UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q10–Q
☑ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31,September 30, 2019
OR
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
OR
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to .
Commission File Number: 001-35512
MIDSTATES PETROLEUM COMPANY, INC.AMPLIFY ENERGY CORP.
(Exact name of registrant as specified in its charter)
Delaware |
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incorporation or organization) |
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(Address of principal executive offices) |
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Registrant’s telephone number, including area code: (918) 947-8550(713) 490-8900
Securities registered pursuant to Section 12(b) of the Act:
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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 x☑ No o☐
Indicate by check mark whether the registrant has submitted electronically, every Interactive Data File required to be submitted 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 such files). Yes x☑ No o☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-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. o☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-212b–2 of the Exchange Act). Yes o☐ No x☑
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. ☑ Yes ☐ No
Securities Registered Pursuant to Section 12(b):
Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
Common Stock | AMPY | NYSE |
As of October 31, 2019, the registrant had 39,430,953 outstanding shares of common stock, $0.01 par value outstanding.
The number
Table of shares outstanding of our stock at May 7, 2019 is shown below:Contents
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DOCUMENTS INCORPORATED BY REFERENCE
None.
MIDSTATES PETROLEUM COMPANY, INC.
QUARTERLY REPORT ON
FORM 10-Q
FOR THE THREE MONTHS ENDED MARCH 31, 2019
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Item 1. |
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Notes to Unaudited Condensed Consolidated Financial Statements | 10 | ||||
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Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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Item 4. | 37 | ||||
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Item | 39 | ||||
Item 2. | Unregistered Sales of Equity Securities and | 39 | |||
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Item 6. | 39 | ||||
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i
GLOSSARYGLOSSARY 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.
BblBbl:: One stock tank barrel, ofor 42 U.S. gallons liquid volume, used herein in reference to oil condensate or natural gas liquids.other liquid hydrocarbons.
Bbl/d: One Bbl per day.
BcfeBoe: Barrels of oil equivalent, with 6,000: One billion cubic feet of natural gas being equivalent to oneequivalent.
Boe: One barrel of oil.
Boe/day: Barrels of oil equivalent, per day.
Completion: The processcalculated by converting natural gas to oil equivalent barrels at a ratio of treating a drilled well followed by the installation of permanent equipment for the productionsix Mcf of natural gas or oil, or into one Bbl of oil.
MBoe/d: One million Boe per day.
BOEM: Bureau of Ocean Energy Management.
Btu: One British thermal unit, the casequantity of heat required to raise the temperature of a dry hole,one-pound mass of water by one degree Fahrenheit.
Development Project: A development project is the reporting of abandonmentmeans by which petroleum resources are brought to the appropriate agency.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: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 do notwould 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.
ExploitationExploratory well:: A well drilleddevelopment 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 findthe 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 new field or to find a new reservoir in a field previously found to be productiveworking 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 or oil in another reservoir.equivalent.
MMcfe/d: One MMcfe per day.
Net ProductionMMBtu:: Production that is owned by us less royalties and production due to others. One million British thermal units.
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.
NYMEXNYMEX: The: 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.
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 reserves:Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
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—producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—regulations, prior to the time at which contracts providing the right to drill or 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 but not limited to, 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 12-monthtwelve-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 TechnologyReasonable certainty: A high degree: Reliable technology is a grouping of confidence.
Recompletion: The process of re-entering an existing wellboreone or more technologies (including computational methods) that is either producinghas been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or not producing and completing new reservoirs in an attempt to establish, re-establishing, or increase existing production.analogous formation.
ReservesReserves: Estimated: 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).
ReservoirReservoir:: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.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.
As used in this Form 10-Q, unless we indicate otherwise:
“Amplify Energy,” “Company,” “we,” “our,” “us” or Spudding: The commencementlike terms refers to Amplify Energy Corp. (f/k/a Midstates Petroleum Company, Inc.) individually and collectively with its subsidiaries, as the context requires;
“Legacy Amplify” refers to Amplify Energy Holdings LLC (f/k/a Amplify Energy Corp.), the successor reporting company of drilling operations of a new well.Memorial Production Partners LP; and
“OLLC” refers to Amplify Energy Operating LLC, our wholly owned subsidiary through which we operate our properties.
Wellbore:C The hole drilled byAUTIONARY NOTE REGARDING FORWARD–LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains “forward-looking statements” within the bitmeaning of Section 27A of the Securities Act of 1933, as amended, and section 21E of the Securities Exchange Act of 1934, as amended, that is equipped for 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 orand natural gas production on a completed well. Also called well or borehole.reserves;
technology;
Working interest: The right granted to the lessee of a property to explore for and to produce and ownrealized 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 minerals. The working interest owners bearcomparable terminology. These statements address activities, events or developments that we expect or anticipate will or may occur in the exploration,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;
risks related to a redetermination of the borrowing base under our 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, 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 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 costsrisks 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 cash, penalty,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 carried basis.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 Legacy Amplify’s Annual Report on Form 10-K for the year ended December 31, 2018 filed with the SEC on March 6, 2019 (“Legacy Amplify Form 10-K”), “Risk Factors” in Legacy Amplify’s definitive proxy statement filed on June 28, 2019 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.
PART I — FINANCIALI—FINANCIAL INFORMATION
AMPLIFY ENERGY CORP.
MIDSTATES PETROLEUM COMPANY, INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands, except share amounts)outstanding shares)
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| March 31, 2019 |
| December 31, 2018 |
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ASSETS |
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CURRENT ASSETS: |
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Cash and cash equivalents |
| $ | 717 |
| $ | 11,341 |
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Accounts receivable: |
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Oil and gas sales |
| 17,519 |
| 22,165 |
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Joint interest billing |
| 2,253 |
| 2,474 |
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Other |
| 377 |
| 1,374 |
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Commodity derivative contracts |
| 309 |
| 6,940 |
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Other current assets |
| 2,534 |
| 1,684 |
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Total current assets |
| 23,709 |
| 45,978 |
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PROPERTY AND EQUIPMENT: |
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Oil and gas properties, on the basis of full-cost accounting |
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Proved properties |
| 818,013 |
| 809,272 |
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Unproved properties not being amortized |
| 1,869 |
| 4,050 |
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Other property and equipment |
| 6,340 |
| 6,345 |
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Less accumulated depreciation, depletion, amortization and impairment |
| (287,544 | ) | (266,198 | ) | ||
Net property and equipment |
| 538,678 |
| 553,469 |
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OTHER NONCURRENT ASSETS: |
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Commodity derivative contracts |
| — |
| 791 |
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Right-of-use lease assets |
| 4,648 |
| — |
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Other noncurrent assets |
| 5,762 |
| 5,257 |
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Total other noncurrent assets |
| 10,410 |
| 6,048 |
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TOTAL |
| $ | 572,797 |
| $ | 605,495 |
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LIABILITIES AND EQUITY |
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CURRENT LIABILITIES: |
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Accounts payable |
| $ | 3,536 |
| $ | 6,511 |
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Accrued liabilities |
| 21,973 |
| 25,521 |
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Commodity derivative contracts |
| 908 |
| — |
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Lease liabilities |
| 1,236 |
| — |
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Total current liabilities |
| 27,653 |
| 32,032 |
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LONG-TERM LIABILITIES: |
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Asset retirement obligations |
| 8,244 |
| 8,087 |
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Commodity derivative contracts |
| 251 |
| 80 |
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Long-term debt |
| 59,059 |
| 23,059 |
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Long-term lease liabilities |
| 4,041 |
| — |
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Other long-term liabilities |
| — |
| 560 |
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Total long-term liabilities |
| 71,595 |
| 31,786 |
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COMMITMENTS AND CONTINGENCIES (Note 15) |
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STOCKHOLDERS’ EQUITY: |
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Preferred stock, $0.01 par value, 50,000,000 shares authorized; no shares issued or outstanding at March 31, 2019 and December 31, 2018 |
| — |
| — |
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Warrants, 6,979,609 and 6,625,554 warrants outstanding at March 31, 2019 and December 31, 2018 |
| 37,329 |
| 37,329 |
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Common stock, $0.01 par value, 250,000,000 shares authorized; 20,619,765 shares issued and 20,414,422 shares outstanding at March 31, 2019; 25,520,170 shares issued and 25,345,981 shares outstanding at December 31, 2018 |
| 206 |
| 255 |
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Treasury stock |
| (2,717 | ) | (2,455 | ) | ||
Additional paid-in-capital |
| 481,901 |
| 531,911 |
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Retained deficit |
| (43,170 | ) | (25,363 | ) | ||
Total stockholders’ equity |
| 473,549 |
| 541,677 |
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TOTAL |
| $ | 572,797 |
| $ | 605,495 |
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| September 30, |
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| December 31, |
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| 2019 |
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| 2018 |
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ASSETS |
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Current assets: |
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Cash and cash equivalents | $ | 7,408 |
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| $ | 49,704 |
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Restricted cash |
| 325 |
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| 325 |
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Accounts receivable |
| 32,554 |
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| 29,514 |
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Short-term derivative instruments |
| 20,709 |
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| 18,813 |
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Prepaid expenses and other current assets |
| 15,919 |
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| 7,241 |
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Total current assets |
| 76,915 |
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| 105,597 |
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Property and equipment, at cost: |
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Oil and natural gas properties, successful efforts method |
| 784,119 |
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| 598,331 |
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Support equipment and facilities |
| 137,267 |
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| 108,760 |
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Other |
| 12,431 |
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| 6,625 |
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Accumulated depreciation, depletion and impairment |
| (129,460 | ) |
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| (85,535 | ) |
Property and equipment, net |
| 804,357 |
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| 628,181 |
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Long-term derivative instruments |
| 17,715 |
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| 2,469 |
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Restricted investments |
| 4,622 |
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| 94,467 |
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Operating lease - long term right-of-use asset |
| 4,925 |
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| — |
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Other long-term assets |
| 6,095 |
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| 6,129 |
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Total assets | $ | 914,629 |
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| $ | 836,843 |
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LIABILITIES AND EQUITY |
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Current liabilities: |
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Accounts payable | $ | 6,472 |
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| $ | 2,345 |
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Revenues payable |
| 26,754 |
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| 24,779 |
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Accrued liabilities (see Note 13) |
| 26,327 |
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| 23,155 |
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Short-term derivative instruments |
| 209 |
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| 139 |
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Total current liabilities |
| 59,762 |
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| 50,418 |
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Long-term debt (see Note 8) |
| 278,000 |
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| 294,000 |
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Asset retirement obligations |
| 89,104 |
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| 75,867 |
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Long-term derivative instruments |
| 489 |
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|
| — |
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Operating lease liability |
| 3,214 |
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| — |
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Other long-term liabilities |
| 4,015 |
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|
| — |
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Total liabilities |
| 434,584 |
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| 420,285 |
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Commitments and contingencies (see Note 15) |
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Stockholders' equity: |
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Preferred stock, $0.01 par value: 50,000,000 shares authorized; no shares issued and outstanding at September 30, 2019 and Preferred stock, $0.0001 par value 45,000,000 shares authorized; no shares issued and outstanding at December 31, 2018 |
| — |
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| — |
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Warrants, 9,153,522 warrants issued and outstanding at September 30, 2019 and 2,173,913 warrants issued and outstanding at December 31, 2018, respectively |
| 4,790 |
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| 4,788 |
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Common stock, $0.01 par value: 300,000,000 shares authorized; 39,978,099 shares issued and outstanding at September 30, 2019 and Common stock, $0.0001 par value 300,000,000 shares authorized; 22,181,881 shares issued and outstanding at December 31, 2018 |
| 209 |
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| 3 |
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Additional paid-in capital |
| 435,019 |
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| 355,872 |
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Accumulated earnings |
| 40,027 |
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| 55,895 |
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Total stockholders' equity |
| 480,045 |
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| 416,558 |
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Total liabilities and equity | $ | 914,629 |
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| $ | 836,843 |
|
The accompanying notes are an integral part of these unaudited interim condensed consolidated financial statements.See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
MIDSTATES PETROLEUM COMPANY, INC.AMPLIFY ENERGY CORP.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CONSOLIDATED OPERATIONS
(Unaudited)
(In thousands, except per share amounts)
|
| For the Three Months |
| ||||
|
| 2019 |
| 2018 |
| ||
REVENUES |
|
|
|
|
| ||
Oil sales |
| $ | 16,327 |
| $ | 32,414 |
|
Natural gas liquid sales |
| 6,216 |
| 11,038 |
| ||
Natural gas sales |
| 6,610 |
| 8,337 |
| ||
Other revenue |
| 688 |
| 1,055 |
| ||
Total revenue from contracts with customers |
| 29,841 |
| 52,844 |
| ||
Losses on commodity derivative contracts—net |
| (7,732 | ) | (3,939 | ) | ||
Total revenues |
| 22,109 |
| 48,905 |
| ||
EXPENSES: |
|
|
|
|
| ||
Lease operating and workover |
| 8,990 |
| 14,808 |
| ||
Gathering and transportation |
| 19 |
| 57 |
| ||
Severance and other taxes |
| 1,933 |
| 2,861 |
| ||
Asset retirement accretion |
| 157 |
| 297 |
| ||
Depreciation, depletion, and amortization |
| 11,794 |
| 15,213 |
| ||
Impairment in carrying value of oil and gas properties |
| 9,653 |
| — |
| ||
General and administrative |
| 6,438 |
| 9,857 |
| ||
Total expenses |
| 38,984 |
| 43,093 |
| ||
OPERATING INCOME (LOSS) |
| (16,875 | ) | 5,812 |
| ||
OTHER EXPENSE |
|
|
|
|
| ||
Interest income |
| 5 |
| 19 |
| ||
Interest expense—net of amounts capitalized |
| (937 | ) | (1,827 | ) | ||
Total other expense |
| (932 | ) | (1,808 | ) | ||
INCOME (LOSS) BEFORE TAXES |
| (17,807 | ) | 4,004 |
| ||
Income tax expense |
| — |
| — |
| ||
NET INCOME (LOSS) |
| $ | (17,807 | ) | $ | 4,004 |
|
Participating securities—non-vested restricted stock |
| — |
| (99 | ) | ||
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS |
| $ | (17,807 | ) | $ | 3,905 |
|
Basic and diluted net income (loss) per share attributable to common shareholders |
| $ | (0.78 | ) | $ | 0.15 |
|
Basic and diluted weighted average number of common shares outstanding (Note 13) |
| 22,837 |
| 25,299 |
| ||
| For the Three Months Ended |
|
| For the Nine Months Ended |
| ||||||||||
| September 30, |
|
| September 30, |
| ||||||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales | $ | 72,426 |
|
| $ | 85,446 |
|
| $ | 196,978 |
|
| $ | 264,187 |
|
Other revenues |
| 533 |
|
|
| 76 |
|
|
| 668 |
|
|
| 255 |
|
Total revenues |
| 72,959 |
|
|
| 85,522 |
|
|
| 197,646 |
|
|
| 264,442 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
| 32,977 |
|
|
| 27,505 |
|
|
| 88,179 |
|
|
| 84,575 |
|
Gathering, processing and transportation |
| 4,459 |
|
|
| 6,197 |
|
|
| 13,507 |
|
|
| 17,772 |
|
Exploration |
| 3 |
|
|
| 9 |
|
|
| 24 |
|
|
| 3,031 |
|
Taxes other than income |
| 5,135 |
|
|
| 4,717 |
|
|
| 13,008 |
|
|
| 15,289 |
|
Depreciation, depletion and amortization |
| 15,617 |
|
|
| 13,355 |
|
|
| 39,696 |
|
|
| 39,932 |
|
General and administrative expense |
| 27,034 |
|
|
| 8,219 |
|
|
| 46,908 |
|
|
| 35,739 |
|
Accretion of asset retirement obligations |
| 1,428 |
|
|
| 1,272 |
|
|
| 4,071 |
|
|
| 4,419 |
|
(Gain) loss on commodity derivative instruments |
| (28,725 | ) |
|
| 21,110 |
|
|
| (19,231 | ) |
|
| 67,218 |
|
(Gain) loss on sale of properties |
| — |
|
|
| (707 | ) |
|
| — |
|
|
| 1,439 |
|
Other, net |
| 224 |
|
|
| 639 |
|
|
| 401 |
|
|
| 519 |
|
Total costs and expenses |
| 58,152 |
|
|
| 82,316 |
|
|
| 186,563 |
|
|
| 269,933 |
|
Operating income (loss) |
| 14,807 |
|
|
| 3,206 |
|
|
| 11,083 |
|
|
| (5,491 | ) |
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net |
| (5,276 | ) |
|
| (5,336 | ) |
|
| (13,787 | ) |
|
| (17,395 | ) |
Loss on lease |
| (4,237 | ) |
|
| — |
|
|
| (4,237 | ) |
|
| — |
|
Other income (expense) |
| (104 | ) |
|
| (2 | ) |
|
| (104 | ) |
|
| — |
|
Total other income (expense) |
| (9,617 | ) |
|
| (5,338 | ) |
|
| (18,128 | ) |
|
| (17,395 | ) |
Income (loss) before reorganization items, net and income taxes |
| 5,190 |
|
|
| (2,132 | ) |
|
| (7,045 | ) |
|
| (22,886 | ) |
Reorganization items, net |
| (33 | ) |
|
| (466 | ) |
|
| (684 | ) |
|
| (1,752 | ) |
Income tax benefit (expense) |
| — |
|
|
| — |
|
|
| 50 |
|
|
| — |
|
Net income (loss) |
| 5,157 |
|
|
| (2,598 | ) |
|
| (7,679 | ) |
|
| (24,638 | ) |
Net (income) loss allocated to participating restricted stockholders |
| (128 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Net income (loss) attributable to common stockholders | $ | 5,029 |
|
| $ | (2,598 | ) |
| $ | (7,679 | ) |
| $ | (24,638 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share: (See Note 10) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted earnings per share | $ | 0.15 |
|
| $ | (0.10 | ) |
| $ | (0.29 | ) |
| $ | (0.98 | ) |
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted |
| 33,707 |
|
|
| 25,073 |
|
|
| 26,093 |
|
|
| 25,037 |
|
The accompanying notes are an integral part of these unaudited interim condensed consolidated financial statements.
MIDSTATES PETROLEUM COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(Unaudited)
(In thousands)
|
| Series A |
| Common |
| Warrants |
| Treasury |
| Additional |
| Retained |
| Total |
| |||||||
Balance as of December 31, 2018 |
| $ | — |
| $ | 255 |
| $ | 37,329 |
| $ | (2,455 | ) | $ | 531,911 |
| $ | (25,363 | ) | $ | 541,677 |
|
Share-based compensation |
| — |
| 1 |
| — |
| — |
| (60 | ) | — |
| (59 | ) | |||||||
Acquisition of treasury stock |
| — |
| — |
| — |
| (50,262 | ) | — |
| — |
| (50,262 | ) | |||||||
Net loss |
| — |
| — |
| — |
| — |
| — |
| (17,807 | ) | (17,807 | ) | |||||||
Retirement of treasury stock |
| — |
| (50 | ) | — |
| 50,000 |
| (49,950 | ) | — |
| — |
| |||||||
Balance as of March 31, 2019 |
| $ | — |
| $ | 206 |
| $ | 37,329 |
| $ | (2,717 | ) | $ | 481,901 |
| $ | (43,170 | ) | $ | 473,549 |
|
|
| Series A |
| Common |
| Warrants |
| Treasury |
| Additional |
| Retained |
| Total |
| |||||||
Balance as of December 31, 2017 |
| $ | — |
| $ | 253 |
| $ | 37,329 |
| $ | (1,603 | ) | $ | 524,755 |
| $ | (75,147 | ) | $ | 485,587 |
|
Share-based compensation |
| — |
| 1 |
| — |
| — |
| 2,795 |
| — |
| 2,796 |
| |||||||
Acquisition of treasury stock |
| — |
| — |
| — |
| (459 | ) | — |
| — |
| (459 | ) | |||||||
Net income |
| — |
| — |
| — |
| — |
| — |
| 4,004 |
| 4,004 |
| |||||||
Balance as of March 31, 2018 |
| $ | — |
| $ | 254 |
| $ | 37,329 |
| $ | (2,062 | ) | $ | 527,550 |
| $ | (71,143 | ) | $ | 491,928 |
|
The accompanying notes are an integral part of these unaudited interim condensed consolidated financial statements.
MIDSTATES PETROLEUM COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
|
| For the Three Months |
| ||||
|
| Ended March 31, |
| ||||
|
| 2019 |
| 2018 |
| ||
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
| ||
Net income (loss) |
| $ | (17,807 | ) | $ | 4,004 |
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
| ||
Losses on commodity derivative contracts—net |
| 7,732 |
| 3,939 |
| ||
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments |
| 769 |
| (160 | ) | ||
Asset retirement accretion |
| 157 |
| 297 |
| ||
Depreciation, depletion, and amortization |
| 11,794 |
| 15,213 |
| ||
Impairment in carrying value of oil and gas properties |
| 9,653 |
| — |
| ||
Share-based compensation, net of amounts capitalized to oil and gas properties |
| 966 |
| 2,210 |
| ||
Amortization of deferred financing costs |
| 174 |
| 108 |
| ||
Change in operating assets and liabilities: |
|
|
|
|
| ||
Accounts receivable—oil and gas sales |
| 3,573 |
| 1,293 |
| ||
Accounts receivable—JIB and other |
| 1,613 |
| (663 | ) | ||
Other current and noncurrent assets |
| (1,529 | ) | (1,750 | ) | ||
Accounts payable |
| 1,044 |
| (1,467 | ) | ||
Accrued liabilities |
| (4,972 | ) | (869 | ) | ||
Other |
| (2 | ) | (8 | ) | ||
Net cash provided by operating activities |
| $ | 13,165 |
| $ | 22,147 |
|
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
| ||
Investment in property and equipment |
| $ | (9,527 | ) | $ | (31,758 | ) |
Net cash used in investing activities |
| $ | (9,527 | ) | $ | (31,758 | ) |
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
| ||
Repayment of revolving credit facility |
| $ | (3,000 | ) | $ | (50,000 | ) |
Proceeds from revolving credit facility |
| 39,000 |
| — |
| ||
Repurchase of restricted stock for tax withholdings |
| (262 | ) | (459 | ) | ||
Common stock repurchased and retired |
| (50,000 | ) | — |
| ||
Net cash used in financing activities |
| $ | (14,262 | ) | $ | (50,459 | ) |
NET DECREASE IN CASH AND CASH EQUIVALENTS |
| $ | (10,624 | ) | $ | (60,070 | ) |
Cash and cash equivalents, beginning of period |
| $ | 11,341 |
| $ | 68,498 |
|
Cash and cash equivalents, end of period |
| $ | 717 |
| $ | 8,428 |
|
|
|
|
|
|
| ||
SUPPLEMENTAL INFORMATION: |
|
|
|
|
| ||
Non-cash transactions — investments in property and equipment accrued — not paid |
| $ | 3,552 |
| $ | 18,508 |
|
Cash paid for interest, net of capitalized interest of $0.1 million, respectively |
| $ | 664 |
| $ | 1,785 |
|
Right-of-use assets obtained in exchange for operating lease liabilities |
| $ | 4,857 |
| $ | — |
|
The accompanying notes are an integral part of these unaudited interim condensed consolidated financial statements.
MIDSTATES PETROLEUM COMPANY, INC.
