Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

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

 

For the quarterly period ended March 31, 2019

 

OR

 

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

 

For the transition period from              to             .

 

Commission File Number: 001-35512

 

MIDSTATES PETROLEUM COMPANY, INC.

(Exact name of registrant as specified in its charter)

 

Delaware

 

45-3691816

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification No.)

 

321 South Boston Avenue, Suite 1000

 

 

Tulsa, Oklahoma

 

74103

(Address of principal executive offices)

 

(Zip Code)

 

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

 

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-2 of the Exchange Act). Yes o   No x

 

The number of shares outstanding of our stock at May 7, 2019 is shown below:

 

Class

 

Number of shares outstanding

Common stock, $0.01 par value

 

20,415,005

 

DOCUMENTS INCORPORATED BY REFERENCE

 

None.

 

 

 


Table of Contents

 

MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31, 2019

 

TABLE OF CONTENTS

 

 

 

Page

 

 

 

Glossary of Oil and Natural Gas Terms

3

 

 

 

PART I — FINANCIAL INFORMATION

 

 

 

 

Item 1.

Financial Statements

 

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

4

Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2019 and 2018 (unaudited)

5

Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2019 and 2018 (unaudited)

6

Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2019 and 2018 (unaudited)

7

 

 

Notes to the Unaudited Interim Condensed Consolidated Financial Statements

8

 

 

 

Item 2.

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

27

 

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

38

 

 

 

Item 4.

Controls and Procedures

39

 

 

 

PART II — OTHER INFORMATION

 

 

 

 

Item 1.

Legal Proceedings

40

 

 

 

Item 1A.

Risk Factors

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

 

2


Table of Contents

 

GLOSSARY OF OIL AND NATURAL GAS TERMS

 

Bbl:  One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to oil, condensate or natural gas liquids.

 

Boe:  Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

 

Boe/day:  Barrels of oil equivalent per day.

 

Completion:  The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

 

Dry hole:  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production do not exceed production expenses and taxes.

 

Exploratory well:  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir.

 

MMBtu:  One million British thermal units.

 

NYMEX:  The New York Mercantile Exchange.

 

Proved reserves:  Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to 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 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 is the average price during the 12-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.

 

Reasonable certainty:  A high degree of confidence.

 

Recompletion:  The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish, re-establishing, or increase existing production.

 

Reserves:  Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development projects to known accumulations.

 

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.

 

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

 

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

 

Working interest:  The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on a cash, penalty, or carried basis.

 

3


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PART I — FINANCIAL INFORMATION

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)

 

 

 

March 31, 2019

 

December 31, 2018

 

ASSETS

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

 

$

717

 

$

11,341

 

Accounts receivable:

 

 

 

 

 

Oil and gas sales

 

17,519

 

22,165

 

Joint interest billing

 

2,253

 

2,474

 

Other

 

377

 

1,374

 

Commodity derivative contracts

 

309

 

6,940

 

Other current assets

 

2,534

 

1,684

 

Total current assets

 

23,709

 

45,978

 

PROPERTY AND EQUIPMENT:

 

 

 

 

 

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

 

 

 

 

 

Proved properties

 

818,013

 

809,272

 

Unproved properties not being amortized

 

1,869

 

4,050

 

Other property and equipment

 

6,340

 

6,345

 

Less accumulated depreciation, depletion, amortization and impairment

 

(287,544

)

(266,198

)

Net property and equipment

 

538,678

 

553,469

 

OTHER NONCURRENT ASSETS:

 

 

 

 

 

Commodity derivative contracts

 

 

791

 

Right-of-use lease assets

 

4,648

 

 

Other noncurrent assets

 

5,762

 

5,257

 

Total other noncurrent assets

 

10,410

 

6,048

 

TOTAL

 

$

572,797

 

$

605,495

 

LIABILITIES AND EQUITY

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable

 

$

3,536

 

$

6,511

 

Accrued liabilities

 

21,973

 

25,521

 

Commodity derivative contracts

 

908

 

 

Lease liabilities

 

1,236

 

 

Total current liabilities

 

27,653

 

32,032

 

LONG-TERM LIABILITIES:

 

 

 

 

 

Asset retirement obligations

 

8,244

 

8,087

 

Commodity derivative contracts

 

251

 

80

 

Long-term debt

 

59,059

 

23,059

 

Long-term lease liabilities

 

4,041

 

 

Other long-term liabilities

 

 

560

 

Total long-term liabilities

 

71,595

 

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 March 31, 2019 and December 31, 2018

 

 

 

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

 

37,329

 

37,329

 

Common stock, $0.01 par value, 250,000,000 shares authorized; 20,619,765 shares issued and 20,414,422 shares outstanding at March 31, 2019; 25,520,170 shares issued and 25,345,981 shares outstanding at December 31, 2018

 

206

 

255

 

Treasury stock

 

(2,717

)

(2,455

)

Additional paid-in-capital

 

481,901

 

531,911

 

Retained deficit

 

(43,170

)

(25,363

)

Total stockholders’ equity

 

473,549

 

541,677

 

TOTAL

 

$

572,797

 

$

605,495

 

 

The accompanying notes are an integral part of these unaudited interim condensed consolidated financial statements.

 

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)

 

 

 

For the Three Months
Ended March 31,

 

 

 

2019

 

2018

 

REVENUES

 

 

 

 

 

Oil sales

 

$

16,327

 

$

32,414

 

Natural gas liquid sales

 

6,216

 

11,038

 

Natural gas sales

 

6,610

 

8,337

 

Other revenue

 

688

 

1,055

 

Total revenue from contracts with customers

 

29,841

 

52,844

 

Losses on commodity derivative contracts—net

 

(7,732

)

(3,939

)

Total revenues

 

22,109

 

48,905

 

EXPENSES:

 

 

 

 

 

Lease operating and workover

 

8,990

 

14,808

 

Gathering and transportation

 

19

 

57

 

Severance and other taxes

 

1,933

 

2,861

 

Asset retirement accretion

 

157

 

297

 

Depreciation, depletion, and amortization

 

11,794

 

15,213

 

Impairment in carrying value of oil and gas properties

 

9,653

 

 

General and administrative

 

6,438

 

9,857

 

Total expenses

 

38,984

 

43,093

 

OPERATING INCOME (LOSS)

 

(16,875

)

5,812

 

OTHER EXPENSE

 

 

 

 

 

Interest income

 

5

 

19

 

Interest expense—net of amounts capitalized

 

(937

)

(1,827

)

Total other expense

 

(932

)

(1,808

)

INCOME (LOSS) BEFORE TAXES

 

(17,807

)

4,004

 

Income tax expense

 

 

 

NET INCOME (LOSS)

 

$

(17,807

)

$

4,004

 

Participating securities—non-vested restricted stock

 

 

(99

)

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS

 

$

(17,807

)

$

3,905

 

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

 

$

(0.78

)

$

0.15

 

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

 

22,837

 

25,299

 

 

The accompanying notes are an integral part of these unaudited interim condensed consolidated financial statements.

