively, for services provided by LOI. The Predecessor also had accounts payable due to Berry of approximately $3 million included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet at December 31, 2016. In addition, $25 million due to Berry was included in “liabilities subject to compromise” on the Predecessor’s condensed consolidated balance sheet at December 31, 2016.
LinnCo, LLC
LinnCo, an affiliate of the Predecessor, was formed on April 30, 2012. All of LinnCo’s common shares were held by the public. As of December 31, 2016, LinnCo had no significant assets or operations other than those related to its interest in the Predecessor and owned approximately 71% of the Predecessor’s then outstanding units. In accordance with the Plan, LinnCo will be dissolved following the resolution of all outstanding claims.
The Predecessor had agreed to provide to LinnCo, or to pay on LinnCo’s behalf, any financial, legal, accounting, tax advisory, financial advisory and engineering fees, and other administrative and out-of-pocket expenses incurred by LinnCo, along with any other expenses incurred in connection with any public offering of shares in LinnCo or incurred as a result of being a publicly traded entity. These expenses include costs associated with annual, quarterly and other reports to holders of LinnCo shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, printing costs, independent auditor fees and expenses, legal counsel fees and expenses, limited liability company governance and compliance expenses and registrar and transfer agent fees. In addition, the Predecessor had agreed to indemnify LinnCo and its officers and directors for damages suffered or costs incurred (other than income taxes payable by LinnCo) in connection with carrying out LinnCo’s activities. All expenses and costs paid by the Predecessor on LinnCo’s behalf were expensed by the Predecessor.
For the two months ended February 28, 2017, LinnCo incurred total general and administrative expenses of approximately $287,000, including approximately $240,000 related to services provided by the Predecessor. All of the expenses incurred during the two months ended February 28, 2017, had been paid by the Predecessor on LinnCo’s behalf as of February 28, 2017.
For the three months and nine months ended September 30, 2016, LinnCo incurred total general and administrative expenses, reorganization expenses and offering costs of approximately $1.0 million and $5.2 million, respectively, including approximately $603,000 and $1.8 million, respectively, related to services provided by the LINN Energy. Of the expenses and costs incurred during the nine months ended September 30, 2016, approximately $5.1 million had been paid by LINN Energy on LinnCo’s behalfnatural gas volumes delivered as of September 30, 2016.2018, current production from producing wells and expected production from wells planned to be drilled in the specified area, the Company expects to meet the required minimum volume commitment.
Note 15 – Subsequent Events
Subsequent to September 30, 2018, the Company entered into fixed price swaps for 2,500 Bbls per day of NGL production at a weighted average price of $34.03 for the period of October 2018 to December 2019 and for 20,000 Mcf per day of natural gas production at a weighted average price of $2.93 for the period of January 2019 to December 2019.
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of the financial condition and results of the Company should be read in conjunction with theour unaudited condensed consolidated financial statements and related notes included elsewhere in this Quarterlyreport as well as our audited consolidated financial statements and notes included in our Current Report on Form 10-Q and in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.8-K filed September 24, 2018. The following discussion contains forward-looking statements based on expectations,that reflect our future plans, estimates, beliefs and assumptions. Actual results may differ materially from those discussed inexpected performance. The forward-looking statements are subject to risk and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices fordevelopment, production, gathering and sale of oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors set forth in “Cautionary Statement Regarding Forward-Looking Statements” below and inNGLs. Please refer to Part II, Item 1A. “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” for additional information regarding these risks and uncertainties. In light of these risks and uncertainties, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Roan Inc. was incorporated in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, and elsewhere in the Annual Report. When referringSeptember 2018 to Linn Energy, Inc. (formerly known as Linn Energy, LLC) (“Successor,” “LINN Energy” or the “Company”), the intent is to refer to LINN Energy, a newly formed Delaware corporation, and its consolidated subsidiariesserve as a whole or on an individual basis, depending on the context in which the statements are made. Linn Energy, Inc. is a successor issuer of Linn Energy, LLC pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). When referring to the “Predecessor” in reference to the periodholding company, and prior to the emergence from bankruptcy,Reorganization, had no previous operations, assets or liabilities. The historical financial and operating information included in this Quarterly Report, (i) on and after September 24, 2018, is that of Roan Inc., and (ii) prior to September 24, 2018, is the intent isinformation of Roan LLC, our accounting predecessor. The historical financial and operating information of Roan LLC presented here, (i) prior to refer to Linn Energy, LLC,August 31, 2017, the predecessor that will be dissolved following the effective date of the Plan (as defined below) and resolution of all outstanding claims, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.
The reference to “Berry” herein refers to Berry Petroleum Company, LLC, which was an indirect 100% wholly owned subsidiarycompletion of the Predecessor through February 28, 2017. Berry was deconsolidated effective December 3, 2016 (see belowContribution is that of Citizen, the predecessor of Roan LLC for financial reporting purposes and Note 4). The reference(ii) on and after August 31, 2017, is that of Roan LLC. Therefore, the operating information of Citizen prior to “LinnCo” herein refers to LinnCo, LLC, an affiliate of the Predecessor.
The reference to a “Note” herein refersAugust 31, 2017 does not include financial information relating to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”oil and natural gas properties contributed by Linn.
Executive Overview
LINN Energy isWe are an independent oil and natural gas company that was formed in February 2017, in connection withfocused on the reorganizationdevelopment of our assets throughout the eastern and southern Anadarko Basin. The Anadarko Basin, which spans from south-central Oklahoma to the northeast corner of the Predecessor. The Predecessor was publicly traded from January 2006 to February 2017. As discussed further below and in Note 2, on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo (collectively, the “LINN Debtors”) and Berry (collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11Texas panhandle, is one of the U.S. Bankruptcy Code (“Bankruptcy Code”)largest and most prolific onshore oil and natural gas basins in the U.S. Bankruptcy Court for the Southern DistrictUnited States, featuring multiple producing horizons and extensive well production history demonstrated over seven decades of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040. During the pendencydevelopment. We focus our development on formations where we believe we can apply our technical and operational expertise in order to increase production and cash flow to deliver compelling economic rates of return on a risk adjusted basis. Our objective is to maximize shareholder value and corporate returns by generating steady production growth, strong pre-tax margins and significant cash flow.
Our primary developmental focus is on our Merge acreage position in Canadian, Grady and McClain counties in Central Oklahoma. We are one of the Chapter 11 proceedings,most active operators in Oklahoma, with eight rigs actively operating as of September 30, 2018, all of which are focused on drilling horizontal well laterals in the Debtors operated their businesses as “debtors-in-possession” underMerge and SCOOP plays. Our acreage position is concentrated in what we believe are the jurisdictionoil and liquids-rich fairways of the Bankruptcy CourtMerge play and provides us development opportunities through multiple stacked prospective development horizons.
How We Evaluate Our Operations We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: 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.
Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations
Corporate Reorganization
On September 24, 2018, we completed the Reorganization, where Roan LLC, our accounting predecessor, became a wholly owned subsidiary of Roan Inc. Roan Inc. was incorporated to serve as a holding company and, prior to the Reorganization, had no previous operations, assets or liabilities. For more information on our Reorganization, please see Note 1 – Business and Organization.
The historical financial and operating information included in accordance withthis Quarterly Report, (i) on and after September 24, 2018, is that of Roan Inc., and (ii) prior to September 24, 2018, is the applicable provisionsinformation of Roan LLC, our accounting predecessor. The historical financial and operating information of Roan LLC presented here, (i) prior to August 31, 2017, the date of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017.completion of the Contribution is that of Citizen, the predecessor of Roan LLC for financial reporting purposes and (ii) on and after August 31, 2017, is that of Roan LLC. Therefore, the operating information of Citizen prior to August 31, 2017 does not include financial information relating to the oil and natural gas properties contributed by Linn. On December 3, 2016, LINN Energy filed an amended plan of reorganization that excluded Berry.
Income Taxes
As a result of itsthe Reorganization, we became subject to federal and state tax. Due to the change in tax status, we have recorded a tax provision for the initial recording of the deferred tax liability recognized as a result of the Reorganization. Our accounting predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of controlRoan LLC and any related tax credits, for federal income tax purposes, were deemed to pass to the members. Accordingly, no tax provision was made in the historical financial statements of Berry, LINN Energy concludedRoan LLC since the income tax was an obligation of the members.
Impact of ASC Topic 606 Adoption
Revenue for the three and nine months ended September 30, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that it was appropriatewere previously recorded as gathering, processing and transportation expenses to deconsolidate Berry effectivebe 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. For a discussion of the impact of the adoption of ASC 606 on the aforementioned dateCompany’s current period results as compared to the previous revenue recognition standards, see Note 3 – Revenue from Contracts with Customers.
Financial and classified itOperational Performance Our financial and operational performance for the nine months ended September 30, 2018 included the following highlights: Net loss was $288.9 million for the nine months ended September 30, 2018, as discontinued operations.compared to net income of $28.8 million for the nine months ended September 30, 2017. The net loss was primarily due to: The Company’s properties are currently located
$100.9 million loss on derivative contracts during the nine months ended September 30, 2018 as a result of increases in seven operating regionsoil prices during this period; $19.7 million increase in production expenses, primarily related to an increase in production volumes for the nine months ended September 30, 2018; $25.7 million increase in exploration expenses, primarily related to increased unproved leasehold amortization during the nine months ended September 30, 2018; $61.5 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; $18.2 million increase in general & administrative expenses, primarily due to fees paid to Citizen and Linn under MSAs, salaries and benefits to our employees and equity-based compensation expense during the nine months ended September 30, 2018; and $299.7 million income tax expense during the nine months ended September 30, 2018 as a result of recognizing a deferred tax liability upon becoming a taxable entity after the Reorganization.
Partially offset by: $213.1 million increase in oil, natural gas and NGL sales, primarily as a result of an increase in total production volumes during the nine months ended September 30, 2018.
Average daily sales volumes were 40.1 MBoe for the nine months ended September 30, 2018, an increase of 208% compared to 13.0 MBoe during 2017. Drilled or participated in 165 gross (51 net) wells in the United Statesfirst nine months of 2018. 1,246 gross (502 net) producing wells online at September 30, 2018, including 584 gross (430 net) operated wells. Our Class A common stock began trading on the New York Stock Exchange (“U.S.”NYSE”): under the ticker symbol “ROAN” on November 9, 2018. Upon trading on the NYSE, our Class A common stock ceased trading on the OTCQB market. Hugoton Basin, which includes properties located
Sources of Revenue Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Revenues from product sales are a function of the volumes produced, product quality, market prices, and gas Btu content. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. For the nine months ended September 30, 2018, our revenues, excluding loss on derivative contracts, were derived 63% from oil sales, 16% from natural gas sales and 21% from NGL sales. Our revenues may vary significantly from period to period as a result of changes in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle;volumes of production sold or changes in commodity prices. Mid-Continent, which includes Oklahoma properties located in the Anadarko and Arkoma basins, as well as waterfloods in the Central Oklahoma Platform;TexLa, which includes properties located in east Texas and north Louisiana;
Rockies, which includes properties located in Wyoming (Washakie Basin), Utah (Uinta Basin) and North Dakota (Williston Basin);
Permian Basin, which includes properties located in west Texas and southeast New Mexico;
Realized Prices on the Sales of ContentsOil, Natural Gas and NGL Volumes Our results of operations are heavily influenced by commodity prices. Commodity prices may fluctuate widely in response to (i) relatively minor changes in the supply of and demand for oil, natural gas and NGLs, (ii) market uncertainty and (iii) a variety of additional factors that are beyond our control. From time to time, we enter into derivative arrangements for our oil and natural gas production to mitigate the impact of price volatility on our business. See Item 3. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk for further discussion of the risks related to commodity price exposure and our derivative contracts. Pricing for certain of our natural gas contracts are based on Oklahoma indexes, including ONEOK Gas Transportation (“OGT”), Natural Gas Pipeline Company of America Mid-Continent (“NGPL MC”), Panhandle Eastern Pipeline (“PEPL”) and Southern Star Central Gas Pipeline (“SSCGP”) due to the proximity of those pipelines to our producing properties. These indexes fluctuate from Henry Hub pricing due to a variety of reasons including the distance to the retail market, availability and capacity of pipelines to move the product to distribution hubs, customer demand, and competition between suppliers.
Oil and natural gas prices have been subject to significant fluctuations during the past several years. The average oil prices were higher while the average natural gas prices remained consistent during the three and nine months ended September 30, 2018 compared to the same periods in 2017. The following table sets forth the average NYMEX oil and natural gas prices for the three and nine months ended September 30, 2018 and 2017: | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2018 | | 2017 | | 2018 | | 2017 | | Average NYMEX prices | | | | | | | | | Oil (Bbl) | $ | 69.55 |
| | $ | 48.21 |
| | $ | 66.75 |
| | $ | 49.47 |
| | Natural gas (MMcf) | $ | 3.04 |
| | $ | 3.06 |
| | $ | 3.06 |
| | $ | 3.12 |
|
Results of Operations Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017 The following table presents selected financial and operating information for the periods presented. | | | | | | | | | | | Three Months Ended
September 30, | | | 2018 | | 2017 | | Production Data | | | | | Oil (MBbls) | 1,089 |
| | 348 |
| | Natural gas (MMcf) | 11,417 |
| | 4,709 |
| | Natural gas liquids (MBbls) | 1,286 |
| | 405 |
| | Total volumes (MBoe) | 4,278 |
| | 1,538 |
| | Average daily total volumes (MBoe/d) | 46.5 |
| | 16.7 |
| Average Prices - as reported (1) | | | | | Oil (per Bbl) | $ | 68.86 |
| | $ | 47.99 |
| | Natural gas (per Mcf) | $ | 1.58 |
| | $ | 2.73 |
| | Natural gas liquids (per Bbl) | $ | 21.08 |
| | $ | 24.87 |
| | Total (per Boe) | $ | 28.09 |
| | $ | 25.76 |
| Average Prices - including impact of derivative contract settlements (1)(2) | | | | Oil (per Bbl) | $ | 55.71 |
| | $ | 47.99 |
| | Natural gas (per Mcf) | $ | 1.62 |
| | $ | 2.73 |
| | Natural gas liquids (per Bbl) | $ | 21.08 |
| | $ | 24.87 |
| | Total (per Boe) | $ | 24.83 |
| | $ | 25.76 |
| Average Prices - excluding gathering, transportation and processing costs (3) | | | | Oil (per Bbl) | $ | 68.93 |
| | $ | 47.99 |
| | Natural gas (per Mcf) | $ | 1.90 |
| | $ | 2.73 |
| | Natural gas liquids (per Bbl) | $ | 27.37 |
| | $ | 24.87 |
| | Total (per Boe) | $ | 30.86 |
| | $ | 25.76 |
|
| | Item 2.(1) | Management’s DiscussionAverage prices for the three months ended September 30, 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 Analysistransportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of Financial Conditiontransition. Accordingly, comparative information has not been adjusted and Results of Operations - Continuedcontinues to be reported under the previous revenue standard. |
| | | (2) | Excludes settlement of derivative contracts prior to their contractual maturity. |
| | | (3) | Excludes the effects of netting gathering, transportation and processing costs under ASC 606. |
Michigan/Illinois, whichRevenues
Our operating revenues includes properties locatedrevenues from the sale of oil, natural gas and NGLs and gain (loss) on our derivative contracts. The following table provides information on our operating revenues: | | | | | | | | | | | Three Months Ended
September 30, | | | 2018 | | 2017 | | Revenues | (in thousands) | Oil sales (1) | $ | 74,987 |
| | $ | 16,701 |
| Natural gas sales (1) | 18,059 |
| | 12,845 |
| Natural gas liquid sales (1) | 27,106 |
| | 10,074 |
| | (Loss) gain on derivative contracts | (36,704 | ) | | 131 |
| | Total revenues | $ | 83,448 |
| | $ | 39,751 |
|
| | | (1) | Revenue for the three months ended September 30, 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. |
Oil sales. Our oil sales increased by approximately $58.3 million, or 349%, to $75.0 million for the three months ended September 30, 2018 from $16.7 million for the three months ended September 30, 2017. This increase was primarily due to the increase in the Antrim Shale formation in north Michigan and oil properties in south Illinois; and South Texas.
In July 2017, the Company divested all of its properties located in California. See below and Note 4 for details of the Company’s divestitures.