See Accompanying Notes to Unaudited Interim Condensed Consolidated Financial StatementsStatements.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(In thousands)
| For the Nine Months Ended |
| |||||
| September 30, |
| |||||
| 2019 |
|
| 2018 |
| ||
Cash flows from operating activities: |
|
|
|
|
|
|
|
Net income (loss) | $ | (7,679 | ) |
| $ | (24,638 | ) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
| 39,696 |
|
|
| 39,932 |
|
(Gain) loss on derivative instruments |
| (18,897 | ) |
|
| 67,218 |
|
Cash settlements (paid) received on expired derivative instruments |
| 2,315 |
|
|
| 6,287 |
|
Bad debt expense |
| 266 |
|
|
| — |
|
Amortization and write-off of deferred financing costs |
| 62 |
|
|
| 2,249 |
|
Accretion of asset retirement obligations |
| 4,071 |
|
|
| 4,419 |
|
(Gain) loss on sale of properties |
| — |
|
|
| 1,439 |
|
Share-based compensation (see Note 11) |
| 4,073 |
|
|
| 3,090 |
|
Settlement of asset retirement obligations |
| (259 | ) |
|
| (600 | ) |
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
Accounts receivable |
| 11,328 |
|
|
| 7,252 |
|
Prepaid expenses and other assets |
| (1,968 | ) |
|
| 1,698 |
|
Payables and accrued liabilities |
| (12,115 | ) |
|
| 8,279 |
|
Other |
| 4,995 |
|
|
| (15 | ) |
Net cash provided by operating activities |
| 25,888 |
|
|
| 116,610 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
Cash acquired from the Merger |
| 19,250 |
|
|
| — |
|
Additions to oil and gas properties |
| (63,004 | ) |
|
| (46,002 | ) |
Additions to other property and equipment |
| 788 |
|
|
| (167 | ) |
Additions to restricted investments |
| (154 | ) |
|
| (413 | ) |
Withdrawals of restricted investments |
| 90,000 |
|
|
| — |
|
Proceeds from the sale of other property and equipment |
| 31 |
|
|
| — |
|
Proceeds from the sale of oil and natural gas properties, net of cash and cash equivalents sold |
| — |
|
|
| 18,088 |
|
Other |
| — |
|
|
| 503 |
|
Net cash provided by (used in) investing activities |
| 46,911 |
|
|
| (27,991 | ) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
Advances on revolving credit facilities |
| 103,000 |
|
|
| 21,000 |
|
Payments on revolving credit facilities |
| (119,000 | ) |
|
| (103,000 | ) |
Repayment of Midstates revolving credit facility |
| (76,559 | ) |
|
| — |
|
Deferred financing costs |
| (832 | ) |
|
| (18 | ) |
Dividends to stockholders |
| (8,189 | ) |
|
| — |
|
Costs incurred in conjunction with tender offer |
| (107 | ) |
|
| — |
|
Common stock repurchased and retired under the share repurchase program |
| (13,251 | ) |
|
| — |
|
Restricted units returned to plan |
| (313 | ) |
|
| (815 | ) |
Other |
| 156 |
|
|
| 9 |
|
Net cash provided by (used in) financing activities |
| (115,095 | ) |
|
| (82,824 | ) |
Net change in cash, cash equivalents and restricted cash |
| (42,296 | ) |
|
| 5,795 |
|
Cash, cash equivalents and restricted cash, beginning of period |
| 50,029 |
|
|
| 6,392 |
|
Cash, cash equivalents and restricted cash, end of period | $ | 7,733 |
|
| $ | 12,187 |
|
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY
(In thousands)
| Stockholders' Equity |
|
|
|
|
| |||||||||||||||||
| Common Stock |
|
| Warrants |
|
| Additional Paid-in Capital |
|
| Treasury Stock |
|
| 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 | ) |
Balance at March 31, 2019 | $ | 3 |
|
| $ | 4,788 |
|
| $ | 356,288 |
|
| $ | — |
|
| $ | 24,418 |
|
| $ | 385,497 |
|
Net income (loss) |
| — |
|
|
| — |
|
|
| — |
|
|
|
|
|
|
| 18,641 |
|
|
| 18,641 |
|
Share-based compensation expense |
| — |
|
|
| — |
|
|
| 1,479 |
|
|
|
|
|
|
| — |
|
|
| 1,479 |
|
Common stock repurchased and retired under the share repurchase program |
| — |
|
|
| — |
|
|
| (331 | ) |
|
|
|
|
|
| — |
|
|
| (331 | ) |
Restricted shares repurchased |
| — |
|
|
| — |
|
|
| (199 | ) |
|
|
|
|
|
| — |
|
|
| (199 | ) |
Balance at June 30, 2019 | $ | 3 |
|
| $ | 4,788 |
|
| $ | 357,237 |
|
| $ | — |
|
| $ | 43,059 |
|
| $ | 405,087 |
|
Net income (loss) |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 5,157 |
|
|
| 5,157 |
|
Equity transactions related to the Merger |
| 206 |
|
|
| 2 |
|
|
| 91,038 |
|
|
| — |
|
|
| — |
|
|
| 91,246 |
|
Treasury shares acquired in the Merger |
| — |
|
|
| — |
|
|
| — |
|
|
| (2,723 | ) |
|
| — |
|
|
| (2,723 | ) |
Retirement of treasury shares |
| — |
|
|
| — |
|
|
| (2,723 | ) |
|
| 2,723 |
|
|
| — |
|
|
| — |
|
Share-based compensation expense |
| — |
|
|
| — |
|
|
| 1,151 |
|
|
| — |
|
|
| — |
|
|
| 1,151 |
|
Common stock repurchased and retired under the share repurchase program |
| — |
|
|
| — |
|
|
| (12,000 | ) |
|
| — |
|
|
| — |
|
|
| (12,000 | ) |
Dividends |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (8,189 | ) |
|
| (8,189 | ) |
Restricted shares repurchased |
| — |
|
|
| — |
|
|
| (115 | ) |
|
| — |
|
|
| — |
|
|
| (115 | ) |
Other |
| — |
|
|
| — |
|
|
| 431 |
|
|
| — |
|
|
| — |
|
|
| 431 |
|
Balance at September 30, 2019 | $ | 209 |
|
| $ | 4,790 |
|
| $ | 435,019 |
|
| $ | — |
|
| $ | 40,027 |
|
| $ | 480,045 |
|
| 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 |
|
Restricted shares repurchased |
| — |
|
|
| — |
|
|
| (208 | ) |
|
| — |
|
|
| (208 | ) |
Balance at March 31, 2018 | $ | 3 |
|
| $ | 4,788 |
|
| $ | 388,824 |
|
| $ | 4,525 |
|
| $ | 398,140 |
|
Net income (loss) |
| — |
|
|
| — |
|
|
| — |
|
|
| (25,279 | ) |
|
| (25,279 | ) |
Share-based compensation expense |
| — |
|
|
| — |
|
|
| 336 |
|
|
| — |
|
|
| 336 |
|
Restricted shares repurchased |
| — |
|
|
| — |
|
|
| (301 | ) |
|
| — |
|
|
| (301 | ) |
Balance at June 30, 2018 | $ | 3 |
|
| $ | 4,788 |
|
| $ | 388,859 |
|
| $ | (20,754 | ) |
| $ | 372,896 |
|
Net income (loss) |
| — |
|
|
| — |
|
|
| — |
|
|
| (2,598 | ) |
|
| (2,598 | ) |
Share-based compensation expense |
| — |
|
|
| — |
|
|
| 1,578 |
|
|
| — |
|
|
| 1,578 |
|
Restricted shares repurchased |
| — |
|
|
| — |
|
|
| (306 | ) |
|
| — |
|
|
| (306 | ) |
Other |
| — |
|
|
| — |
|
|
| 9 |
|
|
| — |
|
|
| 9 |
|
Balance at September 30, 2018 | $ | 3 |
|
| $ | 4,788 |
|
| $ | 390,140 |
|
| $ | (23,352 | ) |
| $ | 371,579 |
|
See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
9
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization and BusinessBasis of Presentation
General
On August 6, 2019, Midstates Petroleum Company, Inc. engages(“Midstates”) completed its business combination (the “Merger”) with Amplify Energy Corp. (“Legacy Amplify”) in accordance with the terms of that certain Agreement and Plan of Merger, dated May 5, 2019 (the “Merger Agreement”), by and among Midstates, Legacy Amplify and Midstates Holdings, Inc., a Delaware corporation and direct, wholly owned subsidiary of Midstates (“Merger Sub”). Pursuant to the terms of the Merger Agreement, Merger Sub merged with and into Legacy Amplify, with Legacy Amplify surviving the Merger as a wholly owned subsidiary of Midstates, and immediately following the Merger, Legacy Amplify merged with and into Alpha Mike Holdings LLC, a Delaware limited liability company and wholly owned subsidiary of Midstates (“LLC Sub”), with LLC Sub surviving as a wholly owned subsidiary of Midstates. On the effective date of the Merger, Midstates changed its name to “Amplify Energy Corp.” (the “Company”) and LLC Sub changed its name to “Amplify Energy Holdings LLC.”
For financial reporting purposes, the Merger represented a “reverse merger” and Legacy Amplify was deemed to be the accounting acquirer in the businesstransaction. Legacy Amplify’s historical results of exploring and drillingoperations will replace Midstates’ historical results of operations for and the production of, oil, natural gas liquids (“NGLs”) and natural gas. Midstates Petroleum Company, Inc. was incorporated pursuantall periods prior to the lawsMerger and, for all periods following the Merger, the Company’s financial statements will reflect the results of operations of the Statecombined company. Accordingly, the financial statements for the Company included in this Quarterly Report for periods prior to the Merger are not the same as Midstates prior reported filings with the SEC, which were derived from the operations of Delaware on October 25, 2011 to becomeMidstates. As a holding company for Midstates Petroleum Company LLC (“Midstates Sub”).result, period-to-period comparisons of our operating results may not be meaningful. The terms “Company,” “we,” “us,” “our,”results of any one quarter should not be relied upon as an indication of future performance.
We operate in one reportable segment engaged in the acquisition, development, exploitation and similar terms refer to Midstates Petroleum Company, Inc. and its subsidiary.
The Company currently conducts oil and gas operations and owns and operates oil and natural gas properties in Oklahoma. The Company operates nearly allproduction of its oil and natural gas properties. The Company’sOur management evaluates performance based on one reportable business segment as allthe economic environments are not different within the operation of its operationsour oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Oklahoma, the United StatesRockies, federal waters offshore Southern California, East Texas / North Louisiana and therefore, it maintains one cost center.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.
2. Summary of Significant Accounting Policies
Basis of Presentation
These unaudited interim condensed consolidated financial statementsOur Unaudited Condensed Consolidated Financial Statements included herein have been prepared pursuant to the rules and regulationsguidelines of the Securities and Exchange Commission (“SEC”(the “SEC”) regarding interim financial reporting. Certain. 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 have been condensed or omitted from these financial statements. Accordingly,in these financial statements do not include all of theare adequate, certain information and notes required byfootnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) for complete consolidatedhave been condensed or omitted pursuant to the rules and regulations of the SEC.
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 should be read in conjunctionevents that are directly associated with the audited consolidated financial statementsreorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and notes thereto for the year ended December 31, 2018, includedlosses that were realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s Annual Report on Form 10-K as filed with the SEC on March 14, 2019.
Unaudited Condensed Statements of Consolidated Operations.
All material intercompany transactions and balances have been eliminated in consolidation. Inpreparation of our consolidated financial statements.
Beginning in 2019, the opinionCompany 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 balanced approach to development of our oil and natural gas asset portfolio. Legacy Amplify’s proved reserves as of year-end 2018 were 50% crude oil, 15% natural gas liquids and 35% natural gas.
Definitive Merger Agreement
On May 5, 2019, as discussed above, the Company entered into the Merger Agreement pursuant to which Legacy Amplify merged with a subsidiary of Midstates in an all-stock merger-of-equals. Under the terms of the Company’s management,Merger Agreement, Legacy Amplify stockholders received 0.933 shares of newly issued Company common stock for each share of Legacy Amplify common stock that they owned. The Merger closed on August 6, 2019.
10
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The preparation of the accompanying unaudited interim condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessaryUnaudited Condensed Consolidated Financial Statements in conformity with GAAP requires management to fairly present the financial position as of, and the results of operations for, all periods presented. In preparing the accompanying unaudited interim condensed consolidated financial statements, management has made certainmake estimates and assumptions that affect the reported amounts inof assets and liabilities and disclosure of contingent assets and liabilities at the unaudited interim condenseddate of the consolidated financial statements and disclosuresthe reported amounts of contingencies.revenues and expenses during the reporting period. Actual results maycould differ from those estimates. The results for interim periods
Significant estimates include, but are not necessarily indicativelimited to, oil and natural gas reserves; depreciation, depletion, and amortization of annual results.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. Summary of Significant Accounting Policies
Recent Accounting Pronouncements Adopted DuringA discussion of our significant accounting policies and estimates is included in Legacy Amplify Form 10-K.
Reorganization Items, Net
The Company has incurred significant costs associated with the Periodreorganization. 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.
The following table summarizes the components of reorganization items, net included in the accompanying Unaudited Condensed Statements of Consolidated Operations (in thousands):
| For the Three Months Ended |
|
| For the Nine Months Ended |
| ||||||||||
| September 30, |
|
| September 30, |
| ||||||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
Professional fees |
| 104 |
|
|
| (14 | ) |
|
| (241 | ) |
|
| (638 | ) |
Other |
| (137 | ) |
|
| (452 | ) |
|
| (443 | ) |
|
| (1,114 | ) |
Reorganization items, net | $ | (33 | ) |
| $ | (466 | ) |
| $ | (684 | ) |
| $ | (1,752 | ) |
Lease Recognition
In July 2017,February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2017-11, “Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815)” (“ASU 2017-11”). ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“EPS”) in accordance with Topic 260 to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for the Company for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The adoption of ASU 2017-11 did not have a material impact on its financial position, results of operations or cash flows.
In June 2018, the FASB issued Accounting Standards Update 2018-07, “Compensation - Stock Compensation (Topic 718) — Improvements to Nonemployee Share-Based Payment Accounting” (“ASU 2018-07”). ASU 2018-07 expands the scope of Topic 718 to include share-based payments issued to non-employees for goods and services. Consequently,guidance regarding the accounting for share-based paymentsleases. The FASB retained a dual model, requiring leases to non-employees and employeesbe classified as either direct financing or operating leases. The classification will be substantially aligned. The new standard is effective forbased on criteria that are similar to the Company for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The adoption of ASU 2018-07 did not have a material impact on its financial position, results of operations or cash flows.
In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases (Topic 842)” (“ASU 2016-02”). ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and acurrent lease liability on the balance sheet for all leases with terms longer than 12 months.accounting treatment. The Company adopted ASU 2016-02is 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.
The Company applied the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using the modified retrospective transition approach. See “—Note 3. Impactapproach with a cumulative impact to retained earnings in that period, and including several optional practical expedients relating to leases commenced before the effective date. The practical expedients the Company adopted are: (1) the original correct assessment of ASU 842 Adoption” below for further details.
Recent Accounting Pronouncements Issued But Not Yet Adopted
In June 2016, the FASB issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (“ASU 2016-13”). ASU 2016-13 replaces the incurred loss model with an expected loss model, which is referred to as the current expected credit loss (“CECL”) model. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to trade receivables. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Company is still performing its evaluation of ASU 2016-13, but does not believe it will have a material impact on its consolidated financial statements at this time.
3. Impact of ASU 842 Adoption
In February 2016, the FASB issued ASU 2016-02, which establishescontract containing a ROU model that requires a lessee to record a ROU asset and lease liability on the balance sheet for all leases with terms longer than 12 months. All leases create an asset and a liability for the lessee and therefore recognition of those lease assets and lease liabilities is required by ASU 2016-02. When measuring lease assets and liabilities, payments to be made for optional extension periods should be included if the lessee is reasonably certain to exercise the option. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 does not impact the accounting or financial presentation of mineral leases and does not apply to leases to explore for or use oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.
In January 2018, the FASB issued ASU 2018-01, “Leases (Topic 842)-Land Easement Practical Expedient for Transition to Topic 842” (“ASU 2018-01”). ASU 2018-01 permits an entity to elect an optional transition practical expedient to not evaluate land easements that existaccepted without further review on all existing or expired prior to a company’s adoption of ASU 2016-02 and that were not accounted forcontracts; (2) the original lease classification as leases under previousan operating lease guidance. Additionally, in July 2018, the FASB issued ASU 2018-11, “Leases (Topic 842): Targeted Improvements” (“ASU 2018-11”), which included the option to implement the standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings,will convert as opposed to the modified retrospective transition method required when ASU 2016-02 was issued. The new standard was effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.
The Company has analyzed and categorized its contracts to determine if they meet the definition of aan operating lease under ASU 2016-02 and has adopted the new standard using the simplified transition method described in ASU 2018-11 as of January 1, 2019. Consequently, financial information will not be updated, and the disclosures required under the new standard will not be provided for the dates and periods before January 1, 2019. Additionally, the Company has elected the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii)guidance; (3) initial direct costs for any existing leases butwill 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 leases standard.
New Accounting Pronouncements
Financial Instruments — Credit Losses. In May 2019 the FASB issued an accounting standards update to provide entities with an option to irrevocably elect the fair value option applied on an instrument-by-instrument basis for certain financial assets upon the adoption. The fair value option election does not apply to held-to-maturity debt securities. The new guidance is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. The Company notes that the impact of this guidance will not be material to the Company’s financial statements and related disclosures.
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not electedexpected to have a material impact on the Company’s financial position, results of operations and cash flows.
11
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 September 30, 2019.
Disaggregation of Revenue
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 |
|
| For the Nine Months Ended |
| ||||||||||
| September 30, |
|
| September 30, |
| ||||||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
| (in thousands) |
| |||||||||||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil | $ | 55,011 |
|
| $ | 52,576 |
|
| $ | 136,754 |
|
| $ | 165,843 |
|
NGLs |
| 4,306 |
|
|
| 12,132 |
|
|
| 15,509 |
|
|
| 34,009 |
|
Natural gas |
| 13,109 |
|
|
| 20,738 |
|
|
| 44,715 |
|
|
| 64,335 |
|
Oil and natural gas sales | $ | 72,426 |
|
| $ | 85,446 |
|
| $ | 196,978 |
|
| $ | 264,187 |
|
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 $28.2 million at September 30, 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 hindsight when determiningproduct delivered to the leasecustomer 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 existing contracts at the effective date. The Company also electedone year or less, we have utilized the practical expedient under ASU 2018-01in 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.
12
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 4. Acquisitions and has not evaluated existing or expired land easements not previouslyDivestitures
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):
For the Three Months Ended |
|
| For the Nine Months Ended |
| ||||||||||
September 30, |
|
| September 30, |
| ||||||||||
2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
$ | 12,833 |
|
| $ | 82 |
|
| $ | 16,655 |
|
| $ | 969 |
|
Business Combination
Acquisitions qualifying as a business combination are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the condensed consolidated balance sheet at their fair values as leasesof the acquisition date. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates at the time of the valuation.
Merger
On May 5, 2019, Midstates, Legacy Amplify and Merger Sub entered into the Merger Agreement pursuant to which, Merger Sub merged with and into Legacy Amplify, with Legacy Amplify surviving the Merger as a wholly owned subsidiary of Midstates. At the effective time of the Merger, each share of Legacy Amplify common stock issued and outstanding immediately prior to the effective time (other than excluded shares) were cancelled and converted into the right to receive 0.933 shares of Midstates common stock, par value $0.01 per share. On August 6, 2019, the effective date of the Merger, Midstates changed its name to “Amplify Energy Corp.”
Purchase Price Allocation
The Merger has been accounted for using the acquisition method, with Legacy Amplify treated as the acquirer for accounting purposes. The following table represents the preliminary allocation of the total purchase price of Midstates to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date. The new standard also provides practical expedients for an entity’s ongoing accounting. The Company electedCertain data necessary to complete the short-term lease recognition exemption for all leasespurchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-acquisition contingencies, final tax returns that qualify. The Company also electedprovide the practical expedientunderlying tax basis of Midstates assets and liabilities and final appraisals of assets acquired and liabilities assumed. We expect to not separate leasecomplete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and non-lease components for the majority of classes of underlying assets.liabilities may be revised as appropriate.
13
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Through its implementation process, the Company evaluated each of its lease arrangements and enhanced its systems to track and calculate additional information required upon adoption of this standard. The standard had an impact on the Company’s unaudited interim condensed consolidated balance sheets as of March 31, 2019, with the primary change relating to the recognition of ROU assets and lease liabilities for operating leases. Adoption of the new lease standard had an immaterial impact to the Company’s unaudited interim condensed consolidated statement of operations and cash provided from or used
| Purchase Price Allocation |
| |
| (In thousands) |
| |
Consideration: |
|
|
|
Fair value of Midstates common stock issued in the Merger (a) | $ | 90,150 |
|
Fair value of Midstates warrants issued in the Merger |
| 2 |
|
Total consideration | $ | 90,152 |
|
|
|
|
|
Fair value of liabilities assumed: |
|
|
|
Current liabilities | $ | 24,135 |
|
Long-term debt |
| 76,559 |
|
Long-term asset retirement obligation |
| 9,440 |
|
Other long-term liabilities |
| 5,067 |
|
Amounts attributable to liabilities assumed | $ | 115,201 |
|
|
|
|
|
Fair value of assets acquired: |
|
|
|
Cash and cash equivalents | $ | 19,250 |
|
Other current assets |
| 17,862 |
|
Oil and natural gas properties |
| 142,642 |
|
Other property and equipment |
| 6,280 |
|
Long-term asset retirement cost |
| 9,440 |
|
Other non-current assets |
| 9,879 |
|
Amounts attributable to assets acquired | $ | 205,353 |
|
|
|
|
|
Total identifiable net assets | $ | 90,152 |
|
(a) | Based on 20,415,005 Midstates common shares issued at closing at $4.12 per share (closing price as of August 6, 2019). |
We included in operating, investing or financing activities in its unaudited interimour condensed consolidated statements of cash flowsoperations revenues of $12.7 million, direct operating expense of $17.7 million and other expenses of $0.2 million for our Oklahoma properties for the period after the Merger closed.
During the quarter ended September 30, 2019, the Company completed an analysis of Midstates asset retirement obligations as of the acquisition date. Based on this analysis, the Company recorded a measurement period adjustment of $0.9 to increase the asset retirement obligations liability.
During the quarter ended September 30, 2019, the Company completed an analysis of Midstates leases under ASC 842 as of the acquisition date. Based on this analysis, the Company recorded an operating lease right of use asset and liability of approximately $0.3 million.
Unaudited Pro Forma Financials
The following unaudited pro forma financial information for the three and nine months ended March 31, 2019. Further discussion of the Company’s accounting for lease arrangements under ASC 842September 30, 2019 and 2018, respectively, is included below.
Leases
The Company determines if an arrangement is a lease at inception of the arrangement. To the extent that it is determined an arrangement represents a lease, the Company classifies that lease as an operating lease or a finance lease. The Company capitalizes operating and finance leases on its unaudited interim condensed consolidated balance sheets through a ROU asset and a corresponding lease liability. ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the Company’s obligation to make lease payments arising from the lease.
Operating leases are included in operating lease ROU assets, and operating lease liabilities in the unaudited interim condensed consolidated balance sheets at March 31, 2019. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on our historical consolidated financial statements adjusted to reflect as if the present value of lease payments over the lease term. The operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.
As of March 31, 2019, the CompanyMerger had no leases classified as finance leases.
Nature of Leases
In support of the Company’s operations, it leases certain office space, field offices, office equipment, compressors, other production equipment and fleet vehicles under cancelable and non-cancelable contracts. A more detailed description of material lease types is included below.
Corporate and Field Offices
The Company enters into long-term contracts to lease corporate and field office space in support of operations. These contracts are generally structured with an initial non-cancelable term of three to five years. To the extent that corporate and field office contracts include renewal options, the Company evaluates whether it is reasonably certain to exercise those options on a contract by contract basis based on expected future office space needs, market rental rates, drilling plans and other factors. The Company has further determined that its current corporate and field office leases represent operating leases.
Compressors
The Company rents compressors from third-parties in order to facilitate the downstream movement of its production to market. Compressor arrangements are typically structured with a non-cancelable primary term of one to twenty-four months and often continue thereafter on a month-to-month basis subject to termination by either party with thirty-days’ notice. The Company has concluded that its compressor rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease without incurring a significant penalty. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term.
To the extent that compressor rental arrangements have a primary term of twelve-months or less, the Company has elected to apply the practical expedient for short-term leases. For those short-term compressor contracts, the Company does not apply the lease recognition requirements, and recognizes lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term. Refer to “Practical Expedients & Accounting Policy Elections” below for additional detail.
Other Production Equipment
The Company rents other production equipment from third-party vendors to be used in its production operations. These arrangements are typically structured on a month-to-month basis subject to termination by either party with thirty-days’ notice. The Company has concluded that it is not reasonably certain of executing the month-to-month renewal options beyond a twelve-month period based on the historical term for which it has used other production equipment, and, therefore, its other equipment agreements represent operating leases with a lease term up to twelve months.
The Company has further elected to apply the practical expedient for short-term leases to its other production equipment contracts. Accordingly, it does not apply the lease recognition requirements to these contracts, and recognizes lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term. Refer to “Practical Expedients & Accounting Policy Elections” below for additional detail.
Fleet Vehicles
The Company executes fleet vehicle leases with a third-party vendor in support of its day-to-day drilling and production operations. Its vehicle leases are typically structured with a term of a minimum of 367 days for passenger and light duty vehicles and a minimum of 24 months for commercial vehicles and continue thereafter on a month-to-month basis subject to termination by either party within thirty-days’ notice. The Company has concluded that its fleet vehicle leases represent operating leases.
Significant Judgments
Transportation, Gathering and Processing Arrangements
The Company is party to a gas purchase, gathering and processing contract in the Mississippian Lime region, which includes certain minimum NGLs volume commitments. To the extent the Company does not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLs, it would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee. The Company is currently delivering at least the minimum volumes required under these contractual provisions. However, decreased drilling activity could result in the inability to meet these commitments in the future.
As the Company does not utilize substantially all of the underlying pipeline, gathering system or processing facilities, it has concluded that those underlying assets do not meet the definition of an identified asset.
Discount Rate
The Company’s leases typically do not provide an implicit rate, and thus, is required to use its incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. The Company’s incremental borrowing rate reflects the rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. In order to determine its incremental borrowing rate, the Company utilizes its current credit rating as well as best available market data, which includes public bond information for publicly traded upstream energy companies with similar credit ratings, to estimate its unsecured borrowing rate and applied adjustments to that rate to account for the effect of collateral.
