10-K 1 ampy-10k_20171231.htm AMPY-10-K-12312017 ampy-10k_20171231.htm

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10–K

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2017

 

OR

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                      to                     .

 

Commission File Number: 001-35364

 

AMPLIFY ENERGY CORP.

(Exact name of registrant as specified in its charter)

 

Delaware

 

82-1326219

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

500 Dallas Street, Suite 1600, Houston, TX

 

77002

(Address of principal executive offices)

 

(Zip Code)

 

Registrant’s telephone number, including area code: (713) 490-8900

 

Securities registered pursuant to Section 12(b) of the Act: None

 

 

Securities registered pursuant to Section 12(g) of the Act: None

 

 

 

Indicate by check mark if the registrant is a well–known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes      No      

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes      No  

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes      No  

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes      No  

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K is not contained herein and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III or any amendment to the Form 10–K  

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 definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b–2 of the Exchange Act. Check one:

 Large accelerated filer

 

 

  

Accelerated filer

 

Non-accelerated filer

 

  (Do not check if a smaller reporting company)

  

Smaller reporting company

 

Emerging growth company

 

 

 

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)  Yes      No  

The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was approximately $250.0 million on June 30, 2017, based on $10.00 per share, the last reported sales price of the shares on the OTCQX U.S. Premier marketplace on such date.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 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  

As of March 2, 2018, the registrant had 25,000,000 outstanding shares of common stock, $0.0001 par value per share.

Documents Incorporated By Reference: None

 


AMPLIFY ENERGY CORP.

TABLE OF CONTENTS

 

 

 

 

  

Page

 

 

 

PART I

  

 

Item 1.

 

Business

  

9

Item 1A.

 

Risk Factors

  

30

Item 1B.

 

Unresolved Staff Comments

  

46

Item 2.

 

Properties

  

46

Item 3.

 

Legal Proceedings

  

46

Item 4.

 

Mine Safety Disclosures

  

46

 

 

 

PART II

  

 

Item 5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

  

47

Item 6.

 

Selected Financial Data

  

48

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

  

50

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

  

66

Item 8.

 

Financial Statements and Supplementary Data

  

68

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  

68

Item 9A.

 

Controls and Procedures

  

68

Item 9B.

 

Other Information

  

71

 

 

 

PART III

  

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

  

72

Item 11.

 

Executive Compensation

  

76

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

  

88

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

  

89

Item 14.

 

Principal Accountant Fees and Services

  

91

 

 

 

PART IV

  

 

Item 15.

 

Exhibits, Financial Statement Schedules

  

92

Item 16.

 

Form 10-K Summary

 

96

 

Signatures

  

97

 

 

 

 


GLOSSARY OF OIL AND NATURAL GAS TERMS

Analogous Reservoir: Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

API Gravity: A system of classifying oil based on its specific gravity, whereby the greater the gravity, the lighter the oil.

Basin: A large depression on the earth’s surface in which sediments accumulate.

Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bbl/d: One Bbl per day.

Bcfe: One billion cubic feet of natural gas equivalent.

Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

Boe/d: One Boe per day.

BOEM: Bureau of Ocean Energy Management.

BSEE: Bureau of Safety and Environmental Enforcement.

Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Deterministic Estimate: The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed Acreage: The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Project: A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Development Well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential: An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Dry Hole or Dry Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Economically Producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For this determination, the value of the products that generate revenue are determined at the terminal point of oil and natural gas producing activities.

Estimated Ultimate Recovery: Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

1


Exploratory Well: A well drilled to find and produce oil and natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have working interest.

ICE: Inter-Continental Exchange.

MBbl: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

Mcf: One thousand cubic feet of natural gas.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

MMcfe/d: One MMcfe per day.

Net Acres or Net Wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage.

Net Production: Production that is owned by us less royalties and production due others.

Net Revenue Interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate.

Operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

OPIS: Oil Price Information Service.

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 occurrences.

Productive Well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

2


Proved Reserves: Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration, unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves: Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Realized Price: The cash market price less all expected quality, transportation and demand adjustments.

Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reliable Technology: Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserve Life: A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year-end by production volumes. In our calculation of reserve life, production volumes are adjusted, if necessary, to reflect property acquisitions and dispositions.

Reserves: Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

3


Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the United States Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses and discounted at 10% per annum to reflect the timing of future net revenue. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in our oil and natural gas properties. Because our Predecessor was a limited partnership, it was generally not subject to federal or state income taxes and thus made no provision for federal or state income taxes in the calculation of standardized measure. Standardized measure does not give effect to derivative transactions.