The Company also owns a 50% equity interest in Roan Resources LLC (“Roan”), which is focused on the accelerated development of the Merge/SCOOP/STACK play in Oklahoma. The Company’s current focus is the development of the Merge/SCOOP/STACK through its equity interest in Roan,production as well as through its midstream operationsthe increase in average sales prices received for those produced volumes. Our oil production increased 741 MBbls, or 213%, to 1,089 MBbls for the three months ended September 30, 2018 from 348 MBbls for the three months ended September 30, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the area. Additionally,fourth quarter of 2017 and during 2018. The increase in average sales prices received on our oil production for the Company is pursuing emerging horizontal opportunitiesthree months ended September 30, 2018 reflects the increase in the Mid-Continentindex price for oil in the 2018 period as compared to the 2017 period.
Natural Gas sales. Our natural gas sales increased by approximately $5.2 million, or 41%, to $18.1 million for the three months ended September 30, 2018 from $12.8 million for the three months ended September 30, 2017. This increase was primarily due to the increase in production partially offset by the decrease in average sales prices received for those produced volumes and TexLa regions while continuingthe impact of netting transportation costs with revenue as a result of adopting ASC 606. Our natural gas production increased 6,708 MMcf, or 142%, to add11,417 MMcf for the three months ended September 30, 2018 from 4,709 MMcf for the three months ended September 30, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018. The decrease in average sales prices received on our natural gas production for the three months ended September 30, 2018 reflects the decrease in the Oklahoma index prices we received under our contract terms for natural gas in the 2018 period as compared to the 2017 period. NGL sales. Our NGL sales increased by approximately $17.0 million, or 169%, to $27.1 million for the three months ended September 30, 2018 from $10.1 million for the three months ended September 30, 2017. This increase was primarily due to the increase in production and an increase in the average sales prices received for those produced volumes, partially offset by the impact of netting of transportation costs with revenue as a result of adopting ASC 606. Our NGL production increased 881 MBbls, or 218%, to 1,286 MBbls for the three months ended September 30, 2018 from 405 MBbls for the three months ended September 30, 2017.
The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018. (Loss) gain on derivative contracts. For the three months ended September 30, 2018, changes in oil prices had a negative impact on the fair value by efficiently operating and applying new technology tosettlement of our derivative contracts. We had a diverse setloss on derivative contracts of long-life producing assets. $36.7 million, including loss on settlement of derivatives contracts of $13.6 million and unfavorable change in the fair value of derivative contracts of $23.1 million. For the three months ended September 30, 2017, we had a gain on derivative contracts of $0.1 million related to the Company’s results includedsettlement of derivative contracts prior to their contractual maturity.
Operating Expenses Our operating expenses reflect costs incurred in the following: development, production and sale of oil, natural gas and NGL sales of approximately $206 million compared to $238 million for the three months ended September 30, 2016; average daily production of approximately 586 MMcfe/d compared to 809 MMcfe/d for the three months ended September 30, 2016;
net income attributable to common stockholders of approximately $137 million compared to a net loss attributable to common unitholders of approximately $198 million for the three months ended September 30, 2016;
capital expenditures of approximately $123 million compared to $44 million for the three months ended September 30, 2016; and
22 wells drilled (all successful) compared to 46 wells drilled (all successful) for the three months ended September 30, 2016.
For the nine months ended September 30, 2017, the Company’s results included the following:
oil, natural gas and NGL sales of approximately $530 million and $189 million for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, compared to $618 million for the nine months ended September 30, 2016;
average daily production of approximately 664 MMcfe/d and 745 MMcfe/d for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, compared to 812 MMcfe/d for the nine months ended September 30, 2016;
net income attributable to common stockholders/unitholders of approximately $350 million and $2.4 billion for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, compared to a net loss attributable to unitholders of approximately $1.3 billion for the nine months ended September 30, 2016;
net cash provided byNGLs. The following table provides information on our operating activities from continuing operations of approximately $192 million and net cash used in operating activities of approximately $30 million for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, compared to net cash provided by operating activities of approximately $851 million for the nine months ended September 30, 2016;
capital expenditures of approximately $237 million and $46 million for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, compared to $98 million for the nine months ended September 30, 2016; and
63 wells drilled (all successful) compared to 142 wells drilled (141 successful) for the nine months ended September 30, 2016.
Predecessor and Successor Reporting
As a result of the application of fresh start accounting (see Note 3), the Company’s condensed consolidated financial statements and certain note presentations are separated into two distinct periods, the period before the Effective Date (labeled Predecessor) and the period after that date (labeled Successor), to indicate the application of a different basis of accounting between the periods presented. Despite this separate presentation, there was continuity of the Company’s operations.
expenses:
Table of Contents | | | | | | | | | | | Three Months Ended
September 30, | | | 2018 | | 2017 | | | (in thousands, except costs per Boe) | | Operating Expenses | | | | | Production expenses | $ | 14,737 |
| | $ | 4,336 |
| Gathering, transportation and processing (1) | — |
| | 4,890 |
| | Production taxes | 6,210 |
| | 847 |
| | Exploration expenses | 11,646 |
| | 4,229 |
| | Depreciation, depletion, amortization and accretion | 37,164 |
| | 10,824 |
| General and administrative (2) | 13,177 |
| | 4,489 |
| | Gain on sale of oil and natural gas properties | — |
| | (838 | ) | | Total | $ | 82,934 |
| | $ | 28,777 |
| | Average Costs per Boe | | | | | Production expenses | $ | 3.44 |
| | $ | 2.82 |
| Gathering, transportation and processing (1) | — |
| | 3.18 |
| | Production taxes | 1.45 |
| | 0.55 |
| | Exploration expenses | 2.72 |
| | 2.75 |
| | Depreciation, depletion, amortization and accretion | 8.69 |
| | 7.04 |
| General and administrative (2) | 3.08 |
| | 2.92 |
| | Gain on sale of oil and natural gas properties | — |
| | (0.54 | ) | | Total | $ | 19.38 |
| | $ | 18.72 |
|
| | Item 2.(1) | Management’s DiscussionGathering, transportation and Analysis of Financial Condition and Results of Operations - Continued |
Chapter 11 Proceedings
On the Petition Date, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040.
On December 3, 2016, the LINN Debtors filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC (“LAC”) and Berry Petroleum Company, LLC (the “Plan”). The LINN Debtors subsequently filed amended versions of the Plan with the Bankruptcy Court.
On December 13, 2016, LAC and Berry filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “Berry Plan” and together with the Plan, the “Plans”). LAC and Berry subsequently filed amended versions of the Berry Plan with the Bankruptcy Court.
On January 27, 2017, the Bankruptcy Court entered an order approving and confirming the Plans (the “Confirmation Order”). On February 28, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the respective Plans, the Plans became effective in accordance with their respective terms and LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities.
Plan of Reorganization
In accordance with the Plan, on the Effective Date:
The Predecessor transferred all of its assets, including equity interests in its subsidiaries, other than LAC and Berry, to Linn Energy Holdco II LLC (“Holdco II”), a newly formed subsidiary of the Predecessor and the borrower under the Credit Agreement (as amended, the “Successor Credit Facility”) entered into in connection with the reorganization, in exchange for 100% of the equity of Holdco II and the issuance of interests in the Successor Credit Facility to certain of the Predecessor’s creditors in partial satisfaction of their claims (the “Contribution”). Immediately following the Contribution, the Predecessor transferred 100% of the equity interests in Holdco II to the Successor in exchange for approximately $530 million in cash and an amount of equity securities in the Successor not to exceed 49.90% of the outstanding equity interests of the Successor, which the Predecessor distributed to certain of its creditors in satisfaction of their claims. Contemporaneously with the reorganization transactions and pursuant to the Plan, (i) LAC assigned all of its rights, title and interest in the membership interests of Berry to Berry Petroleum Corporation, (ii) all of the equity interests in LAC and the Predecessor were canceled and (iii) LAC and the Predecessor commenced liquidation, which is expected to be completed following the resolution of the respective companies’ outstanding claims.
The holders of claims under the Predecessor’s Sixth Amended and Restated Credit Agreement (“Predecessor Credit Facility”) received a full recovery, consisting of a cash paydown and their pro rata share of the $1.7 billion Successor Credit Facility. As a result, all outstanding obligations under the Predecessor Credit Facility were canceled.
Holdco II, as borrower, entered into the Successor Credit Facility with the holders of claims under the Predecessor Credit Facility, as lenders, and Wells Fargo Bank, National Association, as administrative agent, providing for a new reserve-based revolving loan with up to $1.4 billion in borrowing commitments and a new term loan in an original principal amount of $300 million. For additional information, see “Financing Activities” below.
The holders of the Company’s 12.00% senior secured second lien notes due December 2020 (the “Second Lien Notes”) received their pro rata share of (i) 17,678,889 shares of Class A common stock; (ii) certain rights to purchase shares of Class A common stock in the rights offerings, as described below; and (iii) $30 million in cash. The holders of the Company’s 6.50% senior notes due May 2019, 6.25% senior notes due November 2019, 8.625% senior notes due 2020, 7.75% senior notes due February 2021 and 6.50% senior notes due September 2021 (collectively, the “Unsecured Notes”) received their pro rata share of (i) 26,724,396 shares of Class A common stock; and (ii) certain rights to purchase shares of Class A common stock in the rights offerings, as described below. As a result, all outstanding obligations under the Second Lien Notes and the Unsecured Notes and the indentures governing such obligations were canceled.
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
The holders of general unsecured claims (other than claims relating to the Second Lien Notes and the Unsecured Notes) against the LINN Debtors (the “LINN Unsecured Claims”) received their pro rata share of cash from two cash distribution pools totaling $40 million, as divided between a $2.3 million cash distribution pool for the payment in full of allowed LINN Unsecured Claims in an amount equal to $2,500 or less (and larger claims for which the holders irrevocably agreed to reduce such claims to $2,500), and a $37.7 million cash distribution pool for pro rata distributions to all remaining allowed general LINN Unsecured Claims. As a result, all outstanding LINN Unsecured Claims were fully satisfied, settled, released and discharged as of the Effective Date.
All units of the Predecessor that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery. On the Effective Date, the Successor issued in the aggregate 89,229,892 shares of Class A common stock. No cash was raised from the issuance of the Class A common stock on account of claims held by the Predecessor’s creditors.
The Successor entered into a registration rights agreement with certain parties, pursuant to which the Company agreed to, among other things, file a registration statement with the Securities and Exchange Commission within 60 days of the Effective Date covering the offer and resale of “Registrable Securities” (as defined therein).
By operation of the Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. The Successor formed a new board of directors, consisting of the Chief Executive Officer of the Predecessor, one director selected by the Successor and five directors selected by a six-person selection committee.
Rights Offerings
On October 25, 2016, the Company entered into a backstop commitment agreement (“Backstop Commitment Agreement”) with the parties thereto (collectively, the “Backstop Parties”). In accordance with the Plan, the Backstop Commitment Agreement and the rights offerings procedures filed in the Chapter 11 cases and approved by the Bankruptcy Court, the LINN Debtors offered eligible creditors the right to purchase Class A common stock upon emergence from the Chapter 11 cases for an aggregate purchase price of $530 million.
Under the Backstop Commitment Agreement, certain Backstop Parties agreed to purchase their pro rata share of the shares that were not duly subscribed to pursuant to the offerings at the discounted per share price set forth in the Backstop Commitment Agreement by parties other than Backstop Parties. Pursuant to the Backstop Commitment Agreement, the LINN Debtors agreed to pay the Backstop Parties on the Effective Date a commitment premium equal to 4.0% of the $530 million committed amount, of which 3.0% was paid in cash and 1.0% was paid in the form of Class A common stock at the discounted per share price set forth in the Backstop Commitment Agreement.
On the Effective Date, all conditions to the rights offerings and the Backstop Commitment Agreement were met, and the LINN Debtors completed the rights offerings and the related issuances of Class A common stock.
Divestitures
Below are the Company’s completed divestitures in 2017:
On September 12, 2017, August 1, 2017, and July 31, 2017, the Company completed the sales of its interest in certain properties located in south Texas (the “South Texas Assets Sales”). Combined cash proceeds received from the sale of these properties were approximately $49 million, net of costs to sell of approximately $1 million, and the Company recognized a combined net gain of approximately $14 million.
On August 23, 2017, July 28, 2017, and May 9, 2017, the Company completed the sales of its interest in certain properties located in Texas and New Mexico (the “Permian Assets Sales”). Combined cash proceeds received from the sale of these properties were approximately $31 million and the Company recognized a combined net gain of approximately $29 million.
On July 31, 2017, the Company completed the sale of its interest in properties located in the San Joaquin Basin in California to Berry Petroleum Company, LLC (the “San Joaquin Basin Sale”). Cash proceeds received from the sale
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
of these properties were approximately $253 million, net of costs to sell of approximately $4 million, and the Company recognized a net gain of approximately $120 million.
On July 21, 2017, the Company completed the sale of its interest in properties located in the Los Angeles Basin in California to Bridge Energy LLC (the “Los Angeles Basin Sale”). Cash proceeds received from the sale of these properties were approximately $93 million, net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $2 million. The Company will receive an additional $7 million contingent payment if certain operational requirements are satisfied within one year.
On June 30, 2017, the Company completed the sale of its interest in properties located in the Salt Creek Field in Wyoming to Denbury Resources Inc. (the “Salt Creek Assets Sale”). Cash proceeds received from the sale of these properties were approximately $75 million, net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $33 million.
On May 31, 2017, the Company completed the sale of its interest in properties located in western Wyoming to Jonah Energy LLC (the “Jonah Assets Sale”). Cash proceeds received from the sale of these properties were approximately $560 million, net of costs to sell of approximately $6 million, and the Company recognized a net gain of approximately $272 million.
As a result of the Company’s strategic exit from California (completed by the San Joaquin Basin Sale and Los Angeles Basin Sale), the Company classified the assets and liabilities, results of operations and cash flows of its California properties as discontinued operations on its condensed consolidated financial statements.
Divestitures – Pending
On October 20, 2017, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its interest in properties located in the Williston Basin for a contract price of $285 million, subject to closing adjustments.
On October 3, 2017, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its interest in properties located in Wyoming for a contract price of $200 million, subject to closing adjustments.
Proceeds from these sales are expected to be added as additional cash on the Company’s balance sheet to be used for funding of the Company’s announced share repurchase program and other general corporate purposes. The sales are anticipated to close on November 30, 2017, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
The Company continues to market the previously announced non-core assets located in the Permian Basin and south Texas.
Roan Contribution
On August 31, 2017, the Company, through certain of its subsidiaries, completed the transaction in which LINN Energy and Citizen Energy II, LLC (“Citizen”) each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan (the contribution, the “Roan Contribution”), focused on the accelerated development of the Merge/SCOOP/STACK play. In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan, subject to customary post-closing adjustments. As of August 31, 2017, the date of the Roan Contribution, the Company recognized its equity investment at a carryover basis of approximately $452 million.
Construction of Cryogenic Plant
In July 2017 the Company renamed its subsidiary LINN Midstream, LLC to Blue Mountain Midstream LLC (“Blue Mountain”) and entered into a definitive agreement with BCCK Engineering, Inc. (“BCCK”) to construct the Chisholm Trail Cryogenic Gas Plant. Blue Mountain’s assets include the Chisholm Trail midstream business (“Chisholm Trail”) located in Oklahoma. Chisholm Trail is located in the Merge/SCOOP/STACK play in the Mid-Continent region and has approximately 30 miles of existing natural gas gathering pipeline and approximately 60 MMcf/d of current refrigeration capacity. Infrastructure expansions are underway to add 35 miles of low pressure gathering, increase compression throughput and
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
construct a new cryogenic plant to improve liquids recoveries. Blue Mountain has entered into a definitive agreement with BCCK to construct a 225 MMcf/d cryogenic natural gas processing facility with a total capacity of 250 MMcf/d. Construction is underway and it is expected to be commissioned during the second quarter of 2018.
2017 Oil and Natural Gas Capital Budget
For 2017, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $360 million, including approximately $245 million related to its oil and natural gas capital program and approximately $107 million related to its plant and pipeline capital. This estimate is under continuous review and subject to ongoing adjustments.