The Company has determined the discount rate as of January 1, 2019, using end of day December 31, 2018, market data. This discount rate will be used at transition to ASC 842 as well as all new leases executed within 2019. The Company intends to update the discount rate annually thereafteroccurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including adjustments to be usedconform the classification of expenses in Midstates statements of operations to our classification for all new leases withinsimilar expenses and the year (for example,estimated tax impact of pro forma adjustments. The unaudited pro forma financial information is not necessarily indicative of what actually would have occurred if the discount rate will be updatedacquisition had been completed as of January 1, 2020, to be applied to all new leases in 2020). In the event a material lease is executed within a fiscal year or there have been material changes in the market that would impact the Company’s discount rate, the Company will evaluate whether an intra-year updatebeginning of the discount rateperiods presented, nor is required.it necessarily indicative of future results.
| For the Three Months Ended |
|
| For the Nine Months Ended |
| ||||||||||
| September 30, |
|
| September 30, |
| ||||||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
(Unaudited) | (In thousands, except per unit amounts) |
| |||||||||||||
Revenues | $ | 80,482 |
|
| $ | 139,870 |
|
| $ | 258,547 |
|
| $ | 425,306 |
|
Net income (loss) |
| 6,845 |
|
|
| 20,542 |
|
|
| 6,236 |
|
|
| 25,269 |
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic | $ | 0.20 |
|
| $ | 0.41 |
|
| $ | 0.24 |
|
| $ | 0.50 |
|
Diluted | $ | 0.20 |
|
| $ | 0.41 |
|
| $ | 0.24 |
|
| $ | 0.50 |
|
Divestitures
On May 30, 2018, we closed a transaction to divest certain of our non-core assets located in South Texas (the “South Texas Divestiture”) for total proceeds of approximately $17.1 million, including final post-closing adjustments. This disposition did not qualify as a discontinued operation.
14
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Practical Expedients & Accounting Policy Elections
Certain of the Company’s lease agreements include lease and non-lease components. For all current asset classes with multiple component types, the Company has utilized the practical expedient that exempts an entity from separating lease components from non-lease components. Accordingly, the Company accounts for the lease and non-lease components in an arrangement as a single lease component.
In addition, for all asset classes, the Company has made an accounting policy election not to apply the lease recognition requirements to its short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less, including renewal options expected to be exercised, and does not include an option to purchase the underlying asset that is reasonably certain to be exercised). Accordingly, the Company recognizes lease payments related to its short-term leases in profit or loss on a straight-line basis over the lease term. To the extent that there are variable lease payments, those payments are recognized in profit or loss in the period in which the obligation for those payments is incurred. Refer to “Nature of Leases” above for further information regarding those asset classes that include material short-term leases.
4.Note 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 the derivative instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets were considered Level 2.
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, 2019 and December 31, 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.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Derivative Instruments
Commodity derivative contracts reflected in the unaudited interim condensed consolidated balance sheets are recorded at estimatedThe fair value. At March 31, 2019, allmarket values of the Company’sderivative financial instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018 were based on estimated forward commodity derivative contracts were with four bank counterpartiesprices. Financial assets and wereliabilities are classified as Level 2 inbased on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input hierarchy. 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, 2019 and December 31, 2018 for each of the fair value hierarchy levels:
| Fair Value Measurements at September 30, 2019 Using |
| |||||||||||||
| Quoted Prices in |
|
| Significant Other |
|
| Significant |
|
|
|
|
| |||
| Active Market |
|
| Observable Inputs |
|
| Unobservable Inputs |
|
|
|
|
| |||
| (Level 1) |
|
| (Level 2) |
|
| (Level 3) |
|
| Fair Value |
| ||||
| (In thousands) |
| |||||||||||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives | $ | — |
|
| $ | 41,758 |
|
| $ | — |
|
| $ | 41,758 |
|
Interest rate derivatives |
| — |
|
|
| 307 |
|
|
| — |
|
|
| 307 |
|
Total assets | $ | — |
|
| $ | 42,065 |
|
| $ | — |
|
| $ | 42,065 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives | $ | — |
|
| $ | 3,584 |
|
| $ | — |
|
| $ | 3,584 |
|
Interest rate derivatives |
| — |
|
|
| 755 |
|
|
| — |
|
|
| 755 |
|
Total liabilities | $ | — |
|
| $ | 4,339 |
|
| $ | — |
|
| $ | 4,339 |
|
| Fair Value Measurements at December 31, 2018 Using |
| |||||||||||||
| Quoted Prices in |
|
| Significant Other |
|
| Significant |
|
|
|
|
| |||
| Active Market |
|
| Observable Inputs |
|
| Unobservable Inputs |
|
|
|
|
| |||
| (Level 1) |
|
| (Level 2) |
|
| (Level 3) |
|
| Fair Value |
| ||||
| (In thousands) |
| |||||||||||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives | $ | — |
|
| $ | 25,515 |
|
| $ | — |
|
| $ | 25,515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives | $ | — |
|
| $ | 4,372 |
|
| $ | — |
|
| $ | 4,372 |
|
See Note 6 for additional information regarding our derivative instruments.
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 Company’s commodity derivatives is determined using industry-standard models that consider various assumptions including currentexistence 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 contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially allare classified within Level 3 of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.
Derivative instruments listed below are presented gross and include swaps and collars that are carried at fair value. The Company records the net change in the fair value hierarchy. See Note 7 for a summary of these positionschanges in gains (losses) on commodity derivative contracts — net in the Company’s unaudited interim condensed consolidated statements of operations.AROs.
15
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
| Fair Value Measurements at March 31, 2019 |
| ||||||||||
|
|
|
| Significant Other |
| Significant |
|
|
| ||||
|
| Quoted Prices in Active |
| Observable Inputs |
| Unobservable Inputs |
| Total |
| ||||
|
| (in thousands) |
| ||||||||||
Derivative Assets: |
|
|
|
|
|
|
|
|
| ||||
Commodity derivative oil swaps |
| $ | — |
| $ | 422 |
| $ | — |
| $ | 422 |
|
Commodity derivative gas swaps |
| $ | — |
| $ | 74 |
| $ | — |
| $ | 74 |
|
Commodity derivative oil collars |
| $ | — |
| $ | 1,944 |
| $ | — |
| $ | 1,944 |
|
Commodity derivative gas collars |
| $ | — |
| $ | 203 |
| $ | — |
| $ | 203 |
|
Total assets |
| $ | — |
| $ | 2,643 |
| $ | — |
| $ | 2,643 |
|
|
|
|
|
|
|
|
|
|
| ||||
Derivative Liabilities: |
|
|
|
|
|
|
|
|
| ||||
Commodity derivative oil swaps |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
Commodity derivative gas swaps |
| $ | — |
| $ | (80 | ) | $ | — |
| $ | (80 | ) |
Commodity derivative oil collars |
| $ | — |
| $ | (3,132 | ) | $ | — |
| $ | (3,132 | ) |
Commodity derivative gas collars |
| $ | — |
| $ | (281 | ) | $ | — |
| $ | (281 | ) |
Total liabilities |
| $ | — |
| $ | (3,493 | ) | $ | — |
| $ | (3,493 | ) |
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.
|
| Fair Value Measurements at December 31, 2018 |
| ||||||||||
|
|
|
| Significant Other |
| Significant |
|
|
| ||||
|
| Quoted Prices in Active |
| Observable Inputs |
| Unobservable Inputs |
| Total |
| ||||
|
| (in thousands) |
| ||||||||||
Derivative Assets: |
|
|
|
|
|
|
|
|
| ||||
Commodity derivative oil swaps |
| $ | — |
| $ | 3,806 |
| $ | — |
| $ | 3,806 |
|
Commodity derivative gas swaps |
| $ | — |
| $ | 236 |
| $ | — |
| $ | 236 |
|
Commodity derivative oil collars |
| $ | — |
| $ | 9,306 |
| $ | — |
| $ | 9,306 |
|
Commodity derivative gas collars |
| $ | — |
| $ | 577 |
| $ | — |
| $ | 577 |
|
Total assets |
| $ | — |
| $ | 13,925 |
| $ | — |
| $ | 13,925 |
|
|
|
|
|
|
|
|
|
|
| ||||
Derivative Liabilities: |
|
|
|
|
|
|
|
|
| ||||
Commodity derivative oil swaps |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
Commodity derivative gas swaps |
| $ | — |
| $ | (443 | ) | $ | — |
| $ | (443 | ) |
Commodity derivative oil collars |
| $ | — |
| $ | (5,199 | ) | $ | — |
| $ | (5,199 | ) |
Commodity derivative gas collars |
| $ | — |
| $ | (632 | ) | $ | — |
| $ | (632 | ) |
Total liabilities |
| $ | — |
| $ | (6,274 | ) | $ | — |
| $ | (6,274 | ) |
No impairments were recognized during the three or nine months ended September 30, 2019 and 2018, respectively.
5.Note 6. Risk Management and Derivative Instruments
The Company’s production is exposedDerivative instruments are utilized to manage exposure to commodity price fluctuations and achieve a more predictable cash flow in crude oil, NGLs andconnection with natural gas prices. The Company believes it is prudentand oil sales from production and borrowing related activities. These instruments limit exposure to managedeclines in prices, but also limit the variability in cash flows by, at times, entering into derivative financial instruments to economically hedge a portion of its crude and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and collars, to manage fluctuations in cash flows resulting from changes in commodity prices.benefits that would be realized if prices increase.
· Swaps: The Company receives or pays a fixed price for the commodity and pays or receives a floating market price to the counterparty. The fixed-price payment and the floating-price paymentCertain inherent business risks are netted, resulting in a net amount due to or from the counterparty.
· Three-way collars: A three-way collar contains a fixed floor price (long put), fixed sub-floor price (short put), and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, the Company receives the ceiling strike price and pays the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the sub-floor price, the Company receives the floor strike price and pays the market price. If the market price is below the sub-floor price, the Company receives the market price plus the difference between the floor and the sub-floor strike prices and pays the market price.
These derivative contracts are placedassociated with major financial institutions that the Company believes are minimal credit risks. The crude oil and natural gas reference prices upon which the commodity derivative contracts, are based reflect various market indices that management believes correlates with actual prices received by the Company for its crude and natural gas production.
Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commoditynatural 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 Company’s counterparty to a contract. The Company doesIt is our policy to enter into derivative contracts, 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 agreements are counterparties to our derivative contracts. While collateral is generally not require collateral from itsrequired to be posted by counterparties, but does attempt to minimize its 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, which management believes present minimal credit risk. In addition,institutions. Additionally, master netting agreements are used to mitigate its risk of loss due to default the Company haswith counterparties on derivative instruments. We have also entered into agreementsInternational Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with itseach of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties on its derivative instruments that allowwith rights of set-off upon the Company to offset its asset position with its liability position in the eventoccurrence of defined acts of default by either us or our counterparty to a derivative, whereby the counterparty. Dueparty not in default may set-off all liabilities owed to the netting arrangements,defaulting party against all net derivative asset receivables from the defaulting party. Had all counterparties failed completely to perform according to the terms of the existing contracts, we would have had the Company’s counterparties failedright to performoffset $36.6 million against amounts outstanding under existingour New Revolving Credit Facility (as defined below) at September 30, 2019, reducing our maximum credit exposure to approximately $1.4 million, of which approximately $1.2 million was with one counterparty. See Note 8 for additional information regarding our Emergence Credit Facility (as defined below) 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, costless collars and three-way collars) to manage exposure to commodity price volatility. We recognize all derivative contractsinstruments at March 31, 2019, the Company would not have experienced a loss.fair value.
Commodity Derivative Contracts
The Company enteredWe enter into various oil and natural gas derivative contracts that extend through December 31, 2020, summarized as follows: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.
16
|
| NYMEX WTI |
| ||||||||||||||
|
| Fixed Swaps |
| Three-Way Collars |
| ||||||||||||
|
| Hedge |
| Weighted |
| Hedge |
| Weighted |
| Weighted |
| Weighted |
| ||||
Quarter Ended: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
March 31, 2019 |
| 74,800 |
| $ | 66.48 |
| 180,000 |
| $ | 63.14 |
| $ | 53.75 |
| $ | 43.75 |
|
June 30, 2019(1) |
| 57,650 |
| $ | 64.69 |
| 182,000 |
| $ | 63.14 |
| $ | 53.75 |
| $ | 43.75 |
|
September 30, 2019(1) |
| 46,000 |
| $ | 62.96 |
| 184,000 |
| $ | 63.14 |
| $ | 53.75 |
| $ | 43.75 |
|
December 31, 2019(1) |
| 46,000 |
| $ | 61.43 |
| 184,000 |
| $ | 63.14 |
| $ | 53.75 |
| $ | 43.75 |
|
March 31, 2020(1) |
| — |
| $ | — |
| 91,000 |
| $ | 65.75 |
| $ | 50.00 |
| $ | 40.00 |
|
June 30, 2020(1) |
| — |
| $ | — |
| 91,000 |
| $ | 65.75 |
| $ | 50.00 |
| $ | 40.00 |
|
September 30, 2020(1) |
| — |
| $ | — |
| 92,000 |
| $ | 65.75 |
| $ | 50.00 |
| $ | 40.00 |
|
December 31, 2020(1) |
| — |
| $ | — |
| 92,000 |
| $ | 65.75 |
| $ | 50.00 |
| $ | 40.00 |
|
AMPLIFY ENERGY CORP.
(1) Positions shown represent open commodity derivative contract positions as of March 31, 2019.
|
| NYMEX HENRY HUB |
| ||||||||||||||
|
| Fixed Swaps |
| Three-Way Collars |
| ||||||||||||
|
| Hedge |
| Weighted |
| Hedge |
| Weighted |
| Weighted |
| Weighted |
| ||||
Quarter Ended: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
March 31, 2019 |
| 1,980,000 |
| $ | 3.01 |
| 1,350,000 |
| $ | 3.40 |
| $ | 3.00 |
| $ | 2.50 |
|
June 30, 2019(1) |
| 1,365,000 |
| $ | 2.75 |
| — |
| $ | — |
| $ | — |
| $ | — |
|
September 30, 2019(1) |
| 1,380,000 |
| $ | 2.75 |
| — |
| $ | — |
| $ | — |
| $ | — |
|
December 31, 2019(1) |
| 465,000 |
| $ | 2.75 |
| 610,000 |
| $ | 3.45 |
| $ | 2.65 |
| $ | 2.15 |
|
March 31, 2020(1) |
| — |
| $ | — |
| 900,000 |
| $ | 3.45 |
| $ | 2.65 |
| $ | 2.15 |
|
(1) Positions shown represent open commodity derivative contract positions as of March 31, 2019.NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
At September 30, 2019, we had the following open commodity positions:
| Remaining |
|
|
|
|
|
|
|
|
|
|
|
|
| |
| 2019 |
|
| 2020 |
|
| 2021 |
|
| 2022 |
| ||||
Natural Gas Derivative Contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swap contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average monthly volume (MMBtu) |
| 1,643,333 |
|
|
| 150,000 |
|
|
| 187,500 |
|
|
| — |
|
Weighted-average fixed price | $ | 2.84 |
|
| $ | 2.65 |
|
| $ | 2.56 |
|
| $ | — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Two-way collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average monthly volume (MMBtu) |
| — |
|
|
| 520,000 |
|
|
| 162,500 |
|
|
| — |
|
Weighted-average floor price | $ | — |
|
| $ | 2.64 |
|
| $ | 2.58 |
|
| $ | — |
|
Weighted-average ceiling price | $ | — |
|
| $ | 2.96 |
|
| $ | 2.84 |
|
| $ | — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three-way collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average monthly volume (MMBtu) |
| 202,667 |
|
|
| 76,000 |
|
|
| — |
|
|
| — |
|
Weighted-average ceiling price | $ | 3.45 |
|
| $ | 3.45 |
|
| $ | — |
|
| $ | — |
|
Weighted-average floor price | $ | 2.65 |
|
| $ | 2.65 |
|
| $ | — |
|
| $ | — |
|
Weighted-average sub-floor price | $ | 2.15 |
|
| $ | 2.15 |
|
| $ | — |
|
| $ | — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Swaps: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PEPL basis swaps: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average monthly volume (Bbls) |
| — |
|
|
| 600,000 |
|
|
| 500,000 |
|
|
| — |
|
Weighted-average fixed price | $ | — |
|
| $ | (0.46 | ) |
| $ | (0.40 | ) |
| $ | — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Derivative Contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swap contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average monthly volume (Bbls) |
| 180,333 |
|
|
| 153,050 |
|
|
| 116,250 |
|
|
| 30,000 |
|
Weighted-average fixed price | $ | 55.25 |
|
| $ | 57.54 |
|
| $ | 56.05 |
|
| $ | 55.32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Two-way collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average monthly volume (Bbls) |
| 76,000 |
|
|
| 14,300 |
|
|
| — |
|
|
| — |
|
Weighted-average floor price | $ | 55.00 |
|
| $ | 55.00 |
|
| $ | — |
|
| $ | — |
|
Weighted-average ceiling price | $ | 63.85 |
|
| $ | 62.10 |
|
| $ | — |
|
| $ | — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three-way collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average monthly volume (MMBtu) |
| 61,200 |
|
|
| 30,500 |
|
|
| — |
|
|
| — |
|
Weighted-average ceiling price | $ | 63.14 |
|
| $ | 65.75 |
|
| $ | — |
|
| $ | — |
|
Weighted-average floor price | $ | 53.75 |
|
| $ | 50.00 |
|
| $ | — |
|
| $ | — |
|
Weighted-average sub-floor price | $ | 43.75 |
|
| $ | 40.00 |
|
| $ | — |
|
| $ | — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL Derivative Contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swap contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average monthly volume (Bbls) |
| 72,000 |
|
|
| 65,425 |
|
|
| 22,800 |
|
|
| — |
|
Weighted-average fixed price | $ | 29.96 |
|
| $ | 25.20 |
|
| $ | 24.25 |
|
| $ | — |
|
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. At September 30, 2019, we had the following interest rate swap open positions:
| Remaining |
|
|
|
|
|
|
|
|
|
|
|
|
| |
| 2019 |
|
| 2020 |
|
| 2021 |
|
| 2022 |
| ||||
Average Monthly Notional (in thousands) | $ | 125,000 |
|
| $ | 125,000 |
|
| $ | 125,000 |
|
| $ | 75,000 |
|
Weighted-average fixed rate |
| 1.612 | % |
|
| 1.612 | % |
|
| 1.612 | % |
|
| 1.281 | % |
Floating rate | 1 Month LIBOR |
|
| 1 Month LIBOR |
|
| 1 Month LIBOR |
|
| 1 Month LIBOR |
| ||||
17
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes both: (i) the netgross fair valuesvalue of commodity derivative instruments by the appropriate balance sheet classification ineven when the Company’s unaudited interim condensed consolidated balance sheets for the periods presented (in thousands):
Type |
| Balance Sheet Location (1) |
| March 31, 2019 |
| December 31, 2018 |
| ||
Oil swaps |
| Derivative financial instruments — current assets |
| $ | 422 |
| $ | 3,806 |
|
Gas swaps |
| Derivative financial instruments — current assets |
| — |
| (207 | ) | ||
Oil collars |
| Derivative financial instruments — current assets |
| (113 | ) | 3,316 |
| ||
Gas collars |
| Derivative financial instruments — current assets |
| — |
| 25 |
| ||
Total derivative financial instruments — current assets |
| $ | 309 |
| $ | 6,940 |
| ||
|
|
|
|
|
|
|
| ||
Oil collars |
| Derivative financial instruments — noncurrent assets |
| $ | — |
| $ | 791 |
|
Total derivative financial instruments — noncurrent assets |
| $ | — |
| $ | 791 |
| ||
|
|
|
|
|
|
|
| ||
Oil swaps |
| Derivative financial instruments — current liabilities |
| $ | — |
| $ | — |
|
Gas swaps |
| Derivative financial instruments — current liabilities |
| (6 | ) | — |
| ||
Oil collars |
| Derivative financial instruments — current liabilities |
| (823 | ) | — |
| ||
Gas collars |
| Derivative financial instruments — current liabilities |
| (79 | ) | — |
| ||
Total derivative financial instruments — current liabilities |
| $ | (908 | ) | $ | — |
| ||
|
|
|
|
|
|
|
| ||
Oil collars |
| Derivative financial instruments — noncurrent liabilities |
| $ | (251 | ) | $ | — |
|
Gas collars |
| Derivative financial instruments — noncurrent liabilities |
| — |
| (80 | ) | ||
Total derivative financial instruments — noncurrent liabilities |
| $ | (251 | ) | $ | (80 | ) | ||
|
|
|
|
|
|
|
| ||
Total derivative fair value at period end |
| $ | (850 | ) | $ | 7,651 |
| ||
(1) The fair values of commodity derivative instruments reported in the Company’s unaudited interim condensed consolidated balance sheets are subject to netting arrangements and qualify for net presentation.presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2019 and December 31, 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.
|
|
|
| Asset Derivatives |
|
| Liability Derivatives |
|
| Asset Derivatives |
|
| Liability Derivatives |
| ||||
|
|
|
| September 30, |
|
| September 30, |
|
| December 31, |
|
| December 31, |
| ||||
Type |
| Balance Sheet Location |
| 2019 |
|
| 2019 |
|
| 2018 |
|
| 2018 |
| ||||
|
|
|
| (In thousands) |
| |||||||||||||
Commodity contracts |
| Short-term derivative instruments |
| $ | 23,043 |
|
| $ | 2,584 |
|
| $ | 21,217 |
|
| $ | 2,543 |
|
Interest rate swaps |
| Short-term derivative instruments |
|
| 275 |
|
|
| 234 |
|
|
| — |
|
|
| — |
|
Gross fair value |
|
|
|
| 23,318 |
|
|
| 2,818 |
|
|
| 21,217 |
|
|
| 2,543 |
|
Netting arrangements |
|
|
|
| (2,609 | ) |
|
| (2,609 | ) |
|
| (2,404 | ) |
|
| (2,404 | ) |
Net recorded fair value |
| Short-term derivative instruments |
| $ | 20,709 |
|
| $ | 209 |
|
| $ | 18,813 |
|
| $ | 139 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts |
| Long-term derivative instruments |
| $ | 18,715 |
|
| $ | 1,000 |
|
| $ | 4,298 |
|
| $ | 1,829 |
|
Interest rate swaps |
| Long-term derivative instruments |
|
| 32 |
|
|
| 521 |
|
|
| — |
|
|
| — |
|
Gross fair value |
|
|
|
| 18,747 |
|
|
| 1,521 |
|
|
| 4,298 |
|
|
| 1,829 |
|
Netting arrangements |
|
|
|
| (1,032 | ) |
|
| (1,032 | ) |
|
| (1,829 | ) |
|
| (1,829 | ) |
Net recorded fair value |
| Long-term derivative instruments |
| $ | 17,715 |
|
| $ | 489 |
|
| $ | 2,469 |
|
| $ | — |
|
(Gains) Losses on Derivatives
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 Unaudited Condensed Statements of Consolidated Operations. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands):
|
|
|
| For the Three Months Ended |
|
| For the Nine Months Ended |
| ||||||||||
|
| Statements of |
| September 30, |
|
| September 30, |
| ||||||||||
|
| Operations Location |
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
Commodity derivative contracts |
| (Gain) loss on commodity derivatives |
| $ | (28,725 | ) |
| $ | 21,110 |
|
| $ | (19,231 | ) |
| $ | 67,218 |
|
Interest rate derivatives |
| Interest expense, net |
|
| (199 | ) |
|
| — |
|
|
| 334 |
|
|
| — |
|
Note 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 nine months ended September 30, 2019 (in thousands):
Asset retirement obligations at beginning of period | $ | 76,344 |
|
Liabilities added from acquisition or drilling |
| 9,477 |
|
Liabilities settled |
| (259 | ) |
Accretion expense |
| 4,071 |
|
Revision of estimates |
| (52 | ) |
Asset retirement obligation at end of period |
| 89,581 |
|
Less: Current portion |
| (477 | ) |
Asset retirement obligations - long-term portion | $ | 89,104 |
|
18
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table presents our consolidated debt obligations at the dates indicated:
| September 30, |
|
| December 31, |
| ||
| 2019 |
|
| 2018 |
| ||
| (In thousands) |
| |||||
New Revolving Credit Facility (1) | $ | 278,000 |
|
| $ | 294,000 |
|
Long-term debt | $ | 278,000 |
|
| $ | 294,000 |
|
(1) | The carrying amount of our New Revolving Credit Facility approximates fair value because the interest rates are variable and reflective of market rates. |
New Revolving Credit Facility
Amplify Energy Operating LLC, our wholly owned subsidiary (“OLLC”), is a party to a reserve-based revolving credit facility (the “New Revolving Credit Facility”), subject to a borrowing base of $530.0 million as of September 30, 2019, which is guaranteed by us and all of our current subsidiaries. The New Revolving Credit Facility matures on November 2, 2023.
In connection with the Merger, on August 6, 2019, Amplify Energy Operating LLC and Amplify Acquisitionco LLC entered into a Borrowing Base Redetermination, Commitment Increase and Joinder Agreement to Credit Agreement, with the guarantors party thereto, the lenders party thereto and Bank of Montreal, as administrative agent (the “Joinder Agreement”). The Joinder Agreement amends the New Revolving Credit Facility to, among other things:
redetermine the borrowing base of the New Revolving Credit Facility, by increasing the borrowing base from $425.0 million to $530.0 million;
increase the commitments of certain of the original lenders under the New Revolving Credit Facility; and
add additional lenders as parties to the New Revolving Credit Facility.
Upon closing of the Merger on August 6, 2019, Midstates’ existing reserve-based revolving credit facility was terminated and all remaining borrowings were repaid by the Company.
On June 24, 2019, as discussed in Note 15, the Company received the release of $90.0 million from the Beta decommissioning trust account and used the proceeds to reduce amounts outstanding under our New Revolving Credit Facility.
Our borrowing base under our New Revolving Credit Facility 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.
Second Amendment to New Revolving Credit Facility
On July 16, 2019, OLLC entered into the Second Amendment to Credit Agreement (the “Second Amendment”), among OLLC, Amplify Acquisitionco Inc., Amplify Energy, the guarantors party thereto, the lenders party thereto and Bank of Montreal, as administrative agent (the “Administrative Agent”).
