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 June 30, 2018

 

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
(State or other jurisdiction of
incorporation or organization)

 

45-3691816
(I.R.S. Employer
Identification No.)

 

 

 

321 South Boston Avenue, Suite 1000
Tulsa, Oklahoma

(Address of principal executive offices)

 

74103
(Zip Code)

 

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

 

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

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or 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 o

(Do not check if a smaller reporting company)

 

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 August 2, 2018 is shown below:

 

Class

 

Number of shares outstanding

Common stock, $0.01 par value

 

25,256,957

 

DOCUMENTS INCORPORATED BY REFERENCE

None.

 

 

 



Table of Contents

 

MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2018

 

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 June 30, 2018 and December 31, 2017 (unaudited)

4

Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2018  and 2017  (unaudited)

5

Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2018  and 2017 (unaudited)

6

Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2018 and 2017 (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

24

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

37

 

 

Item 4. Controls and Procedures

38

 

 

PART II — OTHER INFORMATION

 

 

Item 1. Legal Proceedings

39

 

 

Item 1A. Risk Factors

39

 

 

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

39

 

 

Item 3. Defaults upon Senior Securities

39

 

 

Item 4. Mine Safety Disclosures

39

 

 

Item 5. Other Information

39

 

 

Item 6. Exhibits

39

 

 

EXHIBIT INDEX

40

 

 

SIGNATURES

41

 

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.

 

MMBoe:  One million barrels of oil equivalent.

 

MMBtu:  One million British thermal units.

 

Net acres:  The percentage of total acres an owner has out of a particular number of acres, or a specified tract.

 

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



Table of Contents

 

PART I — FINANCIAL INFORMATION

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)

 

 

 

June 30, 2018

 

December 31, 2017

 

ASSETS

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

 

$

6,256

 

$

68,498

 

Accounts receivable:

 

 

 

 

 

Oil and gas sales

 

30,278

 

32,455

 

Joint interest billing

 

4,598

 

3,297

 

Other

 

298

 

166

 

Commodity derivative contracts

 

 

762

 

Other current assets

 

2,474

 

1,510

 

Total current assets

 

43,904

 

106,688

 

PROPERTY AND EQUIPMENT:

 

 

 

 

 

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

 

 

 

 

 

Proved properties

 

778,741

 

765,308

 

Unproved properties not being amortized

 

4,383

 

7,065

 

Other property and equipment

 

6,243

 

6,508

 

Less accumulated depreciation, depletion, amortization and impairment

 

(235,948

)

(204,419

)

Net property and equipment

 

553,419

 

574,462

 

OTHER NONCURRENT ASSETS

 

5,263

 

6,978

 

TOTAL

 

$

602,586

 

$

688,128

 

LIABILITIES AND EQUITY

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable

 

$

19,216

 

$

11,547

 

Accrued liabilities

 

40,327

 

42,842

 

Commodity derivative contracts

 

11,549

 

3,433

 

Total current liabilities

 

71,092

 

57,822

 

LONG-TERM LIABILITIES:

 

 

 

 

 

Asset retirement obligations

 

7,573

 

15,506

 

Commodity derivative contracts

 

3,293

 

562

 

Long-term debt

 

28,059

 

128,059

 

Other long-term liabilities

 

578

 

592

 

Total long-term liabilities

 

39,503

 

144,719

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (Note 14)

 

 

 

 

 

 

 

 

 

 

 

STOCKHOLDERS’ EQUITY:

 

 

 

 

 

Preferred stock, $0.01 par value, 50,000,000 shares authorized; no shares issued or outstanding at June 30, 2018 and December 31, 2017

 

 

 

Warrants, 6,625,554 warrants outstanding at June 30, 2018 and December 31, 2017

 

37,329

 

37,329

 

Common stock, $0.01 par value, 250,000,000 shares authorized; 25,386,104 shares issued and 25,256,957 shares outstanding at June 30, 2018; 25,272,969 shares issued and 25,173,346 shares outstanding at December 31, 2017

 

254

 

253

 

Treasury stock

 

(2,081

)

(1,603

)

Additional paid-in-capital

 

529,175

 

524,755

 

Retained deficit

 

(72,686

)

(75,147

)

Total stockholders’ equity

 

491,991

 

485,587

 

TOTAL

 

$

602,586

 

$

688,128

 

 

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 June 30,

 

For the Six Months
Ended June 30,

 

 

 

2018

 

2017

 

2018

 

2017

 

REVENUES:

 

 

 

 

 

 

 

 

 

Oil sales

 

$

34,202

 

$

27,271

 

$

66,616

 

$

58,307

 

Natural gas liquid sales

 

11,893

 

9,730

 

22,931

 

20,924

 

Natural gas sales

 

6,782

 

15,253

 

15,119

 

32,351

 

Other revenue

 

795

 

932

 

1,850

 

1,754

 

Total revenues from contracts with customers

 

53,672

 

53,186

 

106,516

 

113,336

 

Gains (losses) on commodity derivative contracts—net

 

(11,348

)

7,493

 

(15,287

)

12,358

 

Total revenues

 

42,324

 

60,679

 

91,229

 

125,694

 

EXPENSES:

 

 

 

 

 

 

 

 

 

Lease operating and workover

 

16,952

 

16,559

 

31,760

 

32,411

 

Gathering and transportation (Note 3)

 

67

 

3,641

 

124

 

7,328

 

Severance and other taxes

 

2,776

 

1,695

 

5,638

 

3,816

 

Asset retirement accretion

 

250

 

283

 

547

 

559

 

Depreciation, depletion, and amortization

 

16,484

 

15,959

 

31,697

 

31,301

 

General and administrative

 

5,190

 

7,572

 

15,047

 

15,847

 

Advisory fees

 

850

 

 

850

 

 

Total expenses

 

42,569

 

45,709

 

85,663

 

91,262

 

OPERATING INCOME (LOSS)

 

(245

)

14,970

 

5,566

 

34,432

 

OTHER EXPENSE:

 

 

 

 

 

 

 

 

 

Interest income

 

5

 

 

24

 

 

Interest expense—net of amounts capitalized

 

(1,302

)

(1,228

)

(3,129

)

(2,205

)

Total other expense

 

(1,297

)

(1,228

)

(3,105

)

(2,205

)

INCOME (LOSS) BEFORE TAXES

 

(1,542

)

13,742

 

2,461

 

32,227

 

Income tax expense

 

 

 

 

 

NET INCOME (LOSS)

 

$

(1,542

)

$

13,742

 

$

2,461

 

$

32,227

 

Participating securities—non-vested restricted stock

 

 

(360

)

(68

)

(897

)

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS

 

$

(1,542

)

$

13,382

 

$

2,393

 

$

31,330

 

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

 

$

(0.06

)

$

0.53

 

$

0.09

 

$

1.25

 

Basic and diluted weighted average number of common shares outstanding (Note 12)

 

25,332

 

25,093

 

25,316

 

25,053

 

 

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, 2017

 

$

 

$

253

 

$

37,329

 

$

(1,603

)

$

524,755

 

$

(75,147

)

$

485,587

 

