Table of Contents

 

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 June 30, 20192020

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

 

45-369181682-1326219

(State or other jurisdiction of

(I.R.S. Employer

incorporation or organization)

 

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

321 South Boston Avenue, Suite 1000

 

 

Tulsa, Oklahoma500 Dallas Street, Suite 1700, Houston, TX

 

7410377002

(Address of principal executive offices)

 

(Zip Code)

 

Registrant’s telephone number, including area code: (918) 947-8550(713) 490-8900

 

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol

Name of each exchange on which registered

Common stock, $0.01 par value

MPO

New York Stock Exchange

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  o

Accelerated filer  x

Non-accelerated filer  o

Smaller reporting company  x

Emerging growth company o

 

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):

 

The number of shares outstanding of our stock at August 1, 2019 is shown below:

ClassTitle of each class

Trading Symbol(s)

NumberName of shares outstandingeach exchange on which registered

Common Stock

AMPY

NYSE

As of July 31, 2020, the registrant had 37,621,684 outstanding shares of common stock, $0.01 par value outstanding.


AMPLIFY ENERGY CORP.

Table of Contents

 

20,415,005

DOCUMENTS INCORPORATED BY REFERENCE

None.


Table of Contents

MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2019

TABLE OF CONTENTS

Page

 

 

 

Glossary of Oil and Natural Gas Terms

 

3

 

 

 

PART I — FINANCIAL INFORMATION

 

Glossary of Oil and Natural Gas Terms

1

Names of Entities

4

Cautionary Note Regarding Forward-Looking Statements

5

PART I—FINANCIAL INFORMATION

 

 

Item 1.

Financial Statements

 

 

Condensed Consolidated Balance Sheets at June 30, 2019 and December 31, 2018 (unaudited)

 

4

Unaudited Condensed Consolidated StatementsBalance Sheets as of Operations for the Three and Six Months Ended June 30, 20192020 and 2018  (unaudited)December 31, 2019

5

Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three and Six Months Ended June 30, 2019  and 2018 (unaudited)

6

Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2019 and 2018 (unaudited)

7

Notes to the Unaudited Interim Condensed Consolidated Financial Statements

 

8

 

 

Unaudited Condensed Statements of Consolidated Operations for the Three and Six Months Ended June 30, 2020 and 2019

9

Item 2. Management’s DiscussionUnaudited Condensed Statements of Consolidated Cash Flows for the Six Months Ended June 30, 2020 and Analysis2019

10

Unaudited Condensed Statements of Consolidated Equity for the Three and Six Months Ended June 30, 2020 and 2019

11

Notes to Unaudited Condensed Consolidated Financial Statements

12

Note 1 – Organization and Basis of Presentation

12

Note 2 – Summary of Significant Accounting Policies

14

Note 3 – Revenue

15

Note 4 – Acquisitions and Divestitures

15

Note 5 – Fair Value Measurements of Financial ConditionInstruments

16

Note 6 – Risk Management and ResultsDerivative Instruments

18

Note 7 – Asset Retirement Obligations

20

Note 8 – Long-term Debt

21

Note 9 – Equity (Deficit)

22

Note 10 – Earnings per Share

23

Note 11 – Long-Term Incentive Plans

23

Note 12 – Leases

25

Note 13 -Supplemental Disclosures to the Unaudited Condensed Consolidated Balance Sheets and Unaudited Condensed Statements of OperationsConsolidated Cash Flows

 

26

 

 

Note 14 – Related Party Transactions

27

Note 15 – Commitments and Contingencies

27

Note 16 – Income Taxes

28

Item 2.

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

29

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

37

Item 4.

Controls and Procedures

 

38

 

 

PART II—OTHER INFORMATION

 

Item 4. Controls and Procedures1.

Legal Proceedings

 

39

Item 1A.

 

PART II — OTHER INFORMATIONRisk Factors

 

39

Item 1. Legal Proceedings2.

Unregistered Sales of Equity Securities and Use of Proceeds

40

Item 3.

Defaults Upon Senior Securities

40

Item 4.

Mine Safety Disclosures

40

Item 5.

Other Information

40

Item 6.

Exhibits

 

40

 

 

 

Item 1A. Risk FactorsSignatures

40

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

40

Item 3. Defaults Upon Senior Securities

40

Item 4. Mine Safety Disclosures

40

Item 5. Other Information

40

Item 6. Exhibits

40

EXHIBIT INDEX

41

SIGNATURES

 

42

i


GLOSSARY OF OIL AND NATURAL GAS TERMS

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

Bbl:Bbl: 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.

Boe:  Barrels of oil equivalent, with 6,000Bcfe: 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.

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.

Exploratory well:Exploitation: 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.

MBoe: One thousand barrels of oil equivalent.

MBoe/d: One thousand barrels of oil equivalent per day.

MMBoe: One million barrels of oil equivalent.

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.

MMBtu:  One million British thermal units.Net Production: Production that is owned by us less royalties and production due to others.

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


NYMEX:  TheNYMEX: 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.

Reasonable certainty:  A high degreeReliable Technology: 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.

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

 


Spud or Spudding:  The commencement of drilling operations of a new well.NAMES OF ENTITIES

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

“Amplify Energy,” “Company,” “we,” “our,” “us” or like 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 Memorial Production Partners LP;

“Midstates” refers to Midstates Petroleum Company, Inc., which, on the effective date of the Merger (as defined below), changed its name to “Amplify Energy Corp.”; and

“OLLC” refers to Amplify Energy Operating LLC, our wholly owned subsidiary through which we operate our properties.

 


Wellbore:  The hole drilledCAUTIONARY NOTE REGARDING FORWARD–LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and section 21E of the Securities Exchange Act of 1934, as amended, that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

business strategies;

acquisition and disposition strategy;

cash flows and liquidity;

financial strategy;

ability to replace the reserves we produce through drilling;

drilling locations;

oil and natural gas reserves;

technology;

realized oil, natural gas and NGL prices;

production volumes;

lease operating expense;

gathering, processing, and transportation;

general and administrative expense;

future operating results;

ability to procure drilling and production equipment;

ability to procure oil field labor;

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

ability to access capital markets;

marketing of oil, natural gas and NGLs;

risks relating to transportation and storage capacity constraints;

risks relating to production curtailment;

a sustained decrease or further decline in the demand for oil and natural gas;

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

the occurrence or threat of epidemic or pandemic diseases, such as the recent outbreak of a novel strain of coronavirus (“COVID-19”), or any government response to such occurrence or threat;

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 bitnegative of such terms or other comparable terminology. These statements address activities, events or developments that is equippedwe expect or anticipate will or may occur in the future, including things such as projections of results of operations, plans for oilgrowth, 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 gas production on a completed well. Also called wellfinancial condition to differ materially from those expressed or borehole.

Working interest:  The right grantedimplied by forward-looking statements include, but are not limited to, the lesseefollowing 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 risks that may not be covered by an effective indemnity or insurance; and

actions of third-party co-owners of interests in properties in which we also own an interest.


The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events or circumstances described in any forward-looking statement will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in “Part I—Item 1A. Risk Factors” of Amplify’s Annual Report on Form 10-K for the year ended December 31, 2019 filed with the Securities and Exchange Commission (the “SEC”) on March 5, 2020 (“Amplify Form 10-K”). 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 propertyresult of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to explore for and to produce and own oil, natural gas,us or other minerals. The working interest owners bear the exploration, development, and operating costspersons acting on a cash, penalty, or carried basis.our behalf.


PART I — I—FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS.

AMPLIFY ENERGY CORP.

MIDSTATES PETROLEUM COMPANY, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)outstanding shares)

 

 

 

June 30, 2019

 

December 31, 2018

 

ASSETS

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

 

$

4,797

 

$

11,341

 

Accounts receivable:

 

 

 

 

 

Oil and gas sales

 

11,920

 

22,165

 

Joint interest billing

 

2,099

 

2,474

 

Other

 

340

 

1,374

 

Commodity derivative contracts

 

1,659

 

6,940

 

Other current assets

 

1,909

 

1,684

 

Total current assets

 

22,724

 

45,978

 

PROPERTY AND EQUIPMENT:

 

 

 

 

 

Oil and gas properties, on the basis of full-cost accounting

 

 

 

 

 

Proved properties

 

827,638

 

809,272

 

Unproved properties not being amortized

 

1,912

 

4,050

 

Other property and equipment

 

6,280

 

6,345

 

Less accumulated depreciation, depletion, amortization and impairment

 

(331,904

)

(266,198

)

Net property and equipment

 

503,926

 

553,469

 

OTHER NONCURRENT ASSETS

 

 

 

 

 

Commodity derivative contracts

 

108

 

791

 

Right-of-use lease assets

 

4,437

 

 

Other noncurrent assets

 

5,435

 

5,257

 

Total other noncurrent assets

 

9,980

 

6,048

 

TOTAL

 

$

536,630

 

$

605,495

 

LIABILITIES AND EQUITY

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable

 

$

4,061

 

$

6,511

 

Accrued liabilities

 

20,649

 

25,521

 

Commodity derivative contracts

 

329

 

 

Lease liabilities

 

1,180

 

 

Total current liabilities

 

26,219

 

32,032

 

LONG-TERM LIABILITIES:

 

 

 

 

 

Asset retirement obligations

 

8,404

 

8,087

 

Commodity derivative contracts

 

 

80

 

Long-term debt

 

60,559

 

23,059

 

Long-term lease liabilities

 

3,887

 

 

Other long-term liabilities

 

 

560

 

Total long-term liabilities

 

72,850

 

31,786

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (Note 15)

 

 

 

 

 

 

 

 

 

 

 

STOCKHOLDERS’ EQUITY:

 

 

 

 

 

Preferred stock, $0.01 par value, 50,000,000 shares authorized; no shares issued or outstanding at June 30, 2019 and December 31, 2018

 

 

 

Warrants, 6,979,609 and 6,625,554 warrants outstanding at June 30, 2019 and December 31, 2018

 

37,329

 

37,329

 

Common stock, $0.01 par value, 250,000,000 shares authorized; 20,620,866 shares issued and 20,415,005 shares outstanding at June 30, 2019; 25,520,170 shares issued and 25,345,981 shares outstanding at December 31, 2018

 

206

 

255

 

Treasury stock

 

(2,723

)

(2,455

)

Additional paid-in-capital

 

482,867

 

531,911

 

Retained deficit

 

(80,118

)

(25,363

)

Total stockholders’ equity

 

437,561

 

541,677

 

TOTAL

 

$

536,630

 

$

605,495

 

 

June 30,

 

 

December 31,

 

 

2020

 

 

2019

 

ASSETS

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

$

13,202

 

 

$

 

Restricted cash

 

 

 

 

325

 

Accounts receivable, net

 

27,132

 

 

 

33,145

 

Short-term derivative instruments

 

32,216

 

 

 

5,879

 

Prepaid expenses and other current assets

 

12,223

 

 

 

13,238

 

Total current assets

 

84,773

 

 

 

52,587

 

Property and equipment, at cost:

 

 

 

 

 

 

 

Oil and natural gas properties, successful efforts method

 

767,823

 

 

 

797,005

 

Support equipment and facilities

 

142,437

 

 

 

140,023

 

Other

 

8,765

 

 

 

8,045

 

Accumulated depreciation, depletion and impairment

 

(570,237

)

 

 

(141,350

)

Property and equipment, net

 

348,788

 

 

 

803,723

 

Long-term derivative instruments

 

9,134

 

 

 

6,364

 

Restricted investments

 

4,622

 

 

 

4,622

 

Operating lease - long term right-of-use asset

 

3,528

 

 

 

4,406

 

Other long-term assets

 

2,838

 

 

 

5,837

 

Total assets

$

453,683

 

 

$

877,539

 

 

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

Accounts payable

$

5,630

 

 

$

8,310

 

Revenues payable

 

22,542

 

 

 

29,167

 

Accrued liabilities (see Note 13)

 

17,837

 

 

 

23,358

 

Short-term derivative instruments

 

785

 

 

 

253

 

Current portion of long-term debt (see Note 8)

 

20,000

 

 

 

 

Total current liabilities

 

66,794

 

 

 

61,088

 

Long-term debt (see Note 8)

 

265,516

 

 

 

285,000

 

Asset retirement obligations

 

93,568

 

 

 

90,466

 

Long-term derivative instruments

 

1,833

 

 

 

305

 

Operating lease liability

 

1,350

 

 

 

2,720

 

Other long-term liabilities

 

3,367

 

 

 

3,753

 

Total liabilities

 

432,428

 

 

 

443,332

 

Commitments and contingencies (see Note 15)

 

 

 

 

 

 

 

Stockholders' equity:

 

 

 

 

 

 

 

Preferred stock, $0.01 par value: 50,000,000 shares authorized; 0 shares issued and outstanding at June 30, 2020 and December 31, 2019, respectively

 

 

 

 

 

Warrants, 2,173,913 and 9,153,522 warrants issued and outstanding at June 30, 2020 and December 31, 2019, respectively

 

4,788

 

 

 

4,790

 

Common stock, $0.01 par value: 250,000,000 shares authorized; 37,612,914 and 37,566,540 shares issued and outstanding at June 30, 2020 and December 31, 2019, respectively

 

209

 

 

 

209

 

Additional paid-in capital

 

423,770

 

 

 

424,399

 

Accumulated earnings

 

(407,512

)

 

 

4,809

 

Total stockholders' equity

 

21,255

 

 

 

434,207

 

Total liabilities and equity

$

453,683

 

 

$

877,539

 

 

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
Ended June 30,

 

For the Six Months
Ended June 30,

 

 

 

2019

 

2018

 

2019

 

2018

 

REVENUES:

 

 

 

 

 

 

 

 

 

Oil sales

 

$

14,554

 

$

34,202

 

$

30,881

 

$

66,616

 

Natural gas liquids sales

 

4,976

 

11,893

 

11,192

 

22,931

 

Natural gas sales

 

3,168

 

6,782

 

9,778

 

15,119

 

Other revenue

 

542

 

795

 

1,230

 

1,850

 

Total revenues from contracts with customers

 

23,240

 

53,672

 

53,081

 

106,516

 

Gains (losses) on commodity derivative contracts—net

 

2,541

 

(11,348

)

(5,191

)

(15,287

)

Total revenues

 

25,781

 

42,324

 

47,890

 

91,229

 

EXPENSES:

 

 

 

 

 

 

 

 

 

Lease operating and workover

 

9,911

 

16,952

 

18,901

 

31,760

 

Gathering and transportation

 

63

 

67

 

82

 

124

 

Severance and other taxes

 

1,572

 

2,776

 

3,505

 

5,638

 

Asset retirement accretion

 

160

 

250

 

317

 

547

 

Depreciation, depletion, and amortization

 

10,873

 

16,484

 

22,667

 

31,697

 

Impairment in carrying value of oil and gas properties

 

33,557

 

 

43,210

 

 

General and administrative

 

5,238

 

5,190

 

11,676

 

15,047

 

Advisory fees

 

 

850

 

 

850

 

Total expenses

 

61,374

 

42,569

 

100,358

 

85,663

 

OPERATING INCOME (LOSS)

 

(35,593

)

(245

)

(52,468

)

5,566

 

OTHER EXPENSE:

 

 

 

 

 

 

 

 

 

Interest income

 

4

 

5

 

9

 

24

 

Interest expense—net of amounts capitalized

 

(1,359

)

(1,302

)

(2,296

)

(3,129

)

Total other expense

 

(1,355

)

(1,297

)

(2,287

)

(3,105

)

INCOME (LOSS) BEFORE TAXES

 

(36,948

)

(1,542

)

(54,755

)

2,461

 

Income tax expense

 

 

 

 

 

NET INCOME (LOSS)

 

$

(36,948

)

$

(1,542

)

$

(54,755

)

$

2,461

 

Participating securities—non-vested restricted stock

 

 

 

 

(68

)

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS

 

$

(36,948

)

$

(1,542

)

$

(54,755

)

$

2,393

 

Basic and diluted net income (loss) per share attributable to common shareholders

 

$

(1.80

)

$

(0.06

)

$

(2.53

)

$

0.09

 

Basic and diluted weighted average number of common shares outstanding (Note 13)

 

20,512

 

25,332

 

21,668

 

25,316

 

 

For the Three Months Ended

 

 

For the Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

$

34,888

 

 

$

59,485

 

 

$

92,675

 

 

$

124,552

 

Other revenues

 

283

 

 

 

47

 

 

 

632

 

 

 

135

 

Total revenues

 

35,171

 

 

 

59,532

 

 

 

93,307

 

 

 

124,687

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

 

27,828

 

 

 

26,292

 

 

 

63,551

 

 

 

55,202

 

Gathering, processing and transportation

 

4,689

 

 

 

4,391

 

 

 

9,742

 

 

 

9,048

 

Exploration

 

3

 

 

 

6

 

 

 

19

 

 

 

21

 

Taxes other than income

 

2,195

 

 

 

3,464

 

 

 

6,181

 

 

 

7,873

 

Depreciation, depletion and amortization

 

7,623

 

 

 

12,913

 

 

 

23,179

 

 

 

24,079

 

Impairment expense

 

 

 

 

 

 

 

455,031

 

 

 

 

General and administrative expense

 

6,755

 

 

 

10,566

 

 

 

15,108

 

 

 

19,874

 

Accretion of asset retirement obligations

 

1,539

 

 

 

1,332

 

 

 

3,052

 

 

 

2,643

 

(Gain) loss on commodity derivative instruments

 

19,165

 

 

 

(22,993

)

 

 

(88,548

)

 

 

9,494

 

Other, net

 

 

 

 

34

 

 

 

 

 

 

177

 

Total costs and expenses

 

69,797

 

 

 

36,005

 

 

 

487,315

 

 

 

128,411

 

Operating income (loss)

 

(34,626

)

 

 

23,527

 

 

 

(394,008

)

 

 

(3,724

)

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

(6,209

)

 

 

(4,422

)

 

 

(13,856

)

 

 

(8,511

)

Other income (expense)

 

(250

)

 

 

 

 

 

(234

)

 

 

 

Total other income (expense)

 

(6,459

)

 

 

(4,422

)

 

 

(14,090

)

 

 

(8,511

)

Income (loss) before reorganization items, net and income taxes

 

(41,085

)

 

 

19,105

 

 