Undeveloped Acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

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 generally 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.

4


NAMES OF ENTITIES

As used in this Form 10-K, unless we indicate otherwise:

 

“Amplify Energy” and “Successor” refer to Amplify Energy Corp., the successor reporting company of Memorial Production Partners LP, individually and collectively with its subsidiaries, as the context requires;

 

“Memorial Production Partners,” “MEMP,” and “Predecessor” refer to Memorial Production Partners LP, individually and collectively with its subsidiaries, as the context requires;

 

“Company,” “we,” “our,” “us” or like terms refer to Memorial Production Partners for the period prior to emergence from bankruptcy and to Amplify Energy for the period after emergence from bankruptcy;

 

“Predecessor’s general partner” and “MEMP GP” refer to Memorial Production Partners GP LLC, the Predecessor’s general partner and wholly owned subsidiary;

 

“OLLC” refers to Amplify Energy Operating LLC, formerly known as Memorial Production Operating LLC, our wholly owned subsidiary through which we operate our properties;

 

“Memorial Resource” refers to Memorial Resource Development Corp., the former owner of the Predecessor’s general partner, and its subsidiaries;

 

“MRD LLC” refers to Memorial Resource Development LLC, which is the predecessor of Memorial Resource;

 

“Cinco Group” refers to (i) certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies owned by: (a) Boaz Energy, LLC (“Boaz”), (b) Crown Energy Partners, LLC (“Crown”), (c) the Crown net profits overriding royalty interest and overriding royalty interest (“Crown NPI/ORRI”), (d) Propel Energy SPV LLC (“Propel SPV”), together with its wholly owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), (e) Stanolind Oil and Gas SPV LLC (“Stanolind SPV”), (f) Tanos Energy, LLC (“Tanos”), together with its wholly owned subsidiaries and (g) Prospect Energy, LLC (“Prospect”) and (ii) certain oil and natural gas properties in Jackson County, Texas (the “MRD Assets”) owned by Memorial Resource. MEMP acquired substantially all of the Cinco Group on October 1, 2013 from: (x) Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which were primarily owned by two of the Funds (defined below) and (y) MRD LLC;

 

“the previous owners” for accounting and financial reporting purposes refers collectively to: (a) certain oil and natural gas properties MEMP acquired from MRD LLC in April and May 2012 (“Tanos/Classic Properties”) for periods after common control commenced through their respective acquisition dates, (b) Rise Energy Operating, LLC and its wholly owned subsidiaries (except for Rise Energy Operating, Inc.) (“REO”) from February 3, 2009 (inception) through the date of acquisition, (c) certain oil and natural gas properties and related assets in East Texas and North Louisiana that MEMP acquired in March 2013 (the “WHT Properties”) owned by WHT Energy Partners LLC (“WHT”) from February 2, 2011 (inception) through the date of acquisition, (d) the Cinco Group and (e) certain oil and gas properties primarily located in the Joaquin Field in Shelby and Panola counties in East Texas and in Louisiana acquired from Memorial Resource in February 2015 (“Property Swap”) for periods after common control commenced through the date of acquisition;

 

“the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively controlled MRD Holdco LLC;

 

“Finance Corp.” refers to Memorial Production Finance Corporation, our Predecessor’s wholly owned subsidiary, whose activities were limited to co-issuing our Predecessor’s debt securities and engaging in other activities incidental thereto, which was dissolved following the effective date of the Plan (as defined in Note 2 of the Notes to the Consolidated and Combined Financial Statements under “Item 8. Financial Statements and Supplementary Data”);

 

“MRD Holdco” refers to MRD Holdco LLC, which together with a group controlled Memorial Resource; and

 

“NGP” refers to Natural Gas Partners.

 

5


FORWARD–LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

 

business strategies;

 

acquisition and disposition strategy;

 

cash flows and liquidity;

 

financial strategy;

 

ability to replace the reserves we produce through drilling;

 

drilling locations;

 

oil and natural gas reserves;

 

technology;

 

realized oil, natural gas and NGL prices;

 

production volumes;

 

lease operating expense;

 

gathering, processing and transportation;

 

general and administrative expense;

 

future operating results;

 

ability to procure drilling and production equipment;

 

ability to procure oil field labor;

 

planned capital expenditures and the availability of capital resources to fund capital expenditures;

 

ability to access capital markets;

 

marketing of oil, natural gas and NGLs;

 

acts of God, fires, earthquakes, storms, floods, other adverse weather conditions, war, acts of terrorism, military operations or national emergency;

 

expectations regarding general economic conditions;

 

impact of the Tax Cuts and Jobs Act of 2017;

 

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.

