UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10–Q
☑ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2017March 31, 2019
OR
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to .
Commission File Number: 001-35364
AMPLIFY ENERGY CORP.
(Exact name of registrant as specified in its charter)
Delaware |
| 82-1326219 |
(State or other jurisdiction of incorporation or organization) |
| (I.R.S. Employer Identification No.) |
|
| |
500 Dallas Street, Suite |
| 77002 |
(Address of principal executive offices) |
| (Zip Code) |
Registrant’s telephone number, including area code: (713) 490-8900
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically, and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☐ | Accelerated filer ☑ |
Non-accelerated filer ☐ | Smaller reporting company ☐ |
Emerging growth company ☐ |
|
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act). Yes ☐ No ☑
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. ☑ Yes ☐ No
Securities Registered Pursuant to Section 12(b):
Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
None | None | None |
As of NovemberMay 3, 2017,2019, the registrant had 25,000,00022,212,290 outstanding shares of common stock, $0.0001 par value outstanding.
Table of Contents
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Item 1. |
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| Notes to Unaudited Condensed Consolidated Financial Statements |
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Item 2. |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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Item 1. |
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Item 1A. |
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Item 6. |
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i
GLOSSARY OF OIL AND NATURAL GAS TERMS
Analogous Reservoir: Analogous reservoirs, as used in resource 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, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.
Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bbl/d: One Bbl per day.
Bcfe: One billion cubic feet of natural gas equivalent.
Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
MBoe/d: One million Boe per day.
BOEM: Bureau of Ocean Energy Management.
Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
Development Project: A development project is 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.
Dry Hole or Dry Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would 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 this determination, the value of the products that generate revenue are determined at the terminal point of oil and natural gas producing activities.
Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have a working interest.
ICE: Inter-Continental Exchange.
MBbl: One thousand Bbls.
MBbls/d: One thousand Bbls per day.
Mcf: One thousand cubic feet of natural gas.
Mcf/d: One Mcf per day.
MMBtu: One million Btu.
MMcf: One million cubic feet of natural gas.
MMcfe: One million cubic feet of natural gas equivalent.
MMcfe/d: One MMcfe per day.
Net Production: Production that is owned by us less royalties and production due to others.
NGLs: The combination of ethane, propane, butane and natural gasolines that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.
NYMEX: New York Mercantile Exchange.
Oil: Oil and condensate.
Operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
1
OPIS: Oil Price Information Service.
Plugging and abandonment: Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another stratum or to the surface. Regulations of all states require plugging of abandoned wells.
Probabilistic Estimate: The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
1
Proved Reserves: Those quantities of oil and natural gas, 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. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration, unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Realized Price: The cash market price less all expected quality, transportation and demand adjustments.
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: Reserves are 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 reserves.
Resources: Resources are 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 unrecoverable. Resources include both discovered and undiscovered accumulations.
Working Interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.
Workover: Operations on a producing well to restore or increase production.
WTI: West Texas Intermediate.
2
As used in this Form 10-Q, unless we indicate otherwise:
“Amplify Energy” and “Successor” referrefers to Amplify Energy Corp., the successor reporting company of Memorial Production Partners LP, individually and collectively with its subsidiaries, as the context requires;
“Memorial Production Partners,” “MEMP,”Partners” and “Predecessor”“MEMP” refer to Memorial Production Partners LP, individually and collectively with its subsidiaries, as the context requires;
“Company,” “we,” “our,” “us” or like terms refer to Memorial Production Partners for the period prior to emergence from bankruptcy and to Amplify Energy for the period after emergence from bankruptcy;
“Predecessor’s general partner” and “MEMP GP” refer to Memorial Production Partners GP LLC, the Predecessor’s general partner and wholly owned subsidiary;
“OLLC” refers to Amplify Energy Operating LLC, formerly known as Memorial Production Operating LLC, our wholly owned subsidiary through which we operate our properties;
“Finance Corp.” refers to Memorial Production Finance Corporation, our Predecessor’s wholly owned subsidiary, whose activities were limited to co-issuing our debt securities and engaging in other activities incidental thereto, which was dissolved following the effective date of the Plan (as defined in Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, “Item 1. Financial Statements”);
“Memorial Resource” refers collectively to Memorial Resource Development Corp., the former owner of the Predecessor’s general partner, and its subsidiaries;
“Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively controlled MRD Holdco LLC;
“MRD Holdco” refers to MRD Holdco LLC, which together with a group, controlled Memorial Resource; and
“NGP” refers to Natural Gas Partners.properties.
CAUTIONARY NOTE REGARDING FORWARD–LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and section 21E of the Securities Exchange Act of 1934, as amended, that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:
business strategies;
acquisition and disposition strategy;
cash flows and liquidity;
financial strategy;
ability to replace the reserves we produce through drilling;
drilling locations;
oil and natural gas reserves;
technology;
realized oil, natural gas and NGL prices;
production volumes;
lease operating expense;
gathering, processing, and transportation;
general and administrative expense;
future operating results;
ability to procure drilling and production equipment;
ability to procure oil field labor;
planned capital expenditures and the availability of capital resources to fund capital expenditures;
ability to access capital markets;
marketing of oil, natural gas and NGLs;
acts of God, fires, earthquakes, storms, floods, other adverse weather conditions, war, acts of terrorism, military operations, or national emergency;
expectations regarding general economic conditions;
competition in the oil and natural gas industry;
effectiveness of risk management activities;
environmental liabilities;
counterparty credit risk;
expectations regarding governmental regulation and taxation;
expectations regarding developments in oil-producing and natural-gas producing countries; and
plans, objectives, expectations and intentions.
All statements, other than statements of historical fact included in this report, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “would,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “outlook,” “continue,” the negative of such terms or other comparable terminology. These statements address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as projections of results of operations, plans for growth, goals, future capital expenditures, competitive strengths, references to future intentions and other such references. These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from those expressed or implied by forward-looking statements include, but are not limited to, the following risks and uncertainties:
our results of evaluation and implementation of strategic alternatives;
our inability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing, or otherwise;
our indebtedness and our ability to satisfy our debt obligations and a potential inability to effect deleveraging transactions or otherwise reduce those risks;
risks related to a redetermination of the borrowing base under our Exit Credit Facility;senior secured reserve-based revolving credit facility;
our ability to access funds on acceptable terms, if at all, because of the terms and conditions governing our indebtedness;indebtedness, including financial covenants;
our ability to satisfy debt obligations;
volatility in the prices for oil, natural gas, and NGLs, including further or sustained declines in commodity prices;
the potential for additional impairments due to continuing or future declines in oil, natural gas and NGL prices;
the uncertainty inherent in estimating quantities of oil, natural gas and NGLs reserves;
our substantial future capital requirements, which may be subject to limited availability of financing;
the uncertainty inherent in the development and production of oil and natural gas;
our need to make accretive acquisitions or substantial capital expenditures to maintain our declining asset base;
the existence of unanticipated liabilities or problems relating to acquired or divested businesses or properties;
potential acquisitions, including our ability to make acquisitions on favorable terms or to integrate acquired properties;
the uncertainty of whether and when we will be able to complete our announced merger with Midstates Petroleum Company, Inc. (“Midstates”) due to the conditions that must be satisfied or waived prior to the completion of the merger, including shareholder and any required regulatory approvals;
the consequences of changes we have made, or may make from time to time in the future, to our capital expenditure budget, including the impact of those changes on our production levels, reserves, results of operations and liquidity;
| • | potential shortages of, or increased costs for, drilling and production equipment and supply materials for production, such as CO2; |
potential difficulties in the marketing of oil and natural gas;
changes to the financial condition of counterparties;
uncertainties surrounding the success of our secondary and tertiary recovery efforts;
competition in the oil and natural gas industry;
general political and economic conditions, globally and in the jurisdictions in which we operate;
the impact of legislation and governmental regulations, including those related to climate change and hydraulic fracturing;
the risk that our hedging strategy may be ineffective or may reduce our income;
the cost and availability of insurance as well as operating risks that may not be covered by an effective indemnity or insurance; and
actions of third-party co-owners of interests in properties in which we also own an interest.
The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events or circumstances described in any forward-looking statement will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in “Part I—Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 20162018 filed with the SEC on March 10, 20176, 2019 (“20162018 Form 10-K”), “Part II—Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2017 filed with the SEC on August 9, 2017 (“Second Quarter Form 10-Q”), and “Part II—Item 1A. Risk Factors” appearing within this report and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
PARTPART I—FINANCIAL INFORMATION
AMPLIFY ENERGY CORP.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except outstanding shares/units)shares)
| Successor |
|
|
| Predecessor |
| |||||||||
| September 30, |
|
|
| December 31, |
| March 31, |
|
| December 31, |
| ||||
| 2017 |
|
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| 2016 |
| 2019 |
|
| 2018 |
| ||||
ASSETS |
|
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Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents | $ | 14,859 |
|
|
| $ | 15,373 |
| $ | 24,876 |
|
| $ | 49,704 |
|
Restricted cash |
| 325 |
|
|
| 325 |
| ||||||||
Accounts receivable |
| 32,378 |
|
|
|
| 34,584 |
|
| 25,086 |
|
|
| 29,514 |
|
Short-term derivative instruments |
| 41,376 |
|
|
|
| 69,464 |
|
| 276 |
|
|
| 18,813 |
|
Prepaid expenses and other current assets |
| 6,383 |
|
|
|
| 13,163 |
|
| 9,738 |
|
|
| 7,241 |
|
Total current assets |
| 94,996 |
|
|
|
| 132,584 |
|
| 60,301 |
|
|
| 105,597 |
|
Property and equipment, at cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method |
| 591,735 |
|
|
|
| 3,115,012 |
|
| 609,414 |
|
|
| 598,331 |
|
Support equipment and facilities |
| 100,063 |
|
|
|
| 199,093 |
|
| 110,725 |
|
|
| 108,760 |
|
Other |
| 6,055 |
|
|
|
| 15,344 |
|
| 6,687 |
|
|
| 6,625 |
|
Accumulated depreciation, depletion and impairment |
| (21,818 | ) |
|
|
| (1,749,747 | ) |
| (96,701 | ) |
|
| (85,535 | ) |
Property and equipment, net |
| 676,035 |
|
|
|
| 1,579,702 |
|
| 630,125 |
|
|
| 628,181 |
|
Long-term derivative instruments |
| 10,419 |
|
|
|
| 102,630 |
|
| 288 |
|
|
| 2,469 |
|
Restricted investments |
| 156,752 |
|
|
|
| 156,234 |
|
| 94,536 |
|
|
| 94,467 |
|
Deferred tax asset |
| 3,631 |
|
|
|
| — |
| |||||||
Operating lease - long term right-of-use asset |
| 5,011 |
|
|
| — |
| ||||||||
Other long-term assets |
| 9,518 |
|
|
|
| 2,104 |
|
| 5,922 |
|
|
| 6,129 |
|
Total assets | $ | 951,351 |
|
|
| $ | 1,973,254 |
| $ | 796,183 |
|
| $ | 836,843 |
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LIABILITIES AND EQUITY |
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Current liabilities: |
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Accounts payable | $ | 11,303 |
|
|
| $ | 4,353 |
| $ | 4,580 |
|
| $ | 2,345 |
|
Revenues payable |
| 23,403 |
|
|
|
| 21,285 |
|
| 24,136 |
|
|
| 24,779 |
|
Accrued liabilities (see Note 4) |
| 32,293 |
|
|
|
| 65,235 |
| |||||||
Current portion of long-term debt (see Note 9) |
| — |
|
|
|
| 1,622,904 |
| |||||||
Accrued liabilities (see Note 13) |
| 21,199 |
|
|
| 23,155 |
| ||||||||
Short-term derivative instruments |
| 9,108 |
|
|
| 139 |
| ||||||||
Total current liabilities |
| 66,999 |
|
|
|
| 1,713,777 |
|
| 59,023 |
|
|
| 50,418 |
|
Long-term debt (see Note 9) |
| 403,000 |
|
|
|
| — |
| |||||||
Long-term debt (see Note 8) |
| 270,000 |
|
|
| 294,000 |
| ||||||||
Asset retirement obligations |
| 97,876 |
|
|
|
| 154,913 |
|
| 77,082 |
|
|
| 75,867 |
|
Long-term derivative instruments |
| 244 |
|
|
|
| — |
|
| 1,429 |
|
|
| — |
|
Deferred tax liabilities |
| — |
|
|
|
| 2,280 |
| |||||||
Operating lease liability |
| 3,090 |
|
|
| — |
| ||||||||
Other long-term liabilities |
| — |
|
|
|
| 2,795 |
|
| 62 |
|
|
| — |
|
Total liabilities |
| 568,119 |
|
|
|
| 1,873,765 |
|
| 410,686 |
|
|
| 420,285 |
|
Commitments and contingencies (see Note 14) |
|
|
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|
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| |||||||
Stockholders'/ partners' equity: |
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| |||||||
Successor preferred stock, $0.0001 par value: 45,000,000 shares authorized; no shares issued and outstanding at September 30, 2017 and December 31, 2016 |
| — |
|
|
|
| — |
| |||||||
Successor warrants, 2,173,913 warrants issued and outstanding at September 30, 2017 and no warrants issued or outstanding at December 31, 2016 |
| 4,788 |
|
|
|
| — |
| |||||||
Successor common stock, $0.0001 par value: 300,000,000 shares authorized; 25,000,000 shares issued and outstanding at September 30, 2017 and no shares authorized or issued at December 31, 2016 |
| 3 |
|
|
|
| — |
| |||||||
Successor additional paid-in capital |
| 386,883 |
|
|
|
| — |
| |||||||
Successor accumulated earnings (deficit) |
| (8,442 | ) |
|
|
| — |
| |||||||
Predecessor common units, no units issued or outstanding at September 30, 2017 and 83,827,920 units issued and outstanding at December 31, 2016 |
| — |
|
|
|
| 99,489 |
| |||||||
Total stockholders'/partners' equity |
| 383,232 |
|
|
|
| 99,489 |
| |||||||
Commitments and contingencies (see Note 15) |
|
|
|
|
|
|
| ||||||||
Stockholders' equity: |
|
|
|
|
|
|
| ||||||||
Preferred stock, $0.0001 par value: 45,000,000 shares authorized; no shares issued and outstanding at March 31, 2019 and December 31, 2018, respectively |
| — |
|
|
| — |
| ||||||||
Warrants, 2,173,913 warrants issued and outstanding at March 31, 2019 and December 31, 2018, respectively |
| 4,788 |
|
|
| 4,788 |
| ||||||||
Common stock, $0.0001 par value: 300,000,000 shares authorized; 22,258,450 and 22,181,881 shares issued and outstanding at March 31, 2019 and December 31, 2018, respectively |
| 3 |
|
|
| 3 |
| ||||||||
Additional paid-in capital |
| 356,288 |
|
|
| 355,872 |
| ||||||||
Accumulated earnings (deficit) |
| 24,418 |
|
|
| 55,895 |
| ||||||||
Total stockholders' equity |
| 385,497 |
|
|
| 416,558 |
| ||||||||
Total liabilities and equity | $ | 951,351 |
|
|
| $ | 1,973,254 |
| $ | 796,183 |
|
| $ | 836,843 |
|
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(In thousands, except per shares/unitshare amounts)
| Successor |
|
|
| Predecessor |
| |||||||||
| Three Months |
|
|
| Three Months |
| |||||||||
| Ended |
|
|
| Ended |
| For the Three Months Ended |
| |||||||
| September 30, |
|
|
| September 30, |
| March 31, |
| |||||||
| 2017 |
|
|
| 2016 |
| 2019 |
|
| 2018 |
| ||||
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales | $ | 75,534 |
|
|
| $ | 74,222 |
| $ | 65,067 |
|
| $ | 87,847 |
|
Other revenues |
| 55 |
|
|
|
| — |
|
| 88 |
|
|
| 85 |
|
Total revenues |
| 75,589 |
|
|
|
| 74,222 |
|
| 65,155 |
|
|
| 87,932 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
| 29,119 |
|
|
|
| 31,575 |
|
| 28,910 |
|
|
| 29,570 |
|
Gathering, processing, and transportation |
| 7,077 |
|
|
|
| 8,519 |
| |||||||
Gathering, processing and transportation |
| 4,657 |
|
|
| 5,600 |
| ||||||||
Exploration |
| 4 |
|
|
|
| 12 |
|
| 15 |
|
|
| 34 |
|
Taxes other than income |
| 4,214 |
|
|
|
| 3,945 |
|
| 4,409 |
|
|
| 5,037 |
|
Depreciation, depletion, and amortization |
| 13,467 |
|
|
|
| 43,219 |
| |||||||
Impairment of proved oil and natural gas properties |
| — |
|
|
|
| — |
| |||||||
Depreciation, depletion and amortization |
| 11,166 |
|
|
| 12,958 |
| ||||||||
General and administrative expense |
| 11,097 |
|
|
|
| 12,605 |
|
| 9,308 |
|
|
| 10,657 |
|
Accretion of asset retirement obligations |
| 1,665 |
|
|
|
| 2,383 |
|
| 1,311 |
|
|
| 1,718 |
|
(Gain) loss on commodity derivative instruments |
| 14,217 |
|
|
|
| (21,938 | ) |
| 32,487 |
|
|
| 10,456 |
|
(Gain) loss on sale of properties |
| — |
|
|
|
| 60 |
|
| — |
|
|
| 2,373 |
|
Other, net |
| 772 |
|
|
|
| 178 |
|
| 143 |
|
|
| — |
|
Total costs and expenses |
| 81,632 |
|
|
|
| 80,558 |
|
| 92,406 |
|
|
| 78,403 |
|
Operating income (loss) |
| (6,043 | ) |
|
|
| (6,336 | ) |
| (27,251 | ) |
|
| 9,529 |
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net |
| (5,808 | ) |
|
|
| (27,209 | ) |
| (4,089 | ) |
|
| (5,772 | ) |
Other income (expense) |
| — |
|
|
|
| 6 |
| |||||||
Gain on extinguishment of debt |
| — |
|
|
|
| 673 |
| |||||||
Total other income (expense) |
| (5,808 | ) |
|
|
| (26,530 | ) |
| (4,089 | ) |
|
| (5,772 | ) |
Income (loss) before reorganization items, net and income taxes |
| (11,851 | ) |
|
|
| (32,866 | ) |
| (31,340 | ) |
|
| 3,757 |
|
Reorganization items, net |
| (33 | ) |
|
|
| — |
|
| (187 | ) |
|
| (518 | ) |
Income tax benefit (expense) |
| 4,348 |
|
|
|
| — |
|
| 50 |
|
|
| — |
|
Net income (loss) |
| (7,536 | ) |
|
|
| (32,866 | ) |
| (31,477 | ) |
|
| 3,239 |
|
Net income (loss) attributable to Successor/Predecessor | $ | (7,536 | ) |
|
| $ | (32,866 | ) | |||||||
Net (income) loss allocated to participating restricted stockholders |
| — |
|
|
| (83 | ) | ||||||||
Net income (loss) attributable to common stockholders | $ | (31,477 | ) |
| $ | 3,156 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor/Predecessor interest in net income (loss): |
|
|
|
|
|
|
|
| |||||||
Net income (loss) attributable to Successor/Predecessor | $ | (7,536 | ) |
|
| $ | (32,866 | ) | |||||||
Net (income) loss allocated to Predecessor's general partner |
| — |
|
|
|
| — |
| |||||||
Net (income) allocated to participating restricted stockholders |
| — |
|
|
|
| — |
| |||||||
Net income (loss) available to common stockholders/limited partners | $ | (7,536 | ) |
|
| $ | (32,866 | ) | |||||||
|
|
|
|
|
|
|
|
| |||||||
Earnings per share/unit: (See Note 11) |
|
|
|
|
|
|
|
| |||||||
Basic and diluted earnings per share/unit | $ | (0.30 | ) |
|
| $ | (0.39 | ) | |||||||
Weighted average common shares/units outstanding: |
|
|
|
|
|
|
|
| |||||||
Earnings per share: (See Note 10) |
|
|
|
|
|
|
| ||||||||
Basic and diluted earnings per share | $ | (1.42 | ) |
| $ | 0.13 |
| ||||||||
Weighted average common shares outstanding: |
|
|
|
|
|
|
| ||||||||
Basic and diluted |
| 25,000 |
|
|
|
| 83,621 |
|
| 22,179 |
|
|
| 25,000 |
|
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(In thousands, except per shares/unit amounts)
| Successor |
|
|
| Predecessor |
| ||||||
| Period from |
|
|
|
|
|
|
|
|
|
| |
| May 5, 2017 |
|
|
| Period from |
|
| Nine Months |
| |||
| through |
|
|
| January 1, |
|
| Ended |
| |||
| September 30, |
|
|
| 2017 through |
|
| September 30, |
| |||
| 2017 |
|
|
| May 4, 2017 |
|
| 2016 |
| |||
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales | $ | 117,762 |
|
|
| $ | 108,970 |
|
| $ | 202,625 |
|
Other revenues |
| 222 |
|
|
|
| 231 |
|
|
| 529 |
|
Total revenues |
| 117,984 |
|
|
|
| 109,201 |
|
|
| 203,154 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
| 47,961 |
|
|
|
| 35,568 |
|
|
| 96,625 |
|
Gathering, processing, and transportation |
| 11,191 |
|
|
|
| 10,772 |
|
|
| 26,551 |
|
Exploration |
| 11 |
|
|
|
| 21 |
|
|
| 149 |
|
Taxes other than income |
| 6,147 |
|
|
|
| 5,187 |
|
|
| 11,438 |
|
Depreciation, depletion, and amortization |
| 21,818 |
|
|
|
| 37,717 |
|
|
| 132,061 |
|
Impairment of proved oil and natural gas properties |
| — |
|
|
|
| — |
|
|
| 8,342 |
|
General and administrative expense |
| 18,479 |
|
|
|
| 31,606 |
|
|
| 41,375 |
|
Accretion of asset retirement obligations |
| 2,692 |
|
|
|
| 3,407 |
|
|
| 7,802 |
|
(Gain) loss on commodity derivative instruments |
| 12,302 |
|
|
|
| (23,076 | ) |
|
| 50,897 |
|
(Gain) loss on sale of properties |
| — |
|
|
|
| — |
|
|
| (3,575 | ) |
Other, net |
| 772 |
|
|
|
| 36 |
|
|
| 245 |
|
Total costs and expenses |
| 121,373 |
|
|
|
| 101,238 |
|
|
| 371,910 |
|
Operating income (loss) |
| (3,389 | ) |
|
|
| 7,963 |
|
|
| (168,756 | ) |
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net |
| (9,605 | ) |
|
|
| (10,243 | ) |
|
| (91,904 | ) |
Other income (expense) |
| (6 | ) |
|
|
| 8 |
|
|
| 6 |
|
Gain on extinguishment of debt |
| — |
|
|
|
| — |
|
|
| 42,337 |
|
Total other income (expense) |
| (9,611 | ) |
|
|
| (10,235 | ) |
|
| (49,561 | ) |
Income (loss) before reorganization items, net and income taxes |
| (13,000 | ) |
|
|
| (2,272 | ) |
|
| (218,317 | ) |
Reorganization items, net |
| (382 | ) |
|
|
| (88,774 | ) |
|
| — |
|
Income tax benefit (expense) |
| 4,940 |
|
|
|
| 91 |
|
|
| (196 | ) |
Net income (loss) |
| (8,442 | ) |
|
|
| (90,955 | ) |
|
| (218,513 | ) |
Net income (loss) attributable to Successor/Predecessor | $ | (8,442 | ) |
|
| $ | (90,955 | ) |
