crk-10k_20181231.htm

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark  One)

 

 

 

 

 

 

 

 

 

 

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR

 

 

 

 

 

 

 

 

15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

 

 

 

 

 

 

For the fiscal year ended December 31, 2018

 

 

 

 

 

 

 

 

 

OR

 

 

 

 

 

 

 

 

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

 

 

 

 

 

 

 

 

THE SECURITIES EXCHANGE ACT OF 1934

 

 

 

 

 

 

 

 

For the transition period from              to             

 

 

 

 

Commission File No. 001-03262

COMSTOCK RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

NEVADA

 

 

 

94-1667468

(State or other jurisdiction of

incorporation or organization)

 

 

 

(I.R.S. Employer

Identification Number)

5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034

(Address of principal executive offices including zip code)

(972) 668-8800

(Registrant's telephone number and area code)

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

 

Common Stock, $.50 Par Value

 

New York Stock Exchange

(Title of class)

 

(Name of exchange on which registered)

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

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes

 

No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes

 

No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes

No

    

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes

No

    

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer", "accelerated filer", "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. 

 

Large accelerated filer

 

 

Accelerated filer

 

 

Non-accelerated filer

 

 

Smaller reporting company

 

 

 

 

 

 

 

 

 

Emerging growth company

 

 

 

 

 

 

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

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).

Yes

 

No

The aggregate market value of the common stock held by non-affiliates of the registrant, based on the closing price of common stock on the New York Stock Exchange on June 29, 2018 (the last business day of the registrant's most recently completed second fiscal quarter), was $152.5 million.

As of March 1, 2019, there were 105,871,064 shares of common stock of the registrant outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Definitive Proxy Statement for the 2019 Annual Meeting of Stockholders

are incorporated by reference into Part III of this report.

 

 

 

 

 


 

COMSTOCK RESOURCES, INC.

ANNUAL REPORT ON FORM 10-K

For the Fiscal Year Ended December 31, 2018

CONTENTS

 

Item

 

 

 

Page

 

 

 

Part I

 

 

 

 

 

 

Cautionary Note Regarding Forward-Looking Statements

 

2

 

 

 

Definitions

 

3

 

1 and 2.

  

 

Business and Properties

 

6

 

1A.

 

 

Risk Factors

 

27

 

1B.

 

 

Unresolved Staff Comments

 

40

 

3.

 

 

Legal Proceedings

 

40

 

4.

 

 

Mine Safety Disclosures

 

40

 

 

 

Part II

 

 

 

 

5.

 

 

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

 

41

 

6.

 

 

Selected Financial Data

 

42

 

7.

 

 

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

 

43

 

7A.

 

 

Quantitative and Qualitative Disclosures About Market Risk

 

56

 

8.

 

 

Financial Statements and Supplementary Data

 

57

 

9.

 

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

57

 

9A.

 

 

Controls and Procedures

 

57

 

9B.

 

 

Other Information

 

60

 

 

 

Part III

 

 

 

 

10.

 

 

Directors, Executive Officers and Corporate Governance

 

60

 

11.

 

 

Executive Compensation

 

60

 

12.

 

 

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

 

60

 

13.

 

 

Certain Relationships and Related Transactions, and Director Independence

 

61

 

14.

 

 

Principal Accountant Fees and Services

 

61

 

 

 

Part IV

 

 

 

 

15.

 

 

Exhibits and Financial Statement Schedules

 

61

 

 

 

1


 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information contained in this report includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are identified by their use of terms such as "expect," "estimate," "anticipate," "project," "plan," "intend," "believe" and similar terms. All statements, other than statements of historical facts, included in this report, are forward-looking statements, including statements mentioned under "Risk Factors" and "Management's Discussion and Analysis of Financial Condition and Results of Operations," regarding:

 

amount and timing of future production of oil and natural gas;

 

amount, nature and timing of capital expenditures;

 

the number of anticipated wells to be drilled after the date hereof;

 

the availability of exploration and development opportunities;

 

our financial or operating results;

 

our cash flow and anticipated liquidity;

 

operating costs including lease operating expenses, administrative costs and other expenses;

 

finding and development costs;

 

our business strategy; and

 

other plans and objectives for future operations.

Any or all of our forward-looking statements in this report may turn out to be incorrect. They can be affected by a number of factors, including, among others:

 

the risks described in "Risk Factors" and elsewhere in this report;

 

the volatility of prices and supply of, and demand for, oil and natural gas;

 

the timing and success of our drilling activities;

 

the numerous uncertainties inherent in estimating quantities of oil and natural gas reserves and actual future production rates and associated costs;

 

our ability to successfully identify, execute or effectively integrate future acquisitions;

 

the usual hazards associated with the oil and natural gas industry, including fires, well blowouts, pipe failure, spills, explosions and other unforeseen hazards;

 

our ability to effectively market our oil and natural gas;

 

the availability of rigs, equipment, supplies and personnel;

 

our ability to discover or acquire additional reserves;

 

our ability to satisfy future capital requirements;

 

changes in regulatory requirements;

 

general economic conditions, status of the financial markets and competitive conditions; and

 

our ability to retain key members of our senior management and key employees.

2


 

DEFINITIONS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report. Natural gas equivalents and crude oil equivalents are determined using the ratio of six Mcf to one barrel. All references to "us", "our", "we" or "Comstock" mean the registrant, Comstock Resources, Inc. and where applicable, its consolidated subsidiaries.

"Bbl" means a barrel of U.S. 42 gallons of oil.

"Bcf" means one billion cubic feet of natural gas.

"Bcfe" means one billion cubic feet of natural gas equivalent.

"BOE" means one barrel of oil equivalent.

"Btu" means British thermal unit, which is the quantity of heat required to raise the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit.

"Completion" means the installation of permanent equipment for the production of oil or gas.

"Condensate" means a hydrocarbon mixture that becomes liquid and separates from natural gas when the gas is produced and is similar to crude oil.

"Development well" means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

"Dry hole" means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

"Exploratory well" means a well drilled to find a new field or to find a new productive reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

"Gross" when used with respect to acres or wells, production or reserves refers to the total acres or wells in which we or another specified person has a working interest.

"LNG" refers to liquefied natural gas, which is a composition of methane and some mixture of ethane that has been cooled to liquid form for ease and safety of non-pressurized storage or transport.

"MBbls" means one thousand barrels of oil.

"MBbls/d" means one thousand barrels of oil per day.

"Mcf" means one thousand cubic feet of natural gas.

"Mcfe" means one thousand cubic feet of natural gas equivalent.

"MMBbls" means one million barrels of oil.

"MMBOE" means one million barrels of oil equivalent.

"MMBtu" means one million British thermal units.

3


 

"MMcf" means one million cubic feet of natural gas.

"MMcf/d" means one million cubic feet of natural gas per day.

"MMcfe/d" means one million cubic feet of natural gas equivalent per day.

"MMcfe" means one million cubic feet of natural gas equivalent.

"Net" when used with respect to acres or wells, refers to gross acres of wells multiplied, in each case, by the percentage working interest owned by us.

"Net production" means production we own less royalties and production due others.

"Oil" means crude oil or condensate.

"Operator" means the individual or company responsible for the exploration, development, and production of an oil or gas well or lease.

"Proved developed reserves" means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

"Proved developed non-producing" means reserves (i) expected to be recovered from zones capable of producing but which are shut-in because no market outlet exists at the present time or whose date of connection to a pipeline is uncertain or (ii) currently behind the pipe in existing wells, which are considered proved by virtue of successful testing or production of offsetting wells.

"Proved developed producing" means reserves expected to be recovered from currently producing zones under continuation of present operating methods. This category includes recently completed shut-in gas wells scheduled for connection to a pipeline in the near future.

"Proved reserves" means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided by contractual arrangements.

"Proved undeveloped reserves" means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling locations offsetting productive wells that are reasonably certain of production when drilled or where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

"PV 10 Value" means the present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. This amount is the same as the standardized measure of discounted future net cash flows related to proved oil and natural gas reserves except that it is determined without deducting future income taxes.  Although PV 10 Value is not a financial measure calculated in accordance with GAAP, management believes that the presentation of PV 10 Value is relevant and useful to our investors

4


 

because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. Because many factors that are unique to any given company affect the amount of estimated future income taxes, we believe the use of a pre-tax measure is helpful to investors when comparing companies in our industry.

"Recompletion" means the completion for production of an existing well bore in another formation from which the well has been previously completed.

"Reserve life" means the calculation derived by dividing year-end reserves by total production in that year.

"Royalty" means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

"3-D seismic" means an advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

"SEC" means the United States Securities and Exchange Commission.

"Tcf" means one trillion cubic feet of natural gas.

"Tcfe" means one trillion cubic feet of natural gas equivalent.

"Working interest" means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100% working interest in a lease burdened only by a landowner's royalty of 12.5% would be required to pay 100% of the costs of a well but would be entitled to retain 87.5% of the production.

"Workover" means operations on a producing well to restore or increase production.

 

 

 

5


 

PART I

 

ITEMS 1 and 2.   BUSINESS AND PROPERTIES

 

We are a disciplined, growth-oriented, independent energy company focused on creating value through the development of our substantial inventory of highly economic and low-risk drilling opportunities in the Haynesville and Bossier shale. Our common stock is listed and traded on the New York Stock Exchange under the symbol "CRK".