6


All statements, other than statements of historical fact, included in this report are forward-looking statements. These forward-looking statements may be found in “Item 1. Business,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this Annual Report on Form 10-K. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “outlook,” “continue,” the negative of such terms or other comparable terminology. These statements address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as projections of results of operations, plans for growth, goals, future capital expenditures, competitive strengths, references to future intentions and other such references. These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from those expressed or implied by forward-looking statements include, but are not limited to, the following risks and uncertainties:

 

our results of evaluation and implementation of strategic alternatives;

 

our inability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing, or otherwise;

 

our indebtedness and our ability to satisfy our debt obligations and a potential inability to effect deleveraging transactions or otherwise reduce those risks;

 

risks related to a redetermination of the borrowing base under our 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;

 

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 risks that may not be covered by an effective indemnity or insurance;

 

actions of third-party co-owners of interest in properties in which we also own an interest; and

 

other risks and uncertainties described in “Item 1A. Risk Factors.”

7


The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this report are not guarantees of future performance and we cannot assure any reader that such statements will be realized or that the events or circumstances described in any forward-looking statement will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in “Item 1A. Risk Factors” 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.

 

 

8


PART I

ITEM 1.

BUSINESS

References

When referring to Amplify Energy Corp. (also referred to as “Successor,” “Amplify Energy,” or the “Company”), the intent is to refer to Amplify Energy, a Delaware corporation, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Amplify Energy is the successor reporting company of Memorial Production Partners LP (“MEMP”) pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). When referring to “Predecessor” or the “Company” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to MEMP, the predecessor that was dissolved following the effective date of the Plan (as defined below) and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.

Overview

Amplify Energy is an independent oil and natural gas company that was formed on March 21, 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from December 2011 to May 2017. As discussed further in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 2 of the Notes to the Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data”, on January 16, 2017 (the “Petition Date”), MEMP and certain of its subsidiaries (collectively with MEMP, the “Debtors”) filed voluntary petitions (the cases commenced thereby, the “Chapter 11 proceedings”) under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code” or “Chapter 11”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”). The Debtors’ Chapter 11 proceedings were jointly administered under the caption In re Memorial Production Partners LP, et al. (Case No. 17-30262). During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective May 4, 2017 (the “Effective Date”).

We operate in one reportable segment engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment, as the economic environments are not different within the operation of our oil and natural gas properties. Our business activities are conducted through OLLC, our wholly owned subsidiary, and its wholly owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Wyoming and offshore Southern California. 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, 2017:

 

Our total estimated proved reserves were approximately 989.7 Bcfe, of which approximately 44% were oil and 71% were classified as proved developed reserves;

 

We produced from 2,547 gross (1,498 net) producing wells across our properties, with an average working interest of 59% and the Company is the operator of record of the properties containing 93% of our total estimated proved reserves; and

 

Our average net production for the three months ended December 31, 2017 was 184.3 MMcfe/d, implying a reserve-to-production ratio of approximately 15 years.

Recent Developments

Emergence from Voluntary Reorganization under Chapter 11

On April 14, 2017, the Bankruptcy Court entered an order (the “Confirmation Order”) approving the Second Amended Joint Plan of Reorganization of Memorial Production Partners LP and its affiliated Debtors, dated April 13, 2017 (as amended and supplemented, the “Plan”).

On the Effective Date, the Debtors satisfied the conditions to effectiveness of the Plan, the Plan became effective in accordance with its terms and the Company emerged from bankruptcy. Although the Company is no longer a debtor in possession, the Company was a debtor in possession from January 16, 2017 through May 4, 2017. As such, certain aspects of the Chapter 11 proceedings and related matters are described below in order to provide context to the Company’s financial condition and results of operations for the period presented.

Upon emergence from the Chapter 11 proceedings on May 4, 2017, we adopted fresh start accounting as required by GAAP. We met the requirements of fresh start accounting, which include: (i) the holders of the Predecessor’s voting common units immediately prior to the Effective Date received less than 50% of the voting shares of the Company and (ii) the reorganization value of our assets immediately prior to the Effective Date was less than the post-petition liabilities and allowed claims.