| $ | (218,513 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor/Predecessor interest in net income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Successor/Predecessor | $ | (8,442 | ) |
|
| $ | (90,955 | ) |
| $ | (218,513 | ) |
Net (income) loss allocated to Predecessor's general partner |
| — |
|
|
|
| — |
|
|
| 168 |
|
Net (income) allocated to participating restricted stockholders |
| — |
|
|
|
| — |
|
|
| — |
|
Net income (loss) available to common stockholders/limited partners | $ | (8,442 | ) |
|
| $ | (90,955 | ) |
| $ | (218,345 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share/unit: (See Note 11) |
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted earnings per share/unit | $ | (0.34 | ) |
|
| $ | (1.09 | ) |
| $ | (2.62 | ) |
Weighted average common shares/units outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted |
| 25,000 |
|
|
|
| 83,807 |
|
|
| 83,189 |
|
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(In thousands)
| Successor |
|
|
| Predecessor |
| |||||||||||||
| Period from |
|
|
| Period from |
|
|
|
|
| |||||||||
| May 5, 2017 |
|
|
| January 1, 2017 |
|
| Nine Months |
| For the Three Months Ended |
| ||||||||
| through |
|
|
| through |
|
| Ended |
| March 31, |
| ||||||||
| September 30, 2017 |
|
|
| May 4, 2017 |
|
| September 30, 2016 |
| 2019 |
|
| 2018 |
| |||||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) | $ | (8,442 | ) |
|
| $ | (90,955 | ) |
| $ | (218,513 | ) | $ | (31,477 | ) |
| $ | 3,239 |
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, and amortization |
| 21,818 |
|
|
|
| 37,717 |
|
|
| 132,061 |
| |||||||
Impairment of proved oil and natural gas properties |
| — |
|
|
|
| — |
|
|
| 8,342 |
| |||||||
Depreciation, depletion and amortization |
| 11,166 |
|
|
| 12,958 |
| ||||||||||||
(Gain) loss on derivative instruments |
| 12,302 |
|
|
|
| (23,076 | ) |
|
| 54,991 |
|
| 32,393 |
|
|
| 10,456 |
|
Cash settlements (paid) received on expired derivative instruments |
| 21,277 |
|
|
|
| 15,895 |
|
|
| 183,221 |
|
| (1,277 | ) |
|
| 4,876 |
|
Cash settlements (paid) on terminated derivatives |
| — |
|
|
|
| 94,146 |
|
|
| 39,299 |
| |||||||
Bad debt expense |
| — |
|
|
|
| — |
|
|
| 1,601 |
|
| 101 |
|
|
| — |
|
Deferred income tax expense (benefit) |
| (5,837 | ) |
|
|
| (74 | ) |
|
| 129 |
| |||||||
Amortization of deferred financing costs |
| 916 |
|
|
|
| — |
|
|
| 3,862 |
|
| 308 |
|
|
| 541 |
|
Accretion of senior notes discount |
| — |
|
|
|
| — |
|
|
| 1,769 |
| |||||||
Gain on extinguishment of debt |
| — |
|
|
|
| — |
|
|
| (42,337 | ) | |||||||
Accretion of asset retirement obligations |
| 2,692 |
|
|
|
| 3,407 |
|
|
| 7,802 |
|
| 1,311 |
|
|
| 1,718 |
|
Gain on sale of properties |
| — |
|
|
|
| — |
|
|
| (3,575 | ) | |||||||
Share/unit-based compensation (see Note 12) |
| 1,543 |
|
|
|
| 3,667 |
|
|
| 7,370 |
| |||||||
(Gain) loss on sale of properties |
| — |
|
|
| 2,373 |
| ||||||||||||
Share-based compensation (see Note 11) |
| 1,443 |
|
|
| 1,176 |
| ||||||||||||
Settlement of asset retirement obligations |
| (174 | ) |
|
|
| (164 | ) |
|
| (1,099 | ) |
| (162 | ) |
|
| — |
|
Reorganization items, net |
| — |
|
|
|
| 68,356 |
|
|
| — |
| |||||||
Other |
| — |
|
|
|
| 56 |
|
|
| — |
| |||||||
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
| 1,182 |
|
|
|
| 1,024 |
|
|
| 20,873 |
|
| 4,326 |
|
|
| 2,839 |
|
Prepaid expenses and other assets |
| 5,683 |
|
|
|
| 735 |
|
|
| (833 | ) |
| (6,856 | ) |
|
| (115 | ) |
Payables and accrued liabilities |
| (2,570 | ) |
|
|
| 15,030 |
|
|
| 931 |
|
| (537 | ) |
|
| 2,086 |
|
Restricted cash |
| 7,561 |
|
|
|
| (7,561 | ) |
|
| — |
| |||||||
Other |
| (77 | ) |
|
|
| (266 | ) |
|
| 3,253 |
|
| 61 |
|
|
| — |
|
Net cash provided by operating activities |
| 57,874 |
|
|
|
| 117,937 |
|
|
| 199,147 |
|
| 10,800 |
|
|
| 42,147 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and gas properties |
| (27,661 | ) |
|
|
| (6,211 | ) |
|
| (50,534 | ) |
| (10,370 | ) |
|
| (13,098 | ) |
Additions to other property and equipment |
| (48 | ) |
|
|
| (76 | ) |
|
| (7,611 | ) |
| (62 | ) |
|
| — |
|
Additions to restricted investments |
| (310 | ) |
|
|
| (209 | ) |
|
| (5,642 | ) |
| (68 | ) |
|
| (186 | ) |
Proceeds from the sale of oil and natural gas properties, net of cash and cash equivalents sold |
| — |
|
|
|
| — |
|
|
| 54,724 |
| |||||||
Net cash used in investing activities |
| (28,019 | ) |
|
|
| (6,496 | ) |
|
| (9,063 | ) |
| (10,500 | ) |
|
| (13,284 | ) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Advances on revolving credit facilities |
| — |
|
|
|
| 16,600 |
|
|
| 144,000 |
|
| — |
|
|
| 5,000 |
|
Payments on revolving credit facilities |
| (27,000 | ) |
|
|
| (98,252 | ) |
|
| (266,000 | ) |
| (24,000 | ) |
|
| (34,000 | ) |
Deferred financing costs |
| (184 | ) |
|
|
| (8,575 | ) |
|
| (1,350 | ) |
| (101 | ) |
|
| — |
|
Payment to holders of the Notes |
| (8,193 | ) |
|
|
| (16,446 | ) |
|
| — |
| |||||||
Payment to Predecessor common unitholders |
| (1,250 | ) |
|
|
| — |
|
|
| — |
| |||||||
Contribution from management |
| 1,500 |
|
|
|
| — |
|
|
| — |
| |||||||
Repurchase of senior notes |
| — |
|
|
|
| — |
|
|
| (41,261 | ) | |||||||
Contributions related to sale of assets to NGP affiliate |
| — |
|
|
|
| — |
|
|
| 26 |
| |||||||
Transfer of operating subsidiary from Memorial Resource |
| — |
|
|
|
| — |
|
|
| 2,363 |
| |||||||
Proceeds from the issuance of Predecessor common units |
| — |
|
|
|
| — |
|
|
| 2,385 |
| |||||||
Costs incurred in conjunction with issuance of Predecessor common units |
| — |
|
|
|
| — |
|
|
| (312 | ) | |||||||
Distributions to partners |
| — |
|
|
|
| — |
|
|
| (13,300 | ) | |||||||
Acquisition of Predecessor's general partner (see Note 1) |
| — |
|
|
|
| — |
|
|
| (750 | ) | |||||||
Acquisition of incentive distribution rights from NGP (see Note 1) |
| — |
|
|
|
| — |
|
|
| (50 | ) | |||||||
Restricted units returned to plan |
| — |
|
|
|
| (10 | ) |
|
| (589 | ) | |||||||
Costs incurred in conjunction with tender offer |
| (107 | ) |
|
| — |
| ||||||||||||
Common stock repurchased and retired under the share repurchase program |
| (920 | ) |
|
| — |
| ||||||||||||
Other |
| (9 | ) |
|
|
| 9 |
|
|
| — |
|
| — |
|
|
| (213 | ) |
Net cash used in financing activities |
| (35,136 | ) |
|
|
| (106,674 | ) |
|
| (174,838 | ) |
| (25,128 | ) |
|
| (29,213 | ) |
Net change in cash and cash equivalents |
| (5,281 | ) |
|
|
| 4,767 |
|
|
| 15,246 |
| |||||||
Cash and cash equivalents, beginning of period |
| 20,140 |
|
|
|
| 15,373 |
|
|
| 599 |
| |||||||
Cash and cash equivalents, end of period | $ | 14,859 |
|
|
| $ | 20,140 |
|
| $ | 15,845 |
| |||||||
Net change in cash, cash equivalents and restricted cash |
| (24,828 | ) |
|
| (350 | ) | ||||||||||||
Cash, cash equivalents and restricted cash, beginning of period |
| 50,029 |
|
|
| 6,392 |
| ||||||||||||
Cash, cash equivalents and restricted cash, end of period | $ | 25,201 |
|
| $ | 6,042 |
|
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY (PREDECESSOR)
(In thousands)
| Predecessor Partner's Equity |
| |
| Limited Partners Common Units |
| |
Balance at December 31, 2016 (Predecessor) | $ | 99,489 |
|
Net income (loss) |
| (90,955 | ) |
Cancellation and amortization of unit-based awards |
| 3,713 |
|
Restricted units repurchased and other |
| (2 | ) |
Issuance of common stock to Predecessor common unitholders |
| (7,707 | ) |
Issuance of warrants to Predecessor common unitholders |
| (4,788 | ) |
Contribution from management |
| 1,500 |
|
Settlement with Predecessor common unitholders |
| (1,250 | ) |
Balance at May 4, 2017 (Predecessor) |
| — |
|
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY (SUCCESSOR)
(In thousands)
| Stockholders' Equity |
|
|
|
|
| |||||||||||||
| Common Stock |
|
| Warrants |
|
| Additional Paid-in Capital |
|
| Accumulated Earnings (Deficit) |
|
| Total |
| |||||
Issuance of Successor common stock to holders of the Notes | $ | 3 |
|
| $ | — |
|
| $ | 377,642 |
|
| $ | — |
|
| $ | 377,645 |
|
Issuance of Successor warrants to Predecessor common unitholders |
| — |
|
|
| 4,788 |
|
|
| — |
|
|
| — |
|
|
| 4,788 |
|
Issuance of Successor common stock to Predecessor common unitholders |
| — |
|
|
| — |
|
|
| 7,707 |
|
|
| — |
|
|
| 7,707 |
|
Balance at May 5, 2017 (Successor) |
| 3 |
|
|
| 4,788 |
|
|
| 385,349 |
|
|
| — |
|
|
| 390,140 |
|
Net income (loss) |
| — |
|
|
| — |
|
|
| — |
|
|
| (8,442 | ) |
|
| (8,442 | ) |
Share-based compensation expense |
| — |
|
|
| — |
|
|
| 1,543 |
|
|
| — |
|
|
| 1,543 |
|
Other |
| — |
|
|
| — |
|
|
| (9 | ) |
|
| — |
|
|
| (9 | ) |
Balance at September 30, 2017 (Successor) | $ | 3 |
|
| $ | 4,788 |
|
| $ | 386,883 |
|
| $ | (8,442 | ) |
| $ | 383,232 |
|
| Stockholders' Equity |
|
|
|
|
| |||||||||||||
| Common Stock |
|
| Warrants |
|
| Additional Paid-in Capital |
|
| Accumulated Earnings (Deficit) |
|
| Total |
| |||||
Balance at December 31, 2017 | $ | 3 |
|
| $ | 4,788 |
|
| $ | 387,856 |
|
| $ | 1,286 |
|
| $ | 393,933 |
|
Net income (loss) |
| — |
|
|
| — |
|
|
| — |
|
|
| 3,239 |
|
|
| 3,239 |
|
Share-based compensation expense |
| — |
|
|
| — |
|
|
| 1,176 |
|
|
| — |
|
|
| 1,176 |
|
Other |
| — |
|
|
| — |
|
|
| (208 | ) |
|
| — |
|
|
| (208 | ) |
Balance at March 31, 2018 | $ | 3 |
|
| $ | 4,788 |
|
| $ | 388,824 |
|
| $ | 4,525 |
|
| $ | 398,140 |
|
| Stockholders' Equity |
|
|
|
|
| |||||||||||||
| Common Stock |
|
| Warrants |
|
| Additional Paid-in Capital |
|
| Accumulated Earnings (Deficit) |
|
| Total |
| |||||
Balance at December 31, 2018 | $ | 3 |
|
| $ | 4,788 |
|
| $ | 355,872 |
|
| $ | 55,895 |
|
| $ | 416,558 |
|
Net income (loss) |
| — |
|
|
| — |
|
|
| — |
|
|
| (31,477 | ) |
|
| (31,477 | ) |
Costs incurred in conjunction with tender offer |
| — |
|
|
| — |
|
|
| (107 | ) |
|
| — |
|
|
| (107 | ) |
Share-based compensation expense |
| — |
|
|
| — |
|
|
| 1,443 |
|
|
| — |
|
|
| 1,443 |
|
Common stock repurchased and retired under the share repurchase program |
| — |
|
|
| — |
|
|
| (920 | ) |
|
| — |
|
|
| (920 | ) |
Restricted shares repurchased |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Other |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Balance at March 31, 2019 | $ | 3 |
|
| $ | 4,788 |
|
| $ | 356,288 |
|
| $ | 24,418 |
|
| $ | 385,497 |
|
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
1110
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization and Basis of Presentation
General
When referring to Amplify Energy Corp. (formerly known as Memorial Production Partners LP and also referred to as “Successor,” “Amplify Energy,” or the “Company”), the intent is to refer to Amplify Energy, a newly formed Delaware corporation, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Amplify Energy is the successor reporting company of Memorial Production Partners LP (“MEMP”) pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended. When referring to the “Predecessor” or the “Company” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to MEMP, the predecessor that was dissolved following the effective date of the Plan (as defined below) and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.
We operate in one reportable segment engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as the economic environments are not different within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Wyoming andthe Rockies, federal waters offshore Southern California.California, East Texas / North Louisiana and South Texas. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Company’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells.
Unless the context requires otherwise, references to: (i) our “Predecessor’s general partner” and “MEMP GP” refer to Memorial Production Partners GP LLC, our Predecessor’s general partner, which was dissolved following the effective date of the Plan; (ii) “Memorial Resource” refers collectively to Memorial Resource Development Corp., the former owner of our Predecessor’s general partner, and its subsidiaries; (iii) the “Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively controlled MRD Holdco LLC; (iv) “OLLC” refers to Amplify Energy Operating LLC, formerly known as Memorial Production Operating LLC, our wholly owned subsidiary through which we operate our properties; (v) “Finance Corp.” refers to Memorial Production Finance Corporation, our Predecessor’s wholly owned subsidiary, whose activities were limited to co-issuing our debt securities and engaging in other activities incidental thereto and which was dissolved following the effective date of the Plan; and (vi) “NGP” refers to Natural Gas Partners.
On April 27, 2016, we entered into an agreement pursuant to which the Predecessor agreed to acquire, among other things, all of the equity interests in our Predecessor’s general partner, MEMP GP, from Memorial Resource (the “MEMP GP Acquisition”) for cash consideration of approximately $0.8 million. MEMP GP held an approximate 0.1% general partner interest and 50% of the incentive distribution rights (“IDRs”) in us. In conjunction with the MEMP GP Acquisition, on April 27, 2016, we also entered into an agreement with an NGP affiliate pursuant to which we agreed to acquire the other 50% of the IDRs. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition.
In connection with the closing of the transactions on June 1, 2016, our Predecessor’s partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Predecessor held by MEMP GP into a non-economic general partner interest, (ii) cancel the IDRs and (iii) provide that the limited partners of the Predecessor will have the ability to elect the members of MEMP GP’s board of directors. In addition, we terminated the Predecessor’s Omnibus Agreement under which Memorial Resource provided management, administrative and operations personnel to us and our Predecessor’s general partner, and we entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. See Note 13 for additional information regarding the MEMP GP Acquisition and the transition services agreement.
Basis of Presentation
Our Unaudited Condensed Consolidated Financial Statements included herein have been prepared pursuant to the rules and guidelines of the Securities and Exchange Commission (the “SEC”). 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. In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate, and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the SEC.
The inclusion of MEMP GP in our consolidated financial statements was effective June 1, 2016 due to the MEMP GP Acquisition. All material intercompany transactions and balances have been eliminated in preparation of our consolidated financial statements.
12
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
On January 16, 2017, MEMP and certain of its subsidiaries (collectively with MEMP, the “Debtors”) filed voluntary petitions (the cases commenced thereby, the “Chapter 11 proceedings”) under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code” or “Chapter 11”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”). The Debtors operated their business as “debtors-in-possession” under the Bankruptcy Code for the period from January 16, 2017 through May 4, 2017.
The Unaudited Condensed Consolidated Financial Statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that were realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s condensed statements of consolidated operations.
Comparability of Financial Statements to Prior Periods
As discussed in further detail in Note 3 below, we have adopted and applied the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”). Accordingly, our Unaudited Condensed Statements of Consolidated Financial StatementsOperations.
All material intercompany transactions and Notes after May 4, 2017, are not comparable to the Unaudited Condensed Consolidated Financial Statements and Notes prior to that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Unaudited Condensed Consolidated Financial Statements and Notes as the “Successor” for periods subsequent to May 4, 2017 and “Predecessor” for periods prior to May 5, 2017. Furthermore, our Unaudited Condensed Consolidated Financial Statements and Notesbalances have been presentedeliminated in preparation of our consolidated financial statements.
Beginning in 2019, the Company has elected to change its reporting convention from natural gas equivalent (Mcfe) to barrels of oil equivalent (Boe). The change in presentation reflects our liquids-weighted production and reserve profile with a “black line” divisionbalanced approach to delineate the lackdevelopment of comparability between the Predecessorour oil and Successor.natural gas asset portfolio. The Company’s proved reserves as of year-end 2018 were 50% crude oil, 15% natural gas liquids and 35% natural gas.
Use of Estimates
The preparation of the accompanying Unaudited Condensed Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.
Note 2. Emergence from Voluntary Reorganization under Chapter 11
On January 16, 2017 (the “Petition Date”), the Debtors filed voluntary petitions under the Bankruptcy Code in the Bankruptcy Court to pursue a Joint Chapter 11 Plan of Reorganization for the Debtors. The Debtors’ Chapter 11 proceedings were jointly administered under the caption In re Memorial Production Partners LP, et al. (Case No. 17-30262).
On April 14, 2017, the Bankruptcy Court entered an order (the “Confirmation Order”) approving the Second Amended Joint Plan of Reorganization of Memorial Production Partners LP and its affiliated Debtors, dated April 13, 2017 (as amended and supplemented, the “Plan”).
On May 4, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the Plan, the Plan became effective in accordance with its terms and the Company emerged from bankruptcy. Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession from January 16, 2017 through May 4, 2017. As such, certain aspects of the Chapter 11 proceedings and related matters are described below in order to provide context to the Company’s financial condition and results of operations for the period presented.
Plan of Reorganization
In accordance with the Plan, on the Effective Date:
The Successor issued (i) 25,000,000 new shares (the “New Common Shares”) of its common stock, par value $0.0001 per share (“common stock”); and (ii) warrants (the “Warrants”) to purchase up to 2,173,913 shares of the Company’s common stock exercisable for a five-year period commencing on the Effective Date entitling their holders upon exercise thereof, on a pro rata basis, to 8% of the total issued and outstanding common shares (including common shares as of the Effective Date issuable upon full exercise of the Warrants, but excluding any common shares issuable under the Management Incentive Plan (the “MIP”)), at a per share exercise price of $42.60.
13
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The 7.625% senior notes due May 2021 (“2021 Senior Notes”) and 6.875% senior notes due August 2022 (“2022 Senior Notes” and collectively, the “Notes”) were cancelled and the Predecessor’s liability thereunder discharged, and the holders of the Notes received (directly or indirectly) their pro rata share of New Common Shares representing, in the aggregate, 98% of the New Common Shares on the Effective Date (subject to dilution by the MIP and the common shares issuable upon exercise of the Warrants). Additionally, the holders of the Notes received their pro rata share of a $24.6 million cash distribution.
The Predecessor’s common units were cancelled, and each common unitholder received its pro rata share of: (i) 2% of the New Common Shares, (ii) the Warrants, and (iii) cash in an aggregate amount of approximately $1.3 million.
The holders of administrative expense claims, priority tax claims, other priority claims and general unsecured creditors of the Predecessor received in exchange for their claims payment in full in cash or otherwise had their rights unimpaired under Title 11 of the United States Code.
The Successor entered into a stockholders agreement (the “Stockholders Agreement”) with certain parties pursuant to which the Successor agreed to, at the direction of such stockholders, use commercially reasonable efforts to effect the sale of their common stock.
The Successor entered into a registration rights agreement (the “Registration Rights Agreement”) with certain parties pursuant to which the Successor agreed to, among other things, file a registration statement with the SEC within 90 days of the receipt of a request from the stockholders party thereto covering the offer and resale of the common stock held by such stockholders.
The Company’s MIP became effective, such that an aggregate of 2,322,404 shares of the Company’s common stock are available for grant pursuant to awards under the MIP.
The terms of the Predecessor’s general partner’s board of directors automatically expired on the Effective Date. The Successor formed a new seven-member board of directors consisting of the President and Chief Executive Officer, one director of the Predecessor, and five new members designated by certain parties to the plan support agreement.
Note 3. Fresh Start Accounting
Upon emergence from the Chapter 11 proceedings on May 4, 2017, we adopted fresh start accounting as required by GAAP. We met the requirements of fresh start accounting, which include: (i) the holders of the Predecessor’s voting common units immediately prior to the Effective Date received less than 50% of the voting shares of the Company and (ii) the reorganization value of our assets immediately prior to the Effective Date was less than the post-petition liabilities and allowed claims.
Reorganization Value
The Successor’s enterprise value, as approved by the Bankruptcy Court, was estimated to be within a range of $700 million to $900 million, with a midpoint estimate of approximately $800 million. Enterprise value represents the estimated fair value of a company’s interest-bearing debt and its shareholders’ equity. Based on the estimates and assumptions utilized in our fresh start accounting process, we estimated the Successor’s enterprise value to be approximately $800 million before the consideration of cash and cash equivalents on hand at the Effective Date. Reorganization value represents the fair value of the Successor’s total assets prior to the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The reorganization value, which was derived from the Successor’s enterprise value, was allocated to our individual assets based on their estimated fair values.
14
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table is a reconciliation of the enterprise value to the reorganization value of the Successor assets at the Effective Date (in thousands):
Enterprise value | $ | 800,000 |
|
Plus: Cash and cash equivalents |
| 20,140 |
|
Plus: Other working capital liabilities |
| 63,817 |
|
Plus: Other long-term liabilities |
| 97,470 |
|
Reorganization value of Successor assets | $ | 981,427 |
|
Our assets consist primarily of producing oil and natural gas properties. The fair values of proved and unproved oil and natural gas properties were estimated using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with NYMEX forward curve pricing and is adjusted for estimated location and quality differentials, as well as other factors as necessary that the Company’s management believes will impact realizable prices. The fair value of support equipment and facilities were estimated using a cost approach, based on current replacement costs of the assets less depreciation based on the estimated economic useful lives of the assets and age of the assets.
See below under the caption “Fresh Start Adjustments” for additional information regarding assumptions used in the valuation of the Company’s various other significant assets and liabilities.