On August 14, 2018, Arkoma Drilling, L.P. and Williston Drilling, L.P. (collectively, the "Jones Partnerships") contributed certain oil and gas properties in North Dakota and Montana in exchange for 88,571,429 newly issued shares of our common stock representing 84% of the Company's outstanding common stock (the "Jones Contribution"). The Jones Partnerships are wholly owned and controlled by Dallas businessman Jerry Jones and his children (collectively, the "Jones Group").  References to "Successor" or "Successor Company" relate to the operations of the Company subsequent to August 13, 2018.  Reference to "Predecessor" or "Predecessor Company" relate to the operations of the Company on or prior to August 13, 2018.

Our oil and gas operations are primarily concentrated in Louisiana, Texas and North Dakota. Our oil and natural gas properties are estimated to have proved reserves of 2.4 Tcfe with a PV 10 Value of $1.8 billion as of December 31, 2018. Our proved oil and natural gas reserve base is 94% natural gas and 6% oil and was 29% developed as of December 31, 2018, and our properties have an average reserve life of approximately 17 years.

Our proved reserves at December 31, 2018 and our 2018 average daily production are summarized below:

 

 

  

Proved Reserves at December 31, 2018

 

 

  

Oil
(MMBbls)

 

  

Natural
Gas
(Bcf)

 

  

Total
(Bcfe)

 

  

% of
Total

 

Haynesville/Bossier shale

 

 

 

 

 

2,187.6

 

 

 

2,187.6

 

 

 

90

%

Bakken shale

 

 

21.6

 

 

 

47.4

 

 

 

176.9

 

 

 

7

%

Cotton Valley

 

 

0.3

 

 

 

44.1

 

 

 

45.7

 

 

 

2

%

Eagle Ford shale

 

 

1.6

 

 

 

1.1

 

 

 

10.9

 

 

 

1

%

Other

 

 

0.1

 

 

 

2.6

 

 

 

3.3

 

 

 

%

Total

 

 

23.6

 

 

 

2,282.8

 

 

 

2,424.4

 

 

 

100

%

 

 

 

Average Daily Production

 

 

  

Successor Period - August 14, 2018 through December 31, 2018

 

 

  

Oil
(MBbls/d)

 

  

Natural
Gas
(MMcf/d)

 

  

Total
(MMcfe/d)

 

  

% of
Total

 

Haynesville/Bossier shale

 

 

 

 

 

281.5

 

 

 

281.5

 

 

 

74

%

Bakken shale

 

 

9.7

 

 

 

27.5

 

 

 

86.0

 

 

 

23

%

Cotton Valley

 

 

0.1

 

 

 

11.6

 

 

 

12.2

 

 

 

3

%

Other

 

 

0.1

 

 

 

1.0

 

 

 

1.3

 

 

 

%

Total

 

 

9.9

 

 

 

321.6

 

 

 

381.0

 

 

 

100

%

 

 

 

 

 

 

Average Daily Production

 

 

  

Predecessor Period - January 1, 2018 through August 13, 2018

 

 

  

Oil
(MBbls/d)

 

  

Natural
Gas
(MMcf/d)

 

  

Total
(MMcfe/d)

 

  

% of
Total

 

Haynesville/Bossier shale

 

 

 

 

 

231.2

 

 

 

231.2

 

 

 

91

%

Cotton Valley

 

 

0.1

 

 

 

10.5

 

 

 

11.2

 

 

 

5

%

Eagle Ford shale

 

 

1.1

 

 

 

1.7

 

 

 

8.3

 

 

 

3

%

Other

 

 

0.1

 

 

 

2.1

 

 

 

2.5

 

 

 

1

%

Total

 

 

1.3

 

 

 

245.5

 

 

 

253.2

 

 

 

100

%

6


 

Strengths

 

High Quality Properties. As of December 31, 2018, we have accumulated 116,866 acres (87,270 net to us) in the Haynesville and Bossier shale plays, located in the North Louisiana parishes of Bossier, Caddo, DeSoto and Sabine and the Texas counties of Harrison, Panola, Rusk and Shelby. Approximately 83% of our Haynesville/Bossier shale net acreage is held-by-production and our Haynesville/Bossier shale properties have extensive development and exploration potential. Advances in drilling and completion technology have allowed us to increase the reserves recovered through longer horizontal lateral length and substantially larger well stimulation.  As a result of the improved economic returns, we have focused our development activities primarily on drilling Haynesville and Bossier horizontal wells in recent years.

Our Haynesville and Bossier shale positions in North Louisiana and East Texas are located in one of the premier North American natural gas shale plays and we believe our liquids-rich Eagle Ford shale position offers substantial, highly economic and low-risk drilling opportunities. We intend to prudently redeploy the cash flow generated by our properties in the Bakken shale to develop our Haynesville, Bossier and Eagle Ford shale undeveloped locations while maintaining sufficient liquidity and a low leverage profile. We believe we are well positioned for future growth due to the following:

 

De-risked, contiguous and prolific oil and natural gas resources. The Haynesville and Bossier shale plays have been substantially delineated since 2008 through the drilling of over 4,100 horizontal wells. We believe that these shale plays represent some of the most consistent and prolific natural gas development drilling opportunities in North America.

 

Management and operating team with extensive experience in developing the Haynesville and Bossier shale plays. We were among the first exploration and production companies to effectively apply horizontal drilling techniques in the Haynesville and Bossier shales beginning in 2007. Since then, our management and operating team initiated a drilling program in the Haynesville and Bossier shales in 2015 based on a new, enhanced completion well design that significantly improved the economics of these wells in comparison to the 189 wells we drilled from 2008 to 2013. We have drilled and completed a total of 70 operated wells (47.0 net to us) targeting the Haynesville or Bossier shale from 2015 through December 2018 employing this enhanced completion design. These wells had an average per well initial production rate of 25 MMcf per day.

 

Attractive economic returns. The Haynesville, Bossier and Eagle Ford shales offer highly economic and low-risk drilling opportunities through application of advanced drilling and completion technologies, including the use of longer laterals, and high intensity fracture stimulation using tighter frac stages and higher proppant loading. Our management and operating team has been instrumental in developing and optimizing some of the most effective completion techniques in the Haynesville and Bossier shales and such completion techniques have resulted in a material improvement in initial production rates and recoverable reserves, and has resulted in some of the highest single well rates of return when compared to results from other natural gas basins in North America.

 

Proximity to premium natural gas markets.  Our natural gas production benefits from the strong regional Gulf Coast demand growth driven by a substantial increase in LNG exports, greater natural gas exports to Mexico and new or expanded petrochemical facilities. Producers, such as us, with access to the Gulf Coast natural gas markets are receiving higher net realized prices than most producers in other regions. We are also able to realize higher margins due to our ability to access the extensive midstream infrastructure at attractive rates and lack of above-market midstream commitments.

7


 

Value-Added Acquisitions.  During 2018 we completed two acquisitions of acreage and producing properties near our existing acreage.  We acquired 17,386 net acres prospective for Haynesville shale development with 225 (66.4 net) drilling locations in two transactions.  The acreage along with interests in 114 (27.8 net) producing wells was acquired for $41.5 million along with an obligation to provide $20.5 million in future drilling and completion costs on wells drilled on the acreage.  We also reacquired working interests from Arkoma Drilling, L.P. for $17.9 million as part of the termination of the strategic drilling venture entered into prior to the closing of the Jones Contribution.  The acquisitions completed in 2018 added 253.7 Bcfe to our proved reserves which had a PV 10 Value of $126.9 million.

Successful Drilling Program. We spent $271.7 million on development activities in 2018, with $224.4 million on development activity in the Haynesville and Bossier shale.  We spent $197.2 million on drilling and completing horizontal Haynesville and Bossier shale wells and an additional $27.2 million on refrac and other development activity.  We drilled 49 (17.0 net) horizontal Haynesville and Bossier wells in 2018, which had an average lateral length of approximately 8,300 feet.  We also completed 16 (4.2 net) wells that were drilled in 2017.  Thirty (11.9 net) of the wells drilled in 2018 were also completed in 2018.  We expect that the remaining 16 (5.7 net) wells will be completed in 2019.  Our natural gas drilling program in 2018 was the major driver for the increase in our natural gas production of 36% over 2017 and contributed to the 104% growth we had in our natural gas reserves from 2017.  We also spent $42.7 million of development costs on our other properties primarily on completing 24 (7.0 net) Bakken shale wells and $4.6 million on leasehold costs.

Efficient Operator. We operated 86% of our proved reserve base as of December 31, 2018. As the operator, we are better able to control operating costs, the timing and plans for future development, the level of drilling and lifting costs and the marketing of production. As an operator, we receive reimbursements for overhead from other working interest owners, which reduces our general and administrative expenses.

