i
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (the “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 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 Annual Report on Form 10-K for the year ended December 31, 2018 (our “Annual Report on Form 10-K”) filed with the Securities and Exchange Commission (the “SEC”) 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 andindustry:
Analogous reservoir. Analogous reservoirs, as used in this Quarterly Report on Form 10-Q,resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an analogous reservoir refers to a reservoir that shares the following terms havecharacteristics with the following meanings:reservoir of interest: (i) same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) same environment of deposition; (iii) similar geological structure; and (iv) same drive mechanism. For a complete definition of analogous reservoir, refer to the SEC’s Regulation S-X, Rule 4-10(a)(2).
Bbl. Basin. A large natural depression on the earth’s surface in which sediments, generally brought by water, accumulate.
Bbl. One stock tank barrel orof 42 United StatesU.S. gallons liquid volume.volume used herein in reference to crude oil, condensate or NGLs.
Btu.Boe. 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 barrelsbarrel of oil or other liquid hydrocarbons.
MBbls/d. MBbls per day.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet 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. The quantity of heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
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).
Development project. The means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
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 or HBP. 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.
MMBbls.MBbls. One millionthousand barrels of crude oil, condensate or other liquid hydrocarbons.NGLs.
MMBtu.MBoe. One thousand Boe.
MBoe/d. One thousand Boe per day.
Mcf. One thousand cubic feet of natural gas.
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 gas liquids,. A specific geographic area which, arebased 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 hydrocarbon liquids contained within natural gas.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 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 estimation. 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 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.
Reasonable certainty. A high degree of confidence that quantities will be recovered. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).
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.
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)
|
| | | | | | | |
| | June 30,
2018 | | December 31,
2017 |
| | (in thousands, except share amounts) |
| ASSETS | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 301,365 |
| | $ | 464,508 |
|
| Accounts receivable – trade, net | 64,686 |
| | 140,485 |
|
| Derivative instruments | 3,934 |
| | 9,629 |
|
| Restricted cash | 43,387 |
| | 56,445 |
|
| Other current assets | 46,659 |
| | 79,771 |
|
| Assets held for sale | 22 |
| | 106,963 |
|
| Total current assets | 460,053 |
| | 857,801 |
|
| | | | |
| Noncurrent assets: | | | |
| Oil and natural gas properties (successful efforts method) | 785,815 |
| | 950,083 |
|
| Less accumulated depletion and amortization | (59,870 | ) | | (49,619 | ) |
| | 725,945 |
| | 900,464 |
|
| | | | |
| Other property and equipment | 566,861 |
| | 480,729 |
|
| Less accumulated depreciation | (44,412 | ) | | (28,658 | ) |
| | 522,449 |
| | 452,071 |
|
| | | | |
| Derivative instruments | 1,254 |
| | 469 |
|
| Deferred income taxes | 169,691 |
| | 198,417 |
|
| Equity method investments | 473,269 |
| | 464,926 |
|
| Other noncurrent assets | 5,264 |
| | 6,975 |
|
| | 649,478 |
| | 670,787 |
|
| Total noncurrent assets | 1,897,872 |
| | 2,023,322 |
|
| Total assets | $ | 2,357,925 |
| | $ | 2,881,123 |
|
| | | | |
| LIABILITIES AND EQUITY | | | |
| Current liabilities: | | | |
| Accounts payable and accrued expenses | $ | 179,887 |
| | $ | 253,975 |
|
| Share-based payment liability | 111,792 |
| | — |
|
| Derivative instruments | 5,536 |
| | 10,103 |
|
| Other accrued liabilities | 19,830 |
| | 58,617 |
|
| Liabilities held for sale | — |
| | 43,302 |
|
| Total current liabilities | 317,045 |
| | 365,997 |
|
| | | | |
| Noncurrent liabilities: | | | |
| Derivative instruments | 24 |
| | 2,849 |
|
| Asset retirement obligations and other noncurrent liabilities | 105,531 |
| | 160,720 |
|
| Total noncurrent liabilities | 105,555 |
| | 163,569 |
|
LINN ENERGY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS - Continued
(Unaudited)
|
| | | | | | | |
| | June 30,
2018 | | December 31,
2017 |
| | (in thousands, except share amounts) |
| Commitments and contingencies (Note 11) |
|
| |
|
|
| | | | |
| Equity: | | | |
| Preferred stock ($0.001 par value, 30,000,000 shares authorized; no shares issued at June 30, 2018, or December 31, 2017) | — |
| | — |
|
| Class A common stock ($0.001 par value, 270,000,000 shares authorized; 78,749,510 shares and 83,582,176 shares issued at June 30, 2018, and December 31, 2017, respectively) | 79 |
| | 84 |
|
| Additional paid-in capital | 1,427,458 |
| | 1,899,642 |
|
| Retained earnings | 507,788 |
| | 432,860 |
|
| Total common stockholders’ equity | 1,935,325 |
| | 2,332,586 |
|
| Noncontrolling interests | — |
| | 18,971 |
|
| Total equity | 1,935,325 |
| | 2,351,557 |
|
| Total liabilities and equity | $ | 2,357,925 |
| | $ | 2,881,123 |
|
|
| | | | | | | |
| | June 30, 2019 | | December 31, 2018 |
| | (in thousands, except par value and share data) |
| ASSETS | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 5,428 |
| | $ | 6,883 |
|
| Accounts receivable | | | |
| Oil, natural gas and natural gas liquid sales | 44,475 |
| | 55,564 |
|
| Joint interest owners and other, net | 164,156 |
| | 133,387 |
|
| Affiliates | 2,979 |
| | 9,669 |
|
| Prepaid drilling advances | 15,996 |
| | 28,977 |
|
| Derivative contracts | 30,511 |
| | 82,180 |
|
| Other current assets | 4,296 |
| | 6,655 |
|
| Total current assets | 267,841 |
| | 323,315 |
|
| Noncurrent assets | | | |
| Oil and natural gas properties, successful efforts method | 2,913,621 |
| | 2,628,333 |
|
| Accumulated depreciation, depletion, amortization and impairment | (335,678 | ) | | (230,836 | ) |
| Oil and natural gas properties, net | 2,577,943 |
| | 2,397,497 |
|
| Derivative contracts | 12,017 |
| | 20,638 |
|
| Other | 12,873 |
| | 7,659 |
|
| Total assets | $ | 2,870,674 |
| | $ | 2,749,109 |
|
| LIABILITIES AND EQUITY | | | |
| Current liabilities | | | |
| Accounts payable | $ | 85,031 |
| | $ | 49,746 |
|
| Accrued liabilities | 116,174 |
| | 176,494 |
|
| Accounts payable and accrued liabilities – Affiliates | 4,111 |
| | 8,577 |
|
| Revenue payable | 100,070 |
| | 97,963 |
|
| Drilling advances | 20,969 |
| | 31,058 |
|
| Derivative contracts | 26 |
| | 845 |
|
| Other current liabilities | 2,655 |
| | 790 |
|
| Total current liabilities | 329,036 |
| | 365,473 |
|
| Noncurrent liabilities | | | |
| Long-term debt | 659,639 |
| | 514,639 |
|
| Long-term debt, net - Affiliates | 44,924 |
| | — |
|
| Deferred tax liabilities, net | 347,376 |
| | 356,862 |
|
| Asset retirement obligations | 17,496 |
| | 16,058 |
|
| Derivative contracts | — |
| | 141 |
|
| Other | 5,818 |
| | 902 |
|
| Total liabilities | 1,404,289 |
| | 1,254,075 |
|
| Commitments and contingencies (Note 14) |
|
| |
|
|
| Equity | | | |
| Class A common stock, $0.001 par value; 800,000,000 shares authorized; 154,064,927 shares issued and outstanding at June 30, 2019 and 152,539,532 shares issued and outstanding at December 31, 2018 | 154 |
| | 153 |
|
| Preferred stock, $0.001 par value; 50,000,000 shares authorized; no shares issued and outstanding at June 30, 2019 or December 31, 2018 | — |
| | — |
|
| Additional paid-in capital | 1,648,561 |
| | 1,646,401 |
|
| Accumulated deficit | (182,330 | ) | | (151,520 | ) |
| Total equity | 1,466,385 |
| | 1,495,034 |
|
| Total liabilities and equity | $ | 2,870,674 |
| | $ | 2,749,109 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
6
2
Roan Resources, Inc.
Condensed Consolidated Statements of ContentsOperations (Unaudited)
LINN ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
|
| | | | | | | |
| | Successor |
| | Three Months Ended June 30, |
| | 2018 | | 2017 |
| | (in thousands, except per share amounts) |
| Revenues and other: | | | |
| Oil, natural gas and natural gas liquids sales | $ | 87,004 |
| | $ | 243,167 |
|
| Gains (losses) on oil and natural gas derivatives | (7,525 | ) | | 45,714 |
|
| Marketing revenues | 42,967 |
| | 12,547 |
|
| Other revenues | 6,387 |
| | 6,391 |
|
| | 128,833 |
| | 307,819 |
|
| Expenses: | | | |
| Lease operating expenses | 24,088 |
| | 71,057 |
|
| Transportation expenses | 21,213 |
| | 37,388 |
|
| Marketing expenses | 40,327 |
| | 6,976 |
|
| General and administrative expenses | 92,395 |
| | 34,458 |
|
| Exploration costs | 53 |
| | 811 |
|
| Depreciation, depletion and amortization | 21,980 |
| | 51,987 |
|
| Taxes, other than income taxes | 7,297 |
| | 17,871 |
|
| Gains on sale of assets and other, net | (101,777 | ) | | (306,878 | ) |
| | 105,576 |
| | (86,330 | ) |
| Other income and (expenses): | | | |
| Interest expense, net of amounts capitalized | (584 | ) | | (7,551 | ) |
| Earnings (losses) from equity method investments | (9,327 | ) | | 91 |
|
| Other, net | 538 |
| | (1,163 | ) |
| | (9,373 | ) | | (8,623 | ) |
| Reorganization items, net | (1,259 | ) | | (3,377 | ) |
| Income from continuing operations before income taxes | 12,625 |
| | 382,149 |
|
| Income tax expense | 5,722 |
| | 158,770 |
|
| Income from continuing operations | 6,903 |
| | 223,379 |
|
| Loss from discontinued operations, net of income taxes | — |
| | (3,322 | ) |
| Net income | 6,903 |
| | 220,057 |
|
| Net income attributable to noncontrolling interests | 1,799 |
| | — |
|
| Net income attributable to common stockholders | $ | 5,104 |
| | $ | 220,057 |
|
| | | | |
| Income (loss) per share attributable to common stockholders: | | | |
| Income from continuing operations per share – Basic | $ | 0.06 |
| | $ | 2.49 |
|
| Income from continuing operations per share – Diluted | $ | 0.06 |
| | $ | 2.47 |
|
| | | | |
| Loss from discontinued operations per share – Basic | $ | — |
| | $ | (0.04 | ) |
| Loss from discontinued operations per share – Diluted | $ | — |
| | $ | (0.04 | ) |
| | | | |
| Net income per share – Basic | $ | 0.06 |
| | $ | 2.45 |
|
| Net income per share – Diluted | $ | 0.06 |
| | $ | 2.43 |
|
| | | | |
| Weighted average shares outstanding – Basic | 78,718 |
| | 89,849 |
|
| Weighted average shares outstanding – Diluted | 79,277 |
| | 90,484 |
|
|
| | | | | | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in thousands, except per share amounts) |
| Revenues | | | | | | | |
Oil sales | $ | 69,196 |
| | $ | 58,677 |
| | $ | 129,767 |
| | $ | 122,369 |
|
Natural gas sales | 6,659 |
| | 11,126 |
| | 17,848 |
| | 21,458 |
|
| Natural gas sales – Affiliates | 6,430 |
| | 2,881 |
| | 17,022 |
| | 9,439 |
|
Natural gas liquid sales | 8,482 |
| | 13,205 |
| | 16,820 |
| | 25,144 |
|
| Natural gas liquid sales – Affiliates | 6,353 |
| | 4,678 |
| | 14,202 |
| | 13,127 |
|
| Gain (loss) on derivative contracts | 37,054 |
|
| (54,602 | ) |
| (46,588 | ) |
| (64,216 | ) |
| Total revenues | 134,174 |
| | 35,965 |
| | 149,071 |
| | 127,321 |
|
| Operating Expenses | | | | | | | |
| Production expenses | 6,723 |
| | 7,019 |
| | 21,569 |
| | 15,374 |
|
| Production expenses - Affiliates | 4,580 |
| | — |
| | 4,580 |
| | — |
|
| Production taxes | 5,065 |
| | 2,296 |
| | 10,104 |
| | 4,682 |
|
| Exploration expenses | 11,406 |
|
| 10,633 |
|
| 23,894 |
|
| 18,483 |
|
| Depreciation, depletion, amortization and accretion | 44,893 |
|
| 24,601 |
|
| 86,465 |
|
| 46,466 |
|
| General and administrative | 12,311 |
| | 13,086 |
| | 28,136 |
| | 27,106 |
|
| Loss (gain) on sale of other assets | 50 |
|
| — |
|
| (614 | ) |
| — |
|
| Total operating expenses | 85,028 |
| | 57,635 |
| | 174,134 |
| | 112,111 |
|
| Total operating income (loss) | 49,146 |
| | (21,670 | ) | | (25,063 | ) | | 15,210 |
|
| Other income (expense) | | | | | | | |
| Interest expense, net | (8,462 | ) |
| (1,087 | ) |
| (15,206 | ) |
| (2,886 | ) |
| Other | (28 | ) | | — |
| | (28 | ) | | — |
|
| Net income (loss) before income taxes | 40,656 |
|
| (22,757 | ) |
| (40,297 | ) |
| 12,324 |
|
| Income tax expense (benefit) | 13,410 |
|
| — |
|
| (9,487 | ) |
| — |
|
| Net income (loss) | $ | 27,246 |
|
| $ | (22,757 | ) |
| $ | (30,810 | ) |
| $ | 12,324 |
|
| Earnings (loss) per share |
|
|
|
|
|
|
|
|
|
| Basic | $ | 0.18 |
|
| $ | (0.15 | ) |
| $ | (0.20 | ) |
| $ | 0.08 |
|
| Diluted | $ | 0.18 |
|
| $ | (0.15 | ) |
| $ | (0.20 | ) |
| $ | 0.08 |
|
| Weighted average number of shares outstanding |
|
|
|
|
|
|
|
|
|
| Basic | 152,607 |
|
| 152,540 |
|
| 152,573 |
|
| 151,920 |
|
| Diluted | 152,725 |
|
| 152,540 |
|
| 152,573 |
|
| 151,920 |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
7
3
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Six Months Ended June 30, 2018 | | Four Months Ended June 30, 2017 | | | Two Months Ended February 28, 2017 |
| (in thousands, except per share and per unit amounts) | | | | | | |
| Revenues and other: | | | | | | |
| Oil, natural gas and natural gas liquids sales | $ | 223,880 |
| | $ | 323,492 |
| | | $ | 188,885 |
|
| Gains (losses) on oil and natural gas derivatives | (22,555 | ) | | 33,755 |
| | | 92,691 |
|
| Marketing revenues | 89,234 |
| | 15,461 |
| | | 6,636 |
|
| Other revenues | 12,281 |
| | 8,419 |
| | | 9,915 |
|
| | 302,840 |
| | 381,127 |
| | | 298,127 |
|
| Expenses: | | | | | | |
| Lease operating expenses | 71,972 |
| | 95,687 |
| | | 49,665 |
|
| Transportation expenses | 40,307 |
| | 51,111 |
| | | 25,972 |
|
| Marketing expenses | 82,082 |
| | 9,515 |
| | | 4,820 |
|
| General and administrative expenses | 137,174 |
| | 44,869 |
| | | 71,745 |
|
| Exploration costs | 1,255 |
| | 866 |
| | | 93 |
|
| Depreciation, depletion and amortization | 50,445 |
| | 71,901 |
| | | 47,155 |
|
| Taxes, other than income taxes | 15,749 |
| | 24,948 |
| | | 14,877 |
|
| (Gains) losses on sale of assets and other, net | (207,852 | ) | | (306,394 | ) | | | 829 |
|
| | 191,132 |
| | (7,497 | ) | | | 215,156 |
|
| Other income and (expenses): | | | | | | |
| Interest expense, net of amounts capitalized | (988 | ) | | (11,751 | ) | | | (16,725 | ) |
| Earnings from equity method investments | 16,018 |
| | 130 |
| | | 157 |
|
| Other, net | 369 |
| | (1,551 | ) | | | (149 | ) |
| | 15,399 |
| | (13,172 | ) | | | (16,717 | ) |
| Reorganization items, net | (3,210 | ) | | (5,942 | ) | | | 2,331,189 |
|
| Income from continuing operations before income taxes | 123,897 |
| | 369,510 |
| | | 2,397,443 |
|
| Income tax expense (benefit) | 45,896 |
| | 153,455 |
| | | (166 | ) |
| Income from continuing operations | 78,001 |
| | 216,055 |
| | | 2,397,609 |
|
| Loss from discontinued operations, net of income taxes | — |
| | (3,254 | ) | | | (548 | ) |
| Net income | 78,001 |
| | 212,801 |
| | | 2,397,061 |
|
| Net income attributable to noncontrolling interests | 3,073 |
| | — |
| | | — |
|
| Net income attributable to common stockholders/unitholders | $ | 74,928 |
| | $ | 212,801 |
| | | $ | 2,397,061 |
|
| | | | | | | |
| Income (loss) per share/unit attributable to common stockholders/unitholders: | | | | | | |
| Income from continuing operations per share/unit – Basic | $ | 0.95 |
| | $ | 2.41 |
| | | $ | 6.80 |
|
| Income from continuing operations per share/unit – Diluted | $ | 0.93 |
| | $ | 2.40 |
| | | $ | 6.80 |
|
| | | | | | | |
| Loss from discontinued operations per share/unit – Basic | $ | — |
| | $ | (0.04 | ) | | | $ | (0.01 | ) |
| Loss from discontinued operations per share/unit – Diluted | $ | — |
| | $ | (0.04 | ) | | | $ | (0.01 | ) |
| | | | | | | |
| Net income per share/unit – Basic | $ | 0.95 |
| | $ | 2.37 |
| | | $ | 6.79 |
|
| Net income per share/unit – Diluted | $ | 0.93 |
| | $ | 2.36 |
| | | $ | 6.79 |
|
| | | | | | | |
| Weighted average shares/units outstanding – Basic | 78,817 |
| | 89,849 |
| | | 352,792 |
|
| Weighted average shares/units outstanding – Diluted | 79,764 |
| | 90,065 |
| | | 352,792 |
|
|
| | | | | | | | | | | | | | | | | |
| | 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 | — |
| — |
| — |
| — |
| 2,292 |
| 2,292 |
|
| Net income | — |
| — |
| — |
| — |
| 35,081 |
| 35,081 |
|
| Balance at March 31, 2018 | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 1,662,048 |
| $ | 1,662,048 |
|
| Equity-based compensation | — |
| — |
| — |
| — |
| 2,835 |
| 2,835 |
|
| Net loss | — |
| — |
| — |
| — |
| (22,757 | ) | (22,757 | ) |
| Balance at June 30, 2018 | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 1,642,126 |
| $ | 1,642,126 |
|
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Balance at December 31, 2018 | 152,540 |
| $ | 153 |
| $ | 1,646,401 |
| $ | (151,520 | ) | $ | — |
| $ | 1,495,034 |
|
| Equity-based compensation | — |
| — |
| 3,065 |
| — |
| — |
| 3,065 |
|
| Net loss | — |
| — |
| — |
| (58,056 | ) | — |
| (58,056 | ) |
| Balance at March 31, 2019 | 152,540 |
| $ | 153 |
| $ | 1,649,466 |
| $ | (209,576 | ) | $ | — |
| $ | 1,440,043 |
|
| Shares issued in connection with Term Loan | 1,525 |
| 1 |
| 2,317 |
| — |
| — |
| 2,318 |
|
| Equity-based compensation | — |
| — |
| (3,222 | ) | — |
| — |
| (3,222 | ) |
| Net income | — |
| — |
| — |
| 27,246 |
| — |
| 27,246 |
|
| Balance at June 30, 2019 | 154,065 |
| $ | 154 |
| $ | 1,648,561 |
| $ | (182,330 | ) | $ | — |
| $ | 1,466,385 |
|
| | | | | | | |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
LINN ENERGY, INC.8
CONDENSED CONSOLIDATED STATEMENT OF EQUITY
Roan Resources, Inc.