 

(408,098

)

 

 

(12,235

)

Reorganization items, net

 

(166

)

 

 

(464

)

 

 

(352

)

 

 

(651

)

Income tax benefit (expense)

 

(85

)

 

 

 

 

 

(85

)

 

 

50

 

Net income (loss)

 

(41,336

)

 

 

18,641

 

 

 

(408,535

)

 

 

(12,836

)

Net (income) loss allocated to participating restricted stockholders

 

 

 

 

(728

)

 

 

 

 

 

 

Net income (loss) attributable to common stockholders

$

(41,336

)

 

$

17,913

 

 

$

(408,535

)

 

$

(12,836

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings per share: (See Note 10)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted earnings per share

$

(1.10

)

 

$

0.80

 

 

$

(10.87

)

 

$

(0.58

)

Weighted average common shares outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted

 

37,595

 

 

 

22,267

 

 

 

37,582

 

 

 

22,223

 

 

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
Preferred
Stock

 

Common
Stock

 

Warrants

 

Treasury
Stock

 

Additional
Paid-in-Capital

 

Retained
Deficit

 

Total
Stockholders’
Equity

 

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

 

Share-based compensation

 

 

 

 

 

966

 

 

966

 

Acquisition of treasury stock

 

 

 

 

(6

)

 

 

(6

)

Net loss

 

 

 

 

 

 

(36,948

)

(36,948

)

Balance as of June 30, 2019

 

$

 

$

206

 

$

37,329

 

$

(2,723

)

$

482,867

 

$

(80,118

)

$

437,561

 

 

 

Series A
Preferred
Stock

 

Common
Stock

 

Warrants

 

Treasury
Stock

 

Additional
Paid-in-Capital

 

Retained
Deficit

 

Total
Stockholders’
Equity

 

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

 

 

 

 

 

 

4,003

 

4,003

 

Balance as of March 31, 2018

 

$

 

$

254

 

$

37,329

 

$

(2,062

)

$

527,550

 

$

(71,144

)

$

491,927

 

Share-based compensation

 

 

 

 

 

1,625

 

 

1,625

 

Acquisition of treasury stock

 

 

 

 

(19

)

 

 

(19

)

Net loss

 

 

 

 

 

 

(1,542

)

(1,542

)

Balance as of June 30, 2018

 

$

 

$

254

 

$

37,329

 

$

(2,081

)

$

529,175

 

$

(72,686

)

$

491,991

 

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 Six Months Ended June 30,

 

 

 

2019

 

2018

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

Net income (loss)

 

$

(54,755

)

$

2,461

 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

Losses on commodity derivative contracts—net

 

5,191

 

15,287

 

Net cash received (paid) for commodity derivative contracts not designated as hedging instruments

 

1,022

 

(3,677

)

Asset retirement accretion

 

317

 

547

 

Depreciation, depletion, and amortization

 

22,667

 

31,697

 

Impairment in carrying value of oil and gas properties

 

43,210

 

 

Share-based compensation, net of amounts capitalized to oil and gas properties

 

1,880

 

3,425

 

Amortization of deferred financing costs

 

348

 

216

 

Change in operating assets and liabilities:

 

 

 

 

 

Accounts receivable—oil and gas sales

 

7,670

 

1,437

 

Accounts receivable—JIB and other

 

1,834

 

(1,713

)

Other current and noncurrent assets

 

(750

)

(754

)

Accounts payable

 

1,487

 

2,301

 

Accrued liabilities

 

(4,803

)

(1,921

)

Other

 

 

(14

)

Net cash provided by operating activities

 

$

25,318

 

$

49,292

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Investment in property and equipment

 

$

(19,094

)

$

(65,843

)

Proceeds from the sale of oil and gas properties

 

 

54,432

 

Proceeds from the sale of oil and gas equipment

 

 

355

 

Net cash used in investing activities

 

$

(19,094

)

$

(11,056

)

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Repayment of revolving credit facility

 

$

(3,000

)

$

(100,000

)

Proceeds from revolving credit facility

 

40,500

 

 

Repurchase of restricted stock for tax withholdings

 

(268

)

(478

)

Common stock repurchased and retired

 

(50,000

)

 

Net cash used in financing activities

 

$

(12,768

)

$

(100,478

)

NET DECREASE IN CASH AND CASH EQUIVALENTS

 

$

(6,544

)

$

(62,242

)

Cash and cash equivalents, beginning of period

 

$

11,341

 

$

68,498

 

Cash and cash equivalents, end of period

 

$

4,797

 

$

6,256

 

 

 

 

 

 

 

SUPPLEMENTAL INFORMATION:

 

 

 

 

 

Non-cash transactions — investments in property and equipment accrued — not paid

 

$

4,712

 

$

23,219

 

Cash paid for interest, net of capitalized interest of $0.1 million and $0.2 million, respectively

 

$

1,885

 

$

3,010

 

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.


AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(In thousands)

 

For the Six Months Ended

 

 

June 30,

 

 

2020

 

 

2019

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income (loss)

$

(408,535

)

 

$

(12,836

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

23,179

 

 

 

24,079

 

Impairment expense

 

455,031

 

 

 

 

(Gain) loss on derivative instruments

 

(84,494

)

 

 

10,028

 

Cash settlements (paid) received on expired derivative instruments

 

39,471

 

 

 

(1,863

)

Cash settlements (paid) received on terminated derivative instruments

 

17,977

 

 

 

 

Bad debt expense

 

252

 

 

 

101

 

Amortization and write-off of deferred financing costs

 

2,999

 

 

 

574

 

Accretion of asset retirement obligations

 

3,052

 

 

 

2,643

 

Share-based compensation (see Note 11)

 

(632

)

 

 

2,922

 

Settlement of asset retirement obligations

 

 

 

 

(205

)

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Accounts receivable

 

5,762

 

 

 

6,576

 

Prepaid expenses and other assets

 

659

 

 

 

(2,630

)

Payables and accrued liabilities

 

(11,345

)

 

 

3,823

 

Other

 

(387

)

 

 

87

 

Net cash provided by operating activities

 

42,989

 

 

 

33,299

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Additions to oil and gas properties

 

(26,123

)

 

 

(33,232

)

Additions to other property and equipment

 

(719

)

 

 

(205

)

Additions to restricted investments

 

 

 

 

(138

)

Withdrawals of restricted investments

 

 

 

 

90,000

 

Net cash provided by (used in) investing activities

 

(26,842

)

 

 

56,425

 

Cash flows from financing activities:

 

 

 

 

 

 

 

Advances on revolving credit facilities

 

25,000

 

 

 

 

Payments on revolving credit facilities

 

(30,000

)

 

 

(119,000

)

Proceeds from the paycheck protection program

 

5,516

 

 

 

 

Deferred financing costs

 

 

 

 

(169

)

Dividends to stockholders

 

(3,786

)

 

 

 

Common stock repurchased and retired under the share repurchase program

 

 

 

 

(1,251

)

Costs incurred in conjunction with tender offer

 

 

 

 

(107

)

Restricted units returned to plan

 

(35

)

 

 

(199

)

Other

 

35

 

 

 

���

 

Net cash provided by (used in) financing activities

 

(3,270

)

 

 

(120,726

)

Net change in cash, cash equivalents and restricted cash

 

12,877

 

 

 

(31,002

)

Cash, cash equivalents and restricted cash, beginning of period

 

325

 

 

 

50,029

 

Cash, cash equivalents and restricted cash, end of period

$

13,202

 

 

$

19,027

 

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.


AMPLIFY ENERGY CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(In thousands)

 

Stockholders' Equity

 

 

 

 

 

 

Common Stock

 

 

Warrants

 

 

Additional

Paid-in Capital

 

 

Accumulated

Earnings

(Deficit)

 

 

Total

 

Balance at December 31, 2019

$

209

 

 

$

4,790

 

 

$

424,399

 

 

$

4,809

 

 

$

434,207

 

Net loss

 

 

 

 

 

 

 

 

 

 

(367,199

)

 

 

(367,199

)

Share-based compensation expense

 

 

 

 

 

 

 

(1,112

)

 

 

 

 

 

(1,112

)

Restricted shares repurchased

 

 

 

 

 

 

 

(14

)

 

 

 

 

 

(14

)

Dividends

 

 

 

 

 

 

 

 

 

 

(3,786

)

 

 

(3,786

)

Balance at March 31, 2020

 

209

 

 

 

4,790

 

 

 

423,273

 

 

 

(366,176

)

 

 

62,096

 

Net income (loss)

 

 

 

 

 

 

 

 

 

 

(41,336

)

 

 

(41,336

)

Share-based compensation expense

 

 

 

 

 

 

 

480

 

 

 

 

 

 

480

 

Expiration of warrants

 

 

 

 

(2

)

 

 

2

 

 

 

 

 

 

 

Restricted shares repurchased

 

 

 

 

 

 

 

(20

)

 

 

 

 

 

(20

)

Other

 

 

 

 

 

 

 

35

 

 

 

 

 

 

35

 

Balance at June 30, 2020

$

209

 

 

$

4,788

 

 

$

423,770

 

 

$

(407,512

)

 

$

21,255

 

 

 

Stockholders' Equity

 

 

 

 

 

 

Common Stock

 

 

Warrants

 

 

Additional

Paid-in Capital

 

 

Accumulated

Earnings

(Deficit)

 

 

Total

 

Balance at December 31, 2018

$

3

 

 

$

4,788

 

 

$

355,872

 

 

$

55,895

 

 

$

416,558

 

Net 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

 

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements.


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and BusinessBasis of Presentation

General

On August 6, 2019, Midstates Petroleum Company, Inc. engages, a Delaware corporation (“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 on Form 10-Q 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, 2011Midstates. As a result, period-to-period comparisons of our operating results may not be meaningful. The results of any one quarter should not be relied upon as an indication of future performance.

When referring to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”). The terms “Company,” “we,” “us,” “our,” and similar termsLegacy Amplify, the intent is to refer to Midstates Petroleum Company, Inc.Amplify Energy Corp. prior to the effective date of the Merger, and its subsidiary.consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.

The Company currently conducts oilWe operate in 1 reportable segment engaged in the acquisition, development, exploitation 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”) regarding interim financial reporting. CertainSEC. 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 intercompany transactions and balances have been eliminated in consolidation. In the opinionpreparation of our consolidated financial statements.

Use of Estimates

The preparation of the Company’saccompanying Unaudited Condensed Consolidated Financial Statements in conformity with GAAP requires management the accompanying unaudited interim condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessary 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

12


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

Risk and Uncertainties

In March 2020, the World Health Organization declared the outbreak of COVID-19 as a pandemic, which continues to spread throughout the United States. The spread of COVID-19 has caused significant volatility in U.S. and international markets. There is significant uncertainty around the breadth and duration of business disruptions related to COVID-19, as well as its impact on the U.S. and international economies and, as such, the Company is unable to determine the extent of the impact caused by the COVID-19 pandemic to the Company’s operations.

The pandemic has lowered the demand for oil and natural gas which has led to low commodity prices. The reductions in commodity prices have resulted in lower levels of cash flow from operating activities. In addition, the borrowing base under our Revolving Credit Facility (as defined below) is subject to redetermination on at least a semi-annual basis primarily based on an engineering report with respect to our estimated oil, NGL and natural gas reserves which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Severely reduced commodity prices contributed to a reduction in our borrowing base during the Spring 2020 determination process, and continued low prices may adversely impact subsequent redeterminations. The reduction in commodity prices has directly led to an impairment of our oil and natural gas properties. There may be further impairments in future periods if commodity prices continue to decline.

In addition, oil prices severely declined following unsuccessful negotiations between members of Organization of the Petroleum Exporting Countries (“OPEC”) and certain nonmembers, including Russia, to implement production cuts in an effort to decrease the global oversupply and to rebalance supply and demand due to the ongoing COVID-19 pandemic. In April 2020, members of OPEC and Russia agreed to temporary production reductions, but uncertainty about whether such production cuts and/or the duration of such reductions will be sufficient to rebalance supply and demand remains and may continue for the foreseeable future. We anticipate further market and commodity price volatility for the remainder of 2020 as a result of the events described above.

Notice of Non-Compliance with New York Stock Exchange (“NYSE”) Continued Listing Standards

On April 20, 2020, the Company received written notification (the “Notice”) from the NYSE that the Company no longer satisfied the continued listing compliance standards set forth under Section 802.01C of the NYSE Listed Company Manual (“Section 802.01C”) because the average closing price of the Company’s common stock was below $1.00 over a 30 consecutive trading-day period that ended April 17, 2020. Under the NYSE’s rules, the Company had six months following receipt of the Notice to regain compliance with the minimum share price requirement. The Company notified the NYSE of its intent to cure the deficiency and return to compliance with the NYSE’s continued listing requirements. The common stock symbol “AMPY” was assigned a “.BC” indicator by the NYSE to signify that the Company was not in compliance with the NYSE’s continued listing requirements.

On April 20, 2020, the NYSE made a rule filing with the SEC for relief from the $1.00 per share continued listing standard, which became immediately effective on April 21, 2020. The relief provided that the cure period was suspended until June 30, 2020 and recommenced on July 1, 2020. The Company’s cure period under the relief was extended to December 29, 2020.

On June 2, 2020, the Company received written notification from the NYSE that the Company regained compliance with the NYSE’s continued listing standards. The Company regained compliance after its average closing price for the 30 trading-day period ended May 29, 2020 and its closing price on May 29, 2020 both exceeded $1.00 per share. The “.BC” indicator has been removed from the Company’s common shares and the Company was removed from the NYSE list of non-compliant issuers.

Retirement of President, Chief Executive Officer and Director

On April 1, 2020, Mr. Kenneth Mariani notified the board of directors of the Company of his decision to retire. Mr. Mariani vacated his service as President and Chief Executive Officer of the Company and as a member of the board of directors, effective April 3, 2020. Mr. Mariani’s decision to retire stems solely from personal reasons and did not result from any disagreement with the Company, the Company’s management or the board of directors.

Appointment of Interim Chief Executive Officer

Effective upon Mr. Mariani’s retirement, Mr. Martyn Willsher was appointed the Company’s Interim Chief Executive Officer. Mr. Willsher continues to serve in his role as Senior Vice President and Chief Financial Officer of the Company.

13


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Departure of Director

On June 22, 2020, Scott L. Hoffman notified the Company of his intent to resign from the board of directors of the Company, effective June 23, 2020. Mr. Hoffman served as a member and Chairman of the Nominating and Governance Committee of the board of directors. There were no known disagreements between Mr. Hoffman and the Company which led to Mr. Hoffman’s resignation from the board of directors. On June 23, 2020, Christopher W. Hamm, a current member of the board of directors, was appointed to serve as a member and Chairman of the Nominating and Governance Committee of the board of directors.

Definitive Merger Agreement

On May 6,5, 2019, as discussed above, the Company entered into a definitive merger agreement (“the Merger Agreement”)Agreement pursuant to which Legacy Amplify Energy Corp. (“Amplify”) will mergemerged with a subsidiary of the CompanyMidstates in an all-stock merger-of-equals. Under the terms of the Merger Agreement, Legacy Amplify stockholders will receivereceived 0.933 shares of newly issued Company common stock for each Amplify share of Legacy Amplify common stock.stock that they owned. The merger is expected to closeMerger closed on August 6, 2019, at which time Amplify and2019.

Note 2. Summary of Significant Accounting Policies

Other than the accounting policies implemented in connection with the adoption of the current expected credit losses, there have been no changes to the Company’s stockholders will each own 50%significant accounting policies and estimates as described in the Company’s annual financial statements included in our Annual Report on Form 10-K.

Current Expected Credit Losses

In May 2019, the Financial Accounting Standard Board (the “FASB”) issued an accounting standard 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 Company adopted the guidance as of January 1, 2020. The Company has evaluated the impact of this guidance and concluded that the current and historical evaluation of estimated credit losses falls within the acceptable guidance.

The provisions of the outstanding shares of the combined entity.

The transaction is subjectstandard were interpreted to relate only to the termsCompany’s accounts receivable, net. Trade receivables relate to one common pool, revenue earned on the sale of oil, natural gas and conditions set forthnatural gas liquids. The performance obligation is satisfied at a point in time and revenue is recognized and a trade receivable is recorded from the Merger Agreement, including holders of asale when production is delivered to, and title has transferred to, the purchaser. The majority of the Company’s stockpurchasers have been large major companies in the industry with the wherewithal to pay.  

The Company, as operator on most of our wells, also records receivables on billings to our joint interest owners who participate in the operating costs of the wells they have an interest in. Historically an allowance for doubtful accounts has been set up to recognize credit losses on joint interest billing (“JIB”) receivables based upon an aging analysis which is an appropriate method to estimate credit losses under the guidance. The Company will continue to assess the expected credit loss in the future as economic conditions change. Considering the recent drop in commodity prices we believe the majority of our revenue purchasers have the size and financial condition to currently meet their obligations. There could be added risk on the JIB accounts receivable as some wells could become uneconomic, with the revenue not enough to cover operating expenses billed, which could result in additional write-offs. The Company will continue to closely monitor trade receivables. Based upon the analysis performed there was no impact to beginning retained earnings upon the adoption of the guidance. The Company’s monitoring activities include timely account reconciliation and balances are written off when determined to be uncollectible. The Company considered the market conditions surrounding the COVID-19 pandemic and determined that the estimate of credit losses was not significantly impacted. The Company will continue to closely monitor trade receivables.

New Accounting Pronouncements

Reference Rate Reform. In March 2020, the FASB issued an accounting standard update which provides optional expedients and expectations for applying GAAP to contracts, hedging relationships, and other transactions to ease financial reporting burdens to the expected market transition from the London Interbank Offered Rate (“LIBOR”) or another reference rate to alternative reference rates. The amendments in this accounting standards update are effective beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2022. The Company is currently evaluating the impact this guidance may have on the Company’s consolidated financial statements.