Business Strategy

Our strategy consists of the following principal elements:

 

Prudently grow cash flow, production and reserves through the development of our extensive drilling inventory in the Haynesville, Bossier and Eagle Ford shales. We have an extensive inventory of horizontal well drilling locations prospective for the Haynesville and Bossier shales, providing us with years of inventory of development locations.  The following outlines our Haynesville and Bossier shale future drilling locations by lateral length as we currently plan to drill them:

 

 

Haynesville Shale

 

Horizontal

 

Operated

 

 

Non-Operated

 

 

Total

 

Lateral Length

 

(Gross)

 

 

(Net)

 

 

(Gross)

 

 

(Net)

 

 

(Gross)

 

 

(Net)

 

Less than 5,000 feet

 

 

186

 

 

 

139.2

 

 

 

351

 

 

 

48.1

 

 

 

537

 

 

 

187.3

 

5,000 feet to 8,000 feet

 

 

111

 

 

 

86.9

 

 

 

33

 

 

 

4.4

 

 

 

144

 

 

 

91.3

 

Greater than 8,000 feet

 

 

221

 

 

 

158.6

 

 

 

52

 

 

 

6.3

 

 

 

273

 

 

 

164.9

 

 

 

 

518

 

 

 

384.7

 

 

 

436

 

 

 

58.8

 

 

 

954

 

 

 

443.5

 

 

 

 

Bossier Shale

 

Horizontal

 

Operated

 

 

Non-Operated

 

 

Total

 

Lateral Length

 

(Gross)

 

 

(Net)

 

 

(Gross)

 

 

(Net)

 

 

(Gross)

 

 

(Net)

 

Less than 5,000 feet

 

 

155

 

 

 

119.5

 

 

 

161

 

 

 

21.9

 

 

 

316

 

 

 

141.4

 

5,000 feet to 8,000 feet

 

 

98

 

 

 

78.9

 

 

 

8

 

 

 

1.9

 

 

 

106

 

 

 

80.8

 

Greater than 8,000 feet

 

 

192

 

 

 

152.2

 

 

 

2

 

 

 

1.0

 

 

 

194

 

 

 

153.2

 

 

 

 

445

 

 

 

350.6

 

 

 

171

 

 

 

24.8

 

 

 

616

 

 

 

375.4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

963

 

 

 

735.3

 

 

 

607

 

 

 

83.6

 

 

 

1,570

 

 

 

818.9

 

8


 

We have 21,482 (9,432 net to us) undeveloped acres prospective for development in the oil window of the Eagle Ford shale in South Texas.  We have entered into a joint development venture with our acreage and have the opportunity to participate in the drilling of 225 (126.0 net to us) wells.

 

Since much of our net acreage is held by production, we have the ability to allocate capital among projects in a manner that optimizes both costs and returns, resulting in a highly efficient drilling program. We intend to manage the selection of drilling locations and the timing of development and associated capital expenditures in order to economically grow our cash flow, production and reserves while funding our capital expenditures primarily with operating cash flow.

 

 

Enhance returns through a focus on optimizing full cycle economics. We continually monitor and adjust our drilling program on a regular basis with the objective of achieving the most economical returns on our portfolio of drilling opportunities. We believe that we will achieve this objective by (i) minimizing our costs to drill and complete wells, (ii) maximizing well production and recoveries by optimizing lateral length, the number of frac stages, perforation intervals and the type of fracture stimulation employed, (iii) producing near pipeline-quality natural gas, which leads to lower processing costs, and (iv) minimizing operating costs through efficient well management.

 

 

Evaluate and pursue strategic acquisition opportunities to grow our reserves, production, and acreage position. We intend to leverage our management and operating team's significant technical expertise and experience in successfully executing and integrating acquisitions to continue pursuing acquisition opportunities that will add to our drilling inventory.

 

 

Maintain disciplined financial strategy. We believe we are in a strong financial position, and we intend to maintain a conservative balance sheet with lower leverage and adequate liquidity to fund our development program, effectively allocate capital, and continuously improve our cost structure. We intend to pursue a development plan that will be substantially funded with operating cash flow. If necessary, we will use borrowings under our bank credit facility to help fund our development plan, while prudently managing our capital structure, leverage and liquidity.

 

 

Manage commodity price exposure through an active hedging program to protect our expected future cash flows. We expect to maintain an active oil and natural gas price hedging program designed to mitigate volatility in oil and natural gas prices and to protect a portion of our expected future cash flows.

 

Primary Operating Areas

 

The following table summarizes the estimated proved oil and natural gas reserves as of December 31, 2018:

 

 

Oil
(MBbls)

 

 

 

Natural
Gas
(MMcf)

 

 

 

Total
(MMcfe)(1)

 

 

 

%

 

 

PV 10 Value

(000's)(2)

 

 

 

%

 

Haynesville/Bossier Shale

 

 

 

 

2,187,598

 

 

 

2,187,598

 

 

 

90

%

 

$

1,166,389

 

 

 

67

%

Bakken Shale

 

21,580

 

 

 

47,373

 

 

 

176,855

 

 

 

7

%

 

 

541,227

 

 

 

31

%

Cotton Valley

 

274

 

 

 

44,092

 

 

 

45,734

 

 

 

2

%

 

 

36,394

 

 

 

2

%

Eagle Ford Shale

 

1,645

 

 

 

1,066

 

 

 

10,933

 

 

 

1

%

 

 

7,406

 

 

 

%

Other

 

113

 

 

 

2,629

 

 

 

3,311

 

 

 

%

 

 

3,729

 

 

 

%

Total

 

23,612

 

 

 

2,282,758

 

 

 

2,424,431

 

 

 

100

%

 

$

1,755,145

 

 

 

100

%

_____________

 

(1)

Oil is converted to natural gas equivalents by using a conversion factor of one barrel of oil for six Mcf of natural gas based upon the approximate relative energy content of oil to natural gas, which is not indicative of oil and natural gas prices.

 

 

(2)

The PV10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%.  Although it is a non-GAAP measure, we believe that the presentation of PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure.  We use this measure when assessing the potential return on investment related to our oil and gas properties.  The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and gas reserves after income tax, discounted at 10%.

 

9


 

Haynesville/Bossier Shale    

Approximately 90%, or 2.2 Tcfe of our proved reserves, are located in the Haynesville and Bossier shales in East Texas and North Louisiana, where we own interests in 306 producing wells (171.3 net to us). We operate 191 of these wells. The wells produce from the Bossier shale at depths of 10,500 to 12,100 feet and from the Haynesville shale at depths from 10,500 to 12,950 feet.  Our production from the Haynesville and Bossier shale averaged 251 MMcf of natural gas per day in 2018. We spent $197.2 million in 2018 drilling 49 wells (17.0 net to us) and completing 16 (4.2 net) wells that were drilled in 2017.  We spent $27.2 million on refrac and other development activity in this region in 2018.  We also completed two acquisitions in 2018 acquiring 17,386 net acres and 47 producing wells in the Haynesville and Bossier shale.  We currently plan to spend approximately $339.8 million in 2019 to drill 58 (36.4 net) wells and to complete an additional 16 (5.7 net to us) wells we drilled in 2018.

Bakken Shale

Approximately 7% (177 Bcfe) of our proved reserves are located in North Dakota and Montana, where we own interests in 424 producing wells (65.8 net to us) which produce from the Bakken shale. The Bakken shale proved reserves are 73% oil and represent 31% of our PV 10 Value.  We acquired 403 non-operated wells (60.3 net to us) in the Bakken shale with the Jones Contribution and we participated in the completion of 24 wells (7.0 net to us) at a cost of $42.7 million.  Net daily production rates from our Bakken shale properties averaged 9,743 barrels of oil and 27.5 MMcf of natural gas per day in 2018.  

Cotton Valley

Approximately 2%, or 46 Bcfe of our proved reserves, are located primarily in the Cotton Valley formations in East Texas and North Louisiana, where we own interests in 651 producing wells (368.8 net to us). These wells produce from multiple sands at a depth of 8,000 to 10,000 feet.  We operate 416 of these wells.  Our Cotton Valley wells averaged 10.9 MMcf of natural gas per day and 112 barrels of oil per day in 2018.  Future drilling opportunities include approximately 317 horizontal wells (216.1 net to us).

Eagle Ford Shale

Approximately 11 Bcfe of our proved reserves are located in South Texas that are prospective for production from the Eagle Ford shale. Our proved reserves in this field are estimated to be 1.8 MMBOE (10.9 Bcfe) (90% oil) and represent less than 1% of our total proved reserves. The Eagle Ford shale is found between 7,500 feet and 11,500 feet across our acreage position.  We have 21,482 (9,452 net to us) undeveloped acres that are subject to a joint development agreement under which we have the opportunity to participate in up to 225 wells (126.0 net to us) in the future.  In 2019 we plan to drill four Eagle Ford shale wells (1.9 net to us).  

Other Regions

Less than 1%, or 3.3 Bcfe, of our proved reserves are in other regions, primarily in New Mexico and the Mid-Continent region.  We own interests in 243 producing wells (28.9 net to us) in eight fields within these regions.  Net daily production from our other regions during 2018 totaled 1.7 MMcf of natural gas and 55 barrels of oil or 2 MMcfe per day.


10


 

Oil and Natural Gas Reserves

The following table sets forth our estimated proved oil and natural gas reserves as of December 31, 2018:

 

 

 

Oil
  (MBbls)

 

Natural  
Gas
(MMcf)

 

Total
  (MMcfe)

 

 

PV 10
Value

(000's)(1)

 

Proved Developed:

 

 

 

 

 

 

 

 

 

 

Producing

 

20,939

 

543,741

 

669,374

 

 

$1,127,449

 

Non-producing

 

527

 

39,366

 

42,528

 

 

48,436

 

Total Proved Developed

 

21,466

 

583,107

 

711,902

 

 

1,175,885

 

Proved Undeveloped

 

2,146

 

1,699,651

 

1,712,529

 

 

579,260

 

Total Proved

 

23,612

 

2,282,758

 

2,424,431

 

 

1,755,145

 

Discounted Future Income Taxes

 

 

(281,305

)

Standardized Measure of Discounted Cash Flows

 

 

$1,473,840

 

________________

(1)

The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%.  Although it is a non-GAAP measure, we believe that the presentation of PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure.  We use this measure when assessing the potential return on investment related to our oil and gas properties.  The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and gas reserves after income tax, discounted at 10%.