Condensed Consolidated Statements of Cash Flows (Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Class A Common Stock | | Additional Paid-in Capital | | Retained Earnings | | Total Common Stockholders’ Equity | | Noncontrolling Interests | | Total Equity |
| | Shares | | Amount | | | | |
| | (in thousands) |
| | | | | | | | | | | | | | |
| December 31, 2017 | 83,582 |
| | $ | 84 |
| | $ | 1,899,642 |
| | $ | 432,860 |
| | $ | 2,332,586 |
| | $ | 18,971 |
| | $ | 2,351,557 |
|
| Net income | | | — |
| | — |
| | 74,928 |
| | 74,928 |
| | 3,073 |
| | 78,001 |
|
| Issuances of successor Class A common stock | 811 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Repurchases of successor Class A common stock | (8,429 | ) | | (8 | ) | | (394,407 | ) | | — |
| | (394,415 | ) | | — |
| | (394,415 | ) |
| Settlement of equity classified RSUs | | | — |
| | (58,162 | ) | | — |
| | (58,162 | ) | | — |
| | (58,162 | ) |
| Share-based compensation expenses | | | — |
| | 25,132 |
| | — |
| | 25,132 |
| | — |
| | 25,132 |
|
| Equity awards modified to liabilities | | | — |
| | (70,550 | ) | | — |
| | (70,550 | ) | | — |
| | (70,550 | ) |
| Allocation of noncontrolling interest upon vesting of subsidiary units | | | — |
| | (21,233 | ) | | — |
| | (21,233 | ) | | 21,233 |
| | — |
|
| Distributions to noncontrolling interests | | | — |
| | — |
| | — |
| | — |
| | (8,367 | ) | | (8,367 | ) |
| Subsidiary equity transactions | | | — |
| | 646 |
| | — |
| | 646 |
| | (646 | ) | | — |
|
| Other | | | — |
| | 12,129 |
| | — |
| | 12,129 |
| | — |
| | 12,129 |
|
| Dissolution of noncontrolling interests | 2,786 |
| | 3 |
| | 34,261 |
| | — |
| | 34,264 |
| | (34,264 | ) | | — |
|
| June 30, 2018 | 78,750 |
| | $ | 79 |
| | $ | 1,427,458 |
| | $ | 507,788 |
| | $ | 1,935,325 |
| | $ | — |
| | $ | 1,935,325 |
|
|
| | | | | | | |
| Six Months Ended
June 30, |
| 2019 |
| 2018 |
| (in thousands) |
| Cash flows from operating activities |
|
|
|
| Net (loss) income | $ | (30,810 | ) |
| $ | 12,324 |
|
| Adjustments to reconcile net (loss) income to net cash provided by operating activities: |
|
|
|
| Depreciation, depletion, amortization and accretion | 86,465 |
|
| 46,466 |
|
| Unproved leasehold amortization and impairment | 22,232 |
|
| 14,471 |
|
| Gain on sale of other assets | (614 | ) |
| — |
|
| Amortization of deferred financing costs | 875 |
|
| 341 |
|
| Loss on derivative contracts | 46,588 |
|
| 64,216 |
|
| Net cash received (paid) upon settlement of derivative contracts | 8,677 |
|
| (13,911 | ) |
| Equity-based compensation | (157 | ) |
| 5,127 |
|
| Deferred income taxes | (9,487 | ) |
| — |
|
| Other | 6,547 |
|
| 117 |
|
| Changes in operating assets and liabilities increasing (decreasing) cash: |
|
|
|
|
|
| Accounts receivable and other assets | (21,667 | ) |
| (9,036 | ) |
| Accounts payable and other liabilities | (2,656 | ) |
| 44,415 |
|
| Net cash provided by operating activities | 105,993 |
|
| 164,530 |
|
| Cash flows from investing activities |
|
|
|
|
|
| Acquisition of oil and natural gas properties | — |
|
| (22,935 | ) |
| Capital expenditures for oil and natural gas properties | (304,896 | ) |
| (314,662 | ) |
| Acquisition of other property and equipment | (83 | ) |
| (2,371 | ) |
| Proceeds from sale of other assets | 1,214 |
|
| — |
|
| Net cash used in investing activities | (303,765 | ) |
| (339,968 | ) |
| Cash flows from financing activities |
|
|
|
|
|
| Proceeds from borrowings | 190,000 |
|
| 199,300 |
|
| Proceeds from borrowings - Affiliates | 48,750 |
| | — |
|
| Repayment of borrowings | (45,000 | ) |
| — |
|
| Other | 2,567 |
|
| (957 | ) |
| Net cash provided by financing activities | 196,317 |
|
| 198,343 |
|
| Net (decrease) increase in cash and cash equivalents | (1,455 | ) |
| 22,905 |
|
| Cash and cash equivalents, beginning of period | 6,883 |
|
| 1,471 |
|
| Cash and cash equivalents, end of period | $ | 5,428 |
|
| $ | 24,376 |
|
|
|
|
|
|
|
| Supplemental disclosure of cash flow information |
|
|
|
|
|
| Cash paid for interest, net of capitalized interest | $ | 13,685 |
|
| $ | 2,078 |
|
|
|
|
|
|
|
| Supplemental disclosure of non-cash investing and financing activities |
|
|
|
|
|
| Change in accrued capital expenditures | $ | (35,366 | ) |
| $ | (34,614 | ) |
| Acquisition of oil and natural gas properties for equity | $ | — |
|
| $ | 39,906 |
|
| Right of use assets obtained in exchange for operating lease liabilities | $ | 6,858 |
|
| $ | — |
|
| Shares issued in connection with Term Loan | $ | 2,317 |
|
| $ | — |
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
9
5
LINN ENERGY, INC.Roan Resources, Inc.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWSNotes to Unaudited Condensed Consolidated Financial Statements
(Unaudited)
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Six Months Ended June 30, 2018 | | Four Months Ended June 30, 2017 | | | Two Months Ended February 28, 2017 |
| (in thousands) | | | | | | |
| Cash flow from operating activities: | | | | | | |
| Net income | $ | 78,001 |
| | $ | 212,801 |
| | | $ | 2,397,061 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | |
| Loss from discontinued operations | — |
| | 3,254 |
| | | 548 |
|
| Depreciation, depletion and amortization | 50,445 |
| | 71,901 |
| | | 47,155 |
|
| Deferred income taxes | 46,031 |
| | 131,055 |
| | | (166 | ) |
| (Gains) losses on oil and natural gas derivatives | 22,555 |
| | (33,755 | ) | | | (92,691 | ) |
| Cash settlements on derivatives | (25,037 | ) | | 7,929 |
| | | (11,572 | ) |
| Share-based compensation expenses | 66,374 |
| | 19,599 |
| | | 50,255 |
|
| Amortization and write-off of deferred financing fees | 824 |
| | 82 |
| | | 1,338 |
|
| (Gains) losses on sale of assets and other, net | (224,091 | ) | | (293,800 | ) | | | 1,069 |
|
| Reorganization items, net | — |
| | — |
| | | (2,359,364 | ) |
| Changes in assets and liabilities: | | | | | | |
| (Increase) decrease in accounts receivable – trade, net | 76,465 |
| | 27,212 |
| | | (7,216 | ) |
| (Increase) decrease in other assets | 35,828 |
| | (9,146 | ) | | | 528 |
|
| Increase (decrease) in accounts payable and accrued expenses | (52,538 | ) | | (89,755 | ) | | | 20,949 |
|
| Increase (decrease) in other liabilities | (22,955 | ) | | 22,421 |
| | | 2,801 |
|
| Net cash provided by operating activities – continuing operations | 51,902 |
| | 69,798 |
| | | 50,695 |
|
| Net cash provided by operating activities – discontinued operations | — |
| | 13,966 |
| | | 8,781 |
|
| Net cash provided by operating activities | 51,902 |
| | 83,764 |
| | | 59,476 |
|
| | | | | | | |
| Cash flow from investing activities: | | | | | | |
| Development of oil and natural gas properties | (45,938 | ) | | (61,534 | ) | | | (50,597 | ) |
| Purchases of other property and equipment | (87,377 | ) | | (27,287 | ) | | | (7,409 | ) |
| Proceeds from sale of properties and equipment and other | 369,489 |
| | 697,829 |
| | | (166 | ) |
| Net cash provided by (used in) investing activities – continuing operations | 236,174 |
| | 609,008 |
| | | (58,172 | ) |
| Net cash used in investing activities – discontinued operations | — |
| | (1,645 | ) | | | (584 | ) |
| Net cash provided by (used in) investing activities | 236,174 |
| | 607,363 |
| | | (58,756 | ) |
| | | | | | | |
| | | | | | | |
LINN ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - Continued
(Unaudited)
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Six Months Ended June 30, 2018 | | Four Months Ended June 30, 2017 | | | Two Months Ended February 28, 2017 |
| (in thousands) | | | | | | |
| Cash flow from financing activities: | | | | | | |
| Proceeds from rights offerings, net | — |
| | — |
| | | 514,069 |
|
| Repurchases of shares | (393,647 | ) | | — |
| | | — |
|
| Proceeds from borrowings | — |
| | 160,000 |
| | | — |
|
| Repayments of debt | — |
| | (876,570 | ) | | | (1,038,986 | ) |
| Payment to holders of claims under the Predecessor’s second lien notes | — |
| | — |
| | | (30,000 | ) |
| Distributions to noncontrolling interests | (12,174 | ) | | (2,973 | ) | | | — |
|
| Cash settlements of equity classified RSUs | (58,162 | ) | | — |
| | | — |
|
| Other | (294 | ) | | (87 | ) | | | (6,015 | ) |
| Net cash used in financing activities – continuing operations | (464,277 | ) | | (719,630 | ) | | | (560,932 | ) |
| Net cash used in financing activities – discontinued operations | — |
| | — |
| | | — |
|
| Net cash used in financing activities | (464,277 | ) | | (719,630 | ) | | | (560,932 | ) |
| | | | | | | |
| Net decrease in cash, cash equivalents and restricted cash | (176,201 | ) | | (28,503 | ) | | | (560,212 | ) |
| Cash, cash equivalents and restricted cash: | | | | | | |
| Beginning | 520,953 |
| | 144,022 |
| | | 704,234 |
|
| Ending | $ | 344,752 |
| | $ | 115,519 |
| | | $ | 144,022 |
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 – Basis of PresentationBusiness and Organization
When referring to Linn Energy,
Roan Resources, Inc. (“Successor,Roan Inc.” “LINN Energy” or the “Company”), the intent is to refer to LINN Energy, a Delaware corporation was formed in February 2017,September 2018 to facilitate a reorganization and its then consolidated subsidiaries asto become the holding company for Roan Resources LLC (“Roan LLC”). In September 2018, a whole or on an individual basis, depending on the contextseries of transactions were executed with Roan LLC’s members which resulted in which the statements are made. During the reporting period Linn Energy, Inc. wasRoan LLC becoming a successor issuer of Linn Energy, LLC pursuant to Rule 15d‑5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Linn Energy, Inc. was not a successor of Linn Energy, LLC for purposes of Delaware corporate law. When referring to the “Predecessor” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to Linn Energy, LLC, the predecessor that will be dissolved following the effective date of the Plan (as defined in Note 2) 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.
As discussed under Holding Company Reorganization below in this Note 1, subsequent to the reporting period, on July 25, 2018, the Company completed a corporate reorganization pursuant to which LINN Energy merged with and into Linn Merger Sub #1, LLC (“Merger Sub”), a newly formed Delaware limited liability company and wholly owned subsidiary of New LINNRoan Inc., a newly formed Delaware corporation (“New LINN”), with Merger Sub surviving such merger (the “Merger”). Immediately following These transactions are hereafter referred to as the Merger, New LINN changed its name to “Linn Energy, Inc.“Reorganization.” For purposes of Rule 15d-5 under the Exchange Act, New LINN is the successor registrant to LINN Energy.
The reference to “Berry” herein refers to Berry Petroleum Company, LLC, which was an indirect 100% wholly owned subsidiarySee Note 10 – Equity for further discussion of the Predecessor through February 28,Reorganization transaction. The accompanying historical financial statements for the three and six months ended June 30, 2018 are the financial statements of Roan LLC, our accounting predecessor. Following the Reorganization, the historical financial statements are the results of Roan Inc.
Roan LLC was initially formed by Citizen Energy II, LLC (“Citizen”) in May 2017. Berry was deconsolidated effective December 3, 2016. The reference to “LinnCo” herein refers to LinnCo,On August 31, 2017, a contribution agreement (the “Contribution Agreement”) by and among Roan LLC, which was an affiliate of the Predecessor.
Nature of Business
LINN Energy was formed in February 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from January 2006 to February 2017. As discussed further in Note 2, on May 11, 2016 (the “Petition Date”),Citizen, Linn Energy Holdings, LLC certain of its direct(“LEH”) and indirect subsidiaries,Linn Operating, LLC (together with LEH, “Linn”) was executed, pursuant to which, among other things, Citizen and LinnCoLinn agreed to contribute oil and natural gas properties within an area-of-mutual-interest to Roan LLC (collectively the “LINN Debtors”“Contribution”). In exchange for their contributions, Citizen and Berry (collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District 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 pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017.
Prior to the Spin-off (as defined below), the Company’s upstream properties were located in six operating regions in the United States (“U.S.”): the Hugoton Basin, East Texas, North Louisiana, Michigan/Illinois, the Rockies and the Mid-Continent. The Company’s midstream business consisted of the Chisholm Trail gas plant system (“Chisholm Trail”) which is comprised of the newly constructed cryogenic natural gas processing facility, a refrigeration plant, and a network of gathering pipelines located in the Merge/SCOOP/STACK play. The Company also ownseach received a 50% equity interest in Roan ResourcesLLC. In conjunction with the Contribution Agreement, Roan LLC entered into management services agreements with both Citizen and Linn (“Roan”MSAs”), which is focused on the accelerated development. See Note 12 –Transactions with Affiliates for additional discussion of the Merge/SCOOP/STACK playMSAs and transactions with Citizen and Linn.
The Company was formed to engage in the acquisition, exploration, development, production, and sale of oil and natural gas reserves. The Company’s oil and natural gas properties are located in Central Oklahoma. DuringThe Company’s corporate headquarters is located in Oklahoma City, Oklahoma.
Note 2 – Summary of Significant Accounting Policies
For a description of the Company’s significant accounting policies, refer to Note 2 to the Company’s 2018 audited financial statements included in the Annual Report on Form 10-K. The accompanying condensed consolidated financial statements were prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”).
Certain amounts in the prior period financial statements have been reclassified to conform to the 2019 presentation. These reclassifications had no impact on net income (loss), total stockholders’ equity or total cash flows.
Principles of Consolidation
The condensed consolidated financial statements of the Company divested allinclude the accounts of Roan Inc. and its properties locatedwholly owned subsidiaries. All material intercompany balances and transactions have been eliminated.
Interim Financial Statements
The accompanying condensed consolidated financial statements as of December 31, 2018 were derived from the annual financial statements included in the previous Permian Basin operating region. During 2017,Annual Report on Form 10-K. The unaudited interim condensed consolidated financial statements for the Company divested all of its properties located inthree and six months ended June 30, 2019 and 2018 were prepared by the previous California and South Texas operating regions.
Holding Company Reorganization
On July 25, 2018, in accordance with Section 251(g) of the Delaware General Corporation Law, LINN Energy merged with and into Merger Sub, a newly formed Delaware limited liability company and wholly owned subsidiary of New LINN, with Merger Sub surviving the Merger. The Merger was completed pursuant to the terms of an Agreement and Plan of Merger by and among LINN Energy, New LINN and Merger Sub, dated July 25, 2018 (the “Merger Agreement”).
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Pursuant to the Merger Agreement, at the effective time of the Merger, all outstanding shares of Class A common stock of LINN Energy were automatically converted into identical shares of Class A common stock of New LINN on a one-for-one basis, and LINN Energy’s existing stockholders became stockholders of New LINNaccounting policies stated in the same amounts and percentages as they were in LINN Energy immediately prior to the Merger.
Spin-Off Transactions
audited financial statements. In April 2018, the Company announced its intention to separate its then wholly owned subsidiary, Riviera Resources, LLC (together with its corporate successor, “Riviera”) from LINN Energy. To effect the separation, Linn Energy, Inc. and certain of its direct and indirect subsidiaries undertook an internal reorganization (including the conversion of Riviera from a limited liability company to a corporation), following which Riviera Resources, Inc. holds, directly or through its subsidiaries, substantially all of the assets of LINN Energy, other than LINN Energy’s 50% equity interest in Roan. Following the internal reorganization, Linn Energy, Inc. distributed all of the outstanding shares of common stock of Riviera to LINN Energy stockholders on a pro rata basis (the “Spin-off”). Following the Spin-off, Riviera Resources, Inc. is an independent reporting company quoted for trading on the OTC Market under the ticker “RVRA.” LINN Energy did not retain any ownership interest in Riviera and will remain a reporting company quoted for trading on the OTCQB Market under the symbol “LNGG.” The Spin-off was completed on August 7, 2018.
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
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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 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, 2017. 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 pre-Spin-off subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Noncontrolling interests represented ownership in the net assets of the Company’s previous consolidated subsidiary, Linn Energy Holdco LLC (“Holdco”), not attributable to LINN Energy, and were presented as a component of equity. Changes in the Company’s ownership interests in Holdco that did not result in deconsolidation were recognized in equity. Effective April 10, 2018, all outstanding Class A‑2 units in Holdco (“Holdco Class A-2 units”) were converted into Class A common stock in LINN Energy in accordance with the terms of Holdco’s Limited Liability Company Operating Agreement (the “Holdco LLC Agreement”) and the noncontrolling interest was dissolved. 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.
The condensed consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss) or stockholders equity. As a result of the adoption of ASU 2016-18 and the inclusion of restricted cash in the statements of cash flows, previously reported net cash provided by operating activities and cash provided by investing activities have been updated to conform to current presentation. See recently adopted accounting standards below for additional information.
Bankruptcy Accounting
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 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 subsequent tothereto.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Estimates
February 28, 2017. References to “Predecessor” relate to the financial positionThe preparation 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. See Note 2 for additional information.
Use of Estimates
The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires that management of the Company to makeformulate estimates and assumptions about future events. These estimatesthat affect revenues, expenses, assets, liabilities and the underlying assumptions affect the amountdisclosure of assets and liabilities reported, disclosures about contingent assets and liabilities,liabilities. A significant item that requires management’s estimates and reported amountsassumptions is the estimate of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves ofproved oil, natural gas and natural gas liquids (“NGL”), future cash flows fromNGL reserves which are used in the calculation of depletion of the Company’s oil and natural gas properties depreciation, depletion and amortization, asset retirement obligations, certain revenuesimpairment, if any, of proved oil and operating expenses,natural gas properties. Changes in estimated quantities of its reserves could impact the Company’s reported financial results as well as disclosures regarding the quantities and fair values of commodity derivatives. 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.
Recently Adopted
Recent Accounting Standards Issued
In NovemberFebruary 2016, the Financial Accounting Standards Board (“FASB”)FASB issued an Accounting Standards Update (“ASU”ASU 2016-02, Leases (Topic 842) (“ASC 842”). This update applies to any entity that is intended to address diversityenters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the classification and presentation of changes in restricted cash on the statement of cash flows.financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. The Company adopted thisthe new standard using the simplified transition method described in ASU on2018-11 Leases (Topic 842): Targeted Improvements as of January 1, 2018, on a retrospective basis. The adoption of this ASU resulted in2019 and did not retrospectively apply 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 sheetsnew standard to cash, cash equivalents and restricted cash on the statement of cash flows (see Note 17).
In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers (“ASC 606”). The Company adopted this ASU on January 1, 2018, using the modified retrospective transition method.periods before adoption. Accordingly, the comparative information for the six months ended June 30, 2017, has not been adjusted and continues to be reported under the previous revenueleasing standard. See Note 3 - Lease Accounting for additional information on the adoption of ASC 842.
Note 3 - Lease Accounting
The Company adopted ASC 842 on January 1, 2019 using the simplified transition method described in ASU 2018-11 Leases (Topic 842): Targeted Improvements. Accordingly, comparative information was not adjusted and will continue to be reported under the previous lease standard. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment. The Company further utilized the package of thispractical expedients within ASC 842 that allows an entity to not reassess the following prior to the effective date (i) whether any expired or existing contracts were or contained leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases. The Company also elected the practical expedient under ASU impacted2018-01 Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 that allows it to not evaluate existing or expired land easements not previously accounted for as leases prior to the Company’s gross revenues and expenses as reported on its condensed consolidated statements of operations (see below), and resulted in increased disclosures regarding the Company’s disaggregation of revenue (see Note 3).
Under ASC 606,effective date. Finally, the Company recognizes revenues based on a determination of when control of its commodities is transferredhas elected the short-term lease recognition exemption for all leases that qualify and whether it is acting as a principal or agent in certain transactions. All factsthe practical expedient to not separate lease and circumstances of an arrangement are considered and judgment is often required in making this determination. For its natural gas contracts, the Company generally records its sales at the wellhead or inlet of the plant as revenues net of transportation, gathering and processing expenses if the processor is the customer and there is no redelivery of commodities to the Company. Conversely, the Company generally records its sales at the tailgate of the plant on a gross basis alongnon-lease components for all asset classes with the associated transportation, gathering and processing expenses if the processor is a service provider and there is redelivery of commodities to the Company.
In addition, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities. This recognition results in an increase to revenues and expenses with no material impact on net income.multiple component types.
LINN ENERGY, INC.Roan Resources, Inc.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – ContinuedNotes to Unaudited Condensed Consolidated Financial Statements
(Unaudited)
The items discussed above impactedCompany enters into lease agreements to support its operations, such as office space, drilling rigs and field equipment. ASC 842 does not impact the accounting or financial presentation of the Company’s reported “oil, natural gasmineral leases and also does not apply to leases used in the exploration or use of oil and natural gas, liquids sales,” “marketing revenues,” “other revenues,” “transportation expenses,” “marketing expenses”including the rights to explore for those natural resources and “interest expense.” The impact of adoption onrights to use the Company’s current period results is as follows:
|
| | | | | | | | | | | |
| | Three Months Ended June 30, 2018 |
| | Under ASC 606 | | Under Prior Rule | | Increase/ (Decrease) |
| | (in thousands) |
| Revenues: | | | | | |
| Natural gas sales | $ | 53,662 |
| | $ | 53,285 |
| | $ | 377 |
|
| Oil sales | 10,919 |
| | 10,919 |
| | — |
|
| NGL sales | 22,423 |
| | 22,280 |
| | 143 |
|
| Total oil, natural gas and NGL sales | 87,004 |
| | 86,484 |
| | 520 |
|
| Marketing revenues | 42,967 |
| | 25,406 |
| | 17,561 |
|
| Other revenues | 6,387 |
| | 6,003 |
| | 384 |
|
| | 136,358 |
| | 117,893 |
| | 18,465 |
|
| Expenses: | | | | | |
| Transportation expenses | 21,213 |
| | 20,693 |
| | 520 |
|
| Marketing expenses | 40,327 |
| | 22,766 |
| | 17,561 |
|
| Interest expense | 584 |
| | 420 |
| | 164 |
|
| Net income | $ | 6,903 |
| | $ | 6,683 |
| | $ | 220 |
|
|
| | | | | | | | | | | |
| | Six Months Ended June 30, 2018 |
| | Under ASC 606 | | Under Prior Rule | | Increase/ (Decrease) |
| | (in thousands) |
| Revenues: | | | | | |
| Natural gas sales | $ | 116,990 |
| | $ | 117,794 |
| | $ | (804 | ) |
| Oil sales | 56,615 |
| | 56,615 |
| | — |
|
| NGL sales | 50,275 |
| | 50,222 |
| | 53 |
|
| Total oil, natural gas and NGL sales | 223,880 |
| | 224,631 |
| | (751 | ) |
| Marketing revenues | 89,234 |
| | 53,521 |
| | 35,713 |
|
| Other revenues | 12,281 |
| | 11,676 |
| | 605 |
|
| | 325,395 |
| | 289,828 |
| | 35,567 |
|
| Expenses: | | | | | |
| Transportation expenses | 40,307 |
| | 41,058 |
| | (751 | ) |
| Marketing expenses | 82,082 |
| | 46,369 |
| | 35,713 |
|
| Interest expense | 988 |
| | 824 |
| | 164 |
|
| Net income | $ | 78,001 |
| | $ | 77,560 |
| | $ | 441 |
|
New Accounting Standards Issued But Not Yet Adopted
In February 2016,To facilitate compliance with ASC 842, the FASB issued an ASU that is intendedCompany evaluated its existing lease arrangements and enhanced its systems, processes and internal controls to increase transparencyidentify, track and comparability among organizations byrecord applicable leases. The implementation and adoption of this standard resulted in the Company recognizing leaseright-of-use assets and lease liabilities for certain of its operating leases on the accompanying condensed consolidated balance sheet. This ASU is effective for fiscal years beginning after
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
December 15, 2018, and interim periods within those years (early adoption permitted).June 30, 2019. The Company is currently evaluatinghas no finance leases. The following table shows the impact of the adoption of this ASUASC 842 on its financial statements and related disclosures. The Company expects the adoption of this ASU to impact itsCompany’s current period balance sheet resulting from an increase in both assets and liabilities relatedas compared to the Company’s leasing activities.
Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 and Fresh Start Accounting
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, LLCprevious lease accounting standard, ASC Topic 840, Leases (“LAC”ASC 840”) 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.
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 |
| | Three Months Ended June 30, |
| | 2018 | | 2017 |
| | (in thousands) |
| | | | |
| Legal and other professional advisory fees | $ | (1,255 | ) | | $ | (3,446 | ) |
| Other | (4 | ) | | 69 |
|
| Reorganization items, net | $ | (1,259 | ) | | $ | (3,377 | ) |
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
:
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Six Months Ended June 30, 2018 | | Four Months Ended June 30, 2017 | | | Two Months Ended February 28, 2017 |
| (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 fees | (3,207 | ) | | (6,016 | ) | | | (46,961 | ) |
| Terminated contracts | — |
| | — |
| | | (6,915 | ) |
| Other | (3 | ) | | 74 |
| | | (13,049 | ) |
| Reorganization items, net | $ | (3,210 | ) | | $ | (5,942 | ) | | | $ | 2,331,189 |
|
|
| | | | | | | | | |
| | As of June 30, 2019 |
| | Under ASC 842 | Under ASC 840 | Increase/(decrease) |
| | (in thousands) |
| Other noncurrent assets | $ | 5,756 |
| $ | — |
| $ | 5,756 |
|
| Other current liabilities | $ | 1,904 |
| $ | — |
| $ | 1,904 |
|
| Other noncurrent liabilities | $ | 4,954 |
| $ | 1,102 |
| $ | 3,852 |
|
Fresh Start
Lease Accounting Policies
Upon
The Company determines if an arrangement is a lease at the inception of the arrangement by (i) identifying any assets within the contract (ii) determining whether the Company has the right to obtain substantially all of the economic benefits from use of the asset throughout the period of use and (iii) if the Company has the right to direct how and for what purpose the identified asset is used throughout the period of use. To the extent that it is determined that an arrangement represents a lease, the lease is classified as an operating lease or a finance lease. The Company capitalizes both lease classifications on its consolidated balance sheets through a right-of-use (“ROU”) asset and a corresponding lease liability. ROU assets represent the Company’s emergenceright to use an underlying asset for the lease term, and lease liabilities represent the Company’s obligation to make lease payments arising from Chapter 11 bankruptcy, it adopted fresh start accountingthe lease.
Operating leases are included in accordance with the provisions of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”), which resultedother noncurrent assets, other current liabilities, and other noncurrent liabilities in the Company becomingconsolidated balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments is recognized on a new entity for financial reporting purposes. In accordance with ASC 852,straight-line basis over 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 valuelease term.
Certain of the Company’s assets immediately priorlease agreements include lease and non-lease components. For all asset classes with multiple component types, the Company has utilized the practical expedient that exempts it from separating lease components from non-lease components. Accordingly, the Company accounts for the lease and non-lease components in an arrangement as a single lease component.
In addition, for all asset classes, the Company has made an accounting policy election not to confirmationapply the lease recognition requirements to its short-term leases (that is, a lease that, at commencement, has a lease term of
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
12 months or less and does not include an option to purchase the underlying asset that the Company is reasonably certain to exercise). Accordingly, the Company recognizes lease payments related to its short-term leases in profit or loss on a straight-line basis over the lease term. To the extent that there are variable lease payments, the Company recognizes those payments in profit or loss in the period in which the obligation for those payments is incurred. Refer to “Nature of Leases” below for further information regarding those asset classes that include material short-term leases.
Nature of Leases
The Company leases certain office space, drilling rigs and field equipment under cancelable and non-cancelable leases to support our operations.
Office Buildings. The Company leases its corporate office space in Oklahoma City, Oklahoma and additional office space for its field location in Oklahoma. In general, the Company’s office lease agreements contain provisions to extend the lease and contain protective provisions that allow for early termination. Beginning in March 2019, the Company began paying its portion 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 valuebuilding’s operating expenses, as discloseddefined in the Plan was allocated tocorporate office lease agreement. These expenses are considered variable leases payments, which were not included in the Company’s assets and liabilities based on their fair values (except for deferred income taxes) in accordance with ASC 805 “Business Combinations.” The amount of deferred income taxes recorded was determined in accordance with ASC 740 “Income Taxes.” The Effective Date fair valuesmeasurement of the lease liability. The Company’s assets and liabilities differed materially from their recorded values asoffice building leases are long term leases reflected under ASC 842 on the historical balance sheet. The effects of the Plan and the application of fresh start accounting were reflected on theaccompanying condensed consolidated balance sheet as of February 28, 2017,June 30, 2019.
Drilling Rigs. The Company enters into daywork contracts for drilling rigs with third party service contractors to support the development and exploitation of undeveloped reserves. All of the Company’s current drilling contracts have a term of one year or less.
Field Equipment. The Company rents various field equipment, including compressors, from third parties in order to facilitate its operations. Compressor arrangements are typically structured with a non-cancelable primary term of twelve months and continue thereafter on a month-to-month basis subject to termination by either party with thirty days’ notice. The Company has concluded that its compressor rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term. Other field equipment arrangements are typically structured on a month-to-month basis subject to termination by either party.
To the extent that field equipment rental arrangements have a primary term of twelve months or less, the Company has elected to apply the practical expedient for short-term leases. For those short-term arrangements, the Company does not apply the lease recognition requirements, and recognizes lease payments related adjustments thereto were recordedto these arrangements in profit or loss on a straight-line basis over the lease term. Refer to the “Lease Accounting Policies” section above for discussion of practical expedients applied.
Discount Rate. The Company’s leases typically do not provide an implicit rate, and thus, it is required that the Company use its incremental borrowing rate in determining the present value of lease payments based on the condensed consolidated statementinformation available at commencement date. The Company’s incremental borrowing rate reflects the rate of operations forinterest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the two months ended February 28, 2017.lease payments in a similar economic environment. The Company uses the implicit rate in the limited circumstances in which that rate is readily determinable.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 34 – Revenues
Revenue from Contracts with Customers
The Company recognized sales
Revenues from the sale of oil, natural gas and NGLNGLs are recognized when it satisfied a performance obligation by transferring control of the product has been transferred to the customer, all performance obligations have been satisfied and collectability is reasonably assured. We recognize revenues from the sale of oil, natural gas and NGLs based on our share of volumes sold.
Performance Obligations
The Company satisfies the performance obligations under its oil and natural gas sales contracts through delivery of its production and transfer of control to a customer, in an amount that reflected the consideration to whichcustomer. Upon delivery of production, the Company expectedhas the right to be entitledreceive consideration from its customers in exchange foramounts that correspond with the product.
Natural Gas and NGL Sales
The Company’s natural gas production was primarily sold under market-sensitive contracts that were typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets.
For its natural gas contracts, the Company generally recorded its wet gas sales at the wellhead or inletvalue of the plant as revenues net of transportation, gathering and processing expenses, and its residualproduction transferred. The Company typically receives payment for oil, natural gas and NGL sales at the tailgatewithin 30 days of the plant on a gross basis along withmonth of delivery for operated properties and within 90 days of the associated transportation, gathering and processing expenses. All facts and circumstancesmonth of an arrangement were considered and judgment was often required in making this determination.delivery for non-operated properties.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Oil Sales
The Company’s oil production was primarily sold under market-sensitive contracts that were typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or at purchaser posted prices for the producing area. For its oil contracts, the Company generally recorded its sales based on the net amount received.
Production Imbalances
The Company used the sales method to account for natural gas production imbalances. If the Company’s sales volumes for a well exceeded the Company’s proportionate share of production from the well, a liability was recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well was insufficient to satisfy this imbalance. No receivables were recorded for those wells on which the Company had taken less than its proportionate share of production.
Marketing Revenues
The Company engaged in the purchase, gathering and transportation of third-party natural gas and subsequently marketed such natural gas to independent purchasers under separate arrangements. As such, the Company separately reported third-party marketing revenues and marketing expenses.
Disaggregation of Revenue
The following tables present the Company’s disaggregated revenues by source and geographic area:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, 2018 |
| | | Natural Gas | | Oil | | NGL | | Oil, Natural Gas and NGL Sales | | Marketing Revenues | | Other Revenues | | Total |
| | | (in thousands) |
| | | | | | | | | | | | | | | |
| Hugoton Basin | | $ | 17,401 |
| | $ | 238 |
| | $ | 16,875 |
| | $ | 34,514 |
| | $ | 22,421 |
| | $ | 6,303 |
| | $ | 63,238 |
|
| Mid-Continent | | 7,622 |
| | 4,880 |
| | 3,307 |
| | 15,809 |
| | — |
| | 25 |
| | 15,834 |
|
| East Texas | | 12,661 |
| | 1,091 |
| | 1,013 |
| | 14,765 |
| | 467 |
| | 3 |
| | 15,235 |
|
| Permian Basin | | 256 |
| | 546 |
| | (488 | ) | | 314 |
| | — |
| | 16 |
| | 330 |
|
| Rockies | | 2,146 |
| | 1,885 |
| | 1,201 |
| | 5,232 |
| | — |
| | 1 |
| | 5,233 |
|
| North Louisiana | | 6,040 |
| | 1,480 |
| | 503 |
| | 8,023 |
| | 13 |
| | 2 |
| | 8,038 |
|
| Michigan/Illinois | | 7,536 |
| | 799 |
| | 12 |
| | 8,347 |
| | — |
| | 37 |
| | 8,384 |
|
| Chisholm Trail | | — |
| | — |
| | — |
| | — |
| | 20,066 |
| | — |
| | 20,066 |
|
| Total | | $ | 53,662 |
| | $ | 10,919 |
| | $ | 22,423 |
| | $ | 87,004 |
| | $ | 42,967 |
| | $ | 6,387 |
| | $ | 136,358 |
|
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30, 2018 |
| | | Natural Gas | | Oil | | NGL | | Oil, Natural Gas and NGL Sales | | Marketing Revenues | | Other Revenues | | Total |
| | | (in thousands) |
| | | | | | | | | | | | | | | |
| Hugoton Basin | | $ | 39,764 |
| | $ | 2,970 |
| | $ | 36,389 |
| | $ | 79,123 |
| | $ | 46,501 |
| | $ | 12,134 |
| | $ | 137,758 |
|
| Mid-Continent | | 15,555 |
| | 16,747 |
| | 6,361 |
| | 38,663 |
| | — |
| | 39 |
| | 38,702 |
|
| East Texas | | 27,437 |
| | 2,431 |
| | 2,319 |
| | 32,187 |
| | 503 |
| | 8 |
| | 32,698 |
|
| Permian Basin | | 2,282 |
| | 20,654 |
| | 2,557 |
| | 25,493 |
| | — |
| | 32 |
| | 25,525 |
|
| Rockies | | 5,526 |
| | 9,255 |
| | 2,559 |
| | 17,340 |
| | — |
| | (1 | ) | | 17,339 |
|
| North Louisiana | | 12,418 |
| | 3,049 |
| | 67 |
| | 15,534 |
| | 272 |
| | 3 |
| | 15,809 |
|
| Michigan/Illinois | | 14,008 |
| | 1,509 |
| | 23 |
| | 15,540 |
| | — |
| | 66 |
| | 15,606 |
|
| Chisholm Trail | | — |
| | — |
| | — |
| | — |
| | 41,958 |
| | — |
| | 41,958 |
|
| Total | | $ | 116,990 |
| | $ | 56,615 |
| | $ | 50,275 |
| | $ | 223,880 |
| | $ | 89,234 |
| | $ | 12,281 |
| | $ | 325,395 |
|
Contract Balances
Under the Company’s product sales contracts its customers were invoiced once the Company’s performance obligations had been satisfied, at which point payment was unconditional. Accordingly, the Company’s product sales contracts did not give rise to material contract assets or contract liabilities.
The Company had trade accounts receivable related to revenue from contracts with customers of approximately $56 million and $117 million as of June 30, 2018, and December 31, 2017, respectively.
Performance Obligations
The majority of the Company’s sales wereare short-term in nature with a contract term of one year or less. For those contracts, the Company utilized the practical expedient in Revenue from Contracts with Customers (Topic 606) (“ASC 606-10-50-14 exempting the Company606”), which provides an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation wasis part of a contract that hadhas an original expected duration of one year or less.
For the Company’s productnatural gas and NGL sales contracts that hadhave a contract term greater than one year, the Company utilized the practical expedient in ASC 606-10-50-14(A)606 which states the Company wasis not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration wasis allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally representedrepresents a separate performance obligation; therefore, future volumes wereare wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations wasis not required.
Note 4 – DivestituresContract Balances
The Company recognizes sales of oil, natural gas, and Discontinued Operations
Divestitures – 2018
On April 10, 2018,NGLs at a point in time when it satisfies a performance obligation and 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 as of June 30, 2019 and December 31, 2018 of approximately $47.5 million and $65.2 million, respectively, 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 conventional 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 New Mexico. Cash proceedsthe month payment is received from the sale of these properties were approximately $15 millioncustomer. For the three and the Company recognized a net gain of approximately $11 million.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
On April 4, 2018, the Company completed the sale of its interest in properties located in the Altamont Bluebell Field in Utah (the “Altamont Bluebell Assets Sale”). Cash proceeds received from the sale of these properties were approximately $132 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $83 million.
On March 29, 2018, the Company completed the sale of its interest in conventional properties located in west Texas. Cash proceeds received from the sale of these properties were approximately $107 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $55 million.
On February 28, 2018, the Company completed the sale of its Oklahoma waterflood and Texas Panhandle properties (the “Oklahoma and Texas Assets Sale”). Cash proceeds received from the sale of these properties were approximately $112 million (including a deposit of approximately $12 million received in 2017), net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $46 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 and were part of the upstream segment.
The assets and liabilities associated with the Oklahoma and Texas Assets Sale were classified as “held for sale” on the condensed consolidated balance sheet at December 31, 2017. At December 31, 2017, the Company’s condensed consolidated balance sheet included current assets of approximately $107 million included in “assets held for sale” and current liabilities of approximately $43 million included in “liabilities held for sale” related to this transaction.
The following table presents carrying amounts of the assets and liabilities of the Company’s properties classified as held for sale on the condensed consolidated balance sheet:
|
| | | |
| | December 31, 2017 |
| | (in thousands) |
| Assets: | |
| Oil and natural gas properties | $ | 92,245 |
|
| Other property and equipment | 12,983 |
|
| Other | 1,735 |
|
| Total assets held for sale | $ | 106,963 |
|
| Liabilities: | |
| Asset retirement obligations | $ | 42,001 |
|
| Other | 1,301 |
|
| Total liabilities held for sale | $ | 43,302 |
|
Other assets primarily include inventories and other liabilities primarily include accounts payable.
Divestitures – 2017
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 $76 million and the Company recognized a net gain of approximately $22 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 $279 million.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
The gains on these divestitures are included in “(gains) losses on sale of assets and other, net” on the condensed consolidated statements of operations.
Discontinued Operations
During 2017, the Company completed the sale of its interest in properties located in the San Joaquin Basin and the Los Angeles Basin in California. As a result of the Company’s strategic exit from California, the Company classified the results of operations and cash flows of its California properties as discontinued operations on its condensed consolidated financial statements. The California properties were included in the upstream segment.
The following tables present summarized financial results of the Company’s California properties classified as discontinued operations on the condensed consolidated statements of operations:
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended June 30, 2017 | | Four Months Ended June 30, 2017 | | | Two Months Ended February 28, 2017 |
| (in thousands) | | | | | | |
| Revenues and other | $ | 20,511 |
| | $ | 27,636 |
| | | $ | 14,891 |
|
| Expenses | 25,935 |
| | 30,344 |
| | | 13,758 |
|
| Other income and (expenses) | (2,074 | ) | | (2,791 | ) | | | (1,681 | ) |
| Loss from discontinued operations before income taxes | (7,498 | ) | | (5,499 | ) | | | (548 | ) |
| Income tax benefit | (4,176 | ) | | (2,245 | ) | | | — |
|
| Loss from discontinued operations, net of income taxes | $ | (3,322 | ) | | $ | (3,254 | ) | | | $ | (548 | ) |
Other income and (expenses) include an allocation of interest expense for the California properties 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”).
Under the TSSA, Berry reimbursed LINN Energy for any and all reasonable, third-party out-of-pocket costs and expenses, without markup, actually incurred by LINN Energy, to the extent documented, in connection with providing the Transition Services. Additionally, Berry paid to LINN Energy a management fee of $6 million per month, prorated for partialsix months during the period from the Effective Date through the last day of the second full calendar month after the Effective Date (the “Transition Period”) 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, 2017.2019 and 2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.
LINN ENERGY, INC.Notes to Unaudited Condensed Consolidated Financial Statements
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Note 5 – Oil and Natural Gas Properties
OilThe Company’s oil and Natural Gas Capitalized Costs
Aggregate capitalized costs related to oil, natural gas properties are in the continental United States. The oil and NGL production activities with applicable accumulated depletion and amortization are presented below:natural gas properties include the following:
|
| | | | | | | |
| | June 30, 2018 | | December 31, 2017 |
| | (in thousands) |
| | | | |
| Proved properties | $ | 739,656 |
| | $ | 904,390 |
|
| Unproved properties | 46,159 |
| | 45,693 |
|
| | 785,815 |
| | 950,083 |
|
| Less accumulated depletion and amortization | (59,870 | ) | | (49,619 | ) |
| | $ | 725,945 |
| | $ | 900,464 |
|
|
| | | | | | | |
| | June 30, 2019 | | December 31, 2018 |
| | (in thousands) |
| Oil and natural gas properties | | | |
| Proved | $ | 1,842,548 |
| | $ | 1,538,379 |
|
| Unproved | 1,071,073 |
| | 1,089,954 |
|
| Less: accumulated depreciation, depletion, amortization and impairment | (335,678 | ) | | (230,836 | ) |
| Oil and natural gas properties, net | $ | 2,577,943 |
| | $ | 2,397,497 |
|
Note 6 – Equity Method Investments
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.
The Company uses the equity method of accounting forrecorded amortization expense on 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 June 30, 2018, and December 31, 2017, the Company owned 50% of Roan’s outstanding units.
At June 30, 2018, the carrying amount of the Company’s investment in Roan of approximately $466 million was less than the Company’s ownership interest in Roan’s underlying net assets by approximately $355 million. The difference is attributable to proved and unproved oil and natural gas properties of $10.9 million and is amortized over$7.1 million for the lives of the related assets. Such amortization is included in the equity earnings (losses) from the Company’s investment in Roan. At December 31, 2017, the carrying amount of the Company’s investment in Roan of approximately $458three months ended June 30, 2019 and 2018, respectively, and $22.2 million was less than the Company’s ownership interest in Roan’s underlying net assets by approximately $346 million.
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$14.5 million for the six months ended June 30, 2018.
Following2019 and 2018, respectively. Unproved leasehold amortization expense is summarizedreflected in exploration expense on the accompanying condensed consolidated statements of operations information for Roan.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Summarized Roan Resources LLC Statements of Operations Information
|
| | | | | | | |
| | Three Months Ended June 30, 2018 | | Six Months Ended June 30, 2018 |
| | (in thousands) |
| | | | |
| Revenues and other | $ | 44,789 |
| | $ | 145,873 |
|
| Expenses | 72,754 |
| | 130,663 |
|
| Other income and (expenses) | (1,087 | ) | | (2,886 | ) |
| Net income (loss) | $ | (29,052 | ) | | $ | 12,324 |
|
Note 7 – Debt
Credit Facility
On August 4, 2017, the Company entered into a credit agreement with its then subsidiary, Linn Energy Holdco II LLC (“Holdco II”), as borrower, Royal Bank of Canada, as administrative agent,Company’s drilling plans and the lenders and agents party thereto, providing for a new senior secured reserve-based revolving loan facility (the “Credit Facility”) with $500 million in borrowing commitments and an initial borrowing baselease terms of $500 million.
On April 30, 2018, the Company entered into an amendment to the Credit Facility which, among other things, modified the borrowing base and maximum borrowing commitment amount to $425 million.