14


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Income Taxes – Simplifying the Accounting for Income Taxes. In December 2019, the FASB issued an accounting standard update which simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. This accounting standards update removes the following exceptions: (i) exception to the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items; (ii) exception to the requirements to recognize a deferred tax liability for equity method investments when a foreign subsidiary becomes an equity method investment; (iii) exception to the ability not to recognize a deferred tax liability for a foreign subsidiary when a foreign equity method investment becomes a subsidiary; and (iv) exception to the general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the anticipated loss for the year. The amendments in the accounting standards update also improve consistency and simplify other areas of Topic 740 by clarifying and amending existing guidance. The new guidance is effective for fiscal years and interim period within those fiscal years, beginning after December 15, 2020. The Company is currently evaluating the impact of this guidance on the Company's consolidated financial statements.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Note 3. Revenue

Revenue from contracts with customers

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 June 30, 2020.

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 Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

 

(in thousands)

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

$

22,963

 

 

$

41,685

 

 

$

64,814

 

 

$

81,742

 

NGLs

 

3,343

 

 

 

5,336

 

 

 

8,465

 

 

 

11,201

 

Natural gas

 

8,582

 

 

 

12,464

 

 

 

19,396

 

 

 

31,609

 

Oil and natural gas sales

$

34,888

 

 

$

59,485

 

 

$

92,675

 

 

$

124,552

 

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 $19.3 million at June 30, 2020 and $31.9 million at December 31, 2019.

Note 4. Acquisitions and Divestitures

Acquisition and Divestiture Related Expenses

There were no material acquisition or divestitures during the three and six months ended June 30, 2020 and 2019, respectively.

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 of 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 special meeting having voted in favortime of the valuation.

15


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 issuance, holdersissued 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.”

Unaudited Pro Forma Financials

The following unaudited pro forma financial information for the three and six months ended June 30, 2019, is based on our historical consolidated financial statements adjusted to reflect as if the Merger had occurred 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 conform the classification of expenses in Midstates statements of operations to our classification for similar expenses and the 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 acquisition had been completed as of the beginning of the periods presented, nor is it necessarily indicative of future results.

 

For the Three Months Ended June 30, 2019

 

 

For the Six Months Ended June 30, 2019

 

(Unaudited) (In thousands, except per unit amounts)

 

 

 

 

 

 

 

Revenues

$

82,772

 

 

$

177,768

 

Net income (loss)

 

23,385

 

 

 

(7,742

)

Earnings per share:

 

 

 

 

 

 

 

Basic

$

0.57

 

 

$

(0.18

)

Diluted

$

0.57

 

 

$

(0.18

)

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 June 30, 2020 and December 31, 2019. 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

The fair market values of the derivative financial instruments reflected on the accompanying Unaudited Condensed Consolidated Balance Sheets as of June 30, 2020 and December 31, 2019 were based on estimated forward commodity prices. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a majority of Amplify stock having voted in favorparticular input to the fair value measurement requires judgment, and may affect the valuation of the merger,fair value of assets and liabilities and their placement within the waiting periodfair value hierarchy levels.

16


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at June 30, 2020 and December 31, 2019 for each of the fair value hierarchy levels:

 

Fair Value Measurements at June 30, 2020 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

$

 

 

$

49,302

 

 

$

 

 

$

49,302

 

Interest rate derivatives

 

 

 

 

 

 

 

 

 

 

 

Total assets

$

 

 

$

49,302

 

 

$

 

 

$

49,302

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

$

 

 

$

6,877

 

 

$

 

 

$

6,877

 

Interest rate derivatives

 

 

 

 

3,693

 

 

 

 

 

 

3,693

 

Total liabilities

$

 

 

$

10,570

 

 

$

 

 

$

10,570

 

 

Fair Value Measurements at December 31, 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

$

 

 

$

18,509

 

 

$

 

 

$

18,509

 

Interest rate derivatives

 

 

 

 

595

 

 

 

 

 

 

595

 

Total assets

$

 

 

$

19,104

 

 

$

 

 

$

19,104

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

$

 

 

$

6,861

 

 

$

 

 

$

6,861

 

Interest rate derivatives

 

 

 

 

558

 

 

 

 

 

 

558

 

Total liabilities

$

 

 

$

7,419

 

 

$

 

 

$

7,419

 

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 existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. The initial fair value estimates are based on unobservable market data and are classified within Level 3 of the fair value hierarchy. See Note 7 for a summary of changes in AROs.

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The Company uses an income approach based on the discounted cash flow method, whereby the present value of expected future net cash flows are discounted by applying an appropriate discount rate, for purposes of placing a fair value on the assets. The future cash flows are based on management’s estimates for the future. The unobservable inputs used to determine fair value include, but are not limited to, estimates of proved reserves, estimates of probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties (some of which are Level 3 inputs within the fair value hierarchy).

NaN impairment expense for the three months ended June 30, 2020 was recognized.

17


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the six months ended June 30, 2020, we recognized $405.7 million of impairment expense on our proved oil and natural gas properties. These impairments related to certain properties located in East Texas, the Rockies and offshore Southern California. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. The impairments were due to a decline in the value of estimated proved reserves based on declining commodity prices.

NaN impairment expense was recognized during the three and six months ended June 30, 2019.

Note 6. Risk Management and Derivative Instruments

Derivative instruments are utilized to manage exposure to commodity price fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These instruments limit exposure to declines in prices, but also limit the benefits that would be realized if prices increase.

Certain inherent business risks are associated with commodity derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, 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 required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the U.S. Hart-Scott-Rodino Act having expiredISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. Had all counterparties failed completely to perform according to the terms of the existing contracts, we would have had the right to offset $39.9 million against amounts outstanding under our Revolving Credit Facility at June 30, 2020, reducing our maximum credit exposure to approximately $0.3 million, all of which was with one counterparty. See Note 8 for additional information regarding our Revolving Credit Facility.

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 instruments at fair value.

In April 2020, the Company monetized a portion of its 2021 crude oil hedges for total cash proceeds of approximately $18.0 million.  

We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub. We also enter into oil derivative contracts indexed to NYMEX-WTI. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu.

18


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At June 30, 2020, we had the following open commodity positions:

 

Remaining

 

 

 

 

 

 

 

 

 

 

2020

 

 

2021

 

 

2022

 

Natural Gas Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

Average monthly volume (MMBtu)

 

1,450,000

 

 

 

925,000

 

 

 

500,000

 

Weighted-average fixed price

$

2.26

 

 

$

2.49

 

 

$

2.45

 

 

 

 

 

 

 

 

 

 

 

 

 

Collar contracts:

 

 

 

 

 

 

 

 

 

 

 

Two-way collars

 

 

 

 

 

 

 

 

 

 

 

Average monthly volume (MMBtu)

 

420,000

 

 

 

925,000

 

 

 

200,000

 

Weighted-average floor price

$

2.60

 

 

$

2.10

 

 

$

2.10

 

Weighted-average ceiling price

$

2.88

 

 

$

3.28

 

 

$

2.99

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas Basis Swaps:

 

 

 

 

 

 

 

 

 

 

 

PEPL basis swaps:

 

 

 

 

 

 

 

 

 

 

 

Average monthly volume (MMBtu)

 

600,000

 

 

 

500,000

 

 

 

 

Weighted-average spread

$

(0.46

)

 

$

(0.40

)

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

Average monthly volume (Bbls)

 

199,300

 

 

 

33,750

 

 

 

30,000

 

Weighted-average fixed price

$

57.41

 

 

$

56.57

 

 

$

55.32

 

 

 

 

 

 

 

 

 

 

 

 

 

Collar contracts:

 

 

 

 

 

 

 

 

 

 

 

Two-way collars

 

 

 

 

 

 

 

 

 

 

 

Average monthly volume (Bbls)

 

14,300

 

 

 

 

 

 

 

Weighted-average floor price

$

55.00

 

 

$

 

 

$

 

Weighted-average ceiling price

$

62.10

 

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

Three-way collars

 

 

 

 

 

 

 

 

 

 

 

Average monthly volume (Bbls)

 

30,500

 

 

 

 

 

 

 

Weighted-average ceiling price

$

65.75

 

 

$

 

 

$

 

Weighted-average floor price

$

50.00

 

 

$

 

 

$

 

Weighted-average sub-floor price

$

40.00

 

 

$

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL Derivative Contracts:

 

 

 

 

 

 

 

 

 

 

 

Fixed price swap contracts:

 

 

 

 

 

 

 

 

 

 

 

Average monthly volume (Bbls)

 

111,450

 

 

 

22,800

 

 

 

 

Weighted-average fixed price

$

21.99

 

 

$

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 June 30, 2020, we had the following interest rate swap open positions:

 

Remaining

 

 

 

 

 

 

 

 

 

 

2020

 

 

2021

 

 

2022

 

Average Monthly Notional (in thousands)

$

125,000

 

 

$

125,000

 

 

$

75,000

 

Weighted-average fixed rate

 

1.612

%

 

 

1.612

%

 

 

1.281

%

Floating rate

1 Month LIBOR

 

 

1 Month LIBOR

 

 

1 Month LIBOR

 

19


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at June 30, 2020 and December 31, 2019. 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 Revolving Credit Facility.

 

 

 

 

Asset Derivatives

 

 

Liability

Derivatives

 

 

Asset Derivatives

 

 

Liability

Derivatives

 

 

 

 

 

June 30,

 

 

June 30,

 

 

December 31,

 

 

December 31,

 

Type

 

Balance Sheet Location

 

2020

 

 

2020

 

 

2019

 

 

2019

 

 

 

 

 

(In thousands)

 

Commodity contracts

 

Short-term derivative instruments

 

$

38,035

 

 

$

4,744

 

 

$

11,518

 

 

$

5,887

 

Interest rate swaps

 

Short-term derivative instruments

 

 

 

 

 

1,860

 

 

 

248

 

 

 

253

 

Gross fair value

 

 

 

 

38,035

 

 

 

6,604

 

 

 

11,766

 

 

 

6,140

 

Netting arrangements

 

 

 

 

(5,819

)

 

 

(5,819

)

 

 

(5,887

)

 

 

(5,887

)

Net recorded fair value

 

Short-term derivative instruments

 

$

32,216

 

 

$

785

 

 

$

5,879

 

 

$

253

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Long-term derivative instruments

 

$

11,267

 

 

$

2,133

 

 

$

6,990

 

 

$

973

 

Interest rate swaps

 

Long-term derivative instruments

 

 

 

 

 

1,833

 

 

 

347

 

 

 

305

 

Gross fair value

 

 

 

 

11,267

 

 

 

3,966

 

 

 

7,337

 

 

 

1,278

 

Netting arrangements

 

 

 

 

(2,133

)

 

 

(2,133

)

 

 

(973

)

 

 

(973

)

Net recorded fair value

 

Long-term derivative instruments

 

$

9,134

 

 

$

1,833

 

 

$

6,364

 

 

$

305

 

(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 terminated early,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 Six Months Ended

 

 

 

Statements of

 

June 30,

 

 

June 30,

 

 

 

Operations Location

 

2020

 

 

2019

 

 

2020

 

 

2019

 

Commodity derivative contracts

 

(Gain) loss on commodity derivatives

 

$

19,165

 

 

$

(22,993

)

 

$

(88,548

)

 

$

9,494

 

(Gain) loss on interest rate derivatives

 

Interest expense, net

 

 

438

 

 

 

627

 

 

 

4,054

 

 

 

534

 

Note 7. Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the Company’s stock being issuedportion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the six months ended June 30, 2020 (in thousands):

Asset retirement obligations at beginning of period

$

91,089

 

Liabilities added from acquisition or drilling

 

50

 

Liabilities settled

 

 

Accretion expense

 

3,052

 

Revision of estimates

 

 

Asset retirement obligation at end of period

 

94,191

 

Less: Current portion

 

(623

)

Asset retirement obligations - long-term portion

$

93,568

 

20


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 8. Long-Term Debt

The following table presents our consolidated debt obligations at the dates indicated:

 

June 30,

 

 

December 31,

 

 

2020

 

 

2019

 

 

(In thousands)

 

Revolving Credit Facility (1)

$

280,000

 

 

$

285,000

 

Paycheck Protection Program loan (2)

 

5,516

 

 

 

 

Total debt

 

285,516

 

 

 

285,000

 

Current portion of long-term debt (3)

 

20,000

 

 

 

 

Long-term debt

$

265,516

 

 

$

285,000

 

(1)

The carrying amount of our Revolving Credit Facility approximates fair value because the interest rates are variable and reflective of market rates.

(2)

See below for additional information regarding the receipt of the paycheck protection program loan.

(3)

Reflects the current portion of the monthly reductions for the Revolving Credit Facility as described below regarding the Third Amendment (as defined below).

Revolving Credit Facility

Amplify Energy Operating LLC, our wholly owned subsidiary (“OLLC”), is a party to a reserve-based revolving credit facility (the “Revolving Credit Facility”), subject to a borrowing base of $285.0 million as of June 30, 2020, which is guaranteed by us and all of our current subsidiaries. The Revolving Credit Facility matures on November 2, 2023.

Our borrowing base under our 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.

As of June 30, 2020, we were in compliance with all the financial (current ratio and total leverage ratio) and other covenants associated with our Revolving Credit Facility.

Borrowing Base Redetermination

On June 12, 2020, the Company entered into the Borrowing Base Redetermination Agreement and Third Amendment to Credit Agreement, among the Borrower, Amplify stockholdersAcquisitionco LLC, a Delaware limited liability company, the guarantors party thereto, the lenders party thereto and Bank of Montreal, as administrative agent (the “Third Amendment”). The Third Amendment amends the parties’ existing Credit Agreement, dated November 2, 2018, to among other things:

reduce the borrowing base under the Credit Agreement from $450.0 million to $285.0 million, with monthly reductions of $5.0 million thereafter until the borrowing base is reduced to $260.0 million, effective November 1, 2020;

increase the amount of first priority liens on all assets from at least 85% to 90%;

suspend certain financial covenants for the quarter ended June 30, 2020;

amend the definition of “Consolidated EBITDAX” in the Credit Agreement to decrease the limit of cash and cash equivalents permitted from $30.0 million to $25.0 million and increase the limit of transaction-related expense add-backs from $5.0 million to $20.0 million;

increase the minimum hedging requirements to at least 30% -60% of our estimated production from total proved developed producing reserves;

incorporate a mandatory prepayment at times when cash and cash equivalents (as defined in the Credit Agreement) on hand exceed $25.0 million for five consecutive business days; and

amend certain other covenants and provisions.

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 Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

Revolving Credit Facility

3.12%

 

 

5.00%

 

 

3.55%

 

 

5.04%

 

21


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Letters of Credit

At June 30, 2020, we had 0 letters of credit outstanding.

Unamortized Deferred Financing Costs

Unamortized deferred financing costs associated with our Revolving Credit Facility was $1.7 million at June 30, 2020. At June 30, 2020, the unamortized deferred financing costs are amortized over the remaining life of our Revolving Credit Facility. At June 30, 2020, we wrote-off $2.4 million of deferred financing costs in connection with the merger being listeddecrease in our borrowing base.

Paycheck Protection Program

On April 24, 2020, the Company received a $5.5 million loan under the Paycheck Protection Program (the “PPP Loan”). The Paycheck Protection Program was established as part of the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) to provide loans to qualifying businesses. The loans and accrued interest are potentially forgivable provided that the borrower uses the loan proceeds for eligible purposes. At this time, the Company anticipates that a substantial majority of the loan proceeds will be forgiven under the program. The term of the Company’s PPP Loan is two years with an annual interest rate of 1% and 0 payments of principal or interest due during the six-month period beginning on the NYSE and other customary conditions.  All such conditions were satisfieddate of the PPP Loan.

Note 9. Equity (Deficit)

Common Stock

The Company’s authorized capital stock includes 250,000,000 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 six months ended June 30, 2020:

Common

Shares

Balance, December 31, 2019

37,566,540

Issuance of common stock

Restricted stock units vested

64,751

Repurchase of common shares (1)

(18,377

)

Balance, June 30, 2020

37,612,914

(1)

Represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory tax withholding requirements.

Warrants

On the May 4, 2017, 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 August 5, 2019.May 4, 2017), 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, exercisable for a five-year period commencing on May 4, 2017 at an exercise price of $42.60 per share.

The transactions contemplated byOn the effective date of the Merger, Legacy Amplify, Midstates and AST entered into an Assignment and Assumption Agreement, will be treated aspursuant to which the Company agreed to assume Legacy Amplify’s Warrant Agreement.

In connection with the Merger in August 2019, the Company assumed 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”). As a “change in control”result of the Merger, the value of the outstanding Warrants was adjusted downward based on the low stock price and estimated fair value as of the effective dateMerger date. The Warrants expired on April 21, 2020.

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 purposesa total cost of all Parent Benefit Plans (as definedapproximately $1.3 million. On April 18, 2019, in anticipation of the Merger, Agreement), includingLegacy Amplify terminated 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. The Company has agreed 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)repurchase program.

In connection, 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 inMerger, the Merger Agreement) held by such employee shall become fully vested, (B) all Parent RSUs (as defined inboard of directors approved 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 subjectcommencement of an open market share repurchase program of up to the achievement$25.0 million of the Company’s specificoutstanding shares of common stock. As of February 28, 2020, the Company had repurchased approximately 4.2 million shares of common stock at an average price levels shall be deemed earnedof $5.94 per share for a total cost of approximately $24.9 million (inclusive of fees).

22


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Cash Dividend Payment

On March 3, 2020, our board of directors approved a dividend of $0.10 per share of outstanding common stock or $3.8 million in aggregate, which was paid on March 30, 2020, to stockholders of record 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 levelclose 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 thebusiness on March 16, 2020. The board of directors of the Company on December 21, 2018 (the “Equalization Program”) thatpreviously decided to suspend the quarterly dividend program until further notice. Under the terms of our Credit Agreement, dividends are owingrestricted based upon certain leverage and liquidity covenants. Future dividends, if any, are subject to such employee(s) shall be paid

promptly upon termination, (ii) all Parent RSUs heldthese debt covenants and discretionary approval by members of the board of directors shall become fully vested and shall be settled promptly upondirectors.