Financing Activities
Revolving Credit Facility
On August 4, 2017, the Company entered into a credit agreement with Holdco II, as borrower, Royal Bank of Canada, as administrative agent, and the lenders and agents party thereto, providing for a new senior secured reserve-based revolving loan facility (the “Revolving Credit Facility”) with $500 million in borrowing commitments and an initial borrowing base of $500 million.
As of September 30, 2017, there were no borrowings outstanding under the Revolving Credit Facility and there was approximately $455 million of available borrowing capacity (which includes a $45 million reduction for outstanding letters of credit). The maturity date is August 4, 2020.
Redetermination of the borrowing base under the Revolving Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October, with the first scheduled borrowing base redetermination to occur on March 15, 2018. At the Company’s election, interest on borrowings under the Revolving Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin ranging from 2.50% to 3.50% per annum or the alternate base rate (“ABR”) plus an applicable margin ranging from 1.50% to 2.50% per annum, depending on utilization of the borrowing base. Interest is generally payable in arrears quarterly for loans bearing interest based at the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR, or if such interest period is longer than three months, at the end of the three month intervals during such interest period. The Company is required to pay a commitment fee to the lenders under the Revolving Credit Facility, which accrues at a rate per annum of 0.50% on the average daily unused amount of the available revolving loan commitments of the lenders.
The obligations under the Revolving Credit Facility are secured by mortgages covering approximately 85% of the total value of the proved reserves of the oil and natural gas properties of the Company and certain of its subsidiaries, along with liens on substantially all personal property of the Company and certain of its subsidiaries, and are guaranteed by the Company, Holdco and certain of Holdco II’s subsidiaries, subject to customary exceptions. Under the Revolving Credit Facility, the Company is required to maintain (i) a maximum total net debt to last twelve months EBITDA ratio of 4.0 to 1.0, and (ii) a minimum adjusted current ratio of 1.0 to 1.0.
The Revolving Credit Facility also contains affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, mergers, consolidations and sales of assets, paying dividends or other distributions in respect of, or repurchasing or redeeming, the Company’s capital stock, making certain investments and transactions with affiliates.
The Revolving Credit Facility contains events of default and remedies customary for credit facilities of this nature. Failure to comply with the financial and other covenants in the Revolving Credit Facility would allow the lenders, subject to customary cure rights, to require immediate payment of all amounts outstanding under the Revolving Credit Facility.
In September 2017, the Company entered into an amendment to the Revolving Credit Facility to provide for, among other things, an increase in the size of the letter of credit subfacility from $25 million to $50 million.
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Share Repurchase Program
On June 1, 2017, the Company’s Board of Directors announced that it had authorized the repurchase of up to $75 million of the Company’s outstanding shares of Class A common stock. On June 28, 2017, the Company’s Board of Directors announced that it had authorized an increase in the previously announced share repurchase program to up to a total of $200 million of the Company’s outstanding shares of Class A common stock. Any share repurchases are subject to restrictions in the Revolving Credit Facility. During the period from June 2017 through September 2017, the Company repurchased an aggregate of 4,607,598 shares of Class A common stock at an average price of $34.06 per share for a total cost of approximately $157 million.
On October 4, 2017, the Company’s Board of Directors announced that it had authorized an additional increase in the previously announced share repurchase program to up to a total of $400 million of the Company’s outstanding shares of a Class A common stock. In October 2017, the Company repurchased 590,118 shares of Class A common stock at an average price of $38.09 per share for a total cost of approximately $22 million. At October 31, 2017, approximately $221 million was available for share repurchases under the program.
Listing on the OTCQB Market
On the Effective Date, the Predecessor’s units were canceled and ceased to trade on the OTC Markets Group Inc.’s Pink marketplace. In April 2017, the Successor’s Class A common stock was approved for trading on the OTCQB market under the symbol “LNGG.”
Commodity Derivatives
In October 2017, the Company entered into commodity derivative contracts consisting of natural gas swaps for January 2018 through December 2018. Including these new hedges, as of October 31, 2017, the Company had natural gas swaps of approximately 69,715 MMMBtu at an average price of approximately $3.02 per MMBtu for 2018.
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Results of Operations
Three Months Ended September 30, 2017, Compared to Three Months Ended September 30, 2016
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | | | Three Months Ended September 30, 2017 | | | Three Months Ended September 30, 2016 | | Variance | | (in thousands) | | | | | | | | Revenues and other: | | | | | | | | Natural gas sales | $ | 92,470 |
| | | $ | 121,842 |
| | $ | (29,372 | ) | | Oil sales | 74,384 |
| | | 82,244 |
| | (7,860 | ) | | NGL sales | 39,464 |
| | | 33,900 |
| | 5,564 |
| | Total oil, natural gas and NGL sales | 206,318 |
| | | 237,986 |
| | (31,668 | ) | | Gains (losses) on oil and natural gas derivatives | (14,497 | ) | | | 166 |
| | (14,663 | ) | Marketing and other revenues (1) | 44,861 |
| | | 28,823 |
| | 16,038 |
| | | 236,682 |
| | | 266,975 |
| | (30,293 | ) | | Expenses: | | | | | | | | Lease operating expenses | 61,272 |
| | | 67,234 |
| | (5,962 | ) | | Transportation expenses | 34,541 |
| | | 40,986 |
| | (6,445 | ) | | Marketing expenses | 34,099 |
| | | 6,933 |
| | 27,166 |
| General and administrative expenses (2) | 30,035 |
| | | 48,471 |
| | (18,436 | ) | | Exploration costs | 171 |
| | | 4 |
| | 167 |
| | Depreciation, depletion and amortization | 29,657 |
| | | 87,413 |
| | (57,756 | ) | | Impairment of long-lived assets | — |
| | | 41,728 |
| | (41,728 | ) | | Taxes, other than income taxes | 12,368 |
| | | 18,003 |
| | (5,635 | ) | | (Gains) losses on sale of assets and other, net | (26,977 | ) | | | 2,532 |
| | (29,509 | ) | | | 175,166 |
| | | 313,304 |
| | (138,138 | ) | | Other income and (expenses) | (1,885 | ) | | | (25,261 | ) | | 23,376 |
| | Reorganization items, net | (2,605 | ) | | | (28,361 | ) | | 25,756 |
| | Income (loss) from continuing operations before income taxes | 57,026 |
| | | (99,951 | ) | | 156,977 |
| | Income tax expense (benefit) | 5,996 |
| | | (3,650 | ) | | 9,646 |
| | Income (loss) from continuing operations | 51,030 |
| | | (96,301 | ) | | 147,331 |
| | Income (loss) from discontinued operations, net of income taxes | 86,099 |
| | | (102,064 | ) | | 188,163 |
| | Net income (loss) | 137,129 |
| | | (198,365 | ) | | 335,494 |
| | Net income attributable to noncontrolling interests | 66 |
| | | — |
| | 66 |
| | Net income (loss) attributable to common stockholders/unitholders | $ | 137,063 |
| | | $ | (198,365 | ) | | $ | 335,428 |
|
| | (1)
| Marketing and other revenues for the three months ended September 30, 2016, include approximately $14 million2018 reflects the adoption of management fee revenues recognized byASC 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 Company from Berry. Management fee revenues are included in “other revenues” onmodified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the condensed consolidated statement of operations.previous revenue standard. |
| | (2) | General and administrative expenses for the three months ended September 30, 2017, and September 30, 2016,2018 include approximately $6$2.9 million, and $5 million, respectively,or $0.69 per Boe, of noncash share-basedequity-based compensation expenses. In addition, general and administrative expenses for the three months ended September 30, 2016, include expenses incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from Bankruptcy as stand-alone, unaffiliated entities.expense. |
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
| | | | | | | | | | | | | | | Successor | | | Predecessor | | | | | Three Months Ended September 30, 2017 | | | Three Months Ended September 30, 2016 | | Variance | | Average daily production: | | | | | | | | Natural gas (MMcf/d) | 368 |
| | | 518 |
| | (29 | )% | | Oil (MBbls/d) | 17.7 |
| | | 22.0 |
| | (20 | )% | | NGL (MBbls/d) | 18.5 |
| | | 26.6 |
| | (30 | )% | | Total (MMcfe/d) | 586 |
| | | 809 |
| | (28 | )% | | | | | | | | | Average daily production – Equity method investments: (1) | | | | | | | | Total (MMcfe/d) | 23 |
| | | — |
| | | | | | | | | | | Weighted average prices: (2) | | | | | | | | Natural gas (Mcf) | $ | 2.73 |
| | | $ | 2.56 |
| | 7 | % | | Oil (Bbl) | $ | 45.58 |
| | | $ | 40.60 |
| | 12 | % | | NGL (Bbl) | $ | 23.18 |
| | | $ | 13.87 |
| | 67 | % | | | | | | | | | | Average NYMEX prices: | | | | | | | | Natural gas (MMBtu) | $ | 3.00 |
| | | $ | 2.81 |
| | 7 | % | | Oil (Bbl) | $ | 48.20 |
| | | $ | 44.94 |
| | 7 | % | | | | | | | | | | Costs per Mcfe of production: | | | | | | | | Lease operating expenses | $ | 1.14 |
| | | $ | 0.90 |
| | 27 | % | | Transportation expenses | $ | 0.64 |
| | | $ | 0.55 |
| | 16 | % | General and administrative expenses (3) | $ | 0.56 |
| | | $ | 0.65 |
| | (14 | )% | | Depreciation, depletion and amortization | $ | 0.55 |
| | | $ | 1.17 |
| | (53 | )% | | Taxes, other than income taxes | $ | 0.23 |
| | | $ | 0.24 |
| | (4 | )% | | | | | | | | | Average daily production – discontinued operations: (4) | | | | | | | | Total (MMcfe/d) | 8 |
| | | 265 |
| |
|
|
| | (1)
| Represents the Company’s 50% equity interest in Roan. Production of Roan for 2017 is for the period from September 1, 2017 through September 30, 2017. |
| | (2)
| Does not include the effect of gains (losses) on derivatives. |
| | (3)
| General and administrativesaltwater disposal, monitoring, pumping, chemicals, maintenance, repairs, workover expenses for the three months ended September 30, 2017, and September 30, 2016, include approximately $6 million and $5 million, respectively, of noncash share-based compensation expenses. In addition, general and administrative expenses for the three months ended September 30, 2016, include expenses incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from Bankruptcy as stand-alone, unaffiliated entities. |
| | (4)
| Production of discontinued operations for 2017 is for the period from July 1, 2017 through July 31, 2017. |
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Revenues and Other
Oil, Natural Gasdirect labor and NGL Sales
Oil, natural gas and NGL sales decreased by approximately $32overhead related to production activities. Production expenses were $14.7 million, or 13% to approximately $206$3.44 per Boe, for the three months ended September 30, 2018, which was an increase of $10.4 million, or 240%, from $4.3 million for the three months ended September 30, 2017. The increase in production expenses during 2018 compared to 2017 was primarily due to increased production. The increase in production expenses per Boe was primarily driven by increases in maintenance and surface repairs incurred during the three months ended September 30, 2018.
Gathering, transportation and processing. These costs are incurred to get oil, natural gas and NGLs to market. Gathering, transportation, and processing costs were $4.9 million, or $3.18 per Boe, for the three months ended September 30, 2017. As a result of adopting ASC 606 in January 2018, these costs are reflected as a deduction from approximately $238revenue for the three months ended September 30, 2018. Production taxes. Production taxes are paid on produced oil, natural gas, and NGLs based primarily on a percentage of sales revenues from production sold at fixed rates established by federal, state or local taxing authorities. Production taxes were $6.2 million for the three months ended September 30, 2016,2018, an increase of $5.4 million, or 633%, from $0.8 million for the three months ended September 30, 2017. Production taxes primarily increased due to lowerincreased revenues and increased production volumes partially offsettax rates, which became effective in July 2018. Exploration expenses. These are primarily geological and geophysical costs that include seismic survey costs, amortization of the costs of unproved properties assessed for impairment on a group basis, costs of carrying and retaining unproved properties, and costs related to unsuccessful leasing efforts. For the three months ended September 30, 2018, exploration expenses of $11.6 million primarily consisted of unproved leasehold amortization. Unproved leasehold amortization is calculated by higher commodity prices. Higher NGL,considering our drilling plans and the lease terms of our existing unproved properties. For the three months ended September 30, 2017, exploration expenses of $4.2 million consisted of impairment expense recognized related to our unproved properties. The increase in exploration expenses is due, in part, to amortization of unproved leasehold associated with the oil and natural gas prices resulted in an increase in revenues of approximately $16properties contributed by Linn. Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion was $37.2 million, $8or $8.69 per Boe, for the three months ended September 30, 2018, compared to $10.8 million, and $5 million, respectively. Average daily production volumes decreased to approximately 586 MMcfe/dor $7.04 per Boe, for the three months ended September 30, 2017, from 809 MMcfe/dwhich is an increase of $26.3 million or 243%. The increase in depreciation, depletion, amortization and accretion was primarily due to increased production.
General and administrative. General and administrative expenses were $13.2 million, or $3.08 per Boe, for the three months ended September 30, 2016. Lower natural gas, oil and NGL production volumes resulted in a decrease in revenues2018, an increase of approximately $35 million, $16 million and $10 million, respectively. The following table sets forth average daily production by region:
| | | | | | | | | | | | | | | | | Successor | | | Predecessor | | | | | | | Three Months Ended September 30, 2017 | | | Three Months Ended September 30, 2016 | | Variance | | Average daily production (MMcfe/d): | | | | | | | | | | Rockies | 160 |
| | | 343 |
| | (183 | ) | | (54 | )% | | Hugoton Basin | 171 |
| | | 178 |
| | (7 | ) | | (4 | )% | | Mid-Continent | 91 |
| | | 102 |
| | (11 | ) | | (11 | )% | | TexLa | 81 |
| | | 73 |
| | 8 |
| | 12 | % | | Permian Basin | 43 |
| | | 54 |
| | (11 | ) | | (19 | )% | | Michigan/Illinois | 29 |
| | | 30 |
| | (1 | ) | | (6 | )% | | South Texas | 11 |
| | | 29 |
| | (18 | ) | | (62 | )% | | | 586 |
| | | 809 |
| | (223 | ) | | (28 | )% | | Equity method investments | 23 |
| | — |
| — |
| | | | |
The increase in average daily production volumes in the TexLa region primarily reflects increased development capital spending in the region. The decrease in average daily production volumes in the Mid-Continent region primarily reflects lower production volumes as a result of the Roan Contribution on August 31, 2017, partially offset by increased development capital spending in the region. The decreases in average daily production volumes in the Rockies, Permian Basin and South Texas regions primarily reflect lower production volumes as a result of divestitures completed during 2017. See Note 4 for additional information of divestitures. In addition, the decreases in average daily production volumes in these and the remaining regions reflect lower production volumes as a result of reduced development capital spending, as well as marginal well shut-ins, driven by continued low commodity prices. Equity method investments represents the Company’s 50% equity interest in Roan. Production of Roan for 2017 is for the period from September 1, 2017 through September 30, 2017.
Gains (Losses) on Oil and Natural Gas Derivatives
Losses on oil and natural gas derivatives were approximately $14 million for the three months ended September 30, 2017, compared to gains of approximately $166,000 for the three months ended September 30, 2016, representing a variance of approximately $15 million. Gains and losses on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts. The fair value on unsettled derivative contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” and Note 8 and Note 9 for additional details about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” under “Liquidity and Capital Resources” below.
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Marketing and Other Revenues
Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities. Other revenues primarily include management fee revenues recognized by the Company from Berry (in the Predecessor period) and helium sales revenue. Marketing and other revenues increased by approximately $16$8.7 million or 56% to approximately $45 million for the three months ended September 30, 2017,194% from approximately $29 million for the three months ended September 30, 2016. The increase was primarily due to higher revenues generated by the Jayhawk natural gas processing plant in Kansas, principally driven by a change in contract terms, and higher helium sales revenue in the Hugoton Basin, partially offset by the management fee revenues from Berry included in the Predecessor period.
Expenses
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $6$4.5 million, or 9% to approximately $61 million for the three months ended September 30, 2017, from approximately $67 million for the three months ended September 30, 2016. The decrease was primarily due to reduced labor costs for field operations as a result of cost savings initiatives and the divestitures completed in 2017. Lease operating expenses$2.92 per Mcfe increased to $1.14 per Mcfe for the three months ended September 30, 2017, from $0.90 per Mcfe for the three months ended September 30, 2016.