Share-based compensation

 

 

1

 

 

 

4,420

 

 

4,421

 

Acquisition of treasury stock

 

 

 

 

(478

)

 

 

(478

)

Net income

 

 

 

 

 

 

2,461

 

2,461

 

Balance as of June 30, 2018

 

$

 

$

254

 

$

37,329

 

$

(2,081

)

$

529,175

 

$

(72,686

)

$

491,991

 

 

 

 

Series A
Preferred
Stock

 

Common
Stock

 

Warrants

 

Treasury
Stock

 

Additional
Paid-in-Capital

 

Retained
Earnings

 

Total
Stockholders’
Equity

 

Balance as of December 31, 2016

 

$

 

$

250

 

$

37,329

 

$

 

$

514,305

 

$

9,930

 

$

561,814

 

Share-based compensation

 

 

1

 

 

 

5,251

 

 

5,252

 

Acquisition of treasury stock

 

 

 

 

(622

)

 

 

(622

)

Net income

 

 

 

 

 

 

32,227

 

32,227

 

Balance as of June 30, 2017

 

$

 

$

251

 

$

37,329

 

$

(622

)

$

519,556

 

$

42,157

 

$

598,671

 

 

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

 

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Table of Contents

 

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

 

 

 

For the Six Months Ended June 30,

 

 

 

2018

 

2017

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

Net income

 

$

2,461

 

$

32,227

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

(Gains) losses on commodity derivative contracts—net

 

15,287

 

(12,358

)

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

 

(3,677

)

3,240

 

Asset retirement accretion

 

547

 

559

 

Depreciation, depletion, and amortization

 

31,697

 

31,301

 

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

 

3,425

 

4,267

 

Amortization of deferred financing costs

 

216

 

169

 

Change in operating assets and liabilities:

 

 

 

 

 

Accounts receivable—oil and gas sales

 

1,437

 

5,519

 

Accounts receivable—JIB and other

 

(1,713

)

1,310

 

Other current and noncurrent assets

 

(754

)

642

 

Accounts payable

 

2,301

 

809

 

Accrued liabilities

 

(1,921

)

(4,466

)

Other

 

(14

)

(42

)

Net cash provided by operating activities

 

$

49,292

 

$

63,177

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Investment in property and equipment

 

$

(65,843

)

$

(54,369

)

Proceeds from the sale of oil and gas properties

 

54,432

 

 

Proceeds from the sale of oil and gas equipment

 

355

 

1,350

 

Net cash used in investing activities

 

$

(11,056

)

$

(53,019

)

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Repayment of revolving credit facility

 

$

(100,000

)

$

 

Deferred financing costs

 

 

(375

)

Repurchase of restricted stock for tax withholdings

 

(478

)

(622

)

Net cash used in financing activities

 

$

(100,478

)

$

(997

)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

$

(62,242

)

$

9,161

 

Cash and cash equivalents, beginning of period

 

$

68,498

 

$

76,838

 

Cash and cash equivalents, end of period

 

$

6,256

 

$

85,999

 

 

 

 

 

 

 

SUPPLEMENTAL INFORMATION:

 

 

 

 

 

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

 

$

23,219

 

$

17,055

 

Cash paid for interest, net of capitalized interest of $0.2 million and $1.6 million, respectively

 

$

3,010

 

$

2,107

 

 

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

 

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Table of Contents

 

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, 2017 included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 14, 2018.

 

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.

 

As a result of the adoption of Accounting Standards Update 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), certain balances included in the unaudited interim condensed consolidated statements of operations for prior periods have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on net income, cash flows or stockholders’ equity for any period presented.

 

Recent Accounting Pronouncements Adopted During the Period

 

In March 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2018-05, “Income Taxes (Topic 740), Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118” (“ASU 2018-05”). ASU 2018-05 amends certain SEC paragraphs pursuant to the issuance of the December 2017 SEC Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”), which provides guidance on accounting for the tax effects of the Tax Cuts and Jobs Act (“the Tax Act”). SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act’s enactment date for companies to complete its accounting under FASB Accounting Standards Codification (“ASC”) 740. In accordance with SAB 118, to the extent a company has not completed its analysis of the Tax Act but can provide a reasonable estimate, it must record a provisional estimate in its financial statements. The Company has accounted for certain tax effects of the Tax Act under the guidance of SAB 118, on a provisional basis. The Company’s accounting for certain income tax effects is incomplete due to forthcoming guidance and the ongoing analysis of final year-end data and tax positions. The Company expects to complete its analysis within the measurement period in accordance with SAB 118.

 

In May 2014, the FASB issued ASU 2014-09. ASU 2014-09 provides guidance concerning the recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09 is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The Company adopted ASU 2014-09 using the modified retrospective approach. The adoption of this guidance did not have a material impact on the Company’s financial statements. See Note 3 below for further details.

 

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Table of Contents

 

Recent Accounting Pronouncements Issued But Not Yet Adopted

 

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 nonemployees for goods and services. Consequently, the accounting for share-based payments to nonemployees and employees with be substantially aligned. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company does not believe the adoption of ASU 2018-07 will have a material impact on its financial position, results of operations or cash flows.

 

In July 2017, the 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 fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company does not believe the adoption of ASU 2017-11 will 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. 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 in 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.

 

For finance leases, the Company will recognize a ROU asset and liability, initially measured at the present value of the lease payments. Interest expense will be recognized on the lease liability separately from the amortization of the ROU asset. The Company will recognize payments of principal on the lease liability within financing activities in the consolidated statement of cash flows and payments of interest within operating activities in the consolidated statement of cash flows. For operating leases, the Company will recognize a ROU asset and liability, initially measured at the present value of the lease payments. The Company will recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis and all cash payments will be recognized in operating activities within the consolidated statement of cash flows.

 

In January 2018, the FASB issued Accounting Standards Update 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. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available.

 

The Company is currently analyzing contracts to determine if they meet the definition of a lease under ASU 2016-02. The Company cannot reasonably quantify the impact of adoption at this time and expects to complete the assessment of ASU 2016-02 during the fourth quarter of 2018.

 

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Table of Contents

 

3. Impact of ASC 606 Adoption

 

On January 1, 2018, the Company adopted Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”) using the modified retrospective method of transition. ASC 606 supersedes previous revenue recognition requirements in Accounting Standards Codification 605, Revenue Recognition (“ASC 605”) and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.