The Second Amendment amends the parties’ existing Credit Agreement, dated as of November 2, 2018, in connection with the completion of the Merger, following which Midstates may contribute, through a series of transactions, the equity interests it holds in Midstates Petroleum Company, LLC, a Delaware limited liability company, to the borrower (the “Contribution”), to, among other things, (i) provide that if the Merger and the Contribution are not consummated on or prior to August 31, 2019, the Administrative Agent and the lenders have the right (but not the obligation) to redetermine the borrowing base on or after September 1, 2019 and (ii) amend certain other provisions of the New Revolving Credit Facility.
First Amendment to New Revolving Credit Facility
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 completion of the 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 the Merger Agreement or completion of the transactions contemplated thereby, including the Merger, will not be so restricted.
19
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 Legacy Amplify’s current report on Form 8-K filed on May 6, 2019.
Emergence Credit Facility
At September 30, 2018, OLLC, was a party to a $1.0 billion revolving credit facility (our “Emergence Credit Facility”) which was guaranteed by us and all of our current subsidiaries.
On November 2, 2018, in connection with entry into our New Revolving Credit Facility, the Emergence Credit Facility was terminated and 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:
| For the Three Months Ended |
|
| For the Nine Months Ended |
| ||||||
| September 30, |
|
| September 30, |
| ||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
|
New Revolving Credit Facility | 4.89% |
|
| n/a |
|
| 4.99% |
|
| n/a |
|
Emergence Credit Facility | n/a |
|
| 5.94% |
|
| n/a |
|
| 5.73% |
|
Letters of Credit
At September 30, 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 $5.0 million at September 30, 2019. At September 30, 2019, the unamortized deferred financing costs are amortized over the remaining life of our New Revolving Credit Facility.
Common Stock
The Company’s authorized capital stock includes 300,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common stock issued for the nine months ended September 30, 2019:
Common | |||
Shares | |||
Balance, December 31, 2018 | 22,181,881 | ||
Issuance of common stock | — | ||
Restricted stock units vested | 412,938 | ||
Repurchase of common shares | (120,163 | ) | |
Common stock repurchased and retired under share repurchase program | (169,400 | ) | |
Balance, June 30, 2019 | 22,305,256 | ||
Restricted stock units vested | 38,181 | ||
Repurchase of common shares | (9,427 | ) | |
Balance, August 5, 2019 | 22,334,010 | ||
Ratio to convert Amplify shares | 0.933 | ||
Common stock issued to Legacy Amplify stockholders | 20,837,633 | ||
Midstates stock outstanding and acquired with the Merger | 20,415,005 | ||
Treasury shares acquired from the Merger | 205,861 | ||
Restricted stock units vested | 602,053 | ||
Repurchase of common shares | (11,740 | ) | |
Common stock repurchased and retired under share repurchase program | (1,723,146 | ) | |
Cancelation and retirement of shares | (347,567 | ) | |
Balance, September 30, 2019 | 39,978,099 | ||
Treasury Stock
20
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
As of August 5, 2019, Midstates had 205,861 treasury shares outstanding. After the Merger closed, the Company retired and cancelled all treasury stock outstanding. No treasury stock remained outstanding at September 30, 2019.
Warrants
On the May 4, 2017 (the “Effective Date”), Legacy Amplify entered into a warrant agreement (the “Warrant Agreement”) with American Stock Transfer & Trust Company, LLC, as warrant agent (“AST”), pursuant to which Legacy Amplify issued warrants to purchase up to 2,173,913 shares of Legacy Amplify’s common stock (representing 8% of Legacy Amplify’s outstanding common stock as of the Effective Date including shares of Legacy Amplify’s common stock issuable upon full exercise of the warrants, but excluding any common stock issuable under Legacy Amplify’s Management Incentive Plan (the “MIP”)), exercisable for a five-year period commencing on the Effective Date at an exercise price of $42.60 per share.
On the effective date of the Merger, Legacy Amplify, Midstates and AST entered into an Assignment and Assumption Agreement, pursuant to which the Company agreed to assume Legacy Amplify’s Warrant Agreement.
As of August 5, 2019, Midstates had outstanding warrants of 4,647,520 Third Lien Notes Warrants at an exercise price of $22.78 per share (the “Third Lien Warrants”) and 2,332,089 Unsecured Creditor Warrants at an exercise price of $43.67 per share (the “Unsecured Creditor Warrants” and collectively with the Third Lien Warrants, the “Warrants”). The Warrants expire on April 21, 2020. As a result of the Merger, the value of the outstanding Warrants were adjusted downward based on the low stock price and estimated fair value as of the Merger date. See Note 4 for additional information regarding the purchase price allocation of the Merger.
Share Repurchase Program
On December 21, 2018, Legacy Amplify’s board of directors authorized the repurchase of up to $25.0 million of Legacy Amplify outstanding shares of common stock, with repurchases beginning on January 9, 2019. During the six months ended June 30, 2019, Legacy Amplify repurchased 169,400 shares of common stock at an average price of $7.35 for a total cost of approximately $1.3 million. On April 18, 2019, in anticipation of the Merger, Legacy Amplify terminated the repurchase program.
In connection, with the closing of the Merger, the board of directors approved the commencement of an open market share repurchase program of up to $25.0 million of the Company’s outstanding shares of common stock, with repurchases beginning on or after August 6, 2019. During the three months ended September 30, 2019, the Company repurchased 1,773,146 shares of common stock at an average price of $5.81 for a total cost of approximately $10.4 million.
Cash Dividend Payment
On August 6, 2019, our board of directors approved a dividend of $0.20 per share of outstanding common stock or $8.2 million in aggregate, which was paid on September 18, 2019, to stockholders of record at the close of business on September 4, 2019. The amount of future dividends is subject to discretionary approval by the board of directors.
21
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following sets forth the calculation of earnings (loss) per share, or EPS, for the periods indicated (in thousands, except per share amounts):
| For the Three Months Ended |
|
| For the Nine Months Ended |
| ||||||||||
| September 30, |
|
| September 30, |
| ||||||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
Net income (loss) | $ | 5,157 |
|
| $ | (2,598 | ) |
| $ | (7,679 | ) |
| $ | (24,638 | ) |
Less: Net income allocated to participating restricted stockholders |
| 128 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Basic and diluted earnings available to common stockholders | $ | 5,029 |
|
| $ | (2,598 | ) |
| $ | (7,679 | ) |
| $ | (24,638 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares/units: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares outstanding — basic |
| 33,707 |
|
|
| 25,073 |
|
|
| 26,093 |
|
|
| 25,037 |
|
Dilutive effect of potential common shares |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Common shares outstanding — diluted |
| 33,707 |
|
|
| 25,073 |
|
|
| 26,093 |
|
|
| 25,037 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic | $ | 0.15 |
|
| $ | (0.10 | ) |
| $ | (0.29 | ) |
| $ | (0.98 | ) |
Diluted | $ | 0.15 |
|
| $ | (0.10 | ) |
| $ | (0.29 | ) |
| $ | (0.98 | ) |
Antidilutive stock options (1) |
| 3 |
|
|
| 116 |
|
|
| 3 |
|
|
| 116 |
|
Antidilutive warrants (2) |
| 9,154 |
|
|
| 2,174 |
|
|
| 9,154 |
|
|
| 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. |
(2) | Amount represents warrants to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect. |
Note 11. Long-Term Incentive Plans
In May 2017, Legacy Amplify implemented the Management Incentive Plan (the “MIP”). An aggregate of 2,166,803 shares of Legacy Amplify common stock were reserved for issuance under the MIP. In connection with the closing of the Merger, on August 6, 2019, the Company assumed the MIP.
Restricted Stock Units
Restricted Stock Units with Service Vesting Condition
The restricted stock units with 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 $3.2 million at September 30, 2019. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.6 years.
The following table summarizes information regarding the TSUs granted under the MIP for the period presented:
|
|
|
|
| Weighted- |
| |
|
|
|
|
| Average Grant |
| |
| Number of |
|
| Date Fair Value |
| ||
| Units |
|
| per Unit (1) |
| ||
TSUs outstanding at December 31, 2018 |
| 557,963 |
|
| $ | 11.41 |
|
Granted (2) |
| 280,416 |
|
| $ | 6.80 |
|
Forfeited |
| (35,596 | ) |
| $ | 11.13 |
|
Vested |
| (444,142 | ) |
| $ | 9.01 |
|
TSUs outstanding at September 30, 2019 |
| 358,641 |
|
| $ | 10.71 |
|
(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 TSUs issued for the nine months ended September 30, 2019 was $1.9 million based on a grant date market price ranging from $4.48 to $8.70 per share. |
Restricted Stock Units with Market and Service Vesting Conditions
The restricted stock units with market and service vesting conditions (“PSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a graded-vesting basis. As such, the Company recognizes compensation cost over the requisite service 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 related to the PSUs was $0.6 million at September 30, 2019. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.2 years.
22
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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.
In 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 | % |
Awards Issued on April 1, 2019 |
| 2.28 | % |
|
| 2.28 | % |
|
| 2.28 | % |
Awards Issued on July 1, 2019 |
| 1.73 | % |
|
| 1.73 | % |
|
| 1.73 | % |
|
|
|
|
|
|
|
|
|
|
|
|
Dividend yield |
| — |
|
|
| — |
|
|
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected volatility: |
|
|
|
|
|
|
|
|
|
|
|
Awards Issued on January 1, 2019 |
| 54.0 | % |
|
| 54.0 | % |
|
| 54.0 | % |
Awards Issued on April 1, 2019 |
| 50.0 | % |
|
| 50.0 | % |
|
| 50.0 | % |
Awards Issued on July 1, 2019 |
| 57.0 | % |
|
| 57.0 | % |
|
| 57.0 | % |
|
|
|
|
|
|
|
|
|
|
|
|
Calculated fair value per PSU: |
|
|
|
|
|
|
|
|
|
|
|
Awards Issued on January 1, 2019 | $ | 6.76 |
|
| $ | 5.86 |
|
| $ | 5.11 |
|
Awards Issued on April 1, 2019 | $ | 4.22 |
|
| $ | 3.43 |
|
| $ | 2.80 |
|
Awards Issued on July 1, 2019 | $ | 2.63 |
|
| $ | 2.05 |
|
| $ | 1.64 |
|
The following table summarizes information regarding the PSUs granted under the MIP for the period presented:
|
|
|
|
| Weighted- |
| |
|
|
|
|
| Average Grant |
| |
| Number of |
|
| Date Fair Value |
| ||
| Units |
|
| per Unit (1) |
| ||
PSUs outstanding at December 31, 2018 |
| 367,141 |
|
| $ | 8.14 |
|
Granted (2) |
| 16,562 |
|
| $ | 4.06 |
|
Forfeited |
| (44,552 | ) |
| $ | 7.59 |
|
Vested |
| — |
|
| $ | — |
|
PSUs outstanding at September 30, 2019 |
| 339,151 |
|
| $ | 8.01 |
|
(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 PSUs issued for the nine months ended September 30, 2019 was less than $0.1 million based on a calculated fair value price ranging from $1.64 to $6.76 per share. |
2017 Non-Employee Directors Compensation Plan
In June 2017, Legacy Amplify implemented the 2017 Non-Employee Directors Compensation Plan (“Directors Compensation Plan”) to attract and retain the services of experienced non-employee directors of Legacy Amplify or its subsidiaries. An aggregate of 186,600 shares of Legacy Amplify’s common stock were reserved for issuance under the Directors Compensation Plan. In connection with the closing of the Merger, on August 6, 2019, the Company assumed the Directors Compensation Plan.
The restricted stock units with a service vesting condition (“Board RSUs”) 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 restricted stock unit awards was $0.4 million at September 30, 2019. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 2.1 years.
The following table summarizes information regarding the Board RSUs granted under the Directors Compensation Plan for the period presented:
23
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
| Weighted- |
| ||
|
|
|
|
| Average Grant |
| |
| Number of |
|
| Date Fair Value |
| ||
| Units |
|
| per Unit (1) |
| ||
Board RSUs outstanding at December 31, 2018 |
| 36,955 |
|
| $ | 11.36 |
|
Granted (2) |
| 40,060 |
|
| $ | 6.95 |
|
Forfeited |
| — |
|
| $ | — |
|
Vested |
| (46,396 | ) |
| $ | 9.54 |
|
Board RSUs outstanding at September 30, 2019 |
| 30,619 |
|
| $ | 8.35 |
|
(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 Board RSUs issued for the nine months ended September 30, 2019 was $0.3 million based on grant date market price of $6.95 per share. |
Compensation Expense
The following table summarizes the locationamount of recognized compensation expense associated with the MIP and fair value amounts of all commodity derivative instrumentsDirectors Compensation Plan, which are reflected in the unaudited interim condensed consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited interim condensed consolidated balance sheetsaccompanying Unaudited Condensed Statements of Consolidated Operations for the periods presented (in thousands):
|
|
|
| March 31, 2019 |
| |||||||
Not Designated as |
|
|
| Gross Recognized |
| Gross Amounts |
| Net Recognized |
| |||
ASC 815 Hedges |
| Balance Sheet Location Classification |
| Assets/Liabilities |
| Offset |
| Assets/Liabilities |
| |||
Derivative Assets: |
|
|
|
|
|
|
|
|
| |||
Commodity contracts |
| Derivative financial instruments — current |
| $ | 1,738 |
| $ | (1,429 | ) | $ | 309 |
|
Commodity contracts |
| Derivative financial instruments — noncurrent |
| 905 |
| (905 | ) | — |
| |||
|
|
|
| $ | 2,643 |
| $ | (2,334 | ) | $ | 309 |
|
Derivative Liabilities: |
|
|
|
|
|
|
|
|
| |||
Commodity contracts |
| Derivative financial instruments — current |
| $ | (2,337 | ) | $ | 1,429 |
| $ | (908 | ) |
Commodity contracts |
| Derivative financial instruments — noncurrent |
| (1,156 | ) | 905 |
| (251 | ) | |||
|
|
|
| $ | (3,493 | ) | $ | 2,334 |
| $ | (1,159 | ) |
|
|
|
| December 31, 2018 |
| |||||||
Not Designated as |
|
|
| Gross Recognized |
| Gross Amounts |
| Net Recognized |
| |||
ASC 815 Hedges |
| Balance Sheet Location Classification |
| Assets/Liabilities |
| Offset |
| Assets/Liabilities |
| |||
Derivative Assets: |
|
|
|
|
|
|
|
|
| |||
Commodity contracts |
| Derivative financial instruments — current |
| $ | 11,066 |
| $ | (4,126 | ) | $ | 6,940 |
|
Commodity contracts |
| Derivative financial instruments — noncurrent |
| 2,859 |
| (2,068 | ) | 791 |
| |||
|
|
|
| $ | 13,925 |
| $ | (6,194 | ) | $ | 7,731 |
|
Derivative Liabilities: |
|
|
|
|
|
|
|
|
| |||
Commodity contracts |
| Derivative financial instruments — current |
| $ | (4,126 | ) | $ | 4,126 |
| $ | — |
|
Commodity contracts |
| Derivative financial instruments — noncurrent |
| (2,148 | ) | 2,068 |
| (80 | ) | |||
|
|
|
| $ | (6,274 | ) | $ | 6,194 |
| $ | (80 | ) |
| For the Three Months Ended |
|
| For the Nine Months Ended |
| ||||||||||
| September 30, |
|
| September 30, |
| ||||||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
Equity classified awards |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TSUs | $ | 650 |
|
| $ | 490 |
|
| $ | 1,852 |
|
| $ | 601 |
|
PSUs |
| 120 |
|
|
| 495 |
|
|
| 825 |
|
|
| 747 |
|
Board RSUs |
| 58 |
|
|
| 44 |
|
|
| 221 |
|
|
| 98 |
|
Restricted stock options |
| — |
|
|
| 39 |
|
|
| — |
|
|
| 115 |
|
| $ | 828 |
|
| $ | 1,068 |
|
| $ | 2,898 |
|
| $ | 1,561 |
|
Gains/Losses on Commodity Derivative Contracts
The Company does not designate its commodity derivative contracts as hedging instruments for financial reporting purposes. Accordingly, commodity derivative contracts are marked-to-market each quarter with the change in fair value during the periodic reporting period recognized currently as a gain or loss in gains (losses) on commodity derivative contracts—net within revenues in the unaudited interim condensed consolidated statements of operations.
The following table presents net cash received for commodity derivative contracts and unrealized net gains recorded by the Company related to the change in fair value of the derivative instruments in gains (losses) on commodity derivative contracts—net for the periods presented (in thousands):
|
| For the Three Months |
| ||||
|
| Ended March 31, |
| ||||
|
| 2019 |
| 2018 |
| ||
Net cash received (paid) for commodity derivative contracts |
| $ | 769 |
| $ | (160 | ) |
Unrealized net gains (losses) |
| (8,501 | ) | (3,779 | ) | ||
Losses on commodity derivative contracts—net |
| $ | (7,732 | ) | $ | (3,939 | ) |
Cash settlements, as presented in the table above, represent realized gains (losses) related to the Company’s derivative instruments. In addition to cash settlements, the Company also recognizes fair value changes on its derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.
6. Property and Equipment
Property and equipment consisted of the following as of the dates presented:
|
| March 31, 2019 |
| December 31, 2018 |
| ||
|
| (in thousands) |
| ||||
Oil and gas properties, on the basis of full-cost accounting: |
|
|
|
|
| ||
Proved properties |
| $ | 818,013 |
| $ | 809,272 |
|
Unproved properties not being amortized |
| 1,869 |
| 4,050 |
| ||
Other property and equipment |
| 6,340 |
| 6,345 |
| ||
Less accumulated depreciation, depletion, amortization and impairment |
| (287,544 | ) | (266,198 | ) | ||
Net property and equipment |
| $ | 538,678 |
| $ | 553,469 |
|
Oil and Gas Properties
Historically, the Company has capitalized internal costs directly related to exploration and development activities to oil and gas properties. During the three months ended March 31, 2019, the Company did not have significant exploration and development activities and no internal costs were capitalized. During the three months ended March 31, 2019 and 2018, the Company capitalized the following (in thousands):
|
| 2019 |
| 2018 |
| ||
Internal costs capitalized to oil and gas properties (1) |
| $ | — |
| $ | 895 |
|
(1) Inclusive of $0.2 million of qualifying share-based compensation expense for the three months ended March 31, 2018.
The Company accounts for its oil and gas properties under the full cost method. Under the full cost method, proceeds realized from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company’s reserve quantities are sold such that it results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income. During the three months ended March 31, 2018, the Company signed a purchase and sale agreement for its Anadarko Basin assets for $58.0 million before customary closing or post-closing adjustments. The sale of the Anadarko Basin assets closed on May 31, 2018, and did not result in a significant alteration of the full cost pool and therefore, no gain or loss was recognized when the transaction closed.
The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of the Company’s oil and gas properties. The capitalized costs of oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“DD&A”) and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying unaudited interim condensed consolidated statements of operations.
For the three months ended March 31, 2019, capitalized costs exceeded the ceiling and the Company recorded an impairment of oil and gas properties of $9.7 million. This impairment was primarily the result of low commodity prices, which resulted in a reduction of the discounted present value of the Company’s proved oil and natural gas reserves. No impairment of oil and gas properties was recorded during the three months ended March 31, 2018.
Depreciation, depletion and amortization is calculated using the Units of Production Method (“UOP”). The UOP calculation multiplies the percentage of total estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reservoirs are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated depreciation, depletion, amortization and impairment, estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value. The following table presents depletion expense related to oil and gas properties for the periods presented:
|
| Three Months Ended |
| Three Months Ended |
| ||||||||
|
| 2019 |
| 2018 |
| 2019 |
| 2018 |
| ||||
|
| (in thousands) |
| (per Boe) |
| ||||||||
Depletion expense |
| $ | 11,680 |
| $ | 14,623 |
| $ | 9.81 |
| $ | 8.45 |
|
Depreciation on other property and equipment |
| 114 |
| 590 |
| 0.10 |
| 0.34 |
| ||||
Depreciation, depletion, and amortization |
| $ | 11,794 |
| $ | 15,213 |
| $ | 9.91 |
| $ | 8.79 |
|
Oil and gas unproved properties include costs that are not being depleted or amortized. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are transferred to proved properties and become part of our depletion base and subject to the full cost ceiling limitation. No impairment of unproved properties was recorded during the three months ended March 31, 2019 or 2018. Unproved property was $1.9 million and $4.1 million at March 31, 2019 and December 31, 2018, respectively.
Other Property and Equipment
Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are carried at cost. Depreciation is calculated principally using the straight-line method over the estimated useful lives of the assets, which range from two to ten years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.
7. Leases
As previously described in “—Note 3. Impact of ASU 842 Adoption”, the Company leases certain office space, field offices, office equipment, compressors, other production equipment and fleet vehicles under cancelable and non-cancelable leases to support its operations. These leases do not contain material variable payments, residual value guarantees, covenants or other restrictions.
Supplemental cash flow information related to the Company’s leases are included in the table below (in thousands):
|
| Three Months Ended |
| |
Cash paid for amounts included in the measurement of lease liabilities: |
|
|
| |
Operating cash flows from operating leases |
| $ | 310 |
|
Amortization of right-of-use assets: |
|
|
| |
Operating leases |
| $ | 208 |
|
Balance sheet information related to the Company’s leases are included in the table below (in thousands):
|
| March 31, 2019 |
| |
Operating Leases |
|
|
| |
Right-of-use lease assets |
| 4,648 |
| |
Total operating lease ROU asset |
| $ | 4,648 |
|
|
|
|
| |
Lease liabilities |
| $ | 1,236 |
|
Long-term lease liabilities |
| 4,041 |
| |
Total operating lease liabilities |
| $ | 5,277 |
|
|
|
|
| |
Weighted-average remaining lease term |
| 6.68 years |
| |
As of March 31, 2019, the Company had no finance or operating leases that had not yet commenced.
8. Accrued Liabilities
The following table presents the components of accrued liabilities as of the dates presented:
|
| March 31, 2019 |
| December 31, 2018 |
| ||
|
| (in thousands) |
| ||||
Accrued oil and gas capital expenditures |
| $ | 3,021 |
| $ | 1,534 |
|
Accrued revenue and royalty distributions |
| 10,363 |
| 13,302 |
| ||
Accrued lease operating and workover expense |
| 2,799 |
| 2,843 |
| ||
Accrued interest |
| 262 |
| 209 |
| ||
Accrued taxes |
| 1,405 |
| 1,813 |
| ||
Compensation and benefit related accruals |
| 2,152 |
| 2,855 |
| ||
Other |
| 1,971 |
| 2,965 |
| ||
Accrued liabilities |
| $ | 21,973 |
| $ | 25,521 |
|
9. Asset Retirement Obligations
Asset Retirement Obligations (“AROs”) represent the estimated future abandonment costs of tangible assets, such as wells, service assets and other facilities. The estimated fair value of the AROs at inception are capitalized as part of the carrying amount of the related long-lived assets. The following table reflects the changes in the Company’s AROs for the periods presented (in thousands):
|
| Three Months Ended |
| ||||
|
| 2019 |
| 2018 |
| ||
Asset retirement obligations — beginning of period |
| $ | 8,087 |
| $ | 15,506 |
|
Liabilities incurred |
| — |
| 113 |
| ||
Revisions |
| — |
| — |
| ||
Liabilities settled |
| — |
| (1 | ) | ||
Liabilities eliminated through asset sales |
| — |
| (62 | ) | ||
Current period accretion expense |
| 157 |
| 297 |
| ||
Asset retirement obligations — end of period |
| $ | 8,244 |
| $ | 15,853 |
|
10. Debt
Reserves-Based Revolving Credit Facility (“RBL”)
At March 31, 2019 and December 31, 2018, the Company maintained an RBL with a borrowing base of $170.0 million. During the three months ended March 31, 2019, the Company drew down $36.0 million, net on its RBL. At March 31, 2019 and December 31, 2018, the Company had $59.1 million and $23.1 million, respectively, drawn on the RBL and had outstanding letters of credit obligations totaling $1.9 million. As a result, at March 31, 2019, the Company had $109.0 million of availability on the RBL.
The RBL matures on September 30, 2020, and bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. At March 31, 2019, the weighted-average interest rate, excluding amortization expense of deferred financing costs and commitment fees, was 7.0%. Unamortized debt issuance costs of $1.0 million and $1.2 million associated with the RBL are included in other noncurrent assets on the unaudited interim condensed consolidated balance sheets at March 31, 2019 and December 31, 2018, respectively.
In addition to interest expense, the RBL requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of 0.50% per annum based on the average daily amount by which the borrowing base exceeds outstanding borrowings during each quarter.
The RBL, as amended, includes certain financial maintenance covenants that are required to be calculated on a quarterly basis for compliance purposes. These financial maintenance covenants include EBITDA to interest expense for the trailing four fiscal quarters of not less than 2.50:1.00 and a limitation of Total Net Indebtedness (as defined in the RBL) to EBITDA for the trailing four fiscal quarters of not more than 4.00:1.00.
On November 15, 2018, the Company entered into a Second Amendment to the RBL (the “Second Amendment”). The Second Amendment provides the Company with the ability to make dividends and distributions, including repurchases of its equity interests in cash, in each case, so long as both before and after giving effect to any such repurchase (i) the Company and its subsidiaries maintain liquidity of at least $50.0 million, (ii) no default or event of default exists under the RBL, (iii) the ratio of total net indebtedness to adjusted EBITDA for the most recent period of four fiscal quarters for which financial statements have been delivered pursuant to the RBL shall not exceed 1.50:1.00 and (iv) all repurchased equity interests of the Company must be immediately retired.