15
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidated Balance Sheet
The adjustments included in the following condensed consolidated balance sheet reflect the effect of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value and other required accounting adjustments resulting from the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine the fair values and significant assumptions.
| As of May 4, 2017 |
| ||||||||||||||
|
|
|
|
| Reorganization |
|
|
| Fresh Start |
|
|
|
|
| ||
| Predecessor |
|
| Adjustments (1) |
|
|
| Adjustments |
|
| Successor |
| ||||
| (In thousands) |
| ||||||||||||||
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents | $ | 83,050 |
|
| $ | (62,910 | ) |
| (2) | $ | — |
|
| $ | 20,140 |
|
Restricted cash |
| — |
|
|
| 7,411 |
|
| (3) |
| — |
|
|
| 7,411 |
|
Accounts receivable |
| 33,560 |
|
|
| — |
|
|
|
| — |
|
|
| 33,560 |
|
Short-term derivative instruments |
| 51,329 |
|
|
| — |
|
|
|
| — |
|
|
| 51,329 |
|
Prepaid expenses and other current assets |
| 10,229 |
|
|
| 675 |
|
| (4) |
| — |
|
|
| 10,904 |
|
Total current assets |
| 178,168 |
|
|
| (54,824 | ) |
|
|
| — |
|
|
| 123,344 |
|
Property and equipment, net |
| 1,551,500 |
|
|
| — |
|
|
|
| (894,164 | ) | (11) |
| 657,336 |
|
Long-term derivative instruments |
| 33,800 |
|
|
| — |
|
|
|
| — |
|
|
| 33,800 |
|
Restricted investments |
| 156,443 |
|
|
| — |
|
|
|
| — |
|
|
| 156,443 |
|
Other long-term assets |
| 1,929 |
|
|
| 8,575 |
|
| (5) |
| — |
|
|
| 10,504 |
|
Total assets | $ | 1,921,840 |
|
| $ | (46,249 | ) |
|
| $ | (894,164 | ) |
| $ | 981,427 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable | $ | 1,501 |
|
| $ | 1,389 |
|
| (6) | $ | — |
|
| $ | 2,890 |
|
Revenues payable |
| 22,747 |
|
|
| — |
|
|
|
| — |
|
|
| 22,747 |
|
Accrued liabilities |
| 36,954 |
|
|
| 2,939 |
|
| (7) |
| (1,713 | ) | (12) |
| 38,180 |
|
Current portion of long-term debt |
| 454,799 |
|
|
| (454,799 | ) |
| (8) |
| — |
|
|
| — |
|
Total current liabilities |
| 516,001 |
|
|
| (450,471 | ) |
|
|
| (1,713 | ) |
|
| 63,817 |
|
Liabilities subject to compromise |
| 1,162,437 |
|
|
| (1,162,437 | ) |
| (9) |
| — |
|
|
| — |
|
Long-term debt |
| — |
|
|
| 430,000 |
|
| (8) |
| — |
|
|
| 430,000 |
|
Asset retirement obligations |
| 158,114 |
|
|
| — |
|
|
|
| (62,928 | ) | (13) |
| 95,186 |
|
Deferred tax liabilities |
| 2,206 |
|
|
| — |
|
|
|
| — |
|
|
| 2,206 |
|
Other long-term liabilities |
| 2,481 |
|
|
| — |
|
|
|
| (2,403 | ) | (12) |
| 78 |
|
Total liabilities |
| 1,841,239 |
|
|
| (1,182,908 | ) |
|
|
| (67,044 | ) |
|
| 591,287 |
|
Commitments and contingencies (see Note 14) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'/partners' equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor common units |
| 80,601 |
|
|
| (80,601 | ) |
| (10) |
| — |
|
|
| — |
|
Successor warrants |
| — |
|
|
| 4,788 |
|
| (10) |
| — |
|
|
| 4,788 |
|
Successor common stock |
| — |
|
|
| 3 |
|
| (10) |
| — |
|
|
| 3 |
|
Successor additional paid-in capital |
| — |
|
|
| 1,212,469 |
|
| (10) |
| (827,120 | ) | (14) |
| 385,349 |
|
Total stockholders'/ partners' equity |
| 80,601 |
|
|
| 1,136,659 |
|
|
|
| (827,120 | ) |
|
| 390,140 |
|
Total liabilities and equity | $ | 1,921,840 |
|
| $ | (46,249 | ) |
|
| $ | (894,164 | ) |
| $ | 981,427 |
|
Reorganization Adjustments
|
|
16
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Payment on the Predecessor's revolving credit facility | $ | (24,799 | ) |
Payment to holders of the Notes (1) |
| (16,446 | ) |
Payment of fees related to Exit Credit Facility |
| (8,575 | ) |
Funding of the professional fees escrow account |
| (7,411 | ) |
Payment of professional fees |
| (4,295 | ) |
Other |
| (1,384 | ) |
Changes in cash and cash equivalents | $ | (62,910 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
Recognition of liability for settlement with holders of the Notes | $ | 8,193 |
|
Payment of professional fees |
| (4,295 | ) |
Recognition of contribution from management |
| (1,500 | ) |
Recognition of settlement with Predecessor common unitholders |
| 1,250 |
|
Other |
| (709 | ) |
Net increase in accrued liabilities due to reorganization items | $ | 2,939 |
|
|
|
|
|
Accounts payable | $ | 1,389 |
|
Accrued interest payable |
| 49,796 |
|
Debt |
| 1,111,252 |
|
Total liabilities subject to compromise of Predecessor |
| 1,162,437 |
|
Recognition of payables for general unsecured claims |
| (1,389 | ) |
Recognition of settlement with holders of the Notes |
| (24,639 | ) |
Issuance of common stock to holders of the Notes |
| (377,645 | ) |
Gain on settlement of liabilities subject to compromise | $ | 758,764 |
|
|
|
Issuance of common stock to holders of the Notes | $ | 377,645 |
|
Issuance of common stock to Predecessor common unitholders |
| 7,707 |
|
Cancellation of the Predecessor's units issued and outstanding |
| 80,601 |
|
Recognition on gain on settlement of liabilities subject to compromise |
| 758,764 |
|
Recognition of issuance of common stock to Predecessor common unitholders |
| (7,707 | ) |
Recognition of issuance of warrants to Predecessor common unitholders |
| (4,788 | ) |
Recognition of contribution from management |
| 1,500 |
|
Recognition of settlement with Predecessor common unitholders |
| (1,250 | ) |
Par value of common stock |
| (3 | ) |
Change in Successor additional paid-in capital |
| 1,212,469 |
|
Issuance of warrants to Predecessor common unitholders |
| 4,788 |
|
Par value of common stock |
| 3 |
|
Predecessor units issued and outstanding |
| (80,601 | ) |
Net increase in capital accounts | $ | 1,136,659 |
|
17
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
| Predecessor |
|
| Fresh Start Adjustments |
|
|
| Successor |
| |||
| (In thousands) |
| ||||||||||
Property and equipment at cost: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved oil and natural gas properties | $ | 3,124,137 |
|
| $ | (2,615,076 | ) |
|
| $ | 509,061 |
|
Support equipment and facilities |
| 199,463 |
|
|
| (101,883 | ) |
|
|
| 97,580 |
|
Unproved oil and natural gas properties |
| — |
|
|
| 44,688 |
|
|
|
| 44,688 |
|
Other |
| 15,420 |
|
|
| (9,413 | ) |
|
|
| 6,007 |
|
Property and equipment |
| 3,339,020 |
|
|
| (2,681,684 | ) |
|
|
| 657,336 |
|
Accumulated depreciation, depletion and impairment |
| (1,787,520 | ) |
|
| 1,787,520 |
|
|
|
| — |
|
Property and equipment, net | $ | 1,551,500 |
|
| $ | (894,164 | ) |
|
| $ | 657,336 |
|
|
|
|
|
|
|
Reorganization Items, Net
The Company has incurred significant costs associated with the reorganization. These costs, which are expensed as incurred, are expected to significantly affect the Company’s results of operations. Reorganization items, net represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date.
The following table summarizes the components of reorganization items, net included in the accompanying Unaudited Condensed Statements of Consolidated Operations (in thousands):
| Successor |
|
|
| Predecessor |
| ||||||
| Three Months |
|
| Period from |
|
|
| Period from |
| |||
| Ended |
|
| May 5, 2017 |
|
|
| January 1, |
| |||
| September 30, |
|
| through |
|
|
| 2017 through |
| |||
| 2017 |
|
| September 30, 2017 |
|
|
| May 4, 2017 |
| |||
Gain on settlement of liabilities subject to compromise | $ | — |
|
| $ | — |
|
|
| $ | 758,764 |
|
Fresh start valuation adjustments |
| — |
|
|
| — |
|
|
|
| (827,120 | ) |
Professional fees |
| — |
|
|
| (349 | ) |
|
|
| (19,824 | ) |
Other |
| (33 | ) |
|
| (33 | ) |
|
|
| (594 | ) |
Reorganization items, net | $ | (33 | ) |
| $ | (382 | ) |
|
| $ | (88,774 | ) |
Note 4.2. Summary of Significant Accounting Policies
A discussion of our significant accounting policies and estimates is included in our 20162018 Form 10-K.
Accrued Liabilities
Current accrued liabilities consisted of the following at the dates indicated (in thousands):
| Successor |
|
|
| Predecessor |
| ||
| September 30, |
|
|
| December 31, |
| ||
| 2017 |
|
|
| 2016 |
| ||
Accrued capital expenditures | $ | 10,513 |
|
|
| $ | 1,826 |
|
Accrued lease operating expense |
| 8,880 |
|
|
|
| 10,411 |
|
Accrued general and administrative expense |
| 5,561 |
|
|
|
| 3,040 |
|
Accrued ad valorem tax |
| 3,086 |
|
|
|
| 977 |
|
Accrued interest payable |
| 1,343 |
|
|
|
| 46,417 |
|
Asset retirement obligation |
| 941 |
|
|
|
| 789 |
|
Current income tax liability |
| 896 |
|
|
|
| — |
|
Other |
| 1,073 |
|
|
|
| 1,775 |
|
Accrued liabilities | $ | 32,293 |
|
|
| $ | 65,235 |
|
1811
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Supplemental Cash FlowsThe Company has incurred significant costs associated with the reorganization. Reorganization items, net, which are expensed as incurred, represent costs and income directly associated with the Chapter 11 proceedings since January 16, 2017, the petition date.
Supplemental cash flows forThe following table summarizes the periods presentedcomponents of reorganization items, net included in the accompanying Unaudited Condensed Statements of Consolidated Operations (in thousands):
| Successor |
|
|
| Predecessor |
| ||||||
| Period from |
|
|
| Period from |
|
| Nine Months |
| |||
| May 5, 2017 |
|
|
| January 1, 2017 |
|
| Ended |
| |||
| through |
|
|
| through |
|
| September 30, |
| |||
| September 30, 2017 |
|
|
| May 4, 2017 |
|
| 2016 |
| |||
Supplemental cash flows: |
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest, net of amounts capitalized | $ | 7,039 |
|
|
| $ | 6,598 |
|
| $ | 80,446 |
|
Cash paid for reorganization items, net |
| 7,333 |
|
|
|
| 11,999 |
|
|
| — |
|
Noncash investing and financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in capital expenditures in payables and accrued liabilities |
| 12,636 |
|
|
|
| 3,173 |
|
|
| (488 | ) |
(Increase) decrease in accounts receivable/payable related to divestitures |
| — |
|
|
|
| — |
|
|
| 856 |
|
Asset retirement obligation removal related to divestitures |
| — |
|
|
|
| — |
|
|
| (19,591 | ) |
| For the Three Months Ended |
| |||||
| March 31, |
| |||||
| 2019 |
|
| 2018 |
| ||
Professional fees |
| (26 | ) |
|
| (414 | ) |
Other |
| (161 | ) |
|
| (104 | ) |
Reorganization items, net | $ | (187 | ) |
| $ | (518 | ) |
Lease Recognition
New Accounting Pronouncements
Compensation —Stock Compensation. In May 2017, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance in the terms and conditions of a share-based payment award. The new guidance is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures.
Definition of a Business. In January 2017, the FASB issued an accounting standards update to clarify the definition of a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments provide a more robust framework to use in determining when a set of assets and activities is a business. The amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods. Early adoption is permitted and the guidance is to be applied on a prospective basis to purchases or disposals of a business or an asset. The Company is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures.
Statement of Cash Flows – Restricted Cash (a consensus of the FASB Emerging Issues Task Force). In November 2016, the FASB issued an accounting standards update to clarify the guidance on the classification and presentation of restricted cash in the statement of cash flows. The changes in restricted cash and restricted cash equivalents that result from the transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. The Company is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures.
Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued an accounting standards update to address eight specific cash flow issues with the objective of reducing the current and potential future diversity in practice. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Company is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures.
Leases.In February 2016, the FASB issued a revision to leaseguidance regarding the accounting guidance.for leases. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period.
19
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The Company is the lessee under various agreements for office space, compressors, equipment, vehicles and surface rentals (right of use assets) that are currently accounted for as operating leases. As a result, these new rules will increase reported assets and liabilities.
The Company will not early adopt this standard. The Company will applyapplied the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using athe modified retrospective approach with a cumulative impact to retained earnings in that period, and including several optional practical expedients relatedrelating to leases commenced before the effective date. The practical expedients the Company is currently evaluatingadopted are: (1) the impactoriginal correct assessment of these rulesa contract containing a lease will be accepted without further review on its financial statements and has startedall existing or expired contracts; (2) the assessment process by evaluating the population of leasesoriginal lease classification as an operating lease will convert as an operating lease under the revised definition. The quantitative impactsnew guidance; (3) initial direct costs for any existing leases will not be reassessed; (4) existing land easements or right of use agreements will continue under current accounting policy and only new agreements will be evaluated in the future; and (5) short-term leases for twelve months or less will not be evaluated under the guidance.
See Note 12 for additional information regarding the adoption of the new standard are dependent on the leases in place at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods.standard.
Revenue from Contracts with Customers. In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance and requires enhanced disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The guidance is effective for interim and annual reporting periods starting January 1, 2018, and early adoption is permitted. The Company will not early adopt the standard and plans to use a modified retrospective approach upon adoption with the cumulative effect of initial application recognized at the date of initial application subject to certain additional disclosures. The Company is currently evaluating its revenue streams and contracts under the revised standard to determine the impact it is expected to have on the consolidated financial statements and related disclosures.New Accounting Pronouncements
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.
Revenue from contracts with customers
The Company adopted Accounting Standard Update (ASU) No. 2014-09, revenue from contracts with customers (ASC 606), on January 1, 2018 using the modified retrospective method of adoption. Adoption of the ASU did not require an adjustment to the opening balance of equity and did not materially change the Company's amount and timing of revenues. The Company applied the ASU only to contracts that were not completed as of January 1, 2018.
The reclassification of certain fees between oil and natural gas sales and gathering, processing and transportation is the result of the Company’s assessment of the point in time at which its performance obligations under its commodity sales contracts are satisfied and control of the commodity is transferred to the customer. The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas, residue gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as gathering, processing and transportation and fees incurred after control transfers are included as a reduction to the transaction price. The transaction price at which revenue is recognized consists entirely of variable consideration based on quoted market prices less various fees and the quantity of volumes delivered.
Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at March 31, 2019.
12
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
We have identified three material revenue streams in our business: oil, natural gas and NGLs. The following table present our revenues disaggregated by revenue stream.
| For the Three Months Ended |
| |||||
| March 31, |
| |||||
| 2019 |
|
| 2018 |
| ||
| (in thousands) |
| |||||
Revenues |
|
|
|
|
|
|
|
Oil | $ | 40,057 |
|
| $ | 54,726 |
|
NGLs | $ | 5,865 |
|
| $ | 10,946 |
|
Natural gas | $ | 19,145 |
|
| $ | 22,175 |
|
Oil and natural gas sales | $ | 65,067 |
|
| $ | 87,847 |
|
Contract Balances
Under our sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $24.8 million at March 31, 2019 and $25.0 million at December 31, 2018.
Transaction Price Allocated to Remaining Performance Obligations
For our contracts that have a contract term greater than one year, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For our contracts that have a contract term of one year or less, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
Note 5.4. Acquisitions and Divestitures
Related Party Acquisitions
See Note 13 for further information regarding related party acquisitions that have been accounted for as transactions between entities under common control that impact the basis of presentation for the periods presented.
Acquisition and Divestiture Related Expenses
Acquisition and divestiture related expenses for both related party and third party transactions are included in general and administrative expense in the accompanying Unaudited Condensed Statements of Consolidated Operations for the periods indicated below (in thousands):
Successor |
|
|
| Predecessor |
|
| Successor |
|
|
| Predecessor |
| ||||||||
|
|
|
|
|
|
|
|
| Period from |
|
|
| Period from |
|
|
|
|
| ||
Three Months |
|
|
| Three Months |
|
| May 5, 2017 |
|
|
| January 1, 2017 |
|
| Nine Months |
| |||||
Ended |
|
|
| Ended |
|
| through |
|
|
| through |
|
| Ended |
| |||||
September 30, 2017 |
|
|
| September 30, 2016 |
|
| September 30, 2017 |
|
|
| May 4, 2017 |
|
| September 30, 2016 |
| |||||
$ | 238 |
|
|
| $ | 416 |
|
| $ | 238 |
|
|
| $ | — |
|
| $ | 1,429 |
|
For the Three Months Ended |
| |||||
March 31, |
| |||||
2019 |
|
| 2018 |
| ||
$ | 364 |
|
| $ | 208 |
|
Acquisitions and Divestitures
There were no material acquisitions or divestitures during the period from January 1, 2017 through May 4, 2017 or during the period from May 5, 2017 through September 30, 2017.three months ended March 31, 2019.
On July 14, 2016,May 30, 2018, we closed a transaction to divest certain of our non-core assets located in Colorado and WyomingSouth Texas (the “Rockies“South Texas Divestiture”) to a third party for total proceeds of approximately $16.4$17.1 million, including final post-closing adjustments. This disposition did not qualify as a discontinued operation.
On June 14, 2016, we closed a transaction to divest certain assets located in the Permian Basin (the “Permian Divestiture”) to a third party for a total purchase price of approximately $36.7 million including estimated post-closing adjustments. This disposition did not qualify as a discontinued operation.
20
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The income (loss) before income taxes, including the associated (gain) loss on sale of properties, related to the Permian Divestiture and Rockies Divestiture, which is included in the accompanying Unaudited Condensed Statements of Consolidated Operations of the Company, is as follows (in thousands):
| Predecessor |
| ||||||
| Three Months Ended |
|
|
| Nine Months Ended |
| ||
| September 30, 2016 |
|
|
| September 30, 2016 |
| ||
Permian Divestiture | $ | (40 | ) |
|
| $ | 4,792 |
|
Rockies Divestiture |
| 445 |
|
|
|
| (7,175 | ) |
Note 6.5. Fair Value Measurements of Financial Instruments
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All of the derivative instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets were considered Level 2.
13
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The carrying values of accounts receivables, accounts payables (including accrued liabilities), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying Unaudited Condensed Consolidated Balance Sheets approximated fair value at September 30, 2017March 31, 2019 and December 31, 2016.2018. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 9 for the estimated fair value of our outstanding debt.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The fair market values of the derivative financial instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets as of September 30, 2017March 31, 2019 and December 31, 20162018 were based on estimated forward commodity prices. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at September 30, 2017March 31, 2019 and December 31, 20162018 for each of the fair value hierarchy levels:
| Successor |
| ||||||||||||||||||||||||||||
| Fair Value Measurements at September 30, 2017 Using |
| Fair Value Measurements at March 31, 2019 Using |
| ||||||||||||||||||||||||||
| Quoted Prices in |
|
| Significant Other |
|
| Significant |
|
|
|
|
| Quoted Prices in |
|
| Significant Other |
|
| Significant |
|
|
|
|
| ||||||
| Active Market |
|
| Observable Inputs |
|
| Unobservable Inputs |
|
|
|
|
| Active Market |
|
| Observable Inputs |
|
| Unobservable Inputs |
|
|
|
|
| ||||||
| (Level 1) |
|
| (Level 2) |
|
| (Level 3) |
|
| Fair Value |
| (Level 1) |
|
| (Level 2) |
|
| (Level 3) |
|
| Fair Value |
| ||||||||
| (In thousands) |
| (In thousands) |
| ||||||||||||||||||||||||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives | $ | — |
|
| $ | 59,979 |
|
| $ | — |
|
| $ | 59,979 |
| $ | — |
|
| $ | 7,992 |
|
| $ | — |
|
| $ | 7,992 |
|
Interest rate derivatives |
| — |
|
|
| 142 |
|
|
| — |
|
|
| 142 |
| |||||||||||||||
Total assets | $ | — |
|
| $ | 8,134 |
|
| $ | — |
|
| $ | 8,134 |
| |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives | $ | — |
|
| $ | 8,428 |
|
| $ | — |
|
| $ | 8,428 |
| $ | — |
|
| $ | 18,058 |
|
| $ | — |
|
| $ | 18,058 |
|
Interest rate derivatives |
| — |
|
|
| 49 |
|
|
| — |
|
|
| 49 |
| |||||||||||||||
Total liabilities | $ | — |
|
| $ | 18,107 |
|
| $ | — |
|
| $ | 18,107 |
|
| Predecessor |
| ||||||||||||||||||||||||||||
| Fair Value Measurements at December 31, 2016 Using |
| Fair Value Measurements at December 31, 2018 Using |
| ||||||||||||||||||||||||||
| Quoted Prices in |
|
| Significant Other |
|
| Significant |
|
|
|
|
| Quoted Prices in |
|
| Significant Other |
|
| Significant |
|
|
|
|
| ||||||
| Active Market |
|
| Observable Inputs |
|
| Unobservable Inputs |
|
|
|
|
| Active Market |
|
| Observable Inputs |
|
| Unobservable Inputs |
|
|
|
|
| ||||||
| (Level 1) |
|
| (Level 2) |
|
| (Level 3) |
|
| Fair Value |
| (Level 1) |
|
| (Level 2) |
|
| (Level 3) |
|
| Fair Value |
| ||||||||
| (In thousands) |
| (In thousands) |
| ||||||||||||||||||||||||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives | $ | — |
|
| $ | 189,851 |
|
| $ | — |
|
| $ | 189,851 |
| $ | — |
|
| $ | 25,515 |
|
| $ | — |
|
| $ | 25,515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives | $ | — |
|
| $ | 17,757 |
|
| $ | — |
|
| $ | 17,757 |
| $ | — |
|
| $ | 4,372 |
|
| $ | — |
|
| $ | 4,372 |
|
See Note 76 for additional information regarding our derivative instruments.
21
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets. The following methods and assumptions are used to estimate the fair values:
The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors such as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. The initial fair value estimates are based on unobservable market data and are classified within Level 3 of the fair value hierarchy. See Note 87 for a summary of changes in AROs.
If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.
Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, estimates of probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties.
14
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unproved oil and natural gas properties are reviewed for impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered.
No impairments were recognized during the period from May 5, 2017 through September 30, 2017 or during the period from January 1, 2017 through May 4, 2017. During the ninethree months ended September 30, 2016, we recognized approximately $8.3 million of impairments related to certain properties located in East Texas. The estimated future cash flows expected from these properties were compared to their carrying valuesMarch 31, 2019 and determined to be unrecoverable primarily as a result of declining commodity prices. As a result of the impairments, the carrying value of these properties was reduced to approximately $11.0 million.2018, respectively.
Note 7.6. Risk Management and Derivative Instruments
Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These instruments limit exposure to declines in prices, or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease.increase.
Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our previous and current credit agreementagreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At September 30, 2017,March 31, 2019, after taking into effect netting arrangements, we had no counterparty exposure related to our derivative instruments. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have had the right to offset $51.8$0.1 million against amounts outstanding under our ExitNew Revolving Credit Facility (as defined below) at September 30, 2017.March 31, 2019. See Note 98 for additional information regarding our ExitEmergence Credit Facility.Facility and our New Revolving Credit Facility (as defined below).
Commodity Derivatives
We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, and costless collars) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value.
22
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
In January 2017, in connection with our restructuring efforts, we monetized $94.1 million in commodity hedges and used a portion of the proceeds to reduce the amounts outstanding under our Predecessor’s revolving credit facility and kept the remaining portion as cash on hand for general partnership purposes.
During the nine months ended September 30, 2016, we terminated certain “in-the-money” oil and NGL derivatives settling in 2016 and certain oil basis swaps settling in 2016 and 2017. We received cash settlements of approximately $39.3 million from the termination of these oil and NGL derivatives.
We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub. We also enter into oil derivative contracts indexed to either NYMEX-WTI or ICE Brent. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu.
15
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
At September 30, 2017,March 31, 2019, we had the following open commodity positions:
| Remaining |
|
|
|
|
|
|
|
|
| Remaining |
|
|
|
|
|
|
|
|
| ||
| 2017 |
|
| 2018 |
|
| 2019 |
| 2019 |
|
| 2020 |
|
| 2021 |
| ||||||
Natural Gas Derivative Contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swap contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average monthly volume (MMBtu) |
| 1,295,000 |
|
|
| 1,102,000 |
|
|
| 300,000 |
|
| 1,540,000 |
|
|
| 150,000 |
|
|
| — |
|
Weighted-average fixed price | $ | 3.96 |
|
| $ | 3.91 |
|
| $ | 2.91 |
| $ | 2.88 |
|
| $ | 2.65 |
|
| $ | — |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Collar contracts: |
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Average monthly volume (MMBtu) |
| — |
|
|
| 520,000 |
|
|
| 87,500 |
| |||||||||||
Weighted-average floor price |
| — |
|
| $ | 2.64 |
|
| $ | 2.66 |
| |||||||||||
Weighted-average ceiling price | $ | — |
|
| $ | 2.96 |
|
| $ | 2.99 |
| |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Derivative Contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swap contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average monthly volume (Bbls) |
| 129,000 |
|
|
| 122,000 |
|
|
| 50,000 |
|
| 135,333 |
|
|
| 75,000 |
|
|
| 33,750 |
|
Weighted-average fixed price | $ | 71.44 |
|
| $ | 75.69 |
|
| $ | 50.20 |
| $ | 52.60 |
|
| $ | 56.33 |
|
| $ | 55.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average monthly volume (Bbls) |
| 10,000 |
|
|
| — |
|
|
| — |
|
| 50,667 |
|
|
| 14,300 |
|
|
| — |
|
Weighted-average floor price | $ | 45.00 |
|
| $ | — |
|
| $ | — |
| $ | 55.00 |
|
| $ | 55.00 |
|
| $ | — |
|
Weighted-average ceiling price | $ | 54.50 |
|
| $ | — |
|
| $ | — |
| $ | 63.85 |
|
| $ | 62.10 |
|
| $ | — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased put option contracts: |
|
|
|
|
|
|
|
|
|
|
| |||||||||||
Average Monthly Volume (Bbls) |
| — |
|
|
| 25,550 |
|
|
| — |
| |||||||||||
Weighted-average strike price | $ | — |
|
| $ | 55.00 |
|
| $ | — |
| |||||||||||
Weighted-average deferred premium | $ | — |
|
| $ | 7.09 |
|
| $ | — |
| |||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||
NGL Derivative Contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swap contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average monthly volume (Bbls) |
| 78,400 |
|
|
| 65,700 |
|
|
| — |
|
| 72,000 |
|
|
| 37,925 |
|
|
| 5,500 |
|
Weighted-average fixed price | $ | 30.29 |
|
| $ | 24.13 |
|
| $ | — |
| $ | 29.96 |
|
| $ | 27.94 |
|
| $ | 27.23 |
|
Interest Rate Swaps
Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. The Company did not have anyAt March 31, 2019, we had the following interest rate swaps at September 30, 2017.swap open positions:
| Remaining |
|
|
|
|
|
|
|
|
| |
| 2019 |
|
| 2020 |
|
| 2021 |
| |||
Average Monthly Notional (in thousands) | $ | 50,000 |
|
| $ | 50,000 |
|
| $ | 50,000 |
|
Weighted-average fixed rate |
| 2.109 | % |
|
| 2.109 | % |
|
| 2.109 | % |
Floating rate | 1 Month LIBOR |
|
| 1 Month LIBOR |
|
| 1 Month LIBOR |
|
16
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2017March 31, 2019 and December 31, 2016.2018. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement.