 

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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

 

 

 

 

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

 

 

 

 

 

 

4,004

 

4,004

 

Balance as of March 31, 2018

 

$

 

$

254

 

$

37,329

 

$

(2,062

)

$

527,550

 

$

(71,143

)

$

491,928

 

 

The accompanying notes are an integral part of these unaudited interim condensed consolidated financial statements.

 

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

 

 

 

For the Three Months

 

 

 

Ended March 31,

 

 

 

2019

 

2018

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income (loss)

 

$

(17,807

)

$

4,004

 

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

 

 

 

 

 

Losses on commodity derivative contracts—net

 

7,732

 

3,939

 

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

 

769

 

(160

)

Asset retirement accretion

 

157

 

297

 

Depreciation, depletion, and amortization

 

11,794

 

15,213

 

Impairment in carrying value of oil and gas properties

 

9,653

 

 

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

 

966

 

2,210

 

Amortization of deferred financing costs

 

174

 

108

 

Change in operating assets and liabilities:

 

 

 

 

 

Accounts receivable—oil and gas sales

 

3,573

 

1,293

 

Accounts receivable—JIB and other

 

1,613

 

(663

)

Other current and noncurrent assets

 

(1,529

)

(1,750

)

Accounts payable

 

1,044

 

(1,467

)

Accrued liabilities

 

(4,972

)

(869

)

Other

 

(2

)

(8

)

Net cash provided by operating activities

 

$

13,165

 

$

22,147

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Investment in property and equipment

 

$

(9,527

)

$

(31,758

)

Net cash used in investing activities

 

$

(9,527

)

$

(31,758

)

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Repayment of revolving credit facility

 

$

(3,000

)

$

(50,000

)

Proceeds from revolving credit facility

 

39,000

 

 

Repurchase of restricted stock for tax withholdings

 

(262

)

(459

)

Common stock repurchased and retired

 

(50,000

)

 

Net cash used in financing activities

 

$

(14,262

)

$

(50,459

)

NET DECREASE IN CASH AND CASH EQUIVALENTS

 

$

(10,624

)

$

(60,070

)

Cash and cash equivalents, beginning of period

 

$

11,341

 

$

68,498

 

Cash and cash equivalents, end of period

 

$

717

 

$

8,428

 

 

 

 

 

 

 

SUPPLEMENTAL INFORMATION:

 

 

 

 

 

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

 

$

3,552

 

$

18,508

 

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

 

$

664

 

$

1,785

 

Right-of-use assets obtained in exchange for operating lease liabilities

 

$

4,857

 

$

 

 

The accompanying notes are an integral part of these unaudited interim condensed consolidated financial statements.

 

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Interim Condensed Consolidated Financial Statements

 

1. Organization and Business

 

Midstates Petroleum Company, Inc. engages in the business of exploring and drilling for, and the production of, oil, natural gas liquids (“NGLs”) and natural gas. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”). The terms “Company,” “we,” “us,” “our,” and similar terms refer to Midstates Petroleum Company, Inc. and its subsidiary.

 

The Company currently conducts oil and gas operations and owns and operates oil and natural gas properties in Oklahoma. The Company operates nearly all of its oil and natural gas properties. The Company’s management evaluates performance based on one reportable segment as all of its operations are located in the United States and, therefore, it maintains one cost center.

 

2. Summary of Significant Accounting Policies

 

Basis of Presentation

 

These unaudited interim condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, these financial statements do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“US GAAP”) for complete consolidated financial statements, and should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2018, included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 14, 2019.

 

All intercompany transactions have been eliminated in consolidation. In the opinion of the Company’s 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 certain estimates and assumptions that affect reported amounts in the unaudited interim condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

 

Recent Accounting Pronouncements Adopted During 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), and Derivatives and Hedging (Topic 815)” (“ASU 2017-11”). ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“EPS”) in accordance with Topic 260 to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for the Company for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The adoption of ASU 2017-11 did not have a material impact on its financial position, results of operations or cash flows.

 

In June 2018, the FASB issued Accounting Standards Update 2018-07, “Compensation - Stock Compensation (Topic 718) — Improvements to Nonemployee Share-Based Payment Accounting” (“ASU 2018-07”). ASU 2018-07 expands the scope of Topic 718 to include share-based payments issued to non-employees for goods and services. Consequently, 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 ASU 842 Adoption” below for further details.

 

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Recent Accounting Pronouncements Issued But Not Yet Adopted

 

In June 2016, the FASB issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (“ASU 2016-13”). ASU 2016-13 replaces the incurred loss model with an expected loss model, which is referred to as the current expected credit loss (“CECL”) model. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to trade receivables. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Company is still performing its evaluation of ASU 2016-13, but does not believe it will have a material impact on its consolidated financial statements at this time.

 

3. Impact of ASU 842 Adoption

 

In February 2016, the FASB issued ASU 2016-02, which 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 March 31, 2019, with the primary change relating to the recognition of ROU assets and lease liabilities for operating leases. Adoption of the new lease standard had an immaterial impact to the Company’s unaudited interim condensed consolidated statement of operations and cash provided from or used in operating, investing or financing activities in its unaudited interim condensed consolidated statements of cash flows for the three months ended March 31, 2019. Further discussion of the Company’s accounting for lease arrangements under ASC 842 is included below.

 

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Table of Contents

 

Leases

 

The Company determines if an arrangement is a lease at inception of the arrangement. To the extent that it is determined an arrangement represents a lease, the Company classifies that lease as an operating lease or a finance lease. The Company capitalizes operating and finance leases on its unaudited interim condensed consolidated balance sheets through a ROU asset and a corresponding lease liability. ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the Company’s obligation to make lease payments arising from the lease.

 

Operating leases are included in operating lease ROU assets, and operating lease liabilities in the unaudited interim condensed consolidated balance sheets at March 31, 2019. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

 

As of March 31, 2019, the 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.

 

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Table of Contents

 

Fleet Vehicles

 

The Company executes fleet vehicle leases with a third-party vendor in support of its day-to-day drilling and production operations. Its vehicle leases are typically structured with a term of a minimum of 367 days for passenger and light duty vehicles and a minimum of 24 months for commercial vehicles and continue thereafter on a month-to-month basis subject to termination by either party within thirty-days’ notice. The Company has concluded that its fleet vehicle leases represent operating leases.

 

Significant Judgments

 

Transportation, Gathering and Processing Arrangements

 

The Company is party to a gas purchase, gathering and processing contract in the Mississippian Lime region, which includes certain minimum NGLs volume commitments. To the extent the Company does not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLs, it would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee. The Company is currently delivering at least the minimum volumes required under these contractual provisions. However, decreased drilling activity could result in the inability to meet these commitments in the future.

 

As the Company does not utilize substantially all of the underlying pipeline, gathering system or processing facilities, it has concluded that those underlying assets do not meet the definition of an identified asset.