Note 10. Earnings per Share

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 Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2020

 

 

2019

 

 

2020

 

 

 

2019

 

Net loss

$

(41,336

)

 

$

18,641

 

 

$

(408,535

)

 

 

$

(12,836

)

Less: Net income allocated to participating restricted stockholders

 

 

 

 

728

 

 

 

 

 

 

 

 

Basic and diluted earnings available to common stockholders

$

(41,336

)

 

$

17,913

 

 

$

(408,535

)

 

 

$

(12,836

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common shares/units:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common shares outstanding — basic

 

37,595

 

 

 

22,267

 

 

 

37,582

 

 

 

 

22,233

 

Dilutive effect of potential common shares

 

 

 

 

 

 

 

 

 

 

 

 

Common shares outstanding — diluted

 

37,595

 

 

 

22,267

 

 

 

37,582

 

 

 

 

22,233

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net earnings per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

$

(1.10

)

 

$

0.80

 

 

$

(10.87

)

 

 

$

(0.58

)

Diluted

$

(1.10

)

 

$

0.80

 

 

$

(10.87

)

 

 

$

(0.58

)

Antidilutive warrants (1)

 

2,174

 

 

 

2,174

 

 

 

2,174

 

 

 

 

2,174

 

(1)

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 “Legacy Amplify MIP”). In connection with the closing of the merger,Merger, on August 6, 2019, the Company assumed the Legacy Amplify 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 (iii) all cash amounts pursuantforfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with the TSUs was $0.5 million at June 30, 2020. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.7 years.

The following table summarizes information regarding the TSUs granted under the Legacy Amplify MIP for the period presented:

 

 

 

 

 

Weighted-

 

 

 

 

 

 

Average Grant

 

 

Number of

 

 

Date Fair Value

 

 

Units

 

 

per Unit (1)

 

TSUs outstanding at December 31, 2019

 

291,370

 

 

$

5.18

 

Granted (2)

 

43,250

 

 

$

3.10

 

Forfeited

 

(87,314

)

 

$

5.12

 

Vested

 

(57,492

)

 

$

5.12

 

TSUs outstanding at June 30, 2020

 

189,814

 

 

$

4.75

 

(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 six months ended June 30, 2020 was $0.1 million based on a grant date market price of ranging from $0.54 to $6.61 per share.

23


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 Equalization ProgramPSUs was approximately $0.2 million at June 30, 2020. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.6 years.

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 owingachieved 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, 2020

 

1.61

%

 

 

1.61

%

 

 

1.61

%

 

 

 

 

 

 

 

 

 

 

 

 

Dividend yield

 

12.1

%

 

 

12.1

%

 

 

12.1

%

 

 

 

 

 

 

 

 

 

 

 

 

Expected volatility:

 

 

 

 

 

 

 

 

 

 

 

Awards Issued on January 1, 2020

 

60.0

%

 

 

60.0

%

 

 

60.0

%

 

 

 

 

 

 

 

 

 

 

 

 

Calculated fair value per PSU:

 

 

 

 

 

 

 

 

 

 

 

Awards Issued on January 1, 2020

$

3.66

 

 

$

2.98

 

 

$

2.46

 

The following table summarizes information regarding the PSUs granted under the Legacy Amplify MIP for the period presented:

 

 

 

 

 

Weighted-

 

 

 

 

 

 

Average Grant

 

 

Number of

 

 

Date Fair Value

 

 

Units

 

 

per Unit (1)

 

PSUs outstanding at December 31, 2019

 

305,893

 

 

$

2.15

 

Granted (2)

 

43,250

 

 

$

3.03

 

Forfeited

 

(128,058

)

 

$

2.11

 

Vested

 

 

 

$

 

PSUs outstanding at June 30, 2020

 

221,085

 

 

$

2.35

 

(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 PSUs issued for the six months ended June 30, 2020 was $0.1 million based on a calculated fair value price ranging from $2.46 to $3.66 per share.

2017 Non-Employee Directors Compensation Plan

In June 2017, Legacy Amplify implemented the 2017 Non-Employee Directors Compensation Plan (“Legacy Amplify Non-Employee Directors Compensation Plan”) to attract and retain the services of experienced non-employee directors of the Company shall be paid promptly uponLegacy Amplify or its subsidiaries. In connection with the closing of the merger.Merger, on August 6, 2019, the Company assumed the Legacy Amplify Non-Employee 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 less than $0.1 million at June 30, 2020. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.8 years.

24


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

The Company estimates that between 500,000following table summarizes information regarding the Board RSUs granted under the Legacy Amplify Non-Employee Directors Compensation Plan for the period presented:

 

 

 

 

 

Weighted-

 

 

 

 

 

 

Average Grant

 

 

Number of

 

 

Date Fair Value

 

 

Units

 

 

per Unit (1)

 

Board RSUs outstanding at December 31, 2019

 

16,157

 

 

$

5.12

 

Granted

 

 

 

$

 

Forfeited

 

 

 

$

 

Vested

 

(7,259

)

 

$

5.12

 

Board RSUs outstanding at June 30, 2020

 

8,898

 

 

$

5.12

 

(1)

Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

Compensation Expense

The following table summarizes the amount of recognized compensation expense associated with the Legacy Amplify MIP and 800,000 unvested stock awards (including stock options) will vest upon closing and between $8.5 million to $11.5 millionLegacy Amplify Non-Employee Directors Compensation Plan, which are reflected in severance payments will be made. The numberthe accompanying Unaudited Condensed Statements of unvested stock awards and severance payments are estimated andConsolidated Operations for the final amount has not yet been determined.periods presented (in thousands):

 

For the Three Months Ended

 

 

For the Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2020

 

 

2019

 

 

2020

 

 

 

2019

 

Equity classified awards

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TSUs

$

(6

)

 

$

532

 

 

$

125

 

 

 

$

1,202

 

PSUs

 

5

 

 

 

309

 

 

 

10

 

 

 

 

705

 

Board RSUs

 

2

 

 

 

50

 

 

 

40

 

 

 

 

162

 

 

$

1

 

 

$

891

 

 

$

175

 

 

 

$

2,069

 

 

Recent Accounting Pronouncements Adopted DuringNote 12. Leases

For the Period

In July 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2017-11, “Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480),quarter ended June 30, 2020, our leases qualify as operating leases 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 2017-11we did not have any existing or new leases qualifying as financing leases or variable leases. We have leases for office space and equipment in our corporate office and operating regions as well as vehicles, compressors and surface rentals related to our business operations. In addition, we have offshore Southern California pipeline right-of-way use agreements. Most of our leases, other than our corporate office lease, have an initial term and may be extended on a month-to-month basis after expiration of the initial term. Most of our leases can be terminated with 30-day prior written notice. The majority of our month-to-month leases are not included as a lease liability in our balance sheet under ASC 842 because continuation of the lease is not reasonably certain. Additionally, the Company elected the short-term practical expedient to exclude leases with a term of twelve months or less.

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.

For the six months ended June 30, 2020 and 2019, we recognized approximately $1.2 million and $1.0 million, respectively, of costs relating to the operating leases in the Unaudited Condensed Statement of Operations.

Supplemental cash flow information related to the Company’s lease liabilities are included in the table below:

 

For the Six Months Ended

 

 

June 30,

 

 

2020

 

 

2019

 

 

(In thousands)

 

Non-cash amounts included in the measurement of lease liabilities:

 

 

 

 

 

 

 

Operating cash flows from operating leases

$

877

 

 

$

5,096

 

25


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the Company’s right-of-use assets and lease liabilities for the period presented:

 

June 30,

 

 

December 31,

 

 

2020

 

 

2019

 

 

(In thousands)

 

Right-of-use asset

$

3,528

 

 

$

4,406

 

 

 

 

 

 

 

 

 

Lease liabilities:

 

 

 

 

 

 

 

Current lease liability

 

2,205

 

 

 

1,712

 

Long-term lease liability

 

1,350

 

 

 

2,720

 

Total lease liability

$

3,555

 

 

$

4,432

 

The following table reflects the Company’s maturity analysis of the minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year (in thousands):

 

Office leases

 

 

Leased vehicles and office equipment

 

 

Total

 

Remaining in 2020

$

808

 

 

$

353

 

 

$

1,161

 

2021

 

1,287

 

 

 

536

 

 

 

1,823

 

2022

 

478

 

 

 

208

 

 

 

686

 

2023 and thereafter

 

 

 

 

25

 

 

 

25

 

Total lease payments

 

2,573

 

 

 

1,122

 

 

 

3,695

 

Less: interest

 

105

 

 

 

35

 

 

 

140

 

Present value of lease liabilities

$

2,468

 

 

$

1,087

 

 

$

3,555

 

The weighted average remaining lease terms and discount rate for all of our operating leases for the period presented:

 

June 30,

 

 

2020

 

 

2019

 

Weighted average remaining lease term (years):

 

 

 

 

 

 

 

Office leases

 

1.10

 

 

 

1.91

 

Vehicles

 

0.53

 

 

 

0.49

 

Office equipment

 

0.06

 

 

 

0.10

 

Weighted average discount rate:

 

 

 

 

 

 

 

Office leases

 

3.49

%

 

 

3.72

%

Vehicles

 

0.94

%

 

 

0.77

%

Office equipment

 

0.17

%

 

 

0.19

%

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):

 

June 30,

 

 

December 31,

 

 

2020

 

 

2019

 

Accrued lease operating expense

$

8,680

 

 

$

11,794

 

Accrued capital expenditures

 

1,541

 

 

 

5,515

 

Accrued general and administrative expense

 

3,111

 

 

 

3,126

 

Operating lease liability

 

2,205

 

 

 

1,712

 

Accrued ad valorem tax

 

1,566

 

 

 

520

 

Asset retirement obligations

 

623

 

 

 

623

 

Accrued interest payable

 

30

 

 

 

36

 

Other

 

81

 

 

 

32

 

Accrued liabilities

$

17,837

 

 

$

23,358

 

26


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Cash and Cash Equivalents Reconciliation

The following table provides a reconciliation of cash and cash equivalents on the Unaudited Condensed Consolidated Balance Sheet to cash, cash equivalents and restricted cash on the Unaudited Condensed Statements of Consolidated Cash Flows (in thousands):

 

June 30,

 

 

December 31,

 

 

2020

 

 

2019

 

Cash and cash equivalents

$

13,202

 

 

$

 

Restricted cash

 

 

 

 

325

 

Total cash, cash equivalents and restricted cash

$

13,202

 

 

$

325

 

Unproved Property

We recognized $49.3 million of impairment expense on unproved properties for the six months ended June 30, 2020, which was related to expiring leases and the evaluation of qualitative and quantitative factors related to the current decline in commodity prices. NaN impairment expense was recorded for unproved properties for the six months ended June 30, 2019.

Supplemental Cash Flows

Supplemental cash flows for the periods presented (in thousands):

 

For the Six Months Ended

 

 

June 30,

 

 

2020

 

 

2019

 

Supplemental cash flows:

 

 

 

 

 

 

 

Cash paid for interest, net of amounts capitalized

$

5,380

 

 

$

5,861

 

Cash paid for reorganization items, net

 

351

 

 

 

650

 

Cash paid for taxes

 

85

 

 

 

 

 

 

 

 

 

 

 

 

Noncash investing and financing activities:

 

 

 

 

 

 

 

Change in capital expenditures in payables and accrued liabilities

 

(3,618

)

 

 

(5,034

)

Note 14. Related Party Transactions

Related Party Agreements

There have been no transactions in excess of $120,000 between us and any related person in which the related person had a direct or indirect material interest for the three and six months ended June 30, 2020 and 2019, respectively.

Note 15. Commitments and Contingencies

Litigation and Environmental

We are not aware of any litigation, pending or threatened, that we believe will have a material impactadverse effect on itsour financial position, results of operations or cash flows.flows; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.

At June 30, 2020 and December 31, 2019, we had 0 environmental reserves recorded on our Unaudited Condensed Consolidated Balance Sheet.

27


AMPLIFY ENERGY CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

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, the accounting for share-based payments to non-employees and employees will be substantially aligned. The new standard is effective for 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 a lease liability on the balance sheet for all leases with terms longer than 12 months. The Company adopted ASU 2016-02 using the modified retrospective transition approach. See “Note 3. Impact of ASC 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 ASC 842 Adoption

In February 2016, the FASB issued ASU 2016-02, which establishes 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 exist or expired prior to a company’s adoption of ASU 2016-02 and that were not accounted for as leases under previous 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, 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 a 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) initial direct costs for any existing leases, but have not elected the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. The Company also elected the practical expedient under ASU 2018-01 and has not evaluated existing or expired land easements not previously accounted for as leases prior to the effective date. The new standard also provides practical expedients for an entity’s ongoing accounting. The Company elected the short-term lease recognition exemption for all leases that qualify. The Company also elected the practical expedient to not separate lease and non-lease components for the majority of classes of underlying assets.

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 June 30, 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 in operating, investing or financing activities in its unaudited interim condensed consolidated statements of cash flows for the periods presented. Further discussion of the Company’s accounting for lease arrangements under ASC 842 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 ROU lease assets, and lease liabilities in the unaudited interim condensed consolidated balance sheets at June 30, 2019. ROU lease assets and lease liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The ROU lease 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 are recognized on a straight-line basis over the lease term.

As of June 30, 2019, the Company 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

Minimum Volume Commitment

The Company is party to a gas purchase, gathering and processing contract in the Mississippian Lime region,Oklahoma, which includes certain minimum NGLs volumeNGL 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. 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, the Company is not meeting the minimum volume required to use its incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date.under these contractual provisions. 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 informationcommitment fee expense 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 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 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. Fair Value Measurements of Financial Instruments

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 estimated fair value. At June 30, 2019, all of the Company’s commodity derivative contracts were with four bank counterparties and were classified as Level 2 in the fair value input hierarchy. The fair value of the Company’s commodity derivatives are determined using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, non-performance risk, as well as other relevant economic measures. Substantially all 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 of these positions in gains (losses) on commodity derivative contracts — net in the Company’s unaudited interim condensed consolidated statements of operations.

 

 

Fair Value Measurements at June 30, 2019

 

 

 

Quoted Prices

 

Significant Other

 

Significant

 

 

 

 

 

in Active Markets
(Level 1)

 

Observable Inputs
(Level 2)

 

Unobservable Inputs
(Level 3)

 

Total

 

 

 

(in thousands)

 

Derivative Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

368

 

$

 

$

368

 

Commodity derivative gas swaps

 

$

 

$

831

 

$

 

$

831

 

Commodity derivative oil collars

 

$

 

$

1,917

 

$

 

$

1,917

 

Commodity derivative gas collars

 

$

 

$

460

 

$

 

$

460

 

Total assets

 

$

 

$

3,576

 

$

 

$

3,576

 

 

 

 

 

 

 

 

 

 

 

Derivative Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

 

$

 

$

 

Commodity derivative gas swaps

 

$

 

$

 

$

 

$

 

Commodity derivative oil collars

 

$

 

$

(1,883

)

$

 

$

(1,883

)

Commodity derivative gas collars

 

$

 

$

(255

)

$

 

$

(255

)

Total liabilities

 

$

 

$

(2,138

)

$

 

$

(2,138

)

 

 

Fair Value Measurements at December 31, 2018

 

 

 

Quoted Prices

 

Significant Other

 

Significant

 

 

 

 

 

in Active Markets
(Level 1)

 

Observable Inputs
(Level 2)

 

Unobservable Inputs
(Level 3)

 

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

)

5. Risk Management and Derivative Instruments

The Company’s production is exposed to fluctuations in crude oil, NGLs and natural gas prices. The Company believes it is prudent to manage 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.

·                  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 payment 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 placed 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 oil 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 commodity 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 does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Due to the netting arrangements, had the Company’s counterparties failed to perform under existing commodity derivative contracts, the maximum loss at June 30, 2019, would have been $1.4 million.

Commodity Derivative Contracts

The Company has various oil and natural gas derivative contracts that extend through December 31, 2020, summarized as follows:

 

 

NYMEX WTI

 

 

 

Fixed Swaps

 

Three-Way Collars

 

 

 

Hedge
Position
(Bbls)

 

Weighted
Avg
Strike
Price

 

Hedge
Position
(Bbls)

 

Weighted
Avg
Ceiling
Price

 

Weighted
Avg Floor
Price

 

Weighted
Avg
Sub-Floor
Price

 

Quarter Ended:

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2019

 

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

 


(1)                     Positions shown represent open commodity derivative contract positions as of June 30, 2019.

 

 

NYMEX HENRY HUB

 

 

 

Fixed Swaps

 

Three-Way Collars

 

 

 

Hedge
Position
(MMBtu)

 

Weighted
Avg Strike
Price

 

Hedge
Position
(MMBtu)

 

Weighted
Avg
Ceiling
Price

 

Weighted
Avg
Floor
Price

 

Weighted
Avg
Sub-Floor
Price

 

Quarter Ended:

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2019

 

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 June 30, 2019.

Balance Sheet Presentation

The following table summarizes the net fair values of commodity derivative instruments by the appropriate balance sheet classification in the Company’s unaudited interim condensed consolidated balance sheets for the periods presented (in thousands):

Type

 

Balance Sheet Location (1)

 

June 30, 2019

 

December 31, 2018

 

Oil swaps

 

Derivative financial instruments — current assets

 

$

368

 

$

3,806

 

Gas swaps

 

Derivative financial instruments — current assets

 

831

 

(207

)

Oil collars

 

Derivative financial instruments — current assets

 

256

 

3,316

 

Gas collars

 

Derivative financial instruments — current assets

 

204

 

25

 

Total derivative financial instruments current assets

 

$

1,659

 

$

6,940

 

 

 

 

 

 

 

 

 

Oil collars

 

Derivative financial instruments — noncurrent assets

 

$

108

 

$

791

 

Total derivative financial instruments — noncurrent assets

 

$

108

 

$

791

 

 

 

 

 

 

 

 

 

Oil swaps

 

Derivative financial instruments — current liabilities

 

$

 

$

 

Gas swaps

 

Derivative financial instruments — current liabilities

 

 

 

Oil collars

 

Derivative financial instruments — current liabilities

 

(329

)

 

Gas collars

 

Derivative financial instruments — current liabilities

 

 

 

Total derivative financial instruments current liabilities

 

$

(329

)

$

 

 

 

 

 

 

 

 

 

Oil collars

 

Derivative financial instruments — noncurrent liabilities

 

$

 

$

 

Gas collars

 

Derivative financial instruments — noncurrent liabilities

 

 

(80

)

Total derivative financial instruments noncurrent liabilities

 

$

 

$

(80

)

 

 

 

 

 

 

 

 

Total derivative fair value at period end

 

$

1,438

 

$

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.