|
|
|
| Successor |
|
|
| Predecessor |
| ||||||||||||||||||||||||||||
|
|
|
| Asset Derivatives |
|
| Liability Derivatives |
|
|
| Asset Derivatives |
|
| Liability Derivatives |
|
|
|
| Asset Derivatives |
|
| Liability Derivatives |
|
| Asset Derivatives |
|
| Liability Derivatives |
| ||||||||
|
|
|
| September 30, |
|
| September 30, |
|
|
| December 31, |
|
| December 31, |
|
|
|
| March 31, |
|
| March 31, |
|
| December 31, |
|
| December 31, |
| ||||||||
Type |
| Balance Sheet Location |
| 2017 |
|
| 2017 |
|
|
| 2016 |
|
| 2016 |
|
| Balance Sheet Location |
| 2019 |
|
| 2019 |
|
| 2018 |
|
| 2018 |
| ||||||||
|
|
|
| (In thousands) |
|
|
|
| (In thousands) |
| |||||||||||||||||||||||||||
Commodity contracts |
|
|
| $ | 48,435 |
|
| $ | 7,059 |
|
|
| $ | 86,335 |
|
| $ | 16,871 |
|
| Short-term derivative instruments |
| $ | 4,504 |
|
| $ | 13,469 |
|
| $ | 21,217 |
|
| $ | 2,543 |
|
Interest rate swaps |
| Short-term derivative instruments |
|
| 133 |
|
|
| — |
|
|
| — |
|
|
| — |
| |||||||||||||||||||
Gross fair value |
|
|
|
| 48,435 |
|
|
| 7,059 |
|
|
|
| 86,335 |
|
|
| 16,871 |
|
|
|
|
| 4,637 |
|
|
| 13,469 |
|
|
| 21,217 |
|
|
| 2,543 |
|
Netting arrangements |
|
|
|
| (7,059 | ) |
|
| (7,059 | ) |
|
|
| (16,871 | ) |
|
| (16,871 | ) |
|
|
|
| (4,361 | ) |
|
| (4,361 | ) |
|
| (2,404 | ) |
|
| (2,404 | ) |
Net recorded fair value |
| Short-term derivative instruments |
| $ | 41,376 |
|
| $ | — |
|
|
| $ | 69,464 |
|
| $ | — |
|
| Short-term derivative instruments |
| $ | 276 |
|
| $ | 9,108 |
|
| $ | 18,813 |
|
| $ | 139 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts |
|
|
| $ | 11,544 |
|
| $ | 1,369 |
|
|
| $ | 103,515 |
|
| $ | 885 |
|
| Long-term derivative instruments |
| $ | 3,489 |
|
| $ | 4,590 |
|
| $ | 4,298 |
|
| $ | 1,829 |
|
Interest rate swaps |
| Long-term derivative instruments |
|
| 9 |
|
|
| 49 |
|
|
| — |
|
|
| — |
| |||||||||||||||||||
Gross fair value |
|
|
|
| 11,544 |
|
|
| 1,369 |
|
|
|
| 103,515 |
|
|
| 885 |
|
|
|
|
| 3,498 |
|
|
| 4,639 |
|
|
| 4,298 |
|
|
| 1,829 |
|
Netting arrangements |
|
|
|
| (1,125 | ) |
|
| (1,125 | ) |
|
|
| (885 | ) |
|
| (885 | ) |
|
|
|
| (3,210 | ) |
|
| (3,210 | ) |
|
| (1,829 | ) |
|
| (1,829 | ) |
Net recorded fair value |
| Long-term derivative instruments |
| $ | 10,419 |
|
| $ | 244 |
|
|
| $ | 102,630 |
|
| $ | — |
|
| Long-term derivative instruments |
| $ | 288 |
|
| $ | 1,429 |
|
| $ | 2,469 |
|
| $ | — |
|
23
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying condensed statementsUnaudited Condensed Statements of consolidated operations.Consolidated Operations. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands):
| Successor |
|
|
| Predecessor |
|
| Successor |
|
|
| Predecessor |
| ||||||||
| Three Months |
|
|
| Three Months |
|
| Period from |
|
|
| Period from |
|
| Nine Months |
| |||||
| Ended |
|
|
| Ended |
|
| May 5, 2017 |
|
|
| January 1, 2017 |
|
| Ended |
| |||||
| September 30, |
|
|
| September 30, |
|
| through |
|
|
| through |
|
| September 30, |
| |||||
| 2017 |
|
|
| 2016 |
|
| September 30, 2017 |
|
|
| May 4, 2017 |
|
| 2016 |
| |||||
(Gain) loss on commodity derivative instruments | $ | 14,217 |
|
|
| $ | (21,938 | ) |
| $ | 12,302 |
|
|
| $ | (23,076 | ) |
| $ | 50,897 |
|
Interest expense, net |
| — |
|
|
|
| (1,432 | ) |
|
| — |
|
|
|
| — |
|
|
| 4,094 |
|
|
|
|
| For the Three Months Ended |
| |||||
|
| Statements of |
| March 31, |
| |||||
|
| Operations Location |
| 2019 |
|
| 2018 |
| ||
Commodity derivative contracts |
| (Gain) loss on commodity derivatives |
| $ | 32,487 |
|
| $ | 10,456 |
|
Interest rate derivatives |
| Interest expense, net |
|
| (94 | ) |
|
| — |
|
Note 8.7. Asset Retirement Obligations
The Company’s asset retirement obligations primarily relate to the Company’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the period from January 1, 2017 through May 4, 2017 and for the period from May 5, 2017 through September 30, 2017three months ended March 31, 2019 (in thousands):
Asset retirement obligations at beginning of period (Predecessor) | $ | 155,702 |
|
Liabilities added from acquisitions or drilling |
| 6 |
|
Liabilities settled |
| (164 | ) |
Accretion expense |
| 3,407 |
|
Revision of estimates |
| 104 |
|
Asset retirement obligations at May 4, 2017 (Predecessor) | $ | 159,055 |
|
Fresh start adjustments (1) |
| (62,928 | ) |
Asset retirement obligations at May 5, 2017 (Successor) | $ | 96,127 |
|
Liabilities added from acquisition or drilling |
| 145 |
|
Liabilities settled |
| (174 | ) |
Accretion expense |
| 2,692 |
|
Revision of estimates |
| 27 |
|
Asset retirement obligation at end of period (Successor) |
| 98,817 |
|
Less: Current Portion |
| (941 | ) |
Asset retirement obligations - long-term portion (Successor) | $ | 97,876 |
|
Asset retirement obligations at beginning of period | $ | 76,344 |
|
Liabilities added from acquisition or drilling |
| 7 |
|
Liabilities settled |
| (162 | ) |
Accretion expense |
| 1,311 |
|
Revision of estimates |
| 59 |
|
Asset retirement obligation at end of period |
| 77,559 |
|
Less: Current portion |
| (477 | ) |
Asset retirement obligations - long-term portion | $ | 77,082 |
|
|
|
2417
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table presents our consolidated debt obligations at the dates indicated:
| Successor |
|
|
| Predecessor |
| ||
| September 30, |
|
|
| December 31, |
| ||
| 2017 |
|
|
| 2016 |
| ||
| (In thousands) |
| ||||||
Successor $1.0 billion Exit Credit Facility, variable-rate, due March 2021 (1) | $ | 403,000 |
|
|
| $ | — |
|
Predecessor $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) |
| — |
|
|
|
| 511,652 |
|
2021 Senior Notes, fixed-rate, due May 2021 (2) (4) |
| — |
|
|
|
| 646,287 |
|
2022 Senior Notes, fixed-rate, due August 2022 (3) (4) |
| — |
|
|
|
| 464,965 |
|
Total debt |
| 403,000 |
|
|
|
| 1,622,904 |
|
Less: current portion of long-term debt (5) |
| — |
|
|
|
| (1,622,904 | ) |
Long-term debt | $ | 403,000 |
|
|
| $ | — |
|
| March 31, |
|
| December 31, |
| ||
| 2019 |
|
| 2018 |
| ||
| (In thousands) |
| |||||
$425.0 million New Revolving Credit Facility, variable-rate, due November 2023 (1) | $ | 270,000 |
|
| $ | 294,000 |
|
Long-term debt | $ | 270,000 |
|
| $ | 294,000 |
|
(1) | The carrying amount of our |
|
|
|
|
|
|
|
|
ExitNew Revolving Credit Facility
On May 4, 2017, OLLC, as borrower, entered into the Amended and RestatedAmplify Energy Operating LLC, our wholly owned subsidiary, is a party to a reserve-based revolving credit facility (the “New Revolving Credit Agreement (the “Credit Agreement”) among Amplify Acquisitionco Inc., a Delaware corporation (“Acquisitionco”Facility”), as parent guarantor, the lenders from timesubject to time party thereto and Wells Fargo Bank, National Association, as Administrative Agent. Pursuant to the Credit Agreement the lenders party thereto agreed to provide OLLC with the Exit Credit Facility (the loans thereunder, the “Loans”). The aggregate principal amount of Loans outstanding under the Exit Credit Facility as of the Effective Date was $430.0 million.
The terms and conditions under the Credit Agreement include (but are not limited to) the following:
a borrowing base of approximately $490.0$425.0 million (as of March 31, 2019, which is guaranteed by us and all of our current subsidiaries.
Our borrowing base amount will be reduced by $2.5 million each month until the next scheduled redetermination of the borrowing base to occur in November 2017);
a maturity date of March 19, 2021 for the Exitunder our New Revolving Credit Facility;
the Loans shall bear interest at a rate per annum equal to (i) the alternative base rate plus an applicable margin of 2.00% to 3.00% or (ii) adjusted LIBOR plus an applicable margin of 3.00% to 4.00%, in each case based on the borrowing base utilization percentage under the Exit Credit Facility;
the unused commitments under the Exit Credit Facility will accrue a commitment fee of 0.50%, payable quarterly in arrears;
the obligations under the Credit Agreement are guaranteed by Acquisitionco and substantially all of OLLC’s subsidiaries (the “Guarantors”), subject to limited exceptions, and secured on a first-priority basis by substantially all of OLLC’s and the Guarantors’ assets, including, without limitation, liens on at least 95% of the total value of OLLC’s and the Guarantors’ oil and gas properties, a non-recourse pledge by the Company of the capital stock of Acquisitionco, a pledge by Acquisitionco of the membership interests of OLLC and pledges of stock of all other direct and indirect subsidiaries of OLLC, subject to certain limited exceptions;
certain financial covenants, including the maintenance of (i) an interest coverage ratio not to exceed 2.50 to 1.00, determined as of the last day of each fiscal quarter for the four fiscal-quarter period then ending, commencing with the fiscal quarter ending September 30, 2017, (ii) a current ratio, determined as of the last day of each fiscal quarter, commencing with the fiscal quarter ending September 30, 2017, of not less than 1.00 to 1.00 and (iii) a total leverage ratio, determined as of the last day of each fiscal quarter, commencing with the fiscal quarter ending September 30, 2017, of less than or equal to 4.00 to 1.00; and
certain events of default, including, without limitation: non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.
25
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Our borrowing base is subject to redetermination on at least a semi-annual basis primarily based on a reserve engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. The borrowing base as of September 30, 2017 was approximately $480.0 million.
Unamortized deferred financing costs associated with our Exit Credit Facility was $7.8 million at September 30, 2017. The unamortized deferred financing costs are amortized over the remaining life of our Exit Credit Facility.
Letters of Credit
At September 30, 2017, we had $2.5 million of letters of credit outstanding, primarily related to operations at our Wyoming properties.
Predecessor’s RevolvingEmergence Credit Facility
Our PredecessorAt March 31, 2018, Amplify Energy Operating LLC, our wholly owned subsidiary (“OLLC”), was a party to a $2.0$1.0 billion revolving credit facility (our “Emergence Credit Facility”) which was guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries).subsidiaries.
On the Effective Date of the Plan, the holders of claims under the Predecessor’s revolving credit facility received a full recovery, which included a $24.8 million pay down and their pro rata share of the Exit Credit Facility. See NoteNovember 2, for additional information.
Senior Notes
On the Effective Date, the Notes were cancelled and the Predecessor’s liability thereunder discharged, and the holders of the Notes received their pro rata share of the New Common Shares. Additionally, the holders of the Notes received their pro rata share of a $24.6 million cash distribution.
The Company’s voluntary petitions as described2018, in Note 2 constituted an event of default that accelerated the obligations under the Notes. For the period from January 17, 2017 through May 4, 2017 our contractual interest that was not recorded on the Notes was approximately $24.2 million.
During the three and nine months ended September 30, 2016, our Predecessor repurchased on the open market approximately $1.5 million and $53.7 million, respectively, of its 2021 Senior Notes. During the nine months ended September 30, 2016, the Company repurchased on the open market approximately $32.0 million of its 2022 Senior Notes. In connection with entry into our New Revolving Credit Facility, the repurchases, our Predecessor paid approximately $0.8 millionEmergence Credit Facility was terminated and $41.3 million for the three and nine months ended September 30, 2016, respectively. We recorded a gain on extinguishment of debt of approximately $0.7 million and $42.3 million for the three and nine months ended September 30, 2016, respectively.repaid in full.
Weighted-Average Interest Rates
The following table presents the weighted-average interest rates paid, excluding commitment fees, on our consolidated variable-rate debt obligations for the periods presented:
| Successor |
|
|
| Predecessor |
|
| Successor |
|
|
| Predecessor |
| ||||||||
| Three Months |
|
|
| Three Months |
|
| Period from |
|
|
| Period from |
|
| Nine Months |
| |||||
| Ended |
|
|
| Ended |
|
| May 5, 2017 |
|
|
| January 1, 2017 |
|
| Ended |
| |||||
| September 30, |
|
|
| September 30, |
|
| through |
|
|
| through |
|
| September 30, |
| |||||
| 2017 |
|
|
| 2016 |
|
| September 30, 2017 |
|
|
| May 4, 2017 |
|
| 2016 |
| |||||
Successor Exit Credit Facility |
| 4.86% |
|
|
| n/a |
|
|
| 5.01% |
|
|
| n/a |
|
| n/a |
| |||
Predecessor's revolving credit facility | n/a |
|
|
|
| 3.57% |
|
| n/a |
|
|
|
| 4.04% |
|
|
| 3.11% |
|
| For the Three Months Ended |
| |||
| March 31, |
| |||
| 2019 |
|
| 2018 |
|
New Revolving Credit Facility | 5.07% |
|
| n/a |
|
Emergence Credit Facility | n/a |
|
| 5.48% |
|
Letters of Credit
At March 31, 2019, we had $1.7 million of letters of credit outstanding, primarily related to operations at our Wyoming properties.
Unamortized Deferred Financing Costs
Unamortized deferred financing costs associated with our New Revolving Credit Facility was $4.8 million at March 31, 2019. At March 31, 2019, the unamortized deferred financing costs are amortized over the remaining life of our New Revolving Credit Facility.
Issuance of Common Stock and Cancellation of Units
In accordance with the Plan, on the Effective Date:
the Company issued 25,000,000 New Common Shares and Warrants to purchase up to 2,173,913The Company’s authorized capital stock includes 300,000,000 shares of its common stock;
stock, $0.0001 par value per share. The following is a summary of the Predecessorchanges in our common units were cancelled; andstock issued for the three months ended March 31, 2019:
Common | |||
Shares | |||
Balance, December 31, 2018 | 22,181,881 | ||
Issuance of common stock | — | ||
Restricted stock units vested | 287,658 | ||
Repurchase of common shares | (88,508 | ) | |
Common stock repurchased and retired under share repurchase program | (122,581 | ) | |
Balance, March 31, 2019 | 22,258,450 |
2618
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
On the Effective Date, there were 25,000,000 New Common Shares issued and outstanding.
The following table summarizes the changes in the number of outstanding common units and shares of common stock:
| |||
|
| ||
|
| ||
|
|
| |
|
|
| |
|
| ||
|
|
| |
|
| ||
|
| ||
|
| ||
|
| ||
|
|
|
|
Warrants
On the Effective Date,May 4, 2017 (the “Effective Date”), the Company entered into a warrant agreement with American Stock Transfer & Trust Company, LLC, as warrant agent, pursuant to which the Company issued Warrantswarrants to purchase up to 2,173,913 shares of the Company’s common stock (representing 8% of the Company’s outstanding common stock as of the Effective Date including shares of the Company’s common stock issuable upon full exercise of the Warrants,warrants, but excluding any common stock issuable under the MIP)Management Incentive Plan (the “MIP”)), exercisable for a five yearfive-year period commencing on the Effective Date at an exercise price of $42.60 per share.
The fair values for the warrants upon issuance on the Effective Date have been estimated using the Black-Scholes option pricing model using the following assumptions:
| Warrants Issued in |
| |
| Successor Period |
| |
Risk-free interest rate |
| 2.06 | % |
Dividend yield |
| — |
|
Expected life (in years) |
| 5.0 |
|
Expected volatility |
| 50.0 | % |
Strike Price | $ | 42.60 |
|
Calculated fair value | $ | 2.20 |
|
Predecessor “At-the-Market” EquityShare Repurchase Program
On May 25, 2016, our Predecessor entered into an equity distribution agreement forDecember 21, 2018, the saleCompany’s board of directors authorized the repurchase of up to $60.0$25.0 million of common units under an at-the-market offering program (the “ATM Program”). Salesthe Company’s outstanding shares of common units, were made under the ATM Program by means of ordinary brokers’ transactions, through the facilities of the NASDAQ Global Market at market prices, or as otherwise agreed to between the Predecessor and a sales agent.
stock, with repurchases beginning on January 9, 2019. During the three and nine months ended September 30, 2016, our Predecessor sold 355,789 and 1,178,102March 31, 2019, the Company repurchased 122,581 shares of common units, respectively,stock at an average price of $7.82 for a total cost of approximately $0.9 million. At March 31, 2019, approximately $24.1 million remains available for repurchase under the ATM Program. The sale of the common units generated proceeds of approximately $0.5 million and $2.1 million for the three and nine months ended September 30, 2016, which was net of approximately $0.2 million and $0.3 million in fees, respectively. Our Predecessor used the net proceeds from the sale of common units to repurchase senior notes.
Predecessor
Prior to the MEMP GP Acquisition, net income (loss) attributable to the Predecessor was allocated between our Predecessor’s general partner and the common unitholders in proportion to their pro rata ownership after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our Predecessor’s general partner and the Funds. Subsequent to the MEMP GP Acquisition, net income (loss) attributable to the Predecessor was allocated entirely to the common unitholders.
27
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Cash Distributions to Unitholders
The following table summarizes our Predecessor’s declared quarterly cash distribution rates and amounts with respect to the quarter indicated (dollars in millions, except per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Distribution |
| |
|
|
|
|
|
|
|
| Amount |
|
| Aggregate |
|
| Received by |
| |||
Quarter |
| Declaration Date |
| Record Date |
| Payment Date |
| Per Unit |
|
| Distribution |
|
| Affiliates |
| |||
2nd Quarter 2016 |
| July 26, 2016 |
| August 5, 2016 |
| August 12, 2016 |
| $ | 0.0300 |
|
| $ | 2.5 |
|
| $ | < 0.1 |
|
1st Quarter 2016 |
| April 26, 2016 |
| May 6, 2016 |
| May 13, 2016 |
| $ | 0.0300 |
|
| $ | 2.5 |
|
| $ | < 0.1 |
|
4th Quarter 2015 |
| January 26, 2016 |
| February 5, 2016 |
| February 12, 2016 |
| $ | 0.1000 |
|
| $ | 8.3 |
|
| $ | < 0.1 |
|
In October 2016, the board of directors of our Predecessor’s general partner suspended distributions on common units, primarily due to the current and expected commodity price environment and market conditions and their impact on our future business, as well as restrictions imposed by our Predecessor’s debt instruments, including our Predecessor’s revolving credit facility.program.
Note 11.10. Earnings per Share/UnitShare
The following sets forth the calculation of earnings (loss) per share/unit,share, or EPS/EPU,EPS, for the periods indicated (in thousands, except per share/unitshare amounts):
| Successor |
|
|
| Predecessor |
|
| Successor |
|
|
| Predecessor |
| ||||||||
|
|
|
|
|
|
|
|
|
| Period from |
|
|
|
|
|
|
|
|
|
| |
| Three Months |
|
|
| Three Months |
|
| May 5, 2017 |
|
|
| Period from |
|
| Nine Months |
| |||||
| Ended |
|
|
| Ended |
|
| through |
|
|
| January 1, |
|
| Ended |
| |||||
| September 30, |
|
|
| September 30, |
|
| September 30, |
|
|
| 2017 through |
|
| September 30, |
| |||||
| 2017 |
|
|
| 2016 |
|
| 2017 |
|
|
| May 4, 2017 |
|
| 2016 |
| |||||
Net income (loss) attributable to Successor/Predecessor | $ | (7,536 | ) |
|
| $ | (32,866 | ) |
| $ | (8,442 | ) |
|
| $ | (90,955 | ) |
| $ | (218,513 | ) |
Less: predecessor's general partner's 0.1% interest in net income (loss) (1) |
| — |
|
|
|
| — |
|
|
| — |
|
|
|
| — |
|
|
| (168 | ) |
Net (income) allocated to participating restricted stockholders |
| — |
|
|
|
| — |
|
|
| — |
|
|
|
| — |
|
|
| — |
|
Net income (loss) available to common stockholders/limited partners | $ | (7,536 | ) |
|
| $ | (32,866 | ) |
| $ | (8,442 | ) |
|
| $ | (90,955 | ) |
| $ | (218,345 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares/units: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares/units outstanding — basic |
| 25,000 |
|
|
|
| 83,621 |
|
|
| 25,000 |
|
|
|
| 83,807 |
|
|
| 83,189 |
|
Dilutive effect of potential common shares/units |
| — |
|
|
|
| — |
|
|
| — |
|
|
|
| — |
|
|
| — |
|
Common shares/units outstanding — diluted |
| 25,000 |
|
|
|
| 83,621 |
|
|
| 25,000 |
|
|
|
| 83,807 |
|
|
| 83,189 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings per share/unit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic | $ | (0.30 | ) |
|
| $ | (0.39 | ) |
| $ | (0.34 | ) |
|
| $ | (1.09 | ) |
| $ | (2.62 | ) |
Diluted | $ | (0.30 | ) |
|
| $ | (0.39 | ) |
| $ | (0.34 | ) |
|
| $ | (1.09 | ) |
| $ | (2.62 | ) |
Antidilutive stock options (2) |
| 517 |
|
|
|
| — |
|
|
| 517 |
|
|
|
| — |
|
|
| — |
|
Antidilutive warrants (3) |
| 2,174 |
|
|
|
| — |
|
|
| 2,174 |
|
|
|
| — |
|
|
| — |
|
| For the Three Months Ended |
| |||||
| March 31, |
| |||||
| 2019 |
|
| 2018 |
| ||
Net income (loss) | $ | (31,477 | ) |
| $ | 3,239 |
|
Less: Net income allocated to participating restricted stockholders |
| — |
|
|
| (83 | ) |
Basic and diluted earnings available to common stockholders | $ | (31,477 | ) |
| $ | 3,156 |
|
|
|
|
|
|
|
|
|
Common shares/units: |
|
|
|
|
|
|
|
Common shares outstanding — basic |
| 22,179 |
|
|
| 25,000 |
|
Dilutive effect of potential common shares |
| — |
|
|
| — |
|
Common shares outstanding — diluted |
| 22,179 |
|
|
| 25,000 |
|
|
|
|
|
|
|
|
|
Net earnings per share: |
|
|
|
|
|
|
|
Basic | $ | (1.42 | ) |
| $ | 0.13 |
|
Diluted | $ | (1.42 | ) |
| $ | 0.13 |
|
Antidilutive stock options (1) |
| — |
|
|
| 513 |
|
Antidilutive warrants (2) |
| 2,174 |
|
|
| 2,174 |
|
(1) |
|
| Amount represents options to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect. |
|
| Amount represents warrants to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect. |
|
Note 12.11. Long-Term Incentive Plans
On the Effective Date in connection with the Plan,In May 2017, the Company implemented the MIP for selected employees of the Company or its subsidiaries. AnManagement Incentive Plan (the “MIP”). At March 31, 2019, an aggregate of 2,322,404 shares of the Company’s common stock are reserved for issuance under the MIP. MIP awards are granted in the form of nonqualified stock options, incentive stock options, restricted stock awards,
Restricted Stock Units
Restricted Stock Units with Service Vesting Condition
The restricted stock units stock appreciation rights, performancewith service vesting conditions (“TSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with the TSUs was $4.8 million at March 31, 2019. We expect to recognize the unrecognized compensation cost for these awards stock awards and other incentive awards. To the extent that an award under the MIP is expired, forfeited or cancelled for any reason without having been exercised in full, the unexercised award would then be available again for grant under the MIP. The MIP is administered by the boardover a weighted-average period of directors of the Company.approximately 2.0 years.
On May 4, 2017, the board of directors approved grants of restricted stock unit awards and restricted stock options (collectively, the “Emergence Awards”) to certain of the Company’s employees, including the Company’s executive officers. The board granted 614,754 restricted stock units and 614,754 restricted stock options under the MIP on the Effective Date.