9


In accordance with the Plan, on the Effective Date:

 

The Successor issued (i) 25,000,000 new shares (the “New Common Shares”) of its common stock, par value $0.0001 per share (“common stock”); and (ii) warrants (the “Warrants”) to purchase up to 2,173,913 shares of the Company’s common stock exercisable for a five-year period commencing on the Effective Date entitling holders upon exercise thereof, on a pro rata basis, to 8% of the total issued and outstanding common shares (including common shares as of the Effective Date issuable upon full exercise of the Warrants, but excluding any common shares issuable under the Management Incentive Plan (the “MIP”)), at a per share exercise price of $42.60.

 

The holders of claims under the Predecessor’s revolving credit facility received a full recovery, consisting of a cash pay down and their pro rata share of the $1 billion exit senior secured reserve-based revolving credit facility (the “Credit Facility”), as further discussed in Note 10 of the Notes to the Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this annual report for additional information.

 

The 7.625% senior notes due May 2021 (“2021 Senior Notes”) and 6.875% senior notes due August 2022 (“2022 Senior Notes” and collectively, the “Notes”) were cancelled and the Predecessor’s liability thereunder discharged, and the holders of the Notes received (directly or indirectly) their pro rata share of New Common Shares representing, in the aggregate, 98% of the New Common Shares on the Effective Date (subject to dilution by the MIP and the common shares issuable upon exercise of the Warrants). Additionally, the holders of the Notes received their pro rata share of a $24.6 million cash distribution.

 

The Predecessor’s common units were cancelled, and each common unitholder received its pro rata share of: (i) 2% of the New Common Shares, (ii) the Warrants, and (iii) cash in an aggregate amount of approximately $1.3 million.

 

The holders of administrative expense claims, priority tax claims, other priority claims and general unsecured creditors of the Predecessor received in exchange for their claims payment in full in cash or otherwise had their rights unimpaired under Title 11 of the United States Code.

 

The Successor entered into a stockholders agreement with certain parties pursuant to which the Successor agreed to, at the direction of such stockholders, use commercially reasonable efforts to effect the sale of their common stock.

 

The Successor entered into a registration rights agreement with certain parties pursuant to which the Successor agreed to, among other things, file a registration statement with the SEC within 90 days of the receipt of a request from the stockholders party thereto covering the offer and resale of the common stock held by such stockholders.

 

The Company’s MIP became effective, such that an aggregate of 2,322,404 shares of the Company’s common stock became available for grant pursuant to awards under the MIP.

 

The term of the Predecessor’s general partner’s board of directors automatically expired on the Effective Date. The Successor formed a new seven-member board of directors consisting of the President and Chief Executive Officer, one director of the Predecessor, and five new members designated by certain parties to the plan support agreement.

Properties

We engaged Ryder Scott Company, L.P. (“Ryder Scott”), our independent reserve engineers, to audit our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2017. The following table summarizes information, based on a reserve report prepared by our internal reserve engineers and audited by Ryder Scott (which we refer to as our “reserve report”), about our proved oil and natural gas reserves by geographic region as of December 31, 2017 and our average net production for the three months ended December 31, 2017:

 

 

Estimated Net Proved Reserves

 

 

 

 

 

 

Average Net Production

 

 

Average

 

 

Producing Wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reserve

 

 

 

 

 

 

 

 

 

 

 

 

 

 

% Oil and

 

 

% Natural

 

 

% Proved

 

 

Standardized

 

 

 

 

 

 

% of

 

 

-to-Production

 

 

 

 

 

 

 

 

 

Region

Bcfe (1)

 

 

NGL

 

 

Gas

 

 

Developed

 

 

Measure (2)

 

 

MMcfe/d

 

 

Total

 

 

Ratio (3)

 

 

Gross

 

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(in millions)

 

 

 

 

 

 

 

 

 

 

(Years)

 

 

 

 

 

 

 

 

 

East Texas/Louisiana

 

460

 

 

25%

 

 

75%

 

 

69%

 

 

$

298

 

 

 

106.3

 

 

58%

 

 

 

11.9

 

 

 

1,616

 

 

 

905

 

Rockies

 

264

 

 

100%

 

 

0%

 

 

73%

 

 

 

142

 

 

 

27.0

 

 

15%

 

 

 

26.8

 

 

 

116

 

 

 

116

 

California

 

177

 

 

100%

 

 

0%

 

 

65%

 

 

 

254

 

 

 

25.4

 

 

13%

 

 

 

19.1

 

 

 

58

 

 

 

58

 

South Texas

 

89

 

 

32%

 

 

68%

 

 

90%

 

 

 

74

 

 

 

25.6

 

 

14%

 

 

 

9.5

 

 

 

757

 

 

 

419

 

Total

 

990

 

 

59%

 

 

41%

 

 

71%

 

 

$

768

 

 

 

184.3

 

 

100%

 

 

 

14.7

 

 

 

2,547

 

 

 

1,498

 

 

(1)

Determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(2)

Standardized measure is calculated in accordance with Accounting Standards Codification, or ASC, Topic 932, Extractive Activities—Oil and Gas, and is calculated using SEC pricing, before market differentials, of $51.34/Bbl for crude oil and NGLs and $2.98/MMBtu for natural gas.