The following table summarizes the location and fair value amounts of all commodity derivative instruments 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 sheets for the periods presented (in thousands):

 

 

 

 

June 30, 2019

 

Not Designated as

 

 

 

Gross Recognized

 

Gross Amounts

 

Net Recognized
Fair Value

 

ASC 815 Hedges

 

Balance Sheet Location Classification

 

Assets/Liabilities

 

Offset

 

Assets/Liabilities

 

Derivative Assets:

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Derivative financial instruments — current

 

$

2,834

 

$

(1,175

)

$

1,659

 

Commodity contracts

 

Derivative financial instruments — noncurrent

 

742

 

(634

)

108

 

 

 

 

 

$

3,576

 

$

(1,809

)

$

1,767

 

Derivative Liabilities:

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Derivative financial instruments — current

 

$

(1,504

)

$

1,175

 

$

(329

)

Commodity contracts

 

Derivative financial instruments — noncurrent

 

(634

)

634

 

 

 

 

 

 

$

(2,138

)

$

1,809

 

$

(329

)

 

 

 

 

December 31, 2018

 

Not Designated as

 

 

 

Gross Recognized

 

Gross Amounts

 

Net Recognized
Fair Value

 

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

)

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 or net cash paid for the settlement of commodity derivative contracts and unrealized net gains or unrealized net losses 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 June 30,

 

For the Six Months
Ended June 30,

 

 

 

2019

 

2018

 

2019

 

2018

 

Net cash received (paid) for commodity derivative contracts

 

$

253

 

$

(3,518

)

$

1,022

 

$

(3,677

)

Unrealized net gains (losses)

 

2,288

 

(7,830

)

(6,213

)

(11,610

)

Gains (losses) on commodity derivative contracts—net

 

$

2,541

 

$

(11,348

)

$

(5,191

)

$

(15,287

)

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:

 

 

June 30, 2019

 

December 31, 2018

 

 

 

(in thousands)

 

Oil and gas properties, on the basis of full-cost accounting:

 

 

 

 

 

Proved properties

 

$

827,638

 

$

809,272

 

Unproved properties not being amortized

 

1,912

 

4,050

 

Other property and equipment

 

6,280

 

6,345

 

Less accumulated depreciation, depletion, amortization and impairment

 

(331,904

)

(266,198

)

Net property and equipment

 

$

503,926

 

$

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 six months ended June 30, 2019, the Company did not have significant exploration and development activities and no internal costs were capitalized. 2020, was approximately $0.6 million.

The Company capitalizedis party to a gas purchase, gathering and processing contract in East Texas, which includes certain minimum NGL commitments. The Company anticipates that a shortfall will occur for the following (in thousands):year-end 2020 and has established an accrual for the commitment fee expense of $0.8 million for the six months ended June 30, 2020.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2019

 

2018

 

2019

 

2018

 

Internal costs capitalized to oil and gas properties (1)

 

$

 

$

922

 

$

 

$

1,817

 


(1)         InclusiveBeta Operating Company, LLC, has an obligation with the BOEM in connection with its 2009 acquisition of our properties in federal waters offshore Southern California. The Company supports this obligation with $161.3 million of A-rated surety bonds and $0.3 million and $0.5of cash.

Note 16. Income Taxes

The Company had less than ($0.1) million of qualifying share-based compensation expensein income tax benefit/(expense) for the three and six months ended June 30, 2018, respectively.

The Company accounts2020, respectively, 0 income tax for its oilthe three months ended June 30, 2019 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 accountedless than $0.1 million income tax benefit/(expense) 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 six months ended June 30, 2018,2019. The Company’s effective tax rate was 0.2% and 0.0% for the Company signed a purchasethree and sale agreementsix months ended June 30, 2020, respectively, and 0.0% and 0.4% 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 and six months ended June 30, 2019, capitalized costs exceeded the ceiling and the Company recorded impairments of oil and gas properties of $33.6 million and $43.2 million, respectively. These impairments were 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 or six months ended June 30, 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
June 30,

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

 

2019

 

2018

 

2019

 

2018

 

2019

 

2018

 

2019

 

2018

 

 

 

(in thousands)

 

(per Boe)

 

(in thousands)

 

(per Boe)

 

Depletion expense

 

$

10,762

 

$

15,898

 

$

9.85

 

$

8.97

 

$

22,442

 

$

30,520

 

$

9.83

 

$

8.71

 

Depreciation on other property and equipment

 

111

 

586

 

0.10

 

0.33

 

225

 

1,177

 

0.10

 

0.34

 

Depreciation, depletion, and amortization

 

$

10,873

 

$

16,484

 

$

9.95

 

$

9.30

 

$

22,667

 

$

31,697

 

$

9.93

 

$

9.05

 

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 or six months ended June 30, 2019 or 2018. Unproved property was $1.9 million and $4.1 million at June 30, 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
June 30, 2019

 

Six Months Ended
June 30, 2019

 

Cash paid for amounts included in the measurement of lease liabilities:

 

 

 

 

 

Operating cash flows from operating leases

 

$

309

 

$

619

 

Amortization of right-of-use assets:

 

 

 

 

 

Operating leases

 

$

211

 

$

419

 

Balance sheet information related to the Company’s leases are included in the table below (in thousands):

 

 

June 30, 2019

 

Operating Leases

 

 

 

Right-of-use lease assets

 

4,437

 

Total operating lease ROU asset

 

$

4,437

 

 

 

 

 

Lease liabilities

 

$

1,180

 

Long-term lease liabilities

 

3,887

 

Total operating lease liabilities

 

$

5,067

 

 

 

 

 

Weighted-average remaining lease term

 

6.52 years

 

As of June 30, 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:

 

 

June 30, 2019

 

December 31, 2018

 

 

 

(in thousands)

 

Accrued oil and gas capital expenditures

 

$

4,103

 

$

1,534

 

Accrued revenue and royalty distributions

 

8,164

 

13,302

 

Accrued lease operating and workover expense

 

3,839

 

2,843

 

Accrued interest

 

68

 

209

 

Accrued taxes

 

935

 

1,813

 

Compensation and benefit related accruals

 

2,872

 

2,855

 

Other

 

668

 

2,965

 

Accrued liabilities

 

$

20,649

 

$

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):

 

 

Six Months Ended June 30,

 

 

 

2019

 

2018

 

Asset retirement obligations — beginning of period

 

$

8,087

 

$

15,506

 

Liabilities incurred

 

 

219

 

Revisions

 

 

 

Liabilities settled

 

 

(1

)

Liabilities eliminated through asset sales

 

 

(8,698

)

Current period accretion expense

 

317

 

547

 

Asset retirement obligations — end of period

 

$

8,404

 

$

7,573

 

10. Debt

Reserves-Based Revolving Credit Facility (“RBL”)

At June 30, 2019, and December 31, 2018, the Company maintained an RBL with a borrowing base of $170.0 million. During the six months ended June 30, 2019, the Company drew down $37.5 million, net on its RBL. At June 30, 2019 and December 31, 2018, the Company had $60.6 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 June 30, 2019, the Company had $107.5 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 June 30, 2019, the weighted average interest rate, excluding amortization expense of deferred financing costs and commitment fees, was 7.7%. Unamortized debt issuance costs of $0.9 million and $1.2 million associated with the RBL are included in other noncurrent assets on the unaudited interim condensed consolidated balance sheets at June 30, 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 six months ended June 30, 2019, the Company partially funded the stock buyback by drawing down $39.0 million from its 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 June 30, 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 June 30, 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 six months ended June 30, 2019:

 

 

Common
Stock

 

Treasury
Stock(1)

 

Share count as of December 31, 2018

 

25,520,170

 

(174,189

)

Common stock issued

 

100,696

 

 

Acquisition of treasury stock

 

 

(5,031,672

)

Retirement of treasury stock

 

(5,000,000

)

5,000,000

 

Share count as of June 30, 2019

 

20,620,866

 

(205,861

)


(1)                                 Treasury stock at June 30, 2019, and December 31, 2018, represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutoryeffective 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

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 are 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 Company established the 2016 LTIP and filed a Form S-8 with the SEC, registering 3,513,950 shares for issuance under the terms of the 2016 LTIP to employees, directors and certain other persons (the “Award Shares”). The types of awards that may be granted under the 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 as determined by the Compensation Committee of the Board of 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 June 30, 2019, 1,768,660 Award Shares remain available for issuance under the terms of the 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.

Restricted Stock Units

At June 30, 2019, the Company had 353,464 non-vested restricted stock units outstanding to employees and non-employee directors pursuant to the 2016 LTIP, excluding restricted stock units issued to non-employee directors containing a market condition, which are discussed below. During the six months ended June 30, 2019, 161,194 non-vested restricted stock units were issued to employees and non-employee directors. Restricted stock units granted to employees in 2019 under the 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. 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 Board (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 six months ended June 30, 2019, for the future cash settlement of these tendered shares upon vesting.

The following table summarizes the Company’s non-vested restricted stock unit award activity for the six months ended June 30, 2019:

 

 

Restricted Stock

 

Weighted Average
Grant Date
Fair Value

 

Non-vested shares outstanding at December 31, 2018

 

251,522

 

$

15.79

 

Granted

 

161,194

 

$

7.94

 

Vested(1)

 

(37,258

)

$

16.62

 

Forfeited

 

(21,994

)

$

13.70

 

Non-vested shares outstanding at June 30, 2019

 

353,464

 

$

12.25

 


(1)                     Restricted stock units which vested during the six months ended June 30, 2019 were accelerated as a result of a reduction in workforce that occurred during the period.

Unrecognized expense as of June 30, 2019, for all outstanding restricted stock units under the 2016 LTIP Plan was $1.7 million and will be recognized over a weighted average period of 0.9 years.

Stock Options

At June 30, 2019, the Company had 54,365 non-vested options outstanding pursuant to the 2016 LTIP. Stock Option Awards currently outstanding under 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 six months ended June 30, 2019.

The following table summarizes the Company’s 2016 LTIP non-vested stock option activity for the six months ended June 30, 2019:

 

 

Options

 

Range of
Exercise Prices

 

Weighted Average
Exercise Price

 

Weighted
Average
Remaining
Contractual
Term (Years)

 

Stock options outstanding at December 31, 2018

 

70,102

 

 

 

$

19.65

 

7.3

 

Granted

 

 

$

 

$

 

 

Vested(1)

 

(14,889

)

$

19.08–19.66

 

$

19.56

 

0.1

 

Forfeited

 

(848

)

$

19.66

 

$

19.66

 

 

Stock options outstanding at June 30, 2019

 

54,365

 

 

 

$

19.68

 

7.3

 

Vested and exercisable at end of period(2)

 

151,050

 

$

19.08-20.97

 

$

19.66

 

5.4

 


(1)                           Vested stock options during the six months ended June 30, 2019, were accelerated as a result of a reduction in workforce that occurred during the six months ended June 30, 2019.

(2)                           Vested and exercisable options at June 30, 2019, had no aggregate intrinsic value.

Unrecognized expense as of June 30, 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 0.3 years.

Non-Employee Director Restricted Stock Units Containing a Market Condition

On November 23, 2016, the Company issued restricted stock units to non-employee directors that contain a market vesting condition. These restricted stock units will vest (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’s common stock is equal to or greater than $30.00 or (ii) upon a change in control (as defined in the 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).

These restricted stock awards are accounted for as liability awards under FASB Accounting Standards Codification 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 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 June 30, 2019, the Company recorded a $0.1 million liability included within accrued liabilities on the unaudited interim condensed consolidated balance sheets, related to the 50,864 market condition awards outstanding. The weighted-average fair value of the restricted stock units containing a market condition was $0.27 at June 30, 2019.

As of June 30, 2019, there was no unrecognized stock-based compensation expense related to market condition awards.

Chief Executive Officer (“CEO”) Restricted Stock Units Containing a Market Condition

On November 1, 2017, the Company issued 135,778 restricted stock units to its CEO that contain a market vesting condition. These restricted stock units will vest, if at all, based on the Company’s total stockholder return for the performance period of October 25, 2017, through October 31, 2020. Market conditions under this grant are (i) with respect to 50% of the RSUs granted, the Company’s 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 (ii) with respect to the remaining 50% of the RSUs granted, the percentile rank of the Company’s 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 RSUs 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 CEO restricted stock units containing a market condition recognized as general and administrative expense by the Company was $0.1 million and $0.2 millionrates for the three and six months ended June 30, 2019. As2020 and 2019 are different from the statutory U.S. federal income tax rate primarily due to our recorded valuation allowances.

In March 2020, the President of June 30, 2019, unrecognized stock-based compensation relatedthe United States signed the CARES Act, to CEO RSUs containingstabilize the economy during the coronavirus pandemic. The CARES Act temporarily suspends and modifies certain tax laws established by the 2017 tax reform law known as the Tax Cuts and Jobs Act, including, but not limited to, modifications to net operating loss limitations, business interest limitations and alternative minimum tax. The CARES Act did not have a market condition was $0.7 million and will be recognized over a weighted-average period of 1.3 years.

2018 Performance Stock Units Issued to Certain Members of Executive Management Containing a Market Condition

On March 1, 2018, the Company issued 96,305 restricted stock units to certain members of executive management that contain a market vesting condition. These restricted stock units will vest, if at all, basedmaterial impact 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%.current year tax provision.

 

If a member of executive management terminates employment prior to vesting, the outstanding award is forfeited. Executive management restricted stock units with a market condition are subject to accelerated vesting in the event the executive’s employment is terminated prior to vesting by the Company without “Cause” or by the participant with “Good Reason” (each, as defined in the 2016 LTIP) or due to the executive’s death or disability. Upon a change in control (as defined in the 2016 LTIP), the compensation committee of the board of directors could (i) accelerate all or a portion of the award, (ii) cancel all of the award and pay cash, stock or combination equal to the change in control price, (iii) provide for the assumption or substitution or continuation by the successor company, (iv) certify to the extent to which the vesting conditions had been achieved prior to the conclusion of the performance period or (v) adjust restricted stock units to reflect the change in control.

 

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.

The 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 and $0.2 million for the three and six months ended June 30, 2019. As of June 30, 2019, unrecognized stock-based compensation related to executive management’s restricted stock units containing a market condition was $0.7 million and will be recognized over a weighted-average period of 1.5 years.

2019 Performance Stock Units Issued to Certain Members of Executive Management Containing a Market Condition

On March 7, 2019, the Company issued 193,921 restricted stock units to certain members of executive management that contain 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. To the extent that the price per common share of stock 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.

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.

The restricted stock units issued to executive management containing a market condition have a service period of two 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 $0.2 million and $0.3 million for the three and six months ended June 30, 2019. As of June 30, 2019, unrecognized stock-based compensation related to executive management’s restricted stock units containing a market condition was $1.1 million and will be recognized over a weighted-average period of 1.5 years.

12. Income Taxes

For the six months ended June 30, 2019, the Company recorded no income tax expense or benefit. The significant difference between our effective tax rate and the federal statutory income tax rate of 21% is primarily due to the effect of changes in the Company’s valuation allowance. During the six months ended June 30, 2019, the Company’s valuation allowance increased by $13.8 million from December 31, 2018, bringing the total valuation allowance to $123.4 million at June 30, 2019. A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its deferred tax assets are realizable.

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.

13. Income Per Share

The following table provides a reconciliation of net income attributable to common shareholders and weighted average common shares outstanding for basic and diluted income (loss) per share for the periods presented:

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2019

 

2018

 

2019

 

2018

 

 

 

(in thousands, except per
share amounts)

 

(in thousands, except per
share amounts)

 

Net Income (Loss):

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(36,948

)

$

(1,542

)

$

(54,755

)

$

2,461

 

Participating securities—non-vested restricted stock

 

 

 

 

(68

)

Basic and diluted income (loss)

 

$

(36,948

)

$

(1,542

)

$

(54,755

)

$

2,393

 

 

 

 

 

 

 

 

 

 

 

Common Shares:

 

 

 

 

 

 

 

 

 

Common shares outstanding — basic (1)

 

20,512

 

25,332

 

21,668

 

25,316

 

Dilutive effect of potential common shares

 

 

 

 

 

Common shares outstanding — diluted

 

20,512

 

25,332

 

21,668

 

25,316

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Per Share:

 

 

 

 

 

 

 

 

 

Basic

 

$

(1.80

)

$

(0.06

)

$

(2.53

)

$

0.09

 

Diluted

 

$

(1.80

)

$

(0.06

)

$

(2.53

)

$

0.09

 

Antidilutive stock options (2)

 

205

 

500

 

205

 

500

 

Antidilutive warrants (3)

 

6,980

 

6,626

 

6,980

 

6,626

 



(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 June 30, 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 vested as of June 30, 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.

14. Related Party Transactions

During 2017, the Company entered into an arrangement with EcoStim Energy Solutions, Inc. (“EcoStim”) 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 six months ended June 30, 2018. No transactions with EcoStim occurred during the six months ended June 30, 2019.

15. Commitments and Contingencies

The Company is involved in various matters incidental to its operations and business 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 could have a material effect on its results of operations. As of June 30, 2019, the Company did not have an accrual for loss contingencies. As of December 31, 2018, the Company’s total accrual for all loss contingencies was $1.1 million.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussionManagement’s Discussion and analysisAnalysis of our financial conditionFinancial Condition and resultsResults of operationsOperations should be read in conjunction with our consolidated financial statementsthe Unaudited Condensed Consolidated Financial Statements and accompanying notes thereto for the year ended December 31, 2018, and the related management’s discussion and analysisin “Item 1. Financial Statements” contained in our annual report on Form 10-K dated and filed with the Securities and Exchange Commission (“SEC”) on March 14, 2019, as well as the unaudited interim condensed consolidated financial statements and notes thereto included in this quarterly report on Form 10-Qherein and our quarterly report onAnnual Report the Amplify Form 10-Q for the quarter ended March 31, 2019, filed with the SEC on May 10, 2019.

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 reserves at economical costsproperties 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, 2019:

Our total estimated proved reserves were approximately 163.0 MBoe, of which approximately 43% were oil and 80% were classified as proved developed reserves;

We produced from 2,643 gross (1,567 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, 2019 was 29.9 MBoe/d, implying a reserve-to-production ratio of approximately 15 years.