2819
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The Emergence Awards will generally vest annually in three equal installments on each of the first three anniversaries of the Effective Date, subject to the grantee’s continued employment through each such vesting date. However, upon the grantee’s (i) termination of employment without “cause,” or due to death or “disability,” or (ii) resignation for “good reason,” in each case, (A) any unvested restricted stock unit award at such time shall fully vest and (B) the portion of the then unvested stock options that would have vested had the grantee remained employed with the Company or its subsidiaries during the 12 months following such termination or resignation date shall vest. In addition, if the grantee is terminated by the Company without cause or the grantee resigns for good reason, in each case, following a “change of control,” all unvested stock options at such time shall fully vest. Subject to the foregoing, any unvested Emergence Awards will be forfeited upon the grantee’s termination of employment.
Restricted Stock Units
The restricted stock units granted are accounted for as equity-classified awards. The grant-date fair value net of estimated forfeitures is recognized as compensation cost on a straight-line basis over the requisite service period. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with restricted stock unit awards was $7.9 million at September 30, 2017. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.6 years.
The following table summarizes information regarding the restricted stock unit awardsTSUs granted under the MIP for the period presented:
|
|
|
|
| Weighted- |
|
|
|
|
| Weighted- |
| ||
|
|
|
|
| Average Grant |
|
|
|
|
| Average Grant |
| ||
| Number of |
|
| Date Fair Value |
| Number of |
|
| Date Fair Value |
| ||||
| Units |
|
| per Unit (1) |
| Units |
|
| per Unit (1) |
| ||||
Restricted stock units outstanding at May 5, 2017 (Successor) |
| 614,754 |
|
| $ | 13.77 |
| |||||||
TSUs outstanding at December 31, 2018 |
| 598,024 |
|
| $ | 11.35 |
| |||||||
Granted (2) |
| 149,410 |
|
| $ | 13.62 |
|
| 276,398 |
|
| $ | 6.92 |
|
Forfeited |
| (99,232 | ) |
| $ | 13.77 |
|
| (17,250 | ) |
| $ | 10.00 |
|
Vested |
| — |
|
| $ | — |
|
| (276,849 | ) |
| $ | 7.07 |
|
Restricted stock units outstanding at September 30, 2017 (Successor) |
| 664,932 |
|
| $ | 13.74 |
| |||||||
TSUs outstanding at March 31, 2019 |
| 580,323 |
|
| $ | 11.32 |
|
| (1) | Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. |
| (2) | The aggregate grant date fair value of |
Restricted Stock OptionsUnits with Market and Service Vesting Conditions
The fair value for restricted stock options granted during the three months ended June 30, 2017 have been estimated using the Black-Scholes option pricing model using the following assumptions:
| Awards Issued in |
| |
| Successor Period |
| |
Risk-free interest rate |
| 2.06 | % |
Dividend yield |
| — |
|
Expected life (in years) |
| 6.0 |
|
Expected volatility |
| 50.0 | % |
Strike Price | $ | 21.58 |
|
Calculated fair value per stock option | $ | 5.01 |
|
The restricted stock options grantedunits with market and service vesting conditions (“PSUs”) are accounted for as equity-classified awards. The grant-date fair value net of estimated forfeitures is recognized as compensation cost on a straight-line basisgraded-vesting basis. As such, the Company recognizes compensation cost over the requisite service period.period for each separately vesting tranche of the award as though the award were, in substance, multiple awards. The Company accounts for forfeitures as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with restricted stock option awardsrelated to the PSUs was $2.2$1.3 million at September 30, 2017.March 31, 2019. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.6approximately 1.4 years.
29
AMPLIFY ENERGY CORP.During the three months ended March 31, 2019, the Company granted PSUs to certain new employees of the Company. The PSUs will vest based on the satisfaction of service and market vesting conditions with market vesting based on the Company’s achievement of certain share price targets. The PSUs are subject to service-based vesting such that 50% of the PSUs service vest on the applicable market vesting date and an additional 25% of the PSUs service vest on each of the first and second anniversaries of the applicable market vesting date.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTSIn the event of a qualifying termination, subject to certain conditions, (i) all PSUs that have satisfied the market vesting conditions will fully service vest, upon such termination, and (ii) if the termination occurs between the second and third anniversaries of the grant date, then PSUs that have not market vested as of the termination will market vest to the extent that the share targets (in each case, reduced by $0.25) are achieved as of such termination. Subject to the foregoing, any unvested PSUs will be forfeited upon termination of employment.
A Monte Carlo simulation was used in order to determine the fair value of these awards at the grant date.
The assumptions used to estimate the fair value of the PSUs are as follows:
Share price targets | $ | 12.50 |
|
| $ | 15.00 |
|
| $ | 17.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk-free interest rate: |
|
|
|
|
|
|
|
|
|
|
|
Awards Issued on January 1, 2019 |
| 2.44 | % |
|
| 2.44 | % |
|
| 2.44 | % |
|
|
|
|
|
|
|
|
|
|
|
|
Dividend yield |
| — |
|
|
| — |
|
|
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected volatility: |
|
|
|
|
|
|
|
|
|
|
|
Awards Issued on January 1, 2019 |
| 54.0 | % |
|
| 54.0 | % |
|
| 54.0 | % |
|
|
|
|
|
|
|
|
|
|
|
|
Calculated fair value per PSU: |
|
|
|
|
|
|
|
|
|
|
|
Awards Issued on January 1, 2019 | $ | 6.76 |
|
| $ | 5.86 |
|
| $ | 5.11 |
|
The following table summarizes information regarding the restricted stock option awardsPSUs granted under the MIP for the period presented:
|
|
|
|
| Weighted- |
|
|
|
|
| Weighted- |
| ||
|
|
|
|
| Average Grant |
|
|
|
|
| Average Grant |
| ||
| Number of |
|
| Date Fair Value |
| Number of |
|
| Date Fair Value |
| ||||
| Units |
|
| per Unit (1) |
| Units |
|
| per Unit (1) |
| ||||
Restricted stock options outstanding at May 4, 2017 (Successor) |
| 614,754 |
|
| $ | 5.01 |
| |||||||
PSUs outstanding at December 31, 2018 |
| 393,500 |
|
| $ | 8.14 |
| |||||||
Granted |
| 1,876 |
|
| $ | 5.01 |
|
| 7,750 |
|
| $ | 5.91 |
|
Forfeited |
| (99,232 | ) |
| $ | 5.01 |
|
| (13,250 | ) |
| $ | 7.59 |
|
Vested |
| — |
|
| $ | — |
|
| — |
|
| $ | — |
|
Restricted stock options outstanding at September 30, 2017 (Successor) |
| 517,398 |
|
| $ | 5.01 |
| |||||||
PSUs outstanding at March 31, 2019 |
| 388,000 |
|
| $ | 8.11 |
|
| (1) | Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. |
Predecessor Restricted Common Units20
AMPLIFY ENERGY CORP.
On May 1,NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
2017 Non-Employee Directors Compensation Plan
In June 2017, the Company effectively cancelledimplemented the unvested restricted2017 Non-Employee Directors Compensation Plan (“Directors Compensation Plan”) to attract and retain services of experienced non-employee directors of the Company or its subsidiaries. An aggregate of 200,000 shares of the Company’s common unit awardsstock are reserved for issuance under the Memorial Production Partners GP LLC Long-Term Incentive PlanDirectors Compensation Plan.
The restricted stock units with a service vesting condition (“LTIP”Board RSUs”) and recorded $2.3 million in compensation expense with the cancellation of the LTIP.
On June 1, 2016, in connection with the MEMP GP Acquisition, the board of directors of our Predecessor’s general partner approved the acceleration of the vesting schedule of unvested awards under the LTIPare accounted for the employees that remained with Memorial Resource.as equity-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with restricted stock unit awards was $0.2 million at March 31, 2019. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately $0.1 million was reversed and the modified-date grant fair value compensation cost of $0.5 million was recognized.
On March 9, 2016, certain employees were impacted by an involuntary termination which, upon the approval of the board of directors of our Predecessor’s general partner, accelerated the vesting schedule of unvested awards under the LTIP that otherwise would have been forfeited upon an involuntary termination. The acceleration of the LTIP vesting schedule represents an improbable-to-probable modification. The grant-date fair value compensation cost of approximately $0.5 million was reversed and the modified-date grant fair value compensation cost of approximately $0.3 million was recognized.1.8 years.
The following table summarizes information regarding the restricted common unit awardsBoard RSUs granted under the LTIPDirectors Compensation Plan for the periodsperiod presented:
|
|
|
|
| Weighted- |
|
|
|
|
| Weighted- |
| ||
|
|
|
|
| Average Grant |
|
|
|
|
| Average Grant |
| ||
| Number of |
|
| Date Fair Value |
| Number of |
|
| Date Fair Value |
| ||||
| Units |
|
| per Unit (1) |
| Units |
|
| per Unit (1) |
| ||||
Restricted common units outstanding at December 31, 2016 (Predecessor) |
| 432,160 |
|
| $ | 15.00 |
| |||||||
Board RSUs outstanding at December 31, 2018 |
| 39,604 |
|
| $ | 11.36 |
| |||||||
Granted |
| — |
|
| $ | — |
|
| — |
|
| $ | — |
|
Forfeited |
| (12,952 | ) |
| $ | 9.51 |
|
| — |
|
| $ | — |
|
Vested |
| (43,045 | ) |
| $ | 10.40 |
|
| (10,809 | ) |
| $ | 11.57 |
|
Cancelled |
| (376,163 | ) |
| $ | 15.72 |
| |||||||
Restricted common units outstanding at May 4, 2017 (Predecessor) |
| — |
|
| $ | — |
| |||||||
Board RSUs outstanding at March 31, 2019 |
| 28,795 |
|
| $ | 11.29 |
|
| (1) | Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. |
Predecessor Phantom Units
The following table summarizes information regarding the Predecessor’s phantom unit awards granted under the LTIP:
| |||
| |||
|
| ||
|
| ||
|
|
| |
|
|
| |
|
| ||
|
|
| |
|
|
30
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Phantom units issued to non-employee directors of our Predecessor in January 2016 vested on the first anniversary of the date of grant and were settled in cash for less than $0.1 million. Phantom units issued to certain employees in June 2016 were scheduled to vest in substantially equal one-third increments on the first, second, and third anniversaries of the date of grant. The awards included distribution equivalent rights (“DERs”) pursuant to which the recipient would, upon vesting, receive a cash payment with respect to each phantom unit equal to any cash distributions that we paid to a holder of a common unit. DERs were treated as additional compensation expense. Upon vesting, the phantom units were scheduled to be settled through an amount of cash in a single lump sum payment equal to the product of (y) the closing price of our common units on the vesting date and (z) the number of such vested phantom units. In lieu of a cash payment, the board of directors of our Predecessor’s general partner, in its discretion, was permitted to elect for the recipient to receive either a number of common units equal to the number of such vested phantom units or a combination of cash and common units. Upon emergence from bankruptcy, the remaining awards were settled in cash for less than $0.1 million.
Compensation Expense
The following table summarizes the amount of recognized compensation expense associated with the MIP and LTIP awards thatDirectors Compensation Plan, which are reflected in the accompanying Unaudited Condensed Statements of Consolidated Operations for the periods presented (in thousands):
|
| Successor |
|
|
| Predecessor |
|
| Successor |
|
|
| Predecessor |
| ||||||||
|
| Three Months |
|
|
| Three Months |
|
| Period from |
|
|
| Period from |
|
| Nine Months |
| |||||
|
| Ended |
|
|
| Ended |
|
| May 5, 2017 |
|
|
| January 1, 2017 |
|
| Ended |
| |||||
|
| September 30, |
|
|
| September 30, |
|
| through |
|
|
| through |
|
| September 30, |
| |||||
|
| 2017 |
|
|
| 2016 |
|
| September 30, 2017 |
|
|
| May 4, 2017 |
|
| 2016 |
| |||||
Equity classified awards |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock units (Successor) |
| $ | 764 |
|
|
| $ | — |
|
| $ | 1,190 |
|
|
| $ | — |
|
| $ | — |
|
Restricted stock options (Successor) |
|
| 252 |
|
|
|
| — |
|
|
| 353 |
|
|
|
| — |
|
|
| — |
|
Restricted common units (Predecessor) |
|
| — |
|
|
|
| 1,135 |
|
|
| — |
|
|
|
| 3,713 |
|
|
| 6,134 |
|
Liability classified awards |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Phantom units (Predecessor) |
|
| — |
|
|
|
| 1,189 |
|
|
| — |
|
|
|
| (46 | ) |
|
| 1,413 |
|
|
| $ | 1,016 |
|
|
| $ | 2,324 |
|
| $ | 1,543 |
|
|
| $ | 3,667 |
|
| $ | 7,547 |
|
| For the Three Months Ended |
| |||||
| March 31, |
| |||||
| 2019 |
|
| 2018 |
| ||
Equity classified awards |
|
|
|
|
|
|
|
TSUs | $ | 669 |
|
| $ | 948 |
|
PSUs |
| 396 |
|
|
| — |
|
Board RSUs |
| 113 |
|
|
| 19 |
|
Restricted stock options |
| — |
|
|
| 209 |
|
| $ | 1,178 |
|
| $ | 1,176 |
|
As discussed in Note 2, the Company adopted ASU 842, leases, on January 1, 2019 using the modified retrospective approach with a cumulative impact to retained earnings. The adoption of this standard has resulted in an increase in the assets and liabilities on the Company’s Unaudited Condensed Consolidated Balance Sheet. The Company has completed the review and evaluation of current and potential leases which resulted primarily in our corporate office lease and some minor equipment and vehicle leases qualifying under the new guidance. Based upon this analysis, the impact of the new guidance established a liability and the corresponding asset of $5.4 million at January 1, 2019.
For the quarter ended March 31, 2019, our leases qualify as operating leases and we did not have any existing or new leases qualifying as financing leases. We have leases for office space and equipment in our corporate office and operating regions as well as vehicles, compressors and surface rentals related to our business operations. In addition, we have offshore Southern California pipeline right-of-way use agreements. Most of our leases, other than our corporate office lease, have an initial term and may be extended on a month-to-month basis after expiration of the initial term. Most of our leases can be terminated with 30-day prior written notice. The majority of our month-to-month leases are not included as a lease liability in our balance sheet under ASC 842 because continuation of the lease is not reasonably certain. Additionally, the Company elected the short-term practical expedient to exclude leases with a term of twelve months or less.
21
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Our corporate office lease does not provide an implicit rate. To determine the present value of the lease payments, we use our incremental borrowing rate based on the information available at the inception date. To determine the incremental borrowing rate, we apply a portfolio approach based on the applicable lease terms and the current economic environment. We use a reasonable market interest rate for our office equipment and vehicle leases.
The following table presents the Company’s right-of-use assets and lease liabilities as of March 31, 2019.
| March 31, |
| |
| 2019 |
| |
| (In thousands) |
| |
Right-of-use asset | $ | 5,011 |
|
|
|
|
|
Lease liabilities: |
|
|
|
Current lease liability |
| 1,921 |
|
Long-term lease liability |
| 3,090 |
|
Total lease liability | $ | 5,011 |
|
The following table reflects the Company’s maturity analysis of the minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year (in thousands):
| Office lease |
|
| Leased vehicles and office equipment |
|
| Total |
| |||
Remaining 2019 | $ | 1,533 |
|
| $ | 388 |
|
| $ | 1,921 |
|
2020 |
| 1,561 |
|
|
| 357 |
|
|
| 1,918 |
|
2021 |
| 1,320 |
|
|
| 219 |
|
|
| 1,539 |
|
2022 and thereafter |
| — |
|
|
| — |
|
|
| — |
|
Total lease payments | $ | 4,414 |
|
| $ | 964 |
|
| $ | 5,378 |
|
Less: interest | $ | 319 |
|
| $ | 48 |
|
| $ | 367 |
|
Present value of lease liabilities | $ | 4,095 |
|
| $ | 916 | �� |
| $ | 5,011 |
|
The following is a schedule of the Company’s future contractual payment for operating leases prepared in accordance with accounting standards prior to the adoption of ASC 842, as of December 31, 2018:
|
|
|
|
|
| Payment or Settlement Due by Period |
| |||||||||||||||||||||
Operating leases |
| Total |
|
| 2019 |
|
| 2020 |
|
| 2021 |
|
| 2022 |
|
| 2023 |
|
| Thereafter |
| |||||||
Operating leases |
| $ | 11,846 |
|
| $ | 5,893 |
|
| $ | 2,072 |
|
| $ | 2,109 |
|
| $ | 337 |
|
| $ | 205 |
|
| $ | 1,230 |
|
The weighted average remaining lease terms and discount rate for all of our operating leases were as follow as of March 31, 2019:
March 31, | |||
2019 | |||
Weighted average remaining lease term (years): | |||
Corporate office | 2.32 | ||
Vehicles | 0.40 | ||
Office equipment | 0.12 | ||
Weighted average discount rate: | |||
Corporate office | 4.12 | % | |
Vehicles | 0.48 | % | |
Office equipment | 0.21 | % |
We have instituted internal controls going forward to monitor and evaluate new leases for appropriate accounting under the new guidance.
22
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 13. Supplemental Disclosures to the Unaudited Condensed Consolidated Balance Sheets and Unaudited Condensed Consolidated Statements of Cash Flows
Accrued Liabilities
Current accrued liabilities consisted of the following at the dates indicated (in thousands):
| March 31, |
|
| December 31, |
| ||
| 2019 |
|
| 2018 |
| ||
Accrued lease operating expense | $ | 9,090 |
|
| $ | 10,469 |
|
Accrued interest payable |
| 3,724 |
|
|
| 2,476 |
|
Accrued capital expenditures |
| 2,602 |
|
|
| 4,349 |
|
Accrued general and administrative expense |
| 2,398 |
|
|
| 4,393 |
|
Operating lease liability |
| 1,921 |
|
|
| — |
|
Accrued ad valorem tax |
| 987 |
|
|
| 729 |
|
Asset retirement obligations |
| 477 |
|
|
| 477 |
|
Other |
| — |
|
|
| 262 |
|
Accrued liabilities | $ | 21,199 |
|
| $ | 23,155 |
|
Cash and Cash Equivalents Reconciliation
The following table provides a reconciliation of cash and cash equivalents on the Unaudited Condensed Consolidated Balance Sheet to cash, cash equivalents and restricted cash on the Unaudited Condensed Statements of Consolidated Cash Flows (in thousands):
| March 31, |
|
| December 31, |
| ||
| 2019 |
|
| 2018 |
| ||
Cash and cash equivalents | $ | 24,876 |
|
| $ | 49,704 |
|
Restricted cash |
| 325 |
|
|
| 325 |
|
Total cash, cash equivalents and restricted cash | $ | 25,201 |
|
| $ | 50,029 |
|
Supplemental Cash Flows
Supplemental cash flows for the periods presented (in thousands):
| For the Three Months Ended |
| |||||
| March 31, |
| |||||
| 2019 |
|
| 2018 |
| ||
Supplemental cash flows: |
|
|
|
|
|
|
|
Cash paid for interest, net of amounts capitalized | $ | 2,325 |
|
| $ | 6,028 |
|
Cash paid for reorganization items, net |
| 187 |
|
|
| 656 |
|
Noncash investing and financing activities: |
|
|
|
|
|
|
|
Increase (decrease) in capital expenditures in payables and accrued liabilities |
| (2,612 | ) |
|
| 1,890 |
|
Note 13.14. Related Party Transactions
On June 1, 2016, Memorial Resource and certain affiliates of NGP became unaffiliated entities after we closed the MEMP GP Acquisition, as discussed in Note 1.
NGP Affiliated Companies
During the nine months ended September 30, 2016, our Predecessor paid less than $0.1 million to Multi-Shot, LLC, an NGP affiliate company, for services related to our drilling and completion activities.
Common Control Acquisitions
MEMP GP Acquisition. On June 1, 2016, as discussed in Note 1, our Predecessor acquired all of the equity interests in our Predecessor’s general partner, MEMP GP, from Memorial Resource for cash consideration of approximately $0.8 million. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition. In connection with the closing of the transaction, our Predecessor’s partnership agreement was amended and restated to, among other things, (i) convert MEMP GP’s 0.1% general partnership interest into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of our Predecessor had the ability to elect the members of MEMP GP’s board of directors. On June 1, 2016, our Predecessor also acquired the remaining 50% of the IDRs of MEMP owned by an NGP affiliate.
On June 1, 2016, Memorial Resource assigned and transferred Beta Operating Company, LLC to our Predecessor in connection with the MEMP GP Acquisition.
Related Party Agreements
WeThere have been no transactions in excess of $120,000 between us and certain of our former affiliates entered into various documentsany related person in which the related person had a direct or indirect material interest for the three months ended March 31, 2019 and agreements during the Predecessor’s existence, including the Predecessor’s Omnibus Agreement described below. These agreements were negotiated among affiliated parties and, consequently, were not the result of arm’s-length negotiations.2018, respectively.
3123
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Memorial Resource provided management, administrative and operating services to the Predecessor and our Predecessor’s general partner pursuant to our Predecessor’s Omnibus Agreement. Upon completion of the MEMP GP Acquisition, the Predecessor’s Omnibus Agreement was terminated and the Company entered into a transition services agreement with Memorial Resource. The following table summarizes the amount of general and administrative expense recognized under the Predecessor’s Omnibus Agreement that are reflected in the accompanying Unaudited Condensed Statements of Consolidated Operations for the periods presented (in thousands):
Predecessor |
| |||||
Three Months Ended |
|
| Nine Months Ended |
| ||
September 30, |
|
| September 30, |
| ||
2016 |
|
| 2016 |
| ||
$ | — |
|
| $ | 11,867 |
|
Transition Services Agreement
On June 1, 2016, we closed the MEMP GP Acquisition. Upon closing of the MEMP GP Acquisition, we and Memorial Resource became unaffiliated entities. We terminated our Predecessor’s Omnibus Agreement as noted above and entered into a transition services agreement with Memorial Resource to manage post-closing separation costs and activities. The Company did not incur any costs under the transition services agreement for the period from May 5, 2017 through September 30, 2017 or for the period from January 1, 2017 through May 4, 2017. During the three and nine months ended September 30, 2016, we recorded $0.9 million and $1.4 million, respectively, of general and administrative expense related to the transition services agreement with Memorial Resource.
Note 14.Note 15. Commitments and Contingencies
Litigation and Environmental
As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. On January 13, 2017, the Company received a letter from the Environmental Protection Agency (“EPA”) concerning potential violations of the Clean Air Act (“CAA”) section 112(r) associated with our Bairoil complex in Wyoming. The Company met with the EPA on February 16, 2017 to present relevant information related to the allegations. On SeptemberMarch 12, 2017, the EPA filed an Administrative Compliance Order on Consent for which the Company mustwas required to bring all outstanding issues to closure no later than June 30, 2018. We currently cannot estimateOn June 14, 2018, we sent the EPA a letter informing the EPA that we had completed all remedial action items related to the Administrative Compliance Order on Consent. In March 2018, we came to an agreement regarding the potential penalties, fines or other expenditures, if any, that may result from any EPA actions relating to the alleged violations, and, therefore, we cannot determine if the ultimate outcome of this matter will have anoting no material impact on the Company’s financial position, results of operations or cash flows. Other than the Chapter 11 proceedings and the alleged CAA violations discussed herein, based on facts currently available, we are not aware of any litigation, pending or threatened, that we believe will have a material adverse effect on our financial position, results of operations or cash flows; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.
At September 30, 2017March 31, 2019 and December 31, 2016,2018, we had no environmental reserves recorded on our Unaudited Condensed Consolidated Balance Sheet.
Supplemental Bond for Decommissioning Liabilities Trust Agreement
Rise EnergyBeta Operating Company, LLC a wholly owned subsidiary, assumed(“Beta”), has an obligation under a trust agreement with the BOEM for the decommissioning of the offshore production facilities in connection with its 2009 acquisition of our Beta properties in federal waters offshore Southern California. The trust account had the required minimum balanceBeta’s decommissioning obligations remain fully supported by A-rated surety bonds and $90.0 million of $152.0 million as of September 30, 2017 and December 31, 2016.cash. The held-to-maturity investments held in the trust account at September 30, 2017March 31, 2019 for the U.S. Bank money market cash equivalent was $152.2$90.2 million.
In 2015, the Bureau of Safety and Environmental Enforcement issued a preliminary report that indicated the estimated costs of decommissioning may further increase. The implementation of this increase is currently on hold and we do not expect resolution of a negotiated decommissioning estimate until 2018.
32
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
later in 2019.
Effective May 5, 2017, pursuant to the Plan, the Successor became a corporation subject to federal and state income taxes. Prior to the Plan being effective, the Predecessor was a limited partnership and organized as a pass-through entity for federal and most state income tax purposes. As a result, our Predecessor limited partners were responsible for federal and state income taxes on their share of our taxable income. Certain of our consolidated subsidiaries were taxed as corporations for federal and state income tax purposes, which resulted in deferred taxes. We were also subject to the Texas margin tax for partnership activity in the state of Texas.