(3)

The average reserve-to-production ratio is calculated by dividing estimated net proved reserves as of December 31, 2017 by the annualized average net production for the three months ended December 31, 2017.

10


Our Areas of Operation

East Texas/Louisiana

Approximately 47% of our estimated proved reserves as of December 31, 2017 and approximately 58% of our average daily net production for the three months ended December 31, 2017 were located in the East Texas/Louisiana region. Our East Texas/Louisiana properties include wells and properties primarily located in the Joaquin, Carthage, Willow Springs and East Henderson fields in East Texas. Those properties collectively contained 460.3 Bcfe of estimated net proved reserves as of December 31, 2017 based on our reserve report and generated average net production of 106.3 MMcfe/d for the three months ended December 31, 2017. In October 2017, we launched a divestiture process for our assets in the East Texas/Louisiana region.

Rockies

Approximately 27% of our estimated proved reserves as of December 31, 2017 and approximately 15.0% of our average daily net production for the three months ended December 31, 2017 were located in the Rockies region. Our Rockies properties include wells and properties primarily located in the Lost Soldier and Wertz fields in Wyoming at our Bairoil complex. Our Rockies properties contained 44.0 MMBbls of estimated net proved oil and NGLs reserves as of December 31, 2017 based on our reserve report and generated average net production of 27.0 MMcfe/d for the three months ended December 31, 2017. In October 2017, we launched a divestiture process for our assets in the Rockies region.

California

Approximately 18% of our estimated proved reserves as of December 31, 2017 and approximately 13% of our average daily net production for the three months ended December 31, 2017 were located offshore Southern California. These properties (the “Beta properties”) consist of: 100% of the working interests and currently an 87.6% average net revenue interest in three Pacific Outer Continental Shelf lease blocks (P-0300, P-0301 and P-0306), referred to as the Beta Unit, in the Beta Field located in federal waters approximately 11 miles offshore the Port of Long Beach, California. Our Beta properties contained 29.4 MMBbls of estimated net proved oil reserves as of December 31, 2017 based on our reserve report. Oil and gas is produced from the Beta Unit via two production platforms, referred to as the Ellen and Eureka platforms, equipped with permanent drilling rigs and associated equipment systems. On a third platform, Elly, the oil, water and gas are separated and the oil is prepared for sale, while the gas is burned as fuel for power and the water is recycled back into the reservoir for pressure maintenance. Sales quality oil is then pumped from the Elly platform to the Beta pump station located onshore at the Port of Long Beach, California via a 16-inch diameter oil pipeline, which extends approximately 17.5 miles. Amplify Energy’s wholly owned subsidiary, San Pedro Bay Pipeline Company, owns and operates the pipeline system.

Based on our reserve report, the Beta field contains more than 15% of our total estimated reserves. The following table summarizes production volumes from this field for the periods presented:

 

 

Period from

 

 

 

Period from

 

 

 

 

 

 

 

 

 

 

May 5, 2017

 

 

 

January 1, 2017

 

 

For the Year Ended

 

 

through

 

 

 

through

 

 

December 31,

 

 

December 31, 2017

 

 

 

May 4, 2017

 

 

2016

 

 

2015

 

Production Volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

1,022

 

 

 

 

486

 

 

 

1,445

 

 

 

860

 

Average net production (MBbls/d)

 

4.2

 

 

 

 

3.9

 

 

 

3.9

 

 

 

2.4

 

The increase in the production volumes between 2015 and the subsequent periods is primarily due to the acquisition of the remaining interests in our Beta properties from a third party.