 

Discount Rate

 

The Company’s leases typically do not provide an implicit rate, and thus, is required to use its incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. The Company’s incremental borrowing rate reflects the rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. In order to determine its incremental borrowing rate, the Company utilizes its current credit rating as well as best available market data, which includes public bond information for publicly traded upstream energy companies with similar credit ratings, to estimate its unsecured borrowing rate and applied adjustments to that rate to account for the effect of collateral.

 

The Company has determined the discount rate as of January 1, 2019, using end of day December 31, 2018, market data. This discount rate will be used at transition to ASC 842 as well as all new leases executed within 2019.  The Company intends to update the discount rate annually 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.

 

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Table of Contents

 

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 March 31, 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 is determined using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance 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 March 31, 2019

 

 

 

 

 

Significant Other

 

Significant

 

 

 

 

 

Quoted Prices in Active
Markets (Level 1)

 

Observable Inputs
(Level 2)

 

Unobservable Inputs
(Level 3)

 

Total

 

 

 

(in thousands)

 

Derivative Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

422

 

$

 

$

422

 

Commodity derivative gas swaps

 

$

 

$

74

 

$

 

$

74

 

Commodity derivative oil collars

 

$

 

$

1,944

 

$

 

$

1,944

 

Commodity derivative gas collars

 

$

 

$

203

 

$

 

$

203

 

Total assets

 

$

 

$

2,643

 

$

 

$

2,643

 

 

 

 

 

 

 

 

 

 

 

Derivative Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

 

$

 

$

 

Commodity derivative gas swaps

 

$

 

$

(80

)

$

 

$

(80

)

Commodity derivative oil collars

 

$

 

$

(3,132

)

$

 

$

(3,132

)

Commodity derivative gas collars

 

$

 

$

(281

)

$

 

$

(281

)

Total liabilities

 

$

 

$

(3,493

)

$

 

$

(3,493

)

 

 

 

Fair Value Measurements at December 31, 2018

 

 

 

 

 

Significant Other

 

Significant

 

 

 

 

 

Quoted Prices 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

)

 

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Table of Contents

 

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 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 at March 31, 2019, the Company would not have experienced a loss.

 

Commodity Derivative Contracts

 

The Company entered into 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:

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2019

 

74,800

 

$

66.48

 

180,000

 

$

63.14

 

$

53.75

 

$

43.75

 

June 30, 2019(1)

 

57,650

 

$

64.69

 

182,000

 

$

63.14

 

$

53.75

 

$

43.75

 

September 30, 2019(1)

 

46,000

 

$

62.96

 

184,000

 

$

63.14

 

$

53.75

 

$

43.75

 

December 31, 2019(1)

 

46,000

 

$

61.43

 

184,000

 

$

63.14

 

$

53.75

 

$

43.75

 

March 31, 2020(1)

 

 

$

 

91,000

 

$

65.75

 

$

50.00

 

$

40.00

 

June 30, 2020(1)

 

 

$

 

91,000

 

$

65.75

 

$

50.00

 

$

40.00

 

September 30, 2020(1)

 

 

$

 

92,000

 

$

65.75

 

$

50.00

 

$

40.00

 

December 31, 2020(1)

 

 

$

 

92,000

 

$

65.75

 

$

50.00

 

$

40.00

 

 


(1)          Positions shown represent open commodity derivative contract positions as of March 31, 2019.

 

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Table of Contents

 

 

 

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:

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2019

 

1,980,000

 

$

3.01

 

1,350,000

 

$

3.40

 

$

3.00

 

$

2.50

 

June 30, 2019(1)

 

1,365,000

 

$

2.75

 

 

$

 

$

 

$

 

September 30, 2019(1)

 

1,380,000

 

$

2.75

 

 

$

 

$

 

$

 

December 31, 2019(1)

 

465,000

 

$

2.75

 

610,000

 

$

3.45

 

$

2.65

 

$

2.15

 

March 31, 2020(1)

 

 

$

 

900,000

 

$

3.45

 

$

2.65

 

$

2.15

 

 


(1)          Positions shown represent open commodity derivative contract positions as of March 31, 2019.

 

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)

 

March 31, 2019

 

December 31, 2018

 

Oil swaps

 

Derivative financial instruments — current assets

 

$

422

 

$

3,806

 

Gas swaps

 

Derivative financial instruments — current assets

 

 

(207

)

Oil collars

 

Derivative financial instruments — current assets

 

(113

)

3,316

 

Gas collars

 

Derivative financial instruments — current assets

 

 

25

 

Total derivative financial instruments current assets

 

$

309

 

$

6,940

 

 

 

 

 

 

 

 

 

Oil collars

 

Derivative financial instruments — noncurrent assets

 

$

 

$

791

 

Total derivative financial instruments — noncurrent assets

 

$

 

$

791

 

 

 

 

 

 

 

 

 

Oil swaps

 

Derivative financial instruments — current liabilities

 

$

 

$

 

Gas swaps

 

Derivative financial instruments — current liabilities

 

(6

)

 

Oil collars

 

Derivative financial instruments — current liabilities

 

(823

)

 

Gas collars

 

Derivative financial instruments — current liabilities

 

(79

)

 

Total derivative financial instruments current liabilities

 

$

(908

)

$

 

 

 

 

 

 

 

 

 

Oil collars

 

Derivative financial instruments — noncurrent liabilities

 

$

(251

)

$

 

Gas collars

 

Derivative financial instruments — noncurrent liabilities

 

 

(80

)

Total derivative financial instruments noncurrent liabilities

 

$

(251

)

$

(80

)

 

 

 

 

 

 

 

 

Total derivative fair value at period end

 

$

(850

)

$

7,651

 

 


(1)          The fair values of commodity derivative instruments reported in the Company’s unaudited interim condensed consolidated balance sheets are subject to netting arrangements and qualify for net presentation.

 

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Table of Contents

 

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):

 

 

 

 

 

March 31, 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

 

$

1,738

 

$

(1,429

)

$

309

 

Commodity contracts

 

Derivative financial instruments — noncurrent

 

905

 

(905

)

 

 

 

 

 

$

2,643

 

$

(2,334

)

$

309

 

Derivative Liabilities:

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Derivative financial instruments — current

 

$

(2,337

)

$

1,429

 

$

(908

)

Commodity contracts

 

Derivative financial instruments — noncurrent

 

(1,156

)

905

 

(251

)

 

 

 

 

$

(3,493

)

$

2,334

 

$

(1,159

)

 

 

 

 

 

December 31, 2018

 

Not Designated as

 

 

 

Gross Recognized

 

Gross Amounts

 

Net Recognized
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 for commodity derivative contracts and unrealized net gains recorded by the Company related to the change in fair value of the derivative instruments in gains (losses) on commodity derivative contracts—net for the periods presented (in thousands):

 

 

 

For the Three Months 

 

 

 

Ended March 31, 

 

 

 

2019

 

2018

 

Net cash received (paid) for commodity derivative contracts

 

$

769

 

$

(160

)

Unrealized net gains (losses)

 

(8,501

)

(3,779

)

Losses on commodity derivative contracts—net

 

$

(7,732

)

$

(3,939

)

 

Cash settlements, as presented in the table above, represent realized gains (losses) related to the Company’s derivative instruments. In addition to cash settlements, the Company also recognizes fair value changes on its derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.