Transportation Expenses
Transportation expenses decreased by approximately $6 million or 16% to approximately $35 million for the three months ended September 30, 2017, from approximately $41 million for the three months ended September 30, 2016. The decrease was primarily due to reduced costs as a result of lower production volumes and as a result of the divestitures completed in 2017. Transportation expenses per Mcfe increased to $0.64 per Mcfe for the three months ended September 30, 2017, from $0.55 per Mcfe for the three months ended September 30, 2016, primarily due to lower unit rates on the properties sold in 2017.
Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses increased by approximately $27 million or 392% to approximately $34 million for the three months ended September 30, 2017, from approximately $7 million for the three months ended September 30, 2016. The increase was primarily due to higher expenses associated with the Jayhawk natural gas processing plant in Kansas, principally driven by a change in contract terms.
General and Administrative Expenses
General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees. In addition, general and administrative expenses in the Predecessor period includes expenses incurred by LINN Energy associated with the operations of Berry. General and administrative expenses decreased by approximately $18 million or 38% to approximately $30 million for the three months ended September 30, 2017, from approximately $48 million for the three months ended September 30, 2016. The decrease was primarily due to lower salaries and benefits related expenses, the costs associated with the operations of Berry in the Predecessor period and lower various other administrative expenses including insurance and rent, partially offset by higher noncash share-based compensation expenses and higher professional services expenses. General and administrative expenses per Mcfe also decreased to $0.56 per Mcfe for the three months ended September 30, 2017, from $0.65 per Mcfe for the three months ended September 30, 2016.
For the professional services expenses related to the Chapter 11 proceedings that were incurred since the Petition Date, see “Reorganization Items, Net.”
Exploration Costs
Exploration costs increased by approximately $167,000 to approximately $171,000 for the three months ended September 30, 2017, from approximately $4,000 for the three months ended September 30, 2016. The increase was primarily due to higher seismic data expenses.
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by approximately $57 million or 66% to approximately $30 million for the three months ended September 30, 2017, from approximately $87 million for the three months ended September 30, 2016. The decrease was primarily due to lower rates as a result of the application of fresh start accounting, as well as lower total production volumes. Depreciation, depletion and amortization per Mcfe also decreased to $0.55 per Mcfe for the three months ended September 30, 2017, from $1.17 per Mcfe for the three months ended September 30, 2016.
Impairment of Long-Lived Assets
The Company recorded no impairment chargesBoe, for the three months ended September 30, 2017. During the three months ended September 30, 2016, the Company recorded an impairment charge2018, general and administrative expenses included salaries and benefits of approximately $42$6.9 million associated with proved oil and natural gas propertiesequity-based compensation expense of $2.9 million. There were no such expenses incurred in the Mid-Continentthree months ended September 30, 2017. These expenses were offset by fees paid to Citizen and Rockies regions due to a declineLinn under the MSAs of $2.5 million during the three months ended September 30, 2017. The MSAs with Citizen and Linn concluded in commodity prices, changes in expected capital development and a decline in the Company’s estimatesApril 2018.
Other Expenses Interest expense, net. Interest expense, net of proved reserves. Taxes, Other Than Income Taxes
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | | | Three Months Ended September 30, 2017 | | | Three Months Ended September 30, 2016 | | Variance | | (in thousands) | | | | | | | | Severance taxes | $ | 7,610 |
| | | $ | 10,871 |
| | $ | (3,261 | ) | | Ad valorem taxes | 4,983 |
| | | 7,120 |
| | (2,137 | ) | | Other | (225 | ) | | | 12 |
| | (237 | ) | | | $ | 12,368 |
| | | $ | 18,003 |
| | $ | (5,635 | ) |
Taxes, other than income taxes decreased by approximately $6 million or 31%capitalized interest, for the three months ended September 30, 2017,2018 was $2.1 million as compared to $0.3 million for the three months ended September 30, 2017. This increase was due to increased borrowings outstanding during the three months ended September 30, 2018 as compared to the three months ended September 30, 2016. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower production volumes partially offset by higher commodity prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, decreased primarily due to divestitures completed in 2017 and lower estimated valuations on certain of the Company’s properties.2017.
(Gains) Losses on Sale of Assets and Other, Net
DuringIncome tax expense. Income tax expense for the three months ended September 30, 2018 was $299.7 million and relates to the recognition of a deferred tax liability upon becoming a taxable entity in conjunction with the Reorganization.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017 The following table presents selected financial and operating information for the Company recorded the following amounts related to divestitures (see Note 4): Advisory fees of approximately $17 million associated with the Roan Contribution;
Net gain of approximately $25 million on the Permian Assets Sales; and
Net gain of approximately $14 million, including costs to sell of approximately $1 million, on the South Texas Assets Sales.
Other Income and (Expenses)periods presented.
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | | | Three Months Ended September 30, 2017 | | | Three Months Ended September 30, 2016 | | Variance | | (in thousands) | | | | | | | | Interest expense, net of amounts capitalized | $ | (223 | ) | | | $ | (25,283 | ) | | $ | 25,060 |
| | Earnings from equity method investments | 2,575 |
| | | 222 |
| | 2,353 |
| | Other, net | (4,237 | ) | | | (200 | ) | | (4,037 | ) | | | $ | (1,885 | ) | | | $ | (25,261 | ) | | $ | 23,376 |
|
| | | | | | | | | | | Nine Months Ended
September 30, | | | 2018 | | 2017 | | Production Data | | | | | Oil (MBbls) | 3,004 |
| | 884 |
| | Natural gas (MMcf) | 29,486 |
| | 10,523 |
| | Natural gas liquids (MBbls) | 3,042 |
| | 911 |
| | Total volumes (MBoe) | 10,960 |
| | 3,549 |
| | Average daily total volumes (MBoe/d) | 40.1 |
| | 13.0 |
| Average Prices - as reported (1) | | | | | Oil (per Bbl) | $ | 65.70 |
| | $ | 51.70 |
| | Natural gas (per Mcf) | $ | 1.66 |
| | $ | 2.93 |
| | Natural gas liquids (per Bbl) | $ | 21.49 |
| | $ | 24.20 |
| | Total (per Boe) | $ | 28.44 |
| | $ | 27.79 |
| Average Prices - including impact of derivative contract settlements (1)(2) | | | | | Oil (per Bbl) | $ | 55.70 |
| | $ | 51.70 |
| | Natural gas (per Mcf) | $ | 1.73 |
| | $ | 2.95 |
| | Natural gas liquids (per Bbl) | $ | 21.49 |
| | $ | 24.20 |
| | Total (per Boe) | $ | 25.90 |
| | $ | 27.83 |
| Average Prices - excluding gathering, transportation and processing costs (3) | | | | Oil (per Bbl) | $ | 65.72 |
| | $ | 51.70 |
| | Natural gas (per Mcf) | $ | 2.07 |
| | $ | 2.93 |
| | Natural gas liquids (per Bbl) | $ | 27.53 |
| | $ | 24.20 |
| | Total (per Boe) | $ | 31.21 |
| | $ | 27.79 |
|
| | Item 2.(1) | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Other income and (expenses) decreased by approximately $23 million or 93%Average prices for the three months ended September 30, 2017, compared to the three months ended September 30, 2016. Interest expense decreased due to lower outstanding debt during the period. For the three months ended September 2016, contractual interest, which was not recorded, on the senior notes was approximately $56 million. See “Debt” under “Liquidity and Capital Resources” below for additional details.
The Second Lien Notes were accounted for as a troubled debt restructuring which requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized. For the three months ended September 30, 2016, contractual interest, which was not recorded, on the Second Lien Notes was approximately $30 million.
Equity method investments primarily include the Company’s 50% equity interest in Roan. The Company’s equity earnings consists of its share of Roan’s earnings and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets. See Note 4 for additional information.
Reorganization Items, Net
The Company incurred significant costs and recognized significant gains associated with the reorganization. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined. The following table summarizes the components of reorganization items included on the condensed consolidated statements of operations:
| | | | | | | | | | | | Successor | | | Predecessor | | | Three Months Ended September 30, 2017 | | | Three Months Ended September 30, 2016 | | (in thousands) | | | | | | Legal and other professional advisory fees | $ | (2,549 | ) | | | $ | (16,714 | ) | | Terminated contracts | — |
| | | (13,123 | ) | | Other | (56 | ) | | | 1,476 |
| | Reorganization items, net | $ | (2,605 | ) | | | $ | (28,361 | ) |
Income Tax Expense (Benefit)
Effective February 28, 2017, upon the consummation of the Plan, the Successor became a C corporation. Prior to the consummation of the Plan, the Predecessor was a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits were passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. The Company recognized income tax expense of approximately $6 million and an income tax benefit of approximately $4 million for the three months ended September 30, 2017, and September 30, 2016, respectively.
Income (loss) from Discontinued Operations, Net of Income Taxes
As a result of the Company’s strategic exit from California (completed by the San Joaquin Basin Sale and Los Angeles Basin Sale) and the deconsolidation of Berry, the Company has classified the results of operations of its California properties and Berry as discontinued operations. Income from discontinued operations, net of income taxes was approximately $86 million for the three months ended September 30, 2017, compared to loss from discontinued operations, net of income taxes of approximately $l02 million for the three months ended and September 30, 2016. See Note 4 for additional information.
Net Income (Loss) Attributable to Common Stockholders/Unitholders
Net income attributable to common stockholders/unitholders increased by approximately $335 million to approximately $137 million for the three months ended September 30, 2017, from a net loss of approximately $198 million for the three months ended September 30, 2016. The increase was primarily due to lower expenses, including interest, and gains on the divestitures completed in 2017, partially offset by lower production revenues, losses compared to gains on commodity derivatives and income tax expense compared to income tax benefit. See discussion above for explanations of variances.
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Results of Operations
The following table reflects the Company’s results of operations for each of the Successor and Predecessor periods presented:
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | Revenues and other: | | | | | | | | Natural gas sales | $ | 241,021 |
| | | $ | 99,561 |
| | $ | 300,585 |
| | Oil sales | 193,859 |
| | | 58,560 |
| | 228,766 |
| | NGL sales | 94,930 |
| | | 30,764 |
| | 88,923 |
| | Total oil, natural gas and NGL sales | 529,810 |
| | | 188,885 |
| | 618,274 |
| | Gains (losses) on oil and natural gas derivatives | 19,258 |
| | | 92,691 |
| | (74,175 | ) | Marketing and other revenues (1) | 68,741 |
| | | 16,551 |
| | 98,382 |
| | | 617,809 |
| | | 298,127 |
| | 642,481 |
| | Expenses: | | | | | | | | Lease operating expenses | 156,959 |
| | | 49,665 |
| | 220,847 |
| | Transportation expenses | 85,652 |
| | | 25,972 |
| | 124,609 |
| | Marketing expenses | 43,614 |
| | | 4,820 |
| | 21,493 |
| General and administrative expenses (2) | 74,904 |
| | | 71,745 |
| | 184,360 |
| | Exploration costs | 1,037 |
| | | 93 |
| | 2,745 |
| | Depreciation, depletion and amortization | 101,558 |
| | | 47,155 |
| | 262,880 |
| | Impairment of long-lived assets | — |
| | | — |
| | 165,044 |
| | Taxes, other than income taxes | 37,316 |
| | | 14,877 |
| | 53,544 |
| (Gains) losses on sale of assets and other, net | (333,371 | ) | | | 829 |
| | 6,607 |
| | | 167,669 |
| | | 215,156 |
| | 1,042,129 |
| | Other income and (expenses) | (15,057 | ) | | | (16,717 | ) | | (160,323 | ) | | Reorganization items, net | (8,547 | ) | | | 2,331,189 |
| | 457,437 |
| | Income (loss) from continuing operations before income taxes | 426,536 |
| | | 2,397,443 |
| | (102,534 | ) | | Income tax expense (benefit) | 159,451 |
| | | (166 | ) | | 2,944 |
| | Income (loss) from continuing operations | 267,085 |
| | | 2,397,609 |
| | (105,478 | ) | | Income (loss) from discontinued operations, net of income taxes | 82,845 |
| | | (548 | ) | | (1,232,141 | ) | | Net income (loss) | 349,930 |
| | | 2,397,061 |
| | (1,337,619 | ) | | Net income attributable to noncontrolling interests | 66 |
| | | — |
| | — |
| | Net income (loss) attributable to common stockholders/unitholders | $ | 349,864 |
| | | $ | 2,397,061 |
| | $ | (1,337,619 | ) |
| | (1)
| Marketing and other revenues for the two months ended February 28, 2017, and the nine months ended September 30, 2016, include approximately $6 million2018 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 $56 million, respectively,transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of management fee revenues recognized bytransition. Accordingly, comparative information has not been adjusted and continues to be reported under the Company from Berry. Management fee revenues are included in “other revenues” on the condensed consolidated statements of operations.previous revenue standard. |
| | (2) | GeneralExcludes settlement of derivative contracts prior to their contractual maturity. |
| | | (3) | Excludes the effects of netting gathering, transportation and administrative expensesprocessing costs under ASC 606. |
Revenues The following table provides information on our operating revenues: | | | | | | | | | | | Nine Months Ended
September 30, | | | 2018 | | 2017 | | | (in thousands) | | Revenues | | | | Oil sales (1) | $ | 197,356 |
| | $ | 45,702 |
| Natural gas sales (1) | 48,956 |
| | 30,884 |
| Natural gas liquid sales (1) | 65,377 |
| | 22,049 |
| | (Loss) gain on derivative contracts | (100,920 | ) | | 2,385 |
| | Total revenues | $ | 210,769 |
| | $ | 101,020 |
|
| | | (1) | Revenue for the seven months ended September 30, 2017, the two months ended February 28, 2017, and the nine months ended September 30, 2016, include approximately $26 million, $50 million2018 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 $19 million, respectively,transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of noncash share-based compensation expenses. In addition, generaltransition. Accordingly, comparative information has not been adjusted and administrative expenses forcontinues to be reported under the two months ended February 28, 2017, and the nine months ended September 30, 2016, include expenses incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities.previous revenue standard. |
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | Average daily production: | | | | | | | | Natural gas (MMcf/d) | 414 |
| | | 495 |
| | 521 |
| | Oil (MBbls/d) | 19.8 |
| | | 20.2 |
| | 22.6 |
| | NGL (MBbls/d) | 21.8 |
| | | 21.4 |
| | 25.8 |
| | Total (MMcfe/d) | 664 |
| | | 745 |
| | 812 |
| | | | | | | | | Average daily production – Equity method investments: (1) | | | | | | | | Total (MMcfe/d) | 10 |
| | | — |
| | — |
| | | | | | | | | Weighted average prices: (2) | | | | | | | | Natural gas (Mcf) | $ | 2.72 |
| | | $ | 3.41 |
| | $ | 2.10 |
| | Oil (Bbl) | $ | 45.71 |
| | | $ | 49.16 |
| | $ | 36.96 |
| | NGL (Bbl) | $ | 20.32 |
| | | $ | 24.37 |
| | $ | 12.57 |
| | | | | | | | | | Average NYMEX prices: | | | | | | | | Natural gas (MMBtu) | $ | 3.03 |
| | | $ | 3.66 |
| | $ | 2.29 |
| | Oil (Bbl) | $ | 48.45 |
| | | $ | 53.04 |
| | $ | 41.33 |
| | | | | | | | | | Costs per Mcfe of production: | | | | | | | | Lease operating expenses | $ | 1.11 |
| | | $ | 1.13 |
| | $ | 0.99 |
| | Transportation expenses | $ | 0.60 |
| | | $ | 0.59 |
| | $ | 0.56 |
| General and administrative expenses (3) | $ | 0.53 |
| | | $ | 1.63 |
| | $ | 0.83 |
| | Depreciation, depletion and amortization | $ | 0.72 |
| | | $ | 1.07 |
| | $ | 1.18 |
| | Taxes, other than income taxes | $ | 0.26 |
| | | $ | 0.34 |
| | $ | 0.24 |
| | | | | | | | | Average daily production – discontinued operations: (4) | | | | | | | | Total (MMcfe/d) | 20 |
| | | 30 |
| | 277 |
|
| | (1)
| Represents the Company’s 50% equity interest in Roan. Production of Roan for 2017 is for the period from September 1, 2017 through September 30, 2017. |
| | (2)
| Does not include the effect of gains (losses) on derivatives. |
| | (3)
| General and administrative expenses for the seven months ended September 30, 2017, the two months ended February 28, 2017, and the nine months ended September 30, 2016, include approximately $26 million, $50 million and $19 million, respectively, of noncash share-based compensation expenses. In addition, general and administrative expenses for the two months ended February 28, 2017, and the nine months ended September 30, 2016, include expenses incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities. |
| | (4)
| Production of discontinued operations for 2017 is for the period from January 1, 2017 through July 31, 2017. |
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Revenues and Other
Oil Natural Gas and NGL Sales Oil, natural gas and NGLSales. Our oil sales increased by approximately $101$151.7 million, or 16%332%, to approximately $530 million and $189 million for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, from approximately $618$197.4 million for the nine months ended September 30, 2016, due to higher commodity prices partially offset by lower production volumes. Higher natural gas, oil and NGL prices resulted in an increase in revenues of approximately $93 million, $52 million and $51 million, respectively.