The Company’sCompany had less than $0.1 million income tax benefit/(expense) was $4.3 million, $4.9 million, $0.1 million, $0.0 million and $(0.2) million for the three months ended September 30, 2017, the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017,March 31, 2019 and no income tax benefit/(expense) for the three months ended September 30, 2016 and the nine months ended September 30, 2016, respectively.March 31, 2018. The Company’s effective tax rate was 35.6%, 36.1%, 0.1%, 0.0% and (0.1%) for the three months ended September 30, 2017, the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017, the three months ended September 30, 2016March 31, 2019 and the nine months ended September 30, 2016,2018, respectively. The effective tax raterates for the three months ended September 30, 2017March 31, 2019 and the period from May 5, 2017 through September 30, 2017 is different from the statutory U.S. federal income tax rate due to the impact of state taxes, disallowed expenses and changes in the rate applied to historical balances. The effective tax rate for the period from January 1, 2017 through May 4, 2017, and the three and nine months ended September 30, 2016 is2018 are different from the statutory U.S. federal income tax rate primarily due to the Predecessor not being subject to U.S. federal income tax. Deferred tax benefit/(expense) of less than ($0.1) million and $0.1 million wasour recorded in income tax benefit for the Company’s change from a limited partnership to a corporation for the three months ended September 30, 2017 and the period from May 5, 2017 through September 30, 2017, respectively.valuation allowances.
Third-Party Midstream TransactionProposed Merger
In October 2017,On May 5, 2019, the Company, received approximately $15.5 millionMidstates Petroleum Company, Inc. (“Midstates”) and Midstates Holdings, Inc., a direct, wholly owned subsidiary of Midstates (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which, in an all-stock transaction, the Company will merge with and into Merger Sub, with the Company surviving as a wholly owned subsidiary of Midstates (the “Merger”). Pursuant to the Merger Agreement, Amplify Energy stockholders will receive 0.933 shares of Midstates common stock, par value $0.01 per share, for each share of Amplify Energy common stock that they hold (such newly issued common stock, the “Stock Issuance”). Following the closing of the Merger, current Amplify Energy and Midstates stockholders will each own 50% of the outstanding stock of the combined company.
Completion of the Merger is subject to the terms and conditions set forth in the Merger Agreement, including holders of a majority of votes cast by Midstates stockholders at the special meeting voting in favor of the Stock Issuance, holders of a majority of the issued and outstanding shares of Amplify common stock voting in favor of the Merger, the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and other customary closing conditions. Subject to the terms and conditions set forth in the Merger Agreement, the Merger is expected to close in the third quarter of 2019.
The foregoing description of the Merger Agreement is qualified in its entirety by reference to the Merger Agreement, which is attached as Exhibit 2.1 to the Company’s current report on Form 8-K filed on May 6, 2019.
24
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
First Amendment to Credit Agreement
On May 5, 2019, OLLC entered into the First Amendment to Credit Agreement, among OLLC, Amplify Acquisitionco Inc., Amplify Energy, the guarantors party thereto, the lenders party thereto and Bank of Montreal, as administrative agent (the “First Amendment”).
The First Amendment amends the New Revolving Credit Facility to, among other things (i) modify certain defined terms in connection with the salecompletion of a third-party midstream entitythe transactions contemplated by the Merger Agreement, including the Merger; (ii) allow certain structural changes for tax planning activities; and (iii) modify certain covenants in the New Revolving Credit Facility that restrict Amplify Energy’s ability to take certain actions or engage in certain business such that, once the First Amendment is effective, the occurrence of such actions or business in connection with whomthe Merger Agreement or completion of the transactions contemplated thereby, including the Merger, will not be so restricted.
Certain of the modifications to the New Revolving Credit Facility, including those permitting pre-Merger tax restrictions, became effective upon the signing of the First Amendment. The remaining modifications become effective concurrently with the consummation of the Merger, subject to certain closing conditions.
The First Amendment also contains customary representations, warranties and agreements of OLLC and the guarantors. All other material terms and conditions of the New Revolving Credit Facility were unchanged by the First Amendment.
The foregoing description of the First Amendment is qualified in its entirety by reference to the First Amendment, which is attached as Exhibit 10.1 to the Company’s natural gas gathering and processing agreements entitled Amplify Energy to a percentage of the proceeds in the event of a sale.
current report on Form 8-K filed on May 6, 2019.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Unaudited Condensed Consolidated Financial Statements and accompanying notes in “Item 1. Financial Statements” contained herein and our Annual Report on Form 10-K for the year ended December 31, 2016,2018, filed with the SEC on March 10, 20176, 2019 (“20162018 Form 10-K”). The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” in the front of this report.
OverviewReferences
When referring to Amplify Energy Corp. (formerly known as Memorial Production Partners LP and also(also referred to as “Successor,” “Amplify Energy,” or the “Company”), the intent is to refer to Amplify Energy, a newly formed Delaware corporation, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Amplify Energy is the successor reporting company of Memorial Production Partners LP (“MEMP”) pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). When referring to the “Predecessor” or the “Company” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to MEMP, the predecessor that was dissolved following the effective date of the Plan (as defined below) and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. The lenders that held 100% of the loans under the Predecessor’s revolving credit facility and with certain noteholders that held approximately 51.7% of the Predecessor’s 7.625% senior notes due 2021 (the “2021 Senior Notes”) and approximately 69.0% of the Predecessor’s 6.875% senior notes due 2022 (the “2022 Senior Notes,” and such holders collectively, the “Noteholders”) effectuated certain restructuring transactions, pursuant to which Amplify Energy acquired all of the assets of MEMP, and in accordance with the Plan, MEMP was dissolved.
Overview
We operate in one reportable segment engaged in the acquisition, development, explorationexploitation and production of oil and natural gas properties. Our management evaluates performance based on the reportable business segment as the economic environments are not different within the operation of our oil and natural gas properties. Our business activities are conducted through Amplify Energy Operating LLC (“OLLC”), our wholly owned subsidiary, and its wholly owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are principally located in Texas, Louisiana, Wyoming andthe Rockies, in federal waters offshore Southern California.California, East Texas / North Louisiana and South Texas. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristicsreservoirs. The Company’s properties consist primarily of operated and long-lived, predictable production profilesnon-operated working interests in producing and modest capital requirements.undeveloped leasehold acreage and working interests in identified producing wells. As of December 31, 2016:2018:
Our total estimated proved reserves were approximately 916.6841.1 Bcfe, of which approximately 43%65% were oilliquids and 73%79% were classified as proved developed reserves;
We produced from 2,4972,068 gross (1,488(1,125 net) producing wells across our properties, with an average working interest of 60%54% and the Company is the operator of record of the properties containing 94%92% of our total estimated proved reserves; and
Our average net production for the three months ended December 31, 20162018 was 205.5142.5 MMcfe/d, implying a reserve-to-production ratio of approximately 1216 years.
Recent Developments
Divestiture ProcessesProposed Merger
In October 2017,On May 5, 2019, the Company, launched divestiture processesMidstates Petroleum Company, Inc. (“Midstates”) and Midstates Holdings, Inc., a direct, wholly owned subsidiary of Midstates (“Merger Sub”) entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which, in an all-stock transaction, the Company will merge with and into Merger Sub, with the Company surviving as a wholly owned subsidiary of Midstates (the “Merger”). Pursuant to the Merger Agreement, Amplify Energy stockholders will receive 0.933 shares of Midstates common stock, par value $0.01 per share, for each share of Amplify Energy common stock that they hold (such newly issued common stock, the “Stock Issuance”). Following the closing of the Merger, current Amplify Energy and Midstates stockholders will each own 50% of the outstanding stock of the combined company. Following the closing of the Merger, current Amplify Energy and Midstates stockholders will each own 50% of the outstanding stock of the combined company and the combined company will continue to operate under the Amplify brand.
The boards of directors of both the Company and Midstates have unanimously approved the Merger Agreement and have recommended that their respective stockholders vote their shares in favor of the Merger or the Stock Issuance, as applicable.
Completion of the Merger is subject to the terms and conditions set forth in the Merger Agreement, including holders of a majority of votes cast by Midstates stockholders at the special meeting voting in favor of the Stock Issuance, holders of a majority of the issued and outstanding shares of Amplify common stock voting in favor of the Merger, the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and other customary closing conditions. The Company sought, and has received, a technical consent from the lenders in its existing credit facility permitting the consummation of the Merger. Subject to the terms and conditions set forth in the Merger Agreement, the Merger is expected to close in the third quarter of 2019.
The foregoing description of the Merger Agreement is qualified in its entirety by reference to the Merger Agreement, which is attached as Exhibit 2.1 to the Company’s East Texas assetscurrent report on Form 8-K filed on May 6, 2019.
First Amendment to Credit Agreement
On May 5, 2019, Amplify Energy Operating LLC (“OLLC”), a wholly owned subsidiary of Amplify Energy, entered into the First Amendment to Credit Agreement, among OLLC, Amplify Acquisitionco Inc., Amplify Energy, the guarantors party thereto, the lenders party thereto and Rockies CO2 assets in Wyoming. Additionally,Bank of Montreal, as administrative agent (the “First Amendment”).
The First Amendment amends the Company continuesparties’ existing Credit Agreement, dated as of November 2, 2018 (the “New Revolving Credit Facility”) to, market its South Texas conventional and Eagle Ford assets.
Third-Party Midstream Transaction
In October 2017, the Company received approximately $15.5 millionamong other things (i) modify certain defined terms in connection with the salecompletion of a third-party midstream entitythe transactions contemplated by the Merger Agreement, including the Merger; (ii) allow certain structural changes for tax planning activities; and (iii) modify certain covenants in the New Revolving Credit Facility that restrict Amplify Energy’s ability to take certain actions or engage in certain business such that, once the First Amendment is effective, the occurrence of such actions or business in connection with whomthe Merger Agreement or completion of the transactions contemplated thereby, including the Merger, will not be so restricted.
Certain of the modifications to the New Revolving Credit Facility, including those permitting pre-Merger tax restrictions, became effective upon the signing of the First Amendment. The remaining modifications become effective concurrently with the consummation of the Merger, subject to certain closing conditions.
The First Amendment also contains customary representations, warranties and agreements of OLLC and the guarantors. All other material terms and conditions of the New Revolving Credit Facility were unchanged by the First Amendment.
The foregoing description of the First Amendment is qualified in its entirety by reference to the First Amendment, which is attached as Exhibit 10.1 to the Company’s natural gas gathering and processing agreements entitled Amplify Energy to a percentagecurrent report on Form 8-K filed on May 6, 2019.
Resignation of Director
On March 22, 2019, P. Michael Highum resigned from the board of directors of the proceeds inCompany. Mr. Highum served on the eventCompany’s audit committee. There were no known disagreements between Mr. Highum and the Company which led to Mr. Highum’s resignation from the board of a sale.
Predecessor and Successor Reporting
As a resultdirectors of the applicationCompany.
Appointment of fresh start accounting,Director
On March 22, 2019, Scott L. Hoffman was appointed to the Company’s Unaudited 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 applicationboard of different basis of accounting between the periods presented. Despite this separate presentation, there was continuitydirectors of the Company’s operations.
See Note 3Company. Mr. Hoffman has been appointed to the audit committee of the Notesboard of directors. There are no arrangements or understandings between Mr. Hoffman and any other persons pursuant to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements”which Mr. Hoffman was selected as a director of this quarterly report for additional information.the Company.
Business Environment and Operational Focus
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: (i) production volumes; (ii) realized prices on the sale of our production; (iii) cash settlements on our commodity derivatives; (iv) lease operating expense; (v) gathering, processing and transportation; (vi) general and administrative expense; and (vii) Adjusted EBITDA (defined below).
Sources of Revenues
Our revenues are derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from natural gas during processing. Production revenues are derived entirely from the continental United States. Natural gas, NGL and oil prices are inherently volatile and are influenced by many factors outside our control. In order to reduce the impact of fluctuations in natural gas and oil prices on revenues, we intend to periodically enter into derivative contracts that fix the future prices received. At the end of each period the fair value of these commodity derivative instruments are estimated and because hedge accounting is not elected, the changes in the fair value of unsettled commodity derivative instruments are recognized in earnings at the end of each accounting period.
Principal Components of Cost Structure
|
|
Gathering, processing and transportation. These are costs incurred to deliver production of our natural gas, NGLs and oil to the market. Cost levels of these expenses can vary based on the volume of natural gas, NGLs and oil production.
Exploration expense. These are geological and geophysical costs and include seismic costs, costs of unsuccessful exploratory dry holes, delay rentals and unsuccessful leasing efforts.
Taxes other than income. These consist of production, ad valorem and franchise taxes. Production taxes are paid on produced natural gas, NGLs and oil based on a percentage of market prices and at fixed per unit rates established by state or local taxing authorities. We take full advantage of all credits and exemptions in the various taxing jurisdictions where we operate. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties. Franchise taxes are privilege taxes levied by states that are imposed on companies, including limited liability companies and partnerships, which give the businesses the right to be chartered or operate within that state.
Depreciation, depletion and amortization. Depreciation, depletion and amortization, or DD&A, includes the systematic expensing of the capitalized costs incurred to acquire, exploit and develop oil and natural gas properties. As a “successful efforts” company, all costs associated with acquisition and development efforts and all successful exploration efforts are capitalized, and these costs are depleted using the units of production method.
Impairment of proved properties. Proved properties are impaired whenever the carrying value of the properties exceeds their estimated undiscounted future cash flows.
General and administrative expense. These costs include overhead, including payroll and benefits for employees, costs of maintaining headquarters, costs of managing production and development operations, compensation expense associated with certain long-term incentive-based plans, audit and other professional fees and legal compliance expenses.
Prior to June 1, 2016, Memorial Resource provided management, administrative and operating services to the Predecessor and the Predecessor’s general partner pursuant to our Predecessor’s Omnibus Agreement. Upon completion of the MEMP GP Acquisition, the Predecessor’s Omnibus Agreement was terminated and the Predecessor entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. See Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
Accretion expense. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value.
Interest expense. We finance a portion of our working capital requirements and acquisitions with borrowings under our Exit Credit Facility. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and financing decisions. We expect to continue to incur significant interest expense.
Critical Accounting Policies and Estimates
A discussion of our critical accounting policies and estimates is included in our 20162018 Form 10-K. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. These estimates, in our opinion, are subjective in nature, require the use of professional judgment and involve complex analysis.
When used in the preparation of our consolidated financial statements, such estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.
Beginning in 2019, the Company elected to change its reporting convention from natural gas equivalent (Mcfe) to barrels of oil equivalent (Boe). The change in presentation reflects our liquids-weighted production and reserve profile with a balanced approach to development of our oil and natural gas asset portfolio. The Company’s proved reserves as of year-end 2018 were 50% crude oil, 15% natural gas liquids and 35% natural gas.
The results of operations for the three months ended September 30, 2017, for the period from May 5, 2017 through September 30, 2017, for the period from January 1, 2017 through May 4, 2017March 31, 2019 and for the three and nine months ended September 30, 20162018 have been derived from our consolidated financial statements.
The following table summarizes certain of the results of operations for the periods indicated (in thousands).indicated.
| Successor |
|
|
| Predecessor |
| ||
| Three Months Ended |
|
|
| Three Months Ended |
| ||
| September 30, 2017 |
|
|
| September 30, 2016 |
| ||
Oil and natural gas sales | $ | 75,534 |
|
|
| $ | 74,222 |
|
Lease operating expense |
| 29,119 |
|
|
|
| 31,575 |
|
Gathering, processing and transportation |
| 7,077 |
|
|
|
| 8,519 |
|
Taxes other than income |
| 4,214 |
|
|
|
| 3,945 |
|
Depreciation, depletion and amortization |
| 13,467 |
|
|
|
| 43,219 |
|
Impairment of proved oil and natural gas properties |
| — |
|
|
|
| — |
|
General and administrative expense |
| 11,097 |
|
|
|
| 12,605 |
|
Accretion of asset retirement obligations |
| 1,665 |
|
|
|
| 2,383 |
|
(Gain) loss on commodity derivative instruments |
| 14,217 |
|
|
|
| (21,938 | ) |
(Gain) loss on sale of properties |
| — |
|
|
|
| 60 |
|
Interest expense, net |
| (5,808 | ) |
|
|
| (27,209 | ) |
Gain on extinguishment of debt |
| — |
|
|
|
| 673 |
|
Reorganization items, net |
| (33 | ) |
|
|
| — |
|
Income tax benefit (expense) |
| 4,348 |
|
|
|
| — |
|
Net income (loss) |
| (7,536 | ) |
|
|
| (32,866 | ) |
|
|
|
|
|
|
|
|
|
Oil and natural gas revenue: |
|
|
|
|
|
|
|
|
Oil sales | $ | 40,750 |
|
|
| $ | 35,271 |
|
NGL sales |
| 9,927 |
|
|
|
| 8,041 |
|
Natural gas sales |
| 24,857 |
|
|
|
| 30,910 |
|
Total oil and natural gas revenue | $ | 75,534 |
|
|
| $ | 74,222 |
|
|
|
|
|
|
|
|
|
|
Production volumes: |
|
|
|
|
|
|
|
|
Oil (MBbls) |
| 923 |
|
|
|
| 906 |
|
NGLs (MBbls) |
| 437 |
|
|
|
| 515 |
|
Natural gas (MMcf) |
| 8,158 |
|
|
|
| 11,136 |
|
Total (MMcfe) |
| 16,317 |
|
|
|
| 19,665 |
|
Average net production (MMcfe/d) |
| 177.4 |
|
|
|
| 213.8 |
|
|
|
|
|
|
|
|
|
|
Average sales price: |
|
|
|
|
|
|
|
|
Oil (per Bbl) | $ | 44.16 |
|
|
| $ | 38.95 |
|
NGL (per Bbl) |
| 22.72 |
|
|
|
| 15.59 |
|
Natural gas (per Mcf) |
| 3.05 |
|
|
|
| 2.78 |
|
Total (per Mcfe) | $ | 4.63 |
|
|
| $ | 3.77 |
|
|
|
|
|
|
|
|
|
|
Average unit costs per Mcfe: |
|
|
|
|
|
|
|
|
Lease operating expense | $ | 1.78 |
|
|
| $ | 1.61 |
|
Gathering, processing and transportation |
| 0.43 |
|
|
|
| 0.43 |
|
Taxes other than income |
| 0.26 |
|
|
|
| 0.20 |
|
General and administrative expense |
| 0.68 |
|
|
|
| 0.64 |
|
Depletion, depreciation and amortization |
| 0.83 |
|
|
|
| 2.20 |
|
Successor |
|
|
| Predecessor |
| ||||||||||||||
| Period from |
|
|
| Period from |
|
|
|
|
| |||||||||
| May 5, 2017 |
|
|
| January 1, 2017 |
|
| Nine Months |
| For the Three Months Ended |
| ||||||||
| through |
|
|
| through |
|
| Ended |
| March 31, |
| ||||||||
| September 30, 2017 |
|
|
| May 4, 2017 |
|
| September 30, 2016 |
| 2019 |
|
| 2018 |
| |||||
| (In thousands) |
|
|
| (In thousands) |
| ($ In thousands) |
| |||||||||||
Oil and natural gas sales | $ | 117,762 |
|
|
| $ | 108,970 |
|
| $ | 202,625 |
| $ | 65,067 |
|
| $ | 87,847 |
|
Lease operating expense |
| 47,961 |
|
|
|
| 35,568 |
|
|
| 96,625 |
|
| 28,910 |
|
|
| 29,570 |
|
Gathering, processing and transportation |
| 11,191 |
|
|
|
| 10,772 |
|
|
| 26,551 |
|
| 4,657 |
|
|
| 5,600 |
|
Taxes other than income |
| 6,147 |
|
|
|
| 5,187 |
|
|
| 11,438 |
|
| 4,409 |
|
|
| 5,037 |
|
Depreciation, depletion and amortization |
| 21,818 |
|
|
|
| 37,717 |
|
|
| 132,061 |
|
| 11,166 |
|
|
| 12,958 |
|
Impairment of proved oil and natural gas properties |
| — |
|
|
|
| — |
|
|
| 8,342 |
| |||||||
General and administrative expense |
| 18,479 |
|
|
|
| 31,606 |
|
|
| 41,375 |
|
| 9,308 |
|
|
| 10,657 |
|
Accretion of asset retirement obligations |
| 2,692 |
|
|
|
| 3,407 |
|
|
| 7,802 |
|
| 1,311 |
|
|
| 1,718 |
|
(Gain) loss on commodity derivative instruments |
| 12,302 |
|
|
|
| (23,076 | ) |
|
| 50,897 |
|
| 32,487 |
|
|
| 10,456 |
|
(Gain) loss on sale of properties |
| — |
|
|
|
| — |
|
|
| (3,575 | ) |
| — |
|
|
| 2,373 |
|
Interest expense, net |
| (9,605 | ) |
|
|
| (10,243 | ) |
|
| (91,904 | ) |
| (4,089 | ) |
|
| (5,772 | ) |
Gain on extinguishment of debt |
| — |
|
|
|
| — |
|
|
| 42,337 |
| |||||||
Reorganization items, net |
| (382 | ) |
|
|
| (88,774 | ) |
|
| — |
|
| (187 | ) |
|
| (518 | ) |
Income tax benefit (expense) |
| 4,940 |
|
|
|
| 91 |
|
|
| (196 | ) |
| 50 |
|
|
| — |
|
Net income (loss) |
| (8,442 | ) |
|
|
| (90,955 | ) |
|
| (218,513 | ) |
| (31,477 | ) |
|
| 3,239 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales | $ | 62,820 |
|
|
| $ | 55,767 |
|
| $ | 102,021 |
| $ | 40,057 |
|
| $ | 54,726 |
|
NGL sales |
| 14,039 |
|
|
|
| 14,103 |
|
|
| 23,224 |
|
| 5,865 |
|
|
| 10,946 |
|
Natural gas sales |
| 40,903 |
|
|
|
| 39,100 |
|
|
| 77,380 |
|
| 19,145 |
|
|
| 22,175 |
|
Total oil and natural gas revenue | $ | 117,762 |
|
|
| $ | 108,970 |
|
| $ | 202,625 |
| $ | 65,067 |
|
| $ | 87,847 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
| 1,450 |
|
|
|
| 1,204 |
|
|
| 2,928 |
|
| 752 |
|
|
| 902 |
|
NGLs (MBbls) |
| 658 |
|
|
|
| 616 |
|
|
| 1,768 |
|
| 265 |
|
|
| 412 |
|
Natural gas (MMcf) |
| 13,250 |
|
|
|
| 12,411 |
|
|
| 34,688 |
|
| 5,490 |
|
|
| 7,775 |
|
Total (MMcfe) |
| 25,893 |
|
|
|
| 23,336 |
|
|
| 62,866 |
| |||||||
Average net production (MMcfe/d) |
| 173.8 |
|
|
|
| 188.2 |
|
|
| 229.4 |
| |||||||
Total (Boe) |
| 1,932 |
|
|
| 2,610 |
| ||||||||||||
Average net production (MBoe/d) |
| 21.5 |
|
|
| 29.0 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) | $ | 43.35 |
|
|
| $ | 46.28 |
|
| $ | 34.84 |
| $ | 53.28 |
|
| $ | 60.66 |
|
NGL (per Bbl) |
| 21.34 |
|
|
|
| 22.90 |
|
|
| 13.13 |
|
| 22.09 |
|
|
| 26.57 |
|
Natural gas (per Mcf) |
| 3.09 |
|
|
|
| 3.15 |
|
|
| 2.23 |
|
| 3.49 |
|
|
| 2.85 |
|
Total (per Mcfe) | $ | 4.55 |
|
|
| $ | 4.67 |
|
| $ | 3.22 |
| |||||||
Total (per MBoe) | $ | 33.67 |
|
| $ | 33.66 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average unit costs per Mcfe: |
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Average unit costs per MBoe: |
|
|
|
|
|
|
| ||||||||||||
Lease operating expense | $ | 1.85 |
|
|
| $ | 1.52 |
|
| $ | 1.54 |
| $ | 14.96 |
|
| $ | 11.33 |
|
Gathering, processing and transportation |
| 0.43 |
|
|
|
| 0.46 |
|
|
| 0.42 |
|
| 2.41 |
|
|
| 2.15 |
|
Taxes other than income |
| 0.24 |
|
|
|
| 0.22 |
|
|
| 0.18 |
|
| 2.28 |
|
|
| 1.93 |
|
General and administrative expense |
| 0.71 |
|
|
|
| 1.35 |
|
|
| 0.66 |
|
| 4.82 |
|
|
| 4.08 |
|
Depletion, depreciation and amortization |
| 0.84 |
|
|
|
| 1.62 |
|
|
| 2.10 |
|
| 5.78 |
|
|
| 4.97 |
|
For the Three Months Ended September 30, 2017 andthree months ended March 31, 2019 compared to the Three Months Ended September 30, 2016three months ended March 31, 2018
A netNet loss of $7.5$31.5 million and $32.9net income of $3.2 million waswere recorded for the three months ended September 30, 2017March 31, 2019 and 2016,2018, respectively.
Oil, natural gas and NGL revenues were $75.5$65.1 million and $74.2$87.8 million for the three months ended September 30, 2017March 31, 2019 and 2016,2018, respectively. Average net production volumes were approximately 177.4 MMcfe/21.5 MBoe/d and 213.8 MMcfe/29.0 MBoe/d for the three months ended September 30, 2017March 31, 2019 and 2016,2018, respectively. The change in production volumes was primarily from divestitures.due to the natural decline of wells, decreased drilling activity and the divestiture of certain non-core assets located in South Texas (the “South Texas Divestiture”). The average realized sales price was $4.63$33.67 per McfeMBoe and $3.77$33.66 per McfeMBoe for the three months ended September 30, 2017and 2016,March 31, 2019 and 2018, respectively. The increase was primarily due to increases in realized prices for oil, natural gas and NGLs.