Due to low oil and gas prices, the Beta leases were all granted royalty relief by the U.S. Department of Interior in July 2016. On our two primary producing leases, the royalty rate was reduced from 25% to 12.5%, and on our third lease, the royalty rate was reduced from 16.67% to 8.33%, for a weighted average of 12.4% overall. The royalty relief rates will apply to all hydrocarbon production up to 165,801 Boe per month. Monthly production above that level and up to 331,602 Boe per month will bear royalties at 1.5 times the original effective royalty rate. For monthly production above 331,602 Boe per month, the royalty rate will return to the original effective royalty rates. The royalty relief rates will also be suspended in months in which the trailing twelve-month weighted average NYMEX oil and Henry Hub gas price exceeds $55.16 per Boe which represents a 25% premium to the average realized price recognized by the Company during the qualification period. The royalty relief would end in the event that the Company generates no benefit from the royalty relief rates due to either higher production or realized pricing for 12 consecutive months.

11


South Texas

Approximately 9% of our estimated proved reserves as of December 31, 2016 and approximately 14% of our average daily net production for the three months ended December 31, 2017 were located in the South Texas region. Our South Texas properties include wells and properties in numerous fields located primarily in the Eagle Ford, Eagleville, NE Thompsonville, Laredo and East Seven Sisters fields. Our South Texas properties contained 88.6 Bcfe of estimated net proved reserves as of December 31, 2017 based on our reserve report. Those properties collectively generated average net production of 25.6 MMcfe/d for the three months ended December 31, 2017. In July 2017, we launched a divestiture process for our assets in the South Texas region.

Our Oil and Natural Gas Data

Our Reserves

Internal Controls. Our proved reserves were estimated at the well or unit level and audited for reporting purposes by Ryder Scott, our independent reserve engineers. The Company maintains internal evaluations of our reserves in a secure reserve engineering database. Ryder Scott interacts with the Company’s internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data for the reserves audit process. Reserves are reviewed and approved internally by our senior management on an annual basis and evaluated by our lender group on at least a semi-annual basis in connection with borrowing base redeterminations under our Credit Facility. Our reserve estimates are audited by Ryder Scott at least annually.

Our internal professional staff works closely with Ryder Scott to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve audit process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide Ryder Scott other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their audit of our reserves.

Qualifications of Responsible Technical Persons

Internal Engineers. Christa Yin is the technical person at the Company primarily responsible for overseeing the preparation of the reserves estimates and liasoning with and providing oversight of our third-party reserve engineers, which audited the internally prepared reserve report for our properties. Ms. Yin has been practicing petroleum engineering at the Company since March 2015 and has over 19 years of experience in the estimation and evaluation of reserves. From March 2014 to March 2015, she was employed by Tundra Oil and Gas, where she was responsible for analysis of acquisitions, generating development plans and managing reserves. From August 2011 to March 2014, she worked for HighMount Exploration & Production LLC as Manager of Acquisitions and Divestitures. From February 2005 to August 2011, Ms. Yin was employed by Tecpetrol, where she was responsible for generating development plans and managing and evaluating the reserves for the Gulf Coast region. From November 2003 to February 2005, Ms. Yin was employed by Marathon Oil Company where she was responsible for evaluating reserves and field development of various fields in Oklahoma. From June 1997 to November 2003, she held various positions which included the evaluation and estimation of reserves at Coastal Oil & Gas, which subsequently merged with El Paso Production Company. Ms. Yin is a graduate of Texas A&M University and holds a B.S. in petroleum engineering.

Ryder Scott Company, L.P. Ryder Scott is an independent oil and natural gas consulting firm. No director, officer, or key employee of Ryder Scott has any financial ownership in us or any of our affiliates. Ryder Scott’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported. Ryder Scott has not performed other work for us or any of our affiliates that would affect its objectivity. The audit of estimates of our proved reserves presented in the Ryder Scott reserve report were overseen by Timothy Wayne Smith.

Mr. Smith has been practicing consulting petroleum engineering at Ryder Scott since 2008. Before joining Ryder Scott, Mr. Smith served in a number of engineering positions with Wintershall Energy and Cities Service Oil Company. Mr. Smith is a Licensed Professional Engineer in the State of Texas with over 25 years of practical experience in the estimation and evaluation of petroleum reserves. He graduated from West Virginia University with a B.S. in petroleum engineering and from University of Phoenix with an M.B.A.

Mr. Smith meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

12


Estimated Proved Reserves

The following table presents the estimated net proved oil and natural gas reserves attributable to our properties and the standardized measure associated with the estimated proved reserves attributable to our properties as of December 31, 2017, based on our internally prepared reserve report audited by Ryder Scott, our independent reserve engineers. The standardized measure shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.