Industry Trends and Outlook

In March 2020, the World Health Organization declared the outbreak of COVID-19 as a pandemic, which continues to spread throughout the United States. The spread of COVID-19 has caused significant volatility in U.S. and international markets. There is criticalsignificant uncertainty around the breadth and duration of business disruptions related to our long-term success.COVID-19, as well as its impact on the U.S. and international economies and, as such, the Company is unable to determine the extent of the impact caused by the COVID-19 pandemic to the Company’s operations.

Definitive Merger Agreement

On May 6, 2019, we entered into a definitive merger agreement (“Merger Agreement”) pursuantIn addition, oil prices severely declined following unsuccessful negotiations between members of OPEC and certain nonmembers, including Russia, to which Amplify Energy Corp. (“Amplify”) will merge with a subsidiary of oursimplement production cuts in an all-stock merger-of-equals. Undereffort to decrease the termsglobal oversupply and to rebalance supply and demand due to the ongoing COVID-19 pandemic. In April 2020, members of OPEC and Russia agreed to temporary production reductions, but uncertainty about whether such production cuts and/or the duration of such reductions will be sufficient to rebalance supply and demand remains and may continue for the foreseeable future. We anticipate further market and commodity price volatility for the remainder of 2020 as a result of the Merger Agreement, Amplify stockholders will receive 0.933 shares of newly issued common stock for each Amplify share of common stock. The merger is expected to close on August 6, 2019, at which time Amplify and our stockholders will each own 50% of the outstanding shares of the combined entity.

events described above.

The transactionreductions in commodity prices have resulted in lower levels of cash flow from operating activities. In addition, the borrowing base under our Revolving Credit Facility is subject to the terms and conditions set forth in the Merger Agreement, including holders ofredetermination on at least a majority 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 listedsemi-annual basis primarily based on the NYSE and other customary conditions.  All such conditions were satisfied as of August 5, 2019.

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 employee of ours is 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, (i)an engineering report with respect to any employeeour estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, adjusted for the impact of ours whose employment is terminated without “cause” (as such term is definedour commodity derivative contracts. Severely reduced commodity prices contributed to a reduction in our borrowing base during the Spring 2020 determination process, and continued low prices may adversely impact subsequent redeterminations. The reduction in commodity prices has directly led to an impairment of our oil and natural gas properties. There may be further impairments in future periods if commodity prices remain depressed.

The Company has executed several significant initiatives to better position the Company through the downturn, including significant decreases to operating and general and administrative expenses, substantial reductions to capital programs, the monetization of a portion of the Company’s 2021 in-the-money crude oil hedges, the receipt of loan proceeds from the federal government PPP program, Beta royalty relief and the suspension of the quarterly dividend.


Recent Developments

Beta Royalty Relief

On, June 24, 2020, the Bureau of Safety and Environmental Enforcement (“BSEE”) informed the Company that it had been approved for the Special Case Royalty Relief for the Company’s interests in three Pacific Outer Continental Shelf blocks (P-300, P-0301, and P-0306), referred to as the Beta unit in the applicable Parent Benefit Plan, but also including certain employees who are deemedBeta Field located in federal waters approximately 11 miles offshore from the Port of Long Beach, California. The royalty relief was effective beginning July 1, 2020 for the Beta leases. On the Company’s two primary producing leases, the royalty rate was reduced from 25% to 12.5%, and on the third lease, the royalty rate was reduced from 16.67% to 8.33%.

The royalty relief rates will be terminated without cause pursuantsuspended in months in which the weighted average NYMEX oil and Henry Hub gas price exceeds $66.19 per BOE which represents a 25% premium to the Merger Agreement) on or within one year afteraverage realized price recognized by the closing ofCompany during the merger, (A) all Parent Stock Options (as definedqualification period. The royalty relief would end in the Merger Agreement) held by such employee shall become fully vested, (B) all Parent RSUs (as defined inevent that the Merger Agreement) held by such employee shall become fully vestedCompany generates no benefit from the royalty relief rates due to either higher production or realized pricing for 12 consecutive months.

Cure of Non-Compliance with NYSE Continued Listing Standards

On June 2, 2020, the Company received written notification from the NYSE that the Company regained compliance with the NYSE’s continued listing standards. The Company regained compliance after its average closing price for the 30 trading-day period ended May 29, 2020 and shall be settled promptly upon termination, (C) all Parent PSUs (as defined inits closing price on May 29, 2020 both exceeded $1.00 per share. The “.BC” indicator has been removed from the Merger Agreement) that are subjectCompany’s common shares, and the Company was removed from the NYSE list of non-compliant issuers.

Departure of Director

On June 22, 2020, Scott L. Hoffman notified the Company of his intent to resign from 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 owingof the Company, effective June 23, 2020. Mr. Hoffman served as a member and Chairman of the Nominating and Governance Committee of the board of directors. There were no known disagreements between Mr. Hoffman and the Company which led to such employee(s) shall be paid promptly upon termination, (ii) all Parent RSUs held by membersMr. Hoffman’s resignation from the board of directors. On June 23, 2020, Christopher W. Hamm, a current member of the board of directors, shall become fully vestedwas appointed to serve as a member and shall be settled promptly upon the closingChairman of the merger,Nominating and (iii) all cash amounts pursuant to the Equalization Program that are owing to our non-employee directors shall be paid promptly upon the closingGovernance Committee of the merger.board of directors.

Retirement of President, Chief Executive Officer and Director

On April 1, 2020, Mr. Kenneth Mariani notified the board of directors of the Company of his decision to retire. Mr. Mariani vacated his service as President and Chief Executive Officer of the Company and as a member of the board of directors, effective April 3, 2020. Mr. Mariani’s decision to retire stems solely from personal reasons and did not result from any disagreement with the Company, the Company’s management or the board of directors.

Appointment of Interim Chief Executive Officer

Effective upon Mr. Mariani’s retirement, Mr. Martyn Willsher was appointed the Company’s Interim Chief Executive Officer. Mr. Willsher continues to serve in his role as Senior Vice President and Chief Financial Officer of the Company.

Business Environment and Operational Focus

We estimate that between 500,000use a variety of financial and 800,000 unvested stock awards (including stock options) will vest upon closingoperational metrics to assess the performance of our oil and between $8.5 million 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.

Operations Update

Mississippian Lime

The following table presents our average dailynatural gas operations, including: (i) production from our Mississippian Lime asset for the periods presented:

 

 

Three Months Ended
June 30, 2019

 

Three Months Ended
March 31, 2019

 

Decrease in
Production

 

 

 

 

 

 

 

 

 

Average daily production:

 

 

 

 

 

 

 

Oil (Bbls)

 

2,753

 

3,381

 

(18.6

)%

Natural gas liquids (Bbls)

 

3,250

 

3,538

 

(8.1

)%

Natural gas (Mcf)

 

36,032

 

37,919

 

(5.0

)%

Net Boe/day

 

12,008

 

13,239

 

(9.3

)%

In the second quarter of 2019, we incurred approximately $10.7 million of operational capital expenditures in the Mississippian Lime basin.

Anadarko Basin

On May 31, 2018, we closedvolumes; (ii) realized 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 (as defined below).

Sources of closing adjustments).

Capital Expenditures

During the three and six months ended June 30, 2019, we incurred operational capital expenditures of $10.7 million and $17.2 million, respectively, in the Mississippian Lime basin, which consisted of the following:

 

 

For the Three
Months Ended
June 30, 2019

 

For the Six
Months Ended
June 30, 2019

 

Drilling and completion activities

 

$

10,335

 

$

15,670

 

Acquisition of acreage and seismic data

 

380

 

1,488

 

Operational capital expenditures incurred

 

$

10,715

 

$

17,158

 

Capitalized G&A, office, ARO & other

 

(16

)

54

 

Capitalized interest

 

44

 

147

 

Total capital expenditures incurred

 

$

10,743

 

$

17,359

 

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. For the three and six months ended June 30, 2019, the results of our full cost “ceiling test” required us to recognize impairments of our oil and gas properties of $33.6 million and $43.2 million, respectively. While these impairments did not impact cash flows from operating activities or liquidity, they 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 in the Arbuckle formation, 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 9 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 tables summarize our revenues for the periods indicated (in thousands):

 

 

Crude Oil

 

Natural Gas

 

NGLs

 

Total

 

Revenues for the three months ended June 30, 2018

 

$

34,202

 

$

6,782

 

$

11,893

 

$

52,877

 

Changes due to volumes

 

(17,318

)

(2,385

)

(3,543

)

(23,246

)

Changes due to price

 

(2,330

)

(1,229

)

(3,374

)

(6,933

)

Revenues for the three months ended June 30, 2019

 

$

14,554

 

$

3,168

 

$

4,976

 

$

22,698

 

 

 

Crude Oil

 

Natural Gas

 

NGLs

 

Total

 

Revenues for the six months ended June 30, 2018

 

$

66,616

 

$

15,119

 

$

22,931

 

$

104,666

 

Changes due to volumes

 

(30,622

)

(4,780

)

(6,267

)

(41,669

)

Changes due to price

 

(5,113

)

(561

)

(5,472

)

(11,146

)

Revenues for the six months ended June 30, 2019

 

$

30,881

 

$

9,778

 

$

11,192

 

$

51,851

 

Oil, NGLs and Natural Gas Pricing

The following tables set forth information regarding average realized sales prices for the periods indicated (per BOE):

 

 

For the Three

 

For the Three

 

 

 

For the Six

 

For the Six

 

 

 

 

 

Months Ended

 

Months Ended

 

%

 

Months Ended

 

Months Ended

 

%

 

 

 

June 30, 2019

 

June 30, 2018

 

Change

 

June 30, 2019

 

June 30, 2018

 

Change

 

AVERAGE SALES PRICES:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, without realized derivatives (per Bbl)

 

$

58.09

 

$

67.42

 

(13.8

)%

$

55.65

 

$

64.89

 

(14.2

)%

Oil, with realized derivatives (per Bbl)

 

$

58.48

 

$

59.95

 

(2.5

)%

$

57.67

 

$

59.76

 

(3.5

)%

Natural gas liquids, without realized derivatives (per Bbl)

 

$

16.82

 

$

28.24

 

(40.4

)%

$

18.22

 

$

27.14

 

(32.9

)%

Natural gas liquids, with realized derivatives (per Bbl)

 

$

16.82

 

$

28.24

 

(40.4

)%

$

18.22

 

$

27.14

 

(32.9

)%

Natural gas, without realized derivatives (per Mcf)

 

$

0.97

 

$

1.34

 

(27.6

)%

$

1.46

 

$

1.55

 

(5.8

)%

Natural gas, with realized derivatives (per Mcf)

 

$

1.01

 

$

1.39

 

(27.3

)%

$

1.45

 

$

1.71

 

(15.2

)%

Oil, NGLs and Natural Gas Production

 

 

For the Three
Months

 

For the Three
Months

 

 

 

For the Six
Months

 

For the Six
Months

 

 

 

 

 

Ended June
30, 2019

 

Ended June
30, 2018

 

%
Change

 

Ended June
30, 2019

 

Ended June
30, 2018

 

%
Change

 

PRODUCTION DATA:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbls/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

Mississippian Lime

 

2,753

 

4,833

 

(43.0

)%

3,066

 

4,699

 

(34.8

)%

Anadarko Basin(1)

 

 

1,110

 

(100.0

)%

 

1,168

 

(100.0

)%

Natural gas liquids (Bbls/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

Mississippian Lime

 

3,250

 

3,995

 

(18.6

)%

3,393

 

3,821

 

(11.2

)%

Anadarko Basin(1)

 

 

946

 

(100.0

)%

 

1,017

 

(100.0

)%

Natural gas (Mcf/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

Mississippian Lime

 

36,032

 

50,246

 

(28.3

)%

36,970

 

47,083

 

(21.5

)%

Anadarko Basin(1)

 

 

7,956

 

(100.0

)%

 

8,365

 

(100.0

)%

Combined (Boe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

Mississippian Lime

 

12,008

 

17,202

 

(30.2

)%

12,620

 

16,367

 

(22.9

)%

Anadarko Basin(1)

 

 

3,382

 

(100.0

)%

 

3,579

 

(100.0

)%


(1)                     We divested our Anadarko Basin assets during the second quarter of 2018.

Oil Revenues

Oil volumes in the Mississippian Lime decreased 2,080 Boe/day and 1,633 Boe/day, or 43.0% and 34.8%, respectively, for the three and six months ended June 30, 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 $9.33 per barrel and $9.24 per barrel, or 13.8% and 14.2%, respectively, largely as a result of a decrease in prevailing market prices.

NGLs Revenues

NGLs volumes in the Mississippian Lime decreased 745 Boe/day and 428 Boe/day, or 18.6% and 11.2%, respectively, for the three and six months ended June 30, 2019, primarily as a result of reduced drilling activity and natural decline. Average NGLs sales prices, without realized derivatives, decreased by $11.42 per barrel and $8.92 per barrel, or 40.4% and 32.9%, respectively, largely as a result of lower oil prices, which correlate with NGLs pricing.

Natural Gas Revenues

Natural gas volumes in the Mississippian Lime decreased 14,214 Mcf/day and 10,113 Mcf/day, or 28.3% and 21.5%, respectively, for the three and six months ended June 30, 2019, primarily as a result of reduced drilling activity and natural decline. Average natural gas sales prices, without realized derivatives, decreased by $0.37 per MCf and $0.09 per Mcf, or 27.6% and 5.8%, respectively, largely due to lower prevailing index prices at our delivery points.

Gains/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
Months Ended
June 30, 2019

 

For the Three
Months Ended
June 30, 2018

 

For the Six
Months Ended
June 30, 2019

 

For the Six
Months Ended
June 30, 2018

 

Cash receipts (payments on settlement)

 

 

 

 

 

 

 

 

 

Oil derivatives

 

$

98

 

$

(3,776

)

$

1,116

 

$

(5,252

)

Natural gas derivatives

 

155

 

258

 

(94

)

1,575

 

Total cash settlements

 

$

253

 

$

(3,518

)

$

1,022

 

$

(3,677

)

 

 

 

 

 

 

 

 

 

 

Gains (losses) due to fair value changes

 

 

 

 

 

 

 

 

 

Oil derivatives

 

$

1,168

 

$

(6,986

)

$

(7,510

)

$

(9,390

)

Natural gas derivatives

 

1,120

 

(844

)

1,297

 

(2,220

)

Total gains (losses) on fair value changes

 

$

2,288

 

$

(7,830

)

$

(6,213

)

$

(11,610

)

 

 

 

 

 

 

 

 

 

 

Gains (losses) on commodity derivative contractsnet

 

$

2,541

 

$

(11,348

)

$

(5,191

)

$

(15,287

)

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
June 30,

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

 

2019

 

2018

 

2019

 

2018

 

2019

 

2018

 

2019

 

2018

 

 

 

(in thousands)

 

(per Boe)

 

(in thousands)

 

(per Boe)

 

EXPENSES:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating and workover

 

$

9,911

 

$

16,952

 

$

9.07

 

$

9.57

 

$

18,901

 

$

31,760

 

$

8.27

 

$

9.07

 

Gathering and transportation

 

63

 

67

 

0.06

 

0.04

 

82

 

124

 

0.04

 

0.04

 

Severance and other taxes

 

1,572

 

2,776

 

1.44

 

1.57

 

3,505

 

5,638

 

1.53

 

1.61

 

Asset retirement accretion

 

160

 

250

 

0.15

 

0.14

 

317

 

547

 

0.14

 

0.16

 

Depreciation, depletion, and amortization

 

10,873

 

16,484

 

9.95

 

9.30

 

22,667

 

31,697

 

9.93

 

9.05

 

Impairment of oil and gas properties

 

33,557

 

 

30.70

 

 

43,210

 

 

18.92

 

 

General and administrative

 

5,238

 

5,190

 

4.80

 

2.93

 

11,676

 

15,047

 

5.11

 

4.30

 

Advisory fees

 

 

850

 

 

0.48

 

 

850

 

 

0.24

 

Total expenses

 

$

61,374

 

$

42,569

 

$

56.17

 

$

24.03

 

$

100,358

 

$

85,663

 

$

43.94

 

$

24.47

 

Lease Operating and Workover

Lease operating and workover expenses decreased $7.0 million and $12.9 million, or 41.5% and 40.5%, to $9.9 million and $18.9 million, respectively, for the three and six months ended June 30, 2019. 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 $9.07 per Boe and $8.27 per Boe, during the three and six months ended June 30, 2019NGLs that are extracted from $9.57 per Boe and $9.07 per Boe during the related periods in 2018, decreases of $0.50 per Boe and $0.80 per Boe, or 5.2% and 8.8%, respectively, largely as a result of decreased workover activity during the 2019 period.

Gathering and Transportation

Gathering and transportation expenses decreased 6.0% and 33.9%, respectively, for the three and six months ended June 30, 2019. These decreases in gathering and transportation expenses are 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 June 30,

 

Six Months Ended June 30,

 

 

 

2019

 

2018

 

2019

 

2018

 

 

 

(in thousands)

 

(in thousands)

 

Total oil, NGLs and natural gas sales

 

$

22,698

 

$

52,877

 

$

51,851

 

$

104,666

 

 

 

 

 

 

 

 

 

 

 

Severance taxes

 

1,569

 

2,655

 

3,499

 

5,336

 

Ad valorem and other taxes

 

3

 

121

 

6

 

302

 

Severance and other taxes

 

$

1,572

 

$

2,776

 

$

3,505

 

$

5,638

 

Severance taxes as a percentage of sales

 

6.9

%

5.0

%

6.7

%

5.1

%

Severance and other taxes as a percentage of sales

 

6.9

%

5.2

%

6.8

%

5.4

%

Severance and other taxes increased to 6.9% and 6.8% as a percentage of sales forbecause hedge accounting is not elected, the three and six months ended June 30, 2019, as compared to 5.2% and 5.4% for the three and six months ended June 30, 2018. These increases in severance taxes as a percentage of sales for the 2019 period were primarily the result of legislative changes in the State of Oklahoma which increased 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. Beginning in July 2018, this legislation increased the incentive tax rate to 5.0% for all new and existing wells that previously qualified for the 2.0% incentive tax rate.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expense decreased $5.6 million and $9.0 million, or 34.0% and 28.5%, to $10.9 million and $22.7 million, respectively, for the three and six months ended June 30, 2019, compared to $16.5 million and $31.7 million for the three and six months ended June 30, 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 and six months ended June 30, 2018. Depreciation, depletion and amortization per Boe increased $0.65 per Boe and $0.88 per Boe during the three and six months ended June 30, 2019, to $9.95 per Boe and $9.93 per Boe from $9.30 per Boe and $9.05 per Boe for the three and six months ended June 30, 2018. Our depletion rate has increased for the three and six months ended June 30, 2019 compared to prior year primarily as a result of decreased proved reserves volumes from the prior year.