In addition, the RBL contains various other covenants that, among other things, may restrict the Company’s ability to: (i) incur additional indebtedness or guarantee indebtedness (ii) make loans and investments; (iii) pay dividends on capital stock and make other restricted payments, including the prepayment or redemption of other indebtedness; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with the Company’s affiliates; (vii) acquire, consolidate or merge with another entity upon certain terms and conditions; (viii) sell all or substantially all of the Company’s assets; (ix) prepay, redeem or repurchase certain debt; (x) alter the business the Company conducts and make amendments to the Company’s organizational documents, (xi) enter into certain derivative transactions and (xii) enter into certain marketing agreements and take-or-pay arrangements. During the first quarter of 2019, the Company partially funded the stock buyback by drawing down $39.0 million from our RBL, as noted in “— Note 11. Equity and Share-Based Compensation” below, with the remainder funded by cash on hand.
The Company was in compliance with all debt covenants at March 31, 2019.
On April 11, 2019, the Company’s borrowing base was redetermined at the existing amount of $170.0 million.
The Company believes the carrying amount of the RBL at March 31, 2019 approximates its fair value (Level 2) due to the variable nature of the RBL interest rate.
11. Equity and Share-Based Compensation
Common Shares
Share Activity
The following table summarizes changes in the number of shares of common stock and treasury stock during the three months ended March 31, 2019:
|
| Common |
| Treasury |
|
Share count as of December 31, 2018 |
| 25,520,170 |
| (174,189 | ) |
Common stock issued |
| 99,595 |
| — |
|
Acquisition of treasury stock |
| — |
| (5,031,154 | ) |
Retirement of treasury stock |
| (5,000,000 | ) | 5,000,000 |
|
Share count as of March 31, 2019 |
| 20,619,765 |
| (205,343 | ) |
(1) Treasury stock at March 31, 2019 and December 31, 2018 represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory tax withholding requirements.
On January 14, 2019, the Company announced the commencement of a tender offer (the “Tender Offer”), authorized by the Board of Directors, to repurchase up to 5,000,000 shares of common stock at the offer price of $10.00 per share. On February 14, 2019, the Tender Offer was completed with the purchase of 5,000,000 shares of common stock at a purchase price of $10.00 per share. The 5,000,000 shares repurchased by the Company on February 14, 2019, were subsequently retired. When treasury shares are retired, the excess of the repurchase price over the par value of the shares is allocated to additional paid in capital for amounts up to the original price of the shares at issuance, with any residual excess purchase price allocated to retained earnings. The excess of the repurchase price over the par value of the shares repurchased and subsequently retired on February 14, 2019 was allocated solely to additional paid in capital.
Warrants
Midstates 2016 Long Term Incentive Plan
On October 21, 2016, the Company issued 4,411,765 Third Lien Notes Warrants to purchase up to an aggregate of 4,411,765 shares of common stock at an initial exercise price of $24.00 per share and 2,213,789 Unsecured Creditor Warrants to purchase up to an aggregate of 2,213,789 shares of common stock at an initial exercise price of $46.00 per share. The Warrants expire on April 21, 2020.
The number of shares of common stock for which the Warrants is exercisable, and the exercise price per share of the Warrants are subject to adjustment from time to time upon the occurrence of certain events, including the issuance of common stock as a dividend or distribution to all holders of shares of common stock, a pro-rata repurchase offer of common stock or a subdivision, combination, split, reverse split or reclassification of outstanding common stock into a greater or smaller number of shares of common stock.
As a result of the Tender Offer, the outstanding warrants of the Company were adjusted. The exercise price of the Third Lien Notes Warrants were adjusted from $24.00 per share to $22.78 per share and the exercise price of the Unsecured Creditor Warrants were adjusted from $46.00 per share to $43.67 per share. Further, the number of shares eligible to be received upon exercise of each warrant was adjusted by a factor of 1.05. Subsequent to the Tender Offer, the Third Lien Notes Warrants and the Unsecured Creditor Warrants may be exercised for up to an aggregate of 4,647,520 and 2,332,089 shares of common stock, respectively.
Share-Based Compensation
2016 Long Term Incentive Plan
On October 21, 2016, the CompanyMidstates established the 2016 LTIPLong-term Incentive Plan (“Midstates 2016 LTIP”) and filed a Form S-8 with the SEC, registering 3,513,950 shares for issuance under the terms of the Midstates 2016 LTIP to employees, directors and certain other persons (the “Award Shares”). The types of awards that may be granted under the Midstates 2016 LTIP include stock options, restricted stock units, restricted stock, performance awards and other forms of awards granted or denominated in shares of common stock, of the reorganized Company, as well as certain cash-based awards (the “Awards”). The terms of each award are aswere determined by the Compensation CommitteeMidstates compensation committee of the Boardboard of Directors.directors. Awards that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future issuance under the 2016 LTIP. At March 31, 2019, 1,764,041 Award Shares remain available for issuance under the terms of theMidstates 2016 LTIP.
Stock Buyback Equalization Program
On December 21, 2018, the Company adopted a stock buyback equalization program that allows holders of the Company’s outstanding equity awards to participate in any tender program or share repurchase program of the Company with their vested and unvested shares applicable to those equity awards. Vested awards that have been elected for participation in the equalization program are settled in a cash payment equal to the cash purchase price paid by the Company in the applicable tender offer or share repurchase program. Unvested or deferred awards that have been elected for participation in an equalization program are realized through a cash settlement of the awards upon the vesting or lapse of the award’s deferral conditions.
On January 14, 2019, the Company announced the commencement of the Tender Offer, authorized by the Board of Directors, to repurchase up to 5,000,000 shares of common stock at the offer price of $10.00 per share. On February 14, 2019, the Tender Offer was completed with the purchase of 5,000,000 shares of common stock at a purchase price of $10.00 per share. In conjunction with the Tender Offer, holders of the Company’s restricted stock units participated in the related equalization program, as discussed below. No other outstanding equity awards were eligible for participation in the equalization program during the quarter ended March 31, 2019.
Midstates Restricted Stock Units
At March 31,September 30, 2019, the Company had 358,21725,662 non-vested restricted stock units outstanding to employees and non-employee directors pursuant to the Midstates 2016 LTIP, excluding restricted stock units issued to non-employee directors containing a market condition, which are discussed below. During the three months ended March 31, 2019, 161,194The Midstates non-vested restricted stock units were issued to employees and non-employee directors. Restrictedare accounted for as equity-classified awards. Restricted stock units granted to employees in 2019 under the Midstates 2016 LTIP vest in full on March 1, 2021, or upon the occurrence of a change in control, provided the employee has not terminated employment prior to such vesting date. Remaining non-vested employee restricted stock units will vest upon termination after the Merger transition period in the fourth quarter of 2019. Restricted stock units granted to non-employee directors during 2019 vest on the first to occur of (i) December 31, 2019, (ii) the date the non-employee director ceases to be a director of the Boardboard of directors (other than for cause), (iii) the director’s death, (iv) the director’s disability or (v) a change in control of the Company.
The fair value of restricted stock units granted to employees and non-employee directors during 2019 was based on grant date fair value of the Company’s common stock. Compensation expense is recognized ratably over the requisite service period.
In conjunction with the Company’s purchase of common stock through the Tender Offer completed on February 14, 2019, holders of the Company’s restricted stock units participated in an equalization program in which 97,995 unvested shares were tendered at the settlement price of $10.00 per unvested share. The Company recorded a liability of $1.0 million for the modified awards during the quarter ended March 31, 2019 for the future cash settlement of these tendered shares upon vesting.
Midstates.
The following table summarizes the Company’sMidstates non-vested restricted stock unit award activity for the three months ended March 31, 2019:period presented:
|
|
|
|
| Weighted- |
| |
|
|
|
|
| Average Grant |
| |
| Number of |
|
| Date Fair Value |
| ||
| Units |
|
| per Unit (1) |
| ||
Midstates non-vested restricted stock units outstanding at August 6, 2019 |
| 353,464 |
|
| $ | 12.25 |
|
Granted |
| — |
|
| $ | — |
|
Forfeited |
| — |
|
| $ | — |
|
Vested |
| (327,802 | ) |
| $ | 12.02 |
|
Midstates non-vested restricted stock units outstanding at September 30, 2019 |
| 25,662 |
|
| $ | 15.23 |
|
Midstates Stock Options
24
|
| Restricted Stock |
| Weighted Average |
| |
Non-vested shares outstanding at December 31, 2018 |
| 251,522 |
| $ | 15.79 |
|
Granted |
| 161,194 |
| $ | 7.94 |
|
Vested(1) |
| (36,276 | ) | $ | 9.74 |
|
Forfeited |
| (18,223 | ) | $ | 9.74 |
|
Non-vested shares outstanding at March 31, 2019 |
| 358,217 |
| $ | 12.30 |
|
AMPLIFY ENERGY CORP.
(1) Restricted stock units which vested during the three months ended March 31, 2019 were accelerated as a result of a reduction in workforce that occurred during the three months ended March 31, 2019.NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unrecognized expense as of March 31, 2019, for all outstanding restricted stock units under the 2016 LTIP Plan was $2.3 million and will be recognized over a weighted average period of 1.2 years.
Stock Options
At March 31,September 30, 2019, the Company had 55,2133,495 non-vested options outstanding pursuant to the Midstates 2016 LTIP. The Midstates stock options are accounted for as equity-classified awards. Stock Option Awards grantedcurrently outstanding under theMidstates 2016 LTIP vest ratably over a period of three years: one-sixth will vest on the six-month anniversary of the grant date, an additional one-sixth will vest on the twelve-month anniversary of the grant date, an additional one-third will vest on the twenty-four month anniversary of the grant date and the final one-third will vest on the thirty-six month anniversary of the grant date. Stock Option Awards expire 10 years from the grant date. There were no issuances of stock options during the three months ended March 31, 2019.
The following table summarizes the Company’sMidstates 2016 LTIP non-vested stock option activity for the three months ended March 31, 2019:
|
| Options |
| Range of |
| Weighted Average |
| Weighted |
| ||
Stock options outstanding at December 31, 2018 |
| 70,102 |
|
|
| $ | 19.65 |
| 7.8 |
| |
Granted |
| — |
| $ | — |
| $ | — |
| — |
|
Vested(1) |
| (14,889 | ) | $ | 19.08-19.66 |
| $ | 19.56 |
| 0.3 |
|
Forfeited |
| — |
| $ | — |
| $ | — |
| — |
|
Stock options outstanding at March 31, 2019 |
| 55,213 |
|
|
| $ | 19.68 |
| 7.6 |
| |
Vested and exercisable at end of period(2) |
| 151,050 |
| $ | 19.08-20.97 |
| $ | 19.66 |
| 5.6 |
|
period presented:
|
|
|
|
| Weighted- |
| |
|
|
|
|
| Average Grant |
| |
| Number of |
|
| Date Fair Value |
| ||
| Units |
|
| per Unit (1) |
| ||
Midstates stock options outstanding at August 6, 2019 |
| 54,365 |
|
| $ | 19.68 |
|
Granted |
| — |
|
| $ | — |
|
Forfeited |
| — |
|
| $ | — |
|
Vested |
| (50,870 | ) |
| $ | 19.68 |
|
Midstates stock options outstanding at September 30, 2019 |
| 3,495 |
|
| $ | 19.66 |
|
(1) Vested stock options during the three months ended March 31, 2019, were accelerated as a result of a reduction in workforce that occurred during the three months ended March 31, 2019.
(2) Vested and exercisable options at March 31, 2019, had no aggregate intrinsic value.
Unrecognized expense as of March 31, 2019, for all outstanding stock options under the 2016 LTIP Plan was $0.1 million and will be recognized over a weighted average period of 0.6 years.
Non-Employee Director Restricted Stock Units Containing a Market Condition
On November 23, 2016, the CompanyMidstates issued 76,296 restricted stock units to non-employee directors that containcontained a market vesting condition. Midstates previously recognized the non-employee director restricted stock units containing a market condition as liability awards. These restricted stock units will vestwould have vested (i) on the first business day following the date on which the trailing 60-day average share price (including any dividends paid) of the Company’sMidstates common stock is equal to or greater than $30.00 or (ii) upon a change in control (as defined in the Midstates 2016 LTIP) of the Company.. Additionally, all unvested restricted stock units containing a market vesting condition will be immediately forfeited upon the first to occur of (i) the fifth anniversary of the grant date or (ii) any participant’s termination as a director for any reason (except for a termination as part of a change in control of the Company)Midstates).
These restricted stock awards are accounted for as liability awards under FASB ASC 718 — Stock Compensation (“ASC 718”) as the awards allow for the withholding of taxes at the discretion of the non-employee director. The liability is re-measured, with a corresponding adjustment to earnings, at each fiscal quarter-end during the performance cycle. The derived service period related to these awards ended in November of 2017. As such, changes in the fair value of the liability and related compensation expense of these awards are no longer recognized pro-rata over the period for which service has already been provided but rather are compensation cost in the period in which the changes occur. As there are inherent uncertainties related to these factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded compensation may not accurately reflect the amount ultimately earned by the non-employee directors.
At March 31,On August 5, 2019, the Company recorded a $0.1 million liability, included within accrued liabilities on the unaudited interim condensed consolidated balance sheets, related to theMidstates had 50,864 market condition awards outstanding. The weighted-average fair value of theoutstanding and on August 5, 2019 all 50,864 shares were vested. No shares were outstanding at September 30, 2019 related to non-employee director restricted stock units containing a market condition was $1.28 at March 31, 2019.
condition.
As of March 31,September 30, 2019, there waswere no unrecognized stock-based compensation expense related to market condition awards.
Midstates Chief Executive Officer (“CEO”) Restricted Stock Units Containing a Market Condition
On November 1, 2017, the CompanyMidstates issued 135,778 restricted stock units to its CEO that containcontained a market vesting condition. These restricted stock units will vest, if at all, based on the Company’sMidstates total stockholder return for the performance period of October 25, 2017, through October 31, 2020. Market conditions under this grant are (1)(i) with respect to 50% of the RSUsrestricted stock units granted, the Company’sMidstates cumulative total shareholder return (“TSR”) which is defined as the change in the value of the stock over the performance period with the beginning and ending stock price based on a 20-day average stock price and (2)(ii) with respect to the remaining 50% of the RSUsrestricted stock units granted, the percentile rank of the Company’sMidstates TSR compared to the TSR of the Peer Group over the performance period (“Relative TSR”).
To the extent that actual TSR or Relative TSR for the performance period is between specified vesting levels, the portion of the RSUsrestricted stock units that shall become vested based on actual and Relative TSR performance shall be determined on a pro-rata basis using straight-line interpolation; provided that the maximum portion of the RSUs that may become vested based on actual cumulative TSR or Relative TSR for the performance period shall not exceed 120% of the awards granted.
The RSUs issued to the CEO containing a market condition have a service period of three years. The share-based compensation costs related to the CEOOn August 5, 2019, Midstates had 135,778 restricted stock units containing a market condition recognized as generaloutstanding to its CEO and administrative expense by the Company was $0.1 millionon August 5, 2019 all 135,778 shares were vested. No shares were outstanding at March 31,September 30, 2019. As of March 31, 2019, unrecognized stock-based compensation related to CEO RSUs containing a market condition was $0.8 million and will be recognized over a weighted-average period of 1.6 years.
Midstates 2018 Performance Stock Units Issued to Certain Members of Executive Management Containing a Market Condition
On March 1, 2018, the CompanyMidstates issued 96,305 restricted stock units to certain members of Midstates executive management team that containcontained a market vesting condition. TheseMidstates previously accounted for these restricted stock units will vest, if at all, based on the Company’s total stockholder return for the performance period of January 1, 2018 through December 31, 2020.To the extent that the Relative TSR for the performance period is between specified vesting levels, the portion of the restricted stock units that become vested based on the Relative TSR performance shall be determined on a pro-rata basis using straight-line interpolation; provided that the maximum portion of the restricted stock units that may become vested based on the Relative TSR for the performance period shall not exceed 150% of the awards granted. In addition, if the Relative TSR for the Company is negative over the performance period, vesting of these performance stock units is limited to no more than 100%.
award as equity awards.
If a member of Midstates executive management terminatesteam had terminated its employment prior to vesting, the outstanding award iswould have been forfeited. ExecutiveMidstates executive management restricted stock units with a market condition arewere subject to accelerated vesting in the event the executive’s employment is terminated prior to vesting by the CompanyMidstates without “Cause” or by the participant with “Good Reason” (each, as defined in the Midstates 2016 LTIP) or due to the executive’s death or disability. Upon a change in control (as defined in the Midstates 2016 LTIP), the Midstates compensation committee of the board of directors could (1)(i) accelerate all or a portion of the award, (2)(ii) cancel all of the award and pay cash, stock or combination equal to the change in control price, (3)(iii) provide for the assumption or substitution or continuation by the successor company, (4)(iv) certify to the extent to which the vesting conditions had been achieved prior to the conclusion of the performance period or (5)(v) adjust restricted stock units to reflect the change in control.
25
AMPLIFY ENERGY CORP.
These restricted stock awards are accounted for as equity awards under ASC 718 as the awards are settled in shares of the Company with no additional settlement options permitted. At the grant date, the Company estimated the fair value of this equity award. The compensation expense of this award each period is recognized by dividing the fair value of the total award by the requisite service period and recording the pro rata share for the period for which service has already been provided. As there are inherent uncertainties related to these factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded compensation may not accurately reflect the amount ultimately earned by the executives.NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
TheOn August 5, 2019 all 96,305 restricted stock units issued to executive management containing a market condition have a service period of three years. The share-based compensation costs related to executive management’s restricted stock units containing a market condition recognized as general and administrative expense by the Company was $0.1 million for the period ended March 31,had vested noting no shares outstanding at September 30, 2019. As of March 31, 2019, unrecognized stock-based compensation related to executive management’s restricted stock units containing a market condition was $0.8 million and will be recognized over a weighted-average period of 1.8 years.
Midstates 2019 Performance Stock Units Issued to Certain Members of Executive Management Containing a Market Condition
On March 7, 2019, the CompanyMidstates issued 193,921 restricted stock units to certain members of Midstates executive management team that containcontained a market vesting condition. These restricted stock units will vest, if at all, when a 60 consecutive trading day volume weighted average price is achieved at any time during the performance period of January 1, 2019 through December 31, 2020. Market conditions under this grant relate to the Company’s price per common share as follows:
|
| Price per Common Share of Stock |
| Vesting as % of RSUs Granted |
| |
Maximum |
| $ | 12.50 |
| 150 | % |
Target |
| $ | 11.50 |
| 100 | % |
Below Target |
| $ | 10.50 |
| 66 | % |
Threshold |
| $ | 9.50 |
| 33 | % |
To the extent that the price per common share of stockMidstates previously accounted for the performance period is between specified vesting levels, the portion of the restricted stock units that become vested based on the price per common share of stock shall be determined on a pro-rata basis using straight-line interpolation; provided that the maximum portion of the restricted stock units that may become vested based on the price per common share of stock for the performance period shall not exceed 150% of the awards granted.
If a member of executive management terminates employment prior to vesting, the outstanding award is forfeited. Executive management members whose employment is terminated between months 6 and 12 of the performance period without “Cause”, due to the executive’s death or disability, or by the participant with “Good Reason” (each, as defined in the 2016 LTIP) shall forfeit 50% of the restricted stock units. The remaining 50% of the stock units will remain eligible to vest according to the performance vesting schedule above. Executive management members whose employment is terminated without Cause or by the participant for Good Reason between months 12 and 24 of the performance period, will not forfeit restricted stock units, with 100% of the restricted stock units remaining eligible for vesting according to the performance vesting schedule above. Upon a change in control (as defined in the 2016 LTIP), the compensation committee of the board of directors could (1) accelerate all or a portion of the award, (2) cancel all of the award and pay cash, stock or combination equal to the change in control price, (3) provide for the assumption or substitution or continuation by the successor company, (4) certify to the extent to which the vesting conditions had been achieved prior to the conclusion of the performance period or (5) adjust restricted stock units to reflect the change in control. If restricted stock units remain in effect following a change of control effectuated by a sale, merger or business combination and an executive’s employment is terminated without Cause or by the participant with Good Reason, the participant’s right to vest in the restricted stock units is determined by the price determined to have been paid as consideration to the Company for the common share of the Company’s stock in the change of control. If the change of control price is below $9.50 a share of common stock, the restricted stock units of the terminated executive will be forfeited. If the change of control price is above $9.50 a share of common stock, the vesting of the restricted stock units will occur upon termination of the executive, at the vesting percentages specified in the performance vesting schedule above. The termination of an executive without Cause or by the participant with Good Reason within 12 months of a change of control not effectuated by a sale, merger or business combination shall not forfeit restricted stock units, which will vest as described in the performance vesting schedule above.
Thesethese restricted stock awards are accounted for as equity awards under ASC 718 as the awards are settled in shares of the Company with no additional settlement options permitted. At the grant date, the Company estimated the fair value of this equity award. The compensation expense of this award each period is recognized by dividing the fair value of the total award by the requisite service period and recording the pro rata share for the period for which service has already been provided. As there are inherent uncertainties related to these factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded compensation may not accurately reflect the amount ultimately earned by the executives.awards.
A Monte Carlo simulation was used to determine the fair value of these awards at the grant date. The assumptions used to estimate the fair value of the executive management restricted stock unit awards with a market condition are as follows:
|
| Awards Issued |
| |
Risk-free interest rate (1) |
| 2.45 | % | |
Dividend yield |
| — |
| |
Expected volatility |
| 44.0 | % | |
Calculated fair value per unit |
| $ | 6.77 |
|
(1) U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the life of the executives restricted stock unit award with a market condition.
TheOn August 5, 2019 all 193,921 restricted stock units issued were cancelled and no shares were outstanding at September 30, 2019.
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 executive management containingretained 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 market conditionliability and the corresponding asset of $5.4 million at January 1, 2019.
For the quarter ended September 30, 2019, our leases qualify as operating leases and we did not have a service period of two years. The share-based compensation costsany 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 executive management’s restricted stock units containingour 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 market condition recognizedmonth-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 general and administrative expense bya lease liability in our balance sheet under ASC 842 because continuation of the lease is not reasonably certain. Additionally, the Company was $0.1 millionelected the short-term practical expedient to exclude leases with a term of twelve months or less.
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 period ended March 31,Company’s right-of-use assets and lease liabilities as of September 30, 2019. As of March 31, 2019, unrecognized stock-based compensation related to executive management’s restricted stock units containing a market condition was $1.3 million and will be recognized over a weighted-average period of 1.8 years.
| September 30, |
| |
| 2019 |
| |
| (In thousands) |
| |
Right-of-use asset | $ | 4,925 |
|
|
|
|
|
Lease liabilities: |
|
|
|
Current lease liability |
| 1,732 |
|
Long-term lease liability |
| 3,214 |
|
Total lease liability | $ | 4,946 |
|
The following table reflects the outstanding Executive Management restricted stock units containingCompany’s maturity analysis of the minimum lease payment obligations under non-cancelable operating leases with a market condition for the three months ended March 31, 2019:remaining term in excess of one year (in thousands):
|
| Shares |
| Weighted Average |
| |
Outstanding at December 31, 2018 |
| — |
| $ | — |
|
Granted |
| 193,921 |
| $ | 6.77 |
|
Vested |
| — |
| $ | — |
|
Forfeited |
| — |
| $ | — |
|
Outstanding at March 31, 2019 |
| 193,921 |
| $ | 6.77 |
|
| Office leases |
|
| Leased vehicles and office equipment |
|
| Total |
| |||
Remaining 2019 | $ | 399 |
|
| $ | 175 |
|
| $ | 574 |
|
2020 |
| 1,231 |
|
|
| 537 |
|
|
| 1,768 |
|
2021 |
| 1,727 |
|
|
| 627 |
|
|
| 2,354 |
|
2022 and thereafter |
| 411 |
|
|
| 119 |
|
|
| 530 |
|
Total lease payments | $ | 3,768 |
|
| $ | 1,458 |
|
| $ | 5,226 |
|
Less: interest | $ | 220 |
|
| $ | 60 |
|
| $ | 280 |
|
Present value of lease liabilities | $ | 3,548 |
|
| $ | 1,398 |
|
| $ | 4,946 |
|
12. Income Taxes
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 (in thousands):
|
|
|
|
|
| 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 |
|
26
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
For the three months ended March 31, 2019, the Company recorded no income tax expense or benefit. The significant difference betweenweighted average remaining lease terms and discount rate for all of our effective tax rate and the federal statutory income tax rateoperating leases were as follow as of 21% is primarily due to the effect of changes in the Company’s valuation allowance. September 30, 2019:
September 30, | |||
2019 | |||
Weighted average remaining lease term (years): | |||
Office leases | 1.67 | ||
Vehicles | 0.53 | ||
Office equipment | 0.09 | ||
Weighted average discount rate: | |||
Office leases | 3.61 | % | |
Vehicles | 0.85 | % | |
Office equipment | 0.18 | % | |
During the three months ended March 31,September 30, 2019, the Company’s valuation allowance increasedCompany recorded a $4.2 million loss on lease, which relates to the Midstates corporate office lease. The office will be vacated by $4.6 million from December 31, 2018, bringingmid-November. Because of excess sublease inventory in the total valuation allowance to $114.2 million at March 31, 2019. A valuation allowancelocal market, a liability has been recorded as management does not believe that it is more-likely-than-not that its deferred tax assets are realizable.accrued for rent and other operating expenses based upon the term and provisions of the lease.