Asits existing unproved properties. No impairment of June 30, 2018, there were no borrowings outstanding under the Credit Facility and there was approximately $378 million of available borrowing capacity (which includes a $47 million reduction for outstanding letters of credit). The maturity date is August 4, 2020. Pursuant to the Spin-off, Holdco II became a subsidiary of Riviera and as such, Riviera and its subsidiaries have assumed all obligations under the Credit Facility.
Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. At the Company’s election, interest on borrowings under the 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 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 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 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 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 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 Credit Facility would allow the lenders, subject to customary cure rights, to require immediate payment of all amounts outstanding under the Credit Facility.
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 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 arewas recorded in current earnings. See Note 9 for fair value disclosures about oil and natural gas commodity derivatives.
The following table presents derivative positions for the periods indicated as of June 30, 2018: |
| | | | | | | |
| | July 1 – December 31, 2018 | | 2019 |
| Natural gas positions: | | | |
| Fixed price swaps (NYMEX Henry Hub): | | | |
| Hedged volume (MMMBtu) | 35,144 |
| | 22,265 |
|
| Average price ($/MMBtu) | $ | 3.02 |
| | $ | 2.89 |
|
| Oil positions: | | | |
| Fixed price swaps (NYMEX WTI): | | | |
| Hedged volume (MBbls) | 276 |
| | 183 |
|
| Average price ($/Bbl) | $ | 54.07 |
| | $ | 64.00 |
|
Natural gas basis differential positions: (1) | | | |
| PEPL basis swaps: | | | |
| Hedged volume (MMMBtu) | 7,360 |
| | 14,600 |
|
| Hedge differential | $ | (0.67 | ) | | $ | (0.67 | ) |
| NGPL TXOK basis swaps: | | | |
| Hedged volume (MMMBtu) | 1,840 |
| | — |
|
| Hedge differential | $ | (0.19 | ) | | $ | — |
|
| |
(1)
| Settled or to be settled, as applicable, on the indicated pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price. |
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
During the six months ended June 30, 2018, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for March 2018 through December 2019, natural gas fixed price swaps for January 2019 through December 2019 and oil fixed price swaps for January 2019 through December 2019. During the four months ended June 30, 2017, the Company entered into commodity derivative contracts consisting of oil fixed price swaps for January 2018 through December 2018 and natural gas fixed price 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 April 2018, in connection with the closing of the Altamont Bluebell Assets Sale, the Company canceled its oil collars for 2018 and 2019. The Company paid net cash settlements of approximately $20 million for the cancellations.
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:
|
| | | | | | | |
| | June 30, 2018 | | December 31, 2017 |
| | (in thousands) |
| Assets: | | | |
| Commodity derivatives | $ | 6,825 |
| | $ | 22,589 |
|
| Liabilities: | | | |
| Commodity derivatives | $ | 7,197 |
| | $ | 25,443 |
|
By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposed 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 Company’s counterparties are participants in the Credit Facility. The Credit Facility was secured by certain of the Company’s and its then subsidiaries’ oil, natural gas and NGL reserves and personal property; therefore, the Company was not required to post any collateral. The Company did 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 $7 million at June 30, 2018. The Company minimized 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 were subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance was somewhat mitigated.
Gains and Losses on Derivatives
Gains and losses on derivatives were net losses of approximately $8 million and $23 million for the three months and six months ended June 30, 2018, respectively, and net gains of approximately $46 million and $34 million for the three months and four months ended June 30, 2017, respectively, and approximately $93 million for the two months ended February 28, 2017.2019 or 2018.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
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 paid net cash settlements of approximately $21 million and $25 million for the three months and six months ended June 30, 2018, respectively. The Company received net cash settlements of approximately $2 million and $8 million for the three months and four months ended June 30, 2017, respectively, and paid net cash settlements of approximately $12 million for the two months ended February 28, 2017.
Note 9 – Fair Value Measurements on a Recurring Basis
The Company accounted for its commodity derivatives at fair value (see Note 8) on a recurring basis. The Company determined 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 included publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validated 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. Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads, were 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 based on the priority of inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
|
| | | | | | | | | | | |
| | June 30, 2018 |
| | Level 2 | | Netting (1) | | Total |
| | (in thousands) |
| Assets: | | | | | |
| Commodity derivatives | $ | 6,825 |
| | $ | (1,637 | ) | | $ | 5,188 |
|
| Liabilities: | | | | | |
| Commodity derivatives | $ | 7,197 |
| | $ | (1,637 | ) | | $ | 5,560 |
|
|
| | | | | | | | | | | |
| | December 31, 2017 |
| | Level 2 | | Netting (1) | | Total |
| | (in thousands) |
| Assets: | | | | | |
| Commodity derivatives | $ | 22,589 |
| | $ | (12,491 | ) | | $ | 10,098 |
|
| Liabilities: | | | | | |
| Commodity derivatives | $ | 25,443 |
| | $ | (12,491 | ) | | $ | 12,952 |
|
| |
(1)
| Represents counterparty netting under agreements governing such derivatives. |
Note 106 – Asset Retirement Obligations
The Company had the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs were recognized as liabilities with an increase to the carrying amounts of the
22The following is a reconciliation of the changes in the Company’s asset retirement obligation (“ARO”) for the six months ended June 30, 2019 (in thousands):
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
|
| | | |
| Asset retirement obligation, December 31, 2018 | $ | 16,848 |
|
| Liabilities incurred or acquired | 920 |
|
| Revisions in estimated cash flows | — |
|
| Liabilities settled | (90 | ) |
| Accretion expense | 569 |
|
| Asset retirement obligation, June 30, 2019 | 18,247 |
|
Less: current portion of obligations (1) | 751 |
|
| Asset retirement obligation – long term | $ | 17,496 |
|
related long-lived assets when(1) The current portion of the obligationARO liability is incurred. The liabilities are included in “other accrued liabilities” and “asset retirement obligations and other noncurrent liabilities”current liabilities on the condensed consolidated balance sheets. Accretion expensesheet.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 7 – Long-Term Debt
Long-term debt consists of the following:
|
| | | | | | | |
| | June 30, 2019 | | December 31, 2018 |
| | (in thousands) |
| Credit Facility | $ | 659,639 |
| | $ | 514,639 |
|
| Term Loan | 50,000 |
| | — |
|
| Unamortized original issue discount on Term Loan | (1,250 | ) | | — |
|
| Deferred financing costs on Term Loan | (3,826 | ) | | — |
|
| Less: current portion | — |
| | — |
|
| Total Long-term debt, net | $ | 704,563 |
| | $ | 514,639 |
|
Credit Facility
In September 2017, the Company entered into a $750.0 million credit agreement with a maturity date of September 5, 2022 (as amended, the “Credit Facility”). Redetermination of the borrowing base of the Credit Facility occurs semiannually on or about October 1 and April 1. As of June 30, 2019, the Company had $659.6 million of outstanding borrowings and no letters of credit outstanding under the Credit Facility. The Credit Facility is secured by substantially all of the assets of Roan LLC. As discussed below, the Company entered into a Term Loan in June 2019 and used a majority of the proceeds from the initial borrowing to pay down $45.0 million of outstanding borrowings under the Credit Facility.
The Company amended the Credit Facility in March 2019 to increase the borrowing base as well as to allow for (i) secured permitted additional debt of up to $250 million before any reduction in the borrowing base would occur and (ii) unsecured permitted additional debt of up to $400 million before any reduction in the borrowing base would occur.
Effective June 2019, the Credit Facility was amended to (i) reaffirm the borrowing base at $750.0 million, (ii) temporarily reduce the current ratio to 0.85 to 1.00 at June 30, 2019 and to 0.80 to 1.00 at September 30, 2019, (iii) increase the rates in the utilization grid for LIBOR and ABR loans by 0.25% until the Company delivers a compliance certificate demonstrating a current ratio of not less than 1.00 to 1.00, (iv) increase the mortgage coverage requirements from 85% to 95%; and (v) restrict certain payments between Roan Inc and Roan LLC in the event that Roan LLC transfers any of its oil and natural gas properties to Roan Inc.
Amounts borrowed under the Credit Facility bear interest at London Interbank Offered Rate (“LIBOR”) or the alternate base rate (“ABR”) at the Company’s election. The rate used for ABR loans is based on the higher of the prime rate, the federal funds effective rate plus 0.50% or the one-month LIBOR rate plus 1%. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the Credit Facility. Additionally, the 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) until the Company delivers a compliance certificate demonstrating a current ratio of not less than 1.00 to 1.00.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
|
| | | | |
| Utilization Level | Utilization | LIBOR Margin | ABR Margin | Commitment Fee |
| Level I | <25% | 2.25% | 1.25% | 0.375% |
| Level II | >25% but <50% | 2.50% | 1.50% | 0.375% |
| Level III | >50% but <75% | 2.75% | 1.75% | 0.500% |
| Level IV | >75% but <90% | 3.00% | 2.00% | 0.500% |
| Level V | >90% | 3.25% | 2.25% | 0.500% |
The 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 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) of not less than 0.85 to 1.00 for the quarter ended June 30, 2019, not less than 0.80 to 1.00 for the quarter ended September 30, 2019 and not less than 1.00 to 1.00 for all quarters thereafter.
As of June 30, 2019, the Company was in compliance with the covenants under the Credit Facility and expects to remain in compliance for the next twelve months. If the Company is not able to maintain compliance with the covenants under the Credit Facility in the future, it would be in default under the Credit Facility. A default, if not waived, could result in acceleration of the indebtedness outstanding under the Credit Facility and a default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements, including the Term Loan.
Term Loan
In June 2019, Roan Inc. entered into a term loan facility (“Term Loan”) with initial commitments of $100.0 million and a potential incremental commitment of $50.0 million at the Company’s election. The lenders in the facility are funds affiliated with certain significant stockholders of Roan Inc. that are represented on the board of directors. The Term Loan matures in October 2020 and is secured by all of the assets of Roan Inc.
Borrowings under the Term Loan bear interest at the three-month LIBOR rate plus 7.5% or ABR rate plus 6.5%, as elected by the Company. The ABR rate is the highest of the prime rate, the federal funds effective rate plus 0.50% and the one-month LIBOR rate plus 1%. The Company can elect, subject to certain conditions included in “depreciation, depletionthe Term Loan agreement, to pay the interest on the Term Loan in kind. Interest is payable semi-annually for LIBOR loans and amortization”quarterly for ABR loans. The borrowings under the Term Loan are issued at a discount of 2.5%. Additionally, in conjunction with the initial Term Loan commitment and any future
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
incremental commitments, the Company is required to issue shares to the lenders equal to approximately 1% of the outstanding Class A common stock at the time of the commitment.
As of June 30, 2019, the Company had borrowed $50.0 million and received proceeds of $47.8 million, which were net of the issuance discount and certain issuance fees. These proceeds were primarily used to pay down amounts outstanding under the Credit Facility. As of June 30, 2019, the outstanding borrowings under the Term Loan have an interest rate of 9.81%. The Company issued 1,525,395 shares of Class A common stock in June 2019 to the lenders of the Term Loan and received cash equal to the par value of the shares issued in return. The difference between the fair market value of the shares issued and the amount paid for such shares was considered a fee paid to the lenders and was included as deferred financing costs that will be amortized over the term of the Term Loan. The initial discount and all related financing costs are being amortized over the term of the Term Loan using the effective interest method.
Under the Term Loan, any repayment of outstanding borrowings incurs a premium equal to 1% plus any interest that would have accrued on the repaid amount if it had been outstanding for a year; provided, that such additional interest is only due in the event of prepayment before the maturity date. This premium associated with the initial borrowing, or $0.5 million, is amortized over the term of the Term Loan.
The Term Loan contains customary negative covenants including, but not limited to, restrictions on the Company’s ability to incur additional indebtedness or create certain liens on assets, restrictions on selling of assets and restrictions on investments, dividends and other specified transactions. These covenants are subject to a number of important exceptions and qualifications. The Term Loan also contains certain affirmative covenants which, among other things, require the Company to maintain $10.0 million of liquidity, defined in the agreement as unrestricted cash plus the available borrowings under the Credit Facility and require periodic financial and reserve reporting. In addition, the Term Loan agreement contains financial covenants consistent with those required by the Credit Facility.
As of June 30, 2019, the Company was in compliance with the covenants under the Term Loan and expects to remain in compliance for the next twelve months. If the Company is not able to maintain compliance with the covenants under the Term Loan in the future, it would be in default under the Term Loan. A default, if not waived, could result in acceleration of the indebtedness outstanding under the Term Loan and a default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements, including the Credit Facility.
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, natural gas and NGL production. 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, the Panhandle Eastern Pipeline or Natural Gas Pipeline Company of America Mid Continent. 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 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.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table reflects the Company’s open commodity contracts at June 30, 2019:
|
| | | | | | | | | | | | | | | |
| | 2019 | | 2020 | | 2021 | | Total |
| Oil fixed price swaps | | | | | | | |
| Volume (Bbl) | 2,686,660 |
|
| 3,429,500 |
| | 1,730,000 |
|
| 7,846,160 |
|
| Weighted-average price | $ | 59.97 |
|
| $ | 60.57 |
| | $ | 56.08 |
|
| $ | 59.38 |
|
| Natural gas fixed price swaps | | | | | | | |
| Volume (MMBtu) | 21,160,000 |
|
| 16,005,000 |
| | 40,765,000 |
|
| 77,930,000 |
|
| Weighted-average price | $ | 2.90 |
|
| $ | 2.64 |
| | $ | 2.80 |
|
| $ | 2.79 |
|
| Natural gas basis swaps | | | | | | | |
| Volume (MMBtu) | 14,720,000 |
|
| 7,320,000 |
| | — |
|
| 22,040,000 |
|
| Weighted-average price | $ | 0.52 |
|
| $ | 0.53 |
| | $ | — |
|
| $ | 0.52 |
|
| Natural gas liquids fixed price swaps | | | | | | | |
| Volume (Bbl) | 552,000 |
| | — |
| | — |
| | 552,000 |
|
| Weighted-average price | $ | 32.25 |
| | $ | — |
| | $ | — |
| | $ | 32.25 |
|
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 from settlement of derivative contracts are reflected in loss on derivative contracts included in the accompanying condensed consolidated statements of operations.
The following table presents the Company’s gain (loss) on derivative contracts and net cash received (paid) upon settlement of its derivative contracts for the three and six months ended June 30, 2019 and 2018:
|
| | | | | | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in thousands) |
| Gain (loss) on derivative contracts | $ | 37,054 |
| | $ | (54,602 | ) | | $ | (46,588 | ) | | $ | (64,216 | ) |
Net cash received (paid) upon settlement of derivative contracts (1) | $ | 7,361 |
| | $ | (9,773 | ) | | $ | 12,743 |
| | $ | (13,911 | ) |
(1) Includes $0.4 million of cash received upon settlement of derivative contracts prior to their contractual maturity for the six months ended June 30, 2018.
During 2018 and 2019, the Company modified certain existing derivative contracts to comply with hedging requirements under its Credit Facility. During the three and six months ended June 30,2019, $1.2 million and $4.1 million, respectively, of net cash received upon settlement was related to such modified derivative contracts. The cash settlements for these derivatives are classified as cash flows from financing activities in the accompanying condensed consolidated statement of cash flows due to the other-than-insignificant financing element contained in the modified derivative contract. There were no settlements received or paid related to modified contracts during the three and six months ended June 30,2018.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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 additionsthe 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.
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 asset retirement obligations is estimated using valuation techniques that convert future cash flows tofair value measurement. The Company’s assessment of the significance of a single discounted amount. Significant inputsparticular input 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 at the time offair value measurement requires judgment, which may affect the valuation and are the most sensitive and subject to change.
In addition, there is insufficient information to reasonably determine the timing and/or method of settlement for purposes of estimating the fair value of assets and liabilities and their placement within the asset retirement obligationfair value hierarchy levels. The determination of certainthe 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 the reporting period in which the event or change in circumstances causing the transfer occurred. During the three and six months ended June 30, 2019 and 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 performed for its commodity derivatives. Please refer to Note 8 – Derivative Instruments for additional discussion.
Commodity Derivative Instruments
Commodity derivative contracts are stated at fair value in the accompanying condensed consolidated balance sheets. The Company adjusts the valuations from the valuation model for nonperformance risk and for counterparty risk. The fair values of the Company’s Chisholm Trailcommodity 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 full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table presents the amounts and classifications of the Company’s derivative assets which became assetsand liabilities as of Riviera inJune 30, 2019 and December 31, 2018, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands):
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2019 |
| | Level 1 | | Level 2 | | Level 3 | | Gross Fair Value | | Netting | | Carrying Value |
| Assets | | | | | | | | | | | |
| Current commodity derivatives | $ | — |
| | $ | 34,665 |
| | $ | — |
| | $ | 34,665 |
| | $ | (4,154 | ) | | $ | 30,511 |
|
| Noncurrent commodity derivatives | — |
| | 12,261 |
| | — |
| | 12,261 |
| | (244 | ) | | 12,017 |
|
| Total assets | $ | — |
| | $ | 46,926 |
| | $ | — |
| | $ | 46,926 |
| | $ | (4,398 | ) | | $ | 42,528 |
|
| Liabilities | | | | | | | | | | | |
| Current commodity derivatives | $ | — |
| | $ | (4,180 | ) | | $ | — |
| | $ | (4,180 | ) | | $ | 4,154 |
| | $ | (26 | ) |
| Noncurrent commodity derivatives | — |
| | (244 | ) | | — |
| | (244 | ) | | 244 |
| | — |
|
| Total liabilities | $ | — |
| | $ | (4,424 | ) | | $ | — |
| | $ | (4,424 | ) | | $ | 4,398 |
| | $ | (26 | ) |
| | | | | | | | | | | | |
| | December 31, 2018 |
| | Level 1 | | Level 2 | | Level 3 | | Gross Fair Value | | Netting | | Carrying Value |
| Assets | | | | | | | | | | | |
| Current commodity derivatives | $ | — |
| | $ | 85,728 |
| | $ | — |
| | $ | 85,728 |
| | $ | (3,548 | ) | | $ | 82,180 |
|
| Noncurrent commodity derivatives | — |
| | 21,565 |
| | — |
| | 21,565 |
| | (927 | ) | | 20,638 |
|
| Total assets | $ | — |
| | $ | 107,293 |
| | $ | — |
| | $ | 107,293 |
| | $ | (4,475 | ) | | $ | 102,818 |
|
| Liabilities | | | | | | | | | | | |
| Current commodity derivatives | $ | — |
| | $ | (4,393 | ) | | $ | — |
| | $ | (4,393 | ) | | $ | 3,548 |
| | $ | (845 | ) |
| Noncurrent commodity derivatives | — |
| | (1,068 | ) | | — |
| | (1,068 | ) | | 927 |
| | (141 | ) |
| Total liabilities | $ | — |
| | $ | (5,461 | ) | | $ | — |
| | $ | (5,461 | ) | | $ | 4,475 |
| | $ | (986 | ) |
Non-Recurring Fair Value Measurements
The Company’s non‑recurring fair value measurements include the determination of the grant date fair value of the Company’s performance share units. 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 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 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.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 10 – Equity
In connection with the Spin-off. In such cases, asset retirement obligation cost isTerm Loan commitment, the Company issued 1,525,395 shares of its Class A common stock to the lenders. See further discussion in Note 7 – Long-Term Debt. The lenders paid cash equal to the par value of the shares issued or $1,525. The difference between the fair market value of the shares and the amount paid was considered indeterminate because there is no data or informationa fee paid to the lenders that can be derived from past practice, industry practice, management’s experience, or the asset’s estimated economic life. Indeterminate asset retirement obligation costs associated with Chisholm Trail will be recognized inamortized over the period in which sufficient information exists to reasonably estimate potential settlement dates and methods.term of the Term Loan. The fair market value of the shares was calculated as the closing price of the Company’s Class A common stock on the day before the subscription agreement was executed.
Earnings per Share
The following table presents a reconciliation of the Company’s asset retirement obligations (in thousands):basic weighted average shares outstanding to diluted weighted average shares outstanding for the three and six months ended June 30, 2019 and 2018:
|
| | | |
| Asset retirement obligations at December 31, 2017 | $ | 164,553 |
|
| Liabilities added from drilling | 53 |
|
| Liabilities associated with assets divested | (62,195 | ) |
| Current year accretion expense | 4,081 |
|
| Settlements | (1,859 | ) |
| Revisions of estimates | 2,386 |
|
| Asset retirement obligations at June 30, 2018 | $ | 107,019 |
|
|
| | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| | (in thousands) |
| Basic | 152,607 |
| | 152,540 |
| | 152,573 |
| | 151,920 |
|
| Restricted stock units | 118 |
| | — |
| | — |
| | — |
|
| Diluted | 152,725 |
| | 152,540 |
| | 152,573 |
| | 151,920 |
|
The Company uses the treasury stock method to determine the diluted weighted average shares. A portion of the outstanding restricted stock units were deemed anti-dilutive for the three months ended June 30, 2019 and all of the restricted stock units were deemed anti-dilutive for the six months ended June 30, 2019 and were therefore excluded from dilutive weighted average shares. Weighted average restricted stock units excluded from the dilutive weighted average shares were 779,209 for the three months ended June 30, 2019 and 457,739 for the six months ended June 30, 2019. All performance share unit awards were deemed anti-dilutive for all periods presented and were therefore excluded from dilutive weighted average shares. See further discussion of the Company’s equity awards in Note 11 – Equity Compensation.
Reorganization
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.
Roan LLC Equity
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
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
the contribution of oil and natural gas properties. 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.
In March 2018, Roan LLC issued 19.2 million LLC Units to each Citizen and Linn to settle amounts due for the leasehold acreage acquired on Roan LLC’s behalf during 2017.
Note 11 – Equity Compensation
In connection with the Reorganization, the Company 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.
Performance Share Units
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 “Roan LLC PSUs,” and are subject to the terms of the Plan and individual award agreements. The amount of Roan LLC 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 Roan LLC PSU will be settled through the issuance of one share of the Company’s Class A common stock. Other than the security in which the Roan LLC PSUs are settled, no terms of the Roan LLC PSUs were modified in connection with the conversion of the Roan LLC PSUs.