The following table sets forth our year end reserves as of December 31 for each of the last three fiscal years:

 

 

 

2016

 

 

2017

 

 

2018

 

 

 

Oil
(MBbls)

 

 

Natural Gas
(MMcf)

 

 

Oil
(MBbls)

 

 

Natural Gas
(MMcf)

 

 

Oil
(MBbls)

 

 

Natural Gas
(MMcf)

 

 

Proved Developed

 

 

7,277

 

 

 

321,527

 

 

 

7,552

 

 

 

436,114

 

 

 

21,466

 

 

 

583,107

 

Proved Undeveloped

 

 

 

 

 

550,941

 

 

 

 

 

 

680,842

 

 

 

2,146

 

 

 

1,699,651

 

Total Proved Reserves

 

 

7,277

 

 

 

872,468

 

 

 

7,552

 

 

 

1,116,956

 

 

 

23,612

 

 

 

2,282,758

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved reserves that are attributable to existing producing wells are primarily determined using decline curve analysis and rate transient analysis, which incorporates the principles of hydrocarbon flow. Proved reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. Technologies relied on to establish reasonable certainty of economic producibility include electrical logs, radioactivity logs, core analyses, geologic maps and available production data, seismic data and well test data.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

The average prices that we realized from sales of oil and natural gas and lifting costs including severance and ad valorem taxes and transportation costs, for each of the last three fiscal years were as follows:

 

11


 

 

 

Predecessor

 

 

Successor

 

 

 

 

 

 

For the Period from January 1, 2018 through

August 13,

 

 

For the
Period from August 14, 2018 through December 31,

 

 

 

Year Ended December 31,

 

 

 

 

 

 

 

2016

 

 

2017

 

 

2018

 

 

2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Price - $/Bbl

 

$

38.24

 

 

$

49.02

 

 

$

65.23

 

 

$

57.34

 

Natural Gas Price - $/Mcf

 

$

2.28

 

 

$

2.84

 

 

$

2.68

 

 

$

3.20

 

Lifting Costs - $/Mcfe

 

$

1.10

 

 

$

0.77

 

 

$

0.64

 

 

$

0.79

 

Prices used in determining quantities of oil and natural gas reserves and future cash inflows from oil and natural gas reserves represent the average first of the month prices received at the point of sale for the last twelve months. These prices have been adjusted from posted prices for both location and quality differences. The oil and natural gas prices used for reserves estimation were as follows:

 Year

 

 

Oil Price
(per Bbl)

 

 

Natural
Gas Price
(per Mcf)

 

 

 

 

 

 

 

 

 

 

 

2016

 

 

$

37.62

 

 

$

2.29

 

2017

 

 

$

48.71

 

 

$

2.88

 

2018

 

 

$

61.21

 

 

$

2.90

 

 

Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered, and they are scheduled to be drilled within five years of their initial inclusion as proved reserves, unless specific circumstances justify a longer time. In connection with estimating proved undeveloped reserves for our reserve report, reserves on undrilled acreage were limited to those that are reasonably certain of production when drilled where we can verify the continuity of the reservoir. We only include wells in our proved undeveloped reserves that we currently plan to drill and in which we have adequate capital resources to enable us to drill them.  Using empirical evidence, we utilize control points and sample sizes to show continuity in the reservoir. We reflect changes to undeveloped reserves that occur in the same field as revisions to the extent that proved undeveloped locations are revised due to changes in future development plans, including changes to proposed lateral lengths, development spacing and timing of development.

As of December 31, 2018, our proved undeveloped reserves were comprised of 2.1 million barrels of oil and 1.7 Tcf of natural gas. We had proved undeveloped oil reserves of 1.6 million barrels associated with our Eagle Ford shale properties and 0.5 million barrels associated with our Bakken shale properties.  Most of our natural gas undeveloped reserves are associated with our Haynesville and Bossier shale properties where our drilling program in 2018 was focused.  Our natural gas proved undeveloped reserves increased by 1.0 Tcf during 2018.  This increase was primarily related to the reserve additions and performance related revisions which were comprised of 952 Bcf of new undeveloped locations resulting from our successful Haynesville and Bossier shale drilling program and expanded future drilling plans and 64 Bcf of upward performance revisions attributable to our Haynesville and Bossier shale undeveloped reserves added in prior years. Acquisitions during 2018 added 204 Bcf of natural gas.  The reserve additions were partially offset by 129 Bcf of reserves converted to developed reserves and the divestiture of 74 Bcf of natural gas reserves.  Twenty-three of the Haynesville shale wells we drilled in 2018 resulted in conversions of proved undeveloped reserves to proved developed producing reserves at December 31, 2018.

As of December 31, 2017, our proved undeveloped reserves were comprised of 681 Bcf of natural gas. All of our proved undeveloped reserves were associated with our Haynesville and Bossier shale properties where our 2017 drilling program was focused.  Our natural gas proved undeveloped reserves

12


 

increased by 130 Bcf during 2017.  This increase was primarily related to the reserve additions which totaled 239 Bcf of natural gas, which were comprised of 220 Bcf of new undeveloped locations resulting from our successful Haynesville and Bossier shale drilling program and expanded future drilling plans and 19 Bcf of upward performance revisions attributable to our Haynesville and Bossier shale undeveloped reserves added in prior years. The reserve additions were partially offset by 104 Bcf of reserves converted to developed reserves. Eleven of the Haynesville shale wells we drilled in 2017 resulted in conversions of proved undeveloped reserves to proved developed producing reserves at December 31, 2017.

The following table presents the changes in our estimated proved undeveloped oil and natural gas reserves for the years ended December 31, 2016, 2017 and 2018:

 

 

 

Proved Undeveloped Reserves

 

 

 

2016

 

 

2017

 

 

2018

 

 

  

Oil
(MBbls)

 

  

Natural Gas
(MMcf)

 

 

Oil
(MBbls)

 

 

Natural Gas
(MMcf)

 

 

Oil
(MBbls)

  

 

Natural Gas
(MMcf)

 

Beginning Balance

 

 

 

 

 

258,466

 

 

 

 

 

 

550,941

 

 

 

 

 

 

680,842

 

Bakken Shale Contribution

 

 

 

 

 

 

 

 

 

 

 

 

 

 

502

 

 

 

1,061

 

Divestitures

 

 

 

 

 

 

 

 

 

 

 

(5,264

)

 

 

(4,002

)

 

 

(74,297

)

Acquisitions

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

204,414

 

Extension & Discoveries

 

 

 

 

 

253,589

 

 

 

 

 

 

220,048

 

 

 

5,646

 

 

 

952,152

 

Conversions from Undeveloped to Developed

 

 

 

 

 

(55,338

)

 

 

 

 

 

(103,506

)

 

 

 

 

 

(128,692

)

Price, Performance and Other Revisions

 

 

 

 

 

94,224

 

 

 

 

 

 

18,623

 

 

 

 

 

 

64,171

 

Total Change

 

 

 

 

 

292,475

 

 

 

 

 

 

129,901

 

 

 

2,146

 

 

 

1,018,809

 

Ending Balance

 

 

 

 

 

550,941

 

 

 

 

 

 

680,842

 

 

 

2,146

 

 

 

1,699,651

 

The timing, by year, when our proved undeveloped reserve quantities are estimated to be converted to proved developed reserves is as follows:

 

 

 

Proved Undeveloped Reserves

 

 

 

2016

 

 

2017

 

 

2018

 

Year ended December 31,

  

Oil
(MBbls)

 

 

Natural Gas
(MMcf)

 

  

Oil
(MBbls)

 

  

Natural Gas
(MMcf)

 

  

Oil
(MBbls)

  

 

Natural Gas
(MMcf)

 

2017

 

 

 

 

 

101,024

 

 

 

 

 

 

 

 

 

 

 

 

 

2018

 

 

 

 

 

128,531

 

 

 

 

 

 

166,801

 

 

 

 

 

 

 

2019

 

 

 

 

 

121,611

 

 

 

 

 

 

140,953

 

 

 

966

 

 

 

214,481

 

2020

 

 

 

 

 

96,888

 

 

 

 

 

 

156,568

 

 

 

147

 

 

 

385,209

 

2021

 

 

 

 

 

102,887

 

 

 

 

 

 

119,640

 

 

 

378

 

 

 

487,265

 

2022

 

 

 

 

 

 

 

 

 

 

 

96,880

 

 

 

190

 

 

 

368,696

 

2023

 

 

 

 

 

 

 

 

 

 

 

 

 

 

465

 

 

 

244,000

 

Total

 

 

 

 

 

550,941

 

 

 

 

 

 

680,842

 

 

 

2,146

 

 

 

1,699,651

 

 

13


 

The following table presents the timing of our estimated future development capital costs to be incurred for the years ended December 31, 2016, 2017 and 2018:

 

 

  

Future Development Costs
Total Proved Undeveloped Reserves

 

Year ended December 31,

  

2016

 

  

2017

 

  

2018

 

 

  

(in millions)

 

 

2017

 

$

84.0

 

 

$

 

 

$

 

2018

 

 

89.3

 

 

 

149.1

 

 

 

 

2019

 

 

92.9

 

 

 

123.7

 

 

 

193.4

 

2020

 

 

74.6

 

 

 

138.4

 

 

 

364.3

 

2021

 

 

86.5

 

 

 

116.2

 

 

 

516.9

 

2022

 

 

 

 

 

89.9

 

 

 

431.6

 

2023

 

 

 

 

 

 

 

 

276.4

 

Total

 

$

427.3

 

 

$

617.3

 

 

$

1,782.6

 

The following table presents the changes in our estimated future development costs for the years ended December 31, 2017 and 2018:

 

 

 

 

 

(in millions)

 

Total as of December 31, 2016

 

 

 

$

427.3

 

 

Development Costs Incurred

 

 

 

 

(93.4

)

Asset Disposals

 

 

 

 

(2.3

)

Additions and Revisions

 

 

 

 

285.7

 

Total Changes

 

 

 

 

190.0

 

Total as of December 31, 2017

 

 

 

 

617.3

 

 

Development Costs Incurred

 

 

 

 

(103.1

)

Asset Disposals

 

 

 

 

(124.8

)

Jones Contribution

 

 

 

 

9.2

 

Asset Acquisitions

 

 

 

 

184.1

 

Additions and Revisions

 

 

 

 

1,199.9

 

Total Changes

 

 

 

 

1,165.3

 

Total as of December 31, 2018

 

 

 

$

1,782.6

 

Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2018 of $1.8 billion increased by $1.2 billion from our estimated future capital costs of $0.6 billion as of December 31, 2017.  This increase was primarily attributable to the inclusion of 216 additional proved undeveloped Haynesville and Bossier shale locations at December 31, 2018.  As of December 31, 2018, our future capital costs include $1.7 billion to develop our Haynesville/Bossier shale properties and $53.2 million to develop our oil properties in the Eagle Ford shale and the Bakken shale.