Average daily production volumes decreased to approximately 664 MMcfe/d and 745 MMcfe/d for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively,2018 from approximately 812 MMcfe/d for the nine months ended September 30, 2016. Lower natural gas, oil and NGL production volumes resulted in a decrease in revenues of approximately $53 million, $28 million and $14 million, respectively.
The following table sets forth average daily production by region:
| | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | Average daily production (MMcfe/d): | | | | | | | | Rockies | 213 |
| | | 294 |
| | 339 |
| | Hugoton Basin | 168 |
| | | 159 |
| | 183 |
| | Mid-Continent | 111 |
| | | 109 |
| | 100 |
| | TexLa | 79 |
| | | 80 |
| | 72 |
| | Permian Basin | 45 |
| | | 49 |
| | 58 |
| | Michigan/Illinois | 29 |
| | | 29 |
| | 31 |
| | South Texas | 19 |
| | | 25 |
| | 29 |
| | | 664 |
| | | 745 |
| | 812 |
| | Equity method investments | 10 |
| | — |
| — |
| | — |
|
The increase from 2016 in average daily production volumes in the TexLa region primarily reflects increased development capital spending in the region. The increase in average daily production volumes in the Mid-Continent region primarily reflects increased development capital spending in the region, partially offset by lower production volumes as a result of the Roan Contribution on August 31, 2017. The decreases in average daily production volumes in the Rockies, Permian Basin and South Texas regions primarily reflect lower production volumes as a result of divestitures completed during 2017. See Note 4 for additional information of divestitures. In addition, the decreases in average daily production volumes in these and the remaining regions reflect lower production volumes as a result of reduced development capital spending, as well as marginal well shut-ins, driven by continued low commodity prices. Equity method investments represents the Company’s 50% equity interest in Roan. Production of Roan for 2017 is for the period from September 1, 2017 through September 30, 2017.
Gains (Losses) on Oil and Natural Gas Derivatives
Gains on oil and natural gas derivatives were approximately $19 million and $93 million for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, compared to losses on oil and natural gas derivatives of approximately $74$45.7 million for the nine months ended September 30, 2016, representing a variance of approximately $186 million. Gains and losses on2017. This increase was primarily due to the increase in production as well as the increase in average sales prices received for our produced volumes. Our oil production increased 2,120 MBbls, or 240%, to 3,004 MBbls for the nine months ended September 30, 2018 from 884 MBbls for the nine months ended September 30, 2017. The increase in production volumes was due to production associated with oil and natural gas derivatives were primarily due to changesproperties contributed by Linn in fair valueAugust 2017 and drilling activity in the fourth quarter of the derivative contracts.2017 and during 2018. The fair valueincrease in average sales prices received on unsettled derivative contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
The Company determines the fair value of itsour oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” and Note 8 and Note 9 for additional details about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” under “Liquidity and Capital Resources” below.
Marketing and Other Revenues
Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities. Other revenues primarily include management fee revenues recognized by the Company from Berry (in the Predecessor periods) and helium sales revenue. Marketing and other revenues decreased by approximately $12 million or 13% to approximately $69 million and $17 millionproduction for the sevennine months ended September 30, 2018 reflects the increase in the index price for oil in the 2018 period as compared to the 2017 and the two months ended February 28, 2017, respectively, fromperiod.
Natural Gas Sales. Our natural gas sales increased by approximately $98$18.1 million, or 59%, to $49.0 million for the nine months ended September 30, 2016. The decrease was primarily due to the management fee revenues2018 from Berry included in the Predecessor periods, partially offset by higher revenues generated by the Jayhawk natural gas processing plant in Kansas, principally driven by a change in contract terms, and higher helium sales revenue in the Hugoton Basin. Expenses
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $14 million or 6% to approximately $157 million and $50 million for the seven months ended September��30, 2017, and the two months ended February 28, 2017, respectively, from approximately $221$30.9 million for the nine months ended September 30, 2016. The decrease2017. This increase was primarily due to reduced laborthe increase in production, partially offset by a decrease in average sales prices received for those produced volumes and the impact of netting transportation costs for field operationswith revenue as a result of cost savings initiatives and the divestitures completed in 2017. Lease operating expenses per Mcfeadopting ASC 606. Our natural gas production increased 18,963 MMcf, or 180%, to $1.11 per Mcfe and $1.13 per Mcfe for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, compared to $0.99 per Mcfe29,486 MMcf for the nine months ended September 30, 2016.
Transportation Expenses
Transportation expenses decreased by approximately $13 million or 10% to approximately $86 million and $26 million2018 from 10,523 MMcf for the sevennine months ended September 30, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the twofourth quarter of 2017 and during 2018. The decrease in average sales prices received on our natural gas production for the nine months ended February 28,September 30, 2018 reflects the decrease in the Oklahoma index prices we received under our contract terms for natural gas in the 2018 period as compared to the 2017 respectively, fromperiod.
NGL Sales. Our NGL sales increased by approximately $125$43.3 million, or 197%, to $65.4 million for the nine months ended September 30, 2016. The decrease was primarily due to reduced costs as a result of lower production volumes and as a result of the divestitures completed in 2017. Transportation expenses per Mcfe increased to $0.60 per Mcfe and $0.59 per Mcfe for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, compared to $0.56 per Mcfe for the nine months ended September 30, 2016, primarily due to lower unit rates on the properties sold in 2017. Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses increased by approximately $28 million or 125% to approximately $44 million and $5 million for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, compared to approximately $212018 from $22.0 million for the nine months ended September 30, 2016. The2017. This increase was primarily due to higher expensesthe increase in production and an increase in the average sales prices received for those produced volumes, partially offset by the impact of netting transportation costs with revenue as a result of adopting ASC 606. Our NGL production increased 2,131 MBbls, or 234%, to 3,042 MBbls for the nine months ended September 30, 2018 from 911 MBbls the nine months ended September
30, 2017. The increase in production volumes was due to production associated with the Jayhawkoil and natural gas processing plantproperties contributed by Linn in Kansas, principally driven byAugust 2017 and drilling activity in the fourth quarter of 2017 and during 2018. (Loss) gain on derivative contracts. For the nine months ended September 30, 2018, changes in oil prices had a negative impact on the fair value and settlement of our derivative contracts. We had a loss on derivative contracts of $100.9 million, including loss on settlement of derivatives contracts of $27.5 million and unfavorable change in contract terms. General and Administrative Expenses
General and administrative expenses are costs not directly associated with field operations and reflect the costsfair value of employees including executive officers, related benefits, office leases and professional fees. In addition, general and administrative expenses inderivative contracts of $73.4 million. The loss on settlement of derivative contracts included $0.4 million net loss on settlement of derivative contracts prior to their maturity. We had a gain on derivative contracts of $2.4 million during the Predecessor periods include expenses incurred by LINN Energy associated with the operations of Berry. General and administrative expenses decreased by approximately $37 million or 20% to approximately $75 million and $72 million for the sevennine months ended September 30, 2017 andwhich included $2.3 million related to the twosettlement of derivative contracts prior to their contractual maturity.
Operating Expenses The following table provides information on our operating expenses: | | | | | | | | | | | Nine Months Ended
September 30, | | | 2018 | | 2017 | | | (in thousands, except per Boe) | | Operating Expenses | | | | | Production expenses | $ | 30,111 |
| | $ | 10,450 |
| Gathering, transportation and processing (1) | — |
| | 11,360 |
| | Production taxes | 10,892 |
| | 2,057 |
| | Exploration expenses | 30,129 |
| | 4,475 |
| | Depreciation, depletion, amortization and accretion | 83,630 |
| | 22,176 |
| General and administrative (2) | 40,283 |
| | 22,062 |
| | Gain on sale of oil and natural gas properties | — |
| | (838 | ) | | Total | $ | 195,045 |
| | $ | 71,742 |
| | Average Costs per Boe | | | | | Production expenses | $ | 2.75 |
| | $ | 2.94 |
| Gathering, transportation and processing (1) | — |
| | 3.20 |
| | Production taxes | 0.99 |
| | 0.58 |
| | Exploration expenses | 2.75 |
| | 1.26 |
| | Depreciation, depletion, amortization and accretion | 7.63 |
| | 6.25 |
| General and administrative (2) | 3.68 |
| | 6.22 |
| | Gain on sale of oil and natural gas properties | — |
| | (0.24 | ) | | Total | $ | 17.80 |
| | $ | 20.21 |
|
| | | (1) | Gathering, transportation and processing for the nine months ended September 30, 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 nine months ended September 30, 2018 include $8.1 million, or $0.74 per Boe, of equity-based compensation expense. |
Production expenses. Production expenses were $30.1 million, or $2.75 per Boe, for the nine months ended February 28,September 30, 2018, which was an increase of $19.7 million, or 188%, from $10.5 million, or $2.94 per Boe, for the nine months ended September 30, 2017. The increase in production expenses during 2018 compared to 2017 respectively,was primarily due to increased production. Due to certain production expenses being fixed, the increased production resulted in a decrease in production expense per Boe. Gathering, transportation and processing. Gathering, transportation, and processing costs were $11.4 million, or $3.20 per Boe, for the nine months ended September 30, 2017. As a result of adopting ASC 606 in January 2018, these costs are reflected as a deduction from approximately $184revenue for the nine months ended September 30, 2018.
Production taxes. Production taxes were $10.9 million for the nine months ended September 30, 2016. The decrease was primarily due to lower salaries and benefits related expenses, the costs associated with the operations2018, an increase of Berry in the Predecessor periods, lower various other administrative expenses including insurance and rent, and lower professional services expenses, partially offset by higher noncash share-based compensation expenses principally driven by the immediate vesting of certain awards on the Effective
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Date. General and administrative expenses per Mcfe were $0.53 per Mcfe and $1.63 per Mcfe for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, compared to $0.83 per Mcfe for the nine months ended September 30, 2016.
For professional services expenses related to the Chapter 11 proceedings that were incurred since the Petition Date, see “Reorganization Items, Net.”
Exploration Costs
Exploration costs decreased by approximately $2$8.8 million, to approximately $1 million and $93,000 for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively,or 430%, from approximately $3$2.1 million for the nine months ended September 30, 2016. The decrease was2017. Production taxes primarily increased due to lower seismic dataincreased revenues.
Exploration expenses. Depreciation, Depletion and Amortization
Depreciation, depletion and For the nine months ended September 30, 2018, exploration expenses of $30.1 million primarily consisted of amortization decreased by approximately $114 million or 43% to approximately $102 million and $47 million forof unproved leasehold. For the sevennine months ended September 30, 2017, exploration expenses of $4.5 million consisted of impairment expense recognized related to our unproved properties. The increase in exploration expenses is due, in part, to amortization of unproved leasehold associated with the oil and natural gas properties contributed by Linn.
Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion was $83.6 million, or $7.63 per Boe, for the twonine months ended February 28,September 30, 2018, and $22.2 million, or $6.25 per Boe, for the nine months ended September 30, 2017, respectively,which is an increase of $61.5 million or 277%. The increase in depreciation, depletion, amortization and accretion was primarily due to increased production and, to a lesser extent, an increase in the depletion rate for our oil and natural gas properties. The per Boe increase in the depletion rate is attributable to higher capital expenditures. General and administrative. General and administrative expenses were $40.3 million, or $3.68 per Boe, for the nine months ended September 30, 2018, an increase of $18.2 million or 83% from $22.1 million, or $6.22 per Boe, for the nine months ended September 30, 2017. During the nine months ended September 30, 2018, general and administrative expenses included salaries and benefits of $13.7 million, equity-based compensation expense of $8.1 million and fees paid to Citizen and Linn under the MSAs of $10.0 million. Additionally, we incurred consulting and professional fees as part of the implementation of systems and processes and transition efforts in 2018. These expenses were offset by bonuses paid by Citizen of approximately $263$9.0 million and fees paid under the MSAs of $2.5 million during the nine months ended September 30, 2017. The MSAs with Citizen and Linn concluded in April 2018. Other Expenses Interest expense, net. Interest expense, net of capitalized interest, for the nine months ended September 30, 2018 was $5.0 million as compared to $0.4 million for the nine months ended September 30, 2016. The decrease2017. This increase was primarily due to lower rates as a result ofincreased borrowings outstanding during the application of fresh start accounting and impairments recorded in the first quarter of 2016, as well as lower total production volumes. Depreciation, depletion and amortization per Mcfe also decreased to $0.72 per Mcfe and $1.07 per Mcfe for the sevennine months ended September 30, 2017, and2018 as compared to the twonine months ended February 28, 2017, respectively, from $1.18 per McfeSeptember 30, 2017. Income tax expense. Income tax expense for the nine months ended September 30, 2016.2018 was $299.7 million and relates to the recognition of a deferred tax liability upon becoming a taxable entity in conjunction with the Reorganization. Impairment
Liquidity and Capital Resources Our primary sources of Long-Lived Assets The Company recorded no impairment chargesliquidity have been borrowings under our credit facility and cash flows from operations. Our primary uses of capital have been for the seven months ended September 30, 2017, or the two months ended February 28, 2017. Duringexploration, development and acquisition of oil and natural gas properties.
Cash Flows Our cash flows for the nine months ended September 30, 2016, the Company recorded an impairment charge of approximately $165 million associated with proved oil2018 and natural gas properties in the Mid-Continent and Rockies regions due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves. Taxes, Other Than Income Taxes2017 are presented below:
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | Severance taxes | $ | 22,142 |
| | | $ | 9,107 |
| | $ | 28,028 |
| | Ad valorem taxes | 15,084 |
| | | 5,744 |
| | 24,501 |
| | Other | 90 |
| | | 26 |
| | 1,015 |
| | | $ | 37,316 |
| | | $ | 14,877 |
| | $ | 53,544 |
|
| | | | | | | | | | | Nine Months Ended
September 30, | | | 2018 | | 2017 | | | (in thousands) | | Net cash provided by operating activities | $ | 206,644 |
| | $ | 59,248 |
| | Net cash used in investing activities | (510,868 | ) | | (182,571 | ) | | Net cash provided by financing activities | 306,653 |
| | 117,410 |
| | Net increase (decrease) in cash and cash equivalents | $ | 2,429 |
| | $ | (5,913 | ) |
Severance taxes, which are a function of revenues generated from production, increased primarily due to higher commodity prices partially offset
Cash flows provided by lower production volumes. Ad valorem taxes, which are based onoperating activities. Cash flows provided by operating activities for the value of reserves and production equipment and vary by location, decreased primarily due to divestitures completed in 2017 and lower estimated valuations on certain of the Company’s properties. (Gains) Losses on Sale of Assets and Other, Net
During the sevennine months ended September 30, 2017, the Company recorded the following amounts related to divestitures (see Note 4):
Advisory fees of approximately $172018 were $206.6 million associated with the Roan Contribution;
Net gain of approximately $29 million on the Permian Assets Sales;
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Net gain of approximately $14 million, including costs to sell of approximately $1 million, on the South Texas Assets Sales;
Net gain of approximately $33 million, including costs to sell of approximately $1 million, on the Salt Creek Assets Sale; and
Net gain of approximately $272 million, including costs to sell of approximately $6 million, on the Jonah Assets Sale.