Lease operating expense was $29.1$28.9 million and $31.6$29.6 million for the three months ended September 30, 2017March 31, 2019 and 2016,2018, respectively. The change in lease operating expense was primarily a result of the Permian Divestiture and Rockies Divestiture.related to lower production. On a per McfeMBoe basis, lease operating expense was $1.78$14.96 and $1.61$11.33 for the three months ended September 30, 2017March 31, 2019 and 2016,2018, respectively. The change in lease operating expense on a per McfeMBoe basis was primarily relateddue to lower production.
Taxes other than income were $4.2Gathering, processing and transportation was $4.7 million and $3.9$5.6 million for the three months ended September 30, 2017March 31, 2019 and 2016,2018, respectively. The change in gathering, processing and transportation was primarily the result of lower production. On a per MBoe basis, gathering, processing and transportation was $2.41 and $2.15 for the three months ended March 31, 2019 and 2018, respectively.
Taxes other than income was $4.4 million and $5.0 million for the three months ended March 31, 2019 and 2018, respectively. On a per McfeMBoe basis, taxes other than income were $0.26$2.28 and $0.20$1.93 for the three months ended September 30, 2017March 31, 2019 and 2016,2018, respectively. The change in taxes other than income on a per McfeMBoe basis was primarily due to an increase in commodity price.
DD&A expense was $13.5$11.2 million and $43.2$13.0 million for the three months ended September 30, 2017March 31, 2019 and 2016,2018, respectively. The change in DD&A expense was primarily due to lower rates as a result of the application of fresh start accounting and a decrease in production volumes.volumes and the South Texas Divestiture, which closed on May 30, 2018 and which assets were accounted for as assets held for sale for the period from March 31, 2018 through the closing date.
General and administrative expense was $11.1$9.3 million and $12.6$10.7 million for the three months ended September 30, 2017March 31, 2019 and 2016,2018, respectively. Non-cash share/unit-basedshare-based compensation expense was approximately $1.0$1.9 million and $2.1$1.2 million for the three months ended September 30, 2017March 31, 2019 and 2016,2018, respectively.
Net losses on commodity derivative instruments of $14.2$32.5 million were recognized for the three months ended September 30, 2017,March 31, 2019, consisting of $13.0$31.2 million decrease in the fair value of open positions and $1.3 million of cash settlements paid on expired positions. Net losses on commodity derivative instruments of $10.5 million were recognized for the three months ended March 31, 2018, consisting of $4.8 million of cash settlement receipts on expired positions offset by a $27.2$15.3 million decrease in the fair value of open positions. Net gains on commodity derivative instruments of $21.9 million were recognized for the three months ended September 30, 2016, consisting of $36.9 million of cash settlement receipts on expired positions partially offset by a $15.0 million decrease in the fair value of open positions.
Given the volatility of commodity prices, it is not possible to predict future reported mark-to-market net gains or losses and the actual net gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If commodity prices at settlement are lower than the prices of the hedge positions, the hedges are expected to partially mitigate the otherwise negative effect on earnings of lower oil, natural gas and NGL prices. However, if commodity prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher oil, natural gas and NGL prices and will, in this context, be viewed as having resulted in an opportunity cost.
Interest expense, net was $5.8$4.1 million and $27.2$5.8 million for the three months ended September 30, 2017March 31, 2019 and 2016,2018, respectively. NoInterest expense, net for 2019 included losses of interest rate swaps of approximately $0.1 million and amortization of deferred financing fees of $0.3 million. Interest expense, net for 2018 included amortization of deferred financing fees of $0.5 million. The change in interest expense relatedis primarily due to the Notes was recognizeda $1.5 million reduction in interest expense due to lower outstanding borrowings for the three months ended September 30, 2017, as the NotesMarch 31, 2019.
Average outstanding borrowings under our New Revolving Credit Facility were cancelled on the Effective Date. For the three months ended September 30, 2016, the Company recorded $20.3 million of interest expense related to the Notes. Additionally, the Company recognized a gain on interest rate swaps of $1.4$278.0 million for the three months ended September 30, 2016, and no expensesMarch 31, 2019. Average outstanding borrowings under our Emergence Credit Facility were recognized$364.2 million for the three months ended September 30,March 31, 2018.
Reorganization items, net represents costs and income directly associated with the Company’s Chapter 11 proceedings since January 16, 2017, due to the termination of the interest rate swaps in the fourth quarter of 2016.petition date, such as advisor and professional fees. The Company recognized $0.6incurred $0.2 million and $1.3$0.5 million in amortization of deferred financing cost for the three months ended September 30, 2017March 31, 2019 and 2016,2018, respectively. The Company recorded $0.6 million in accretion of the Notes discount for the three months ended September 30, 2016. No expense was recorded for the three months ended September 30, 2017, as the unamortized amount of accretion of the Notes discount was written off in the fourth quarter of 2016. See Note 2 and Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements under “Item 1. Financial Statements” of this quarterly report for additional information.
Average outstanding borrowings under our Exit Credit Facility were $411.2 million for the three months ended September 30, 2017. Average outstanding borrowings under our Predecessor’s revolving credit facility were $715.0 million for the three months ended September 30, 2016. We had an average of $1.1 billion aggregate principal amount of the Notes issued and outstanding for the three months ended September 30, 2016. The Notes were cancelled on the Effective Date.
For the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the Nine Months Ended September 30, 2016
A net loss of $8.4 million, $91.0 million and $218.5 million was recorded for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively.
Oil, natural gas and NGL revenues were $117.8 million, $109.0 million and $202.6 million for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. Average net production volumes were approximately 173.8 MMcfe/d, 188.2 MMcfe/d and 229.4 MMcfe/d for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 to May 4, 2017 and the nine months ended September 30, 2016, respectively. The change in production volumes was primarily related to decreases in drilling activities and divestitures. The average realized sales price was $4.55 per Mcfe, $4.67 per Mcfe and $3.22 per Mcfe for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. The change in the average realized sales price was primarily due to increases in realized prices for oil, natural gas and NGLs.
Lease operating expense was $48.0 million, $35.6 million and $96.6 million for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. The change in lease operating expense was the result of decreased workover activity and the Permian Divestiture and Rockies Divestiture. On a per Mcfe basis, lease operating expense was $1.85, $1.52 and $1.54 for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. The change in lease operating expense on a per Mcfe basis was primarily related to lower production.
Gathering, processing and transportation was $11.2 million, $10.8 million and $26.6 million for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. The change in gathering, processing and transportation was primarily due to lower production. On a per Mcfe basis, gathering, processing and transportation was $0.43, $0.46, and $0.42 for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively.
Taxes other than income were $6.1 million, $5.2 million and $11.4 million for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. On a per Mcfe basis, taxes other than income were $0.24, $0.22 and $0.18 for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. The change in taxes other than income on a per Mcfe basis was due to an increase in commodity prices.
DD&A expense was $21.8 million, $37.7 million and $132.1 million for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. The change in DD&A expense was primarily due to lower rates as a result of the application of fresh start accounting and a decrease in production volumes.
No impairments were recognized for the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017. We recognized $8.3 million of impairments for the nine months ended September 30, 2016 related to certain properties in East Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily due to a downward revision of estimated proved reserves as a result of significant declines in commodity prices.
General and administrative expense was $18.5 million, $31.6 million and $41.4 million for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. Non-cash share/unit-based compensation expense was approximately $1.5 million, $3.7 million and $7.4 million for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. Additionally, the Company recorded $7.5 million in pre-petition restructuring-related costs primarily for advisory and professional fees for the period from January 1, 2017 through May 4, 2017.
Interest expense, net was $9.6 million, $10.2 million and $91.9 million for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. The change in interest expense was primarily due to the Company not recording interest expense on the Notes for the period from the Petition Date through the Effective Date. The Company recorded $3.5 million and $63.8 million in interest expense related to the Notes for the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. No interest expense was recorded on the Notes for the period from May 5, 2017 through September 30, 2017, as the Notes were cancelled on the Effective Date. Additionally, the Company recognized losses on interest rate swaps of $4.1 million for the nine months ended September 30, 2016, and no expenses were recognized for the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017 due to the termination of the interest rate swaps in the fourth quarter of 2016. The Company recognized $0.9 million and $3.9 million in amortization of deferred financing cost for the period from May 5, 2017 through September 30, 2017 and the nine months ended September 30, 2016, respectively. No amortization of deferred financing cost was recorded for the period from January 1, 2017 through May 4, 2017, as the unamortized amount of deferred financing cost was written off in the fourth quarter of 2016. The Company recorded $1.8 million of accretion of the Notes discount for the nine months ended September 30, 2016. No expense was recorded for the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, as the unamortized amount of accretion of the Notes discount was written off in the fourth quarter of 2016. See Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements under “Item 1. Financial Statements” of this quarterly report for additional information.
Average outstanding borrowings under our Exit Credit Facility were $416.4 million for the period from May 5, 2017 through September 30, 2017. Average outstanding borrowings under our Predecessor’s revolving credit facility were $460.2 million and $765.7 million for the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. We had an average of $1.1 billion aggregate principal amount of the Notes issued and outstanding for the period from January 1, 2017 through May 4, 2017. The Notes were cancelled on the Effective Date. We had an average of $1.2 billion aggregate principal amount of the Notes issued and outstanding for the nine months ended September 30, 2016.
The Company has incurred significant costs associated with the reorganization. Reorganization items, net represents costs and income directly associated with the Chapter 11 proceedings since the Petition Date, such as the gain on settlement of liabilities subject to compromise, fresh start valuation adjustments and professional fees. The Company incurred $0.4 million and $88.8 million of reorganization items, net for the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively. See Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements under “Item 1. Financial Statements” of this quarterly report for additional information.
We recognized a gain on extinguishment of debt of approximately $42.3 million for the nine months ended September 30, 2016 related to the repurchase of certain of the 2021 Senior Notes and 2022 Senior Notes.
Liquidity and Capital Resources
Overview. Our ability to finance our operations, including funding capital expenditures and acquisitions, meet our indebtedness obligations, refinance our indebtedness or meet our collateral requirements will depend on our ability to generate cash in the future. Our primary sources of liquidity and capital resources have historically been cash flows generated by operating activities, borrowings under our Predecessor’s revolving credit facility and equity and debt capital markets. For the remainder of 2017, we expect our primary funding sources to be cash flows generated by operating activities, available borrowing capacity under our Exit Credit Facility and/or the divestiture of assets.
If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures, and/or fund a portion of our capital expenditures using borrowings under our Exit Credit Facility, issuances of debt and equity securities or other sources, such as asset divestitures. Needed capital may not be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by many factors, including the covenants in our Exit Credit Facility. If we are unable to obtain funds when needed or on acceptable terms, we may be unable to finance the capital expenditures necessary to maintain our production or proved reserves.
As a result of our Chapter 11 proceedings and the effectiveness of the Plan, the holders of claims under the Predecessor’s revolving credit facility received a full recovery, consisting of a cash pay down and their pro rata share of the Exit Credit Facility. In addition, the Notes were cancelled and the Predecessor’s liability thereunder discharged, as further discussed below under “— Debt Agreements.”
Capital Markets. We do not currently anticipate any near-term capital markets activity, but we will continue to evaluate the availability of public debt and equity for funding potential future growth projects and acquisition activity.
Hedging. Commodity hedging has been and remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil, NGL, and natural gas prices at targeted levels and to manage our exposure to commodity price fluctuations. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 50% of our estimated production from total proved developed producing reserves over a one-to-three year period at any given point of time to satisfy the hedging covenants in our Exit Credit Facility. We may, however, from time to time, hedge more or less than this approximate amount. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. The current market conditions may also impact our ability to enter into future commodity derivative contracts. For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of September 30, 2017, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.”
We evaluate counterparty risks related to our commodity derivative contracts and trade credit. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices. We sell our oil and natural gas to a variety of purchasers. Non-performance by a customer could also result in losses.
Capital Expenditures. Our total capital expenditures were approximately $39.8 million and $9.5 million, for the period from May 5, 2017 through September 30, 2017 and the period from January 1, 2017 through May 4, 2017, respectively, which were primarily related to drilling, capital workovers and facilities located in East Texas, South Texas and California.
Government Trust Account. In 2015, the Bureau of Safety and Environmental Enforcement issued a preliminary report that indicated the estimated cost of decommissioning the offshore production facilities associated with our Beta properties in offshore Southern California may further increase. The implementation of this increase is currently on hold and we do not expect resolution of a negotiated decommissioning estimate until 2018. At September 30, 2017, there was approximately $152.2 million in the Rise Energy Operating, LLC trust account and $62.0 million in surety bonds.
Working Capital. We expect to fund our working capital needs primarily with operating cash flows. We also plan to reinvest a sufficient amount of our operating cash flow to fund our expected capital expenditures. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements. See Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” and “— Overview” of this quarterly report for additional information.
As of September 30, 2017, we had working capital of $28.0 million primarily due to a current derivative asset balance of $41.4 million partially offset by the timing of accruals, which included accrued general and administrative expense of approximately $5.6 million, accrued capital expenditures of approximately $10.5 million, accrued lease operating expense of approximately $8.9 million, accrued ad valorem tax of approximately $3.1 million and accrued interest payable of approximately $1.3 million.
Debt Agreements
Exit Credit Facility. On May 4, 2017, OLLC, as borrower, entered into the Exit Credit Facility with Wells Fargo Bank, National Association, as administrative agent. Pursuant to the Credit Agreement the lenders party thereto agreed to provide OLLC with a $1 billion exit senior secured reserve-based Exit Credit Facility. Our borrowing base is subject to redetermination on at least a semi-annual basis primarily based on a reserve engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the prevailing natural gas, oil, and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. The borrowing base as of September 30, 2017, was approximately $480.0 million.
As of September 30, 2017, we were in compliance with all the financial (interest coverage ratio, current ratio and total leverage ratio) and other covenants associated with our Exit Credit Facility.
As of September 30, 2017, we had approximately $74.5 million of available borrowings under our Exit Credit Facility, net of $2.5 million in letters of credit. See Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information regarding the Exit Credit Facility.
See Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
Cash Flows from Operating, Investing and Financing Activities
The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016 have been derived from our consolidated financial statements. For information regarding the individual components of our cash flow amounts, see the Unaudited Condensed Statements of Consolidated Cash Flows included under “Item 1. Financial Statements” of this quarterly report.
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Net cash provided by operating activities | $ | 57,874 |
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| $ | 117,937 |
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Net cash used in investing activities |
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Net cash used in financing activities |
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Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $57.9 million, $117.9 million and $199.1 million for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. Production volumes were approximately 173.8 MMcfe/d, 188.2 MMcfe/d and 229.4 MMcfe/d for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. The average realized sales price was $4.55 per Mcfe, $4.67 per Mcfe and $3.22 per Mcfe for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. Lease operating expenses were $48.0 million, $35.6 million and $96.6 million for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively. Gathering, processing and transportation was $11.2 million, $10.8 million and $26.6 million for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively.
Investing Activities. Net cash used in investing activities for the period from May 5, 2017 through September 30, 2017 was $28.0 million, of which $27.7 million was used for additions to oil and natural gas properties. Net cash used in investing activities for the period from January 1, 2017 through May 4, 2017 was $6.5 million, of which $6.2 million was used for additions to oil and natural gas properties. Net cash used in investing activities for the nine months ended September 30, 2016 was $9.1 million, of which $50.5 million was used for additions to oil and natural gas properties and $7.6 million was used for additions to other property and equipment. These amounts were partially offset by $54.7 million of proceeds from sale of oil and natural gas properties for the nine months ended September 30, 2016. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California oil and natural gas properties. Additions to restricted investments were $0.3 million, $0.2 million and $5.6 million for the period from May 5, 2017 through September 30, 2017, the period from January 1, 2017 through May 4, 2017 and the nine months ended September 30, 2016, respectively.
Financing Activities. The Company had net repayments of $27.0 million under the Exit Credit Facility and made $8.2 million in payments to the holders of the Notes, $1.3 million in payments to the Predecessor common unitholders and received a $1.5 million contribution from management in accordance with the Plan for the period from May 5, 2017 through September 30, 2017. The Company had net repayments of $81.7 million under the Predecessor’s revolving credit facility, made $16.4 million in payments to the holders of the Notes and paid $8.6 million in deferred financing costs for the period from January 1, 2017 through May 4, 2017. The Company had net repayments of $122.0 million under the Predecessor’s revolving credit facility for the nine months ended September 30, 2016. Distributions to partners for the nine months ended September 30, 2016 were $13.3 million.
We repurchased an aggregate principal amount of approximately $85.7 million of the Notes for $41.3 million for the nine months ended September 30, 2016.
We sold 1,178,102 Predecessor common units under the ATM Program and generated net proceeds of $2.1 million for the nine months ended September 30, 2016.
We include in this report the non-GAAP financial measure Adjusted EBITDA and provide our reconciliation of Adjusted EBITDA to net income and net cash flows from operating activities, our most directly comparable financial measures calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss):
Plus:
Interest expense;
Income tax expense;
Depreciation, depletion and amortization (“DD&A”);
Impairment of goodwill and long-lived assets (including oil and natural gas properties);
Accretion of asset retirement obligations (“AROs”);
Loss on commodity derivative instruments;
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Cash settlements received on expired commodity derivative instruments;
Losses on sale of assets;
Share/unit basedunit-based compensation expenses;
Exploration costs;
Acquisition and divestiture related expenses;
Amortization of gain associated with terminated commodity derivatives;
Bad debt expense;
Restructuring related costs;
Reorganization items, net;
Severance payments; and
Other non-routine items that we deem appropriate.
Less:
Interest income;
Income tax benefit;
Gain on commodity derivative instruments;
Cash settlements paid on expired commodity derivative instruments;
Gains on sale of assets and other, net; and
Other non-routine items that we deem appropriate.
We believe that Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, research analysts and rating agencies,useful because it allows us to assess:
more effectively evaluate our operating performance as comparedand compare the results of our operations from period to that of other companies and partnerships in our industry,period without regard to our financing methods or capital structurestructure.
Adjusted EBITDA should not be considered as an alternative to, or historical cost basis;
the abilitymore meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to generate cash sufficientother similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to pay interest costs and supportmeasure our indebtedness; andability to meet debt service requirements.
the viability of projects and the overall rates of return on alternative investment opportunities.
In addition, management uses Adjusted EBITDA to evaluate actual cash flow available to develop existing reserves or acquire additional oil and natural gas properties.
Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.
The following tables present our reconciliation of Adjusted EBITDA to net income and net cash flows from operating activities, our most directly comparable GAAP financial measures, for each of the periods indicated.
Reconciliation of Adjusted EBITDA to Net Income (Loss)
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Net income (loss) | $ | (7,536 | ) |
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| $ | (32,866 | ) |
| $ | (8,442 | ) |
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| $ | (90,955 | ) |
| $ | (218,513 | ) | $ | (31,477 | ) |
| $ | 3,239 |
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Interest expense, net |
| 5,808 |
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| 27,209 |
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| 9,605 |
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| 10,243 |
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| 91,904 |
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| 4,089 |
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| 5,772 |
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Gain on extinguishment of debt |
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Income tax expense (benefit) |
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| (4,940 | ) |
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| (91 | ) |
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| 196 |
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DD&A |
| 13,467 |
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| 43,219 |
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| 21,818 |
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| 37,717 |
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| 132,061 |
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| 11,166 |
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| 12,958 |
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Impairment of proved oil and gas properties |
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| — |
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| — |
|
|
|
| — |
|
|
| 8,342 |
| |||||||
Accretion of AROs |
| 1,665 |
|
|
|
| 2,383 |
|
|
| 2,692 |
|
|
|
| 3,407 |
|
|
| 7,802 |
|
| 1,311 |
|
|
| 1,718 |
|
(Gains) losses on commodity derivative instruments |
| 14,217 |
|
|
|
| (21,938 | ) |
|
| 12,302 |
|
|
|
| (23,076 | ) |
|
| 50,897 |
|
| 32,487 |
|
|
| 10,456 |
|
Cash settlements received (paid) on expired commodity derivative instruments |
| 12,992 |
|
|
|
| 36,876 |
|
|
| 21,276 |
|
|
|
| 15,895 |
|
|
| 184,735 |
|
| (1,277 | ) |
|
| 4,876 |
|
Amortization of gain associated with terminated commodity derivatives |
| — |
|
|
|
| 19,997 |
|
|
| — |
|
|
|
| — |
|
|
| 19,997 |
| |||||||
(Gain) loss on sale of properties |
| — |
|
|
|
| 60 |
|
|
| — |
|
|
|
| — |
|
|
| (3,575 | ) |
| — |
|
|
| 2,373 |
|
Acquisition and divestiture related expenses |
| 238 |
|
|
|
| 416 |
|
|
| 238 |
|
|
|
| — |
|
|
| 1,429 |
|
| 364 |
|
|
| 208 |
|
Share/Unit based compensation expense |
| 1,016 |
|
|
|
| 2,070 |
|
|
| 1,543 |
|
|
|
| 3,667 |
|
|
| 7,369 |
| |||||||
Share-based compensation expense |
| 1,936 |
|
|
| 1,176 |
| |||||||||||||||||||||
Exploration costs |
| 4 |
|
|
|
| 12 |
|
|
| — |
|
|
|
| 16 |
|
|
| 149 |
|
| 15 |
|
|
| 34 |
|
(Gain) loss on settlement of AROs |
| 284 |
|
|
|
| 160 |
|
|
| 284 |
|
|
|
| 36 |
|
|
| 229 |
|
| 143 |
|
|
| — |
|
Bad debt expense |
| — |
|
|
|
| — |
|
|
| — |
|
|
|
| — |
|
|
| 1,601 |
|
| 101 |
|
|
| — |
|
Restructuring related costs |
| — |
|
|
|
| — |
|
|
| — |
|
|
|
| 7,548 |
|
|
| — |
| |||||||
Reorganization items, net |
| 33 |
|
|
|
| — |
|
|
| 382 |
|
|
|
| 88,774 |
|
|
| — |
|
| 187 |
|
|
| 518 |
|
Other |
| — |
|
|
|
| — |
|
|
| — |
|
|
|
| 57 |
|
|
| — |
| |||||||
Severance payments |
| 39 |
|
|
| — |
| |||||||||||||||||||||
Adjusted EBITDA | $ | 37,840 |
|
|
| $ | 76,925 |
|
| $ | 56,758 |
|
|
| $ | 53,238 |
|
| $ | 242,286 |
| $ | 19,034 |
|
| $ | 43,328 |
|
Reconciliation of Adjusted EBITDA to Net Cash from Operating Activities
| Successor |
|
|
| Predecessor |
|
| Successor |
|
|
| Predecessor |
| |||||||||||||||
|
|
|
|
|
|
|
|
|
| Period from |
|
|
|
|
|
|
|
|
|
| ||||||||
| Three Months |
|
|
| Three Months |
|
| May 5, 2017 |
|
|
| Period from |
|
| Nine Months |
| ||||||||||||
| Ended |
|
|
| Ended |
|
| through |
|
|
| January 1, |
|
| Ended |
| For the Three Months Ended |
| ||||||||||
| September 30, |
|
|
| September 30, |
|
| September 30, |
|
|
| 2017 through |
|
| September 30, |
| March 31, |
| ||||||||||
| 2017 |
|
|
| 2016 |
|
| 2017 |
|
|
| May 4, 2017 |
|
| 2016 |
| 2019 |
|
| 2018 |
| |||||||
| (In thousands) |
|
|
| (In thousands) |
|
|
| (In thousands) |
| (In thousands) |
| ||||||||||||||||
Net cash provided by (used in) operating activities | $ | 37,330 |
|
|
| $ | 43,175 |
|
| $ | 57,874 |
|
|
| $ | 117,937 |
|
| $ | 199,147 |
| $ | 10,800 |
|
| $ | 42,147 |
|
Changes in working capital |
| (6,358 | ) |
|
|
| (14,297 | ) |
|
| (11,780 | ) |
|
|
| (8,963 | ) |
|
| (24,224 | ) |
| 3,006 |
|
|
| (4,810 | ) |
Interest expense, net |
| 5,808 |
|
|
|
| 27,209 |
|
|
| 9,605 |
|
|
|
| 10,243 |
|
|
| 91,904 |
|
| 4,089 |
|
|
| 5,772 |
|
Gain (loss) on interest rate swaps |
| — |
|
|
|
| 1,432 |
|
|
| — |
|
|
|
| — |
|
|
| (4,094 | ) |
| 94 |
|
|
| — |
|
Cash settlements paid on interest rate derivative instruments |
| — |
|
|
|
| 471 |
|
|
| — |
|
|
|
| — |
|
|
| 1,514 |
| |||||||
Cash settlements received on terminated derivatives |
| — |
|
|
|
| — |
|
|
| — |
|
|
|
| (94,146 | ) |
|
| (39,299 | ) | |||||||
Amortization of gain associated with terminated commodity derivatives |
| — |
|
|
|
| 19,997 |
|
|
| — |
|
|
|
| — |
|
|
| 19,997 |
| |||||||
Amortization of deferred financing fees |
| (570 | ) |
|
|
| (1,312 | ) |
|
| (916 | ) |
|
|
| — |
|
|
| (3,862 | ) |
| (308 | ) |
|
| (541 | ) |
Accretion of senior notes discount |
| — |
|
|
|
| (568 | ) |
|
| — |
|
|
|
| — |
|
|
| (1,769 | ) | |||||||
Acquisition and divestiture related expenses |
| 238 |
|
|
|
| 416 |
|
|
| 238 |
|
|
|
| — |
|
|
| 1,429 |
|
| 364 |
|
|
| 208 |
|
Income tax expense (benefit) - current portion |
| 897 |
|
|
|
| — |
|
|
| 897 |
|
|
|
| (17 | ) |
|
| 67 |
|
| (50 | ) |
|
| — |
|
Exploration costs |
| 4 |
|
|
|
| 12 |
|
|
| — |
|
|
|
| 16 |
|
|
| 149 |
|
| 15 |
|
|
| 34 |
|
Plugging and abandonment cost |
| 458 |
|
|
|
| 390 |
|
|
| 458 |
|
|
|
| 200 |
|
|
| 1,327 |
|
| 305 |
|
|
| — |
|
Restructuring related costs |
| — |
|
|
|
| — |
|
|
| — |
|
|
|
| 7,548 |
|
|
| — |
| |||||||
Reorganization items, net |
| 33 |
|
|
|
| — |
|
|
| 382 |
|
|
|
| 20,420 |
|
|
| — |
|
| 187 |
|
|
| 518 |
|
Severance payments |
| 39 |
|
|
| — |
| |||||||||||||||||||||
Other |
| 493 |
|
|
| — |
| |||||||||||||||||||||
Adjusted EBITDA | $ | 37,840 |
|
|
| $ | 76,925 |
|
| $ | 56,758 |
|
|
| $ | 53,238 |
|
| $ | 242,286 |
| $ | 19,034 |
|
| $ | 43,328 |
|
Liquidity and Capital Resources
Overview. Our ability to finance our operations, including funding capital expenditures and acquisitions, meet our indebtedness obligations, refinance our indebtedness or meet our collateral requirements will depend on our ability to generate cash in the future. Our primary sources of liquidity and capital resources have historically been cash flows generated by operating activities, borrowings under our revolving credit facility and equity and debt capital markets. For the remainder of 2019, we expect our primary funding sources to be cash flows generated by operating activities and available borrowing capacity under our New Revolving Credit Facility.