The following table presents activity for the Roan LLC PSUs during the six months ended June 30,2019:
|
| | | | | | | | | | |
| | Number of
PSUs | | Weighted
Average Fair
Value | | Total Fair
Value ($ in thousands) |
| Outstanding at December 31, 2018 | 1,158,750 |
| | $ | 30.95 |
| | $ | 35,864 |
|
| Granted | — |
| | — |
| | — |
|
| Vested | — |
| | — |
| | — |
|
| Forfeited | (477,500 | ) | | 29.39 |
| | (14,033 | ) |
| Outstanding at June 30, 2019 | 681,250 |
| | $ | 32.05 |
| | $ | 21,831 |
|
During the three months ended June 30, 2019, the Company granted performance share units (“Roan Inc PSUs”) to certain of its employees under the Plan. The amount of Roan Inc PSUs that can be earned range from 0% to 100% based on the 60-day volume weighted average price of the Company’s Class A common stock for any 60 consecutive trading days during the two-year performance period beginning on the date of grant. There were no such grants during the three months ended March 31, 2019 or during 2018.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table presents activity for the Roan Inc PSUs during the six months ended June 30,2019:
|
| | | | | | | | | | |
| | Number of
PSUs | | Weighted
Average Fair
Value | | Total Fair
Value ($ in thousands) |
| Outstanding at December 31, 2018 | — |
| | $ | — |
| | $ | — |
|
| Granted | 1,189,918 |
| | 2.55 | | 3,034 |
|
| Vested | — |
| | — |
| | — |
|
| Forfeited | (24,369 | ) | | 2.55 | | (62 | ) |
| Outstanding at June 30, 2019 | 1,165,549 |
| | $ | 2.55 |
| | $ | 2,972 |
|
Compensation expense associated with the Roan LLC PSUs and Roan Inc PSUs for the three months ended June 30, 2019 and 2018 was $(3.7) million and $2.8 million, respectively, and for the six months ended June 30, 2019 and 2018 was $(0.7) million and $5.1 million, respectively. During 2019, forfeitures of Roan LLC PSUs and Roan Inc PSUs resulted in the reversal of compensation expense of $5.8 million. Compensation expense is included in general and administrative expenses on the accompanying condensed consolidated statements of operations. Unrecognized expense as of June 30, 2019 for the outstanding Roan LLC PSUs and the outstanding Roan Inc PSUs was $14.1 million and will be recognized over a weighted-average remaining period of 1.72 years.
The grant date fair value of both the Roan LLC PSUs and the Roan Inc PSUs was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units earned and estimated Company value at the end of the performance period. The grant date fair value of the Roan LLC PSUs and the Roan Inc PSUs is expensed on a straight-line basis from the grant date to the end of the performance period.
The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense for the Roan Inc PSU awards granted in 2019:
|
| | |
| Equity volatility | 65.00 | % |
| Weighted average risk-free interest rate | 2.25 | % |
Restricted Stock Units
Under the Plan, the Company is authorized to issue restricted stock units, hereafter referred to as the “RSUs,” to eligible employees and other service providers. The Company estimates the fair values of RSUs as of the closing price of the Company’s Class A common stock on the grant date of the award, which is expensed over the applicable vesting period.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table presents activity for the Company’s RSUs during the six months ended June 30,2019:
|
| | | | | | | | | | |
| | Number of
RSUs | | Weighted
Average Fair
Value | | Total Fair
Value ($ in thousands) |
| Outstanding at December 31, 2018 | 11,800 |
| | $ | 16.95 |
| | $ | 200 |
|
| Granted | 1,294,646 |
| | 4.62 |
| | 5,976 |
|
| Vested | — |
| | — |
| | — |
|
| Forfeited | (27,183 | ) | | 4.36 |
| | (118 | ) |
| Outstanding at June 30, 2019 | 1,279,263 |
| | $ | 4.73 |
| | $ | 6,057 |
|
Compensation expense associated with the RSUs for three and six months ended June 30, 2019 was $0.5 million and $0.5 million, respectively, and is included in general and administrative expenses on the accompanying condensed consolidated statements of operations. There were no RSUs issued prior to the Reorganization in 2018. Unrecognized expense as of June 30, 2019 for all outstanding RSUs was $5.5 million and will be recognized over a weighted-average remaining period of 2.16 years.
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 Roan LLC. 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 owners for their share of costs and billed Roan LLC for its share of costs. The services provided under the MSAs ended in April 2018 when Roan LLC took over as operator for the oil and natural gas properties contributed by Citizen and Linn. In conjunction with the conclusion of the MSAs in April 2018, Roan LLC assumed certain working capital accounts associated with the properties contributed from Citizen and Linn.
During the three and six months ended June 30, 2018, Roan LLC incurred approximately $2.5 million and $10.0 million for charges related to the services provided under the MSAs, which were recorded in general and administrative expenses in the condensed consolidated statements of operations. As the MSAs ended in April 2018, there were no such charges related to the MSAs in 2019.
Acquisition of Acreage
As provided for in the Contribution Agreement, Citizen and Linn acquired additional acreage totaling $63.0 million as of December 31, 2017 within an area of mutual interest on behalf of the Company. See 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 June 30, 2019 and December 31, 2018 are reflected as Accounts receivable – Affiliates in the accompanying condensed consolidated balance sheets and represent
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
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 Natural gas liquids 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 with an option to extend the lease for an additional 5 years at the end of the initial term. The Company paid $0.4 million and $0.7 million during the three and six months ended June 30, 2019, respectively, under this lease. During the three and six months ended June 30, 2018, the Company paid $0.1 million and $0.2 million, respectively. Total remaining payments under the lease are $7.4 million, excluding the Company’s portion of the operating expenses of the building.
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. As a result of the TMA and the refund of an overpayment of estimated federal taxes by Linn Energy, Inc. related to the Riviera business that was received by the Company in November 2018, the Company paid $7.6 million to Riviera during the six months ended June 30,2019.
Water Management Services Agreement
In January 2019, the Company entered into a water management services agreement with a subsidiary of Blue Mountain, Wildcat Water Gathering LLC (“Wildcat Water”). Under this agreement, Wildcat Water will provide water management services including pipeline gathering, disposal, treatment and redelivery of recycled water. The agreement provides for an acreage dedication for water management services through January 2029. Wildcat Water began providing services under this agreement in April 2019. During the three and six months ended June 30, 2019, the Company incurred costs of $8.5 million related to these services as operator of the related wells. The Company’s portion of these costs totaled $6.4 million, of which $4.6 million was included in production expenses in the accompanying condensed consolidated statements of operations and $1.8 million was capitalized in oil and natural gas properties on the accompanying condensed consolidated balance sheets. The remainder of the costs are billed out to third-party interest owners for their share of such costs. Amounts payable and accrued under this agreement at June 30, 2019 of $4.1 million are included in accounts payable and accrued liabilities - Affiliates on the accompanying condensed consolidated balance sheets.
Term Loan
In June 2019, the Company entered into the Term Loan agreement with lenders affiliated with certain stockholders of the Company that are represented on the board of directors. See further discussion in Note 7 – Long-Term Debt.
Note 13 – Income Taxes
As discussed in Note 1 – Business and Organization, Roan Inc. was formed in September 2018 in connection with the Reorganization. Roan Inc.’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,
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
for income tax purposes, flowed through to its members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of its members. Roan Inc. is a corporation and subject to U.S. federal and state income tax.
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 Company’s effective combined U.S. federal and state income tax rate for the three and six months ended June 30, 2019 was 33.0% and 23.5%, respectively, based on estimated net income for the year. The Company’s effective tax rate for the three months ended June 30, 2019 reflects updates to the Company’s 2019 forecast based on market conditions and related changes to its drilling program. The Company’s effective tax rate for six months ended June 30, 2019 approximates the Company’s estimated annual effective tax rate which includes the federal and state income tax. 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.
In conjunction with the Reorganization, the Company entered into the TMA with Riviera. The TMA, in part, provides for the indemnification of the Company and the entitlement of Riviera to refunds related to certain taxes of Linn Energy, Inc. prior to the spinoff of Riviera from Linn Energy, Inc.
Note 1114 – Commitments and Contingencies
On May 11, 2016,
Lease Commitments
As discussed in Note 3 - Lease Accounting, the Debtors filed Bankruptcy PetitionsCompany leases certain office buildings, drilling rigs, and field equipment under cancelable and non-cancelable leases to support our operations.
The Company’s lease costs for relief under Chapter 11the three and six months ended June 30, 2019 included operating lease costs of $0.7 million and $1.1 million, respectively, and short-term lease costs of $13.6 million and $47.1 million, respectively. Short-term lease costs exclude leases with a contract term of one month or less. Included in short-term lease costs is $12.5 million and $44.6 million, respectively, of gross costs related to the Company’s drilling rig leases. The Company’s portion 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 subjectdrilling rig costs are capitalized to certain conditions set forth in the Plan. On the Effective Date, all of the conditions were satisfied or waivedoil and natural gas properties and the Plan became effectiveremainder is billed out to third-party interest owners for their share of such costs. Payments made for operating leases included in lease liabilities for the three 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.six months ended June 30, 2019 were $0.4 million and $0.7 million, respectively.
The commencementCompany’s condensed consolidated balance sheet as of June 30, 2019 included lease assets and liabilities as follows (in thousands):
|
| | | |
| Operating Leases | |
| Operating lease right of use assets | $ | 5,756 |
|
| | |
| Current operating lease liabilities | $ | 1,904 |
|
| Noncurrent operating lease liabilities | 4,954 |
|
| Total operating lease liabilities | $ | 6,858 |
|
The weighted average remaining lease term for our operating leases is 3.8 years and 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 Companyweighted average discount rate 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’s 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. On November 13, 2017, the Bankruptcy Court ruled that the secured lenders are not entitled to payment of post-petition default interest. That ruling was appealed by Wells Fargo and on March 29, 2018, the U.S. District Court for the Southern District of Texas affirmed the Bankruptcy Court’s ruling. On April 30, 2018, the Bankruptcy Court approved the substitution of UMB Bank, National Association (“UMB Bank”) as successor to Wells Fargo as administrative agent under the Predecessor’s credit facility. UMB Bank then immediately filed a notice of appeal to the United States Court of Appeals for the Fifth Circuit from the decision by the U.S. District Court for the Southern District of Texas, which affirmed the decision of the Bankruptcy Court. That appeal remains pending.8.5%.
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The Company’s operating lease liabilities as of ContentsJune 30, 2019 with enforceable contract terms that are greater than one year mature as follows (in thousands):
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued |
| | | |
| 2019 | $ | 986 |
|
| 2020 | 2,046 |
|
| 2021 | 2,136 |
|
| 2022 | 2,229 |
|
| 2023 | 456 |
|
| Thereafter | 171 |
|
| Total lease payments | 8,024 |
|
| Less imputed interest | (1,166 | ) |
| Total | $ | 6,858 |
|
(Unaudited)
The Company’s future lease payments under ASC 840 as of December 31, 2018 were not materially different than those presented above.
Litigation
The Company is party to lawsuits arising in the ordinary course of business, including, but not limited to, commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. The Company cannot predict the outcome of any such lawsuits with certainty, but management does not currently believe that any pending or threatened legal matters will have a partymaterial adverse impact on the Company’s financial condition.
Due to anythe nature of its business, the Company is, from time to time, involved in other routine litigation or subject to disputes or claims related to its business activities, including workers’ compensation claims and employment related disputes. In the opinion of management, none of these other pending litigation disputes or claims that it believes wouldagainst the Company, if decided adversely, will have a material adverse effect on its overall business,the Company’s financial position,condition, cash flows or results of operations.
Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. At June 30, 2019, the Company had no environmental matters requiring specific disclosure or liquidity; however, cash flow could be significantly impactedrequiring the recognition of a liability.
Natural Gas Dedication Agreements
The Company has dedicated its natural gas production from the oil and natural gas properties contributed by Citizen under an agreement with a third party. Under this dedication agreement, the Company is required to deliver its natural gas production from the contract area, as defined in the reporting periodsagreement, through November 2030. There is no specified volume or volume penalty in which such matters are resolved.the agreement.
Except for in connection with its Chapter 11 proceedings,
Roan Resources, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
For the oil and natural gas properties contributed by Linn, the Company madeassumed Linn’s dedication agreement with Blue Mountain. The agreement with Blue Mountain requires the Company to deliver its natural gas production from the contract area, as defined in the agreement, through November 2030. There is no significant paymentsspecified volume or volume penalty in the agreement.
Volume Commitment
Under an agreement with a third party, the Company has a requirement to settledeliver a minimum volume of natural gas from a specified area, as defined in the agreement. In the event that the Company is unable to meet this natural gas volume delivery commitment, it would incur deficiency fees on any legal, environmental or tax proceedings duringundelivered volumes as of November 2021. Based on expected production from currently producing wells in the six months ended June 30, 2018, or June 30, 2017. Thespecified area, the Company regularly analyzes current information and accruesanticipates that it may not deliver the required minimum volume of natural gas by November 2021. As a result, the Company has accrued $0.6 million 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.
Note 12 – Equity
Shares Issued and Outstanding
As of June 30, 2018, there were 78,749,510 shares of Class A common stock issued and outstanding. An additional 922,696 unvested restricted stock units were outstanding under the Company’s Omnibus Incentive Plan. Effective April 10, 2018, all outstanding Holdco Class A-2 units were converted into Class A common stock in accordance with the termsits share of the Holdco LLC Agreement. Pursuant to such conversion, an aggregate of 2,785,681 shares of Class A common stock were issued to the respective holders, of which 914,632 remained subject to the vesting provisions applicable to the underlying Class A-2 unitsestimated shortfall deficiency fees as of June 30, 2018. See Note 14 for additional information related to the restricted stock units and Holdco Class A-2 units.
Share Repurchase Program
2019. The Company’s Board of Directors previously authorized the repurchase of up to $400 million of the Company’s outstanding shares of Class A common stock. The Company discontinued the share repurchase programaccrued liability is included in July 2018.
During the six months ended June 30, 2018, the Company repurchased an aggregate of 1,557,180 shares of Class A common stock at an average price of $39.13 per share for a total cost of approximately $61 million. In June 2017, the Company repurchased 7,540 shares of Class A common stock at an average price of $30.48 per share for a total cost of approximately $230,000.
In addition, in July 2018, the Company purchased 280,289 shares of Class A common stock at an average price of $40.30 for a total cost of approximately $11 million. During 2017 and 2018, the Company purchased an aggregate of 7,527,661 shares of Class A common stock at an average price of $35.94 for a total cost of approximately $271 million under the share repurchase program.
Tender Offer
On December 14, 2017, the Company’s Board of Directors announced the intention to commence a tender offer to purchase at least $250 million of the Company’s Class A common stock. In January 2018, upon the terms and subject to the conditions describedother noncurrent liabilities in the Offer to Purchase dated December 20, 2017, as amended, the Company repurchased an aggregate of 6,770,833 shares of Class A common stock at a fixed price of $48.00 per share for a total cost of approximately $325 million (excluding expenses of approximately $4 million related to the tender offer).
Dividends
The Company 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.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
Note 13 – Noncontrolling Interests
Noncontrolling interests represented ownership in the net assets of the Company’s then 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 December 31, 2017, the noncontrolling Class A-2 units represented approximately 0.88% of Holdco’s total outstanding units. Effective April 10, 2018, all outstanding Holdco Class A-2 units were converted into Class A common stock in accordance with the terms of the Holdco LLC Agreement.
Note 14 – Share-Based Compensation
A summary of share-based compensation expenses included on the condensed consolidated statements of operations is presented below:
|
| | | | | | | |
| | Three Months Ended June 30, |
| | 2018 | | 2017 |
| | (in thousands) |
| | | | |
| General and administrative expenses | $ | 58,188 |
| | $ | 15,422 |
|
| Income tax benefit | $ | 4,315 |
| | $ | 3,128 |
|
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Six Months Ended June 30, 2018 | | Four Months Ended June 30, 2017 | | | Two Months Ended February 28, 2017 |
| (in thousands) | | | | | | |
| General and administrative expenses | $ | 75,225 |
| | $ | 19,599 |
| | | $ | 50,255 |
|
| Income tax benefit | $ | 6,732 |
| | $ | 3,555 |
| | | $ | 5,170 |
|
During the six months ended June 30, 2018, the Company granted to certain employees 12,500 restricted stock units with an aggregate grant date fair value of approximately $519,000. The restricted stock units vest over three years.
As of June 30, 2018, 922,696 shares were issuable under the Omnibus Incentive Plan pursuant to outstanding restricted stock units and approximately 4.7 million additional shares were reserved for future issuance under the Plan. The Compensation Committee of the Board of Directors of the Company (the “Compensation Committee”) generally has discretion regarding the timing, size and terms of future awards; however, the Omnibus Incentive Plan requires that 1) the portion of 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”) and 2) if a Change in Control (as defined in the Omnibus Incentive Plan) occurs before the Final Allocation Date, the entire Remaining Share Reserve will be allocated on 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. As of April 30, 2018, all current participants in the Omnibus Incentive Plan have agreed to waive any rights they may have to future awards under this provision in consideration for the ability to participate in the Liquidity Program described below or a similar future program. The Compensation Committee has indicated that it does not intend to grant any future awards under the Omnibus Incentive Plan.
Upon a participant’s termination of employment and/or service (as applicable), the Company has the right (but not the obligation) to repurchase all or 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
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
repurchased, measured as of the date of the Company’s repurchase notice. During May 2018, the Company began exercising its right to repurchase vesting awards under the Omnibus Incentive Plan which modified all outstanding awards to liability classification. For the six months ended June 30, 2018, the Company has repurchased 271,314 restricted stock units for a total cost of approximately $11 million pursuant to its right to repurchase vesting awards. The Company has recognized a liability of approximately $112 million related to awards required to be liability classified, included in “share-based payment liability” on theaccompanying condensed consolidated balance sheet and recorded incremental share-based compensation expense of approximately $18 million relatedsheet. If the Company is unable to modifying the awardsdeliver any natural gas volumes subsequent to liability classification. At June 30, 2018, all outstanding share-based payment awards are liability classified.
In April 2018,2019 through November 2021, total shortfall deficiency fees of $7.0 million would be due at the Company entered into agreements with eachend of the then serving executive officers of the Company, under which the Company agreed, at the option of each officer, to repurchase certain of their vested restricted stock unit awards and outstanding Class A common stock. Pursuant to those agreements, on August 7, 2018, the Company repurchased an aggregate of 2,477,834 shares of Class A common stock for a total cost of approximately $102 million.commitment period.
On August 2, 2018, the Board authorized the termination of the Linn Energy, Inc. 2017 Omnibus Incentive Plan following the settlement of all outstanding RSUs and restricted common stock. In addition, all remaining unvested restricted stock units of Linn Energy, Inc. vested upon the Spin-off, which participants have the option to require the Company to settle in cash.
In addition, in January 2018, the Compensation Committee approved a one-time liquidity program under which the Company agreed, at the option of the participant, to 1) settle all or a portion of an eligible participant’s restricted stock units vesting on or before March 1, 2018 in cash and/or 2) repurchase all or a portion of any shares of Class A common stock held by an eligible participant as a result of a prior vesting of restricted stock units, in each case at an agreed upon price (the “Liquidity Program”). For the six months ended June 30, 2018, the Company settled 1,028,875 restricted stock units in cash and repurchased 120,829 shares of Class A common stock for a total cost of approximately $45 million pursuant to the Liquidity Program.
Note 15 – Earnings Per Share/UnitSubsequent Events
Basic earnings
Subsequent to June 30, 2019, the Company entered into fixed price swaps for 1,500 Bbls per share/unit is computed by dividing net earnings attributable to common stockholders/unitholders by theday of NGL production at a weighted average numberprice of shares/units outstanding during the period. Diluted earnings per share/unit is computed by adjusting the average number of shares/units outstanding$24.50 for the dilutive effect, if any,period of potential common shares/units.