 

The impact of adoption on the Company’s results is as follows for the periods presented (in thousands):

 

 

 

Three Months Ended June 30, 2018

 

 

 

Under ASC 606

 

Under ASC 605

 

Decrease

 

 

 

 

 

 

 

 

 

Oil sales

 

$

34,202

 

$

34,218

 

$

(16

)

Natural gas liquid sales

 

11,893

 

11,911

 

(18

)

Natural gas sales

 

6,782

 

10,187

 

(3,405

)

Gathering and transportation

 

67

 

3,429

 

(3,362

)

Lease operating and workover expense

 

16,952

 

17,029

 

(77

)

 

 

 

 

 

 

 

 

Net loss

 

$

(1,542

)

$

(1,542

)

$

 

 

 

 

 

 

 

 

 

Retained deficit

 

$

(72,686

)

$

(72,686

)

$

 

 

 

 

Six Months Ended June 30, 2018

 

 

 

Under ASC 606

 

Under ASC 605

 

Decrease

 

 

 

 

 

 

 

 

 

Oil sales

 

$

66,616

 

$

66,642

 

$

(26

)

Natural gas liquid sales

 

22,931

 

22,976

 

(45

)

Natural gas sales

 

15,119

 

21,587

 

(6,468

)

Gathering and transportation

 

124

 

6,499

 

(6,375

)

Lease operating and workover expense

 

31,760

 

31,924

 

(164

)

 

 

 

 

 

 

 

 

Net income

 

$

2,461

 

$

2,461

 

$

 

 

 

 

 

 

 

 

 

Retained deficit

 

$

(72,686

)

$

(72,686

)

$

 

 

The primary impact to the Company’s revenues as a result of the adoption of ASC 606 is the netting of certain deductions and costs against revenue instead of its historical practice of presenting such expenses gross in gathering and transportation. These changes are due to analysis of the control model in ASC 606. Further discussion of the Company’s revenue recognition under ASC 606 is included below.

 

Revenue Recognition

 

Oil, NGLs and natural gas revenues are recognized at the point in time that control of the product is transferred to the customer and collectability is reasonably assured. Other revenue consists of iodine royalty income, which are point in time sales, and salt water disposal income, which is recognized over time. A more detailed summary of the underlying contracts that give rise to revenue and the method of recognition is included below.

 

Natural Gas and NGLs Sales

 

Under the Company’s gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas, sells the resulting NGLs and residue gas to third-parties and pays the Company for the NGLs and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts that the Company concluded that it was the principal, the ultimate third party is the customer, and it recognizes revenue on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Alternatively, for those contracts that the Company has concluded that it is the agent, the purchaser is its customer, and it recognizes revenue based on the net amount of the proceeds received from the purchaser.

 

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Table of Contents

 

Oil Sales

 

Under the Company’s oil sales contracts, it delivers all or a specified percentage of the crude oil production from specified leases to the purchaser at the wellhead. The Company sells oil production at the wellhead and collects an agreed-upon index price, net of applicable transport costs. The Company recognizes revenue when control transfers to the purchaser at the wellhead at the net price received.

 

Other Revenue

 

Other revenue consists of fees charged to outside working interest owners for salt water disposal as well as royalties received from a third-party for iodine extracted from the Company’s salt water. Salt water disposal revenue is recognized over time because the customer simultaneously receives and consumes the benefit of the salt water disposal service as the service is provided. For salt water disposal income the Company utilized the practical expedient in ASC 606-10-55-18 that states that if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date, the entity may recognize revenue in the amount to which the entity has a right to invoice. Iodine royalty revenue is recognized point-in-time when control transfers to the customer.

 

Imbalances

 

The Company recognizes revenue for all oil, NGLs and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company’s share of remaining proved oil and gas reserves. The Company had no significant imbalances at June 30, 2018 or December 31, 2017.

 

Significant Judgments

 

Principal versus agent

 

The Company engages in various types of transactions in which midstream entities process its wet gas and, in some scenarios, subsequently market resulting NGLs and residue gas to third-party customers on its behalf, such as its percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. The Company analyzed control under ASC 606 and determined for those contracts where control passes at the wellhead, the Company acts as agent and revenue should be recognized net of amounts paid after such control passed for costs such as gathering, compression, processing and transportation, among others. The determination of control and the presentation of revenues was completed for ASC 606 purposes only. Amounts paid by the Company for royalties are calculated under a different methodology and may differ from the amount of revenues recognized under ASC 606.

 

Transaction price allocated to remaining performance obligations

 

A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

 

For the Company’s product sales that have a contract term greater than one year,  it has utilized the practical expedient in ASC 606-10-50-14A that states it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

 

For salt water disposal income, the Company has utilized the practical expedient in ASC 606-10-50-14 that states that if it recognizes revenue from the satisfaction of the performance obligation in accordance with the right to invoice practical expedient then it is exempted from disclosure of the transaction price allocated to remaining performance obligations.

 

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Table of Contents

 

Prior-period performance obligations

 

The Company records revenue in the month production is delivered and control passes to the customer. However settlement statements and payment may not be received for 30 to 90 days after the date production occurs, and as a result, the Company is required to estimate the amount of production that was delivered and the price that will be received for the sale of the product. The Company utilizes its knowledge of the properties, its historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices and other pertinent factors as the basis for these estimates. The Company records the variances between its estimates and the actual amounts received in the month payment is received and such variances have historically not been significant. For the three and six months ended June 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

 

4. Fair Value Measurements of Financial Instruments

 

Assets and Liabilities Measured at Fair Value on a Recurring Basis

 

Derivative Instruments

 

Commodity derivative contracts reflected in the unaudited interim condensed consolidated balance sheets are recorded at estimated fair value. At June 30, 2018, all of the Company’s commodity derivative contracts were with four bank counterparties and were classified as Level 2 in the fair value input hierarchy. The fair value of the Company’s commodity derivatives are determined using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, 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 June 30, 2018

 

 

 

Quoted Prices

 

Significant Other

 

Significant

 

 

 

 

 

in Active Markets
(Level 1)

 

Observable Inputs
(Level 2)

 

Unobservable Inputs
(Level 3)

 

Total

 

 

 

(in thousands)

 

Derivative Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

 

$

 

$

 

Commodity derivative gas swaps

 

$

 

$

79

 

$

 

$

79

 

Commodity derivative oil collars

 

$

 

$

3,058

 

$

 

$

3,058

 

Commodity derivative gas collars

 

$

 

$

698

 

$

 

$

698

 

Total assets

 

$

 

$

3,835

 

$

 

$

3,835

 

 

 

 

 

 

 

 

 

 

 

Derivative Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

(6,371

)

$

 

$

(6,371

)

Commodity derivative gas swaps

 

$

 

$

(476

)

$

 

$

(476

)

Commodity derivative oil collars

 

$

 

$

(11,408

)

$

 

$

(11,408

)

Commodity derivative gas collars

 

$

 

$

(422

)

$

 

$

(422

)

Total liabilities

 

$

 

$

(18,677

)

$

 

$

(18,677

)

 

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Table of Contents

 

 

 

Fair Value Measurements at December 31, 2017

 

 

 

Quoted Prices

 

Significant Other

 

Significant

 

 

 

 

 

in Active Markets
(Level 1)

 

Observable Inputs
(Level 2)

 

Unobservable Inputs
(Level 3)

 

Total

 

 

 

(in thousands)

 

Derivative Assets:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

 

$

 

$

 

Commodity derivative gas swaps

 

$

 

$

821

 

$

 

$

821

 

Commodity derivative oil collars

 

$

 

$

952

 

$

 

$

952

 

Commodity derivative gas collars

 

$

 

$

2,611

 

$

 

$

2,611

 

Total assets

 

$

 

$

4,384

 

$

 

$

4,384

 

 

 

 

 

 

 

 

 

 

 

Derivative Liabilities:

 

 

 

 

 

 

 

 

 

Commodity derivative oil swaps

 

$

 

$

(3,679

)

$

 

$

(3,679

)

Commodity derivative gas swaps

 

$

 

$

 

$

 

$

 

Commodity derivative oil collars

 

$

 

$

(2,605

)

$

 

$

(2,605

)

Commodity derivative gas collars

 

$

 

$

(1,333

)

$

 

$

(1,333

)

Total liabilities

 

$

 

$

(7,617

)

$

 

$

(7,617

)

 

5. Risk Management and Derivative Instruments

 

The Company’s production is exposed to fluctuations in crude oil, NGLs and natural gas prices. The Company believes it is prudent to manage the variability in cash flows by, at times, entering into derivative financial instruments to economically hedge a portion of its crude and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and collars, to manage fluctuations in cash flows resulting from changes in commodity prices.