We have instituted internal controls going forward to monitor and evaluate new leases for appropriate accounting under the new guidance.
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):
The Company expects to incur a tax loss in the current year due to the flexibility in deducting or capitalizing current year intangible drilling costs; thus no current income taxes are anticipated to be paid.
| September 30, |
|
| December 31, |
| ||
| 2019 |
|
| 2018 |
| ||
Accrued lease operating expense | $ | 11,561 |
|
| $ | 10,469 |
|
Accrued capital expenditures |
| 5,448 |
|
|
| 4,349 |
|
Accrued general and administrative expense |
| 4,459 |
|
|
| 4,393 |
|
Accrued ad valorem tax |
| 2,541 |
|
|
| 729 |
|
Operating lease liability |
| 1,732 |
|
|
| — |
|
Asset retirement obligations |
| 477 |
|
|
| 477 |
|
Accrued interest payable |
| 38 |
|
|
| 2,476 |
|
Other |
| 71 |
|
|
| 262 |
|
Accrued liabilities | $ | 26,327 |
|
| $ | 23,155 |
|
13. Income (Loss) Per Share
Cash and Cash Equivalents Reconciliation
The following table provides a reconciliation of net income (loss) attributablecash and cash equivalents on the Unaudited Condensed Consolidated Balance Sheet to common shareholderscash, cash equivalents and weighted average common shares outstanding for basic and diluted income (loss) per sharerestricted cash on the Unaudited Condensed Statements of Consolidated Cash Flows (in thousands):
| September 30, |
|
| December 31, |
| ||
| 2019 |
|
| 2018 |
| ||
Cash and cash equivalents | $ | 7,408 |
|
| $ | 49,704 |
|
Restricted cash |
| 325 |
|
|
| 325 |
|
Total cash, cash equivalents and restricted cash | $ | 7,733 |
|
| $ | 50,029 |
|
27
AMPLIFY ENERGY CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Supplemental cash flows for the periods presented:presented (in thousands):
|
| Three Months Ended March 31, |
| ||||
|
| 2019 |
| 2018 |
| ||
|
| (in thousands, except per share amounts) |
| ||||
Net Income (Loss): |
|
|
|
|
| ||
Net income (loss) |
| $ | (17,807 | ) | $ | 4,004 |
|
Participating securities—non-vested restricted stock |
| — |
| (99 | ) | ||
Basic and diluted income (loss) |
| $ | (17,807 | ) | $ | 3,905 |
|
|
|
|
|
|
| ||
Common Shares: |
|
|
|
|
| ||
Common shares outstanding — basic (1) |
| 22,837 |
| 25,299 |
| ||
Dilutive effect of potential common shares |
| — |
| — |
| ||
Common shares outstanding — diluted |
| 22,837 |
| 25,299 |
| ||
|
|
|
|
|
| ||
Net Income (Loss) Per Share: |
|
|
|
|
| ||
Basic |
| $ | (0.78 | ) | $ | 0.15 |
|
Diluted |
| $ | (0.78 | ) | $ | 0.15 |
|
Antidilutive stock options (2) |
| 206 |
| 500 |
| ||
Antidilutive warrants (3) |
| 6,980 |
| 6,626 |
| ||
| For the Nine Months Ended |
| |||||
| September 30, |
| |||||
| 2019 |
|
| 2018 |
| ||
Supplemental cash flows: |
|
|
|
|
|
|
|
Cash paid for interest, net of amounts capitalized | $ | 12,477 |
|
| $ | 15,405 |
|
Cash paid for reorganization items, net |
| 684 |
|
|
| 2,004 |
|
|
|
|
|
|
|
|
|
Noncash investing and financing activities: |
|
|
|
|
|
|
|
Increase (decrease) in capital expenditures in payables and accrued liabilities |
| 324 |
|
|
| (565 | ) |
Assets acquired & liabilities assumed in the Merger: |
|
|
|
|
|
|
|
Accounts receivable |
| 14,633 |
|
|
| — |
|
Prepaids and other current assets |
| 3,229 |
|
|
| — |
|
Other non-current assets |
| 9,879 |
|
|
|
|
|
Oil and natural gas properties |
| 142,642 |
|
|
| — |
|
Other property and equipment |
| 6,280 |
|
|
|
|
|
Accounts payable and accrued liabilities |
| (24,135 | ) |
|
| — |
|
Other non-current liabilities |
| (5,067 | ) |
|
| — |
|
Long-term debt |
| (76,559 | ) |
|
| — |
|
Issuance of common stock in connection with the Merger |
| 90,150 |
|
|
| — |
|
(1) Weighted-average common shares outstanding for basic and diluted income per share purposes includes 9,407 shares of common stock that, while not issued and outstanding at March 31, 2019 or 2018, respectively, are required by the First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate as filed on September 28, 2016 (the “Plan”) to be issued. Weighted-average common shares outstanding for basic and diluted income per share purposes also includes 79,389 director shares that were vested as of March 31, 2019, but final issuance of the vested shares was deferred by the non-employee directors until 2021.
(2) Amount represents options to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.
(3) Amount represents warrants to purchase common stock that are excluded from the diluted net income per share calculations because of their antidilutive effect.
Note 14. Related Party Transactions
Related Party Agreements
During 2017,There have been no transactions in excess of $120,000 between us and any related person in which the Company entered into an arrangement with EcoStim Energy Solutions, Inc. (“EcoStim”)related person had a direct or indirect material interest for well stimulation and completion services. EcoStim is an affiliate of Fir Tree Inc. who is a holder of the Company’s outstanding common stock. The Company had $2.1 million included in accounts payable in the Company’s unaudited interim condensed consolidated balance sheets at December 31, 2017 to EcoStim that was paid during the three and nine months ended March 31, 2018. No transactions with EcoStim occurred during the three months ended March 31, 2019.September 30, 2019 and 2018, respectively.
Note 15. Commitments and Contingencies
Litigation and Environmental
The Company is involved in various matters incidental to its operations and businessWe are not aware of any litigation, pending or threatened, that might give rise to a loss contingency. These matters may include legal and regulatory proceedings, commercial disputes, claims from royalty, working interest and surface owners, property damage and personal injury claims and environmental or other matters. In addition, the Company may be subject to customary audits by governmental authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as compliance with unclaimed property (escheatment) requirements and other laws. Further, other parties with an interest in wells operated by the Company have the ability under various contractual agreements to perform audits of its joint interest billing practices.
The Company vigorously defends itself in these matters. If the Company determines that an unfavorable outcome or loss of a particular matter is probable, and the amount of loss can be reasonably estimated, it accrues a liability for the contingent obligation. As new information becomes available or as a result of legal or administrative rulings in similar matters or a change in applicable law, the Company’s conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. The impact of subsequent changes to the Company’s accruals couldwe believe will have a material adverse effect on itsour financial position, results of operations. Asoperations 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 March 31,such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.
At September 30, 2019 and December 31, 2018, we had no environmental reserves recorded on our Unaudited Condensed Consolidated Balance Sheet.
Supplemental Bond for Decommissioning Liabilities Trust Agreement
Beta Operating Company, LLC (“Beta”), has an obligation with the Company’s total accrual for all loss contingencies was $1.1 million.
16. Subsequent Event
On May 6, 2019, the Company entered into a definitive merger agreement (“Merger Agreement”) pursuant to which Amplify Energy Corp. (“Amplify”) will merge with a subsidiary of the Company in an all-stock merger-of-equals. Under the terms of the Merger Agreement, Amplify stockholders will receive 0.933 shares of newly issued Company common stock for each Amplify share of common stock. The merger is expected to close in the third quarter of 2019, at which time Amplify and the Company’s stockholders will each own 50% of the outstanding shares of the combined entity.
The transaction is subject to the terms and conditions set forth in the Merger Agreement, including holders of a majority of the Company’s stock present at the special meeting having voted in favor of the stock issuance, holders of a majority of Amplify stock having voted in favor of the merger, the waiting period under the U.S. Hart-Scott-Rodino Act having expired or been terminated early, the Company’s stock being issued to Amplify stockholdersBOEM in connection with the merger being listed on the NYSE and other customary conditions.
The transactions contemplated by the Merger Agreement will be treated as a “changeits 2009 acquisition of our properties in control” as of the effective date for purposes of all Parent Benefit Plans (as defined in the Merger Agreement), including the Parent Stock Plans (as defined in the Merger Agreement) and all applicable employment agreements in effect prior to the effective date to which any employee of the Company is a party. federal waters offshore Southern California. The Company has agreedhad previously supported this obligation with $71.3 million of A-rated surety bonds and $90.2 million of cash, but $90.0 million of cash was released to satisfy promptly all applicable severance, retention and change in control payments and benefits owing to its employees, directors and other service providers under the Parent Benefit Plans. Without limiting the foregoing, (i) with respect to any employee of the Company whose employment is terminated without “cause” (as such term is defined in the applicable Parent Benefit Plan, but also including certain employees who are deemed to be terminated without cause pursuant to the Merger Agreement) on or within one year after the closing of the merger, (A) all Parent Stock Options (as defined in the Merger Agreement) held by such employee shall become fully vested, (B) all Parent RSUs (as defined in the Merger Agreement) held by such employee shall become fully vested and shall be settled promptly upon termination, (C) all Parent PSUs (as defined in the Merger Agreement) that are subject to the achievement of the Company’s specific stock price levels shall be deemed earned at the level specified in the applicable award agreement and shall become vested and settled promptly upon termination, (D) all Parent PSUs that are not described in the foregoing clause (C) shall be deemed earned at the target level of such award and shall become vested and settled promptly upon termination, and (E) all cash amounts pursuant to the “Share Buyback Equalization Program” approved by the board of directors of the Company on December 21, 2018 (the “Equalization Program”) that are owing to such employee(s) shall be paid promptly upon termination, (ii) all Parent RSUs heldJune 24, 2019. Following the release, Beta’s decommissioning obligations remain fully supported by members of the board of directors shall become fully vested$161.3 million in A-rated surety bonds and shall be settled promptly upon the closing of the merger, and (iii) all cash amounts pursuant to the Equalization Program that are owing to non-employee directors of the Company shall be paid promptly upon the closing of the merger.$0.3 million in cash.
The Company estimates that between 500,000had no income tax benefit/(expense) for the three months ended September 30, 2019 and 800,000 unvested stock awards (including stock options) will vest upon closinghad less than $0.1 million income tax benefit/(expense) for the nine months ended September 30, 2019, and between $8.5 millionno income tax benefit/(expense) for the three and nine months ended September 30, 2018. The Company’s effective tax rate was 0.0% and 0.6% for the three and nine months ended September 30, 2019, respectively, and 0.0% for the three and nine months ended September 30, 2018, respectively. The effective tax rates for the three and nine months ended September 30, 2019 and 2018 are different from the statutory U.S. federal income tax rate primarily due to $11.5 million in severance payments will be made. The number of unvested stock awards and severance payments are estimated and the final amount has not yet been determined.our recorded valuation allowances.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussionManagement’s Discussion and analysisAnalysis of our financial conditionFinancial Condition and resultsResults of operationsOperations should be read in conjunction with the Unaudited Condensed Consolidated Financial Statements and accompanying notes in “Item 1. Financial Statements” contained herein and our consolidated financial statements and notes theretoAnnual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on March 14, 2019 and the related management’s discussion and analysis contained in ourLegacy Amplify’s Annual Report on Form 10-K dated andfor the year ended December 31, 2018, filed with the Securities and Exchange Commission (“SEC”)SEC on March 14,6, 2019 as well as the unaudited interim condensed consolidated financial statements and notes thereto included in this quarterly report on(“Legacy Amplify Form 10-Q.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
Various statements contained in or incorporated by reference into this report are10-K”). The following discussion contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”)that reflect our future plans, estimates, beliefs and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, and the plans, beliefs, expectations, intentions and objectives of management are forward-looking statements. When used in this quarterly report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words. All forward-looking statements speak only as of the date of this quarterly report. You should not place undue reliance on these forward-looking statements. Theseexpected performance. The forward-looking statements are subject to a number ofdependent upon events, risks uncertainties and assumptions, including changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affectingthat may be outside our business, as well as those factors discussed below and elsewhere in this report and in the Annual Report on Form 10-K. Moreover, we operate in a very competitive and rapidly changing environment. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this quarterly report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, andcontrol. Our actual results could differ materially and adversely from those anticipated or implieddiscussed in these forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” in the forward-looking statements.front of this report.
Overview
Forward-looking statements may include statements about our:
· business strategy;
· estimated future net reservesWe operate in one reportable segment engaged in the acquisition, development, exploitation and present value thereof;
· technology;
· financial condition, revenues, cash flows and expenses;
· levels of indebtedness, liquidity, borrowing capacity and compliance with debt covenants;
· financial strategy, budget, projections and operating results;
· oil and natural gas realized prices;
· timing and amount of future production of oil and natural gas;
· availability of drilling and production equipment;
·gas properties. Our management evaluates performance based on the amount, nature and timing of capital expenditures, including future development costs;
· availability of oilfield labor;
· availability of third party natural gas gathering and processing capacity;
· availability and terms of capital;
· drilling of wells, including our identified drilling locations;
· successful results from our identified drilling locations;
· marketing of oil and natural gas;
·reportable business segment as the integration and benefits of asset and property acquisitions or the effects of asset and property acquisitions or dispositions on our cash position and levels of indebtedness;
· infrastructure for salt water disposal and electricity;
· current and future ability to dispose of salt water;
· sources of electricity utilized in operations and the related infrastructures;
· costs of developing our properties and conducting other operations;
· general economic conditions;
· effectiveness of our risk management activities;
· environmental liabilities;
· counterparty credit risk;
· the outcome of pending and future litigation;
· governmental regulation and taxation of the oil and natural gas industry;
· developments in oil and natural gas producing countries;
· capital structure and capital returns;
· uncertainty regarding our future operating results; and
· plans, objectives, expectations and intentions contained in this quarterly report thatenvironments are not historical.
Overview
We are an independent exploration and production company focused ondifferent within the application of modern drilling and completion techniques in oil and liquids-rich basins in the onshore United States. Our operations are primarily focused on exploration and production activities in the Mississippian Lime. The terms “Company,” “we,” “us,” “our,” and similar terms refer to us and our subsidiary, unless the context indicates otherwise.
Our financial results depend upon many factors, but are largely driven by the volumeoperation of our oil and natural gas productionproperties. Our business activities are conducted through OLLC our wholly owned subsidiary, and the price that we realize from the saleits wholly owned subsidiaries. Our assets consist primarily of that production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, if any, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials, and other factors. Accordingly, finding and developingproducing oil and natural gas properties and are located in Oklahoma, the Rockies, in federal waters offshore Southern 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. As of December 31, 2018:
Our total estimated proved reserves at economical costswere approximately 841.1 Bcfe, of which approximately 65% were liquids and 79% were classified as proved developed reserves;
We produced from 2,068 gross (1,125 net) producing wells across our properties, with an average working interest of 54% and the Company is critical tothe operator of record of the properties containing 92% of our long-term success.total estimated proved reserves; and
Our average net production for the three months ended December 31, 2018 was 142.5 MMcfe/d, implying a reserve-to-production ratio of approximately 16 years.
Recent Developments
Merger
On MayAugust 6, 2019, weMidstates, Legacy Amplify and Merger Sub closed on the Merger Agreement entered into a definitive merger agreementon May 5, 2019, pursuant to which, Amplify will merge with a subsidiary of us in an all-stock merger-of-equals. Undertransaction, Merger Sub merged with and into Legacy Amplify, with Legacy Amplify surviving the termsMerger as a wholly owned subsidiary of Midstates. At the effective time of the merger agreement,Merger, each share of Legacy Amplify stockholders willcommon stock issued and outstanding immediately prior to the effective time (other than excluded shares) were cancelled and converted into the right to receive 0.933 shares of our newly issuedMidstates common stock, forpar value $0.01 per share. On the effective date of the Merger, Midstates changed its name to “Amplify Energy Corp.” Following the closing of the Merger, Legacy Amplify stockholders and Midstates stockholders each Amplify share of common stock. The merger is expected to close in the third quarter of 2019, at which time Amplify and our stockholders will each ownowned approximately 50% of the outstanding sharesstock of the combined entity.Company and the Company continues to operate under the Amplify brand.
Business Environment and Operational Focus
The transaction is subjectWe use a variety of financial and operational metrics to assess the terms and conditions set forth in the merger agreement, including holders of a majorityperformance of our stock present at the special meeting having voted in favor of the stock issuance, holders of a majority of Amplify stock having voted in favor of the merger, the waiting period under the U.S. Hart-Scott-Rodino Act having expired or been terminated early, our stock being issued to Amplify stockholders in connection with the merger being listed on the NYSEoil and other customary conditions.
The transactions contemplated by the Merger Agreement will be treated as a “change in control” as of the effective date for purposes of all Parent Benefit Plans (as defined in the Merger Agreement), including the Parent Stock Plans (as defined in the Merger Agreement) and all applicable employment agreements in effect prior to the effective date to which any of our employees are a party. We have agreed to satisfy promptly all applicable severance, retention and change in control payments and benefits owing to our employees, directors and other service providers under the Parent Benefit Plans. Without limiting the foregoing,natural gas operations, including: (i) with respect to any employee of ours whose employment is terminated without “cause” (as such term is defined in the applicable Parent Benefit Plan, but also including certain employees who are deemed to be terminated without cause pursuant to the Merger Agreement) on or within one year after the closing of the merger, (A) all Parent Stock Options (as defined in the Merger Agreement) held by such employee shall become fully vested, (B) all Parent RSUs (as defined in the Merger Agreement) held by such employee shall become fully vested and shall be settled promptly upon termination, (C) all Parent PSUs (as defined in the Merger Agreement) that are subject to the achievement of our specific stock price levels shall be deemed earned at the level specified in the applicable award agreement and shall become vested and settled promptly upon termination, (D) all Parent PSUs that are not described in the foregoing clause (C) shall be deemed earned at the target level of such award and shall become vested and settled promptly upon termination, and (E) all cash amounts pursuant to the “Share Buyback Equalization Program” approved by our board of directors on December 21, 2018 (the “Equalization Program”) that are owing to such employee(s) shall be paid promptly upon termination,production volumes; (ii) all Parent RSUs held by members of the board of directors shall become fully vested and shall be settled promptly upon the closing of the merger, and (iii) all cash amounts pursuant to the Equalization Program that are owing to our non-employee directors shall be paid promptly upon the closing of the merger.
Operations Update
Mississippian Lime
The following table presents our average daily production from our Mississippian Lime asset for the periods presented:
|
| Three Months Ended |
| Three Months Ended |
| Decrease in |
|
|
|
|
|
|
|
|
|
Average daily production: |
|
|
|
|
|
|
|
Oil (Bbls) |
| 3,381 |
| 4,463 |
| (24.2 | )% |
Natural gas liquids (Bbls) |
| 3,538 |
| 4,194 |
| (15.6 | )% |
Natural gas (Mcf) |
| 37,919 |
| 46,161 |
| (17.9 | )% |
Net Boe/day |
| 13,239 |
| 16,351 |
| (19.0 | )% |
In the first quarter of 2019, we incurred approximately $6.4 million of operational capital expenditures in the Mississippian Lime basin.
Anadarko Basin
On May 31, 2018, we closedrealized prices on the sale of our Anadarko Basin assets for $58.0 million inproduction; (iii) cash ($54.4 million, netsettlements 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 closing adjustments).
Capital Expenditures
During the three months ended March 31, 2019, we incurred operational capital expenditures of $6.4 million in the Mississippian Lime basin, which consisted of the following:
Drilling and completion activities |
| $ | 5,335 |
|
Acquisition of acreage and seismic data |
| 1,108 |
| |
Operational capital expenditures incurred |
| $ | 6,443 |
|
Capitalized G&A, office, ARO & other |
| 70 |
| |
Capitalized interest |
| 103 |
| |
Total capital expenditures incurred |
| $ | 6,616 |
|
Factors that Significantly Affect Our Risk
Revenues
Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments, as well as competitionrevenues are derived from other sourcesthe sale of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, our cash flows, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.
We follow the full cost method of accounting for our oil and gas properties. In the first quarter of 2019, the results of our full cost “ceiling test” required us to recognize an impairment of our oil and gas properties of $9.7 million. While this impairment did not impact cash flows from operating activities or liquidity, it did increase our net loss and shareholders’ equity. As a result of the pause in our drilling program, we could continue to incur impairment charges throughout fiscal year 2019. The magnitude of future impairment charges, if any, will be impacted by certain factors outside of our control, such as commodity pricing.
We dispose of large volumes of saltwater produced in conjunction with oil and natural gas from drilling and production, operations in the Mississippian Lime. Our disposal operations are conducted pursuant to permits issued to us by governmental authorities overseeing such disposal activities.
There continues to be a concern that the injection of saltwater into belowground disposal wells contributes to seismic activity in certain areas, including Oklahoma, where we operate. The Oil and Gas Conservation Division (“OGCD”) of the Oklahoma Corporation Commission established caps for additional wells, including 16 that we operate, on February 24, 2017. On March 1, 2017, the OGCD also issued a statement saying that further actions to reduce the earthquake rate in Oklahoma could be expected. The OGCD has since issued several directives for disposal well shut-in and volume reductions in certain areas following seismic activity. While our current plans are for future disposal wells to inject into formations other than the Arbuckle and we currently operate 10 such non-Arbuckle formation disposal wells, we continue to utilize wells that dispose into the Arbuckle formation. We have timely met and satisfied all requests of the OGCD regarding changes and/or reductions in disposal capacity in our operated disposal wells, all while maintaining our production base without any negative material impact thereto. We believe we are currently in compliance with the OGCD’s latest requests regarding Arbuckle injection limits; however, a change in disposal well regulations or injection limits, or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of saltwater and ultimately increase the cost of our operations and/or reduce the volume of oil and natural gas that we produce from our wells.
Results of Operations
The following table summarizes our revenues for the periods indicated (in thousands):
|
| Crude Oil |
| NGLs |
| Natural Gas |
| Total |
| ||||
Revenues for the three months ended March 31, 2018 |
| $ | 32,414 |
| $ | 11,038 |
| $ | 8,337 |
| $ | 51,789 |
|
Changes due to volumes |
| (13,423 | ) | (2,747 | ) | (2,319 | ) | (18,489 | ) | ||||
Changes due to price |
| (2,664 | ) | (2,075 | ) | 592 |
| (4,147 | ) | ||||
Revenues for the three months ended March 31, 2019 |
| $ | 16,327 |
| $ | 6,216 |
| $ | 6,610 |
| $ | 29,153 |
|
Oil, NGLs and Natural Gas Pricing
The following table sets forth information regarding average realized sales prices for the periods indicated (per BOE):
|
| For the Three Months |
| For the Three Months |
|
|
| ||
|
| Ended March 31, 2019 |
| Ended March 31, 2018 |
| % Change |
| ||
AVERAGE SALES PRICES: |
|
|
|
|
|
|
| ||
Oil, without realized derivatives (per Bbl) |
| $ | 53.65 |
| $ | 62.41 |
| (14.0 | )% |
Oil, with realized derivatives (per Bbl) |
| $ | 57.00 |
| $ | 59.57 |
| (4.3 | )% |
Natural gas liquids, without realized derivatives (per Bbl) |
| $ | 19.52 |
| $ | 26.04 |
| (25.0 | )% |
Natural gas liquids, with realized derivatives (per Bbl) |
| $ | 19.52 |
| $ | 26.04 |
| (25.0 | )% |
Natural gas, without realized derivatives (per Mcf) |
| $ | 1.94 |
| $ | 1.76 |
| 10.2 | % |
Natural gas, with realized derivatives (per Mcf) |
| $ | 1.86 |
| $ | 2.04 |
| (8.8 | )% |
Oil, NGLs and Natural Gas Production
|
| For the Three Months |
| For the Three Months |
|
|
|
|
| Ended March 31, 2019 |
| Ended March 31, 2018 |
| % Change |
|
PRODUCTION DATA: |
|
|
|
|
|
|
|
Oil (Bbls/d) |
|
|
|
|
|
|
|
Mississippian Lime |
| 3,381 |
| 4,564 |
| (25.9 | )% |
Anadarko Basin(1) |
| — |
| 1,207 |
| (100.0 | )% |
Natural gas liquids (Bbls/d) |
|
|
|
|
|
|
|
Mississippian Lime |
| 3,538 |
| 3,644 |
| (2.9 | )% |
Anadarko Basin(1) |
| — |
| 1,065 |
| (100.0 | )% |
Natural gas (Mcf/d) |
|
|
|
|
|
|
|
Mississippian Lime |
| 37,919 |
| 43,857 |
| (13.5 | )% |
Anadarko Basin(1) |
| — |
| 8,671 |
| (100.0 | )% |
Combined (Boe/d) |
|
|
|
|
|
|
|
Mississippian Lime |
| 13,239 |
| 15,518 |
| (14.7 | )% |
Anadarko Basin(1) |
| — |
| 3,717 |
| (100.0 | )% |
(1) We divested our Anadarko Basin assets during the second quarter of 2018.
Oil Revenues
Oil volumes in the Mississippian Lime decreased 1,183 Boe/day, or 25.9% for the three months ended March 31, 2019, primarily due to lower production as a result of reduced drilling activity and natural decline. Average oil sales prices, without realized derivatives, decreased by $8.76 per barrel, or 14.0%, largely as a result of a decrease in prevailing market prices.