The following tables provideJanuary 2020 to December 2020 and basis swaps for 10,000 Mcf per day of natural gas production at a reconciliationweighted average price of $0.41 for the numerators and denominatorsperiod of the basic and diluted per share/unit computations for net income:
|
| | | | | | | | | | |
| | Successor |
| | Three Months Ended June 30, 2018 |
| | Income | | Shares | | Per Share |
| | (in thousands, except per share data) |
| | | | | | |
| Basic: | | | | | |
| Net income attributable to common stockholders | $ | 5,104 |
| | 78,718 |
| | $ | 0.06 |
|
| | | | | | |
| Effect of Dilutive Securities: | | | | | |
| Dilutive effect of restricted stock units | | | 559 |
| | |
| Dilutive effect of unvested Class A-2 units of Holdco | $ | — |
| | — |
| | |
| | | | | | |
| Diluted: | | | | | |
| Net income attributable to common stockholders | $ | 5,104 |
| | 79,277 |
| | $ | 0.06 |
|
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
|
| | | | | | | | | | |
| | Successor |
| | Three Months Ended June 30, 2017 |
| | Income | | Shares | | Per Share |
| | (in thousands, except per share data) |
| | | | | | |
| Basic: | | | | | |
| Income from continuing operations | $ | 223,379 |
| | 89,849 |
| | $ | 2.49 |
|
| Loss from discontinued operations, net of income taxes | (3,322 | ) | | 89,849 |
| | (0.04 | ) |
| Net income attributable to common stockholders | $ | 220,057 |
| | 89,849 |
| | $ | 2.45 |
|
| | | | | | |
| Effect of Dilutive Securities: | | | | | |
| Dilutive effect of restricted stock units | $ | — |
| | 635 |
| | |
| | | | | | |
| Diluted: | | | | | |
| Income from continuing operations | $ | 223,379 |
| | 90,484 |
| | $ | 2.47 |
|
| Loss from discontinued operations | (3,322 | ) | | 90,484 |
| | (0.04 | ) |
| Net income attributable to common stockholders | $ | 220,057 |
| | 90,484 |
| | $ | 2.43 |
|
|
| | | | | | | | | | |
| | Successor |
| | Six Months Ended June 30, 2018 |
| | Income | | Shares | | Per Share |
| | (in thousands, except per share data) |
| | | | | | |
| Basic: | | | | | |
| Net income attributable to common stockholders | $ | 74,928 |
| | 78,817 |
| | $ | 0.95 |
|
| | | | | | |
| Effect of Dilutive Securities: | | | | | |
| Dilutive effect of restricted stock units | $ | — |
| | 947 |
| | |
| Dilutive effect of unvested Class A-2 units of Holdco | $ | (1,140 | ) | | — |
| | |
| | | | | | |
| Diluted: | | | | | |
| Net income attributable to common stockholders | $ | 73,788 |
| | 79,764 |
| | $ | 0.93 |
|
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
|
| | | | | | | | | | |
| | Successor |
| | Four Months Ended June 30, 2017 |
| | Income | | Shares | | Per Share |
| | (in thousands, except per share data) |
| | | | | | |
| Basic: | | | | | |
| Income from continuing operations | $ | 216,055 |
| | 89,849 |
| | $ | 2.41 |
|
| Loss from discontinued operations, net of income taxes | (3,254 | ) | | 89,849 |
| | (0.04 | ) |
| Net income attributable to common stockholders | $ | 212,801 |
| | 89,849 |
| | $ | 2.37 |
|
| | | | | | |
| Effect of Dilutive Securities: | | | | | |
| Dilutive effect of restricted stock units | $ | — |
| | 216 |
| | |
| | | | | | |
| Diluted: | | | | | |
| Income from continuing operations | $ | 216,055 |
| | 90,065 |
| | $ | 2.40 |
|
| Loss from discontinued operations | (3,254 | ) | | 90,065 |
| | (0.04 | ) |
| Net income attributable to common stockholders | $ | 212,801 |
| | 90,065 |
| | $ | 2.36 |
|
|
| | | | | | | | | | |
| | 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 |
|
The diluted earnings per share calculation excludes approximately 1,989 restricted stock units that were anti-dilutive for the six months ended June 30, 2018. No restricted stock units were anti-dilutive for the three months ended June 30, 2018. The diluted earnings per share calculation for the three months and four months ended June 30, 2017, exclude approximately 3,470,051 Class B units associated with management’s profits interests awards that were not yet considered to be dilutive as the applicable hurdle rate had not been met as of June 30, 2017. There were no potential common units outstanding during the two months ended February 28, 2017.
Note 16 – Income Taxes
Amounts recognized as income taxes are included in “income tax expense (benefit),” as well as discontinued operations, on the consolidated statements of operations. The effective income tax rates were approximately 45% and 37% for the three months and six months ended June 30, 2018, respectively, approximately 42% for both the three months and four months ended June 30, 2017, and zero for the two months ended February 28, 2017. For the six months ended June 30, 2018, the Company’s federal and state statutory rate net of the federal tax benefit was approximately 24%. The increase in the effective tax rate during 2018 is primarily due to non-deductible executive compensation.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
The Successor was formed as a C corporation. For federal and state income tax purposes (with the exception of the state of Texas), the Predecessor was a limited liability company treated as a partnership, in which income tax liabilities and/or benefits were passed through to the Predecessor’s 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 exceptionCompany’s acreage for a term 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 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.
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:
|
| | | | | | | |
| | June 30, 2018 | | December 31, 2017 |
| | (in thousands) |
| | | | |
| Prepaids | $ | 14,209 |
| | $ | 46,238 |
|
| Receivable from related party | 25,982 |
| | 23,163 |
|
| Inventories | 3,981 |
| | 7,667 |
|
| Other | 2,487 |
| | 2,703 |
|
| Other current assets | $ | 46,659 |
| | $ | 79,771 |
|
“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:
|
| | | | | | | |
| | June 30, 2018 | | December 31, 2017 |
| | (in thousands) |
| | | | |
| Accrued compensation | $ | 13,533 |
| | $ | 29,089 |
|
| Asset retirement obligations (current portion) | 1,488 |
| | 3,926 |
|
| Deposits | 3,170 |
| | 15,349 |
|
| Income taxes payable | 23 |
| | 7,496 |
|
| Other | 1,616 |
| | 2,757 |
|
| Other accrued liabilities | $ | 19,830 |
| | $ | 58,617 |
|
The following table provides a reconciliation of cash and cash equivalents on the condensed consolidated balance sheets to cash, cash equivalents and restricted cash on the condensed consolidated statement of cash flows:
|
| | | | | | | |
| | June 30, 2018 | | December 31, 2017 |
| | (in thousands) |
| | | | |
| Cash and cash equivalents | $ | 301,365 |
| | $ | 464,508 |
|
| Restricted cash | 43,387 |
| | 56,445 |
|
| Cash, cash equivalents and restricted cash | $ | 344,752 |
| | $ | 520,953 |
|
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 |
| | Six Months Ended June 30, 2018 | | Four Months Ended June 30, 2017 | | | Two Months Ended February 28, 2017 |
| (in thousands) | | | | | | |
| Cash payments for interest, net of amounts capitalized | $ | — |
| | $ | 14,436 |
| | | $ | 17,651 |
|
| Cash payments for income taxes | $ | 7,748 |
| | $ | 215 |
| | | $ | — |
|
| Cash payments for reorganization items, net | $ | 2,911 |
| | $ | 6,300 |
| | | $ | 21,571 |
|
| | | | | | | |
| Noncash investing activities: | | | | | | |
| Accrued capital expenditures | $ | 21,968 |
| | $ | 34,547 |
| | | $ | 22,191 |
|
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 June 30, 2018, “restricted cash” on the condensed consolidated balance sheet consisted of approximately $33 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 $3 million related to deposits and approximately $7 million for other items. At December 31, 2017, “restricted cash” on the condensed consolidated balance sheet consisted of approximately $36 million that will be used to settle certain claims in accordance with the Plan, approximately $15 million related to deposits and approximately $5 million for other items.
Note 18 – Related Party Transactions
Roan Resources LLC
On August 31, 2017, the Company completed the Roan Contribution. In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan. See Note 6 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 agreed to provide certain operating, administrative and other services in respect of the assets contributed to Roan during a transitional period.
Under the MSA, Roan agreed to reimburse Linn Operating for certain costs and expenses incurred by Linn Operating in connection with providing the services, and to pay to Linn Operating a service fee of $1.25 million per month, prorated for partial months. The MSA terminated according to its terms on April 30, 2018.
In addition, the Company’s pre-Spin-off subsidiary, Blue Mountain Midstream LLC (“Blue Mountain”), has an agreement in place with Roan for the purchase and processing of natural gas from certain of Roan’s properties. Blue Mountain became a subsidiary of Riviera on August 7, 2018 in connection with the Spin-off.
For the three months and six months ended June 30, 2018, the Company made natural gas purchases from Roan of approximately $15 million and $32 million, respectively, included in “marketing expenses” on the condensed consolidated statements of operations. In addition, for the three months and six months ended June 30, 2018, the Company recognized service fees of approximately $1 million and $5 million, respectively, under the MSA, as a reduction to general and administrative expenses. At June 30, 2018, the Company had approximately $26 million due from Roan, primarily associated with capital spending, included in “other current assets” and approximately $11 million due to Roan, associated with natural gas purchases, included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet. At December 31, 2017, the Company had approximately $23 million due from Roan, primarily associated with capital spending,
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
included in “other current assets” and approximately $18 million due to Roan, primarily associated with joint interest billings and natural gas purchases, included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet.
Berry Petroleum Company, LLC
Berry, a former subsidiary of the Predecessor, was deconsolidated effective December 31, 2016. 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, Berry incurred management fees of approximately $6 million for services provided by LOI.
LinnCo, LLC
LinnCo, which was an affiliate of the Predecessor, was formed on April 30, 2012. 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.
Note 19 – Segments
During the second quarter of 2018, the Company had two reporting segments: Upstream and Chisholm Trail. The Upstream reporting segment was engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs. The Chisholm Trail reporting segment is new for the second quarter of 2018 as a result of a change in the way our chief operating decision maker (“CODM”) assesses the Company’s results of operations following the hiring of a segment manager to lead the Chisholm Trail reporting segment and the commissioning of the cryogenic natural gas processing facility during the second quarter of 2018. The Chisholm Trail reporting segment consisted of the Chisholm Trail gas plant system, which is comprised of the newly constructed cryogenic natural gas processing facility, a refrigeration plant, and a network of gathering pipelines located in the Merge/SCOOP/STACK play. To assess the performance of the Company’s operating segments, the CODM analyzes field level cash flow. The Company defines field level cash flow as revenues less direct operating expenses. Other indirect income (expenses) include “general and administrative expenses,” “exploration costs,” “depreciation, depletion and amortization,” “gains on sale of assets and other, net,” “other income and (expenses)” and “reorganization items, net.” Prior period amounts are presented on a comparable basis. In addition, information regarding total assets by segment is not presented because it is not reviewed by the CODM.
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
The following tables present the Company’s financial information by reportable segment:
|
| | | | | | | | | | | | | | | |
| | Successor |
| | Three Months Ended June 30, 2018 |
| | Upstream | | Chisholm Trail | | Not Allocated to Segments | | Consolidated |
| | (in thousands) |
| | | | | | | | |
| Oil, natural gas and natural gas liquids sales | $ | 87,004 |
| | $ | — |
| | $ | — |
| | $ | 87,004 |
|
| Marketing revenues | 22,901 |
| | 20,066 |
| | — |
| | 42,967 |
|
| Other revenues | 6,387 |
| | — |
| | — |
| | 6,387 |
|
| | 116,292 |
| | 20,066 |
| | — |
| | 136,358 |
|
| Lease operating expenses | 24,088 |
| | — |
| | — |
| | 24,088 |
|
| Transportation expenses | 21,213 |
| | — |
| | — |
| | 21,213 |
|
| Marketing expenses | 20,244 |
| | 20,083 |
| | — |
| | 40,327 |
|
| Taxes other than income taxes | 6,737 |
| | 285 |
| | 275 |
| | 7,297 |
|
| Total direct operating expenses | 72,282 |
| | 20,368 |
| | 275 |
| | 92,925 |
|
| Field level cash flow | $ | 44,010 |
| | $ | (302 | ) | | (275 | ) | | 43,433 |
|
| Losses on oil and natural gas derivatives | | | | | (7,525 | ) | | (7,525 | ) |
| Other indirect income (expenses) | | | | | (23,283 | ) | | (23,283 | ) |
| Income from continuing operations before income taxes | | | | |
|
| | $ | 12,625 |
|
|
| | | | | | | | | | | | | | | |
| | Successor |
| | Three Months Ended June 30, 2017 |
| | Upstream | | Chisholm Trail | | Not Allocated to Segments | | Consolidated |
| | (in thousands) |
| | | | | | | | |
| Oil, natural gas and natural gas liquids sales | $ | 243,167 |
| | $ | — |
| | $ | — |
| | $ | 243,167 |
|
| Marketing revenues | 10,793 |
| | 1,754 |
| | — |
| | 12,547 |
|
| Other revenues | 6,391 |
| | — |
| | — |
| | 6,391 |
|
| | 260,351 |
| | 1,754 |
| | — |
| | 262,105 |
|
| Lease operating expenses | 71,057 |
| | — |
| | — |
| | 71,057 |
|
| Transportation expenses | 37,388 |
| | — |
| | — |
| | 37,388 |
|
| Marketing expenses | 6,156 |
| | 820 |
| | — |
| | 6,976 |
|
| Taxes other than income taxes | 17,486 |
| | 116 |
| | 269 |
| | 17,871 |
|
| Total direct operating expenses | 132,087 |
| | 936 |
| | 269 |
| | 133,292 |
|
| Field level cash flow | $ | 128,264 |
| | $ | 818 |
| | (269 | ) | | 128,813 |
|
| Gains on oil and natural gas derivatives | | | | | 45,714 |
| | 45,714 |
|
| Other indirect income (expenses) | | | | | 207,622 |
| | 207,622 |
|
| Income from continuing operations before income taxes | | | | |
|
| | $ | 382,149 |
|
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
|
| | | | | | | | | | | | | | | |
| | Successor |
| | Six Months Ended June 30, 2018 |
| | Upstream | | Chisholm Trail | | Not Allocated to Segments | | Consolidated |
| | (in thousands) |
| | | | | | | | |
| Oil, natural gas and natural gas liquids sales | $ | 223,880 |
| | $ | — |
| | $ | — |
| | $ | 223,880 |
|
| Marketing revenues | 47,276 |
| | 41,958 |
| | — |
| | 89,234 |
|
| Other revenues | 12,281 |
| | — |
| | — |
| | 12,281 |
|
| | 283,437 |
| | 41,958 |
| | — |
| | 325,395 |
|
| Lease operating expenses | 71,972 |
| | — |
| | — |
| | 71,972 |
|
| Transportation expenses | 40,307 |
| | — |
| | — |
| | 40,307 |
|
| Marketing expenses | 41,380 |
| | 40,702 |
| | — |
| | 82,082 |
|
| Taxes other than income taxes | 14,908 |
| | 477 |
| | 364 |
| | 15,749 |
|
| Total direct operating expenses | 168,567 |
| | 41,179 |
| | 364 |
| | 210,110 |
|
| Field level cash flow | $ | 114,870 |
| | $ | 779 |
| | (364 | ) | | 115,285 |
|
| Losses on oil and natural gas derivatives | | | | | (22,555 | ) | | (22,555 | ) |
| Other indirect income (expenses) | | | | | 31,167 |
| | 31,167 |
|
| Income from continuing operations before income taxes | | | | |
|
| | $ | 123,897 |
|
|
| | | | | | | | | | | | | | | |
| | Successor |
| | Four Months Ended June 30, 2017 |
| | Upstream | | Chisholm Trail | | Not Allocated to Segments | | Consolidated |
| | (in thousands) |
| | | | | | | | |
| Oil, natural gas and natural gas liquids sales | $ | 323,492 |
| | $ | — |
| | $ | — |
| | $ | 323,492 |
|
| Marketing revenues | 13,273 |
| | 2,188 |
| | — |
| | 15,461 |
|
| Other revenues | 8,419 |
| | — |
| | — |
| | 8,419 |
|
| | 345,184 |
| | 2,188 |
| | — |
| | 347,372 |
|
| Lease operating expenses | 95,687 |
| | — |
| | — |
| | 95,687 |
|
| Transportation expenses | 51,111 |
| | — |
| | — |
| | 51,111 |
|
| Marketing expenses | 8,513 |
| | 1,002 |
| | — |
| | 9,515 |
|
| Taxes other than income taxes | 24,478 |
| | 155 |
| | 315 |
| | 24,948 |
|
| Total direct operating expenses | 179,789 |
| | 1,157 |
| | 315 |
| | 181,261 |
|
| Field level cash flow | $ | 165,395 |
| | $ | 1,031 |
| | (315 | ) | | 166,111 |
|
| Gains on oil and natural gas derivatives | | | | | 33,755 |
| | 33,755 |
|
| Other indirect income (expenses) | | | | | 169,644 |
| | 169,644 |
|
| Income from continuing operations before income taxes | | | | |
|
| | $ | 369,510 |
|
LINN ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)
|
| | | | | | | | | | | | | | | |
| | Predecessor |
| | Two Months Ended February 28, 2017 |
| | Upstream | | Chisholm Trail | | Not Allocated to Segments | | Consolidated |
| | (in thousands) |
| | | | | | | | |
| Oil, natural gas and natural gas liquids sales | $ | 188,885 |
| | $ | — |
| | $ | — |
| | $ | 188,885 |
|
| Marketing revenues | 5,999 |
| | 637 |
| | — |
| | 6,636 |
|
| Other revenues | 9,915 |
| | — |
| | — |
| | 9,915 |
|
| | 204,799 |
| | 637 |
| | — |
| | 205,436 |
|
| Lease operating expenses | 49,665 |
| | — |
| | — |
| | 49,665 |
|
| Transportation expenses | 25,972 |
| | — |
| | — |
| | 25,972 |
|
| Marketing expenses | 4,602 |
| | 218 |
| | — |
| | 4,820 |
|
| Taxes other than income taxes | 14,773 |
| | 78 |
| | 26 |
| | 14,877 |
|
| Total direct operating expenses | 95,012 |
| | 296 |
| | 26 |
| | 95,334 |
|
| Field level cash flow | $ | 109,787 |
| | $ | 341 |
| | (26 | ) | | 110,102 |
|
| Gains on oil and natural gas derivatives | | | | | 92,691 |
| | 92,691 |
|
| Other indirect income (expenses) | | | | | 2,194,650 |
| | 2,194,650 |
|
| Income from continuing operations before income taxes | | | | |
|
| | $ | 2,397,443 |
|
| |
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 Quarterly Report on Form 10-Qreport as well as our audited consolidated financial statements and notes included in the Company’sour Annual Report on Form 10-K for the year ended December 31, 2017.10-K. The following discussion contains forward-looking statements basedthat reflect our future plans, estimates, beliefs and expected 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 development, production, gathering and sale of oil, natural gas and NGLs. 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 September 2018 to serve as a holding company, and prior to the Reorganization, had no operations, assets or liabilities. The historical financial and operating information included in this Quarterly Report, (i) on expectations, estimates and assumptions. Actual results may differ materiallyafter September 24, 2018, is that of Roan Inc., and (ii) prior to September 24, 2018, is the information of Roan LLC, our accounting predecessor.
Overview
We are an independent oil and natural gas company focused on the development of our assets throughout the eastern and southern Anadarko Basin. The Anadarko Basin, which spans from those discussedsouth-central Oklahoma to the northeast corner of the Texas panhandle, is one of the largest and most prolific onshore oil and natural gas basins in the forward-looking statements. United States, featuring multiple producing horizons and extensive well production history demonstrated over seven decades of development. 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 acreage position is concentrated in areas that we believe demonstrate higher percentage production of oil and NGLs within the Merge play and provides us development opportunities through multiple stacked prospective development horizons.
Outlook
In the second quarter of 2019, our Board of Directors announced plans to evaluate possible strategic alternatives, which could include, among other possibilities, a possible sale of the Company or significant assets of the Company. Any decision by the Board of Directors of the Company to pursue any such strategic alternatives will depend on a number of factors, which may be beyond our control and, as a result, we cannot provide any assurances that any of the alternatives being evaluated will be available on terms acceptable to us, on a timely basis, or at all in the foreseeable future.
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, as a result of which 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 this Quarterly Report, (i) on and after September 24, 2018, is that could cause or contributeof Roan Inc., and (ii) prior to such differences include,September 24, 2018, is the information of Roan LLC, our accounting predecessor.
Public Company Expenses
Subsequent to the Reorganization, we incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including but are not limited to, costs associated with hiring new personnel, Sarbanes-Oxley compliance, implementation of compensation programs that are competitive with our public company peer group, costs associated with annual and quarterly reports and our other filings with the SEC, exchange listing fees, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental general and administrative expenses are not included in our historical results of operations.
Income Taxes
As a result of the Reorganization, we became subject to federal and state tax. 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 Roan LLC and any related tax credits, for federal income tax purposes, flowed through to its members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of its members.
Financial and Operational Performance
Our financial and operational performance for the six months ended June 30, 2019 included the following highlights:
Net loss was $30.8 million for the six months ended June 30, 2019, as compared to net income of $12.3 million for the six months ended June 30, 2018. The net loss was primarily due to:
$10.8 million increase in production expenses, primarily related to an increase in production volumes for the six months ended June 30, 2019;
$5.4 million increase in exploration expenses, primarily related to increased unproved leasehold amortization during the six months ended June 30, 2019;
$40.0 million increase in depreciation, depletion, amortization and accretion, primarily due to an increase in production volumes and a higher depletion rate due to increases in capital expenditures;
partially offset by:
$4.1 million increase in total oil, natural gas and NGL sales, primarily as a result of an increase in production volumes partially offset by a decrease in realized prices during the six months ended June 30, 2019;
$17.6 million decrease in loss on derivative contracts during the six months ended June 30, 2019 as a result of decreases in natural gas prices and, to a lesser extent, oil prices during this period;
$9.5 million income tax benefit during the six months ended June 30, 2019.
Average daily sales volumes were 49.9 MBoe for the six months ended June 30, 2019, an increase of 35% compared to 36.9 MBoe during the same period in 2018.
Drilled or participated in 69 gross (30 net) wells with first production during the first six months of 2019.
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. Under our major gas dedication agreements, we have the ability to elect ethane recovery or rejection on a monthly basis. An election of ethane recovery typically results in higher NGL volumes and lower realized NGL prices while ethane rejection typically results in lower NGL volumes and higher realized NGL prices. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The following table presents the sources of our revenues, excluding the effects of our derivative contracts, for the periods presented:
|
| | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| Revenues | | | | | | | |
| Oil sales | 71 | % | | 65 | % | | 66 | % | | 64 | % |
| Natural gas sales | 14 | % | | 15 | % | | 18 | % | | 16 | % |
| Natural gas liquid sales | 15 | % | | 20 | % | | 16 | % | | 20 | % |
Realized Prices on the Sales of Oil, 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 NGL, production volumes, estimatesNGLs, (ii) market uncertainty and (iii) a variety of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as thoseadditional factors set forth in “Cautionary Statement Regarding Forward-Looking Statements” below and in Item 1A. “Risk Factors” in the Company’s Annual Report on Form 10-Kthat are beyond our control. From time to time, we enter into derivative arrangements for the year ended December 31, 2017, and elsewhere in the Annual Report.
When referring to Linn Energy, Inc. (“Successor,” “LINN Energy” or the “Company”), the intent is to refer to LINN Energy, a Delaware corporation formed in February 2017, and its then consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. During the reporting period, Linn Energy, Inc. was a successor issuer of Linn Energy, LLC pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Linn Energy, Inc. was not a successor of Linn Energy, LLC for purposes of Delaware corporate law. When referring to the “Predecessor” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to Linn Energy, LLC, 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.