 

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6. Property and Equipment

 

Property and equipment consisted of the following as of the dates presented:

 

 

 

March 31, 2019

 

December 31, 2018

 

 

 

(in thousands)

 

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

 

 

 

 

 

Proved properties

 

$

818,013

 

$

809,272

 

Unproved properties not being amortized

 

1,869

 

4,050

 

Other property and equipment

 

6,340

 

6,345

 

Less accumulated depreciation, depletion, amortization and impairment

 

(287,544

)

(266,198

)

Net property and equipment

 

$

538,678

 

$

553,469

 

 

Oil and Gas Properties

 

Historically, the Company has capitalized internal costs directly related to exploration and development activities to oil and gas properties. During the three months ended March 31, 2019, the Company did not have significant exploration and development activities and no internal costs were capitalized. During the three months ended March 31, 2019 and 2018, the Company capitalized the following (in thousands):

 

 

 

2019

 

2018

 

Internal costs capitalized to oil and gas properties (1)

 

$

 

$

895

 

 


(1)                           Inclusive of $0.2 million of qualifying share-based compensation expense for the three months ended March 31, 2018.

 

The Company accounts for its oil and gas properties under the full cost method. Under the full cost method, proceeds realized from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company’s reserve quantities are sold such that it results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income. During the three months ended March 31, 2018, the Company signed a purchase and sale agreement for its Anadarko Basin assets for $58.0 million before customary closing or post-closing adjustments. The sale of the Anadarko Basin assets closed on May 31, 2018, and did not result in a significant alteration of the full cost pool and therefore, no gain or loss was recognized when the transaction closed.

 

The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of the Company’s oil and gas properties. The capitalized costs of oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“DD&A”) and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying unaudited interim condensed consolidated statements of operations.

 

For the three months ended March 31, 2019, capitalized costs exceeded the ceiling and the Company recorded an impairment of oil and gas properties of $9.7 million. This impairment was primarily the result of low commodity prices, which resulted in a reduction of the discounted present value of the Company’s proved oil and natural gas reserves. No impairment of oil and gas properties was recorded during the three months ended March 31, 2018.

 

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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
March 31,

 

Three Months Ended
March 31,

 

 

 

2019

 

2018

 

2019

 

2018

 

 

 

(in thousands)

 

(per Boe)

 

Depletion expense

 

$

11,680

 

$

14,623

 

$

9.81

 

$

8.45

 

Depreciation on other property and equipment

 

114

 

590

 

0.10

 

0.34

 

Depreciation, depletion, and amortization

 

$

11,794

 

$

15,213

 

$

9.91

 

$

8.79

 

 

Oil and gas unproved properties include costs that are not being depleted or amortized. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are transferred to proved properties and become part of our depletion base and subject to the full cost ceiling limitation. No impairment of unproved properties was recorded during the three months ended March 31, 2019 or 2018. Unproved property was $1.9 million and $4.1 million at March 31, 2019 and December 31, 2018, respectively.

 

Other Property and Equipment

 

Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are carried at cost. Depreciation is calculated principally using the straight-line method over the estimated useful lives of the assets, which range from two to ten years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.

 

7. Leases

 

As previously described in Note 3. Impact of ASU 842 Adoption”, the Company leases certain office space, field offices, office equipment, compressors, other production equipment and fleet vehicles under cancelable and non-cancelable leases to support its operations. These leases do not contain material variable payments, residual value guarantees, covenants or other restrictions.

 

Supplemental cash flow information related to the Company’s leases are included in the table below (in thousands):

 

 

 

Three Months Ended
March 31, 2019

 

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

 

 

 

Operating cash flows from operating leases

 

$

310

 

Amortization of right-of-use assets:

 

 

 

Operating leases

 

$

208

 

 

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

 

 

 

March 31, 2019

 

Operating Leases

 

 

 

Right-of-use lease assets

 

4,648

 

Total operating lease ROU asset

 

$

4,648

 

 

 

 

 

Lease liabilities

 

$

1,236

 

Long-term lease liabilities

 

4,041

 

Total operating lease liabilities

 

$

5,277

 

 

 

 

 

Weighted-average remaining lease term

 

6.68 years

 

 

As of March 31, 2019, the Company had no finance or operating leases that had not yet commenced.

 

8. Accrued Liabilities

 

The following table presents the components of accrued liabilities as of the dates presented:

 

 

 

March 31, 2019

 

December 31, 2018

 

 

 

(in thousands)

 

Accrued oil and gas capital expenditures

 

$

3,021

 

$

1,534

 

Accrued revenue and royalty distributions

 

10,363

 

13,302

 

Accrued lease operating and workover expense

 

2,799

 

2,843

 

Accrued interest

 

262

 

209

 

Accrued taxes

 

1,405

 

1,813

 

Compensation and benefit related accruals

 

2,152

 

2,855

 

Other

 

1,971

 

2,965

 

Accrued liabilities

 

$

21,973

 

$

25,521

 

 

9. Asset Retirement Obligations

 

Asset Retirement Obligations (“AROs”) represent the estimated future abandonment costs of tangible assets, such as wells, service assets and other facilities. The estimated fair value of the AROs at inception are capitalized as part of the carrying amount of the related long-lived assets. The following table reflects the changes in the Company’s AROs for the periods presented (in thousands):

 

 

 

Three Months Ended
March 31,

 

 

 

2019

 

2018

 

Asset retirement obligations — beginning of period

 

$

8,087

 

$

15,506

 

Liabilities incurred

 

 

113

 

Revisions

 

 

 

Liabilities settled

 

 

(1

)

Liabilities eliminated through asset sales

 

 

(62

)

Current period accretion expense

 

157

 

297

 

Asset retirement obligations — end of period

 

$

8,244

 

$

15,853

 

 

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10. Debt

 

Reserves-Based Revolving Credit Facility (“RBL”)

 

At March 31, 2019 and December 31, 2018, the Company maintained an RBL with a borrowing base of $170.0 million. During the three months ended March 31, 2019, the Company drew down $36.0 million, net on its RBL. At March 31, 2019 and December 31, 2018, the Company had $59.1 million and $23.1 million, respectively, drawn on the RBL and had outstanding letters of credit obligations totaling $1.9 million. As a result, at March 31, 2019, the Company had $109.0 million of availability on the RBL.

 

The RBL matures on September 30, 2020, and bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. At March 31, 2019, the weighted-average interest rate, excluding amortization expense of deferred financing costs and commitment fees, was 7.0%. Unamortized debt issuance costs of $1.0 million and $1.2 million associated with the RBL are included in other noncurrent assets on the unaudited interim condensed consolidated balance sheets at March 31, 2019 and December 31, 2018, respectively.