Capital Markets. We do not currently anticipate any near-term capital markets activity, but we will continue to evaluate the availability of public debt and equity for funding potential future growth projects and acquisition activity.
Hedging. Commodity hedging has been and remains an important part of our strategy to reduce cash flow volatility. Our hedging activities are intended to support oil, NGL, and natural gas prices at targeted levels and to manage our exposure to commodity price fluctuations. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering at least 25% - 50% of our estimated production from total proved developed producing reserves over a one-to-three year period at any given point of time to satisfy the hedging covenants in our New Revolving Credit Facility and pursuant to our internal policies. We may, however, from time to time, hedge more or less than this approximate amount. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. The current market conditions may also impact our ability to enter into future commodity derivative contracts. For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of March 31, 2019, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.”
We evaluate counterparty risks related to our commodity derivative contracts and trade credit. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices. We sell our oil and natural gas to a variety of purchasers. Non-performance by a customer could also result in losses.
Capital Expenditures. Our total capital expenditures were approximately $13.1 million for the three months ended March 31, 2019, which were primarily related to drilling, capital workovers and facilities located in the Rockies and California.
Government Trust Account. In 2015, the Bureau of Safety and Environmental Enforcement issued a preliminary report that indicated the estimated cost of decommissioning the offshore production facilities associated with our properties in federal waters offshore Southern California may further increase. The implementation of this increase is currently on hold and we do not expect resolution of a negotiated decommissioning estimate until later in 2019. At March 31, 2019, there was approximately $90.2 million in the trust account and $71.3 million in surety bonds.
Working Capital. We expect to fund our working capital needs primarily with operating cash flows. We also plan to reinvest a sufficient amount of our operating cash flow to fund our expected capital expenditures. Our debt service requirements are expected to be funded by operating cash flows. See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” and “— Overview” of this quarterly report for additional information.
As of March 31, 2019, we had working capital of $1.3 million primarily due to a cash balance of $24.9 million and accounts receivable of $25.1 million partially offset by the timing of accruals, which included accrued liabilities of $21.2 million, revenues payable of $24.1 million and a current derivative liability of $9.1 million.
Debt Agreements
New Revolving Credit Facility. On November 2, 2018, OLLC as borrower, entered into the New Revolving Credit Facility with Bank of Montreal, as administrative agent. At March 31, 2019, our borrowing base under our New Revolving Credit Facility was subject to redetermination on at least a semi-annual basis primarily based on a reserve engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. The borrowing base as of March 31, 2019, was approximately $425.0 million.
As of March 31, 2019, we were in compliance with all the financial (interest coverage ratio, current ratio and total leverage ratio) and other covenants associated with our New Revolving Credit Facility.
As of March 31, 2019, we had approximately $153.4 million of available borrowings under our New Revolving Credit Facility, net of $1.7 million in letters of credit. See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information regarding our New Revolving Credit Facility.
Cash Flows from Operating, Investing and Financing Activities
The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the three months ended March 31, 2019 and 2018, have been derived from our Unaudited Condensed Consolidated Financial Statements. For information regarding the individual components of our cash flow amounts, see the Unaudited Condensed Statements of Consolidated Cash Flows included under “Item 1. Financial Statements” of this quarterly report.
| For the Three Months Ended |
| |||||
| March 31, |
| |||||
| 2019 |
|
| 2018 |
| ||
| (In thousands) |
| |||||
Net cash provided by operating activities | $ | 10,800 |
|
| $ | 42,147 |
|
Net cash used in investing activities |
| (10,500 | ) |
|
| (13,284 | ) |
Net cash used in financing activities |
| (25,128 | ) |
|
| (29,213 | ) |
Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $10.8 million and $42.1 for the three months ended March 31, 2019 and 2018, respectively. Production volumes were approximately 21.5 MBoe/d and 29.0MBoe/d for the three months ended March 31, 2019 and 2018, respectively. The average realized sales price was $33.67 per MBoe and $33.66 per MBoe for the three months ended March 31, 2019 and 2018, respectively. Lease operating expenses were $28.9 million and $29.6 million for the three months ended March 31, 2019 and 2018, respectively. Gathering, processing and transportation was $4.7 million and $5.6 million for the three months ended March 31, 2019 and 2018, respectively.
Investing Activities. Net cash used in investing activities for the three months ended March 31, 2019 was $10.5 million, of which $10.4 million was used for additions to oil and natural gas properties. Net cash used in investing activities for the three months ended March 31, 2018 was $13.3 million, of which $13.1 million was used for additions to oil and natural gas properties.
Financing Activities. The Company had net repayments of $24.0 million related to our New Revolving Credit Facility and $29.0 million under the Emergence Credit Facility for the three months ended March 31, 2019 and 2018, respectively.
Contractual Obligations
During the three months ended September 30, 2017,March 31, 2019, there were no significant changes in our consolidated contractual obligations from those reported in our Quarterly Report on2018 Form 10-Q for the quarter ended June 30, 2017 filed with the SEC on August 9, 201710-K except for Exitthe Credit Facility borrowings and repayments.
Off–Balance Sheet Arrangements
As of September 30, 2017,March 31, 2019, we had no off–balance sheet arrangements.
Recently Issued Accounting Pronouncements
For a discussion of recent accounting pronouncements that will affect us, see Note 42 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.
In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes. We do not designate these or plan to designate future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings. We believe that our exposures to market risk have not changed materially since those reported under Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” included in our 20162018 Form 10-K.
Commodity Price Risk
Our major market risk exposure is in the prices that we receive for our oil, natural gas and NGL production. To reduce the impact of fluctuations in commodity prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected production through various transactions that fix the future prices we receive. It has been our practice to enter into fixed price swaps and costless collars only with lenders and their affiliates under our Predecessor’s revolving credit facilityEmergence Credit Facility and our ExitNew Revolving Credit Facility.
For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of September 30, 2017,March 31, 2019, see Note 76 of the Notes to Unaudited Condensed Consolidated Financial Statements included “Item 1. Financial Statements” of this quarterly report.
Interest Rate Risk
Our risk management policy allowsprovides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. The Company did not have anyFrom time to time we enter into offsetting positions to avoid being economically over-hedged. See Note 6 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for interest rate swapsswap arrangements that were outstanding at September 30, 2017.March 31, 2019.
Counterparty and Customer Credit Risk
We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. In addition, our derivative contracts may expose us to credit risk in the event of nonperformance by counterparties. Some of the lenders, or certain of their affiliates, under our Credit Agreementprevious and current credit agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At September 30, 2017,March 31, 2019, after taking into effect netting arrangements, we had no counterparty exposure related to our derivative instruments. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have had the right to offset $51.8$0.1 million against amounts outstanding under our ExitNew Revolving Credit Facility at September 30, 2017.March 31, 2019.
Evaluation of Disclosure Controls and Procedures
As required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) and under the Exchange Act) as of the end of the period covered by this quarterly report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, the principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of September 30, 2017.March 31, 2019.
Change in Internal Control Over Financial Reporting
No changes in our internal control over financial reporting occurred during the quarter ended September 30, 2017March 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
The certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as Exhibits 31.1 and 31.2, respectively, to this quarterly report.
For information regarding legal proceedings, see Part I, “Item 1. Financial Statements,” Note 14,15, “Commitments and Contingencies — Litigation and Environmental” of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, “Item 1. Financial Statements” in this quarterly report, which is incorporated herein by reference.
Our business faces many risks. Any of the risks discussed elsewhere in this quarterly report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. There have been no material changes with respectIn addition to the risk factors since those disclosed in our 20162018 Form 10-K, and our Second Quarter Form 10-Q, except forwe face risk factors relating to the Merger, including the following:
We may befail to complete the Merger in the anticipated time frame or at all. Our failure to complete the Merger could adversely affect the market price of our common stock and otherwise adversely affect our business, results of operations and financial condition.
The completion of the Merger is not assured and is subject to a number of conditions and risks, including conditions and risks that are outside of our control. The Merger Agreement contains a number of conditions that must be satisfied or waived prior to the completion of the Merger. There can be no assurance that all of the conditions to the completion of the Merger will be so satisfied or waived. For example, holders of a majority of votes cast by Midstates stockholders at the special meeting may not vote in connection with divestituresfavor of the Stock Issuance, holders of a majority of the issued and acquisitions.
In June 2017,outstanding shares of Amplify common stock may not vote in favor of the Merger or we announced that the Company had engaged Jefferies LLCor Midstates may fail to explore and evaluate potential strategic alternatives, including the marketing of certain non-core assets for sale. In November 2017, we announced that the Company had launched divestiture processes in October for the Company’s East Texas assets and Rockies CO2 assets in Wyoming, and is in the market with its South Texas conventional and Eagle Ford assets. We may sell ofreceive any required regulatory approvals. If any of these coreconditions are not satisfied or non-core assetswaived, we will be unable to complete the Merger.
If we fail to complete the Merger, our ongoing business may be adversely affected and we will not realize any of the anticipated benefits of the Merger. For example, our failure to complete the Merger may result in ordernegative publicity or a negative impression of us in the investment community, which may adversely affect the market price of our common stock, and may affect our relationships with our customers, suppliers, employees and other business partners. In addition, even if we fail to increase capital resources available forcomplete the Merger, we will still incur certain significant costs associated with the Merger, primarily consisting of legal fees, accounting fees, financial advisory, financial printing and other core assets, create organizationalrelated costs. Furthermore, pursuant to the Merger Agreement, if the Merger is not completed, in certain specified circumstances, we may be required to pay Midstates a termination fee in the amount of $4.5 million. Accordingly, if the Merger is not completed, or if there are significant delays in completing the Merger, the trading price of our common stock and operational efficienciesour business, results of operations and financial condition could be adversely affected.
We are subject to business uncertainties while the Merger is pending, which could adversely affect our business, results of operations and financial condition.
While the Merger is pending, our customers, suppliers, employees and other business partners may delay or for other purposes. Various factorsdefer certain business decisions with respect to us or seek to terminate, change or renegotiate their relationships with us as a result of the Merger. Any of these developments could materiallyadversely affect our business, results of operations and financial condition, as well as the market price of our common stock, regardless of whether the Merger is completed.
In addition, under the terms of the Merger Agreement, we are subject to certain restrictions on the conduct of our business prior to the completion of the Merger, which may adversely affect our ability to execute certain of our business strategies, including our ability to enter into contracts, acquire or dispose of such assets includingor incur indebtedness or capital expenditures. These contractual restrictions could negatively affect our business, results of operations and financial condition while the approvalsMerger is pending.
Our stockholders will be diluted by the Merger.
Pursuant to the Merger Agreement, our stockholders will receive 0.933 shares of governmental agenciesMidstates common stock for each share of Amplify Energy common stock that they hold. Accordingly, the Merger will dilute the ownership position of our current stockholders in the combined company. We currently estimate that our current stockholders will own approximately 50 percent of the issued and outstanding shares of Midstates immediately following the completion of the Merger.
Because the exchange ratio pursuant to the Merger Agreement is fixed, our stockholders cannot be certain of the market value of the shares of Midstates common stock that they will receive in connection with the Merger relative to the value of the shares of Amplify Energy common stock that they currently hold.
Pursuant to the Merger Agreement, our stockholders will receive 0.933 shares of Midstates common stock for each share of Amplify Energy common stock that they hold. There is no mechanism in the Merger Agreement that would adjust the number of shares of Midstates common stock that our stockholders will receive based on any decreases or third partiesincreases in the trading price of shares of Midstates common stock. Accordingly, the market value of the consideration that our stockholders will receive in connection with the Merger will depend on the respective market prices of our common stock and Midstates’ common stock at the closing of the Merger.
The respective market prices of our common stock and Midstates’ common stock may be highly volatile and could fluctuate significantly for various reasons, including:
•changes in market assessments of the likelihood that the Merger will be completed;
•the nature and content of our or Midstates’ respective earnings releases, announcements or events that impact our or Midstates’ respective products, customers, competitors or markets; and
•business conditions in our markets and the availabilitygeneral state of purchasers willingthe securities markets and the market for energy-related stocks, as well as general economic and market conditions.
Furthermore, while the Merger is pending, the market price of our common stock could be negatively affected by risks and conditions that apply to acquireMidstates, which may be different from the assetsrisks and conditions currently applicable to our business.
Even if the Merger is completed, the integration of our business with termsthat of Midstates may be more difficult, costly or time consuming than we deem acceptable. Thoughexpect and we continuemay fail to evaluate various options forrealize the divestitureanticipated benefits of such assets,the Merger fully or at all.
The success of the Merger will depend on our and Midstates’ ability to successfully combine and integrate our respective businesses. Even if the Merger is completed, there can be no assurance that this evaluationwe and Midstates will result in any specific action.
In addition, in the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities.successfully combine and integrate our respective businesses or otherwise realize the anticipated benefits of the Merger. The combined company may perform differently than we expect. Potential difficulties that we and Midstates may face in the integration process include: the inability to successfully integrate our respective businesses in a manner that permits the combined company to achieve the full revenue and cost savings anticipated from the transaction; complexities associated with managing a larger and more complex business; challenges integrating personnel from the two companies and the loss of key employees; potential unknown liabilities and unforeseen expenses, delays or regulatory conditions in connection with the Merger or the integration process; difficulties integrating relationships with customers, suppliers, employees and other business partners; and poorer performance at one or both of the companies as a result of the diversion of our or Midstates’ respective management’s attention in connection with the Merger or the integration process. If we experience any of these difficulties or other problems in connection the integration process, we and Midstates may fail to realize the anticipated benefits of the Merger fully or at all.
We expect to incur significant costs in connection with the Merger.
We and Midstates have incurred and we expect to continue to incur significant non-recurring transaction-related costs associated with completing the Merger, combining the operations of the two companies and achieving desired synergies. Transaction costs include legal fees, accounting fees, financial advisory, financial printing and other related costs. These costs may be substantial and, in many cases, will be borne by us whether or not the Merger is completed. We will also incur costs related to formulating and implementing integration plans, including facilities and systems consolidation costs and other employment-related costs. Even if we do identify attractive acquisition opportunities, wethe Merger is completed, the benefits of the Merger may not be ableoffset transaction costs or allow the combined company to completeachieve a net benefit in the acquisitionnear term, or do soat all.
We or Midstates may become the target of securities class action or derivative lawsuits that could result in substantial costs and may delay or prevent the Merger from being completed.
Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered into merger agreements. Defending against these claims can result in substantial costs and divert management time and resources, even if the lawsuits are without merit. An adverse judgment could result in monetary damages, which could have a negative impact on commercially acceptable terms. Asour and Midstates’ respective businesses, results of operations and financial condition. Additionally, if a result, our acquisition activitiesplaintiff is successful in obtaining an injunction prohibiting completion of the Merger, the injunction may not be successful,delay or prevent the Merger from being completed, which may hinder our replacement of reserves and adversely affect our and Midstates’ respective businesses, results of operations.operations and financial condition.
None.The following table summarizes our repurchase activity during the three months ended March 31, 2019:
Period |
| Total Number of Shares Purchased |
|
| Average Price Paid per Share |
|
| Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs |
|
| Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (1) | |||
|
|
|
|
|
|
|
|
|
|
|
|
|
| (In thousands) |
Common Shares Repurchased (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1, 2019 - January 31, 2019 |
|
| — |
|
| n/a |
|
|
| — |
|
| n/a | |
February 1, 2019 - February 28, 2019 |
|
| — |
|
| n/a |
|
|
| — |
|
| n/a | |
March 1, 2019 - March 31, 2019 |
|
| 88,508 |
|
| $ | 6.94 |
|
|
| — |
|
| n/a |
(1) | Common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. The Company repurchased the remaining vesting shares on the vesting date at current market price. See Note 9 of the Notes to the Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information. |
None.
Not applicable.
None.Employment Agreements
On May 1, 2019, the Company approved new compensatory arrangements for Messrs. Willsher, Smiley and Willis. On May 3, 2019, the Company entered into employment agreements with each of Messrs. Willsher, Smiley and Willis (each, an “Employment Agreement” and collectively, the “Employment Agreements”), memorializing the previously approved compensatory arrangements and setting forth terms and conditions under which each will serve as an executive officer of the Company.
Martyn Willsher
Mr. Willsher’s Employment Agreement provides Mr. Willsher with an initial base salary of $300,000 per year; an annual bonus opportunity (the “Annual Bonus”) (targeted at 75% of his annual base salary) (the “Target Bonus”); the potential to receive long-term incentive compensation awards as determined in the Board’s discretion; the right to participate in the benefit plans, programs and arrangements available to the Company’s other senior executives generally, subject to the terms and conditions of such plans, programs and arrangements; and reimbursement for his business expenses incurred during the employment term.
Upon any termination of employment with the Company, Mr. Willsher will be entitled to: (i) his accrued but unpaid base salary as of the termination date, (ii) any unreimbursed business expenses incurred through the termination date and (iii) any payments and benefits to which he may be entitled under any benefit plans, programs, or arrangements (collectively, the “Accrued Obligations”).
In the event of a termination of Mr. Willsher’s employment with the Company without “cause” (as defined below) or for “good reason” (as defined below) (each, a “Good Leaver Termination”), then in addition to the Accrued Obligations and subject to his timely execution and non-revocation of a general release of claims, and complying with the release and the restrictive covenants, Mr. Willsher will be entitled to: (i) any earned but unpaid Annual Bonus for the preceding calendar year (the “Actual Full Year Bonus”); (ii) a pro-rated Annual Bonus in respect of the calendar year of termination, with the amount determined based on actual results for such calendar year and with the pro-ration determined based on the duration of his employment with the Company during such calendar year (the “Pro-Rated Bonus”); (iii) (A) if the termination date occurs on or prior to December 11, 2019, an amount equal to Mr. Willsher’s then-current monthly base salary rate, and (B) if the termination occurs after December 11, 2019, an amount equal to 200% of his then-current monthly base salary rate, in each case, payable in accordance with the Company’s regularly scheduled payroll practices for a period of 12 months following the termination date; and (iv) up to 12 months of continued health insurance benefits under the Company group health plan (at the employee-rate), subject to his continued eligibility for COBRA coverage and terminable if he obtains other employment offering group health plan coverage.
If Mr. Willsher’s employment with the Company is terminated due to his death or “disability” (as defined in the Employment Agreement), then in addition to the Accrued Obligations, Mr. Willsher will be entitled to the Actual Full Year Bonus and the Pro-Rated Bonus.
For purposes of the Employment Agreement, the Company will have “cause” to terminate Mr. Willsher’s employment upon the occurrence of any of his: (i) conviction of a felony, or plea of guilty or nolo contendere to, any felony or any crime of moral turpitude; (ii) repeated intoxication by alcohol or drugs during the performance of his duties; (iii) embezzlement or other willful and intentional misuse of any of the funds of the Company or its direct or indirect subsidiaries, (iv) commission of a demonstrable act of fraud; (v) willful and material misrepresentation or concealment on any written reports submitted to the Company or its direct or indirect subsidiaries; (vi) material breach of the Employment Agreement; (vii) failure to follow or comply with the reasonable, material and lawful written directives of the Board; or (vii) conduct constituting his material breach of the Company’s then current code of conduct or similar written policy.
For purposes of the Employment Agreement, Mr. Willsher will have “good reason” to terminate his employment with the Company upon the occurrence of any of the following without his written consent: (i) a relocation of his principal work location to a location more than 40 miles from its then current location; (ii) a reduction in his then current base salary or Target Bonus, or both; (iii) a material breach of any provision of the Employment Agreement by the Company; or (iv) any material reduction in his title, authority, duties, responsibilities or reporting relationship from those in effect as of the Effective Date, except to the extent such reduction occurs in connection with his termination of employment for “cause” or due to his death or “disability”.
The Employment Agreement provides for a Code Section 280G “best-net” cutback, which would cause an automatic reduction in any payments or benefits Mr. Willsher would receive which constitute parachute payments within the meaning of Code Section 280G, in the event such reduction would result in Mr. Willsher receiving greater payments and benefits on an after-tax basis.
The Employment Agreement subjects Mr. Willsher to employment term and 12-month post-employment non-competition, non-solicitation and non-interference restrictive covenants, as well as assignment of invention, perpetual non-disparagement and employment term and post-employment confidentiality covenants.
Richard P. Smiley
Mr. Smiley’s Employment Agreement provides Mr. Smiley with an initial base salary of $330,000 per year; an annual bonus opportunity (targeted at 70% of his annual base salary); the potential to receive long-term incentive compensation awards as determined in the Board’s discretion; the right to participate in the benefit plans, programs and arrangements available to the Company’s other senior executives generally, subject to the terms and conditions of such plans, programs and arrangements; and reimbursement for his business expenses incurred during the employment term. The remaining terms of Mr. Smiley’s Employment Agreement are substantially similar to Mr. Willsher’s Employment Agreement discussed above.
Eric M. Willis
Mr. Willis’ Employment Agreement provides Mr. Willis with an initial base salary of $350,000 per year; an annual bonus opportunity (targeted at 65% of his annual base salary); the potential to receive long-term incentive compensation awards as determined in the Board’s discretion; the right to participate in the benefit plans, programs and arrangements available to the Company’s other senior executives generally, subject to the terms and conditions of such plans, programs and arrangements; and reimbursement for his business expenses incurred during the employment term. The remaining terms of Mr. Willis’ Employment Agreement are substantially similar to Mr. Willsher’s Employment Agreement discussed above.
The foregoing description of the Employment Agreements for each of Messrs. Willsher, Smiley and Willis are qualified in their entirety by reference to the Employment Agreements, which are attached as Exhibits 10.1, 10.2 and 10.3 to this quarterly report.
Exhibit |
|
|
| Description |
2.1 |
| — |
| |
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|
3.1 |
| — |
| |
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3.2 |
| — |
| |
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|
Exhibit |
|
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| Description |
| — |
| ||
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| — |
| |
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| — |
| |
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10.4 |
| — |
| |
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| |||
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| |||
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| |||
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| |||
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| |||
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| |||
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| |||
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| |||
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31.1* |
| — |
| |
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31.2* |
| — |
| |
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|
32.1** |
| — |
| |
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|
|
101.CAL* |
| — |
| XBRL Calculation Linkbase Document |
|
|
|
|
|
101.DEF* |
| — |
| XBRL Definition Linkbase Document |
|
|
|
|
|
101.INS* |
| — |
| XBRL Instance Document |
|
|
|
|
|
101.LAB* |
| — |
| XBRL Labels Linkbase Document |
|
|
| ||
101.PRE* |
| — |
| XBRL Presentation Linkbase Document |
|
|
| ||
101.SCH* |
| — |
| XBRL Schema Document |
* | Filed as an exhibit to this Quarterly Report on Form 10-Q. |
** | Furnished as an exhibit to this Quarterly Report on Form 10-Q. |
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| Amplify Energy Corp. | ||
| (Registrant) | ||
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Date: | By: |
| /s/ |
| Name: |
|
|
| Title: |
| Senior Vice President and Chief Financial Officer |
|
|
|
|
Date: May 9, 2019 | By: | /s/ Denise DuBard | |
Name: | Denise DuBard | ||
Title: | Vice President and Chief Accounting Officer | ||
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