As discussed under Holding Company Reorganization below, subsequent to the reporting period, on July 25, 2018, the Company completed a corporate reorganization pursuant to which LINN Energy merged with and into Linn Merger Sub #1, LLC (“Merger Sub”), a newly formed Delaware limited liability company and wholly owned subsidiary of New LINN Inc., a newly formed Delaware corporation (“New LINN”), with Merger Sub surviving such merger (the “Merger”). Immediately following the Merger, New LINN changed its name to “Linn Energy, Inc.” For purposes of Rule 15d-5 under the Exchange Act, New LINN is the successor registrant to LINN Energy.
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. The reference to “LinnCo” herein refers to LinnCo, LLC, which was an affiliate of the Predecessor.
The reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”
Executive Overview
LINN Energy was formed in February 2017, in connection with the reorganization 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 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District 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 pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017.
On December 3, 2016, LINN Energy filed an amended plan of reorganization that excluded Berry. 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.
Prior to the Spin-Off (as defined below), the Company’s upstream properties were located in six operating regions in the United States (“U.S.”):
Hugoton Basin, which includesour oil and natural gas properties, as well asproduction to mitigate the Jayhawkimpact 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 processing plant, located in Kansas;contracts are based on Oklahoma indexes, including ONEOK Gas Transportation, Natural Gas Pipeline Company of America Mid-Continent, Panhandle Eastern Pipeline and Southern Star Central Gas Pipeline 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.
| |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
East Texas, which includesOil and natural gas prices have been subject to significant fluctuations during the past several years. The following table sets forth the average NYMEX oil and natural gas properties producing primarilyprices for the three and six months ended June 30, 2019 and 2018:
|
| | | | | | | | | | | | | | | |
| | Three Months Ended
June 30, | | Six Months Ended
June 30, |
| | 2019 | | 2018 | | 2019 | | 2018 |
| Average NYMEX prices | | | | | | | |
| Oil (Bbl) | $ | 59.79 |
| | $ | 67.85 |
| | $ | 57.32 |
| | $ | 65.35 |
|
| Natural gas (MMcf) | $ | 2.66 |
| | $ | 2.96 |
| | $ | 2.84 |
| | $ | 3.08 |
|
Results of Operations
Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018
The following table presents selected financial and operating information for the periods presented.
|
| | | | | | | |
| | Three Months Ended
June 30, |
| | 2019 |
| 2018 |
| Production Data | | | |
| Oil (MBbls) | 1,198 |
| | 877 |
|
| Natural gas (MMcf) | 12,533 |
| | 9,157 |
|
| Natural gas liquids (MBbls) | 1,339 |
| | 883 |
|
| Total volumes (MBoe) | 4,626 |
| | 3,286 |
|
| Average daily total volumes (MBoe/d) | 50.8 |
| | 36.1 |
|
| Average Prices - as reported | | | |
| Oil (per Bbl) | $ | 57.76 |
| | $ | 66.91 |
|
| Natural gas (per Mcf) | $ | 1.04 |
| | $ | 1.53 |
|
| Natural gas liquids (per Bbl) | $ | 11.08 |
| | $ | 20.25 |
|
| Total (per Boe) | $ | 20.99 |
| | $ | 27.56 |
|
| Average Prices - including impact of derivative contract settlements | | |
| Oil (per Bbl) | $ | 58.17 |
| | $ | 54.41 |
|
| Natural gas (per Mcf) | $ | 1.33 |
| | $ | 1.66 |
|
| Natural gas liquids (per Bbl) | $ | 13.53 |
| | $ | 20.25 |
|
| Total (per Boe) | $ | 22.59 |
| | $ | 24.59 |
|
| Average Prices - excluding gathering, transportation and processing costs | | |
| Oil (per Bbl) | $ | 58.00 |
| | $ | 66.91 |
|
| Natural gas (per Mcf) | $ | 1.82 |
| | $ | 1.95 |
|
| Natural gas liquids (per Bbl) | $ | 15.57 |
| | $ | 26.60 |
|
| Total (per Boe) | $ | 24.45 |
| | $ | 30.44 |
|
Revenues
Our operating revenues includes revenues from the Cotton Valley and Bossier Sandstone;
North Louisiana, which includessale of oil, and natural gas properties producingand NGLs and gain (loss) on derivative contracts. The following table provides information on our operating revenues:
|
| | | | | | | |
| | Three Months Ended
June 30, |
| | 2019 |
| 2018 |
| Revenues | (in thousands) |
| Oil sales | $ | 69,196 |
| | $ | 58,677 |
|
| Natural gas sales | 13,089 |
| | 14,007 |
|
| Natural gas liquid sales | 14,835 |
| | 17,883 |
|
| Gain (loss) on derivative contracts | 37,054 |
| | (54,602 | ) |
| Total revenues | $ | 134,174 |
| | $ | 35,965 |
|
Oil sales. Our oil sales increased by approximately $10.5 million, or 18%, to $69.2 million for the three months ended June 30, 2019 from $58.7 million for the three months ended June 30, 2018. This increase was primarily due to the increase in volumes during the three months ended June 30, 2019 of 321 MBbls, or 37%, which resulted from the Cotton Valley Sandstones;
Michigan/Illinois, which includes properties producingwells brought on line during the second half of 2018 and the first half of 2019. The increase in oil sales from higher volumes was partially offset by the Antrim Shale formation located in northern Michigan and oil properties in southern Illinois;
Rockies, which includes non-operated properties locateddecrease in the Dunkards Wash fieldaverage sales prices received for produced volumes. The decrease in Utah; and
Mid-Continent, which includes propertiesaverage sales prices received on our oil production for the three months ended June 30, 2019 reflects the decrease in the Northwest STACKindex price for oil in northwestern Oklahoma, the Arkoma STACK located in southeastern Oklahoma, and various other oil and2019 period as compared to the 2018 period.
Natural Gas sales. Our natural gas producing properties throughout Oklahoma.
sales decreased by approximately $0.9 million, or 7%, to $13.1 million for the three months ended June 30, 2019 from $14.0 million for the three months ended June 30, 2018. This decrease was primarily due to the decrease in the average sales prices received for produced volumes. The Company’s midstream business consisted of the Chisholm Trail gas plant system (“Chisholm Trail”), which is comprised of the newly constructed cryogenicdecrease in average sales prices received on our natural gas processing facility,production for the three months ended June 30, 2019 reflects the decrease in the index price for natural gas in the 2019 period as compared to the 2018 period. The decrease in natural gas sales from lower sales prices was partially offset by an increase in production. Our natural gas production increased 3,376 MMcf, or 37%, to 12,533 MMcf for the three months ended June 30, 2019 from 9,157 MMcf for the three months ended June 30, 2018. The increase in production volumes was due to drilling activity during 2018 and the first half of 2019.
NGL sales. Our NGL sales decreased by approximately $3.0 million, or 17%, to $14.8 million for the three months ended June 30, 2019 from $17.9 million for the three months ended June 30, 2018. This decrease was primarily due to the decrease in the average sales prices received for produced volumes partially offset by an increase in production. The decrease in average sales prices received on our NGL production for the three months ended June 30, 2019 reflects the weakening of market pricing for NGL products in the 2019 period as compared to the 2018 period. Our NGL production increased 456 MBbls, or 52%, to 1,339 MBbls for the three months ended June 30, 2019 from 883 MBbls for the three months ended June 30, 2018. The increase in production volumes was due to drilling activity during 2018 and the first half of 2019.
Gain (loss) on derivative contracts. For the three months ended June 30, 2019, we had a refrigeration plant,gain on derivative contracts of $37.1 million compared with a loss on derivative contracts of $54.6 million for the three months ended June 30, 2018. For the three months ended June 30, 2019, our gain on derivative contracts included a favorable change in the fair value of derivative contracts of $29.7 million and a networkgain on settlement of gathering pipelines located in the Merge/SCOOP/STACK play.
The Company also owns a 50% equity interest in Roan Resources LLC (“Roan”), which is focused on the accelerated developmentderivatives contracts of the Merge/SCOOP/STACK play in Oklahoma. During 2018, the Company divested all of its properties located in the previous Permian Basin operating region.
During 2017, the Company divested all of its properties located in the previous California and South Texas operating regions. See below and Note 4 for details of the Company’s divestitures.
$7.4 million. For the three months ended June 30, 2018, our loss on derivative contracts included an unfavorable change in the Company’s results includedfair value of derivative contracts of $44.8 million and a loss on settlement of derivative contracts of $9.8 million. This change in the following:fair value of derivative contracts was related to changes in the future price outlook for oil and natural gas prices that had a positive impact on the fair value of our derivative contracts. Additionally, we had settlements received during 2019 for natural gas and NGL derivative contracts due to favorable pricing compared to payments made during 2018 for oil derivative contracts due to unfavorable pricing.
Operating Expenses
Our operating expenses reflect costs incurred in the development, production and sale of oil, natural gas and NGL sales of approximately $87 million compared to $243 million for the three months ended June 30, 2017;
average daily production of approximately 312 MMcfe/d compared to 710 MMcfe/d for the three months ended June 30, 2017;
net income attributable to common stockholders of approximately $5 million compared to $220 million for the three months ended June 30, 2017;
capital expenditures of approximately $42 million compared to $96 million for the three months ended June 30, 2017; and
10 wells drilled (all successful) compared to 14 wells drilled (all successful) for the three months ended June 30, 2017.
For the six months ended June 30, 2018, the Company’s results included the following:
oil, natural gas and NGL sales of approximately $224 million compared to $323 million and $189 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively;
average daily production of approximately 356 MMcfe/d compared to 722 MMcfe/d and 745 MMcfe/d for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively;
net income attributable to common stockholders/unitholders of approximately $75 million compared to $213 million and $2.4 billion for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively;
net cash provided byNGLs. The following table provides information on our operating activities from continuing operations of $52 million compared to approximately $70 million and $51 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively;
capital expenditures of approximately $109 million compared to $114 million and $46 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively; and
15 wells drilled (all successful) compared to 41 wells drilled (all successful) for the six months ended June 30, 2017.
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
June 30, |
| | 2019 |
| 2018 |
| | (in thousands, except costs per Boe) |
| Operating Expenses | | | |
| Production expenses | $ | 11,303 |
| | $ | 7,019 |
|
| Production taxes | 5,065 |
| | 2,296 |
|
| Exploration expenses | 11,406 |
| | 10,633 |
|
| Depreciation, depletion, amortization and accretion | 44,893 |
| | 24,601 |
|
General and administrative (1) | 12,311 |
| | 13,086 |
|
| Loss on sale of other assets | 50 |
| | — |
|
| Total | $ | 85,028 |
| | $ | 57,635 |
|
| Average Costs per Boe | | | |
| Production expenses | $ | 2.44 |
| | $ | 2.14 |
|
| Production taxes | 1.09 |
| | 0.70 |
|
| Exploration expenses | 2.47 |
| | 3.24 |
|
| Depreciation, depletion, amortization and accretion | 9.70 |
| | 7.49 |
|
General and administrative (1) | 2.66 |
| | 3.98 |
|
| Loss on sale of other assets | 0.01 |
| | — |
|
| Total | $ | 18.37 |
| | $ | 17.55 |
|
| |
Item 2.(1) | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Holding Company Reorganization
On July 25, 2018, in accordance with Section 251(g) of the Delaware General Corporation Law, LINN Energy merged with and into Merger Sub, a newly formed Delaware limited liability company and wholly owned subsidiary of New LINN, with Merger Sub surviving the Merger. The Merger was completed pursuant to the terms of an Agreement and Plan of Merger by and among LINN Energy, New LINN and Merger Sub, dated July 25, 2018 (the “Merger Agreement”).
Pursuant to the Merger Agreement, at the effective time of the Merger, all outstanding shares of Class A common stock of LINN Energy were automatically converted into identical shares of Class A common stock of New LINN on a one-for-one basis, and LINN Energy’s existing stockholders became stockholders of New LINN in the same amounts and percentages as they were in LINN Energy immediately prior to the Merger.
Spin-Off Transactions
In April 2018, the Company announced its intention to separate its then wholly owned subsidiary, Riviera Resources, LLC (together with its corporate successor, “Riviera”) from LINN Energy. To effect the separation, Linn Energy, Inc. and certain of its direct and indirect subsidiaries undertook an internal reorganization (including the conversion of Riviera from a limited liability company to a corporation), following which Riviera Resources, Inc. holds, directly or through its subsidiaries, substantially all of the assets of LINN Energy, other than LINN Energy’s 50% equity interest in Roan. Following the internal reorganization, Linn Energy, Inc. distributed all of the outstanding shares of common stock of Riviera to LINN Energy stockholders on a pro rata basis (the “Spin-off”). Following the Spin-off, Riviera Resources, Inc. is an independent reporting company quoted for trading on the OTC Market under the ticker “RVRA.” LINN Energy did not retain any ownership interest in Riviera and will remain a reporting company quoted for trading on the OTCQB Market under the symbol “LNGG.” The Spin-off was completed on August 7, 2018.
Divestitures
Below are the Company’s completed divestitures in 2018:
On April 10, 2018, the Company completed the sale of its conventional properties located in New Mexico (the “New Mexico Assets Sale”). Cash proceeds received from the sale of these properties were approximately $15 million and the Company recognized a net gain of approximately $11 million.
On April 4, 2018, the Company completed the sale of its interest in properties located in the Altamont Bluebell Field in Utah (the “Altamont Bluebell Assets Sale”). Cash proceeds received from the sale of these properties were approximately $132 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $83 million.
On March 29, 2018, the Company completed the sale of its interest in conventional properties located in west Texas (the “West Texas Assets Sale”). Cash proceeds received from the sale of these properties were approximately $107 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $55 million.
On February 28, 2018, the Company completed the sale of its Oklahoma waterflood and Texas Panhandle properties (the “Oklahoma and Texas Assets Sale”). Cash proceeds received from the sale of these properties were approximately $112 million (including a deposit of approximately $12 million received in 2017), net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $46 million.
As a result of the Company’s strategic exit from California during 2017 (completed by the San Joaquin Basin Sale and Los Angeles Basin Sale), the Company classified the results of operations and cash flows of its California properties as discontinued operations on its condensed consolidated financial statements.
Construction of Cryogenic Plant
In July 2017, the Company’s then subsidiary, Blue Mountain Midstream LLC (“Blue Mountain”) entered into a definitive agreement with BCCK Engineering, Inc. to construct a 225 MMcf/d cryogenic natural gas processing facility with a total capacity of 250 MMcf/d. The facility was successfully commissioned in the second quarter of 2018. Blue Mountain became a subsidiary of Riviera on August 7, 2018 in connection with the Spin-off.
| |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Financing Activities
Share Repurchase Program
The Company’s Board of Directors previously authorized the repurchase of up to $400 million of the Company’s outstanding shares of Class A common stock. The Company discontinued the share repurchase program in July 2018.
During the six months ended June 30, 2018, the Company repurchased an aggregate of 1,557,180 shares of Class A common stock at an average price of $39.13 per share for a total cost of approximately $61 million. In July 2018, the Company purchased 280,289 shares of Class A common stock at an average price of $40.30 for a total cost of approximately $11 million. During 2017 and 2018, the Company purchased an aggregate of 7,527,661 shares of Class A common stock at an average price of $35.94 for a total cost of approximately $271 million.
Tender Offer
On December 14, 2017, the Company’s Board of Directors announced the intention to commence a tender offer to purchase at least $250 million of the Company’s Class A common stock. In January 2018, upon the terms and subject to the conditions described in the Offer to Purchase dated December 20, 2017, as amended, the Company repurchased an aggregate of 6,770,833 shares of Class A common stock at a fixed price of $48.00 per share for a total cost of approximately $325 million (excluding expenses of approximately $4 million related to the tender offer).
Credit Facility
On April 30, 2018, the Company entered into an amendment to the Credit Facility which, among other things, modified the borrowing base and maximum borrowing commitment amount to $425 million. Pursuant to the Spin-off, the borrower under the Credit Facility became a subsidiary of Riviera and as such, Riviera and its subsidiaries have assumed all obligations under the Credit Facility.
Commodity Derivatives
During the six months ended June 30, 2018, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for March 2018 through December 2019, natural gas fixed price swaps for January 2019 through December 2019 and oil fixed price swaps for January 2019 through December 2019. In April 2018, in connection with the closing of the Altamont Bluebell Assets Sale, the Company canceled its oil collars for 2018 and 2019. The Company paid net cash settlements of approximately $20 million for the cancellations.
| |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Results of Operations
Three Months Ended June 30, 2018, Compared to Three Months Ended June 30, 2017
|
| | | | | | | | | | | |
| | Successor | | |
| | Three Months Ended June 30, | | |
| | 2018 | | 2017 | | Variance |
| | (in thousands) |
| Revenues and other: | | | | | |
| Natural gas sales | $ | 53,662 |
| | $ | 110,481 |
| | $ | (56,819 | ) |
| Oil sales | 10,919 |
| | 89,237 |
| | (78,318 | ) |
| NGL sales | 22,423 |
| | 43,449 |
| | (21,026 | ) |
| Total oil, natural gas and NGL sales | 87,004 |
| | 243,167 |
| | (156,163 | ) |
| Gains (losses) on oil and natural gas derivatives | (7,525 | ) | | 45,714 |
| | (53,239 | ) |
| Marketing and other revenues | 49,354 |
| | 18,938 |
| | 30,416 |
|
| | 128,833 |
| | 307,819 |
| | (178,986 | ) |
| Expenses: | | | | | |
| Lease operating expenses | 24,088 |
| | 71,057 |
| | (46,969 | ) |
| Transportation expenses | 21,213 |
| | 37,388 |
| | (16,175 | ) |
| Marketing expenses | 40,327 |
| | 6,976 |
| | 33,351 |
|
General and administrative expenses (1) | 92,395 |
| | 34,458 |
| | 57,937 |
|
| Exploration costs | 53 |
| | 811 |
| | (758 | ) |
| Depreciation, depletion and amortization | 21,980 |
| | 51,987 |
| | (30,007 | ) |
| Taxes, other than income taxes | 7,297 |
| | 17,871 |
| | (10,574 | ) |
| Gains on sale of assets and other, net | (101,777 | ) | | (306,878 | ) | | 205,101 |
|
| | 105,576 |
| | (86,330 | ) | | 191,906 |
|
| Other income and (expenses) | (9,373 | ) | | (8,623 | ) | | (750 | ) |
| Reorganization items, net | (1,259 | ) | | (3,377 | ) | | 2,118 |
|
| Income from continuing operations before income taxes | 12,625 |
| | 382,149 |
| | (369,524 | ) |
| Income tax expense | 5,722 |
| | 158,770 |
| | (153,048 | ) |
| Income from continuing operations | 6,903 |
| | 223,379 |
| | (216,476 | ) |
| Loss from discontinued operations, net of income taxes | — |
| | (3,322 | ) | | 3,322 |
|
| Net income | 6,903 |
| | 220,057 |
| | (213,154 | ) |
| Net income attributable to noncontrolling interests | 1,799 |
| | — |
| | 1,799 |
|
| Net income attributable to common stockholders | $ | 5,104 |
| | $ | 220,057 |
| | $ | (214,953 | ) |
| |
(1)
| General and administrative expenses for the three months ended June 30, 2018,2019 and June 30, 2017,2018 include approximately $58$(3.2) million, or $(0.70) per Boe, and $15$2.8 million, respectively,or $0.86 per Boe, of share-basedequity-based compensation expenses. In addition, general and administrative expenses for the three months ended June 30, 2018, and June 30, 2017, include approximately $14 million and $502,000, respectively of severance costs. |
| |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
|
| | | | | | | | | | |
| | Successor | | |
| | Three Months Ended June 30, | | |
| | 2018 | | 2017 | | Variance |
| Average daily production: | | | | | |
| Natural gas (MMcf/d) | 238 |
| | 432 |
| | (45 | )% |
| Oil (MBbls/d) | 1.8 |
| | 21.6 |
| | (92 | )% |
| NGL (MBbls/d) | 10.5 |
| | 24.8 |
| | (58 | )% |
| Total (MMcfe/d) | 312 |
| | 710 |
| | (56 | )% |
| | | | | | |
Average daily production – Equity method investments: (1) | | | | | |
| Total (MMcfe/d) | 109 |
| | — |
| | 100 | % |
| | | | | | |
Weighted average prices: (2) | | | | | |
| Natural gas (Mcf) | $ | 2.48 |
| | $ | 2.81 |
| | (12 | )% |
| Oil (Bbl) | $ | 66.66 |
| | $ | 45.42 |
| | 47 | % |
| NGL (Bbl) | $ | 23.43 |
| | $ | 19.29 |
| | 21 | % |
| | | | | | |
| Average NYMEX prices: | | | | | |
| Natural gas (MMBtu) | $ | 2.80 |
| | $ | 3.18 |
| | (12 | )% |
| Oil (Bbl) | $ | 67.88 |
| | $ | 48.28 |
| | 41 | % |
| | | | | | |
| Costs per Mcfe of production: | | | | | |
| Lease operating expenses | $ | 0.85 |
| | $ | 1.10 |
| | (23 | )% |
| Transportation expenses | $ | 0.75 |
| | $ | 0.58 |
| | 29 | % |
General and administrative expenses (3) | $ | 3.26 |
| | $ | 0.53 |
| | 515 | % |
| Depreciation, depletion and amortization | $ | 0.77 |
| | $ | 0.80 |
| | (3 | )% |
| Taxes, other than income taxes | $ | 0.26 |
| | $ | 0.28 |
| | (8 | )% |
| | | | | | |
| Average daily production – discontinued operations: | | | | | |
| Total (MMcfe/d) | — |
| | 29 |
| | (100 | )% |
| |
(1)
| Represents the Company’s 50% equity interest in Roan. |
| |
(2)
| Does not include the effect of gains (losses) on derivatives. |
| |
(3)
| expense, respectively. General and administrative expenses for the three months ended June 30, 2018,2019 includes $3.9 million, or $0.83 per Boe, of bad debt expense and June 30, 2017, include approximately $58$2.2 million, and $15 million, respectively,or $0.47 per Boe, of share-based compensation expenses. In addition, general and administrative expenses for the three months ended June 30, 2018, and June 30, 2017, include approximately $14 million and $502,000, respectively of severanceaborted offering costs. |
| |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
saltwater disposal, monitoring, pumping, chemicals, maintenance, repairs, workover expenses and direct labor and overhead related to production activities. Production expenses were $11.3 million, or $2.44 per Boe, for the three months ended June 30, 2019, which was an increase of $4.3 million, or 61%, from $7.0 million, or $2.14 per Boe, for the three months ended June 30, 2018. The increase in production expenses during 2019 compared to 2018 was primarily due to increased production and increases in water hauling and disposal costs as a result of higher water volumes as well as increases in compression services and surface repairs incurred during the three months ended June 30, 2019.