 

In addition to interest expense, the RBL requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of 0.50% per annum based on the average daily amount by which the borrowing base exceeds outstanding borrowings during each quarter.

 

The RBL, as amended, includes certain financial maintenance covenants that are required to be calculated on a quarterly basis for compliance purposes. These financial maintenance covenants include EBITDA to interest expense for the trailing four fiscal quarters of not less than 2.50:1.00 and a limitation of Total Net Indebtedness (as defined in the RBL) to EBITDA for the trailing four fiscal quarters of not more than 4.00:1.00.

 

On November 15, 2018, the Company entered into a Second Amendment to the RBL (the “Second Amendment”). The Second Amendment provides the Company with the ability to make dividends and distributions, including repurchases of its equity interests in cash, in each case, so long as both before and after giving effect to any such repurchase (i) the Company and its subsidiaries maintain liquidity of at least $50.0 million, (ii) no default or event of default exists under the RBL, (iii) the ratio of total net indebtedness to adjusted EBITDA for the most recent period of four fiscal quarters for which financial statements have been delivered pursuant to the RBL shall not exceed 1.50:1.00 and (iv) all repurchased equity interests of the Company must be immediately retired.

 

In addition, the RBL contains various other covenants that, among other things, may restrict the Company’s ability to: (i) incur additional indebtedness or guarantee indebtedness (ii) make loans and investments; (iii) pay dividends on capital stock and make other restricted payments, including the prepayment or redemption of other indebtedness; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with the Company’s affiliates; (vii) acquire, consolidate or merge with another entity upon certain terms and conditions; (viii) sell all or substantially all of the Company’s assets; (ix) prepay, redeem or repurchase certain debt; (x) alter the business the Company conducts and make amendments to the Company’s organizational documents, (xi) enter into certain derivative transactions and (xii) enter into certain marketing agreements and take-or-pay arrangements. During the first quarter of 2019, the Company partially funded the stock buyback by drawing down $39.0 million from our RBL, as noted in “ Note 11. Equity and Share-Based Compensation” below, with the remainder funded by cash on hand.

 

The Company was in compliance with all debt covenants at March 31, 2019.

 

On April 11, 2019, the Company’s borrowing base was redetermined at the existing amount of $170.0 million.

 

The Company believes the carrying amount of the RBL at March 31, 2019 approximates its fair value (Level 2) due to the variable nature of the RBL interest rate.

 

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11. Equity and Share-Based Compensation

 

Common Shares

 

Share Activity

 

The following table summarizes changes in the number of shares of common stock and treasury stock during the three months ended March 31, 2019:

 

 

 

Common
Stock

 

Treasury
Stock(1)

 

Share count as of December 31, 2018

 

25,520,170

 

(174,189

)

Common stock issued

 

99,595

 

 

Acquisition of treasury stock

 

 

(5,031,154

)

Retirement of treasury stock

 

(5,000,000

)

5,000,000

 

Share count as of March 31, 2019

 

20,619,765

 

(205,343

)

 


(1)                                 Treasury stock at March 31, 2019 and December 31, 2018 represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory tax withholding requirements.

 

On January 14, 2019, the Company announced the commencement of a tender offer (the “Tender Offer”), authorized by the Board of Directors, to repurchase up to 5,000,000 shares of common stock at the offer price of $10.00 per share. On February 14, 2019, the Tender Offer was completed with the purchase of 5,000,000 shares of common stock at a purchase price of $10.00 per share. The 5,000,000 shares repurchased by the Company on February 14, 2019, were subsequently retired. When treasury shares are retired, the excess of the repurchase price over the par value of the shares is allocated to additional paid in capital for amounts up to the original price of the shares at issuance, with any residual excess purchase price allocated to retained earnings. The excess of the repurchase price over the par value of the shares repurchased and subsequently retired on February 14, 2019 was allocated solely to additional paid in capital.

 

Warrants

 

On October 21, 2016, the Company issued 4,411,765 Third Lien Notes Warrants to purchase up to an aggregate of 4,411,765 shares of common stock at an initial exercise price of $24.00 per share and 2,213,789 Unsecured Creditor Warrants to purchase up to an aggregate of 2,213,789 shares of common stock at an initial exercise price of $46.00 per share. The Warrants expire on April 21, 2020.

 

The number of shares of common stock for which the Warrants is exercisable, and the exercise price per share of the Warrants are subject to adjustment from time to time upon the occurrence of certain events, including the issuance of common stock as a dividend or distribution to all holders of shares of common stock, a pro-rata repurchase offer of common stock or a subdivision, combination, split, reverse split or reclassification of outstanding common stock into a greater or smaller number of shares of common stock.

 

As a result of the Tender Offer, the outstanding warrants of the Company were adjusted. The exercise price of the Third Lien Notes Warrants were adjusted from $24.00 per share to $22.78 per share and the exercise price of the Unsecured Creditor Warrants were adjusted from $46.00 per share to $43.67 per share. Further, the number of shares eligible to be received upon exercise of each warrant was adjusted by a factor of 1.05. Subsequent to the Tender Offer, the Third Lien Notes Warrants and the Unsecured Creditor Warrants may be exercised for up to an aggregate of 4,647,520 and 2,332,089 shares of common stock, respectively.

 

Share-Based Compensation

 

2016 Long Term Incentive Plan

 

On October 21, 2016, the 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 March 31, 2019, 1,764,041 Award Shares remain available for issuance under the terms of the 2016 LTIP.

 

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Stock Buyback Equalization Program

 

On December 21, 2018, the Company adopted a stock buyback equalization program that allows holders of the Company’s outstanding equity awards to participate in any tender program or share repurchase program of the Company with their vested and unvested shares applicable to those equity awards. Vested awards that have been elected for participation in the equalization program are settled in a cash payment equal to the cash purchase price paid by the Company in the applicable tender offer or share repurchase program. Unvested or deferred awards that have been elected for participation in an equalization program are realized through a cash settlement of the awards upon the vesting or lapse of the award’s deferral conditions.

 

On January 14, 2019, the Company announced the commencement of the Tender Offer, authorized by the Board of Directors, to repurchase up to 5,000,000 shares of common stock at the offer price of $10.00 per share. On February 14, 2019, the Tender Offer was completed with the purchase of 5,000,000 shares of common stock at a purchase price of $10.00 per share. In conjunction with the Tender Offer, holders of the Company’s restricted stock units participated in the related equalization program, as discussed below.  No other outstanding equity awards were eligible for participation in the equalization program during the quarter ended March 31, 2019.