We incurred approximately $93.4 million during 2017 in development costs related to proved undeveloped reserves.  Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2017 of $617.3 million increased by $190.0 million from our estimated future capital costs of $427.3 million as of December 31, 2016.  This increase was primarily attributable to the inclusion of 32 additional proved undeveloped locations at December 31, 2017.

The estimates of our oil and natural gas reserves were determined by Lee Keeling and Associates, Inc. ("Lee Keeling"), an independent petroleum engineering firm. Lee Keeling has been providing consulting engineering and geological services for over fifty years. Lee Keeling's professional staff is comprised of qualified petroleum engineers who are experienced in all productive areas of the United States. The technical person responsible for review of our reserve estimates at Lee Keeling meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the

14


 

Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Lee Keeling does not own any interests in our properties and is not employed on a contingent fee basis.

We have established, and maintain, internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations promulgated by the SEC. These internal controls include documented process workflows, employing qualified professional engineering and geological personnel, and on-going education for personnel involved in our reserves estimation process. Our internal audit function routinely tests our processes and controls. Inputs to our reserves estimation process, which we provide to Lee Keeling for use in their reserves evaluation, are based upon our historical results for production history, oil and natural gas prices, lifting and development costs, ownership interests and other required data. Our Reservoir Engineering Department, comprised of qualified petroleum engineers and technical support staff, works with our operating, accounting, land and marketing departments in order to accumulate the information required for the reserves estimation process. Our Vice President of Reservoir Engineering is the primary person in charge of overseeing our reserve estimates and our Reservoir Engineering Department. He has a B.S. Degree and a Masters Degree in Petroleum Engineering, is a Registered Professional Engineer and has over forty years of experience in various technical roles within the oil and gas industry. During the reserves estimation process our petroleum engineers work with Lee Keeling to ensure that all data we provide is properly reflected in the final reserves estimates and they consult with Lee Keeling throughout the reserves estimation process on technical questions regarding the reserve estimates. We also regularly communicate with Lee Keeling throughout the year about our operations and the potential impact of operational changes and events on our reserve estimates.

We did not provide estimates of total proved oil and natural gas reserves during the three year period ended December 31, 2018 to any federal authority or agency, other than the SEC.

Drilling Activity Summary

During the three-year period ended December 31, 2018, we drilled development and exploratory wells as set forth in the table below:

 

 

 

 

 

 

2016

 

 

2017

 

 

2018

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

 

2

 

 

 

0.1

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas

 

 

11

 

 

 

7.8

 

 

 

30

 

 

 

15.7

 

 

 

49

 

 

 

17.0

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

13

 

 

 

7.9

 

 

 

30

 

 

 

15.7

 

 

 

49

 

 

 

17.0

 

Exploratory:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

13

 

 

 

7.9

 

 

 

30

 

 

 

15.7

 

 

 

49

 

 

 

17.0

 

In 2019 to the date of this report, we have drilled five wells (3.3 net to us) and we have seven wells (5.1 net to us) currently in the process of being drilled.

15


 

Producing Well Summary

The following table sets forth the gross and net producing oil and natural gas wells in which we owned an interest at December 31, 2018:

 

 

Oil

 

 

Natural Gas

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Louisiana

 

 

16

 

 

 

4.2

 

 

 

533

 

 

 

265.9

 

Mississippi

 

 

2

 

 

 

1.0

 

 

 

—  

 

 

 

 

Montana

 

 

1

 

 

 

0.2

 

 

 

—  

 

 

 

 

New Mexico

 

 

1

 

 

 

 

 

 

90

 

 

 

13.8

 

North Dakota

 

 

423

 

 

 

65.6

 

 

 

—  

 

 

 

 

Oklahoma

 

 

6

 

 

 

0.6

 

 

 

99

 

 

 

8.9

 

Texas

 

 

11

 

 

 

2.5

 

 

 

418

 

 

 

271.2

 

Wyoming

 

 

 

 

 

 

 

 

26

 

 

 

1.9

 

Total

 

 

460

 

 

 

74.1

 

 

 

1,166

 

 

 

561.7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

We operate 608 of the 1,626 producing wells presented in the above table. As of December 31, 2018, we did not own an interest in any wells containing multiple completions, which means that a well is producing from more than one completed zone.

Acreage

The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2018, all of which is onshore in the continental United States. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.

 

 

Developed

 

 

Undeveloped

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Louisiana

 

 

113,307

 

 

 

72,409

 

 

 

9,830

 

 

 

6,158

 

Mississippi

 

 

2,016

 

 

 

1,944

 

 

 

737

 

 

 

47

 

New Mexico

 

 

12,757

 

 

 

2,740

 

 

 

 

 

 

 

Oklahoma

 

 

26,080

 

 

 

3,382

 

 

 

 

 

 

 

Texas

 

 

50,668

 

 

 

28,125

 

 

 

33,095

 

 

 

19,373

 

Wyoming

 

 

13,440

 

 

 

927

 

 

 

 

 

 

 

Total

 

 

218,268

 

 

 

109,527

 

 

 

43,662

 

 

 

25,578

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

In addition to the acreage above, we have the right to earn interests in 2,829 (1,058 net to us) acres in Louisiana under the terms of a joint development venture.

Our undeveloped acreage expires as follows:

 

Expires in 2019

 

%

Expires in 2020

 

5

%

Expires in 2021

 

3

%

Thereafter

 

92

%

 

 

100

%

Title to our oil and natural gas properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the oil and gas industry, liens incident to operating agreements and for current taxes not yet due and other minor encumbrances. All of our oil and natural gas properties are pledged as collateral under our secured notes and our bank credit facility. As is customary in the oil and natural gas industry, we are generally able to retain our ownership interest in undeveloped acreage by production of existing wells, by drilling activity which establishes commercial reserves sufficient to maintain the lease, by payment of delay rentals or by the exercise of contractual extension rights.

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Markets and Customers

The market for our production of oil and natural gas depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Our oil production is currently sold under short-term contracts with a duration of six months or less. The contracts require the purchasers to purchase the amount of oil production that is available at prices tied to the spot oil markets. Our natural gas production is primarily sold under contracts with various terms and priced on first of the month index prices or on daily spot market prices. Approximately 47% of our 2018 natural gas sales were priced utilizing first of the month index prices and approximately 53% were priced utilizing daily spot prices. CIMA Energy, BP Energy Company and its subsidiaries, and Shell Oil Company and its subsidiaries accounted for 26%, 23%, and 19%, respectively, of our total 2018 sales. The loss of any of these customers would not have a material adverse effect on us as there is an available market for our crude oil and natural gas production from other purchasers.

We have entered into longer term marketing arrangements to ensure that we have adequate transportation to get our natural gas production in North Louisiana to the markets. As an alternative to constructing our own gathering and treating facilities, we have entered into a variety of gathering and treating agreements with midstream companies to transport our natural gas to the long-haul natural gas pipelines. We have entered into an agreement with a major natural gas marketing company to provide us with firm transportation for 10,000 MMBtu per day for our North Louisiana natural gas production on the long-haul pipelines. This agreement expires in 2019. To the extent we are not able to deliver the contracted natural gas volumes, we may be responsible for the transportation costs. Our production available to deliver under these agreements in North Louisiana is expected to exceed the firm transportation arrangements we have in place. In addition, the marketing company managing the firm transportation is required to use reasonable efforts to supplement our deliveries should we have a shortfall during the term of the agreements.

Competition

The oil and gas industry is highly competitive. Competitors include major oil companies, other independent energy companies and individual producers and operators, many of which have financial resources, personnel and facilities substantially greater than we do. We face intense competition for the acquisition of oil and natural gas properties and leases for oil and gas exploration.

Regulation

General. Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulation, as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members. The Federal Energy Regulatory Commission, or "FERC", regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938, or "NGA", and the Natural Gas Policy Act of 1978, or "NGPA". In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting all "first sales" of natural gas, effective January 1, 1993, subject to the terms of any private contracts that may be in effect. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, in the future Congress could reenact price controls or enact other legislation with detrimental impact on many aspects

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of our business. Under the provisions of the Energy Policy Act of 2005 (the "2005 Act"), the NGA has been amended to prohibit any form of market manipulation with the purchase or sale of natural gas, and the FERC has issued new regulations that are intended to increase natural gas pricing transparency. The 2005 Act has also significantly increased the penalties for violations of the NGA. The FERC has issued Order No. 704 et al. which requires a market participant to make an annual filing if it has sales or purchases equal to or greater than 2.2 million MMBtu in the reporting year to facilitate price transparency.