 

·                  Swaps: The Company receives or pays a fixed price for the commodity and pays or receives a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

 

·                  Three-way collars: A three-way collar contains a fixed floor price (long put), fixed sub-floor price (short put), and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, the Company receives the ceiling strike price and pays the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the sub-floor price, the Company receives the floor strike price and pays the market price. If the market price is below the sub-floor price, the Company receives the market price plus the difference between the floor and the sub-floor strike prices and pays the market price.

 

These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The crude oil and natural gas reference prices upon which the commodity derivative contracts are based reflect various market indices that management believes correlates with actual prices received by the Company for its crude oil and natural gas production.

 

Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Due to the netting arrangements, had the Company’s counterparties failed to perform under existing commodity derivative contracts at June 30, 2018, the Company would not have experienced a loss.

 

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Table of Contents

 

Commodity Derivative Contracts

 

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

 

 

 

NYMEX WTI

 

 

 

Fixed Swaps

 

Three-Way Collars

 

 

 

Hedge
Position
(Bbls)

 

Weighted
Avg
Strike
Price

 

Hedge
Position
(Bbls)

 

Weighted
Avg
Ceiling
Price

 

Weighted
Avg Floor
Price

 

Weighted
Avg
Sub-Floor
Price

 

Quarter Ended:

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2018

 

159,250

 

$

52.50

 

182,000

 

$

60.65

 

$

50.00

 

$

40.00

 

September 30, 2018(1)

 

175,720

 

$

57.23

 

184,000

 

$

59.93

 

$

50.00

 

$

40.00

 

December 31, 2018(1)

 

313,720

 

$

58.59

 

46,000

 

$

56.70

 

$

50.00

 

$

40.00

 

March 31, 2019(1)

 

171,000

 

$

66.48

 

180,000

 

$

63.14

 

$

53.75

 

$

43.75

 

June 30, 2019(1)

 

133,900

 

$

64.86

 

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

 

 

 

 

NYMEX HENRY HUB

 

 

 

Fixed Swaps

 

Three-Way Collars

 

 

 

Hedge
Position
(MMBtu)

 

Weighted
Avg Strike
Price

 

Hedge
Position
(MMBtu)

 

Weighted
Avg
Ceiling
Price

 

Weighted
Avg
Floor
Price

 

Weighted
Avg
Sub-Floor
Price

 

Quarter Ended:

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2018

 

1,155,000

 

$

2.82

 

1,365,000

 

$

3.40

 

$

3.00

 

$

2.50

 

September 30, 2018(1)

 

2,116,000

 

$

2.84

 

1,380,000

 

$

3.40

 

$

3.00

 

$

2.50

 

December 31, 2018(1)

 

2,055,000

 

$

2.95

 

1,380,000

 

$

3.40

 

$

3.00

 

$

2.50

 

March 31, 2019(1)

 

1,980,000

 

$

3.01

 

1,350,000

 

$

3.40

 

$

3.00

 

$

2.50

 

 


(1)          Positions shown represent open commodity derivative contract positions as of June 30, 2018.

 

Balance Sheet Presentation

 

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

 

Type

 

Balance Sheet Location (1)

 

June 30, 2018

 

December 31, 2017

 

Gas swaps

 

Derivative financial instruments — current assets

 

$

 

$

821

 

Oil collars

 

Derivative financial instruments — current assets

 

 

(760

)

Gas collars

 

Derivative financial instruments — current assets

 

 

701

 

Total derivative financial instruments current assets

 

$

 

$

762

 

 

 

 

 

 

 

 

 

Oil swaps

 

Derivative financial instruments — current liabilities

 

$

(6,209

)

$

(3,679

)

Gas swaps

 

Derivative financial instruments — current liabilities

 

(396

)

 

Oil collars

 

Derivative financial instruments — current liabilities

 

(5,220

)

(370

)

Gas collars

 

Derivative financial instruments — current liabilities

 

276

 

616

 

Total derivative financial instruments current liabilities

 

$

(11,549

)

$

(3,433

)

 

 

 

 

 

 

 

 

Oil swaps

 

Derivative financial instruments — noncurrent liabilities

 

$

(162

)

$

(523

)

Oil collars

 

Derivative financial instruments — noncurrent liabilities

 

(3,131

)

(39

)

Total derivative financial instruments noncurrent liabilities

 

$

(3,293

)

$

(562

)

 

 

 

 

 

 

 

 

Total derivative fair value at period end

 

$

(14,842

)

$

(3,233

)

 

14



Table of Contents

 


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

 

The following table summarizes the location and fair value amounts of all commodity derivative as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited interim condensed consolidated balance sheets for the periods presented (in thousands):

 

 

 

 

 

June 30, 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

 

$

1,366

 

$

(1,366

)

$

 

Commodity contracts

 

Derivative financial instruments — noncurrent

 

2,469

 

(2,469

)

 

 

 

 

 

$

3,835

 

$

(3,835

)

$

 

Derivative Liabilities:

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Derivative financial instruments — current

 

$

(12,915

)

$

1,366

 

$

(11,549

)

Commodity contracts

 

Derivative financial instruments — noncurrent

 

(5,762

)

2,469

 

(3,293

)

 

 

 

 

$

(18,677

)

$

3,835

 

$

(14,842

)

 

 

 

 

 

December 31, 2017

 

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

 

$

3,479

 

$

(2,717

)

$

762

 

Commodity contracts

 

Derivative financial instruments — noncurrent

 

905

 

(905

)

 

 

 

 

 

$

4,384

 

$

(3,622

)

$

762

 

Derivative Liabilities:

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Derivative financial instruments — current

 

$

(6,150

)

$

2,717

 

$

(3,433

)

Commodity contracts

 

Derivative financial instruments — noncurrent

 

(1,467

)

905

 

(562

)

 

 

 

 

$

(7,617

)

$

3,622

 

$

(3,995

)

 

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 in gains (losses) on commodity derivative contracts—net within revenues in the unaudited interim condensed consolidated statements of operations.