 

Restricted Stock Units

 

At March 31, 2019, the Company had 358,217 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 three months ended March 31, 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 quarter ended March 31, 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 three months ended March 31, 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)

 

(36,276

)

$

9.74

 

Forfeited

 

(18,223

)

$

9.74

 

Non-vested shares outstanding at March 31, 2019

 

358,217

 

$

12.30

 

 


(1)                           Restricted stock units which vested during the three months ended March 31, 2019 were accelerated as a result of a reduction in workforce that occurred during the three months ended March 31, 2019.

 

Unrecognized expense as of March 31, 2019, for all outstanding restricted stock units under the 2016 LTIP Plan was $2.3 million and will be recognized over a weighted average period of 1.2 years.

 

Stock Options

 

At March 31, 2019, the Company had 55,213 non-vested options outstanding pursuant to the 2016 LTIP. Stock Option Awards granted under the 2016 LTIP vest ratably over a period of three years: one-sixth will vest on the six-month anniversary of the grant date, an additional one-sixth will vest on the twelve-month anniversary of the grant date, an additional one-third will vest on the twenty-four month anniversary of the grant date and the final one-third will vest on the thirty-six month anniversary of the grant date. Stock Option Awards expire 10 years from the grant date. There were no issuances of stock options during the three months ended March 31, 2019.

 

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The following table summarizes the Company’s 2016 LTIP non-vested stock option activity for the three months ended March 31, 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

 

7.8

 

Granted

 

 

$

 

$

 

 

Vested(1)

 

(14,889

)

$

19.08-19.66

 

$

19.56

 

0.3

 

Forfeited

 

 

$

 

$

 

 

Stock options outstanding at March 31, 2019

 

55,213

 

 

 

$

19.68

 

7.6

 

Vested and exercisable at end of period(2)

 

151,050

 

$

19.08-20.97

 

$

19.66

 

5.6

 

 


(1)                                       Vested stock options during the three months ended March 31, 2019, were accelerated as a result of a reduction in workforce that occurred during the three months ended March 31, 2019.

(2)                                       Vested and exercisable options at March 31, 2019, had no aggregate intrinsic value.

 

Unrecognized expense as of March 31, 2019, for all outstanding stock options under the 2016 LTIP Plan was $0.1 million and will be recognized over a weighted average period of 0.6 years.

 

Non-Employee Director Restricted Stock Units Containing a Market Condition

 

On November 23, 2016, the Company issued 76,296 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 ASC 718 — Stock Compensation (“ASC 718”) as the awards allow for the withholding of taxes at the discretion of the non-employee director. The liability is re-measured, with a corresponding adjustment to earnings, at each fiscal quarter-end during the performance cycle. The derived service period related to these awards ended in November of 2017. As such, changes in the fair value of the liability and related compensation expense of these awards are no longer recognized pro-rata over the period for which service has already been provided but rather are compensation cost in the period in which the changes occur. As there are inherent uncertainties related to these factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded compensation may not accurately reflect the amount ultimately earned by the non-employee directors.

 

At March 31, 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 $1.28 at March 31, 2019.

 

As of March 31, 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 (1) 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 (2) 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.

 

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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 at March 31, 2019. As of March 31, 2019, unrecognized stock-based compensation related to CEO RSUs containing a market condition was $0.8 million and will be recognized over a weighted-average period of 1.6 years.

 

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, based on the Company’s total stockholder return for the performance period of January 1, 2018 through December 31, 2020.To the extent that the Relative TSR for the performance period is between specified vesting levels, the portion of the restricted stock units that become vested based on the Relative TSR performance shall be determined on a pro-rata basis using straight-line interpolation; provided that the maximum portion of the restricted stock units that may become vested based on the Relative TSR for the performance period shall not exceed 150% of the awards granted. In addition, if the Relative TSR for the Company is negative over the performance period, vesting of these performance stock units is limited to no more than 100%.

 

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 (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.

 

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 for the period ended March 31, 2019. As of March 31, 2019, unrecognized stock-based compensation related to executive management’s restricted stock units containing a market condition was $0.8 million and will be recognized over a weighted-average period of 1.8 years.

 

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. Market conditions under this grant relate to the Company’s price per common share as follows:

 

 

 

Price per Common Share of Stock
for the Performance Period

 

Vesting as % of RSUs Granted

 

Maximum

 

$

12.50

 

150

%

Target

 

$

11.50

 

100

%

Below Target

 

$

10.50

 

66

%

Threshold

 

$

9.50

 

33

%

 

To the extent that the price per common share of 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.

 

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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.

 

A Monte Carlo simulation was used to determine the fair value of these awards at the grant date. The assumptions used to estimate the fair value of the executive management restricted stock unit awards with a market condition are as follows:

 

 

 

Awards Issued
March 7, 2019

 

Risk-free interest rate (1)

 

2.45

%

Dividend yield

 

 

Expected volatility

 

44.0

%

Calculated fair value per unit

 

$

6.77

 

 


(1)   U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the life of the executives restricted stock unit award with a market condition.

 

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 $0.1 million for the period ended March 31, 2019. As of March 31, 2019, unrecognized stock-based compensation related to executive management’s restricted stock units containing a market condition was $1.3 million and will be recognized over a weighted-average period of 1.8 years.

 

The following table reflects the outstanding Executive Management restricted stock units containing a market condition for the three months ended March 31, 2019:

 

 

 

Shares

 

Weighted Average
Fair Value

 

Outstanding at December 31, 2018

 

 

$

 

Granted

 

193,921

 

$

6.77

 

Vested

 

 

$

 

Forfeited

 

 

$

 

Outstanding at March 31, 2019

 

193,921

 

$

6.77

 

 

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12. Income Taxes

 

For the three months ended March 31, 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 three months ended March 31, 2019, the Company’s valuation allowance increased by $4.6 million from December 31, 2018, bringing the total valuation allowance to $114.2 million at March 31, 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 (Loss) Per Share

 

The following table provides a reconciliation of net income (loss) 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 March 31,

 

 

 

2019

 

2018

 

 

 

(in thousands, except per share amounts)

 

Net Income (Loss):

 

 

 

 

 

Net income (loss)

 

$

(17,807

)

$

4,004

 

Participating securities—non-vested restricted stock

 

 

(99

)

Basic and diluted income (loss)

 

$

(17,807

)

$

3,905

 

 

 

 

 

 

 

Common Shares:

 

 

 

 

 

Common shares outstanding — basic (1)

 

22,837

 

25,299

 

Dilutive effect of potential common shares

 

 

 

Common shares outstanding — diluted

 

22,837

 

25,299

 

 

 

 

 

 

 

Net Income (Loss) Per Share:

 

 

 

 

 

Basic

 

$

(0.78

)

$

0.15

 

Diluted

 

$

(0.78

)

$

0.15

 

Antidilutive stock options (2)

 

206

 

500

 

Antidilutive warrants (3)

 

6,980

 

6,626

 

 


(1)                                 Weighted-average common shares outstanding for basic and diluted income per share purposes includes 9,407 shares of common stock that, while not issued and outstanding at March 31, 2019 or 2018, respectively, are required by the First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate as filed on September 28, 2016 (the “Plan”) to be issued. Weighted-average common shares outstanding for basic and diluted income per share purposes also includes 79,389 director shares that were vested as of March 31, 2019, but final issuance of the vested shares was deferred by the non-employee directors until 2021.