 

 

Reserves

 

 

Oil

 

 

Natural Gas

 

 

NGLs

 

 

Total

 

 

(MBbls)

 

 

(MMcf)

 

 

(MBbls)

 

 

(MMcfe) (1)

 

Estimated Proved Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed

 

50,014

 

 

 

299,481

 

 

 

17,982

 

 

 

707,459

 

Undeveloped

 

21,990

 

 

 

107,077

 

 

 

7,207

 

 

 

282,262

 

Total

 

72,004

 

 

 

406,558

 

 

 

25,189

 

 

 

989,721

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves as a percentage of total proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

71

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Standardized measure (in thousands) (2)

 

 

 

 

 

 

 

 

 

 

 

 

$

767,671

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and Natural Gas Prices (3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil – WTI per Bbl

 

 

 

 

 

 

 

 

 

 

 

 

$

51.34

 

Natural gas – Henry Hub per MMBtu

 

 

 

 

 

 

 

 

 

 

 

 

$

2.98

 

 

 

(1)

Determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

 

(2)

Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest expense, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to derivative transactions. For a description of our commodity derivative contracts, see “Item 1. Business—Operations—Derivative Activities” as well as “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commodity Derivative Contracts.”

 

(3)

Our estimated net proved reserves and related standardized measure were determined using 12-month trailing average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month in effect as of the date of the estimate, without giving effect to derivative contracts, held constant throughout the life of the properties. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For a discussion of risks associated with internal reserve estimates, see “Item 1A. Risk Factors — Risks Related to Our Business — Our estimated proved reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.”

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure shown above should not be construed as the current market value of our estimated oil and natural gas reserves. The 10% discount factor used to calculate standardized measure, which is required by the SEC and FASB, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Development of Proved Undeveloped Reserves

As of December 31, 2017, we had 282.3 Bcfe of proved undeveloped reserves comprised of 22.0 MMBbls of oil, 107.1 Bcfe of natural gas and 7 MMBbls of NGLs. None of our PUDs as of December 31, 2017 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as PUDs. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Changes in PUDs that occurred during 2017 were due to:

 

Upward performance and price revisions of 46 Bcfe;

 

Reclassifications of 20 Bcfe into proved developed reserves as wells are drilled, completed and turned to production; and

 

Reserve additions of 6 Bcfe.

13


Approximately 8% (20 Bcfe) of our PUDs recorded as of December 31, 2016 were developed during the twelve months ended December 31, 2017. Total costs incurred to develop these PUDs were approximately $30.5 million, of which $0.8 million was incurred in fiscal year 2016 and $29.7 million was incurred in fiscal year 2017. In total, we incurred total capital expenditures of approximately $41.5 million during fiscal year 2017 developing PUDs, which includes $11.7 million associated with PUDs to be completed in 2018. As we continue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in the upcoming years. Based on our current expectations of our cash flows, we believe that we can fund the drilling of our current PUD inventory and our expansions in the next five years from our cash flow from operations and borrowings under our Credit Facility. For a more detailed discussion of our liquidity position, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Production, Revenue and Price History

For a description of our and the previous owners’ combined historical production, revenues and average sales prices and per unit costs, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”

The following tables summarize our average net production, average unhedged sales prices by product and average production costs by geographic region for the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the years ended December 31, 2016 and 2015, respectively:

 

 

For the Period from May 5, 2017 through December 31, 2017 (Successor)

 

 

Oil

 

 

NGLs

 

 

Natural Gas

 

 

Total

 

 

 

 

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

Lease

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Operating

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Expense

 

 

(MBbls)

 

 

($/bbl)

 

 

(MBbls)

 

 

($/bbl)

 

 

(MMcf)

 

 

($/Mcf)

 

 

(MMcfe)

 

 

($/Mcfe)

 

 

($/Mcfe)

 

East Texas/Louisiana

 

163

 

 

$

50.31

 

 

 

811

 

 

$

22.40

 

 

 

18,402

 

 

$

3.06

 

 

 

24,240

 

 

$

3.41

 

 

$

0.65

 

Rockies

 

879

 

 

 

45.52

 

 

 

151

 

 

 

34.77

 

 

 

 

 

 

 

 

 

6,180

 

 

 

7.32

 

 

 

4.95

 

South Texas

 

316

 

 

 

50.88

 

 

 

152

 

 

 

22.37

 

 

 

3,483

 

 

 

2.84

 

 

 

6,297

 

 

 

4.67

 

 

 

1.17

 

California

 

1,022

 

 

 

46.81

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

6,133

 

 

 

7.80

 

 

 

3.38

 

Total

 

2,380

 

 

$

47.11

 