NGLs Revenues
NGLs volumes in the Mississippian Lime decreased 106 Boe/day, or 2.9%, for the three months ended March 31, 2019, primarily as a result of reduced drilling activity and natural decline. Average NGLs sales prices, without realized derivatives, decreased by $6.52 per barrel, or 25.0%, largely as a result of lower oil prices, which correlate with NGLs pricing.
Natural Gas Revenues
Natural gas volumes in the Mississippian Lime decreased 5,938 Mcf/day, or 13.5%, as a result of reduced drilling activity and natural decline. Average natural gas sales prices, without realized derivatives, increased by $0.18 per Mcf, or 10.2%, largely due to higher prevailing index prices at our delivery points.
Losses on Commodity Derivative Contracts—Net
A summary of our open commodity derivative positions is included in Note 5 to the financial statements included in “Part I. Financial Information — Item 1. Financial Statements” of this report. The following tables provide financial information associated with our oil and natural gas hedges for the periods indicated (in thousands):
|
| For the Three |
| For the Three |
| ||
|
| (in thousands) |
| (in thousands) |
| ||
Cash receipts (payments) on settlement |
|
|
|
|
| ||
Oil derivatives |
| $ | 1,018 |
| $ | (1,476 | ) |
Natural gas derivatives |
| (249 | ) | 1,316 |
| ||
Total cash settlements |
| $ | 769 |
| $ | (160 | ) |
|
|
|
|
|
| ||
Gains (losses) due to fair value changes |
|
|
|
|
| ||
Oil derivatives |
| $ | (8,678 | ) | $ | (2,404 | ) |
Natural gas derivatives |
| 177 |
| (1,375 | ) | ||
Total gains (losses) on fair value changes |
| $ | (8,501 | ) | $ | (3,779 | ) |
|
|
|
|
|
| ||
Losses on commodity derivative contracts |
| $ | (7,732 | ) | $ | (3,939 | ) |
Cash settlements, as presented in the table above, represent realized gains (losses) related to our derivative instruments. In addition to cash settlements, we also recognize fair value changes on our derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.
Expenses
|
| Three Months Ended March 31, |
| Three Months Ended March 31, |
| ||||||||
|
| 2019 |
| 2018 |
| 2019 |
| 2018 |
| ||||
|
| (in thousands) |
| (per Boe) |
| ||||||||
EXPENSES: |
|
|
|
|
|
|
|
|
| ||||
Lease operating and workover |
| $ | 8,990 |
| $ | 14,808 |
| $ | 7.54 |
| $ | 8.56 |
|
Gathering and transportation |
| 19 |
| 57 |
| 0.02 |
| 0.03 |
| ||||
Severance and other taxes |
| 1,933 |
| 2,861 |
| 1.62 |
| 1.65 |
| ||||
Asset retirement accretion |
| 157 |
| 297 |
| 0.13 |
| 0.17 |
| ||||
Depreciation, depletion, and amortization |
| 11,794 |
| 15,213 |
| 9.91 |
| 8.79 |
| ||||
Impairment in carrying value of oil and gas properties |
| 9,653 |
| — |
| 8.10 |
| — |
| ||||
General and administrative |
| 6,438 |
| 9,857 |
| 5.40 |
| 5.70 |
| ||||
Total expenses |
| $ | 38,984 |
| $ | 43,093 |
| $ | 32.72 |
| $ | 24.90 |
|
Lease Operating and Workover
Lease operating and workover expenses decreased $5.8 million, or 39.3% to $9.0 million for the three months ended March 31, 2019, compared to $14.8 million for the three months ended March 31, 2018. Lower lease operating and work over expense was due to the sale of Anadarko in the second quarter of 2018. Lease operating and workover expenses decreased to $7.54 per Boe during the three months ended March 31, 2019NGLs that are extracted from $8.56 per Boe during the related period in 2018, a decrease of $1.02 per Boe, or 11.9%, largely as a result of decreased workover activity during the 2019 period.
Gathering and Transportation
Gathering and transportation expenses decreased 66.7% for the three months ended March 31, 2019. This decrease in gathering and transportation expenses is due primarily to decreased natural gas productionduring 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 Mississippian Lime basin.
Severancefuture prices received. At the end of each period the fair value of these commodity derivative instruments are estimated and Other Taxes
|
| Three Months Ended March 31, |
| ||||
|
| 2019 |
| 2018 |
| ||
|
| (in thousands) |
| ||||
Total oil, natural gas, and natural gas liquids sales |
| $ | 29,153 |
| $ | 51,789 |
|
|
|
|
|
|
| ||
Severance taxes |
| 1,930 |
| 2,681 |
| ||
Ad valorem and other taxes |
| 3 |
| 180 |
| ||
Severance and other taxes |
| $ | 1,933 |
| $ | 2,861 |
|
Severance taxes as a percentage of sales |
| 6.6 | % | 5.2 | % | ||
Severance and other taxes as a percentage of sales |
| 6.6 | % | 5.5 | % | ||
Severance and other taxes increased to 6.6% as a percentage of sales forbecause hedge accounting is not elected, the three months ended March 31, 2019, as compared to 5.5% for the three months ended March 31, 2018. The increase in severance taxes as a percentage of sales increased for the 2019 period due to legislative changes in the State of Oklahoma increasing the gross production incentive tax rate for wells drilled beginning July 1, 2015, from 2.0% to 5.0%. The initial 2.0% rate is effective for the first thirty-six months of production and moves to 7.0% thereafter. This legislation will increase the incentive tax rate to 5.0% for all new and existing wells that currently qualify for the 2.0% incentive tax rate beginning in July 2018.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization expense decreased $3.4 million, or 22.5%, to $11.8 million for the three months ended March 31, 2019, compared to $15.2 million for the three months ended March 31, 2018. This decrease in depreciation, depletion and amortization is due primarily to the Anadarko Divestiture in the second quarter of 2018, as well as a decrease in our production as compared to the three months ended March 31, 2018. Depreciation, depletion and amortization per Boe increased $1.12 per Boe during the three months ended March 31, 2019, to $9.91 per Boe from $8.79 per Boe for the three months ended March 31, 2018. Our depletion rate has increased $1.36 per BOE for the three months ended March 31, 2019, to $9.81 primarily as a result of decreased proved reserves volumes from the prior year due to decreased drilling.
Impairment in Carrying Value of Oil and Gas Properties
As we account for our oil and gas properties under the full cost method, we are required to perform a full-cost ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated DD&A and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price we received as of the first trading day of each month over the preceding twelve months (such average price is held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved propertiesunsettled commodity derivative instruments are recognized in earnings at the end of each accounting period.
Critical Accounting Policies and Estimates
A discussion of our critical accounting policies and estimates is included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to impairment expense in the accompanying consolidated statements of operations.
During the three months ended March 31, 2019, we recorded an impairment charge of $9.7 million. This impairment expense recognized during the period was primarily due to a decrease in the PV-10 value of proven oil and natural gas reserves as a result of lower commodity pricing.
General and Administrative (“G&A”)
G&A expenses decreased $3.4 million, or 34.7%, to $6.4 million for the three months ended March 31, 2019, compared to $9.9 million for the three months ended March 31, 2018. The decrease in G&A expenses during the three months ended March 31, 2019 is primarily due to a $2.3 million decrease in cost related to our review of various strategic options as compared to the three months ended March 31, 2018. Additionally, a reduction-in-force occurred in both the three months ended 2019 and 2018, resulting in a $2.5 million decrease in employee compensation and share based compensation expense in the 2019 period, offset by a $1.4 million decrease in cost recovery due to the divestiture of producing wells in the Anadarko basin during the second quarter of 2018.
Other Expense
|
| For the Three Months Ended March 31, |
| ||||
|
| 2019 |
| 2018 |
| ||
|
| (in thousands) |
| ||||
OTHER EXPENSE |
|
|
|
|
| ||
Interest income |
| $ | 5 |
| $ | 19 |
|
Interest expense |
| (865 | ) | (1,796 | ) | ||
Amortization of deferred financing costs |
| (174 | ) | (108 | ) | ||
Capitalized interest |
| 102 |
| 77 |
| ||
Interest expense—net of amounts capitalized |
| (937 | ) | (1,827 | ) | ||
|
|
|
|
|
| ||
Total other expense |
| $ | (932 | ) | $ | (1,808 | ) |
Interest Expense
Interest expense was $0.9 million for the three months ended March 31, 2019, a decrease of 51.8%, from $1.8 million for the three months ended March 31, 2018. Our average outstanding balance under our revolving credit facility was $40.3 million during the three months ended March 31, 2019, compared to $113.1 million for the three months ended March 31, 2018. Total interest expense capitalized to oil and gas properties was $0.1 million for the three months ended March 31, 2019 and 2018.
Provision for Income Taxes
We recorded no income tax expense or benefit during the three months ended March 31, 2019 or 2018, respectively, due to the change in our valuation allowance recorded against our net deferred tax assets. Our valuation allowance was $114.2 million and $119.0 million at March 31, 2019 and 2018, respectively.
Liquidity and Capital Resources
Overview
The following table presents a summary of our key financial indicators at the dates presented (in thousands):
|
| March 31, 2019 |
| December 31, 2018 |
| ||
Cash and cash equivalents |
| $ | 717 |
| $ | 11,341 |
|
Net working capital (deficit) |
| (3,944 | ) | 13,946 |
| ||
Total long-term debt |
| 59,059 |
| 23,059 |
| ||
Total stockholders’ equity |
| 473,549 |
| 541,677 |
| ||
Available borrowing capacity |
| 109,000 |
| 145,000 |
| ||
Our decisions regarding capital structure, hedging and drillingLegacy Amplify Form 10-K. Significant estimates include, but are based upon many factors, including anticipated future commodity pricing, expected economic conditions and recoverable reserves.
We anticipate our operating cash flows, cash on hand and cash available from borrowings under the RBL will be our primary sources of liquidity although we may seek to supplement our liquidity through divestitures, additional or refinanced borrowings or debt or equity securities offerings as circumstances and market conditions dictate. We believe the combination of these sources of liquidity will be adequate to fund anticipated capital expenditures, service our existing debt and remain compliant with all other contractual commitments.
Our cash flows from operations are impacted by various factors, the most significant of which is the market pricing for oil, NGLs and natural gas. The pricing for these commodities is volatile, and the factors that impact such market pricing are global and therefore outside of our control. Volatility in commodity prices also impacts estimated quantities of proved reserves. As a result, it is not possible for us to precisely predict our future cash flows from operating revenues due to these market forces.
We enter into hedging activities with respect to a portion of our production to manage our exposurelimited to, oil and natural gas price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefitsreserves; depreciation, depletion and amortization of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts.
Significant Sources of Capital
RBL
At March 31, 2019, in addition to cash on hand of $0.7 million, we maintained the RBL. The RBL has a current borrowing base of $170.0 million. At March 31, 2019, we had $59.1 million drawn on the RBL and outstanding letters of credit obligations totaling $1.9 million. As a result, at March 31, 2019, we had $109.0 million of availability on the RBL.
The RBL matures on September 30, 2020 and borrowings thereunder are secured by (i) first-priority mortgages on at least 90% of the ourproved oil and natural gas properties, (ii) all other presently owned or after-acquired property (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing) and (iii) a perfected pledge on all equity interests. The RBL bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. At March 31, 2019, the weighted average interest rate, excluding amortization expense of deferred financing costs and commitment fees, was 7.0%.
In addition to interest expense, the RBL requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of 0.50% per annum based on the average daily amount by which the borrowing base exceeds outstanding borrowings during each quarter.
On April 11, 2019, our borrowing base was redetermined at the existing amount of $170.0 million.
Debt Covenants
The RBL as amended, contains various other financial covenants, including an EBITDA to interest expense coverage ratio limitation of not less than 2.50:1.00 and a ratio limitation of Total Net Indebtedness (as defined in the RBL) to EBITDA of not more than 4.00:1.00.
In addition, the RBL contains various other covenants that, among other things, may restrict our ability to: (i) incur additional indebtedness or guarantee indebtedness (ii) make loans and investments; (iii) pay dividends on capital stock and make other restricted payments, including the prepayment or redemption of other indebtedness; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with our affiliates; (vii) acquire, consolidate or merge with another entity upon certain terms and conditions; (viii) sell all or substantially all of our assets; (ix) prepay, redeem or repurchase certain debt; (x) alter the business we conduct and make amendments to our organizational documents, (xi) enter into certain derivative transactions and (xii) enter into certain marketing agreements and take-or-pay arrangements.
As of March 31, 2019, we were in compliance with our debt covenants.
Cash Flows from Operating, Investing and Financing Activities
The following table summarizes our consolidatedproperties; future cash flows from operating, investing and financing activities for the periods presented. For information regarding the individual components of our cash flow amounts, please refer to the unaudited interim condensed consolidated statements of cash flows included under “Part I. Financial Information — Item 1. Financial Statements” of this Quarterly Report.
Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and natural gas prices. Regionalproperties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and worldwide economic activity, weather, infrastructure capacity to reach marketsliabilities assumed in business combinations and other variable factors significantly impact the prices of these commodities.asset retirement obligations. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Part I. Financial Information — Item 3. Quantitative and Qualitative Disclosures about Market Risk.”
The following information highlights the significant period-to-period variancesestimates, in our cash flow amounts (in thousands):
|
| For the Three Months |
| For the Three Months |
| ||
Net cash provided by operating activities |
| $ | 13,165 |
| $ | 22,147 |
|
Net cash used in investing activities |
| (9,527 | ) | (31,758 | ) | ||
Net cash used in financing activities |
| (14,262 | ) | (50,459 | ) | ||
Net change in cash |
| $ | (10,624 | ) | $ | (60,070 | ) |
Cash flows provided by operating activities
Net cash provided by operating activities was $13.2 millionopinion, are subjective in nature, require the use of professional judgment and $22.1 million for the three months ended March 31, 2019 and 2018, respectively. The decrease in net cash provided by operating activities was primarily the result of a $23.0 million decrease in revenues from contracts with customers, partially offset by payments received for the settlement of certain derivatives of $0.8 million as compared to payments for derivative settlements of $0.2 million, a decrease in general and administrative expenses of $3.4 million, a decrease in lease operating and workover expenses of $5.8 million and an increase in the change of working capital of $3.2 million for the three months ended March 31, 2019 as compared to the three months ended March 31, 2018.
Cash flows used in investing activities
Net cash used in investing activities of $9.5 million and $31.8 million for the three months ended March 31, 2019 and 2018, respectively. Substantially all of our capital spend is invested into our Mississippi Lime asset, and the decrease year-over-year is the result of our decision to pause drilling beginning in the fourth quarter of 2018.
Cash flows provided by financing activities
Net cash used in financing activities was $14.3 million and $50.5 million for the three months ended March 31, 2019 and 2018, respectively. During the three months ended March 31, 2019, we drew down $36.0 million, net on the RBL, as well as, repurchased and retired $50.0 million of common stock as a result of the Tender Offer noted in “Part I. Financial Information — Note 11. Equity and Share-Based Compensation” of this Quarterly Report.
Critical Accounting Policies and Estimates
involve complex analysis.
When used in the preparation of our unaudited interim condensed consolidated financial statements, such estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our condensed consolidated financial position, results of operations and cash flows.
Results of Operations
A discussionBeginning in 2019, the Company elected to change its reporting convention from natural gas equivalent (Mcfe) to barrels of oil equivalent (Boe). The change in presentation reflects our liquids-weighted production and reserve profile with a balanced approach to development of our critical accounting policiesoil and estimatesnatural gas asset portfolio. Legacy Amplify’s proved reserves as of year-end 2018 were 50% crude oil, 15% natural gas liquids and 35% natural gas.
The results of operations for the three and nine months ended September 30, 2019 and 2018 have been derived from our consolidated financial statements.
The following table summarizes certain of the results of operations for the periods indicated.
| For the Three Months Ended |
|
| For the Nine Months Ended |
| ||||||||||
| September 30, |
|
| September 30, |
| ||||||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
| ($ In thousands) |
| |||||||||||||
Oil and natural gas sales | $ | 72,426 |
|
| $ | 85,446 |
|
| $ | 196,978 |
|
| $ | 264,187 |
|
Lease operating expense |
| 32,977 |
|
|
| 27,505 |
|
|
| 88,179 |
|
|
| 84,575 |
|
Gathering, processing and transportation |
| 4,459 |
|
|
| 6,197 |
|
|
| 13,507 |
|
|
| 17,772 |
|
Exploration expense |
| 3 |
|
|
| 9 |
|
|
| 24 |
|
|
| 3,031 |
|
Taxes other than income |
| 5,135 |
|
|
| 4,717 |
|
|
| 13,008 |
|
|
| 15,289 |
|
Depreciation, depletion and amortization |
| 15,617 |
|
|
| 13,355 |
|
|
| 39,696 |
|
|
| 39,932 |
|
General and administrative expense |
| 27,034 |
|
|
| 8,219 |
|
|
| 46,908 |
|
|
| 35,739 |
|
Accretion of asset retirement obligations |
| 1,428 |
|
|
| 1,272 |
|
|
| 4,071 |
|
|
| 4,419 |
|
(Gain) loss on commodity derivative instruments |
| (28,725 | ) |
|
| 21,110 |
|
|
| (19,231 | ) |
|
| 67,218 |
|
(Gain) loss on sale of properties |
| — |
|
|
| (707 | ) |
|
| — |
|
|
| 1,439 |
|
Interest expense, net |
| (5,276 | ) |
|
| (5,336 | ) |
|
| (13,787 | ) |
|
| (17,395 | ) |
Loss on lease |
| (4,237 | ) |
|
| — |
|
|
| (4,237 | ) |
|
| — |
|
Reorganization items, net |
| (33 | ) |
|
| (466 | ) |
|
| (684 | ) |
|
| (1,752 | ) |
Income tax benefit (expense) |
| — |
|
|
| — |
|
|
| 50 |
|
|
| — |
|
Net income (loss) |
| 5,157 |
|
|
| (2,598 | ) |
|
| (7,679 | ) |
|
| (24,638 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales | $ | 55,011 |
|
| $ | 52,576 |
|
| $ | 136,754 |
|
| $ | 165,843 |
|
NGL sales |
| 4,306 |
|
|
| 12,132 |
|
|
| 15,509 |
|
|
| 34,009 |
|
Natural gas sales |
| 13,109 |
|
|
| 20,738 |
|
|
| 44,715 |
|
|
| 64,335 |
|
Total oil and natural gas revenue | $ | 72,426 |
|
| $ | 85,446 |
|
| $ | 196,978 |
|
| $ | 264,187 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
| 1,017 |
|
|
| 784 |
|
|
| 2,465 |
|
|
| 2,579 |
|
NGLs (MBbls) |
| 383 |
|
|
| 364 |
|
|
| 907 |
|
|
| 1,167 |
|
Natural gas (MMcf) |
| 7,482 |
|
|
| 7,134 |
|
|
| 18,775 |
|
|
| 22,575 |
|
Total (MBoe) |
| 2,647 |
|
|
| 2,337 |
|
|
| 6,501 |
|
|
| 7,509 |
|
Average net production (MBoe/d) |
| 28.8 |
|
|
| 25.4 |
|
|
| 23.8 |
|
|
| 27.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) | $ | 54.11 |
|
| $ | 67.03 |
|
| $ | 55.48 |
|
| $ | 64.30 |
|
NGL (per Bbl) |
| 11.25 |
|
|
| 33.34 |
|
|
| 17.11 |
|
|
| 29.14 |
|
Natural gas (per Mcf) |
| 1.75 |
|
|
| 2.91 |
|
|
| 2.38 |
|
|
| 2.85 |
|
Total (per Boe) | $ | 27.37 |
|
| $ | 36.56 |
|
| $ | 30.30 |
|
| $ | 35.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average unit costs per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense | $ | 12.46 |
|
| $ | 11.77 |
|
| $ | 13.56 |
|
| $ | 11.26 |
|
Gathering, processing and transportation |
| 1.68 |
|
|
| 2.65 |
|
|
| 2.08 |
|
|
| 2.37 |
|
Taxes other than income |
| 1.94 |
|
|
| 2.02 |
|
|
| 2.00 |
|
|
| 2.04 |
|
General and administrative expense |
| 10.21 |
|
|
| 3.52 |
|
|
| 7.22 |
|
|
| 4.76 |
|
Depletion, depreciation and amortization |
| 5.90 |
|
|
| 5.71 |
|
|
| 6.11 |
|
|
| 5.32 |
|
For the three months ended September 30, 2019 compared to the three months ended September 30, 2018
Net income of $5.2 million and net loss of $2.6 million were recorded for the three months ended September 30, 2019 and 2018, respectively.
Oil, natural gas and NGL revenues were $72.4 million and $85.4 million for the three months ended September 30, 2019 and 2018, respectively. Average net production volumes were approximately 28.8 MBoe/d and 25.4 MBoe/d for the three months ended September 30, 2019 and 2018, respectively. The change in production volumes was primarily due to the Merger. The average realized sales price was $27.37 per Boe and $36.56 per Boe for the three months ended September 30, 2019 and 2018, respectively. The decrease is primarily due to decreases in commodity prices.
Lease operating expense was $33.0 million and $27.5 million for the three months ended September 30, 2019 and 2018, respectively. The change in lease operating expense was primarily related to the Merger. On a per Boe basis, lease operating expense was $12.46 and $11.77 for the three months ended September 30, 2019 and 2018, respectively.
Gathering, processing and transportation was $4.5 million and $6.2 million for the three months ended September 30, 2019 and 2018, respectively. On a per Boe basis, gathering, processing and transportation was $1.68 and $2.65 for the three months ended September 30, 2019 and 2018, respectively.
Taxes other than income was $5.1 million and $4.7 million for the three months ended September 30, 2019 and 2018, respectively. On a per Boe basis, taxes other than income were $1.94 and $2.02 for the three months ended September 30, 2019 and 2018, respectively. The change in taxes other than income on a per MBoe basis was primarily due to a decrease in commodity prices.
DD&A expense was $15.6 million and $13.4 million for the three months ended September 30, 2019 and 2018, respectively. The change in DD&A expense is due to the Merger that closed August 6, 2019.
General and administrative expense was $27.0 million and $8.2 million for the three months ended September 30, 2019 and 2018, respectively. General and administrative expense for the three months ended September 30, 2019 included $12.8 million of acquisition costs. The Merger acquisition costs are non-recurring and are not expected to impact future expenses. Non-cash share-based compensation expense was $1.2 million and $1.6 million for the three months ended September 30, 2019 and 2018, respectively.
Net gains on commodity derivative instruments of $28.7 million were recognized for the three months ended September 30, 2019, consisting of $24.6 million increase in the fair value of open positions and $4.1 million of cash settlements paid on expired positions. Net losses on commodity derivative instruments of $21.1 million were recognized for the three months ended September 30, 2018, consisting of $20.5 million decrease in fair value of open positions and $0.6 million of cash settlements paid on expired 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 $5.3 million for the three months ended September 30, 2019 and 2018, respectively. Interest expense included gains on interest rate swaps of approximately $0.3 million for the three months ended September 30, 2019.
Loss on Lease of $4.2 million for the three months ended September 30, 2019, which relates to the Midstates corporate office lease. The office will be vacated by mid-November. Because excess sublease inventory in the local market, a liability has been accrued for rent and other operating expenses based upon the term and provisions of the lease.
Average outstanding borrowings under our New Revolving Credit Facility were $238.0 million for the three months ended September 30, 2019. Average outstanding borrowings under our Emergence Credit Facility were $306.7 million for the three months ended September 30, 2018.
Reorganization items, net represents costs and income directly associated with Legacy Amplify’s Chapter 11 proceedings since January 16, 2017, the petition date, such as advisor and professional fees. The Company incurred less than $0.1 million and $0.5 million for the three months ended September 30, 2019 and 2018, respectively. See Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements under “Item 1. Financial Statements” of this quarterly report for additional information.
For the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018
Net losses of $7.7 million and $24.6 million were recorded for the nine months ended September 30, 2019 and 2018, respectively.
Oil, natural gas and NGL revenues were $197.0 million and $264.2 million for the nine months ended September 30, 2019 and 2018, respectively. Average net production volumes were approximately 23.8 MBoe/d and 27.5 MBoe/d for the nine months ended September 30, 2019 and 2018, respectively. The change in production volumes was primarily 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 $30.30 per Boe and $35.19 per Boe for the nine months ended September 30, 2019 and 2018, respectively.
Lease operating expense was $88.2 million and $84.6 million for the nine months ended September 30, 2019 and 2018, respectively. The change in lease operating expense was primarily related to the Merger. On a per Boe basis, lease operating expense was $13.56 and $11.26 for the nine months ended September 30, 2019 and 2018, respectively.
Gathering, processing and transportation was $13.5 million and $17.8 million for the nine months ended September 30, 2019 and 2018, respectively. The change in gathering, processing and transportation was primarily the result of lower production. On a per Boe basis, gathering, processing and transportation was $2.08 and $2.37 for the nine months ended September 30, 2019 and 2018, respectively.
Exploration expense was less than $0.1 million and $3.0 million for the nine months ended September 30, 2019 and 2018, respectively. The change in exploration expense was primarily due to a $2.9 million expense associated with the early termination of a rig contract in East Texas during 2018.
Taxes other than income was $13.0 million and $15.3 million for the nine months ended September 30, 2019 and 2018, respectively. On a per Boe basis, taxes other than income were $2.00 and $2.04 for the nine months ended September 30, 2019 and 2018, respectively. The change in taxes other than income on a per MBoe basis was primarily due to a decrease in commodity prices.