 

(2)                                 Amount represents options to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.

 

(3)                                 Amount represents warrants to purchase common stock that are excluded from the diluted net income per share calculations because of their antidilutive effect.

 

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 three months ended March 31, 2018. No transactions with EcoStim occurred during the three months ended March 31, 2019.

 

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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 March 31, 2019 and December 31, 2018, the Company’s total accrual for all loss contingencies was $1.1 million.

 

16. Subsequent Event

 

On May 6, 2019, the Company entered into a definitive merger agreement (“Merger Agreement”) pursuant to which Amplify Energy Corp. (“Amplify”) will merge with a subsidiary of the Company in an all-stock merger-of-equals. Under the terms of the Merger Agreement, Amplify stockholders will receive 0.933 shares of newly issued Company common stock for each Amplify share of common stock. The merger is expected to close in the third quarter of 2019, at which time Amplify and the Company’s stockholders will each own 50% of the outstanding shares of the combined entity.

 

The transaction is subject to the terms and conditions set forth in the Merger Agreement, including holders of a majority of the Company’s stock present at the special meeting having voted in favor of the stock issuance, holders of a majority of Amplify stock having voted in favor of the merger, the waiting period under the U.S. Hart-Scott-Rodino Act having expired or been terminated early, the Company’s stock being issued to Amplify stockholders in connection with the merger being listed on the NYSE and other customary conditions.

 

The transactions contemplated by the Merger Agreement will be treated as a “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 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) with respect to any employee of the Company whose employment is terminated without “cause” (as such term is defined in the applicable Parent Benefit Plan, but also including certain employees who are deemed to be terminated without cause pursuant to the Merger Agreement) on or within one year after the closing of the merger, (A) all Parent Stock Options (as defined in the Merger Agreement) held by such employee shall become fully vested, (B) all Parent RSUs (as defined in the Merger Agreement) held by such employee shall become fully vested and shall be settled promptly upon termination, (C) all Parent PSUs (as defined in the Merger Agreement) that are subject to the achievement of the Company’s specific stock price levels shall be deemed earned at the level specified in the applicable award agreement and shall become vested and settled promptly upon termination, (D) all Parent PSUs that are not described in the foregoing clause (C) shall be deemed earned at the target level of such award and shall become vested and settled promptly upon termination, and (E) all cash amounts pursuant to the “Share Buyback Equalization Program” approved by the board of directors of the Company on December 21, 2018 (the “Equalization Program”) that are owing to such employee(s) shall be paid promptly upon termination, (ii) all Parent RSUs held by members of the board of directors shall become fully vested and shall be settled promptly upon the closing of the merger, and (iii) all cash amounts pursuant to the Equalization Program that are owing to non-employee directors of the Company shall be paid promptly upon the closing of the merger.

 

The Company estimates that between 500,000 and 800,000 unvested stock awards (including stock options) will vest upon closing 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.

 

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

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto for the year ended December 31, 2018, and the related management’s discussion and analysis 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-Q.

 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

Various statements contained in or incorporated by reference into this report are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) 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. These forward-looking statements are subject to a number of 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 affecting 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, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

 

Forward-looking statements may include statements about our:

 

·                  business strategy;

·                  estimated future net reserves 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;

·                  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;

·                  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;

 

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·                  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 that are not historical.

 

Overview

 

We are an independent exploration and production company focused on 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 volume of our oil and natural gas production and the price that we realize from the sale 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 developing oil and natural gas reserves at economical costs is critical to our long-term success.

 

Recent Developments

 

On May 6, 2019, we entered into a definitive merger agreement pursuant to which Amplify will merge with a subsidiary of us in an all-stock merger-of-equals. Under the terms of the merger agreement, Amplify stockholders will receive 0.933 shares of our newly issued common stock for each Amplify share of common stock. The merger is expected to close in the third quarter of 2019, at which time Amplify and our stockholders will each own 50% of the outstanding shares of the combined entity.

 

The transaction is subject to the terms and conditions set forth in the merger agreement, including holders of a majority of our stock present at the special meeting having voted in favor of the stock issuance, holders of a majority of Amplify stock having voted in favor of the merger, the waiting period under the U.S. Hart-Scott-Rodino Act having expired or been terminated early, our stock being issued to Amplify stockholders in connection with the merger being listed on the NYSE and other customary conditions.

 

The transactions contemplated by the Merger Agreement will be treated as a “change in control” as of the effective date for purposes of all Parent Benefit Plans (as defined in the Merger Agreement), including the Parent Stock Plans (as defined in the Merger Agreement) and all applicable employment agreements in effect prior to the effective date to which any of our employees are a party. We have agreed to satisfy promptly all applicable severance, retention and change in control payments and benefits owing to our employees, directors and other service providers under the Parent Benefit Plans. Without limiting the foregoing, (i) with respect to any employee of ours whose employment is terminated without “cause” (as such term is defined in the applicable Parent Benefit Plan, but also including certain employees who are deemed to be terminated without cause pursuant to the Merger Agreement) on or within one year after the closing of the merger, (A) all Parent Stock Options (as defined in the Merger Agreement) held by such employee shall become fully vested, (B) all Parent RSUs (as defined in the Merger Agreement) held by such employee shall become fully vested and shall be settled promptly upon termination, (C) all Parent PSUs (as defined in the Merger Agreement) that are subject to the achievement of our specific stock price levels shall be deemed earned at the level specified in the applicable award agreement and shall become vested and settled promptly upon termination, (D) all Parent PSUs that are not described in the foregoing clause (C) shall be deemed earned at the target level of such award and shall become vested and settled promptly upon termination, and (E) all cash amounts pursuant to the “Share Buyback Equalization Program” approved by our board of directors on December 21, 2018 (the “Equalization Program”) that are owing to such employee(s) shall be paid promptly upon termination, (ii) all Parent RSUs held by members of the board of directors shall become fully vested and shall be settled promptly upon the closing of the merger, and (iii) all cash amounts pursuant to the Equalization Program that are owing to our non-employee directors shall be paid promptly upon the closing of the merger.

 

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Operations Update

 

Mississippian Lime

 

The following table presents our average daily production from our Mississippian Lime asset for the periods presented:

 

 

 

Three Months Ended
March 31, 2019

 

Three Months Ended
December 31, 2018

 

Decrease in
Production

 

 

 

 

 

 

 

 

 

Average daily production:

 

 

 

 

 

 

 

Oil (Bbls)

 

3,381

 

4,463

 

(24.2

)%

Natural gas liquids (Bbls)

 

3,538

 

4,194

 

(15.6

)%

Natural gas (Mcf)

 

37,919

 

46,161

 

(17.9

)%

Net Boe/day

 

13,239

 

16,351

 

(19.0

)%

 

In the first quarter of 2019, we incurred approximately $6.4 million of operational capital expenditures in the Mississippian Lime basin.