 

The following table presents net cash received or net cash paid for the settlement of commodity derivative contracts and unrealized net gains or unrealized net losses recorded by the Company related to the change in fair value of the derivative instruments in gains (losses) on commodity derivative contracts—net for the periods presented (in thousands):

 

 

 

For the Three Months
Ended June 30,

 

For the Six Months
Ended June 30,

 

 

 

2018

 

2017

 

2018

 

2017

 

Net cash received (paid) for commodity derivative contracts

 

$

(3,518

)

$

2,429

 

$

(3,677

)

$

3,240

 

Unrealized net gains (losses)

 

(7,830

)

5,064

 

(11,610

)

9,118

 

Gains on commodity derivative contracts—net

 

$

(11,348

)

$

7,493

 

$

(15,287

)

$

12,358

 

 

Net cash received (paid) for commodity derivative contracts, as presented in the table above, represent realized gains (losses) related to the Company’s derivative instruments. In addition to these 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 cash 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:

 

 

 

June 30, 2018

 

December 31, 2017

 

 

 

(in thousands)

 

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

 

 

 

 

 

Proved properties

 

$

778,741

 

$

765,308

 

Unproved properties not being amortized

 

4,383

 

7,065

 

Other property and equipment

 

6,243

 

6,508

 

Less accumulated depreciation, depletion, amortization and impairment

 

(235,948

)

(204,419

)

Net property and equipment

 

$

553,419

 

$

574,462

 

 

Oil and Gas Properties

 

The Company capitalizes internal costs directly related to exploration and development activities to oil and gas properties. During the three and six months ended June 30, 2018 and 2017, the Company capitalized the following (in thousands):

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2018

 

2017

 

2018

 

2017

 

Internal costs capitalized to oil and gas properties (1)

 

$

922

 

$

1,412

 

$

1,817

 

$

3,005

 

 


(1)         Inclusive of $0.3 million and $0.5 million of qualifying share-based compensation expense for the three months ended June 30, 2018 and 2017, respectively. For the six months ended June 30, 2018 and 2017, inclusive of $0.5 million and $1.2 million, respectively, of qualifying share-based compensation expense.

 

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 six months ended June 30, 2018 and 2017, the Company disposed of certain oil and gas equipment for cash proceeds of $0.4 million and $1.4 million, respectively, which were reflected as reduction of oil and gas properties with no gain or loss recognized. In addition, during the six months ended June 30, 2018, the Company disposed of its Anadarko Basin assets, which is discussed further below.

 

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. While the Company did not record any impairments of oil and gas properties during the three or six months ended June 30, 2018 or 2017, the Company recorded impairments of oil and gas properties during the year ended December 31, 2017, the period January 1, 2016 through October 20, 2016 and the year ended December 31, 2015.

 

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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
June 30,

 

Three Months Ended
June 30,

 

Six Months Ended
June 30,

 

Six Months Ended
June 30,

 

 

 

2018

 

2017

 

2018

 

2017

 

2018

 

2017

 

2018

 

2017

 

 

 

(in thousands)

 

(per Boe)

 

(in thousands)

 

(per Boe)

 

Depletion expense

 

$

15,898

 

$

15,367

 

$

8.97

 

$

7.51

 

$

30,520

 

$

30,120

 

$

8.71

 

$

7.23

 

Depreciation on other property and equipment

 

586

 

592

 

0.33

 

0.29

 

1,177

 

1,181

 

0.34

 

0.28

 

Depreciation, depletion, and amortization

 

$

16,484

 

$

15,959

 

$

9.30

 

$

7.80

 

$

31,697

 

$

31,301

 

$

9.05

 

$

7.51

 

 

Oil and gas unproved properties include costs that are not being depleted or amortized. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are transferred to proved properties and become part of our depletion base and subject to the full cost ceiling limitation. No impairment of unproved properties was recorded during the three or six months ended June 30, 2018 or 2017. Unproved property was $4.4 million and $7.1 million at June 30, 2018 and December 31, 2017, 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.

 

Sale of Anadarko Basin Assets

 

On May 31, 2018, the Company closed on the sale of its Anadarko Basin assets for $58.0 million in cash ($54.4 million, net of closing adjustments), subject to standard post-closing adjustments to occur within 120 days of closing. The net proceeds were reflected as a reduction of oil and natural gas properties, with no gain or loss recognized as the sale did not result in a significant alteration of the full cost pool. The Company used $50.0 million of the net proceeds from the sale of the Anadarko Basin assets to pay down a portion of outstanding borrowings under the Company’s reserves-based revolving credit facility (“RBL”) and retained the remainder for general corporate purposes.

 

7. Accrued Liabilities

 

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

 

 

 

June 30, 2018

 

December 31, 2017

 

 

 

(in thousands)

 

Accrued oil and gas capital expenditures

 

$

9,768

 

$

9,081

 

Accrued revenue and royalty distributions

 

16,924

 

18,701

 

Accrued lease operating and workover expense

 

4,516

 

5,150

 

Accrued interest

 

162

 

108

 

Accrued taxes

 

2,278

 

2,758

 

Compensation and benefit related accruals

 

2,821

 

4,520

 

Other

 

3,858

 

2,524

 

Accrued liabilities

 

$

40,327

 

$

42,842

 

 

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8. Asset Retirement Obligations

 

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

 

 

 

Six Months Ended June 30,

 

 

 

2018

 

2017

 

Asset retirement obligations — beginning of period

 

$

15,506

 

$

14,200

 

Liabilities incurred

 

219

 

117

 

Revisions

 

 

 

Liabilities settled

 

(1

)

(35

)

Liabilities eliminated through asset sales

 

(8,698

)

 

Current period accretion expense

 

547

 

559

 

Asset retirement obligations — end of period

 

$

7,573

 

$

14,841

 

 

9. Debt

 

Reserves-Based Revolving Credit Facility

 

At June 30, 2018 and December 31, 2017, the Company maintained an RBL with a borrowing base of $170.0 million. During the six months ended June 30, 2018, the Company paid down $100.0 million of its RBL utilizing $50.0 million of available cash on hand and $50.0 million of the net proceeds from the sale of its Anadarko Basin assets. At June 30, 2018 and December 31, 2017, the Company had $28.1 million and $128.1 million, respectively, drawn on the RBL and had outstanding letters of credit obligations totaling $1.9 million. As a result, at June 30, 2018, the Company had $140.0 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 June 30, 2018, the weighted average interest rate was 8.0%, excluding amortization expense of deferred financing costs. 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 June 30, 2018 and December 31, 2017, 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.

 

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.

 

The Company was in compliance with all debt covenants at June 30, 2018.

 

On April 19, 2018, the Company’s borrowing base was redetermined at the existing amount of $170.0 million. The Company’s Anadarko Basin assets in Texas and Oklahoma were excluded from the redetermination of the borrowing base and subsequently divested, as discussed above.

 

The Company believes the carrying amount of the RBL at June 30, 2018, approximates, its fair value (Level 2) due to the variable nature of the RBL interest rate.