Regulation and transportation of natural gas.   Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. The FERC requires interstate pipelines to provide open-access transportation on a not unduly discriminatory basis for similarly situated shippers. The FERC frequently reviews and modifies its regulations regarding the transportation of natural gas, with the stated goal of fostering competition within the natural gas industry.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The Texas Railroad Commission has been changing its regulations governing transportation and gathering services provided by intrastate pipelines and gatherers. While the changes by these state regulators affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC or state regulators will take on these matters; however, we do not believe that we will be affected differently in any material respect than other natural gas producers with which we compete by any action taken.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach pursued by the FERC, Congress and state regulatory authorities will continue.

Federal leases.   Some of our operations are located on federal oil and natural gas leases that are administered by the Bureau of Land Management ("BLM") of the United States Department of the Interior. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed Department of Interior and BLM regulations and orders that are subject to interpretation and change. These leases are also subject to certain regulations and orders promulgated by the Department of Interior's Bureau of Ocean Energy Management, Regulation & Enforcement ("BOEMRE"), through its Minerals Revenue Management Program, which is responsible for the management of revenues from both onshore and offshore leases.

Oil and natural gas liquids transportation rates.   Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. The price received from the sale of these products may be affected by the cost of transporting the products to market.

The FERC's regulation of pipelines that transport crude oil, condensate and natural gas liquids under the Interstate Commerce Act is generally more light-handed than the FERC's regulation of natural gas pipelines under the NGA. FERC-regulated pipelines that transport crude oil, condensate and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates are permitted in certain circumstances. Effective January 1, 1995, the

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FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates governed by the Interstate Commerce Act that allowed for an increase or decrease in the transportation rates. The FERC's regulations include a methodology for such pipelines to change their rates through the use of an index system that establishes ceiling levels for such rates. The mandatory five year review in 2005 revised the methodology for this index to be based on Producer Price Index for Finished Goods (PPI-FG) plus 1.3 percent for the period July 1, 2006 through June 30, 2011. The mandatory five year review in 2012 revised the methodology for this index to be based on PPI-FG plus 2.65 percent for the period July 1, 2011 through June 30, 2016. The regulations provide that each year the Commission will publish the oil pipeline index after the PPI-FG becomes available.

With respect to intrastate crude oil, condensate and natural gas liquids pipelines subject to the jurisdiction of state agencies, such state regulation is generally less rigorous than the regulation of interstate pipelines. State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests. Complaints or protests have been infrequent and are usually resolved informally.

We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate or natural gas liquids pipelines will affect us in a way that materially differs from the way it affects other crude oil, condensate and natural gas liquids producers or marketers.

Environmental regulations.   We are subject to stringent federal, state and local laws. These laws, among other things, govern the issuance of permits to conduct exploration, drilling and production operations, the amounts and types of materials that may be released into the environment, the discharge and disposition of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, sites and facilities. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup cost without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability. These costs are considered a normal, recurring cost of our on-going operations. Our domestic competitors are generally subject to the same laws and regulations.

We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements or new regulatory schemes such as carbon "cap and trade" programs could have a material adverse effect upon our capital expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas. The Trump Administration and Congress have made some changes and are expected to make additional changes to laws, regulations, and policies applicable to us.  Executive Order 13783 directs federal agencies to review actions that potentially burden the development or use of domestically produced energy resources, and as a result, more regulatory changes are expected.  Those changes may be favorable, but we are unable to predict the scope, timing, or impacts of such changes.  There are also costs associated with responding to changing regulations and policies, whether such regulations are more or less stringent.  As such, there can be no assurance that material cost and liabilities will not be incurred in the future.

The Comprehensive Environmental Response, Compensation and Liability Act; or "CERCLA", imposes liability, without regard to fault, on certain classes of persons that are considered to be

19


 

responsible for the release of a "hazardous substance" into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies. In addition, companies that incur liability frequently also confront third party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site.

The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, or "RCRA", regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites. RCRA currently excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as "hazardous waste". Disposal of such non-hazardous oil and natural gas exploration, development and production wastes usually are regulated by state law. Other wastes handled at exploration and production sites or used in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from RCRA's definition of "hazardous wastes", thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted, it could have a significant impact on our operating costs, as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.

Certain oil and gas wastes may also contain naturally occurring radioactive materials ("NORM"), which is regulated by the federal Occupational Safety and Health Administration and state agencies.  These regulations require certain worker protections and waste handling and disposal procedures.  We believe our operations comply in all material respects with these worker protection and waste handling and disposal requirements.

Our operations are also subject to the Clean Air Act, or "CAA", and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. On April 17, 2012, the U. S. Environmental Protection Agency or "EPA" promulgated new emission standards for the oil and gas industry. These rules require a nearly 95 percent reduction in volatile organic compounds ("VOCs") emitted from hydraulically fractured gas wells by January 1, 2015. This significant reduction in emissions is to be accomplished primarily through the use of "green completions" (i.e., capturing natural gas that currently escapes to the air). These rules also have notification and reporting requirements.  In 2014, EPA revised the emission requirements for storage tanks emitting certain levels of VOCs requiring a 95% reduction of VOC emissions by April 15, 2014 and April 15, 2015 (depending upon the date of construction of the storage tank).  In 2016, EPA finalized regulations that required further reductions specifically regarding methane emissions. However, on October 15, 2016, EPA proposed revisions to these finalized regulations with regard to certain emissions sources, including fugitive emission, pneumatic pumps, and closed vent systems.  There are costs associated with following the status and impacts of these changes, and implementing any changes as they become effective.  However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

The Federal Water Pollution Control Act of 1972, as amended, or the "Clean Water Act", imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction

20


 

activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters, unless otherwise authorized. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the cost of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

The Federal Safe Drinking Water Act of 1974, as amended, requires EPA to develop minimum federal requirements for Underground Injection Control ("UIC") programs and other safeguards to protect public health by preventing injection wells from contaminating underground sources of drinking water. The UIC program does not regulate wells that are solely used for production. However, EPA has authority to regulate hydraulic fracturing when diesel fuels are used in fluids or propping agents. In February 2014, EPA issued guidance on when UIC permitting requirements apply to fracking fluids containing diesel.  We believe that our operations comply in all material respects with the requirements of the Federal Safe Drinking Water Act and similar state statutes.  We believe the requirements are not any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.  

State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma, and Texas, have modified their regulations to account for induced seismicity. Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity; and a 2015 report by researchers at the University of Texas has suggested that the link between seismic activity and wastewater disposal may vary by region. In 2015, the United States Geological Survey identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. More recently, in March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Texas, Colorado, Oklahoma, Kansas, New Mexico, and Arkansas.  In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. Also, the EPA may develop rules to specifically address the disposal of wastewater from oil and gas development and the potential for induced seismicity from wastewater injection.  These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing.

In December 2016, the EPA finalized its report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities could impact drinking water resources under some circumstances.  Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies have the potential to impact the likelihood or scope of future legislation or regulation.

21


 

Federal regulators require certain owners or operators of facilities that store or otherwise handle oil to prepare and implement spill prevention, control, countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") contains numerous requirements relating to the prevention and response to oil spills in the waters of the United States. The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages relating to a spill. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities.

Executive Order 13158, issued on May 26, 2000, directs federal agencies to safeguard existing Marine Protected Areas, or MPAs, in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future exploration and development projects and/or causing us to incur increased operating expenses.

Certain flora and fauna that have officially been classified as "threatened" or "endangered" are protected by the Endangered Species Act. This law prohibits any activities that could "take" a protected plant or animal or reduce or degrade its habitat area. If endangered species are located in an area we wish to develop, the work could be prohibited or delayed and/or expensive mitigation might be required.

Other statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the Oil Pollution Act, the Emergency Planning and Community Right to Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands and other protected areas and impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities. In addition, laws such as the National Environmental Policy Act and the Coastal Zone Management Act may make the process of obtaining certain permits more difficult or time consuming, resulting in increased costs and potential delays that could affect the viability or profitability of certain activities. Administrative policies with respect to such laws are also changing, and we incur costs to follow such changes and comply as changes become effective.

Certain statutes such as the Emergency Planning and Community Right to Know Act require the reporting of hazardous chemicals manufactured, processed, or otherwise used, which may lead to heightened scrutiny of the company's operations by regulatory agencies or the public. In 2012, the EPA adopted a new reporting requirement, the Petroleum and Natural Gas Systems Greenhouse Gas Reporting Rule (40 C.F.R. Part 98, Subpart W), which requires certain onshore petroleum and natural gas facilities to begin collecting data on their emissions of greenhouse gases, or GHGs, in January 2012, with the first annual reports of those emissions due on September 28, 2012. GHGs include gases such as methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning natural gas. Different GHGs have different global warming potentials with CO2 having the lowest global warming potential, so emissions of GHGs are typically expressed in terms of CO2 equivalents, or CO2e. The rule applies to facilities that emit 25,000 metric tons of CO2e or more per year, and requires onshore petroleum and natural gas operators to group all equipment under common ownership or control within a single hydrocarbon basin together when determining if the threshold is met.  These greenhouse gas reporting rules were amended on October 22, 2015 to expand the number of sources and operations that are subject to these rules, and again on November 18, 2016 to provide less burdensome reporting requirements.  We have determined that these reporting requirements apply to us and we believe we have met all of the EPA

22


 

required reporting deadlines and strive to ensure accurate and consistent emissions data reporting. It is possible that these requirements may be loosened or otherwise changed in the future.  Other EPA actions with respect to the reduction of greenhouse gases (such as EPA's Greenhouse Gas Endangerment Finding, and EPA's Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule) and various state actions have or could impose mandatory reductions in greenhouse gas emissions. We are unable to predict at this time how much the cost of compliance with any legislation or regulation of greenhouse gas emissions will be in future periods.  