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 unaudited interim condensed consolidated statements of operations.

During the three and six months ended June 30, 2019, we recorded impairment charges of $33.6 million and $43.2 million, respectively. These impairment expenses recognized during the periods were primarily due to decreases 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 remained relatively unchanged during the three months ended June 30, 2019 when compared to the same period in prior year. G&A expenses decreased $3.4 million, or 22.4%, to $11.7 million, for the six months ended June 30, 2019, compared to $15.0 million for the six months ended June 30, 2018. The decrease in G&A expenses during the six months ended June 30, 2019 is primarily due to reductions-in-force that occurred in both the six months ended 2019 and 2018, resulting in a $2.1 million decrease in share based compensation expense in the 2019 period. Additionally, there was a $0.9 million decrease in cost related to our review of various strategic options as compared to the six months ended June 30, 2018.

Other Income (Expense)

 

 

For the Three Months Ended
June 30,

 

For the Six Months Ended
June 30,

 

 

 

2019

 

2018

 

2019

 

2018

 

 

 

(in thousands)

 

(in thousands)

 

OTHER EXPENSE

 

 

 

 

 

 

 

 

 

Interest income

 

$

4

 

$

5

 

$

9

 

$

24

 

Interest expense

 

(1,229

)

(1,308

)

(2,094

)

(3,104

)

Amortization of deferred financing costs

 

(174

)

(108

)

(348

)

(216

)

Capitalized interest

 

44

 

114

 

146

 

191

 

Interest expense—net of amounts capitalized

 

(1,359

)

(1,302

)

(2,296

)

(3,129

)

 

 

 

 

 

 

 

 

 

 

Total other income (expense)

 

$

(1,355

)

$

(1,297

)

$

(2,287

)

$

(3,105

)

Interest Expense

Interest expense was $1.4 million for the three months ended June 30, 2019, an increase of 4.4%, from $1.3 million for the three months ended June 30, 2018. Interest expense was $2.3 million for the six months ended June 30, 2019, a decrease of 26.6%, from $3.1 million for the six months ended June 30, 2018. Our average outstanding balance under our revolving credit facility was $60.6 million and $50.5 million during the three and six months ended June 30, 2019, compared to $65.5 million and $89.2 million for the three and six months ended June 30, 2018. Total interest expense capitalized to oil and gas properties was $0.1 million for the three months ended June 30, 2019 and 2018, respectively. Total interest expense capitalized to oil and gas properties was $0.1 million and $0.2 million for the six months ended June 30, 2019 and 2018, respectively.

Provision for Income Taxes

We recorded no income tax expense or benefit for the three and six months ended June 30, 2019 or 2018, respectively, due to the change in our valuation allowance recorded against our net deferred tax assets. Our valuation allowances were $123.4 million and $119.4 million for the six months ended June 30, 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):

 

 

June 30, 2019

 

December 31, 2018

 

Cash and cash equivalents

 

$

4,797

 

$

11,341

 

Net working capital (deficit)

 

(3,495

)

13,946

 

Total long-term debt

 

60,559

 

23,059

 

Total stockholders’ equity

 

437,561

 

541,677

 

Available borrowing capacity

 

107,500

 

145,000

 

Our decisions regarding capital structure, hedging and drillingAmplify 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 June 30, 2019, in addition to cash on hand of $4.8 million, we maintained the RBL. The RBL has a current borrowing base of $170.0 million. At June 30, 2019, we had $60.6 million drawn on the RBL and outstanding letters of credit obligations totaling $1.9 million. As a result, at June 30, 2019, we had $107.5 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. For the six months ended June 30, 2019, the weighted average interest rate was 7.7%, excluding amortization expense of deferred financing costs and commitment fees.

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 June 30, 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 Six Months
Ended June 30, 2019

 

For the Six Months
Ended June 30, 2018

 

Net cash provided by operating activities

 

$

25,318

 

$

49,292

 

Net cash used in investing activities

 

(19,094

)

(11,056

)

Net cash used in financing activities

 

(12,768

)

(100,478

)

Net change in cash

 

$

(6,544

)

$

(62,242

)

Cash flows provided by operating activities

Net cash provided by operating activities was $25.3 millionopinion, are subjective in nature, require the use of professional judgment and $49.3 million for the six months ended June 30, 2019 and 2018, respectively. The decrease in net cash provided by operating activities was primarily the result of a $53.4 million decrease in revenues from contracts with customers, partially offset by payments received for the settlement of certain derivatives of $1.0 million as compared to payments for derivative settlements of $3.7 million, a decrease in general and administrative expenses of $3.4 million, a decrease in lease operating and workover expenses of $12.9 million and an increase in the change of working capital of $6.1 million for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018.

Cash flows used in investing activities

Net cash used in investing activities were $19.1 million and $11.1 million for the six months ended June 30, 2019 and 2018, respectively. Substantially all of our capital spend is invested into our Mississippi Lime asset, and the decrease year-over-year, after consideration of the sale of our Anadarko Basin assets in May of 2018, is the result of our decision to pause drilling beginning in the fourth quarter of 2018.

Cash flows used in financing activities

Net cash used in financing activities was $12.8 million and $100.5 million for the six months ended June 30, 2019 and 2018, respectively. During the six months ended June 30, 2019, we drew down $37.5 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 discussionThe results of operations for the three and six months ended June 30, 2020 and 2019 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 Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

 

($ In thousands)

 

Oil and natural gas sales

$

34,888

 

 

$

59,485

 

 

$

92,675

 

 

$

124,552

 

Lease operating expense

 

27,828

 

 

 

26,292

 

 

 

63,551

 

 

 

55,202

 

Gathering, processing and transportation

 

4,689

 

 

 

4,391

 

 

 

9,742

 

 

 

9,048

 

Taxes other than income

 

2,195

 

 

 

3,464

 

 

 

6,181

 

 

 

7,873

 

Depreciation, depletion and amortization

 

7,623

 

 

 

12,913

 

 

 

23,179

 

 

 

24,079

 

Impairment expense

 

 

 

 

 

 

 

455,031

 

 

 

 

General and administrative expense

 

6,755

 

 

 

10,566

 

 

 

15,108

 

 

 

19,874

 

Accretion of asset retirement obligations

 

1,539

 

 

 

1,332

 

 

 

3,052

 

 

 

2,643

 

(Gain) loss on commodity derivative instruments

 

19,165

 

 

 

(22,993

)

 

 

(88,548

)

 

 

9,494

 

Interest expense, net

 

(6,209

)

 

 

(4,422

)

 

 

(13,856

)

 

 

(8,511

)

Reorganization items, net

 

(166

)

 

 

(464

)

 

 

(352

)

 

 

(651

)

Income tax benefit (expense)

 

(85

)

 

 

 

 

 

(85

)

 

 

50

 

Net income (loss)

 

(41,336

)

 

 

18,641

 

 

 

(408,535

)

 

 

(12,836

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas revenue:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

$

22,963

 

 

$

41,685

 

 

$

64,814

 

 

$

81,742

 

NGL sales

 

3,343

 

 

 

5,336

 

 

 

8,465

 

 

 

11,201

 

Natural gas sales

 

8,582

 

 

 

12,464

 

 

 

19,396

 

 

 

31,609

 

Total oil and natural gas revenue

$

34,888

 

 

$

59,485

 

 

$

92,675

 

 

$

124,552

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

945

 

 

 

696

 

 

 

1,927

 

 

 

1,448

 

NGLs (MBbls)

 

435

 

 

 

258

 

 

 

889

 

 

 

524

 

Natural gas (MMcf)

 

6,857

 

 

 

5,803

 

 

 

14,443

 

 

 

11,293

 

Total (MBoe)

 

2,523

 

 

 

1,921

 

 

 

5,223

 

 

 

3,854

 

Average net production (MBoe/d)

 

27.7

 

 

 

21.1

 

 

 

28.7

 

 

 

21.3

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average sales price:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

$

24.30

 

 

$

59.85

 

 

$

33.64

 

 

$

56.44

 

NGL (per Bbl)

 

7.68

 

 

 

20.65

 

 

 

9.52

 

 

 

21.38

 

Natural gas (per Mcf)

 

1.25

 

 

 

2.15

 

 

 

1.34

 

 

 

2.80

 

Total (per Boe)

$

13.83

 

 

$

30.95

 

 

$

17.74

 

 

$

32.32

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average unit costs per Boe:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expense

$

11.03

 

 

$

13.69

 

 

$

12.17

 

 

$

14.32

 

Gathering, processing and transportation

 

1.86

 

 

 

2.29

 

 

 

1.87

 

 

 

2.35

 

Taxes other than income

 

0.87

 

 

 

1.80

 

 

 

1.18

 

 

 

2.04

 

General and administrative expense

 

2.68

 

 

 

5.50

 

 

 

2.89

 

 

 

5.16

 

Depletion, depreciation and amortization

 

3.02

 

 

 

6.72

 

 

 

4.44

 

 

 

6.25

 

For the three months ended June 30, 2020 compared to the three months ended June 30, 2019

Net loss of $41.3 million and net income of $18.6 million were recorded for the three months ended June 30, 2020 and 2019, respectively.


Oil, natural gas and NGL revenues were $34.9 million and $59.5 million for the three months ended June 30, 2020 and 2019, respectively. Average net production volumes were approximately 27.7 MBoe/d and 21.1 MBoe/d for the three months ended June 30, 2020 and 2019, respectively. The increase in production volumes was primarily due to the Merger. The average realized sales price was $13.83 per Boe and $30.95 per Boe for the three months ended June 30, 2020 and 2019, respectively. The decrease in average realized sales price is primarily due to decrease in commodity prices. The overall decrease in revenue is due to a decline in well activity and a decrease in commodity pricing offset by additional volumes related to the Merger.

Lease operating expense was $27.8 million and $26.3 million for the three months ended June 30, 2020 and 2019, respectively. The change in lease operating expense was primarily related to the Merger. On a per Boe basis, lease operating expense was $11.03 and $13.69 for the three months ended June 30, 2020 and 2019, respectively. The change on a per Boe basis is related to decreased drilling activities, cost savings initiatives implemented during the quarter and an increase in production due to the Merger.

Gathering, processing and transportation was $4.7 million and $4.4 million for the three months ended June 30, 2020 and 2019, respectively. The increase in gathering, processing and transportation was primarily driven by the Merger. On a per Boe basis, gathering, processing and transportation was $1.86 and $2.29 for the three months ended June 30, 2020 and 2019, respectively. The change on a per Boe basis was primarily due to increased production related to the Merger.

Taxes other than income was $2.2 million and $3.5 million for the three months ended June 30, 2020 and 2019, respectively. On a per Boe basis, taxes other than income were $0.87 and $1.80 for the three months ended June 30, 2020 and 2019, respectively. The change in taxes other than income on a per Boe basis was primarily due to a decrease in commodity prices.

Depreciation, depletion and amortization (“DD&A expense”) was $7.6 million and $12.9 million for the three months ended June 30, 2020 and 2019, respectively. The change in DD&A expense is primarily due to the first quarter 2020 impairment which reduced depletable oil and gas property. The decrease was also impacted by the Merger and lower production.

General and administrative expense was $6.8 million and $10.6 million for the three months ended June 30, 2020 and 2019, respectively. The change in general and administrative expense is primarily related to a decrease in acquisition expense of $3.4 million and a decrease in stock compensation expense of $0.9 million due to the revaluation of post-merger expense.

Net losses on commodity derivative instruments of $19.2 million were recognized for the three months ended June 30, 2020, consisting of $64.4 million decrease in the fair value of open positions offset by $27.3 million of cash settlements received on expired positions and $18.0 million of cash settlements received on terminated positions. Net gains on commodity derivative instruments of $23.0 million were recognized for the three months ended June 30, 2019, consisting of $23.6 million increase in fair value of open positions and offset by $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 $6.2 million and $4.4 million for the three months ended June 30, 2020 and 2019, respectively. Interest expense included a $2.7 million and $0.3 million in the amortization and write-off of deferred financing fees for the three months ended June 30, 2020 and 2019, respectively. Losses incurred on interest rate swaps was approximately $0.4 million and $0.6 million for the three months ended June 30, 2020 and 2019, respectively.

Average outstanding borrowings under our Revolving Credit Facility were $287.5 million and $259.3 million for the three months ended June 30, 2020 and 2019, respectively.

For the six months ended June 30, 2020 compared to the six months ended June 30, 2019

Net losses of $408.5 million and $12.8 million were recorded for the six months ended June 30, 2020 and 2019, respectively.

Oil, natural gas and NGL revenues were $92.7 million and $124.6 million for the six months ended June 30, 2020 and 2019, respectively. Average net production volumes were approximately 28.7 MBoe/d and 21.3 MBoe/d for the six months ended June 30, 2020 and 2019, respectively. The change in production volumes was primarily due to the Merger offset with the natural decline of wells and decreased drilling activity. The average realized sales price was $17.74 per Boe and $32.32 per Boe for the six months ended June 30, 2020 and 2019, respectively. The decrease in average realized sales price is primarily due to decrease in commodity prices. The overall decrease in revenue is due to a decline in well activity and a decrease in commodity pricing offset by additional volumes related to the Merger.


Lease operating expense was $63.6 million and $55.2 million for the six months ended June 30, 2020 and 2019, respectively. The change in lease operating expense was primarily related to the Merger. On a per Boe basis, lease operating expense was $12.17 and $14.32 for the six months ended June 30, 2020 and 2019, respectively. The change on a per Boe basis is related to decreased drilling activities, cost savings initiatives implemented during the quarter and an increase in production due to the Merger.

Gathering, processing and transportation was $9.7 million and $9.0 million for the six months ended June 30, 2020 and 2019, respectively. The increase in gathering, processing and transportation was primarily driven by the Merger. On a per Boe basis, gathering, processing and transportation was $1.87 and $2.35 for the six months ended June 30, 2020 and 2019, respectively. The change on a per Boe basis was primarily due to increased production related to the Merger.

Taxes other than income was $6.2 million and $7.9 million for the six months ended June 30, 2020 and 2019, respectively. On a per Boe basis, taxes other than income were $1.18 and $2.04 for the six months ended June 30, 2020 and 2019, respectively. The change in taxes other than income on a per Boe basis was primarily due to a decrease in commodity prices.

DD&A expense was $23.2 million and $24.1 million for the six months ended June 30, 2020 and 2019, respectively. The change in DD&A expense was primarily due to the first quarter impairment which reduced depletable oil and gas property.

Impairment expense was $455.0 million for the six months ended June 30, 2020. We recognized $405.7 million of impairment expense on proved properties. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. We recognized $49.3 million of impairment expense on unproved properties, which was related to expiring leases and the evaluation of qualitative and quantitative factors related to the current decline in commodity prices. No impairment expense was recorded for the six months ended June 30, 2019.

General and administrative expense was $15.1 million and $19.9 million for the six months ended June 30, 2020 and 2019, respectively. The change in general and administrative expense is primarily related to a decrease of $3.3 million in acquisition costs and a decrease of stock compensation expense of $1.9 million.

Net gains on commodity derivative instruments of $88.5 million were recognized for the six months ended June 30, 2020, consisting of $30.8 million increase in the fair value of open positions, $39.8 million of cash settlements paid on expired positions and $18.0 million of cash settlements received on terminated positions. Net losses on commodity derivative instruments of $9.5 million were recognized for the six months ended June 30, 2019, consisting of $7.6 million decrease in the fair value of open positions and $1.9 million of cash settlement receipts on expired positions.

Interest expense, net was $13.9 million and $8.5 million for the six months ended June 30, 2020 and 2019, respectively. The change in interest expense is primarily due to a $1.5 million reduction in interest expense due to lower outstanding borrowings for the six months ended June 30, 2020. The Company had $3.0 million and $0.6 million in amortization and write-off of deferred financing fees for the six months ended June 30, 2020 and 2019, respectively. In addition we had losses on interest rate swaps of approximately $4.1 million and $0.5 million for the six months ended June 30, 2020 and 2019 respectively.

Average outstanding borrowings under our Revolving Credit Facility were $291.3 million and $268.6 million for the six months ended June 30, 2020 and 2019, respectively.

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;

DD&A;

Impairment of goodwill and long-lived assets (including oil and natural gas properties);

Accretion of 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;

Reorganization items, net;

Severance payments; and

Other non-routine items that we deem appropriate.

Less:

Interest income;

Income tax benefit;

Gain on commodity derivative instruments;

Cash settlements paid on expired commodity derivative instruments;

Gains on sale of assets and other, net; and

Other non-routine items that we deem appropriate.