 

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Table of Contents

 

10. Equity and Share-Based Compensation

 

Common Shares

 

Share Activity

 

The following table summarizes changes in the number of shares of common stock and treasury stock during the six months ended June 30, 2018:

 

 

 

Common
Stock

 

Treasury
Stock(1)

 

Share count as of December 31, 2017

 

25,272,969

 

(99,623

)

Common stock issued

 

113,135

 

 

Acquisition of treasury stock

 

 

(29,524

)

Share count as of June 30, 2018

 

25,386,104

 

(129,147

)

 


(1)                                 Treasury stock represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory tax withholding requirements.

 

Share-Based Compensation

 

2016 Long Term Incentive Plan

 

On October 21, 2016, the Company established the 2016 LTIP and filed a Form S-8 with the SEC, registering 3,513,950 shares for issuance under the terms of the 2016 LTIP to employees, directors and certain other persons (the “Award Shares”). The types of awards that may be granted under the 2016 LTIP include stock options, restricted stock units, restricted stock, performance awards and other forms of awards granted or denominated in shares of common stock of the reorganized Company, as well as certain cash-based awards (the “Awards”). The terms of each award are as determined by the Compensation Committee of the Board of Directors. Awards that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future issuance under the 2016 LTIP. At June 30, 2018, 1,892,511 Award Shares remain available for issuance under the terms of the 2016 LTIP.

 

Restricted Stock Units

 

At June 30, 2018, the Company had 491,943 non-vested restricted stock units outstanding to employees and non-employee directors pursuant to the 2016 LTIP, excluding restricted stock units issued to non-employee directors containing a market condition, which are discussed below. During the six months ended June 30, 2018, 271,968 non-vested restricted stock units were issued to employees and non-employee directors. Restricted stock units granted to employees in 2018 under the 2016 LTIP vest ratably over a period of three years: one-third will vest on December 31, 2018, an additional one-third will vest on December 31, 2019, and the final one-third will vest on December 31, 2020. Restricted stock units granted to non-employee directors during 2018 vest on the first to occur of (i) December 31, 2018, (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 2018 was based on grant date fair value of the Company’s common stock. Compensation expense is recognized ratably over the requisite service period.

 

The following table summarizes the Company’s non-vested restricted stock unit award activity for the six months ended June 30, 2018:

 

 

 

Restricted Stock

 

Weighted Average
Grant Date
Fair Value

 

Non-vested shares outstanding at December 31, 2017

 

324,984

 

$

18.84

 

Granted

 

271,968

 

$

14.24

 

Vested(1)

 

(105,009

)

$

19.63

 

Forfeited

 

 

$

 

Non-vested shares outstanding at June 30, 2018

 

491,943

 

$

16.13

 

 


(1)                                 Vested restricted stock units include 102,092 shares in which vesting was accelerated as a result of a reduction in workforce that occurred during the six months ended June 30, 2018.

 

Unrecognized expense as of June 30, 2018 for all outstanding restricted stock units under the 2016 LTIP Plan was $4.3 million and will be recognized over a weighted average period of 1.1 years.

 

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Table of Contents

 

Stock Options

 

At June 30, 2018, the Company had 143,086 non-vested options outstanding pursuant to the 2016 LTIP. Stock Option Awards currently outstanding under 2016 LTIP vest ratably over a period of three years: one-sixth will vest on the six-month anniversary of the grant date, an additional one-sixth will vest on the twelve-month anniversary of the grant date, an additional one-third will vest on the twenty-four month anniversary of the grant date and the final one-third will vest on the thirty-six month anniversary of the grant date. Stock Option Awards expire 10 years from the grant date. There were no issuances of stock options during the six months ended June 30, 2018.

 

The following table summarizes the Company’s 2016 LTIP non-vested stock option activity for the six months ended June 30, 2018:

 

 

 

Options

 

Range of
Exercise Prices

 

Weighted Average
Exercise Price

 

Weighted
Average
Remaining
Contractual
Term (Years)

 

Stock options outstanding at December 31, 2017

 

245,845

 

 

 

$

19.66

 

8.3

 

Granted

 

 

$

 

$

 

 

Vested(1)

 

(102,759

)

$

19.08–19.66

 

$

19.66

 

0.1

 

Forfeited

 

 

$

 

$

 

 

Stock options outstanding at June 30, 2018

 

143,086

 

 

 

$

19.66

 

8.3

 

Vested and exercisable at end of period(2)

 

224,664

 

$

19.08-20.97

 

$

19.66

 

4.6

 

 


(1)                                 Vested stock options include 102,092 options in which vesting was accelerated as a result of a reduction in workforce that occurred during the six months ended June 30, 2018.

(2)                                 Vested and exercisable options at June 30, 2018, had no aggregate intrinsic value.

 

Unrecognized expense as of June 30, 2018 for all outstanding stock options under the 2016 LTIP Plan was $0.5 million and will be recognized over a weighted average period of 0.8 years.

 

Non-Employee Director Restricted Stock Units Containing a Market Condition

 

On November 23, 2016, the Company issued restricted stock units to non-employee directors that contain a market vesting condition. These restricted stock units will vest (i) on the first business day following the date on which the trailing 60-day average share price (including any dividends paid) of the Company’s common stock is equal to or greater than $30.00 or (ii) upon a change in control (as defined in the 2016 LTIP) of the Company. Additionally, all unvested restricted stock units containing a market vesting condition will be immediately forfeited upon the first to occur of (i) the fifth anniversary of the grant date or (ii) any participant’s termination as a director for any reason (except for a termination as part of a change in control of the Company).

 

These restricted stock awards are accounted for as liability awards under FASB Accounting Standards Codification 718 — Stock Compensation (“ASC 718”) as the awards allow for the withholding of taxes at the discretion of the non-employee director. The liability is re-measured, with a corresponding adjustment to earnings, at each fiscal quarter-end during the performance cycle. The derived service period related to these awards ended in November 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 June 30, 2018, the Company recorded a $0.4 million liability included within accrued liabilities on the unaudited interim condensed consolidated balance sheets related to the restricted stock units containing a market condition. The weighted-average fair value of the restricted stock units containing a market condition was $5.28 at June 30, 2018.

 

As of June 30, 2018, there was no unrecognized stock-based compensation expense related to market condition awards.

 

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Table of Contents

 

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

 

On November 1, 2017, the Company issued restricted stock units to its CEO that contain a market vesting condition. These restricted stock units will vest, if at all, based on the Company’s total stockholder return for the performance period of October 25, 2017 through October 31, 2020. Market conditions under this grant are (i) with respect to 50% of the RSUs granted, the Company’s cumulative total shareholder return (“TSR”) which is defined as the change in the value of the stock over the performance period with the beginning and ending stock price based on a 20-day average stock price and (ii) with respect to the remaining 50% of the RSUs granted, the percentile rank of the Company’s TSR compared to the TSR of the Peer Group over the performance period (“Relative TSR”).

 

To the extent that actual TSR or Relative TSR for the performance period is between specified vesting levels, the portion of the RSUs that shall become vested based on actual and Relative TSR performance shall be determined on a pro-rata basis using straight-line interpolation; provided that the maximum portion of the RSUs that may become vested based on actual cumulative TSR or Relative TSR for the performance period shall not exceed 120% of the awards granted.