Other Income and (Expenses)
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | Interest expense, net of amounts capitalized | $ | (11,974 | ) | | | $ | (16,725 | ) | | $ | (159,476 | ) | | Earnings from equity method investments | 2,705 |
| | | 157 |
| | 511 |
| | Other, net | (5,788 | ) | | | (149 | ) | | (1,358 | ) | | | $ | (15,057 | ) | | | $ | (16,717 | ) | | $ | (160,323 | ) |
Interest expense decreased primarily due to the Company’s discontinuation of interest expense recognition on the senior notes for the two months ended February 28, 2017, as a result of the Chapter 11 proceedings, lower outstanding debt and lower amortization of discounts and financing fees. For the two months ended February 28, 2017, and the period from May 12, 2016 through September 30, 2016, contractual interest, which was not recorded, on the senior notes was approximately $37 million and $86 million, respectively. See “Debt” under “Liquidity and Capital Resources” below for additional details.
The Second Lien Notes were accounted for as a troubled debt restructuring which requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized. For the two months ended February 28, 2017, and the period from May 12, 2016 through September 30, 2016, unrecorded contractual interest on the Second Lien Notes was approximately $20 million and $46 million, respectively.
Equity method investments primarily include the Company’s 50% equity interest in Roan. The Company’s equity earnings consists of its share of Roan’s earnings and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets. See Note 4 for additional information.
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Reorganization Items, Net
The Company incurred significant costs and recognized significant gains associated with the reorganization. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined. The following table summarizes the components of reorganization items included on the condensed consolidated statements of operations:
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | Gain on settlement of liabilities subject to compromise | $ | — |
| | | $ | 3,724,750 |
| | $ | — |
| | Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement | — |
| | | (1,000,000 | ) | | — |
| | Fresh start valuation adjustments | — |
| | | (591,525 | ) | | — |
| | Income tax benefit related to implementation of the Plan | — |
| | | 264,889 |
| | — |
| | Legal and other professional advisory fees | (8,565 | ) | | | (46,961 | ) | | (30,165 | ) | | Unamortized deferred financing fees, discounts and premiums | — |
| | | — |
| | (52,045 | ) | | Gain related to interest payable on Predecessor’s Second Lien Notes | — |
| | | — |
| | 551,000 |
| | Terminated contracts | — |
| | | (6,915 | ) | | (13,123 | ) | | Other | 18 |
| | | (13,049 | ) | | 1,770 |
| | Reorganization items, net | $ | (8,547 | ) | | | $ | 2,331,189 |
| | $ | 457,437 |
|
Income Tax Expense (Benefit)
Effective February 28, 2017, upon the consummation of the Plan, the Successor became a C corporation. Prior to the consummation of the Plan, the Predecessor was a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits were passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. The Company recognized income tax expense of approximately $159 million and an income tax benefit of approximately $166,000 for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, compared to income tax expense of approximately $3$59.2 million for the nine months ended September 30, 2016.2017. The increase in cash flows provided by operating activities is primarily related to changes in working capital accounts and increased revenues partially offset by higher cash expenses due to increased activity in 2018.
Income (loss) from Discontinued Operations, Net of Income Taxes
As a result of the Company’s strategic exit from California (completed by the San Joaquin Basin Sale and Los Angeles Basin Sale) and the deconsolidation of Berry, the Company has classified the results of operations of its California properties and Berry as discontinued operations. Income from discontinued operations, net of income taxes was approximately $83 million for the seven months ended September 30, 2017, compared to loss from discontinued operations, net of income taxes of approximately $548,000 and $1.2 billion for the two months ended February 28, 2017, and the nine months ended September 30, 2016, respectively. See Note 4 for additional information.
Net Income (Loss) Attributable to Common Stockholders/Unitholders
Net income attributable to common stockholders/unitholders increased by approximately $4.1 billion to net income of approximately $350 million and $2.4 billion for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, from a net loss of approximately $1.3 billionCash flows used in investing activities. Cash flows used in investing activities for the nine months ended September 30, 2016. The increase was primarily due to higher gains included in reorganization items, income2018 were $510.9 million compared to losses from discontinued
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
operations, gains on the divestitures completed in 2017, gains compared to losses on commodity derivatives, lower impairment charges, lower expenses and higher production revenues. See discussion above for explanations of variances.
Liquidity and Capital Resources
Since its emergence from Chapter 11 bankruptcy in February 2017, the Company’s sources of cash have primarily consisted of proceeds from its 2017 oil and natural gas properties divestitures and net cash provided by operating activities. As a result of divesting certain oil and natural gas properties, the Company received over $1 billion in cash proceeds and repaid all of its outstanding debt as of July 31, 2017. The Company has also used its cash to fund capital expenditures, principally for the development of its oil and natural gas properties, and plant and pipeline construction, as well as repurchases of its Class A common stock. The Company expects to fund the remaining 2017 capital program and any share repurchases with excess cash from its pending divestitures and net cash provided by operating activities.
Prior to its emergence from bankruptcy, the Company utilized funds from debt and equity offerings, borrowings under its credit facilities and net cash provided by operating activities for liquidity and capital resources, and the primary use was for the development of oil and natural gas properties, as well as for acquisitions.
See below for details regarding capital expenditures for the periods presented:
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | Oil and natural gas | $ | 168,446 |
| | | $ | 39,409 |
| | $ | 66,066 |
| | Plant and pipeline | 63,923 |
| | | 4,990 |
| | 25,188 |
| | Other | 5,015 |
| | | 1,243 |
| | 6,259 |
| | Capital expenditures, excluding acquisitions | $ | 237,384 |
| | | $ | 45,642 |
| | $ | 97,513 |
| | Capital expenditures, excluding acquisitions – discontinued operations | $ | 2,007 |
| | | $ | 436 |
| | $ | 17,282 |
|
The increase in capital expenditures was primarily due to oil and natural gas development activities in the Merge/SCOOP/STACK and plant and pipeline construction activities associated with the Chisholm Trail Cryogenic Gas Plant. For 2017, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $360 million, including approximately $245 million related to its oil and natural gas capital program and approximately $107 million related to its plant and pipeline capital. This estimate is under continuous review and subject to ongoing adjustments.
Statements of Cash Flows
The following provides a comparative cash flow summary:
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | Net cash: | | | | | | | | Provided by (used in) operating activities | $ | 194,605 |
| | | $ | (20,814 | ) | | $ | 885,192 |
| | Provided by (used in) investing activities | 851,583 |
| | | (58,756 | ) | | (129,063 | ) | | Provided by (used in) financing activities | (1,068,501 | ) | | | (560,932 | ) | | 42,210 |
| | Net increase (decrease) in cash and cash equivalents | $ | (22,313 | ) | | | $ | (640,502 | ) | | $ | 798,339 |
|
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Operating Activities
Cash provided by operating activities was approximately $195 million and cash used in operating activities was approximately $21 million for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, compared to cash provided by operating activities of approximately $885$182.6 million for the nine months ended September 30, 2016.2017. The decrease was primarily due to lowerincrease in cash settlements on derivatives partially offset by higher production related revenues principally due to higher commodity prices. In addition, in February 2017, restricted cash increased by approximately $80 million in order to fund the settlement of certain claims and pay certain professional fees in accordance with the Plan.
Investing Activities
The following provides a comparative summary of cash flow from investing activities:
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | Cash flow from investing activities: | | | | | | | | Capital expenditures | $ | (197,294 | ) | | | $ | (58,006 | ) | | $ | (144,875 | ) | | Proceeds from sale of properties and equipment and other | 703,234 |
| | | (166 | ) | | (3,321 | ) | Net cash provided by (used in) investing activities – continuing operations | 505,940 |
| | | (58,172 | ) | | (148,196 | ) | | Net cash provided by (used in) investing activities – discontinued operations | 345,643 |
| | | (584 | ) | | 19,133 |
| | Net cash provided by (used in) investing activities | $ | 851,583 |
| | | $ | (58,756 | ) | | $ | (129,063 | ) |
The primary use of cashflows used in investing activities is fordue to the development of the Company’sincrease in capital expenditures on oil and natural gas properties. Capital expenditures increased primarily due to higher spending on developmentproperties resulting from the increase in drilling and completion activities in the Company’s Mid-Continent, Rockies and TexLa regions. The Company made no acquisitions of properties during2018 compared to 2017.
Cash flows provided by financing activities. Cash flows provided by financing activities for the nine months ended September 30, 2017, or September 30, 2016. The Company has classified the cash flows of its California properties and Berry as discontinued operations. Proceeds from sale of properties and equipment and other for the seven months ended September 30, 2017, include cash proceeds received of approximately $502018 were $306.7 million from the South Texas Assets Sales, approximately $31 million from the Permian Basin Assets Sales, approximately $76 million from the Salt Creek Assets Sale and approximately $561 million from the Jonah Assets Sale. An additional $8 million received from the 2017 divestitures remains in escrow and is currently classified as restricted cash. See Note 4 for additional details of divestitures.
Financing Activities
Cash used in financing activities was approximately $1.1 billion and $561 million for the seven months ended September 30, 2017, and the two months ended February 28, 2017, respectively, compared to cash provided by financing activities of approximately $42$117.4 million for the nine months ended September 30, 2016. In 2017, the primary use of2017. The increase in cash inflows provided by financing activities has been for repayments of debt.
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
The following provides a comparative summary of proceeds from borrowings and repayments of debt:
| | | | | | | | | | | | | | | | Successor | | | Predecessor | | | Seven Months Ended September 30, 2017 | | | Two Months Ended February 28, 2017 | | Nine Months Ended September 30, 2016 | | (in thousands) | | | | | | | | Proceeds from borrowings: | | | | | | | | Successor Credit Facility | $ | 190,000 |
| | | $ | — |
| | $ | — |
| | Predecessor Credit Facility | — |
| | | — |
| | 978,500 |
| | | $ | 190,000 |
| | | $ | — |
| | $ | 978,500 |
| | Repayments of debt: | | | | | | | | Successor Credit Facility | $ | (790,000 | ) | | | $ | — |
| | $ | — |
| | Successor Term Loan | (300,000 | ) | | | — |
| | — |
| | Predecessor Credit Facility | — |
| | | (1,038,986 | ) | | (814,299 | ) | | Predecessor Term Loan | — |
| | | — |
| | (98,911 | ) | | | $ | (1,090,000 | ) | | | $ | (1,038,986 | ) | | $ | (913,210 | ) |
On February 28, 2017, the Company canceled its obligations under the Predecessor Credit Facility and entered into the Successor Credit Facility (see Note 7), which was a net transaction and is reflected as such on the condensed consolidated statement of cash flows. In addition, in February 2017, the Company made a $30 million payment to holders of claims under the Second Lien Notes, and also issued 41,359,806 shares of Class A common stock to participants in the rights offerings extended by the Company to certain holders of claims arising under the Second Lien Notes and the Unsecured Notes for net proceeds of approximately $514 million.
Debt
The following summarizes the Company’s outstanding debt:
| | | | | | | | | | | Successor | | | Predecessor | | September 30, 2017 | | | December 31, 2016 | (in thousands, except percentages) | | | | | Revolving credit facility | $ | — |
| | | $ | — |
| Predecessor credit facility | — |
| | | 1,654,745 |
| Predecessor term loan | — |
| | | 284,241 |
| 6.50% senior notes due May 2019 | — |
| | | 562,234 |
| 6.25% senior notes due November 2019 | — |
| | | 581,402 |
| 8.625% senior notes due April 2020 | — |
| | | 718,596 |
| 12.00% senior secured second lien notes due December 2020 | — |
| | | 1,000,000 |
| 7.75% senior notes due February 2021 | — |
| | | 779,474 |
| 6.50% senior notes due September 2021 | — |
| | | 381,423 |
| Net unamortized deferred financing fees | — |
| | | (1,257 | ) | Total debt, net | — |
| | | 5,960,858 |
| Less current portion, net (1)
| — |
| | | (1,937,729 | ) | Less liabilities subject to compromise (2)
| — |
| | | (4,023,129 | ) | Long-term debt | $ | — |
| | | $ | — |
|
| | (1)
| Due to covenant violations, the Predecessor’s credit facility and term loan were classified as current at December 31, 2016. |
| | (2)
| The Predecessor’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016. On the Effective Date, pursuant to the terms of the Plan, all outstanding amounts under these debt instruments were canceled. |
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
As of October 31, 2017, there were no borrowings outstanding under the Revolving Credit Facility and there was approximately $461 million of available borrowing capacity (which includes a $39 million reduction for outstanding letters of credit).
In connection with the entry into the Revolving Credit Facility in August 2017, the Successor Credit Facility was terminated and repaid in full. On the Effective Date, pursuant to the terms of the Plan, all outstanding obligations under the Predecessor’s credit facility, Second Lien Notes and senior notes were canceled.
For additional information related to the Company’s outstanding debt, see Note 7.
Share Repurchase Program
On June 1, 2017, the Company’s Board of Directors announced that it had authorized the repurchase of up to $75 million of the Company’s outstanding shares of Class A common stock. On June 28, 2017, the Company’s Board of Directors announced that it had authorized an increase in the previously announced share repurchase program to up to a total of $200 million of the Company’s outstanding shares of Class A common stock. Any share repurchases are subject to restrictions in the Revolving Credit Facility. During the period from June 2017 through September 2017, the Company repurchased an aggregate of 4,607,598 shares of Class A common stock at an average price of $34.06 per share for a total cost of approximately $157 million.
Counterparty Credit Risk
The Company accounts for its commodity derivatives at fair value. The Company’s counterparties are participants in the Revolving Credit Facility or were participants in the Successor Credit Facility or Predecessor Credit Facility. The Revolving Credit Facility is secured by certain of the Company’s and its subsidiaries’ oil, natural gas and NGL reserves and personal property; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.
Dividends/Distributions
Under the Predecessor’s limited liability company agreement, unitholders were entitled to receive a distribution of available cash, which included cash on hand plus borrowings less any reserves established by the Predecessor’s Board of Directors to provide for the proper conductnine months ended September 30, 2018 is attributable to borrowings of $309.3 million from our credit facility. Financing activity for the Predecessor’s business (including reserves for future capital expenditures, acquisitions and anticipated future credit needs) or to fund distributions, if any, over the next four quarters. In October 2015, the Predecessor’s Board of Directors determined to suspend payment of the Predecessor’s distribution. The Successor is not currently paying a cash dividend; however, the Board of Directors periodically reviews the Company’s liquidity position to evaluate whether or not to pay a cash dividend. Any future payment of cash dividends would be subject to the restrictions in the Revolving Credit Facility.
Off-Balance Sheet Arrangements
The Company does not currently have any off-balance sheet arrangements.
Contingencies
See Part II. Item 1. “Legal Proceedings” for information regarding legal proceedings that the Company is party to and any contingencies related to these legal proceedings.
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Commitments and Contractual Obligations
The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in the table of contractual obligations in the March 31, 2017, Quarterly Report on Form 10-Q. During the sixnine months ended September 30, 2017 were related to capital contributions from Citizen members of $95.6 million and borrowings of $75.3 million, partially offset by distributions to Citizen members and repayments of $40.0 million on Citizen's credit facility.
Credit Facility Our 2017 Credit Facility is a $750.0 million credit agreement with a maturity date of September 5, 2022. As of September 30, 2018, the Company repaidborrowing base is set at $675.0 million. Redetermination of the borrowing base occurs semiannually on or about October 1 and April 1. As of September 30, 2018, we had $394.6 million of outstanding borrowings and no letters of credit outstanding under the 2017 Credit Facility.
Amounts borrowed under the 2017 Credit Facility bear interest at LIBOR or the ABR. Either rate is adjusted upward by an applicable margin (ranging from 2.00% to 3.00% for LIBOR and 1.00% to 2.00% for ABR), based on the utilization percentage of the 2017 Credit Facility. Additionally, the 2017 Credit Facility provides
for a commitment fee of 0.375% to 0.50% based on utilization, which is payable at the end of each calendar quarter.
The 2017 Credit Facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, we are prohibited from hedging in fullexcess of (a) 80% of reasonably anticipated projected production for the Successorfirst thirty (30) month rolling period (based upon our internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, we are required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per our most recent reserve report.