The U.S. has not passed legislation to expressly address GHGs; however, in recent years the EPA moved ahead with its efforts to regulate GHG emissions from certain sources by rule. Beyond requiring measurement and reporting of GHGs as discussed above, the EPA issued an "Endangerment Finding" under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The EPA has adopted regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities.  States in which we operate may also require permits and reductions in GHG emissions.  Additionally, the EPA published a set of final rules in 2016 that require reductions in VOC and methane generation from new sources, and EPA has announced plans to issue rules regulating existing sources.  However, these rules have been challenged in court, and in 2017, the EPA took steps to institute a two-year delay in implementing the rules.  In 2018, EPA revised a portion of these rules and additional changes may still be forthcoming.  Similarly, the Bureau of Land Management ("BLM") has proposed to suspend and revise a 2016 rule relating to methane venting, flaring, and leaks from oil and gas production on public lands that was being challenged by multiple western states and energy companies.  On April 4, 2018, the Federal District Court in Wyoming issued an order staying the current litigation until BLM either finalizes a revised rule or withdraws it.  Since all of our oil and natural gas production is in the United States, laws or regulations that have been or may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur substantial increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.  In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires ratifying countries to review and "represent a progression" in the ambitions of their nationally determined contributions, which set GHG emission reduction goals, every five years.  The United States signed the Paris Agreement on April 22, 2016; however, the Trump Administration has stated that it intends to withdraw from the Paris Agreement.  The Agreement allows for the U.S. to formally announce its intention to withdraw in November 2019 with the withdrawal effective in November 2020.  Considering the extended timeline for this action, impacts to our operations are uncertain; however, we expect that the impacts to our operations will not be materially different from other similarly situated companies involved in oil and natural gas exploration and production activities.

In 2010 the BLM began implementation of a proposed oil and gas leasing reform that would increase environmental review requirements and was expected to have the effect of reducing the amount of new federal lands made available for lease, increasing the competition for and cost of available parcels.  This leasing reform initiative was replaced by a new BLM policy, dated January 31, 2018, which is expected to remove the additional environmental review created under the 2010 initiative and streamline the leasing process.  Additionally, on December 28, 2017, the BLM rescinded a rule the BLM adopted in 2015 concerning hydraulic fracturing on federal land.  The 2015 rule would have required increased well integrity testing, increased requirements for the managing of fluids, and the disclosure of chemicals used in fracturing.  Due to the ongoing regulatory and legal uncertainty, we cannot predict what effect these changes will have on our operations, though the changes may be advantageous.  We expect that the impacts to our operations will be similar to other similarly situated companies involved in oil and natural gas exploration and production activities.  

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Such changes in environmental laws and regulations which result in more stringent and costly reporting, or waste handling, storage, transportation, disposal or cleanup activities, could materially affect companies operating in the energy industry. Adoption of new regulations further regulating emissions from oil and gas production could adversely affect our business, financial position, results of operations and prospects, as could the adoption of new laws or regulations which levy taxes or other costs on greenhouse gas emissions from other industries, which could result in changes to the consumption and demand for natural gas. We may also be assessed administrative, civil and/or criminal penalties if we fail to comply with any such new laws and regulations applicable to oil and natural gas production.

Regulation of oil and natural gas exploration and production.   Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing, plugging and abandonment of such wells. Some state statutes limit the rate at which oil and natural gas can be produced from our properties. It is also possible that certain states may increase regulatory activity in response to changing federal regulations or policies.

State regulation.   Most states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may be established on a market demand or conservation basis or both.

Office and Operations Facilities

Our executive offices are located at 5300 Town and Country Blvd., Suite 500 in Frisco, Texas 75034 and our telephone number is (972) 668-8800. We lease office space in Frisco, Texas covering 66,382 square feet at a monthly rate of $129,998. This lease expires on December 31, 2021. We also own production offices and pipe yard facilities near Carthage and Marshall, Texas and Homer and Logansport, Louisiana.

Employees

As of December 31, 2018, we had 113 employees and utilized contract employees for certain of our field operations. We consider our employee relations to be satisfactory.

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Directors and Executive Officers

The following table sets forth certain information concerning our executive officers and directors.

 

Name

  

Position with Company

  

    Age    

M. Jay Allison

  

Chief Executive Officer and Chairman of the Board of Directors

  

63

Roland O. Burns

  

President, Chief Financial Officer, Secretary and Director

  

58

Daniel S. Harrison

 

Vice President of Operations

 

55

Michael D. McBurney

  

Vice President of Marketing

  

63

Daniel K. Presley

  

Vice President of Accounting, Controller and Treasurer

  

58

Russell W. Romoser

  

Vice President of Reservoir Engineering

  

67

LaRae L. Sanders

 

Vice President of Land

 

56

Richard D. Singer

  

Vice President of Financial Reporting

  

64

Blaine M. Stribling

  

Vice President of Corporate Development

  

47

Elizabeth B. Davis

 

Director

 

56

Morris E. Foster

 

Director

 

75

Jim L. Turner

 

Director

 

73

A brief biography of each person who serves as an executive officer or director follows below.

Executive Officers

M. Jay Allison has been our Chief Executive Officer since 1988. Mr. Allison was elected Chairman of the Board in 1997 and has been a director since 1987. From 1988 to 2013, Mr. Allison served as our President. From 1981 to 1987, he was a practicing oil and gas attorney with the firm of Lynch, Chappell & Alsup in Midland, Texas. He received B.B.A., M.S. and J.D. degrees from Baylor University in 1978, 1980 and 1981, respectively. Mr. Allison presently serves on the Board of Regents for Baylor University.

Roland O. Burns has been our President since 2013, Chief Financial Officer since 1990, Secretary since 1991 and a director since 1999. Mr. Burns served as our Senior Vice President from 1994 to 2013 and Treasurer from 1990 to 2013. From 1982 to 1990, Mr. Burns was employed by the public accounting firm, Arthur Andersen. During his tenure with Arthur Andersen, Mr. Burns worked primarily in the firm's oil and gas audit practice. Mr. Burns received B.A. and M.A. degrees from the University of Mississippi in 1982 and is a Certified Public Accountant. Mr. Burns also serves on the Board of Directors of the Cotton Bowl Athletic Association and the University of Mississippi Foundation.

Daniel S. Harrison has been our Vice President of Operations since 2017.  Mr. Harrison has been with us since 2008 and served in various engineering and operations management positions of increasing responsibility during that time. Prior to joining us, Mr. Harrison was an operations engineer at Cimarex Energy Company from 2005 to 2008. Prior to 2005 he worked in various petroleum engineering operations management positions for several independent oil and gas exploration and development companies. Mr. Harrison received a B.S. Degree in Petroleum Engineering from the Louisiana State University in 1985.

Michael D. McBurney has been our Vice President of Marketing since 2013. Mr. McBurney has over 34 years of energy industry experience within the oil, natural gas, LNG, and power segments. Prior to joining us, Mr. McBurney worked for EXCO Resources, Inc., an independent exploration and production company where he was responsible for natural gas and natural gas liquids marketing. From 2000 to 2006, Mr. McBurney was with FPL Energy of Florida, where he was responsible for Fuel and Transportation

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logistics for large scale power generation facilities located throughout the U.S. Mr. McBurney received a B.B.A. in Finance from the University of North Texas in 1978.

Daniel K. Presley has been our Treasurer since 2013. Mr. Presley, who has been with us since 1989, also continues to serve as our Vice President of Accounting and Controller, positions he has had held since 1997 and 1991, respectively. Prior to joining us, Mr. Presley had six years of experience with several independent oil and gas companies including AmBrit Energy, Inc. Prior thereto, Mr. Presley spent two and one-half years with B.D.O. Seidman, a public accounting firm. Mr. Presley received a B.B.A. degree from Texas A & M University in 1983.

Russell W. Romoser has been our Vice President of Reservoir Engineering since 2012. Mr. Romoser has over 40 years of experience as a reservoir engineer both with industry and with a petroleum engineering consulting firm. Prior to joining us, Mr. Romoser served eleven years as the Acquisitions Engineering Manager for EXCO Resources, Inc. Mr. Romoser received a B.S. Degree in Petroleum Engineering in 1975 and a Masters Degree in Petroleum Engineering in 1976 from the University of Texas and is a Registered Professional Engineer in Oklahoma and Texas.

LaRae L. Sanders has been our Vice President of Land since 2014.  Ms. Sanders has been with us since 1995.  She has served as Land Manager since 2007, and has been instrumental in all of our active development programs and major acquisitions.  Prior to joining us, Ms. Sanders held positions with Bridge Oil Company and Kaiser-Francis Oil Company, as well as other independent exploration and production companies.  Ms. Sanders is a Certified Professional Landman with 36 years of experience.  She became the nation's first Certified Professional Lease and Title Analyst in 1990.  

Richard D. Singer has been our Vice President of Financial Reporting since 2005. Mr. Singer has over 40 years of experience in financial accounting and reporting. Prior to joining us, Mr. Singer most recently served as an assistant controller for Holly Corporation from 2004 to 2005 and as assistant controller for Santa Fe International Corporation from 1988 to 2002. Mr. Singer received a B.S. degree from the Pennsylvania State University in 1976 and is a Certified Public Accountant.