 

 

1,114

 

 

$

24.07

 

 

 

21,885

 

 

$

3.03

 

 

 

42,850

 

 

$

4.79

 

 

$

1.74

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average net production (MMcfe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

177.8

 

 

 

 

 

 

 

 

 

 

 

For the period from January 1, 2017 through May 4, 2017 (Predecessor)

 

 

Oil

 

 

NGLs

 

 

Natural Gas

 

 

Total

 

 

 

 

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

Lease

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Operating

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Expense

 

 

(MBbls)

 

 

($/bbl)

 

 

(MBbls)

 

 

($/bbl)

 

 

(MMcf)

 

 

($/Mcf)

 

 

(MMcfe)

 

 

($/Mcfe)

 

 

($/Mcfe)

 

East Texas/Louisiana

 

149

 

 

$

48.23

 

 

 

456

 

 

$

20.68

 

 

 

10,708

 

 

$

3.17

 

 

 

14,345

 

 

$

3.53

 

 

$

0.54

 

Rockies

 

440

 

 

 

46.34

 

 

 

86

 

 

 

37.10

 

 

 

 

 

 

 

 

 

3,155

 

 

 

7.48

 

 

 

5.04

 

South Texas

 

129

 

 

 

49.48

 

 

 

74

 

 

 

20.05

 

 

 

1,703

 

 

 

3.02

 

 

 

2,919

 

 

 

4.46

 

 

 

1.18

 

California

 

486

 

 

 

44.77

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2,917

 

 

 

7.46

 

 

 

2.88

 

Total

 

1,204

 

 

$

46.28

 

 

 

616

 

 

$

22.90

 

 

 

12,411

 

 

$

3.15

 

 

 

23,336

 

 

$

4.67

 

 

$

1.52

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average net production (MMcfe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

188.2

 

 

 

 

 

 

 

 

 

14


 

 

For the Year Ended December 31, 2016 (Predecessor)

 

 

Oil

 

 

NGLs

 

 

Natural Gas

 

 

Total

 

 

 

 

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

Lease

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Operating

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Expense

 

 

(MBbls)

 

 

($/bbl)

 

 

(MBbls)

 

 

($/bbl)

 

 

(MMcf)

 

 

($/Mcf)

 

 

(MMcfe)

 

 

($/Mcfe)

 

 

($/Mcfe)

 

East Texas/Louisiana

 

443

 

 

$

39.48

 

 

 

1,841

 

 

$

13.64

 

 

 

37,236

 

 

$

2.45

 

 

 

50,938

 

 

$

2.62

 

 

$

0.53

 

Rockies

 

1,399

 

 

 

37.94

 

 

 

202

 

 

 

22.02

 

 

 

1,612

 

 

 

1.73

 

 

 

11,217

 

 

 

5.38

 

 

 

4.45

 

South Texas

 

416

 

 

 

39.24

 

 

 

240

 

 

 

14.95

 

 

 

5,804

 

 

 

2.29

 

 

 

9,742

 

 

 

3.41

 

 

 

1.31

 

California

 

1,445

 

 

 

34.97

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8,672

 

 

 

5.83

 

 

 

3.62

 

Permian

 

180

 

 

 

33.39

 

 

 

 

 

 

 

 

 

124

 

 

 

2.54

 

 

 

1,204

 

 

 

5.25

 

 

 

4.10

 

Total

 

3,883

 

 

$

36.94

 

 

 

2,283

 

 

$

14.52

 

 

 

44,776

 

 

$

2.40

 

 

 

81,773

 

 

$

3.47

 

 

$

1.54

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average net production (MMcfe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

223.4

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31, 2015 (Predecessor)

 

 

Oil

 

 

NGLs

 

 

Natural Gas

 

 

Total

 

 

 

 

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

 

 

 

 

Average

 

 

Lease

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Production

 

 

Sales

 

 

Operating

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Volumes

 

 

Price

 

 

Expense

 

 

(MBbls)

 

 

($/bbl)

 

 

(MBbls)

 

 

($/bbl)

 

 

(MMcf)

 

 

($/Mcf)

 

 

(MMcfe)

 

 

($/Mcfe)

 

 

($/Mcfe)

 

East Texas/Louisiana

 

538

 

 

$

43.93

 

 

 

2,192

 

 

$

13.79

 

 

 

40,313

 

 

$

2.68

 

 

 

56,694

 

 

$

2.86

 

 

$

0.78

 

Rockies

 

1,657

 

 

 

43.44

 

 

 

366