The 2017 Credit Facility also contains financial covenants requiring us to comply with a leverage ratio of consolidated debt to consolidated EBITDAX (as defined in the credit agreement) for the period of four fiscal quarters then ended of not more than 4.00 to 1.00 and a current ratio of consolidated current assets to consolidated current liabilities (as defined in the credit agreement to exclude non-cash assets and liabilities under ASC Topic 815 Derivatives and Hedging and ASC Topic 410 Asset Retirement and Environmental Obligations) as of the fiscal quarter ended of not less than 1.00 to 1.00.
As of September 30, 2018, we were in compliance with the covenants under the 2017 Credit Facility. Capital Expenditures Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, payment of contractual obligations and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow and financing under our 2017 Credit Facility. Our capital budget for the fourth quarter of 2018 is $200 million to $225 million. During the nine months ended September 30, 2018, capital expenditures were $558.0 million. Capital expenditures include expenditures related to drilling and completion costs of $474.7 million, leasehold additions of $73.5 million, and other costs of $9.8 million which includes corporate spending on other property and equipment. Capital expenditures for our operated properties are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We will continue to monitor commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions. Based upon current oil and natural gas prices and production expectations for the remainder of 2018 and 2019, we believe our cash flow from operations, cash on hand, borrowings under our 2017 Credit Facility and enteredaccess to capital markets will be sufficient to fund our operations for the next twelve months. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties.
Working Capital At September 30, 2018, we had a working capital deficit of $183.1 million compared to $121.2 million at December 31, 2017. Current assets and current liabilities increased by $150.7 million and $212.6 million, respectively, at September 30, 2018, compared to December 31, 2017 as a result of us taking over as operator in May 2018 on the oil and natural gas properties contributed to us by Citizen and Linn and increased drilling activity during 2018. Additionally, at the conclusion of the MSAs, we assumed certain working capital accounts associated with these properties from Citizen and Linn. Another factor contributing to the increase in the working capital deficit is the increase in the derivative contract liabilities of $54.9 million, which is due to the negative impact of higher in oil prices on the fair value of our open oil contracts with maturity dates in the next twelve months. Off-Balance Sheet Arrangements We enter into certain off-balance sheet arrangements and transactions, including operating lease arrangements and undrawn letters of credit. In addition, we enter into other contractual agreements in the Revolving Credit Facility (see Note 7). Asnormal course of business for processing and transportation as well as for other oil and natural gas activities. Other than the items discussed above, there are no other arrangements, transactions or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or capital resource positions. Contractual Obligations The following table summarizes our contractual obligations and commitments as of September 30, 2017, there were no2018: | | | | | | | | | | | | | | | | | | | | | | | | | Payments Due by Period | | | 2018 | 2019 | 2020 | 2021 | 2022 | Thereafter | Total | | | (in thousands) | | Credit Facility | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 394,639 |
| $ | — |
| $ | 394,639 |
| Interest expenses related to Credit Facility (1) | 5,366 |
| 21,288 |
| 21,288 |
| 21,288 |
| 14,464 |
| — |
| 83,694 |
| Pipe and equipment purchases commitments (2) | 1,925 |
| — |
| — |
| — |
| — |
| — |
| 1,925 |
| | Office building leases | 489 |
| 1,677 |
| 2,047 |
| 2,136 |
| 2,229 |
| 627 |
| 9,205 |
| Drilling rig commitments (3) | 8,050 |
| 15,352 |
| — |
| — |
| — |
| — |
| 23,402 |
| | Total contractual obligations and commitments | $ | 15,830 |
| $ | 38,317 |
| $ | 23,335 |
| $ | 23,424 |
| $ | 411,332 |
| $ | 627 |
| $ | 512,865 |
|
(1) Includes interest expense on our outstanding borrowings outstanding undercalculated using the Revolving Credit Facility. There have been no other significant changesweighted average interest rate of 5.32% at September 30, 2018. (2) Reflects commitments to purchase specified amounts of pipe and equipment. (3) Reflects future minimum drilling fees including early termination fees as specified by the Company’s contractual obligations since March 31, 2017.contract.
The above table does not include liabilities related to ARO. These are costs associated with the plugging of wells and the related abandonment of oil and natural gas properties. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. Critical Accounting Policies and Estimates The discussion and analysis of the Company’sour financial condition and results of operations is based on the condensed consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles.GAAP. The preparation of these financial statements requires that management of the Company to makeformulate estimates and assumptions that affect the reported amounts ofrevenues, expenses, assets, liabilities revenues and expenses, and related disclosuresthe disclosure of contingent assets and liabilities. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors
that are believed to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. ActualAlthough management believes they are reasonable, actual results maycould differ from these estimates and assumptions used in the preparation of the financial statements.assumptions. Recently Issued Accounting Standards For a discussion of recently issued accounting standards, see Note 1.2 – Summary of Significant Accounting Policiesin the accompanying condensed consolidated financial statements. Cautionary Statement Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond the Company’s control. These statements may include discussions about the Company’s:
business strategy;
acquisition and disposition strategy;
financial strategy;
new capital structure and the adoption of fresh start accounting;
uncertainty of the Company’s ability to improve its financial results and profitability following emergence from bankruptcy and other risks and uncertainties related to the Company’s emergence from bankruptcy;
inability to maintain relationships with suppliers, customers, employees and other third parties following emergence from bankruptcy;
failure to satisfy the Company’s short- or long-term liquidity needs, including its inability to generate sufficient cash flow from operations or to obtain adequate financing to fund its capital expenditures and meet working capital needs following emergence from bankruptcy;
large or multiple customer defaults on contractual obligations, including defaults resulting from actual or potential insolvencies;
ability to comply with covenants under the Revolving Credit Facility;
effects of legal proceedings;
drilling locations;
oil, natural gas and NGL reserves;
realized oil, natural gas and NGL prices;
production volumes;
capital expenditures;
economic and competitive advantages;
credit and capital market conditions;
regulatory changes;
lease operating expenses, general and administrative expenses and development costs;
future operating results, including results of acquired properties;
plans, objectives, expectations and intentions; and
taxes.
| | Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
All of these types of statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, are forward-looking statements. These forward-looking statements may be found in Item 2. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.
The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on Company expectations, which reflect estimates and assumptions made by Company management. These estimates and assumptions reflect management’s best judgment based on currently known market conditions and other factors. Although the Company believes such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond its control. In addition, management’s assumptions may prove to be inaccurate. The Company cautions that the forward-looking statements contained in this Quarterly Report on Form 10-Q are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the events will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors set forth in Item 1A. “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2016, and elsewhere in the Annual Report. The forward-looking statements speak only as of the date made and, other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
| | Item 3. | Item 3. Quantitative and Qualitative Disclosures About Market Risk |
The Company’s primary
We are exposed to a number of market risks are attributable to fluctuations inincluding commodity pricesprice risk, credit risk and interest rates. These risks can affect the Company’s business, financial condition, operating results and cash flows. See below forrate risk. The following information provides quantitative and qualitative information about theseour potential risks and how we seek to manage such risks. The following should be read in conjunction with the financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q and in the Company’s 2016 Annual Report on Form 10-K. The reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”Commodity Price Risk The Company’s most significantfollowing table reflects our open commodity contracts as of September 30, 2018: | | | | | | | | | | | | | | | | | | | 2018 | | 2019 | | 2020 | | Total | | Oil fixed prices swaps | | | | | | | | | Volume (Bbl) | 1,233,180 |
| | 5,540,670 |
| | 1,599,500 |
| | 8,373,350 |
| | Weighted-average price | $ | 57.09 |
| | $ | 59.86 |
| | $ | 63.14 |
| | $ | 60.08 |
| | Natural gas fixed price swaps | | | | | | | | | Volume (MMBtu) | 8,004,000 |
| | 29,200,000 |
| | 12,325,000 |
| | 49,529,000 |
| | Weighted-average price | $ | 2.94 |
| | $ | 2.86 |
| | $ | 2.63 |
| | $ | 2.81 |
| | Natural gas basis swaps | | | | | | | | | Volume (MMBtu) | 4,600,000 |
| | 21,900,000 |
| | 3,640,000 |
| | 30,140,000 |
| | Weighted-average price | $ | 0.54 |
| | $ | 0.58 |
| | $ | 0.62 |
| | $ | 0.58 |
|
Our primary market risk relates to prices ofexposure is in the price we receive for our oil, natural gas and NGL. The Company expects commodity prices to remainNGL production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable. As commodity prices decline or rise significantly, revenuesunpredictable for several years, and we expect this volatility to continue in the future. To achieve more predictable cash flows are likewise affected. In addition, future declinesflow and to reduce our exposure to adverse fluctuations in commodity prices, may result in noncash write-downsfrom time to time we enter into derivative arrangements for our oil and natural gas production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the Company’s carrying amounts of its assets. Historically, the Company has hedged a portion of its forecasted production to reduce exposurevariability in cash flow from operations due to fluctuations in oil and natural gas prices and provide long-termincreased certainty of cash flow predictability to manage its business. The Company doesflows. These derivatives are not enter intodesignated as a hedging instrument for hedge accounting under GAAP and as such, gains or losses resulting from the change in fair value along with the gains or losses resulting from settlement of derivative contracts for trading purposes. The appropriate levelare reflected as gain or loss on derivative contracts included in the consolidated statement of production to be hedged is an ongoing consideration based onoperations.
There are a variety of factors, including among other things, currenthedging strategies and instruments used to hedge future expected commodity market prices, the Company’s overall risk profile, including leverage and size and scale considerations, as well as any requirements for or restrictions on levels of hedging contained in any credit facility or other debt instrument applicable at the time. In addition, when commodity prices are depressed and forward commodity price curves are flat or in backwardation, the Company may determine that the benefit of hedging its anticipated production at these levels is outweighed by its resultant inability to obtain higher revenues for its production if commodity prices recover during the duration of the contracts. As a result, the appropriate percentage of production volumes to be hedged may change over time. At September 30, 2017, the fair value ofrisk. We utilize fixed price swaps and collars was a net assetbasis swaps to manage the price risk associated with forecasted sale of approximately $7 million. A 10% increase in the indexour oil and natural gas prices aboveproduction. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. Basis swaps are settled monthly based on differences between a fixed price differential and the applicable market price differential. When the referenced settlement price is less than the price specified in the contract, we receive an amount from the counterparty based on the price difference multiplied by the volume. When the referenced settlement price exceeds the price
specified in the contract, we pay the counterparty an amount based on the price difference multiplied by the volume.
At September 30, 2017, prices2018, we had a net liability position of $83.0 million related to our derivative contracts. Utilizing actual derivative contractual volumes under our fixed price swaps as of September 30, 2018, an increase of 10% in the forward curves associated with the underlying commodity would resulthave increased the net liability position to $156.2 million, while a decrease of 10% in the forward curves associated with the underlying commodity would have resulted in a net liability position of approximately $41 million, which represents a decrease in$16.0 million. Credit Risk Our principal exposure to credit risk is through the fair valuesale of approximately $48 million; conversely, a 10% decrease in the indexour oil, and natural gas prices belowand NGL production, which we market to energy marketing companies and refineries, and to a lesser extent, our derivative counterparties. We are subject to credit risk resulting from the September 30, 2017, prices would result in a net asset of approximately $54 million, which represents an increase in the fair value of approximately $47 million. At December 31, 2016, the fair value of fixed price swaps and collars was a net liability of approximately $85 million. A 10% increase in the index oil and natural gas prices above the December 31, 2016, prices would result in a net liability of approximately $183 million, which represents a decrease in the fair value of approximately $98 million; conversely, a 10%
Item 3. Quantitative and Qualitative Disclosures About Market Risk - Continued
decrease in the index oil and natural gas prices below the December 31, 2016, prices would result in a net asset of approximately $13 million, which represents an increase in the fair value of approximately $98 million.
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.
The pricesconcentration of oil, natural gas and NGL receivables with two significant purchasers. We do not believe the loss of any single purchaser would materially impact our results of operations because oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers.
Our derivative transactions have been extremely volatile, and the Company expects this volatility to continue. Prices for these commodities may fluctuate widely in response to relatively minor changescarried out in the supplyover-the-counter market. The entry into derivative transactions in the over-the-counter market involves the risk that the counterparties, which are financial institutions, may be unable to meet the financial terms of the transactions. We monitor on an ongoing basis the credit ratings of our derivative counterparties and demand for such commodities, market uncertaintyconsider their credit default risk ratings in determining the fair value of our derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. The counterparties to our derivative contracts at September 30, 2018, are also lenders under our 2017 Credit Facility. As a result, we do not require collateral or other security from counterparties nor are we required to post collateral to support derivative instruments. We have master netting agreements with all of our derivative counterparties, which allow us to net our derivative assets and liabilities with the same counterparty. As a varietyresult of additional factors that are beyond its control. Actual gains or losses recognized relatedthe netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the Company’s derivative contracts depend exclusively onnet amounts due from the price of the commodities on the specified settlement dates provided bycounterparties under the derivative contracts. Additionally, the Company cannot be assured that its counterparties will be able to perform under its derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, the Company’s cash flows could be impacted. Interest Rate Risk We are subject to market risk exposure related to changes in interest rates on our indebtedness under our 2017 Credit Facility. The terms of our 2017 Credit Facility provide for interest on borrowings at LIBOR or the alternate base rate, in each case adjusted upward by an applicable margin based on the utilization percentage of the credit facility. As of September 30, 2018, we had $394.6 million in outstanding borrowings under our 2017 Credit Facility. At September 30, 2017,2018, the Company had no debt outstandingweighted average interest rate on borrowings under the Revolving Credit Facility. At December 31, 2016, the Company had debt outstanding under the Predecessorour 2017 Credit Facility was 5.32%. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our interest expense of approximately $1.9 billion which incurred interest at floating rates. A 1% increase in the respective market rates would result in an estimated $19$3.9 million increase in annual interest expense.based on outstanding borrowings of $394.6 million under our 2017 Credit Facility as of September 30, 2018. Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. The Company maintains
As required by Rule 13a-15 and 15d-15 of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures that(as defined
in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to ensureprovide reasonable assurance that the information required to be disclosed by us in the Company’s reports that we file or submit under the Securities Exchange Act of 1934,is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as amended (the “Exchange Act”)appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, and the Company’s Audit Committee of the Board of Directors, as appropriate, to allow timely decisions regarding required disclosure. In designingSEC. Based upon the evaluation, our principal executive officer and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officerprincipal financial officer have concluded that the Company’sour disclosure controls and procedures were not effective as ofat September 30, 2017,2018 at the reasonable assurance level because of athe material weakness related to the Company’s controlsweaknesses in our internal control over application of fresh start accounting in the first quarter of 2017,financial reporting as discussedfurther described below.
Description of Material Weakness
Upon emergence from bankruptcy on February 28, 2017, the Company adopted fresh start accounting. The Company involved third party individuals to assist in the accounting and disclosure of the complex non-routine transaction. As part of fresh start accounting in February 2017, the reorganization value derived from the enterprise value as disclosed in the plan of reorganization was allocated using a residual method to the Company’s assets and liabilities based on their fair values measured in accordance with ASC 805 “Business Combinations.” The Company recorded its proved oil and natural gas properties at fair value as of the Effective Date and no value was assigned to the unproved properties. During the third quarter of 2017, the Company concluded that a relative fair value method should have been used and a portion of the value should have been attributed to its unproved properties, and because of this, the Company re-allocated value from its proved properties to its unproved properties.
Item 4. Controls and Procedures - Continued
Material Weaknesses
The Company did notWe have adequately designed controlsidentified material weaknesses in our internal control over the application of GAAP used to measure the carrying value of the underlying assets and liabilitiesfinancial reporting in fresh start accounting, the involvement of individualsconnection with the requisite knowledge, expertiseaudit of our financial statements as of and industry-specific experience to account for the years ended December 31, 2017 and disclose complex non-routine transactions, and the review and supervision of such accounting.
2016. A material weakness is a deficiency or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of theour annual or interim financial statements will not be prevented or detected on a timely basis.