 

The RSUs issued to the CEO containing a market condition have a service period of three years. The share-based compensation costs related to the CEO restricted stock units containing a market condition recognized as general and administrative expense by the Company was $0.1 million and $0.2 million for the three and six months ended June 30, 2018. As of June 30, 2018, unrecognized stock-based compensation related to CEO RSUs containing a market condition was $1.2 million and will be recognized over a weighted-average period of 2.3 years.

 

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

 

On March 1, 2018, the Company issued 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 (i) accelerate all or a portion of the award, (ii) cancel all of the award and pay cash, stock or combination equal to the change in control price, (iii) provide for the assumption or substitution or continuation by the successor company, (iv) certify to the extent to which the vesting conditions had been achieved prior to the conclusion of the performance period or (v) adjust restricted stock units to reflect the change in control.

 

These restricted stock awards are accounted for as equity awards under ASC 718 as the awards are settled in shares of the Company with no additional settlement options permitted. At the grant date, the Company estimated the fair value of this equity award. The compensation expense of this award each period is recognized by dividing the fair value of the total award by the requisite service period and recording the pro rata share for the period for which service has already been provided. As there are inherent uncertainties related to these factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded compensation may not accurately reflect the amount ultimately earned by the executives.

 

The restricted stock units issued to executive management containing a market condition have a service period of three years. The share-based compensation costs related to executive management’s restricted stock units containing a market condition recognized as general and administrative expense by the Company was $0.1 million and $0.2 million for the three and six months ended June 30, 2018. As of June 30, 2018, unrecognized stock-based compensation related to executive management’s restricted stock units containing a market condition was $1.1 million and will be recognized over a weighted-average period of 2.5 years.

 

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11. Income Taxes

 

On December 22, 2017, the Tax Act was enacted into law and the new legislation contains several key tax provisions that affected the Company, primarily a reduction of the corporate income tax rate to 21% effective January 1, 2018. The Company was required to recognize the effect of the tax law changes in the period of enactment. The Company re-measured its U.S. deferred tax assets and liabilities as well as reassessed the net realizability of its deferred tax assets and liabilities. In December 2017, the SEC staff issued SAB 118, which allows the Company to record provisional amounts during a measurement period not to extend beyond one year of the enactment date. As the Tax Act was passed late in the fourth quarter of 2017, ongoing guidance from the Department of Treasury and state agencies and accounting interpretation is expected to be issued over the next 6 months. Therefore, for the six months ended June 30, 2018, the Company considered the accounting of certain items to be incomplete due to forthcoming guidance and the ongoing analysis of final year-end data and tax positions.

 

For the six months ended June 30, 2018, the Company has estimated deductions of $19.2 million associated with the full expensing of the costs of qualified property that were incurred and placed into service during the period from January 1, 2018 to June 30, 2018. The Company continues to analyze assets placed into service after September 27, 2017, but not qualifying for full expensing as a result of being acquired under an agreement entered into prior to that date. In addition, further guidance and analysis is required in order to review the terms of the Company’s compensation plans and agreements and assess the impact of transitional guidance related to IRC Section 162(m) on awards granted prior to November 2, 2017, subject to the grandfather provisions. As a result, the Company has not adjusted certain tax items previously reported on its financial statements for IRC Section 162(m) until the Company is able to obtain sufficient information to make a reasonable estimate of the effects of the Tax Act. The Company expects to complete its analysis within the measurement period in accordance with SAB No. 118.

 

For the six months ended June 30, 2018, the Company recorded no income tax expense or benefit. The significant difference between its effective tax rate and the federal statutory income tax rate of 21% is primarily due to the effect of changes in the Company’s valuation allowance. During the six months ended June 30, 2018, the Company’s valuation allowance decreased by $0.7 million from December 31, 2017, bringing the total valuation allowance to $119.4 million at June 30, 2018. 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.

 

12. Income Per Share

 

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

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2018

 

2017

 

2018

 

2017

 

 

 

(in thousands, except per
share amounts)

 

(in thousands, except per
share amounts)

 

Net Income (Loss):

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(1,542

)

$

13,742

 

$

2,461

 

$

32,227

 

Participating securities—non-vested restricted stock

 

 

(360

)

(68

)

(897

)

Basic and diluted income (loss)

 

$

(1,542

)

$

13,382

 

$

2,393

 

$

31,330

 

 

 

 

 

 

 

 

 

 

 

Common Shares:

 

 

 

 

 

 

 

 

 

Common shares outstanding — basic (1)

 

25,332

 

25,093

 

25,316

 

25,053

 

Dilutive effect of potential common shares

 

 

 

 

 

Common shares outstanding — diluted

 

25,332

 

25,093

 

25,316

 

25,053

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) Per Share:

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.06

)

$

0.53

 

$

0.09

 

$

1.25

 

Diluted

 

$

(0.06

)

$

0.53

 

$

0.09

 

$

1.25

 

Antidilutive stock options (2)

 

500

 

529

 

500

 

578

 

Antidilutive warrants (3)

 

6,626

 

6,626

 

6,626

 

6,626

 

 

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(1)                                 Weighted-average common shares outstanding for basic and diluted income per share purposes includes 9,407 and 17,533 shares of common stock that, while not issued and outstanding at June 30, 2018 or 2017, 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 to be issued. Weighted-average common shares outstanding for basic and diluted income per share purposes also includes 57,856 director shares that vested as of December 31, 2017, but final issuance of the vested shares was deferred by the non-employee directors until 2020.

 

(2)                                 Amount represents options to purchase common stock that are excluded from the diluted net income 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.

 

13. Related Party Transactions

 

During 2017, the Company entered into an arrangement with EcoStim Energy Solutions, Inc. (“EcoStim”) for well stimulation and completion services. EcoStim is an affiliate of Fir Tree Inc. who is a holder of the Company’s outstanding common stock. The Company had $2.1 million included in accounts payable in the Company’s unaudited interim condensed consolidated balance sheets at December 31, 2017 to EcoStim that was paid during the six months ended June 30, 2018. For the three and six months ended June 30, 2017, the Company paid approximately $1.4 million to EcoStim Energy Solutions, Inc. for services provided.

 

14. Commitments and Contingencies

 

The Company is involved in various matters incidental to its operations and business that might give rise to a loss contingency. These matters may include legal and regulatory proceedings, commercial disputes, claims from royalty, working interest and surface owners, property damage and personal injury claims and environmental or other matters. In addition, the Company may be subject to customary audits by governmental authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as compliance with unclaimed property (escheatment) requirements and other laws. Further, other parties with an interest in wells operated by the Company have the ability under various contractual agreements to perform audits of its joint interest billing practices.

 

The Company vigorously defends itself in these matters. If the Company determines that an unfavorable outcome or loss of a particular matter is probable and the amount of loss can be reasonably estimated, it accrues a liability for the contingent obligation. As new information becomes available or as a result of legal or administrative rulings in similar matters or a change in applicable law, the Company’s conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. The impact of subsequent changes to the Company’s accruals could have a material effect on its results of operations. As of June 30, 2018 and December 31, 2017, the Company’s total accrual for all loss contingencies was $1.1 million.