DD&A expense was $39.7 million and $39.9 million for the nine months ended September 30, 2019 and 2018, respectively. The change in DD&A expense was primarily due to a decrease in production volumes, the Merger, which closed on August 6, 2019, and the South Texas Divestiture, which closed on May 30, 2018.
General and administrative expense was $46.9 million and $35.7 million for the nine months ended September 30, 2019 and 2018, respectively. General and administrative expense for the nine months ended September 30, 2019 included $16.7 million of acquisition cost. The Merger acquisition costs are non-recurring and are not expected to impact future expenses. Non-cash share-based compensation expense was $4.5 million and $3.1 million for the nine months ended September 30, 2019 and 2018, respectively. General and administrative expense included $7.5 million in severance payments to certain Legacy Amplify departing executives during the nine months ended September 30, 2018.
Net gains on commodity derivative instruments of $19.2 million were recognized for the nine months ended September 30, 2019, consisting of $17.0 million in the fair value of open positions and $2.2 million of cash settlements paid on expired positions. Net losses on commodity derivative instruments of $67.2 million were recognized for the nine months ended September 30, 2018, consisting of $6.3 million of cash settlement received on expired positions offset by a $73.5 million decrease in the fair value of open positions.
Loss on Lease of $4.2 million for the nine months ended September 30, 2019, which relates to the Midstates corporate office lease. The office will be vacated by mid-November. Because of excess sublease inventory in the local markets, a liability has been accrued for rent and other operating expenses based upon the term and provisions of the lease.
Interest expense, net was $13.8 million and $17.4 million for the nine months ended September 30, 2019 and 2018, respectively. The change in interest expense is primarily due to a $4.4 million reduction in interest expense due to lower outstanding borrowings for the nine months ended September 30, 2019. In addition we had gains of interest rate swaps of approximately $0.3 million and net change of $0.6 million in the amortization and write-off of deferred financing fees.
Average outstanding borrowings under our New Revolving Credit Facility were $258.3 million for the nine months ended September 30, 2019. Average outstanding borrowings under our Emergence Credit Facility were $334.8 million for the nine months ended September 30, 2018.
Reorganization items, net represents costs and income directly associated with Legacy Amplify’s Chapter 11 proceedings since January 16, 2017, the petition date, such as advisor and professional fees. The Company incurred $0.7 million and $1.8 million for the nine months ended September 30, 2019 and 2018, respectively. See Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements under “Item 1. Financial Statements” of this quarterly report for additional information.
Adjusted EBITDA
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;
Cash settlements received on expired commodity derivative instruments;
Losses on sale of assets;
Share/unit-based compensation expenses;
Exploration costs;
Acquisition and divestiture related expenses;
Restructuring related costs;
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 useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure.
Adjusted EBITDA should not be considered as an alternative to, or more 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 other 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 measure our ability to meet debt service requirements.
In addition, management uses Adjusted EBITDA to evaluate actual cash flow available to develop existing reserves or acquire additional oil and natural gas properties.
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)
| For the Three Months Ended |
|
| For the Nine Months Ended |
| ||||||||||
| September 30, |
|
| September 30, |
| ||||||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
| (In thousands) |
| |||||||||||||
Net income (loss) | $ | 5,157 |
|
| $ | (2,598 | ) |
| $ | (7,679 | ) |
| $ | (24,638 | ) |
Interest expense, net |
| 5,276 |
|
|
| 5,336 |
|
|
| 13,787 |
|
|
| 17,395 |
|
Income tax expense (benefit) |
| — |
|
|
| — |
|
|
| (50 | ) |
|
| — |
|
DD&A |
| 15,617 |
|
|
| 13,355 |
|
|
| 39,696 |
|
|
| 39,932 |
|
Accretion of AROs |
| 1,428 |
|
|
| 1,272 |
|
|
| 4,071 |
|
|
| 4,419 |
|
(Gains) losses on commodity derivative instruments |
| (28,725 | ) |
|
| 21,110 |
|
|
| (19,231 | ) |
|
| 67,218 |
|
Cash settlements received (paid) on expired commodity derivative instruments |
| 4,109 |
|
|
| (616 | ) |
|
| 2,201 |
|
|
| 6,287 |
|
(Gain) loss on sale of properties |
| — |
|
|
| (707 | ) |
|
| — |
|
|
| 1,439 |
|
Acquisition and divestiture related expenses |
| 12,833 |
|
|
| 82 |
|
|
| 16,655 |
|
|
| 969 |
|
Share-based compensation expense |
| 1,178 |
|
|
| 1,578 |
|
|
| 4,489 |
|
|
| 3,090 |
|
Exploration costs |
| 3 |
|
|
| 9 |
|
|
| 24 |
|
|
| 3,031 |
|
(Gain) loss on settlement of AROs |
| 224 |
|
|
| 639 |
|
|
| 401 |
|
|
| 529 |
|
Bad debt expense |
| 165 |
|
|
| — |
|
|
| 266 |
|
|
| — |
|
Reorganization items, net |
| 33 |
|
|
| 466 |
|
|
| 684 |
|
|
| 1,752 |
|
Severance payments |
| 6,389 |
|
|
| (258 | ) |
|
| 6,478 |
|
|
| 7,451 |
|
Non-cash loss on office lease |
| 4,237 |
|
|
| — |
|
|
| 4,237 |
|
|
| — |
|
Other |
| — |
|
|
| — |
|
|
| — |
|
|
| (105 | ) |
Adjusted EBITDA | $ | 27,924 |
|
| $ | 39,668 |
|
| $ | 66,029 |
|
| $ | 128,769 |
|
Reconciliation of Adjusted EBITDA to Net Cash from Operating Activities
| For the Three Months Ended |
|
| For the Nine Months Ended |
| ||||||||||
| September 30, |
|
| September 30, |
| ||||||||||
| 2019 |
|
| 2018 |
|
| 2019 |
|
| 2018 |
| ||||
| (In thousands) |
| |||||||||||||
Net cash provided by (used in) operating activities | $ | (7,411 | ) |
| $ | 32,335 |
|
| $ | 25,888 |
|
| $ | 116,610 |
|
Changes in working capital |
| 5,616 |
|
|
| 1,336 |
|
|
| (2,240 | ) |
|
| (17,214 | ) |
Interest expense, net |
| 5,276 |
|
|
| 5,336 |
|
|
| 13,787 |
|
|
| 17,395 |
|
Gain (loss) on interest rate swaps |
| (448 | ) |
|
| — |
|
|
| (932 | ) |
|
| — |
|
Cash settlements paid (received) on interest rate swaps |
| (113 | ) |
|
| — |
|
|
| (158 | ) |
|
| — |
|
Amortization and write-off of deferred financing fees |
| 512 |
|
|
| (497 | ) |
|
| (62 | ) |
|
| (2,249 | ) |
Acquisition and divestiture related expenses |
| 12,833 |
|
|
| 82 |
|
|
| 16,655 |
|
|
| 969 |
|
Income tax expense (benefit) - current portion |
| — |
|
|
| — |
|
|
| (50 | ) |
|
| — |
|
Exploration costs |
| 3 |
|
|
| 9 |
|
|
| 24 |
|
|
| 3,031 |
|
Plugging and abandonment cost |
| 278 |
|
|
| 859 |
|
|
| 660 |
|
|
| 1,129 |
|
Reorganization items, net |
| 33 |
|
|
| 466 |
|
|
| 684 |
|
|
| 1,752 |
|
Severance payments |
| 6,389 |
|
|
| (258 | ) |
|
| 6,478 |
|
|
| 7,451 |
|
Non-cash loss on office lease |
| 4,237 |
|
|
| — |
|
|
| 4,237 |
|
|
| — |
|
Other |
| 719 |
|
|
| — |
|
|
| 1,058 |
|
|
| (105 | ) |
Adjusted EBITDA | $ | 27,924 |
|
| $ | 39,668 |
|
| $ | 66,029 |
|
| $ | 128,769 |
|
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 and borrowings under our revolving credit facility. 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 Annual Report on Form 10-KNew 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 September 30, 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 $59.7 million for the yearnine months ended December 31, 2018. ThereSeptember 30, 2019, which were primarily related to accelerated capital cost for the Bairoil plant expansion, drilling, capital workovers and facilities located in the Rockies and Oklahoma.
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 September 30, 2019, we had working capital of $17.2 million primarily due to an accounts receivable of $32.6 million, prepaid expenses of $15.9 million and short-term derivatives of $20.7 million offset by the timing of accruals, which included accrued liabilities of $26.3 million and revenues payable of $26.8 million.
New Revolving Credit Facility. On November 2, 2018, OLLC as borrower, entered into the New Revolving Credit Facility (as amended and supplemented to date) with Bank of Montreal, as administrative agent. At September 30, 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 September 30, 2019, was $530.0 million.
As of September 30, 2019, we were in compliance with all the financial (current ratio and total leverage ratio) and other covenants associated with our New Revolving Credit Facility.
As of September 30, 2019, we had approximately $145.4 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 nine months ended September 30, 2019 and 2018, have been no changes toderived from our critical accounting policies other than discussed below.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.
Leases
We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. We capitalize operating and finance leases on our unaudited interim condensed consolidated balance sheets through a ROU asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term, and lease liabilities represent our obligation to make lease payments arising from the lease.
| For the Nine Months Ended |
| |||||
| September 30, |
| |||||
| 2019 |
|
| 2018 |
| ||
| (In thousands) |
| |||||
Net cash provided by operating activities | $ | 25,888 |
|
| $ | 116,610 |
|
Net cash provided by (used in) investing activities |
| 46,911 |
|
|
| (27,991 | ) |
Net cash provided by (used in) financing activities |
| (115,095 | ) |
|
| (82,824 | ) |
Operating leasesActivities. Key drivers of net operating cash flows are included in operating lease ROU assets,commodity prices, production volumes and operating lease liabilitiescosts. Net cash provided by operating activities was $25.9 million and $116.6 million for the nine months ended September 30, 2019 and 2018, respectively. Production volumes were approximately 23.8 MBoe/d and 27.5MBoe/d for the nine months ended September 30, 2019 and 2018, respectively. The average realized sales prices were $30.30 per Boe and $35.19 per Boe for the nine months ended September 30, 2019 and 2018, respectively. Lease operating expenses were $88.2 million and $84.6 million for the nine months ended September 30, 2019 and 2018, respectively. Gathering, processing and transportation was $13.5 million and $17.8 million for the nine months ended September 30, 2019 and 2018, respectively.
Investing Activities. Net cash provided by investing activities for the nine months ended September 30, 2019 was $46.9 million, of which $19.3 million was related to cash acquired from the Merger and offset by $63.0 million which was used for additions to oil and natural gas properties. Withdrawal of restricted investments was $90.0 million, which related to the Company receipt of $90.0 million from the Beta decommissioning trust account. See Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements under “Item 1. Financial Statements” of this quarterly report for additional information. Net cash used in investing activities for the nine months ended September 30, 2018 was $28.0 million, of which $46.0 million was used for additions to oil and natural gas properties and partially offset by $18.1 million in proceeds from the sale of oil and natural gas properties related to the South Texas Divestiture.
Financing Activities. The Company had net repayments of $16.0 million related to our New Revolving Credit Facility and $82.0 million under the Emergence Credit Facility for the nine months ended September 30, 2019 and 2018, respectively.
Upon closing of the Merger on August 6, 2019, Midstates’ existing reserve-based revolving credit facility was terminated and all remaining borrowings were repaid by the Company.
During the nine months ended September 30, 2019, the Company repurchased 1,942,546 shares of common stock at an average price of $5.95 for a total cost of approximately $13.3 million.
On August 6, 2019, our board of directors declared a dividend of $0.20 per share on our outstanding common stock, which was paid on September 18, 2019 to stockholders of record at the close of business on September 4, 2019.
Contractual Obligations
During the nine months ended September 30, 2019, there were no significant changes in our unaudited interim condensed consolidated balance sheets. Operating lease ROU assetscontractual obligations from those reported in the Legacy Amplify Form 10-K except for the New Revolving Credit Facility borrowings and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.repayments.
Off–Balance Sheet Arrangements
As of March 31,September 30, 2019, we had no leases classified as finance leases.off–balance sheet arrangements.
Recently Issued Accounting Pronouncements
NatureFor a discussion of Leases
In support of our operations, we lease certain office space, field offices, office equipment, compressors, other production equipment and fleet vehicles under cancelable and non-cancelable contracts. A more detailed description of our material lease types is included below.
Corporate and Field Offices
We enter into long-term contracts to lease corporate and field office space in support of company operations. These contracts are generally structured with an initial non-cancelable term of three to five years. To the extentrecent accounting pronouncements that our corporate and field office contracts include renewal options, we evaluate whether we are reasonably certain to exercise those options on a contract by contract basis based on expected future office space needs, market rental rates, drilling plans and other factors. We have further determined that our current corporate and field office leases represent operating leases.
Compressors
We rent compressors from third parties in order to facilitate the downstream movement of our production to market. Our compressor arrangements are typically structured with a non-cancelable primary term of one to twenty-four months and often continue thereafter on a month-to-month basis subject to termination by either party with thirty days’ notice. We have concluded that our compressor rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completionwill affect us, see Note 2 of the primary term, both parties have substantive rights to terminate the lease without incurring a significant penalty. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term.
To the extent that our compressor rental arrangements have a primary term of twelve-months or less, we have elected to apply the practical expedient for short-term leases. For those short-term compressor contracts, we do not apply the lease recognition requirements, and we recognize lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term. Refer to “Practical Expedients & Accounting Policy Elections” below for additional detail.
Other Production Equipment
We rent other production equipment from third party vendors to be used in our production operations. These arrangements are typically structured on a month-to-month basis subject to termination by either party with thirty days’ notice. We have concluded that we are not reasonably certain of executing the month-to-month renewal options beyond a twelve-month period based on the historical term for which we have used other production equipment, and, therefore, our other equipment agreements represent operating leases with a lease term up to twelve-months.
We have further elected to apply the practical expedient for short-term leases to our other production equipment contracts. Accordingly, we do not apply the lease recognition requirements to these contracts, and we recognize lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term. Refer to “Practical Expedients & Accounting Policy Elections” below for additional detail.
Fleet Vehicles
We execute fleet vehicle leases with a third-party vendor in support of our day-to-day drilling and production operations. Our vehicle leases are typically structured with a term of a minimum of 367 days for passenger and light duty vehicles and a minimum of 24 months for commercial vehicles and continue thereafter on a month-to-month basis subject to termination by either party within thirty days’ notice. We have concluded that our fleet vehicle leases represent operating leases.
Significant Judgments
Transportation, Gathering and Processing Arrangements
The Company is party to a gas purchase, gathering and processing contract in the Mississippian Lime region, which includes certain minimum NGLs volume commitments. To the extent the Company does not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLs, it would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee. The Company is currently delivering at least the minimum volumes required under these contractual provisions. However, decreased drilling activity could result in the inability to meet these commitments in the future.
As the Company does not utilize substantially all of the underlying pipeline, gathering system or processing facilities, we have concluded that those underlying assets do not meet the definition of an identified asset.
Discount Rate
Our leases typically do not provide an implicit rate, and thus, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the rate of interest that we would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. In order to determine our incremental borrowing rate, we utilized our current credit rating as well as best available market data, which includes public bond information for publicly traded upstream energy companies with similar credit ratings, to estimate our unsecured borrowing rate and applied adjustments to that rate to account for the effect of collateral.
The Company has determined the discount rate as of January 1, 2019 using end of day December 31, 2018 market data. This discount rate will be used at transition to ASC 842 as well as all new leases executed within 2019. The Company intends to update the discount rate annually thereafter on January 1 to be used for all new leases within the year (for example, the discount rate will be updated as of January 1, 2020 to be applied to all new leases in 2020). In the event a material lease is executed within a fiscal year or there have been material changes in the market that would impact the Company’s discount rate, the Company will evaluate whether an intra-year update of the discount rate is required.
Practical Expedients & Accounting Policy Elections
Certain of our lease agreements include lease and non-lease components. For all current asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component.
In addition, for all of our asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less, including renewal options expected to be exercised, and does not include an option to purchase the underlying asset that we are reasonably certain to exercise). Accordingly, we recognize lease payments related to our short-term leases in profit or loss on a straight-line basis over the lease term. To the extent that there are variable lease payments, we recognize those payments in profit or loss in the period in which the obligation for those payments is incurred. Refer to “Nature of Leases” above for further information regarding those asset classes that include material short-term leases.
Recent Accounting Pronouncements Adopted During The Period
In July 2017, the FASB issued ASU 2017-11, “Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815)”. ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“EPS”) in accordance with Topic 260 to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for us for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The adoption of ASU 2017-11 did not have a material impact on its financial position, results of operations or cash flows.
In June 2018, the FASB issued ASU 2018-07, “Compensation - Stock Compensation (Topic 718) — Improvements to Nonemployee Share-Based Payment Accounting”. ASU 2018-07 expands the scope of Topic 718 to include share-based payments issued to non-employees for goods and services. Consequently, the accounting for share-based payments to non-employees and employees will be substantially aligned. The new standard is effective for us for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The adoption of ASU 2018-07 did not have a material impact on its financial position, results of operations or cash flows.
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)”. ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. We adopted ASU 2016-02 using the modified retrospective transition approach. See “Part I. Financial Information — Item 1. Financial Statements Notes to the Unaudited Itermin Condensed Consolidated Financial Statements— Note 3. Impact included under “Item 1. Financial Statements” of ASU 842 Adoption”.this quarterly report for additional information.
Recent Accounting Pronouncements Issued But Not Yet Adopted
In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”. ASU 2016-13 replaces the incurred loss model with an expected loss model, which is referred to as the current expected credit loss (“CECL”) model. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to trade receivables. The ASU is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We are still performing our evaluation of Update 2016-13, but do not believe it will have a material impact on our consolidated financial statements at this time.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
WeIn the normal course of our business operations, we are exposed to a variety of marketcertain risks, including 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 the Legacy Amplify 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 risk, interest rate riskswaps and counterpartycostless collars only with lenders and customer risk. We address these risks through a programtheir affiliates under our Emergence Credit Facility and our New Revolving Credit Facility.
For additional information regarding the volumes of risk management includingour production covered by commodity derivative contracts and the useaverage prices at which production is hedged as of derivative instruments.
The primary objectiveSeptember 30, 2019, see Note 6 of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The disclosures are not meant to be precise indicators of expected future losses or gains, but rather indicators of reasonably possible losses or gains. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. These derivative instruments are discussed in “Part I. Financial Information — Item 1. Financial Statements — Notes to the Unaudited Interim Condensed Consolidated Financial Statements —included “Item 1. Financial Statements” of this quarterly report.
Interest Rate Risk
Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. See Note 5.6 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for interest rate swap arrangements that were outstanding at September 30, 2019.
Counterparty and Customer Credit Risk Management and Derivative Instruments.”
Commodity Price Exposure
We are exposedalso subject to marketcredit risk as the prices of oil, NGLs and natural gas fluctuate due to changes in supply and demand. To partially reduce price risk caused by these market fluctuations, we have hedged and in the long-term, expect to hedge, a significant portionconcentration of our future production.
We utilize derivative financial instruments to manage risks related to changes in oil and natural gas prices. At March 31, 2019, we utilized fixed price swapsreceivables 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 previous and three-way collarscurrent credit agreements are counterparties to reduceour 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 volatilityevent of oil and natural gas prices on a portiondefault by the counterparty. We have also entered into ISDA Agreements with each of our future expected production.
For derivative instruments recorded at fair value,counterparties. The terms of the credit standingISDA Agreements provide us and each of our counterparties is analyzed and factored intowith rights of set-off upon the fair value amounts recognized onoccurrence of defined acts of default by either us or our counterparty to a derivative, whereby the balance sheet.
The fair values of our commodity derivatives are largely determined by estimatesparty not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. Had all counterparties failed completely to perform according to the terms of the forward curves of the relevant price indices. At March 31, 2019, a 10% change in the forward curves associated with our commodity derivative instrumentsexisting contracts, we would have changed our net liability positions byhad the following amounts:
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| 10% Increase |
| 10% Decrease |
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| (in thousands) |
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Gain (loss): |
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Gas derivatives |
| $ | (1,093 | ) | $ | 1,090 |
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Oil derivatives |
| $ | (4,342 | ) | $ | 3,530 |
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Interest Rate Risk
At March 31, 2019, we had indebtednessright to offset $36.6 million against amounts outstanding under our RBLNew Revolving Credit Facility at September 30, 2019, reducing our maximum credit exposure to approximately $1.4 million of $59.1which $1.2 million which bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. Assuming the RBL is fully drawn, awas with one percent increase in interest rates for the three months ended March 31, 2019 would have resulted in a $1.7 million increase in annual interest cost, before capitalization.counterparty.
At March 31, 2019, we did not have any interest rate derivatives in place and have not historically utilized interest rate derivatives. In the future, we may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing or future debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
DuringAs required by Rules 13a-15(b) and 15d-15(b) of the period covered by this report,Exchange Act, we have evaluated, under the supervision and with the participation of our management, carried out an evaluation ofincluding the principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures pursuant to(as defined in Rules 13a-15(e) and 15d-15(e) and under the Exchange Act Rule 13a-15.Act) as of the end of the period covered by this quarterly report. Our disclosure controls and procedures are designed to ensureprovide reasonable assurance that the information required to be disclosed by us in the reports that we file withunder the SECExchange 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,SEC. Based upon the evaluation, the principal executive officer and that such information is accumulated and communicated to our management, including our President, Chief Executive Officer and Director and our Vice President and Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosures. Based on that evaluation, our President, Chief Executive Officer and Director and our Vice President and Chief Accounting Officerprincipal financial officer have concluded that as of March 31, 2019, theseour disclosure controls and procedures were effective and ensured thatat the information required to be disclosed in our reports filed with the SEC is recorded, processed, summarized and reported on a timely basis.reasonable assurance level as of September 30, 2019.
ChangesChange in Internal Control overOver Financial Reporting
There wereOn August 6, 2019, the Company completed the Merger. See Note 4. “Acquisitions and Divestitures” included in Part I. Item 1 of this Quarterly Report on Form 10-Q for a discussion of the Merger and related financial data. The Company is currently in the process of integrating Midstates into our internal controls over financial reporting. Except for the inclusion of Midstates, there has been no changeschange in our internal control over financial reporting that occurred during the third quarter ended March 31,of 2019 that havehas materially affected, or areis 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.
PART II - PART II—OTHER INFORMATION
From time to time, we are party to variousFor information regarding legal proceedings, arising in the ordinary course of business. Although we cannot predict the outcomes of any such legal proceedings, our management believes that the resolution of currently pending legal actions will not have a material adverse effect on our business, results of operations and financial condition. See “Part I. Financial Information — Itemsee Part I, “Item 1. Financial Statements,” Note 15, “Commitments and Contingencies — Litigation and Environmental” of the Notes to the Unaudited Interim Condensed Consolidated Financial Statements — Note 14. Commitments and Contingencies”,included in this quarterly report, which is incorporated in this itemherein by reference.
Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Reportquarterly 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 tofrom the risks describedrisk factors disclosed in Part I, Item 1A of our1A. Risk Factors in Legacy Amplify’s Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on March 14, 2019.10-K., which are incorporated herein by reference.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.Item Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information regarding the purchase ofsummarizes our common stock maderepurchase activity during the first quarter of 2019. Shares purchased represent the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory withholding requirements.three months ended September 30, 2019:
Period |
| Total Number of Shares |
| Average Price Paid |
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January 1, 2019 — January 31, 2019 |
| 18,634 |
| $ | 7.51 |
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February 1, 2019 — February 28, 2019 |
| 5,012,520 |
| $ | 10.00 |
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March 1, 2019 — March 31, 2019 |
| — |
| $ | — |
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Total |
| 5,031,154 |
| $ | 9.99 |
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Period |
| Total Number of Shares Purchased |
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| Average Price Paid per Share |
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| Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs |
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| Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (1) | |||
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Common Shares Repurchased (1) |
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July 1, 2019 - July 31, 2019 |
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| 8,802 |
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| $ | 5.22 |
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| — |
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| n/a |
August 1, 2019 - August 31, 2019 |
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| 11,740 |
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| $ | 5.43 |
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| — |
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| n/a |
September 1, 2019 -September 30, 2019 |
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| — |
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| $ | — |
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| — |
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| 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.
Exhibits included in this Quarterly Report are listed in the Exhibit Index and incorporated herein by reference.
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On November 5, 2019, David M. Dunn resigned from the board of directors (the “Board”) of the Company, effective November 7, 2019. Mr. Dunn served on the audit committee of the Board. There were no known disagreements between Mr. Dunn and the Company which led to Mr. Dunn’s resignation from the Board.
On November 5, 2019, Randal T. Klein, a current member of the Board, was appointed to the audit committee of the Board, effective November 7, 2019.
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Description | ||||
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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 | ||
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101.INS* |
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101.LAB* | — |
| XBRL Labels Linkbase Document | |
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101.PRE* | — |
| XBRL Presentation Linkbase | |
101.SCH* | — | XBRL Schema Document |
* | Filed |
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.
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(Registrant) | |||
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| By: | /s/ | |
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| Martyn Willsher | |
Title: | Senior Vice President and Chief Financial Officer | ||
Date: November 6, 2019 | By: | /s/ Denise DuBard | |
Name: | Denise DuBard | ||
Title: |
| Vice President and Chief Accounting Officer | |
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