We have identified five material weaknesses in our internal control over financial reporting. The material weaknesses identified relate to an overall lack of qualified personnel within the organization who possessed an appropriate level of expertise, experience and training to effectively design, implement and maintain: (i) adequate controls to monitor and assess the control environment. Specifically, internal controls were not designed or operating effectively to ensure appropriate monitoring or assessment of the control environment, including utilizing an appropriate control framework; (ii) adequate controls to establish appropriate entity level controls. Specifically, internal controls were not designed or operating effectively to ensure a sufficient amount of entity level controls were in place and operating effectively; (iii) effective controls over our period-end financial reporting processes, including controls over the preparation, analysis and review of certain significant account reconciliations required to assess the appropriateness of account balances at period-end; and controls over segregation of duties and the review of manual journal entries. Specifically, we did not design and maintain effective controls to verify that journal entries were properly prepared with sufficient supporting documentation or were reviewed and approved to ensure the accuracy and completeness of the manual journal entries. Additionally, certain key accounting personnel have the ability to prepare and post journal entries, as well as review account reconciliations, without an independent review by someone other than the preparer; and (iv) effective controls over information technology systems that are relevant to the preparation of the financial statements. Specifically, we did not design and maintain (a) user access controls to ensure appropriate segregation of duties and to adequately restrict user and privileged access to infrastructure, financial applications, programs, and data to appropriate personnel, (b) program change management controls to ensure that information technology program and data changes affecting financial IT applications and underlying accounting records are identified, tested, authorized and implemented appropriately, (c) computer operation controls to ensure all financially significant batch jobs are monitored for the completeness and accuracy of data transfer, and (d) program development controls to ensure that new software development is aligned with business and IT requirements. The deficiencies described in this clause (iv), when aggregated, could impact both maintaining effective segregation of duties and the effectiveness of IT-dependent controls (such as automated controls that address the risk of material misstatement to one or more assertions, along with the IT controls and underlying data that support the effectiveness of system-generated data and reports) that could result in misstatements potentially impacting all financial statement accounts and disclosures that would not be prevented or detected in a timely manner; and (v) a sufficient complement of resources with an appropriate level of accounting knowledge, experience and training to
develop and maintain an effective internal control environment. These material weaknesses originated with Citizen, the predecessor of Roan LLC, which had a lack of sufficient resources and inadequate control systems as it commenced operations as a private company. These material weaknesses did not result in any material misstatements of our financial statements or disclosures. The control deficiencies resulteddiscussed above could result in immaterial misstatementsa misstatement of account balances or disclosures that would result in the carrying amount of oil and natural gas properties, accumulated depletion and amortization, depreciation, depletion and amortization expense, gains on sale of assets, and discontinued operations to the Company’s condensed consolidated financial statements for the quarters ended March 31, June 30 and September 30, 2017, as described in Note 1. These control deficiencies create a reasonable possibility that a material misstatement to the Company’s annual or interim consolidated financial statements willthat would not be prevented or detected on a timely basis by the Company’s internal controls.detected. Accordingly, the Company’sour management has determined that these control deficiencies representconstitute material weaknesses.
Remediation Plan for the Material Weaknesses
We have taken and will continue to take a number of actions to remediate these material weakness. Notwithstanding the material weakness in the Company’sweaknesses. We are currently implementing measures designed to improve our internal control over financial reporting management concludedand remediate the control deficiencies that 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 Company as of, and for, the periods presented in this report.
Remediation Effortsled to Address the Material Weakness
During the third quarter of 2017, the Company took actions to commence remediation of the material weakness,weaknesses, including performingbut not limited to, (i) hiring additional reviewsIT and accounting personnel with appropriate technical skillsets, (ii) initiating design and implementation of our control environment, including the allocationexpansion of provedformal accounting and unproved properties onIT policies and procedures and financial reporting controls, (iii) conducting a field-by-field basis,company-wide assessment of our control environment, (iv) implementing appropriate review and revised its policy to engage parties with the requisite knowledge, expertise and industry-specific experience as needed to assist inoversight responsibilities within the accounting and disclosure of complex non-routine transactions. Managementfinancial reporting functions, and (v) evaluating controls over our information technology environment. We can give no assurance that these actions will consider the qualifications of team members reviewing non-routine complex transactions to ensure they meet the qualifications required for the proposed and actual scope of work.
Changesremediate these material weaknesses in the Company’s Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequateinternal controls or that additional material weaknesses in our internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. The Company’s internal controls were designed to provide reasonable assurance as to the reliability of its financial reporting and the preparation and presentation of the condensed consolidated financial statements for external purposes in accordance with accounting principles generally acceptedwill not be identified in the United States.future.
Because of its inherent limitations, internal control
Changes in Internal Control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.Financial Reporting. On August 31, 2017, the Company completed the transaction in which LINN Energy and Citizen Energy II, LLC each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan Resources LLC (“Roan” and the contribution, the “Roan Contribution”). The Company uses the equity method of accounting for its investment in Roan, and after the date of the Roan Contribution, the Company designed and tested additional controls over the financial reporting process for this investment.
Other than the additional controls related to the remediation of the material weakness and the equity method investment,Except as described herein, there were no changes in the Company’sour internal control over financial reporting during the third quarter of 2017 thatended September 30, 2018, which materially affected, or were reasonably likely to materially affect, the Company’sour internal control over financial reporting.
PartPART II – Other Information- OTHER INFORMATION
| | Item 1. | Item 1. Legal Proceedings |
On May 11, 2016, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040. On January 27, 2017, the Bankruptcy Court entered the Confirmation Order. Consummation of the Plan was subject to certain conditions set forth in the Plan. On the Effective Date, all of the conditions were satisfied or waived and the Plan became effective and was implemented in accordance with its terms. The LINN Debtors Chapter 11 cases will remain pending until the final resolution of all outstanding claims.
The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates. However, the Company is, and will continue to be until the final resolution of all claims, subject to certain contested matters and adversary proceedings stemming from the Chapter 11 proceedings.
In March 2017, Wells Fargo Bank, National Association (“Wells Fargo”), the administrative agent under the Predecessor Credit Facility, filed a motion in the Bankruptcy Court seeking payment of post-petition default interest of approximately $31 million. The Company has vigorously disputed that Wells Fargo is entitled to any default interest based on the plain language of the Plan and Confirmation Order. A hearing was held on April 27, 2017, and on November 13, 2017, the Bankruptcy Court ruled that the secured lendersWe are not entitled to payment of post-petition default interest. The ruling is subject to appeal by Wells Fargo.
The Company is not currently a party to proceedings and claims incidental to our business. While many of these other matters involve inherent uncertainty, we believe that the liability, if any, litigation or pendingultimately incurred with respect to such other proceedings and claims that it believes wouldwill not have a material adverse effect on its overall business,our consolidated financial position as a whole or on our liquidity, capital resources or future results of operationsoperations. We will continue to evaluate proceedings and claims involving us on a regular basis and will establish and adjust any reserves as appropriate to reflect our assessment of the then current status of the matters.
We maintain insurance against some risks associated with above or liquidity; however, cash flowunderground contamination that may occur as a result of our exploration and production activities. There can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could be significantly impacted in the reporting periods in which such matters are resolved.have a materially adverse effect on our financial condition and operations.
OurItem 1A. Risk Factors
In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading "Risk Factors" included in our Current Report on Form 8-K filed on September 24, 2018, which could materially affect our business, has many risks. Factorsfinancial condition or future results. Additional risks and uncertainties not currently known to us or that couldwe currently
deem to be immaterial also may materially adversely affect our business, financial condition operating results or liquidity and the trading price offuture results. There have been no material changes in our shares arerisk factors from those described in Item 1A. “Risk Factors” in our Annualthe Current Report, on Form 10-K for the year ended December 31, 2016. Exceptexcept as set forth below, asbelow.
The marketability and pricing of the date of this report, these risk factors have not changed materially. This information should be considered carefully, together with other information in this reportour production is dependent upon transportation and other reportsfacilities and materialsvarious market factors, which we filegenerally do not control. If these facilities are unavailable or we become subject to adverse pricing differentials, our operations could be interrupted and our revenues reduced.
The marketability of our oil, natural gas and NGL production depends in part upon the availability, proximity and capacity of transportation and other production facilities owned by third parties. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to produce or deliver to market our oil, natural gas and NGLs, causing a significant interruption in our operations. While we believe we have reserved sufficient capacity with third-party facilities to gather, process, fractionate and transport a significant portion of our projected production, that capacity may not be sufficient to handle all of our production, or these third-party facilities may experience delays in construction, mechanical problems or become unavailable to us due to unforeseen circumstances.
Additionally, we depend on various trucking providers for our oil production and on two third-party midstream companies for substantially all of our current natural gas and NGL production. Our current natural gas and NGL arrangements provide for pricing at Mont Belvieu, Texas, but future arrangements could be tied to pricing at Conway, Kansas or other market hubs and subject us to adverse pricing differentials. In the United States Securitiesfuture, we may be required to find alternative markets and Exchange Commission. We have limited control overgathering, processing or fractionation arrangements for our production, and such alternative arrangements may only be available on unfavorable terms, or not at all. If we are unable, for any sustained period, to access these third-party facilities or find acceptable alternative arrangements, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for gathering, processing, fractionating and delivering the operations of Roan, which couldoil, natural gas and NGLs produced from our fields, would materially and adversely affect our business.financial condition and results of operations.
We have limited control over the operations of Roan Resources LLC (“Roan”). Although we own a 50% equity interest in Roan, we do not control its board of directors or operating committee. Because of this limited control:
Roan may take actions contrary to our strategy or objectives;
we have limited ability to influence the day to day operations of Roan or its properties, including compliance with environmental, safety and other regulations; and
we are dependent on third parties for financial reporting matters upon which our financial statements are based.
Since Roan represents a significant investment of ours, adverse developments in Roan’s business could adversely affect our business.
| | Item 2. | Item 2. Unregistered Sales of Equity Securities and Use of Proceeds |
Issuer Purchases of Equity Securities and Use of Proceeds
The Company’s Board of Directors has authorized the repurchase of up to $400 million of the Company’s outstanding shares of Class A common stock. Purchases may be made from time to time in negotiated purchases orNone other than previously disclosed in the open market, including through Rule 10b5-1 prearranged stock trading plans designed to facilitate the repurchase of the Company’s shares during timesCurrent Report.
it would not otherwise be in the market due to self-imposed trading blackout periods or possible possession of material nonpublic information. The timing and amounts of any such repurchases of shares will be subject to market conditions and certain other factors, and will be in accordance with applicable securities laws and other legal requirements, including restrictions contained in the Company’s then current credit facility. The repurchase plan does not obligate the Company to acquire any specific number of shares and may be discontinued at any time.
The following sets forth information with respect to the Company’s repurchases of its shares of Class A common stock during the third quarter of 2017:
| | | | | | | | | | | | | | | | | Period | | Total Number of Shares Purchased | | Average Price Paid Per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (1) | | | | | | | | | | (in thousands) | | | | | | | | | | | | July 1 – 31 | | 833,763 |
| | $ | 32.43 |
| | 833,763 |
| | $ | 172,732 |
| | August 1 – 31 | | 2,770,661 |
| | $ | 34.33 |
| | 2,770,661 |
| | $ | 77,622 |
| | September 1 – 30 | | 995,634 |
| | $ | 34.72 |
| | 995,634 |
| | $ | 43,049 |
| | Total | | 4,600,058 |
| | $ | 34.07 |
| | 4,600,058 |
| | |
| | (1)
| On June 1, 2017, the Company’s Board of Directors announced that it had authorized the repurchase of up to $75 million of the Company’s outstanding shares of Class A common stock. On June 28, 2017, the Company’s Board of Directors announced that it had authorized an increase in the previously announced share repurchase program to up to a total of $200 million of the Company’s outstanding shares of Class A common stock. On October 4, 2017, the Company’s Board of Directors announced that it had authorized an additional increase in the previously announced share repurchase program to up to a total of $400 million of the Company’s outstanding shares of a Class A common stock. |
| | Item 3. | Defaults Upon Senior Securities |
NoneItem 3. Defaults Upon Senior Securities
None. | | Item 4. | Mine Safety Disclosures |
Item 4. Mine Safety Disclosure Not applicableapplicable. NoneItem 5. Other Information
Not applicable.
| | | | | Exhibit NumberNo. | | DescriptionExhibit | | | | 2.1 | — | First Amendment, dated July 10, 2017, to Purchase and SaleLinn Merger Agreement, dated June 1, 2017,September 24, 2018, by and betweenamong Linn Energy, Holdings, LLC,Inc., Roan Resources, Inc. and Linn Operating, LLC, Linn Midstream, LLC and Bridge Energy LLC (incorporated by reference to Exhibit 2.6 to Quarterly Report on Form 10‑Q filed on August 3, 2017) | 2.2 | — | Purchase and Sale Agreement, dated October 3, 2017, by and between Linn Energy Holdings, LLC, Linn Operating, LLC and Washakie Exaro Opportunities,Merger Sub #2, LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on October 5, 2017)September 24, 2018) | 3.1 | — | Roan Merger Agreement, dated September 24, 2018, by and among Roan Holdings, LLC, Roan Holdings Holdco, LLC, Roan Resource, 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 Linn Energy,Roan Resources, Inc. (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-88-K filed on February 28, 2017)September 27, 2018) | | — | Second Amended and Restated Bylaws of Linn Energy,Roan Resources, Inc. (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-88-K filed on February 28, 2017)September 27, 2018) | 10.1 | — | CreditRegistration Rights Agreement, dated as of August 4, 2017,September 24, 2018, by and among Linn Energy Holdco II LLC, as borrower, Linn Energy Holdco LLC, as parent, Linn Energy, Inc. as holdings, Royal Bank of Canada, as administrative agent, Citibank, N.A., as syndication agent, Barclays Bank PLC, JPMorgan Chase Bank, N.A., Morgan Stanley Senior Funding,Roan Resources, Inc. and PNC Bank National Association, as co-documentation agents, andeach of the lenders partyother parties listed on the signature page thereto (incorporated by reference to Exhibit 10.264.1 to Registration Statement on Form S-1/A8-K filed on September 26, 2017)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 as ofApril 9, 2018 (incorporated by reference to Exhibit 10.2 to Form 8-K filed on September 29, 2017,24, 2018) | | | Amendment No. 2 to Credit Agreement, dated as of August 4, 2017, among Linn Energy Holdco II LLC, as borrower, Linn Energy Holdco LLC, as parent, Linn Energy, Inc. as holdings, Royal Bank of Canada, as administrative agent, Citibank, N.A., as syndication agent, Barclays Bank PLC, JPMorgan Chase Bank, N.A., Morgan Stanley Senior Funding, Inc. and PNC Bank National Association, as co-documentation agents, and the lenders party theretoMay 30, 2018 (incorporated by reference to Exhibit 10.3 to Form 8-K filed on September 24, 2018) | 10.3 | — | 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) |
| | 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 |
| | 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) |
| | Amended and Restated Employment Agreement, dated as ofNovember 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) |
| | 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) |
| | 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) |
| | 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) |
| | 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 31, 20177, 2018, by and among Linn Energy, Inc., Riviera Resources, Inc. and the Riviera Resources, Inc. Subsidiaries (incorporated by reference to Exhibit 10.1 to Current ReportForm 8-K filed by Linn Energy, Inc. on Form 8‑K filed on September 7, 2017)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) | | | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | | — | pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | | — | pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | | — | pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | 101.INS** | — | XBRL Instance Document | 101.SCH** | — | XBRL Taxonomy Extension Schema Document | 101.CAL** | — | XBRL Taxonomy Extension Calculation Linkbase Document | 101.DEF** | — | XBRL Taxonomy Extension Definition Linkbase Document | 101.LAB** | — | XBRL Taxonomy Extension Label Linkbase Document | 101.PRE** | — | XBRL Taxonomy Extension Presentation Linkbase Document |
| herewith | ** | Furnished herewith.†Compensatory plan or arrangement |
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrantRegistrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
ROAN RESOURCES, INC.
| | | | LINN ENERGY, INC. | | | (Registrant) | | | Date: November 14, 2017 | /s/ Darren R. Schluter | | Darren R. Schluter | | Vice President and Controller | | (Duly Authorized Officer and Principal Accounting Officer) | | | | | | | | | Date: | November 14, 201713, 2018 | /s/ Tony C. Maranto | | | Tony C. Maranto | | | Chairman, President and Chief Executive Officer | | | (Principal Executive Officer) | | | | | | | | | | | Date: | November 13, 2018 | /s/ David B. RottinoM. Edwards | | | | David B. RottinoM. Edwards | | | Executive Vice President and | Chief Financial Officer | | | | (Principal Financial Officer) | | | | | | | | | |
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