 

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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, 2017, 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, 2018, as well as the unaudited interim condensed consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q and our quarterly report on Form 10-Q for the quarter ended March 31, 2018 filed with the SEC on May 10, 2018.

 

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;

 

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·                  counterparty credit risk;

·                  the outcome of pending and future litigation;

·                  governmental regulation and taxation of the oil and natural gas industry;

·                  developments in oil and natural gas producing countries;

·                  new capital structure;

·                  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 currently 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

 

Sale of Anadarko Basin Assets

 

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), subject to standard post-closing adjustments to occur within 120 days of closing. The net proceeds were reflected as a reduction of oil and natural gas properties, with no gain or loss recognized as the sale did not result in a significant alteration of the full cost pool. We used $50.0 million of the net proceeds from the sale of the Anadarko Basin assets to pay down a portion of outstanding borrowings under our RBL and retained the remainder for general corporate purposes. The Anadarko Basin assets in Texas and Oklahoma were excluded from the April 2018 redetermination of our $170.0 million borrowing base, as discussed above.

 

Operations Update

 

Mississippian Lime

 

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

 

 

 

Three Months Ended
June 30, 2018

 

Three Months Ended
March 31, 2018

 

Increase in
Production

 

 

 

 

 

 

 

 

 

Average daily production:

 

 

 

 

 

 

 

Oil (Bbls)

 

4,833

 

4,564

 

5.9

%

Natural gas liquids (Bbls)

 

3,995

 

3,644

 

9.6

%

Natural gas (Mcf)

 

50,246

 

43,857

 

14.6

%

Net Boe/day

 

17,202

 

15,518

 

10.9

%

 

The following table shows our total number of horizontal wells spud and brought into production in the Mississippian Lime asset during the second quarter of 2018:

 

 

 

Total Number of
Gross Horizontal
Wells Spud (1)

 

Total Number of
Gross Horizontal
Wells Brought
into Production

 

Mississippian Lime

 

4

 

8

 

 


(1)         We had one rig drilling in the Mississippian Lime horizontal well program at June 30, 2018. Of the four wells spud, two were producing, one was awaiting completion and one was being drilled at quarter-end. In addition, three wells spud during the three months ended March 31, 2018 were awaiting completion at June 30, 2018.

 

In the second quarter of 2018, we incurred approximately $39.2 million of operational capital expenditures in the Mississippian Lime basin.

 

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Anadarko Basin

 

The following table presents our average daily production from our Anadarko Basin asset for the periods presented:

 

 

 

Two Months Ended
May 31, 2018(1)

 

Three Months Ended
March 31, 2018

 

Decrease in
Production

 

 

 

 

 

 

 

 

 

Average daily production:

 

 

 

 

 

 

 

Oil (Bbls)

 

1,110

 

1,207

 

(8.0

)%

Natural gas liquids (Bbls)

 

946

 

1,065

 

(11.2

)%

Natural gas (Mcf)

 

7,956

 

8,671

 

(8.2

)%

Net Boe/day

 

3,382

 

3,717

 

(9.0

)%

 


(1)         We closed on the sale of our Anadarko Basin assets on May 31, 2018.  As a result, average daily production as presented in the table above is for the period April 1, 2018 through May 31, 2018.

 

We did not spud any wells in our Anadarko Basin asset and did not have any operated drilling rigs in the area during the second quarter of 2018.

 

Capital Expenditures

 

During the three and six months ended June 30, 2018, we incurred operational capital expenditures of $39.2 million and $71.4 million, respectively, which consisted of the following:

 

 

 

For the Three
Months Ended
June 30, 2018

 

For the Six
Months Ended
June 30, 2018

 

Drilling and completion activities

 

$

36,651

 

$

67,405

 

Acquisition of acreage and seismic data

 

2,515

 

3,952

 

Operational capital expenditures incurred

 

$

39,166

 

$

71,357

 

Capitalized G&A, office, ARO & other

 

969

 

2,189

 

Capitalized interest

 

114

 

191

 

Total capital expenditures incurred

 

$

40,249

 

$

73,737

 

 

Operational capital expenditures by area were as follows:

 

 

 

For the Three
Months Ended
June 30, 2018

 

For the Six
Months Ended
June 30, 2018

 

Mississippian Lime

 

$

39,192

 

$

71,397

 

Anadarko Basin

 

(26

)

(40

)

Total operational capital expenditures incurred

 

$

39,166

 

$

71,357

 

 

We are currently operating one drilling rig in the Mississippian Lime asset. Based upon a one rig program, we would expect to invest between $100.0 million to $110.0 million in this area during the year ended December 31, 2018.

 

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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.

 

Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from any given well is expected to decline. As a result, oil and natural gas exploration and production companies deplete their asset base with each unit of oil or natural gas they produce. We attempt to overcome this natural production decline by developing additional reserves through our drilling operations, acquiring additional reserves and production and implementing secondary recovery techniques. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus on the capital investments necessary to produce our reserves as well as to add to our reserves through drilling and acquisition. Our ability to make the necessary capital expenditures is dependent on cash flow from operations as well as our ability to obtain additional debt and equity financing. That ability can be limited by many factors, including the cost and terms of such capital, our current financial condition, expectations regarding the future price for oil and natural gas, and operational considerations.

 

The volumes of oil and natural gas that we produce are driven by several factors, including:

 

·                  success in the drilling of new wells, including exploratory wells, and the recompletion or workover of existing wells;

·                  the amount of capital we invest in the leasing and development of our oil and natural gas properties;

·                  facility or equipment availability and unexpected downtime;

·                  delays imposed by or resulting from compliance with regulatory requirements;

·                  the rate at which production volumes on our wells naturally decline; and

·                  our ability to economically dispose of salt water produced in conjunction with our production of oil and gas.

 

We follow the full cost method of accounting for our oil and gas properties. For the three and six months ended June 30, 2018, the results of our full cost “ceiling test” did not require us to recognize impairments of our oil and gas properties. However, we recorded impairments of oil and gas properties during the year ended December 31, 2017, the period January 1, 2016 through October 20, 2016 and the year ended December 31, 2015. Impairments can result from multiple factors, such as commodity pricing, changes in our strategic drilling plans, increased capital costs, well performance that is below expectations or higher operating costs. Our industry is dynamic and while we have not experienced impairments for the three and six months ended June 30, 2018, we may be required to record impairments in the future based upon changes in the factors discussed above. While an impairment does not impact cash flow from operating activities or liquidity, such adjustments do decrease our net income and shareholders’ equity.

 

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

 

There continues to be a concern that the injection of saltwater contributes to seismic activity in certain areas of Oklahoma where we operate. The Oil and Gas Conservation Division (“OGCD”) of the Oklahoma Corporation Commission (“OCC”) established injection limits for additional wells in the Arbuckle formation, including 10 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 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 11 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 OCC 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.

 

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Results of Operations

 

The following tables summarize our revenues for the periods indicated (in thousands):

 

 

 

Crude Oil

 

Natural Gas

 

NGLs