We believe that Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our critical accounting policiesoperations 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 estimatesassessing 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 includeda 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 Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

 

(In thousands)

 

Net loss

$

(41,336

)

 

$

18,641

 

 

$

(408,535

)

 

$

(12,836

)

Interest expense, net

 

6,209

 

 

 

4,422

 

 

 

13,856

 

 

 

8,511

 

Income tax expense (benefit)

 

85

 

 

 

 

 

 

85

 

 

 

(50

)

DD&A

 

7,623

 

 

 

12,913

 

 

 

23,179

 

 

 

24,079

 

Impairment expense

 

 

 

 

 

 

 

455,031

 

 

 

 

Accretion of AROs

 

1,539

 

 

 

1,332

 

 

 

3,052

 

 

 

2,643

 

(Gains) losses on commodity derivative instruments

 

19,165

 

 

 

(22,993

)

 

 

(88,548

)

 

 

9,494

 

Cash settlements received (paid) on expired commodity derivative instruments

 

27,295

 

 

 

(631

)

 

 

39,795

 

 

 

(1,908

)

Acquisition and divestiture related expenses

 

44

 

 

 

3,458

 

 

 

525

 

 

 

3,822

 

Share-based compensation expense

 

371

 

 

 

1,375

 

 

 

(540

)

 

 

3,311

 

Exploration costs

 

3

 

 

 

6

 

 

 

19

 

 

 

21

 

(Gain) loss on settlement of AROs

 

 

 

 

34

 

 

 

 

 

 

177

 

Bad debt expense

 

141

 

 

 

 

 

 

251

 

 

 

101

 

Reorganization items, net

 

166

 

 

 

464

 

 

 

352

 

 

 

651

 

Severance payments

 

10

 

 

 

50

 

 

 

29

 

 

 

89

 

Adjusted EBITDA

$

21,315

 

 

$

19,071

 

 

$

38,551

 

 

$

38,105

 


Reconciliation of Adjusted EBITDA to Net Cash from Operating Activities

 

For the Three Months Ended

 

 

For the Six Months Ended

 

 

June 30,

 

 

June 30,

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

 

(In thousands)

 

Net cash provided by operating activities

$

29,900

 

 

$

22,499

 

 

$

42,989

 

 

$

33,299

 

Changes in working capital

 

5,766

 

 

 

(10,862

)

 

 

5,311

 

 

 

(7,856

)

Interest expense, net

 

6,209

 

 

 

4,422

 

 

 

13,856

 

 

 

8,511

 

Gain (loss) on interest rate swaps

 

(438

)

 

 

(578

)

 

 

(4,055

)

 

 

(484

)

Cash settlements paid (received) on interest rate swaps

 

346

 

 

 

(45

)

 

 

324

 

 

 

(45

)

Cash settlements paid (received) on terminated derivatives

 

(17,977

)

 

 

 

 

 

(17,977

)

 

 

 

Amortization and write-off of deferred financing fees

 

(2,690

)

 

 

(266

)

 

 

(2,999

)

 

 

(574

)

Acquisition and divestiture related expenses

 

44

 

 

 

3,458

 

 

 

525

 

 

 

3,822

 

Income tax expense (benefit) - current portion

 

85

 

 

 

 

 

 

85

 

 

 

(50

)

Exploration costs

 

3

 

 

 

6

 

 

 

19

 

 

 

21

 

Plugging and abandonment cost

 

 

 

 

77

 

 

 

 

 

 

382

 

Reorganization items, net

 

166

 

 

 

464

 

 

 

352

 

 

 

651

 

Severance payments

 

10

 

 

 

50

 

 

 

29

 

 

 

89

 

Other

 

(109

)

 

 

(154

)

 

 

92

 

 

 

339

 

Adjusted EBITDA

$

21,315

 

 

$

19,071

 

 

$

38,551

 

 

$

38,105

 

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 2020, we expect our primary funding sources to be cash flows generated by operating activities and available borrowing capacity under our 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 30% - 60% 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-KRevolving 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 June 30, 2020, 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 $22.2 million for the yearsix months ended December 31, 2018. There have been no changesJune 30, 2020, which were primarily related to capital workovers and facilities located in Oklahoma and California and non-operated drilling activities in South Texas.

Working Capital. We expect to fund our critical accounting policies other than discussed below.

Leases

working capital needs primarily with operating cash flows. We determine if an arrangement isalso plan to reinvest a lease at inceptionsufficient 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 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 operatingNotes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” 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“— Overview” of this quarterly report for the lease term, and lease liabilities represent our obligation to make lease payments arising from the lease.

Operating leases are included in ROU lease assets, and lease liabilities in our unaudited interim condensed consolidated balance sheets. ROU lease assets and lease liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The ROU lease 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 are recognized on a straight-line basis over the lease term.

additional information.

As of June 30, 2020, we had working capital of $18.0 million primarily due to being in a receivable position with our short-term derivatives of $32.2 million, accounts receivable of $27.1 million, cash of $13.2 million and prepaid expenses of $12.2 million, offset by revenues payable of $22.5 million, current portion of long-term debt of $20.0 million, accrued liabilities of $17.8 million, and accounts payable of $5.6 million.


Debt Agreements

Revolving Credit Facility. On November 2, 2018, OLLC as borrower, entered into the Revolving Credit Facility (as amended and supplemented to date) with Bank of Montreal, as administrative agent. At June 30, 2020, our borrowing base under our 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.

On June 12, 2020, the Company entered into the Third Amendment; which, among other things, decreased the borrowing base from $450.0 million to $285.0 million, with monthly reductions of $5.0 million thereafter until the borrowing base is reduced to $260.0 million, effective November 1, 2020. The borrowing base as of June 30, 2020, was $285.0 million.

As of June 30, 2020, we were in compliance with all the financial (current ratio and total leverage ratio) and other covenants associated with our Revolving Credit Facility.

As of June 30, 2020, we had approximately $5.0 million of available borrowings under our Revolving Credit Facility. 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 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 six months ended June 30, 2020 and 2019, have been derived from our Unaudited Condensed Consolidated Financial Statements. For information regarding the individual components of our cash flow amounts, see the Unaudited Condensed Statements of Consolidated Cash Flows included under “Item 1. Financial Statements” of this quarterly report.

 

For the Six Months Ended

 

 

June 30,

 

 

2020

 

 

2019

 

 

(In thousands)

 

Net cash provided by operating activities

$

42,989

 

 

$

33,299

 

Net cash provided by (used in) investing activities

 

(26,842

)

 

 

56,425

 

Net cash used in financing activities

 

(3,270

)

 

 

(120,726

)

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities was $43.0 million and $33.3 million for the six months ended June 30, 2020 and 2019, respectively. Production volumes were approximately 28.7 MBoe/d and 21.3 MBoe/d for the six months ended June 30, 2020 and 2019, respectively. The average realized sales prices were $17.74 per Boe and $32.32 per Boe for the six months ended June 30, 2020 and 2019, respectively. Lease operating expenses were $63.6 million and $55.2 million for the six months ended June 30, 2020 and 2019, respectively. Gathering, processing and transportation was $9.7 million and $9.0 million for the six months ended June 30, 2020 and 2019, respectively.

Net cash provided by operating activities for the six months ended June 30, 2020 included $39.8 million of cash receipts on expired derivative instruments and $18.0 million of cash receipts on terminated derivative instruments compared to $1.9 million of cash paid on expired derivatives for the six months ended June 30, 2019. For the six months ended June 30, 2020, we had net gains on derivative instruments of $88.5 million compared to a net loss of $9.5 million for the six months ended June 30, 2019.

Investing Activities. Net cash provided by investing activities for the six months ended June 30, 2020 was $26.8 million, of which $26.1 million was used for additions to oil and natural gas properties. Net cash used in investing activities for the six months ended June 30, 2019 was $56.4 million, of which $33.2 million was used for additions to oil and natural gas properties. Withdrawal of restricted investments was $90.0 million, which related to the Company receiving $90.0 million from the Beta decommissioning trust account for the six months ended June 30, 2019.

Financing Activities. The Company had net repayments of $5.0 million and $119.0 million for the six months ended June 30, 2020 and 2019, respectively, related to our Revolving Credit Facility. The Company received a $5.5 million loan under the Paycheck Protection Program on April 24, 2020.

On March 3, 2020, our board of directors declared a dividend of $0.10 per share on our outstanding common stock, which was paid on March 30, 2020 to stockholders of record at the close of business on March 16, 2020.


Contractual Obligations

During the six months ended June 30, 2020, there were no significant changes in our consolidated contractual obligations from those reported in the Amplify Form 10-K except for the Revolving Credit Facility borrowings and repayments and the receipt of the PPP Loan. 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.

Off–Balance Sheet Arrangements

As of June 30, 2020, 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. 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 Interim Condensed Consolidated Financial Statements Note 3. Impact included under “Item 1. Financial Statements” of ASC 842 Adoption”.

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 effectivethis quarterly report 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.additional information.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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 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 objectiveJune 30, 2020, 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 June 30, 2020.

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 June 30, 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 June 30, 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:

 

 

10% Increase

 

10% Decrease

 

 

 

(in thousands)

 

Gain (loss):

 

 

 

 

 

Gas derivatives

 

$

(621

)

$

606

 

Oil derivatives

 

$

(2,918

)

$

2,395

 

Interest Rate Risk

At June 30, 2019, we had indebtednessright to offset $39.9 million against amounts outstanding under our RBL of $60.6 million, which bears interestRevolving Credit Facility at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. Assuming the RBL is fully drawn, a one percent increase in interest rates for the three months ended June 30, 2019, would have resulted in a $1.72020, reducing our maximum credit exposure to approximately $0.3 million, increase in annual interest cost, before capitalization.

At June 30, 2019, we did not have any interest rate derivatives in place and have not historically utilized interest rate derivatives. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverageall of the debt portfolio.which was with one counterparty.


ITEM 4.

CONTROLS AND PROCEDURES.

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 June 30, 2019, theseour disclosure controls and procedures were effective at the reasonable assurance level as of June 30, 2020.

The full impact of COVID-19 on our business is uncertain. In order to protect the health and ensured thatsafety of our employees, we took proactive steps to allow employees to work remotely and to reduce the information required to be disclosednumber of employees on site at any one time in our reports filedfield areas to comply with social distancing guidelines. We believe that our internal controls and procedures are still functioning as designed and were effective for the SEC is recorded, processed, summarized and reported on a timely basis.most recent quarter.

ChangesChange in Internal Control overOver Financial Reporting

There were noNo changes in our internal control over financial reporting occurred during the most recent quarter ended June 30, 2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as Exhibits 31.1 and 31.2, respectively, to this quarterly report.


PART II - II—OTHER INFORMATION

ITEM 1.

Item 1. Legal Proceedings

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 15. Commitments and Contingencies”,included in this quarterly report, which is incorporated in this itemherein by reference.reference.

Item 1A. Risk Factors

ITEM 1A.

RISK FACTORS.

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 In addition to the risk factors disclosed in Item 1A. Risk Factors in our 2019 Form 10-K, we face risks describedincluding the following:

The oversupply of oil and natural gas and lower demand caused by the COVID-19 pandemic, the failure of oil producing countries to sufficiently curtail production and general global economic instability may result in Part I, Item 1Atransportation and storage constraints, reduced production or the shut-in of our Annual Reportproducing wells, any of which would adversely affect our business, financial condition and results of operations.

In March 2020, the World Health Organization declared the outbreak of COVID-19 as a pandemic, which continues to spread throughout the United States. The spread of COVID-19 has caused significant volatility in U.S. and international markets. There is significant uncertainty regarding the breadth and duration of business disruptions related to COVID-19, as well as its impact on Form 10-Kthe U.S. and international economies. The outbreak of COVID-19 in the United States and the uncertainty of its impact, has contributed to an unprecedented oversupply of and decline in demand for oil and natural gas.  At this time, the full extent to which COVID-19 will negatively impact the global economy and our business is uncertain.

In addition, in March 2020, oil prices severely declined following unsuccessful negotiations between members of OPEC and certain nonmembers, including Russia, to implement production cuts in an effort to decrease the global oversupply and to rebalance supply and demand due to the ongoing COVID-19 pandemic. In April 2020, members of OPEC and Russia agreed to temporary production reductions, but uncertainty about whether such production cuts and/or the duration of such reductions will be sufficient to rebalance supply and demand remains and may continue for the year ended December 31, 2018, filed withforeseeable future. We anticipate further market and commodity price volatility for the SEC on March 14, 2019.remainder of 2020 as a result of the events described above.

To the extent that the outbreak of COVID-19 continues to negatively impact demand and OPEC members and other oil exporting nations fail to take actions aimed at supporting and stabilizing commodity prices, we expect there to be excess supply of oil and natural gas for a sustained period. This excess supply could, in turn, result in transportation and storage capacity constraints, as well as shut-ins and production curtailment in the United States. If, in the future, our transportation and/or storage capacity becomes constrained, we may be required to shut-in wells or curtail production, which may adversely affect our business, financial condition and results of operations.  

In addition, uncertainties regarding the global economic and financial environment could lead to an extended national or global economic recession. A slowdown in economic activity caused by a recession would likely reduce national and worldwide demand for oil and natural gas and result in lower commodity prices. Costs of exploration, development and production have not yet adjusted to current economic conditions, or in proportion to the significant reduction in product prices.

Over the past several years, capital and credit markets for the oil and natural gas industry have experienced volatility and disruption. Further market volatility and disruption and concerns regarding borrower solvency may substantially diminish the availability of funds from those markets, increase the cost of accessing the credit markets, subject borrowers to stricter lending standards, or may cause lenders to cease providing funding to borrowers, any of which may adversely affect our business, financial condition and results of operations.


Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

ITEM 2.

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 second 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 June 30, 2020:

 

Period

 

Total Number of Shares
Purchased

 

Average Price Paid
Per Share

 

April 1, 2019 — April 30, 2019

 

518

 

$

10.34

 

May 1, 2019 — May 31, 2019

 

 

$

 

June 1, 2019 — June 30, 2019

 

 

$

 

Total

 

518

 

$

10.34

 

Period

 

Total Number of

Shares Purchased

 

 

Average Price

Paid per Share

 

 

Total Number of

Shares Purchased as

Part of Publicly

Announced Plans

or Programs

 

 

Approximate Dollar

Value of Shares That

May Yet Be

Purchased Under the

Plans or Programs (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(In thousands)

Common Shares Repurchased (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

April 1, 2020 - April 30, 2020

 

 

1,020

 

 

$

0.54

 

 

 

 

 

n/a

May 1, 2020 - May 31, 2020

 

 

10,279

 

 

$

1.29

 

 

 

 

 

n/a

June 1, 2020 - June 30, 2020

 

 

3,737

 

 

$

1.12

 

 

 

 

 

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.

Item 3. Defaults Upon Senior Securities

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES.

None.

Item 4. Mine Safety Disclosures

ITEM 4.

MINE SAFETY DISCLOSURES.

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibits included in this Quarterly Report are listed in the Exhibit Index and incorporated herein by reference.

EXHIBIT INDEX

Exhibit
Number
ITEM 5.

OTHER INFORMATION.

None.

ITEM 6.

Exhibit DescriptionEXHIBITS.

2.1Exhibit
Number

Agreement and Plan of Merger, dated May 5, 2019, by and among Amplify Energy Corp., Midstates Petroleum Company, Inc. and Midstates Holdings, Inc. (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on May 6, 2019, and incorporated herein by reference).

 

 

 

Description

3.1

 

Second Amended and Restated Certificate of Incorporation of Midstates Petroleum Company, Inc. (filed as Exhibit 3.1 to the Company’s Registration Statement on Form 8-A filed on October 21, 2016, and incorporated herein by reference).

 

 

 

3.2

 

Certificate of Amendment to the Second Amended and Restated Certificate of Incorporation of Midstates Petroleum Company, Inc., dated August 6, 2019 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (File No. 001-35512) filed on August 6, 2019).

3.3

Second Amended and Restated Bylaws of Midstates Petroleum Company Inc. (filed as(incorporated by reference to Exhibit 3.2 toof the Company’s Registration StatementCurrent Report on Form 8-A8-K (File No. 001-35512) filed on October 21, 2016, and incorporated herein by reference)August 6, 2019).

 

 

 

10.1

 

VotingBorrowing Base Redetermination Agreement and SupportThird Amendment to Credit Agreement, dated May 5, 2019,June 12, 2020, by and between Midstates Petroleum Company,among Amplify Energy Operating LLC, Amplify Acquisitionco, Inc., the guarantors party thereto, Bank of Montreal, as administrative agent, and Fir Tree Capital Management LP (filed asthe other lenders and agents from time to time party thereto (incorporated by reference to Exhibit 10.1 toof the Company’s Current Report on Form 8-K (File No. 001-35512) filed on May 6, 2019, and incorporated herein by reference)June 15, 2020).

 

 

10.2

Voting and Support Agreement, dated May 5, 2019, by and between Midstates Petroleum Company, Inc. and Brigade Capital Management, LP (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 6, 2019, and incorporated herein by reference).

10.3

Voting and Support Agreement, dated May 5, 2019, by and between Midstates Petroleum Company, Inc. and Axys Capital Income Fund, LLC (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on May 6, 2019, and incorporated herein by reference).

10.4

Voting and Support Agreement, dated May 5, 2019, by and between Midstates Petroleum Company, Inc. and Cross Sound Management LLC (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on May 6, 2019, and incorporated herein by reference).

 

 

 

31.1*

 

Sarbanes-Oxley Section 302 certificationCertification of PrincipalChief Executive Officer.Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

 

 

 

31.2*

 

Sarbanes-Oxley Section 302 certificationCertification of PrincipalChief Financial Officer.Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

 

 

 

32.1**

 

Sarbanes-Oxley Section 906 certificationCertifications of PrincipalChief Executive Officer and PrincipalChief Financial Officer.Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

101.INS*

 

Inline XBRL Instance Document.Document

 

 

 

101.SCH*

 

Inline XBRL Schema Document.Document

 

 

 

101.CAL*

 

Inline XBRL Calculation Linkbase Document.Document

 

 

 

101.DEF*

 

Inline XBRL Definition Linkbase Document.Document

 

 

 


101.LAB*Exhibit
Number

 

Description

101.LAB*

Inline XBRL Labels Linkbase Document

 

 

 

101.PRE*

 

XBRL Presentation Linkbase Document.


*

 

Filed herewithInline XBRL Presentation Linkbase Document

**

 

Furnished herewith

104*

Cover Page Interactive Data File (embedded within the Inline XBRL document)

SIGNATURES

*

Filed as an exhibit to this Quarterly Report on Form 10-Q.

**

Furnished as an exhibit to this Quarterly Report on Form 10-Q.

 


SIGNATURES

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.

 

MIDSTATES PETROLEUM COMPANY, INC.Amplify Energy Corp.

(Registrant)

 

 

Dated: August 5, 2019

/s/ DAVID J. SAMBROOKS

 

David J. Sambrooks

President, Chief Executive Officer and Director

(Principal Executive Officer)

 

 

Dated:Date: August 5, 20192020

By:

/s/ RICHARD W. MCCULLOUGHMartyn Willsher

 

Richard W. McCulloughName:

Martyn Willsher

Title:

Interim Chief Executive Officer, Senior Vice President and Chief Financial Officer

Date: August 5, 2020

By:

/s/ Denise DuBard

Name:

Denise DuBard

Title:

 

Vice President and Chief Accounting Officer

 

(Principal Financial Officer and Principal Accounting Officer)

 

42