Revenues and Other
Oil, Natural Gas and NGL Sales
Oil,Production taxes. Production taxes are paid on produced oil, natural gas, and NGLNGLs based primarily on a percentage of sales decreasedrevenues from production sold at fixed rates established by approximately $156 millionfederal, state or 64% to approximately $87local taxing authorities. Production taxes were $5.1 million for the three months ended June 30, 2018,2019, an increase of $2.8 million, or 121%, from approximately $243$2.3 million for the three months ended June 30, 2017,2018. Production taxes primarily increased due to lowerincreased production volumes astax 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 resultgroup basis, costs of divestitures completed in 2017carrying and 2018. Lower natural gas prices resulted in a decrease in revenues of approximately $7 million. Higher NGLretaining unproved properties, and oil prices resulted incosts related to unsuccessful leasing efforts. Exploration expenses were $11.4 million for the three months ended June 30, 2019, an increase in revenues of approximately $4$0.8 million, or 7%, from $10.6 million for the three months ended June 30, 2018. Exploration expenses for the three months ended June 30, 2019 primarily consisted of unproved leasehold amortization. For the three months ended June 30, 2018, exploration expenses included unproved leasehold amortization of $7.1 million and $3 million, respectively. In addition, revenues increasedgeological and geophysical expenses of $3.5 million. Unproved leasehold amortization is calculated by approximately $1 millionconsidering our drilling plans and the lease terms of our existing unproved properties. The increase in unproved leasehold amortization for the 2019 period is primarily due to additional leasehold set to expire in upcoming periods.
Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion was $44.9 million, or $9.70 per Boe, for the impact of the new accounting standard relatedthree months ended June 30, 2019, compared to revenues from contracts with customers, adopted on January 1, 2018. As of January 1, 2017, revenue was recognized net of transportation expenses if the processor was the customer and there was no redelivery of commodities to the Company. See Note 1 for additional details of the revenue accounting standard.
Average daily production volumes decreased to approximately 312 MMcfe/d$24.6 million, or $7.49 per Boe, for the three months ended June 30, 2018, from 710 MMcfe/dwhich is an increase of $20.3 million or 82%. The increase in depreciation, depletion, amortization and accretion was primarily due to an increase in the depletion rate for our oil and natural gas properties and, to a lesser extent, increased production. The per Boe increase in the depletion rate is attributable to higher capital expenditures.
General and administrative. General and administrative expenses were $12.3 million, or $2.66 per Boe, for the three months ended June 30, 2017. Lower oil, natural gas and NGL production volumes resulted in2019, a decrease in revenues of approximately $82$0.8 million $50or 6% from $13.1 million, or $3.98 per Boe, for the three months ended June 30, 2018. During the three months ended June 30, 2019, general and administrative expenses included salaries and benefits of $6.5 million, equity-based compensation expense of $(3.2) million due to forfeitures during the quarter, bad debt expense of $3.9 million and $25offering costs of $2.2 million, respectively.including $1.3 million that were previously deferred offering costs. During the three months ended June 30, 2018, general and administrative expenses included salaries and benefits of $4.6 million, equity-based compensation expense of $2.8 million and fees paid to Citizen and Linn under the MSAs of $2.5 million. The MSAs with Citizen and Linn concluded in April 2018.
The following table sets forth average daily production by region:
|
| | | | | | | | | | | |
| | Successor | | | | |
| | Three Months Ended June 30, | | | | |
| | 2018 | | 2017 | | Variance |
| Average daily production (MMcfe/d): | | | | | | | |
| Hugoton Basin | 136 |
| | 164 |
| | (28 | ) | | (18 | )% |
| Mid-Continent | 49 |
| | 126 |
| | (77 | ) | | (61 | )% |
| East Texas | 51 |
| | 53 |
| | (2 | ) | | (3 | )% |
| Rockies | 22 |
| | 244 |
| | (222 | ) | | (91 | )% |
| Michigan/Illinois | 27 |
| | 29 |
| | (2 | ) | | (6 | )% |
| North Louisiana | 27 |
| | 23 |
| | 4 |
| | 14 | % |
| Permian Basin | — |
| | 46 |
| | (46 | ) | | (100 | )% |
| South Texas | — |
| | 25 |
| | (25 | ) | | (100 | )% |
| | 312 |
| | 710 |
| | (398 | ) | | (56 | )% |
| Equity method investments | 109 |
| | — |
| | 109 |
| | 100 | % |
The increase in average daily production volumes inInterest expense, net. Interest expense, net of capitalized interest, for the North Louisiana region primarily reflect increased development capital spending in the region. The decrease in average daily production volumes in the Mid-Continent region primarily reflects lower production volumesthree months ended June 30, 2019 was $8.5 million 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 Hugoton Basin, Rockies, Permian Basin and South Texas regions primarily reflect lower production volumes as a result of divestitures completed during 2017 and 2018. 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 driven by continued low commodity prices. Equity method investments represents the Company’s 50% equity interest in Roan.
Gains (Losses) on Oil and Natural Gas Derivatives
Losses on oil and natural gas derivatives were approximately $8compared to $1.1 million for the three months ended June 30, 2018,2018. This increase was due to increased borrowings outstanding during the three months ended June 30, 2019 as compared to gainsthe three months ended June 30, 2018.
Income tax expense. The income tax expense for the three months ended June 30, 2019 was $13.4 million and is the result of approximately $46 millionour effective tax rate applied to our net income for the quarter. As Roan LLC was a flow‑through entity for income tax purposes, there was no income tax expense or benefit recorded for the three months ended June 30, 2017, representing a variance2018.
Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018
The following table presents selected financial and operating information for the periods presented.
|
| | | | | | | |
| | Six Months Ended
June 30, |
| | 2019 | | 2018 |
| Production Data | | | |
| Oil (MBbls) | 2,337 |
| | 1,915 |
|
| Natural gas (MMcf) | 24,153 |
| | 18,069 |
|
| Natural gas liquids (MBbls) | 2,668 |
| | 1,757 |
|
| Total volumes (MBoe) | 9,031 |
| | 6,684 |
|
| Average daily total volumes (MBoe/d) | 49.9 |
| | 36.9 |
|
| Average Prices - as reported | | | |
| Oil (per Bbl) | $ | 55.53 |
| | $ | 63.90 |
|
| Natural gas (per Mcf) | $ | 1.44 |
| | $ | 1.71 |
|
| Natural gas liquids (per Bbl) | $ | 11.63 |
| | $ | 21.78 |
|
| Total (per Boe) | $ | 21.67 |
| | $ | 28.66 |
|
| Average Prices - including impact of derivative contract settlements | | |
| Oil (per Bbl) | $ | 58.80 |
| | $ | 55.70 |
|
| Natural gas (per Mcf) | $ | 1.43 |
| | $ | 1.81 |
|
| Natural gas liquids (per Bbl) | $ | 13.69 |
| | $ | 21.78 |
|
| Total (per Boe) | $ | 23.08 |
| | $ | 26.58 |
|
| Average Prices - excluding gathering, transportation and processing costs | | |
| Oil (per Bbl) | $ | 55.69 |
| | $ | 63.90 |
|
| Natural gas (per Mcf) | $ | 2.15 |
| | $ | 2.17 |
|
| Natural gas liquids (per Bbl) | $ | 15.94 |
| | $ | 27.63 |
|
| Total (per Boe) | $ | 24.87 |
| | $ | 31.43 |
|
Revenues
Our operating revenues includes revenues from the sale of approximately $54 million. Gains and losses on oil, and natural gas derivatives were primarily due to changes in fair value of theand NGLs and loss on derivative contracts. The fair valuefollowing table provides information 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.our operating revenues:
|
| | | | | | | |
| | Six Months Ended
June 30, |
| | 2019 |
| 2018 |
| Revenues | (in thousands) |
| Oil sales | $ | 129,767 |
|
| $ | 122,369 |
|
| Natural gas sales | 34,870 |
|
| 30,897 |
|
| Natural gas liquid sales | 31,022 |
|
| 38,271 |
|
| Loss on derivative contracts | (46,588 | ) |
| (64,216 | ) |
| Total revenues | $ | 149,071 |
|
| $ | 127,321 |
|
| |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
The Company determined the fair value of itsOil sales. Our 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 7 and Note 8 for additional details about the Company’s commodity derivatives. For information about the Company’s pre-Spin-off 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 helium sales revenue. Consolidated marketing and other revenues increased by approximately $30$7.4 million, or 161%6%, to approximately $49$129.8 million for the threesix months ended June 30, 2018,2019 from approximately $19$122.4 million for the three months ended June 30, 2017. Marketing and other revenues of the upstream segment increased by approximately $12 million or 70% to approximately $29 million for the three months ended June 30, 2018, from approximately $17 million for the three months ended June 30, 2017. 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 the impact of the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018. As of January 1, 2018, the Company recognized revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities. This recognition resulted in an increase to revenues and expenses with no impact on net income. See Note 1 for additional details of the revenue accounting standard.
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 $47 million or 66% to approximately $24 million for the three months ended June 30, 2018, from approximately $71 million for the three months ended June 30, 2017. 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 and 2018. Lease operating expenses per Mcfe decreased to $0.85 per Mcfe for the three months ended June 30, 2018, from $1.10 per Mcfe for the three months ended June 30, 2017.
Transportation Expenses
Transportation expenses decreased by approximately $16 million or 43% to approximately $21 million for the three months ended June 30, 2018, from approximately $37 million for the three months ended June 30, 2017. The decrease was due to reduced costs as a result of lower production volumes primarily as a result of the divestitures completed in 2017 and 2018, partially offset by the impact of the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018. As of January 1, 2018, revenue is recognized net of transportation expenses if the processor is the customer and there is no redelivery of commodities to the Company. See Note 1 for additional details of the revenue accounting standard. Transportation expenses per Mcfe increased to $0.75 per Mcfe for the three months ended June 30, 2018, from $0.58 per Mcfe for the three months ended June 30, 2017.
Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Consolidated marketing expenses increased by approximately $33 million to approximately $40 million for the three months ended June 30, 2018, from approximately $7 million for the three months ended June 30, 2017. Marketing expenses of the upstream segment increased by approximately $14 million to approximately $20 million for the three months ended June 30, 2018, from approximately $6 million for the three months ended June 30, 2017. 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 and the impact of the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018. As of January 1, 2018, the Company recognized revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities. This recognition resulted in an increase to revenues and expenses with no impact on net income. See Note 1 for additional details of the revenue accounting standard.
| |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
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. General and administrative expenses increased by approximately $58 million or 168% to approximately $92 million for the three months ended June 30, 2018, from approximately $34 million for the three months ended June 30, 2017. The increase was primarily due to higher share-based compensation expenses, higher severance costs, and transition service fees received from Berry in the prior year, partially offset by lower salaries and benefits related expenses. General and administrative expenses per Mcfe increased to $3.26 per Mcfe for the three months ended June 30, 2018, from $0.53 per Mcfe for the three months ended June 30, 2017.
For the professional services expenses related to the Chapter 11 proceedings, see “Reorganization Items, Net.”
Exploration Costs
Exploration costs decreased by approximately $758,000 to approximately $53,000 for the three months ended June 30, 2018, from approximately $811,000 for the three months ended June 30, 2017. The decrease was primarily due to lower seismic data expenses.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by approximately $30 million or 58% to approximately $22 million for the three months ended June 30, 2018, from approximately $52 million for the three months ended June 30, 2017. The decrease was primarily due to lower total production volumes. Depreciation, depletion and amortization per Mcfe decreased to $0.77 per Mcfe for the three months ended June 30, 2018, from $0.80 per Mcfe for the three months ended June 30, 2017.
Taxes, Other Than Income Taxes
|
| | | | | | | | | | | |
| | Successor | | |
| | Three Months Ended June 30, | | |
| | 2018 | | 2017 | | Variance |
| | (in thousands) |
| | | | | | |
| Severance taxes | $ | 2,861 |
| | $ | 10,669 |
| | $ | (7,808 | ) |
| Ad valorem taxes | 4,161 |
| | 6,933 |
| | (2,772 | ) |
| Other | 275 |
| | 269 |
| | 6 |
|
| | $ | 7,297 |
| | $ | 17,871 |
| | $ | (10,574 | ) |
Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower production volumes. 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 2018 and lower estimated valuations on certain of the Company’s properties.
Gains on Sale of Assets and Other, Net
During the three months ended June 30, 2018, the Company recorded the following net gains on divestitures (see Note 4):
Net gain of approximately $11 million on the New Mexico Assets Sale; and
Net gain of approximately $83 million, including costs to sell of approximately $2 million, on the Altamont Bluebell Assets Sale.
During the three months ended June 30, 2017, the Company recorded the following net gains on divestitures (see Note 4):
Net gain of approximately $22 million on the Salt Creek Assets Sale; and
Net gain of approximately $279 million, including costs to sell of approximately $6 million, on the Jonah Assets Sale.
| |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Other Income and (Expenses)
|
| | | | | | | | | | | |
| | Successor | | |
| | Three Months Ended June 30, | | |
| | 2018 | | 2017 | | Variance |
| | (in thousands) |
| | | | | | |
| Interest expense, net of amounts capitalized | $ | (584 | ) | | $ | (7,551 | ) | | $ | 6,967 |
|
| Earnings (losses) from equity method investments | (9,327 | ) | | 91 |
| | (9,418 | ) |
| Other, net | 538 |
| | (1,163 | ) | | 1,701 |
|
| | $ | (9,373 | ) | | $ | (8,623 | ) | | $ | (750 | ) |
Interest expense decreased primarily due to no outstanding debt during 2018, and lower amortization of financing fees. For the three months ended June 30, 2018, interest expense is primarily related to amortization of financing fees. See “Debt” under “Liquidity and Capital Resources” below for additional details.
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 6 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 |
| | Three Months Ended June 30, |
| | 2018 | | 2017 |
| | (in thousands) |
| | | | |
| Legal and other professional advisory fees | $ | (1,255 | ) | | $ | (3,446 | ) |
| Other | (4 | ) | | 69 |
|
| Reorganization items, net | $ | (1,259 | ) | | $ | (3,377 | ) |
Income Tax Expense
The Company recognized income tax expense of approximately $6 million and $159 million for the three months ended June 30, 2018, and June 30, 2017, respectively. The decrease is primarily due to a decrease in taxable earnings and a decrease in the federal statutory income tax rate.
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), the Company has classified the results of operations of its California properties as discontinued operations. Loss from discontinued operations, net of income taxes was approximately $3 million for the three months ended June 30, 2017. See Note 4 for additional information.
| |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Net Income Attributable to Common Stockholders
Net income attributable to common stockholders decreased by approximately $215 million to approximately $5 million for the three months ended June 30, 2018, from approximately $220 million the three months ended June 30, 2017. The decrease was primarily due to lower gains on sales of assets, lower production revenue and losses compared to gains on commodity derivatives, partially offset by lower expenses during the threesix months ended June 30, 2018. See discussion above for explanations of variances.This increase was primarily
Chisholm Trail Reporting Segment
|
| | | | | | | | | | | |
| | Successor | | |
| | Three Months Ended June 30, | | |
| | 2018 | | 2017 | | Variance |
| | (in thousands) |
| | | | | | |
| Marketing revenues | $ | 20,066 |
| | $ | 1,754 |
| | $ | 18,312 |
|
| | | | | | |
| Marketing expenses | 20,083 |
| | 820 |
| | 19,263 |
|
| Severance taxes and ad valorem taxes | 285 |
| | 116 |
| | 169 |
|
| Total direct operating expenses | 20,368 |
| | 936 |
| | 19,432 |
|
Field level cash flow (1) | $ | (302 | ) | | $ | 818 |
| | $ | (1,120 | ) |
| |
(1)
| Refer to Note 19 for a reconciliation of field level cash flow to income from continuing operations before income taxes. |
Marketing Revenues
Chisholm Trail’s marketing revenue increased by approximately $18 milliondue to approximately $20 million for the threeincrease in volumes during the six months ended June 30, 2019 of 422 MBbls, or 22%, which resulted from the wells brought on line during the second half of 2018 and the first half of 2019. The increase in oil sales from approximately $2 millionhigher volumes was partially offset by the decrease in the average sales prices received for produced volumes. The decrease in average sales prices received on our oil production for the threesix months ended June 30, 2017. The2019 reflects the decrease in the index price for oil in the 2019 period as compared to the 2018 period.
Natural Gas sales. Our natural gas sales increased by approximately $4.0 million, or 13%, to $34.9 million for the six months ended June 30, 2019 from $30.9 million for the six months ended June 30, 2018. This increase was primarily due to the new accounting standard relatedincrease in production. Our natural gas production increased 6,084 MMcf, or 34%, to revenues24,153 MMcf for the six months ended June 30, 2019 from contracts with customers, adopted on January 1,18,069 MMcf for the six months ended June 30, 2018. The increase in production volumes was due to drilling activity during 2018 and the first half of 2019. The increase in natural gas sales from higher throughput volumes sold. As of January 1, 2018,was partially offset by the Company recognizes revenuesdecrease in the average sales prices received for commoditiesproduced volumes. The decrease in average sales prices received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of producton our natural gas production for the subsequent sale of those same commodities. This recognition resultssix months ended June 30, 2019 reflects the decrease in an increasethe index price for natural gas in the 2019 period as compared to revenues and expenses with no impact on net income. See Note 1 for additional details of the revenue accounting standard.2018 period.
Marketing Expenses
Chisholm Trail’s marketing expenses increasedNGL sales. Our NGL sales decreased by approximately $19$7.2 million, or 19%, to approximately $20$31.0 million for the six months ended June 30, 2019 from $38.3 million for the six months ended June 30, 2018. This decrease was primarily due to the decrease in the average sales prices received for produced volumes partially offset by an increase in production. The decrease in average sales prices received on our NGL production for the six months ended June 30, 2019 reflects the weakening of market pricing for NGL products in the 2019 period as compared to the 2018 period. Our NGL production increased 911 MBbls, or 52%, to 2,668 MBbls for the six months ended June 30, 2019 from 1,757 MBbls for the six months ended June 30, 2018. The increase in production volumes was due to drilling activity during 2018 and the first half of 2019. Additionally, we elected ethane recovery for three of the six months in 2019 while electing ethane rejection for all six months of 2018. Under ethane recovery, we receive the ethane volumes. However, ethane typically receives a lower price on produced volumes.
Loss on derivative contracts. For the six months ended June 30, 2019, we had a loss on derivative contracts of $46.6 million compared with a loss on derivative contracts of $64.2 million for the six months ended June 30, 2018. For the six months ended June 30, 2019, our loss on derivative contracts included an unfavorable change in the fair value of derivative contracts of $59.3 million partially offset by a gain on settlement of derivatives contracts of $12.7 million. For the six months ended June 30, 2018, from approximately $820,000our loss on derivative contracts included an unfavorable change in the fair value of derivative contracts of $50.3 million and a loss on settlement of derivative contracts of $13.9 million. We had settlements received during 2019 for the three months ended June 30, 2017. The increase was primarilyoil and NGL derivative contracts due to the new accounting standard relatedfavorable pricing compared to revenues frompayments made during 2018 for oil derivative contracts with customers, adopted on January 1, 2018, and higher throughput volumes purchased. As of January 1, 2018, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities. This recognition results in an increase to revenues and expenses with no impact on net income. See Note 1 for additional details of the revenue accounting standard.
Field Level Cash Flow
Chisholm Trail’s field level cash flow decreased by approximately $1 million to negative cash flow of approximately $302,000 for the three months ended June 30, 2018, from positive cash flow of approximately $818,000 for the three months ended June 30, 2017. The decrease was primarily due to widening pricing spreads between the Conway and Mont Belvieu market hubs.unfavorable pricing.
Operating Expenses
45
Our operating expenses reflect costs incurred in the development, production and sale of oil, natural gas and NGLs. The following table provides information on our operating expenses:
|
| | | | | | | |
| | Six Months Ended
June 30, |
| | 2019 | | 2018 |
| | (in thousands, except costs per Boe) |
| Operating Expenses | | | |
| Production expenses | $ | 26,149 |
| | $ | 15,374 |
|
| Production taxes | 10,104 |
| | 4,682 |
|
| Exploration expenses | 23,894 |
| | 18,483 |
|
| Depreciation, depletion, amortization and accretion | 86,465 |
| | 46,466 |
|
General and administrative (1) | 28,136 |
| | 27,106 |
|
| Gain on sale of other assets | (614 | ) | | — |
|
| Total | $ | 174,134 |
| | $ | 112,111 |
|
| Average Costs per Boe | | | |
| Production expenses | $ | 2.90 |
| | $ | 2.30 |
|
| Production taxes | 1.12 |
| | 0.70 |
|
| Exploration expenses | 2.65 |
| | 2.77 |
|
| Depreciation, depletion, amortization and accretion | 9.57 |
| | 6.95 |
|
General and administrative (1) | 3.12 |
| | 4.06 |
|
| Gain on sale of other assets | (0.07 | ) | | — |
|
| Total | $ | 19.29 |
| | $ | 16.78 |
|
| |
Item 2.(1) | Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued |
Item 4. Controls and Procedures