 

Anadarko Basin

 

On May 31, 2018, we closed on the sale of our Anadarko Basin assets for $58.0 million in cash ($54.4 million, net of closing adjustments).

 

Capital Expenditures

 

During the three months ended March 31, 2019, we incurred operational capital expenditures of $6.4 million in the Mississippian Lime basin, which consisted of the following:

 

Drilling and completion activities

 

$

5,335

 

Acquisition of acreage and seismic data

 

1,108

 

Operational capital expenditures incurred

 

$

6,443

 

Capitalized G&A, office, ARO & other

 

70

 

Capitalized interest

 

103

 

Total capital expenditures incurred

 

$

6,616

 

 

Factors that Significantly Affect Our Risk

 

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, our cash flows, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

 

We follow the full cost method of accounting for our oil and gas properties. In the first quarter of 2019, the results of our full cost “ceiling test” required us to recognize an impairment of our oil and gas properties of $9.7 million. While this impairment did not impact cash flows from operating activities or liquidity, it did increase our net loss and shareholders’ equity. As a result of the pause in our drilling program, we could continue to incur impairment charges throughout fiscal year 2019. The magnitude of future impairment charges, if any, will be impacted by certain factors outside of our control, such as commodity pricing.

 

We dispose of large volumes of saltwater produced in conjunction with oil and natural gas from drilling and production operations in the Mississippian Lime. Our disposal operations are conducted pursuant to permits issued to us by governmental authorities overseeing such disposal activities.

 

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There continues to be a concern that the injection of saltwater into belowground disposal wells contributes to seismic activity in certain areas, including Oklahoma, where we operate. The Oil and Gas Conservation Division (“OGCD”) of the Oklahoma Corporation Commission established caps for additional wells, including 16 that we operate, on February 24, 2017. On March 1, 2017, the OGCD also issued a statement saying that further actions to reduce the earthquake rate in Oklahoma could be expected. The OGCD has since issued several directives for disposal well shut-in and volume reductions in certain areas following seismic activity. While our current plans are for future disposal wells to inject into formations other than the Arbuckle and we currently operate 10 such non-Arbuckle formation disposal wells, we continue to utilize wells that dispose into the Arbuckle formation. We have timely met and satisfied all requests of the OGCD regarding changes and/or reductions in disposal capacity in our operated disposal wells, all while maintaining our production base without any negative material impact thereto. We believe we are currently in compliance with the OGCD’s latest requests regarding Arbuckle injection limits; however, a change in disposal well regulations or injection limits, or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of saltwater and ultimately increase the cost of our operations and/or reduce the volume of oil and natural gas that we produce from our wells.

 

Results of Operations

 

The following table summarizes our revenues for the periods indicated (in thousands):

 

 

 

Crude Oil

 

NGLs

 

Natural Gas

 

Total

 

Revenues for the three months ended March 31, 2018

 

$

32,414

 

$

11,038

 

$

8,337

 

$

51,789

 

Changes due to volumes

 

(13,423

)

(2,747

)

(2,319

)

(18,489

)

Changes due to price

 

(2,664

)

(2,075

)

592

 

(4,147

)

Revenues for the three months ended March 31, 2019

 

$

16,327

 

$

6,216

 

$

6,610

 

$

29,153

 

 

Oil, NGLs and Natural Gas Pricing

 

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

 

 

 

For the Three Months

 

For the Three Months

 

 

 

 

 

Ended March 31, 2019

 

Ended March 31, 2018

 

% Change

 

AVERAGE SALES PRICES:

 

 

 

 

 

 

 

Oil, without realized derivatives (per Bbl)

 

$

53.65

 

$

62.41

 

(14.0

)%

Oil, with realized derivatives (per Bbl)

 

$

57.00

 

$

59.57

 

(4.3

)%

Natural gas liquids, without realized derivatives (per Bbl)

 

$

19.52

 

$

26.04

 

(25.0

)%

Natural gas liquids, with realized derivatives (per Bbl)

 

$

19.52

 

$

26.04

 

(25.0

)%

Natural gas, without realized derivatives (per Mcf)

 

$

1.94

 

$

1.76

 

10.2

%

Natural gas, with realized derivatives (per Mcf)

 

$

1.86

 

$

2.04

 

(8.8

)%

 

Oil, NGLs and Natural Gas Production

 

 

 

For the Three Months

 

For the Three Months

 

 

 

 

 

Ended March 31, 2019

 

Ended March 31, 2018

 

% Change

 

PRODUCTION DATA:

 

 

 

 

 

 

 

Oil (Bbls/d)

 

 

 

 

 

 

 

Mississippian Lime

 

3,381

 

4,564

 

(25.9

)%

Anadarko Basin(1)

 

 

1,207

 

(100.0

)%

Natural gas liquids (Bbls/d)

 

 

 

 

 

 

 

Mississippian Lime

 

3,538

 

3,644

 

(2.9

)%

Anadarko Basin(1)

 

 

1,065

 

(100.0

)%

Natural gas (Mcf/d)

 

 

 

 

 

 

 

Mississippian Lime

 

37,919

 

43,857

 

(13.5

)%

Anadarko Basin(1)

 

 

8,671

 

(100.0

)%

Combined (Boe/d)

 

 

 

 

 

 

 

Mississippian Lime

 

13,239

 

15,518

 

(14.7

)%

Anadarko Basin(1)

 

 

3,717

 

(100.0

)%

 


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

 

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Oil Revenues

 

Oil volumes in the Mississippian Lime decreased 1,183 Boe/day, or 25.9% for the three months ended March 31, 2019, primarily due to lower production as a result of reduced drilling activity and natural decline. Average oil sales prices, without realized derivatives, decreased by $8.76 per barrel, or 14.0%, largely as a result of a decrease in prevailing market prices.

 

NGLs Revenues

 

NGLs volumes in the Mississippian Lime decreased 106 Boe/day, or 2.9%, for the three months ended March 31, 2019, primarily as a result of reduced drilling activity and natural decline. Average NGLs sales prices, without realized derivatives, decreased by $6.52 per barrel, or 25.0%, largely as a result of lower oil prices, which correlate with NGLs pricing.

 

Natural Gas Revenues

 

Natural gas volumes in the Mississippian Lime decreased 5,938 Mcf/day, or 13.5%, as a result of reduced drilling activity and natural decline. Average natural gas sales prices, without realized derivatives, increased by $0.18 per Mcf, or 10.2%, largely due to higher prevailing index prices at our delivery points.

 

Losses on Commodity Derivative Contracts—Net

 

A summary of our open commodity derivative positions is included in Note 5 to the financial statements included in “Part I. Financial Information — Item 1. Financial Statements” of this report. The following tables provide financial information associated with our oil and natural gas hedges for the periods indicated (in thousands):