Blaine M. Stribling has been our Vice President of Corporate Development since 2012. From 2007 to 2012, Mr. Stribling served as our Asset & Corporate Development Manager. Prior to joining us, Mr. Stribling managed a development project team at Encana Oil & Gas from 2005 to 2007. Prior to 2005 he worked in various petroleum engineering operations management positions of increasing responsibility for several independent oil and gas exploration and development companies. Mr. Stribling received a B.S. Degree in Petroleum Engineering from the Colorado School of Mines.

Outside Directors

Elizabeth B. Davis has served as a director since 2014.  Dr. Davis is currently the President of Furman University.  Dr. Davis was the Executive Vice President and Provost for Baylor University until July 2014, and served as Interim Provost from 2008 until 2010. Prior to her appointment as Provost, she was a professor of accounting in the Hankamer School of Business at Baylor University where she also served as associate dean for undergraduate programs and as acting chair for the Department of Accounting and Business Law. Prior to joining Baylor University, she worked for the public accounting firm Arthur Andersen from 1984 to 1987.

Morris E. Foster has served as a director since 2017. Mr. Morris retired in 2008 as Vice President of ExxonMobil Corporation and President of ExxonMobil Production Company following more than 40 years of service with the ExxonMobil group. Mr. Foster served in a number of production engineering and management roles domestically as well as in the United Kingdom and Malaysia prior to his appointment in 1995 as a Senior Vice President in charge of the upstream business of Exxon Company,

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USA. In 1998, Mr. Foster was appointed President of Exxon Upstream Development Company, and following the merger of Exxon and Mobil in 1999, he was named to the position of President of ExxonMobil Development Company. In 2004, Mr. Foster was named President of Exxon Mobil Production Company, the division responsible for ExxonMobil's upstream oil and gas exploration and production business, and a Vice President of ExxonMobil Corporation. Mr. Foster currently serves as Chairman of Stagecoach Properties Inc., a real estate holding corporation with properties in Salado, Houston and College Station, Texas and Carmel, California and as a member of the Board of Regents of Texas A&M University. In addition, Mr. Foster currently serves on the board of directors of Scott & White Medical Institute and First State Bank of Temple, Texas.

Jim L. Turner has served as a director since 2014.  Mr. Turner currently serves as principal of JLT Beverages, L.P., a position he has held since 1996. Mr. Turner is also Chief Executive Officer of JLT Automotive, Inc. Mr. Turner served as President and Chief Executive Officer of Dr. Pepper/Seven Up Bottling Group, Inc., from its formation in 1999 through 2005, when he sold his interest in that company. Prior to that, Mr. Turner served as Owner/Chairman of the Board and Chief Executive Officer of the Turner Beverage Group, the largest privately owned independent bottler in the United States. Mr. Turner currently serves as a non-executive chairman of the board of directors for Dean Foods Company and is past chairman and currently serves on the board of trustees of Baylor Scott and White Health, the largest not-for-profit healthcare system in the state of Texas.  He is also a director of Crown Holdings, Inc. and INSURICA.

Available Information

Our executive offices are located at 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034. Our telephone number is (972) 668-8800. We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934. The SEC maintains a website that contains reports, proxy and information statements, and other information that is electronically filed with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov. We also make available free of charge on our website (www.comstockresources.com) our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we file such material with, or furnish it to, the SEC.

 

ITEM 1A.  Risk Factors

You should carefully consider the following risk factors as well as the other information contained or incorporated by reference in this report, as these important factors, among others, could cause our actual results to differ from our expected or historical results. It is not possible to predict or identify all such factors. Consequently, you should not consider any such list to be a complete statement of all of our potential risks or uncertainties. Based on the information currently known to us, we believe the following information identifies the most significant risk ‎factors affecting us, but the below risks and uncertainties are not the only ones related to our businesses and are not necessarily ‎listed in the order of their significance. Additional risks and uncertainties not presently known to us or that we currently ‎believe to be immaterial may also adversely affect our business

An extended period of depressed oil and natural gas prices will adversely affect our business, financial condition, cash flow, liquidity, results of operations and our ability to meet our capital expenditure obligations and financial commitments.

Our business is heavily dependent upon the prices of, and demand for, oil and natural gas. Historically, the prices for oil and natural gas have been volatile and are likely to remain volatile in the future.  During 2018, commodity prices fluctuated significantly, with the settlement price for West Texas Intermediate ("WTI") crude oil ranging from a high of approximately $76.41 per barrel to a low of

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approximately $44.61 per barrel and settlement prices for Henry Hub natural gas ranging from a high of approximately $4.84 per Mcf to a low of approximately $2.56 per Mcf.  Oil and natural gas price volatility continued into 2019 and, through March 1, 2019, the WTI settlement price of crude oil had a low of approximately $46.54 per barrel, and the Henry Hub settlement price of natural gas reached a low of approximately $2.55 per Mcf.

The prices we receive for our oil and natural gas production are subject to wide fluctuations and depend on numerous factors beyond our control, including the following:

 

the domestic and foreign supply of oil, natural gas liquids and natural gas;

 

weather conditions;

 

the price and quantity of imports of oil and natural gas;

 

political conditions and events in other oil-producing and natural gas-producing countries, including embargoes, hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;

 

the actions of the Organization of Petroleum Exporting Countries, or OPEC;

 

domestic government regulation, legislation and policies;

 

the level of global oil and natural gas inventories;

 

technological advances affecting energy consumption;

 

the price and availability of alternative fuels; and

 

overall economic conditions.

Lower oil and natural gas prices will adversely affect:

 

our revenues, profitability and cash flow from operations;

 

the value of our proved oil and natural gas reserves;

 

the economic viability of certain of our drilling prospects;

 

our borrowing capacity; and

 

our ability to obtain additional capital.

Our debt service requirements could adversely affect our operations and limit our growth.

We had $1.3 billion principal amount of debt as of December 31, 2018.

Our outstanding debt has important consequences, including, without limitation:

 

a portion of our cash flow from operations is required to make debt service payments;

 

our ability to borrow additional amounts for capital expenditures (including acquisitions) or other purposes is limited; and

 

our debt limits (i) our ability to capitalize on significant business opportunities, (ii) our flexibility in planning for or reacting to changes in market conditions, and (iii) our ability to withstand competitive pressures and economic downturns.

Future acquisitions or development activities may require us to alter our capitalization significantly. These changes in capitalization may significantly increase our debt. Moreover, our ability to meet our debt service obligations and to reduce our total debt will be dependent upon our future performance, which will be subject to general economic conditions and financial, business and other factors affecting our operations, many of which are beyond our control. If we are unable to service our indebtedness and to meet other commitments, we will be required to adopt one or more alternatives, such as refinancing or restructuring our indebtedness, selling material assets or seeking to raise additional debt or equity capital. We cannot assure you that any of these actions could be effected on a timely basis or on satisfactory terms or that these actions would enable us to continue to satisfy our capital requirements.

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Our debt agreements contain a number of significant covenants. These covenants limit our ability to, among other things:

 

borrow additional money;

 

merge, consolidate or dispose of assets;

 

make certain types of investments;

 

enter into transactions with our affiliates; and

 

pay dividends.

Our failure to comply with any of these covenants could cause a default under our bank credit facility and the indenture governing our outstanding notes. A default, if not waived, could result in acceleration of our indebtedness, in which case the debt would become immediately due and payable. If this occurs, we may not be able to repay our debt or borrow sufficient funds to refinance it given the current status of the credit markets. Even if new financing is available, it may not be on terms that are acceptable to us. Complying with these covenants may cause us to take actions that we otherwise would not take or not take actions that we otherwise would take.

Our access to capital markets may be limited in the future.

Adverse changes in the financial and credit markets could negatively impact our ability to grow production and reserves and meet our future obligations.  In addition, the continuation of the current low oil and natural gas price environment, or further declines of oil and natural gas prices, will affect our ability to obtain financing for acquisitions and drilling activities and could result in a reduction in drilling activity, which could lead to a loss of acreage due to lease expirations, both of which could negatively affect our ability to replace reserves.

Our future production and revenues depend on our ability to replace our reserves.

Our future production and revenues depend upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we must continue our acquisition and drilling activities. We cannot assure you that we will have adequate capital resources to conduct acquisition and drilling activities or that our acquisition and drilling activities will result in significant additional reserves or that we will have continuing success drilling productive wells at low finding and development costs. Furthermore, while our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return.

A prospect is a property in which we own an interest, or have operating rights to, and that has what our geoscientists believe, based on available seismic and geological information, to be an indication of potential oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional evaluation and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. The analysis that we perform using

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data from other wells, more fully explored prospects and/or producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling prospects. If we drill additional unsuccessful wells, our drilling success rate may decline and we may not achieve our targeted rate of return.

Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our success depends on the success of our exploration and development activities. Exploration activities involve numerous risks, including the risk that no commercially productive natural gas or oil reserves will be discovered. In addition, these activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells can hurt our efforts to replace production and reserves.

Our business involves a variety of operating risks, including:

 

unusual or unexpected geological formations;

 

fires;

 

explosions;

 

blow-outs and surface cratering;

 

uncontrollable flows of natural gas, oil and formation water;

 

natural disasters, such as hurricanes, tropical storms and other adverse weather conditions;

 

pipe, cement, or pipeline failures;

 

casing collapses;

 

mechanical difficulties, such as lost or stuck oil field drilling and service tools;

 

abnormally pressured formations; and

 

environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

If we experience any of the above operating risks, our well bores, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations.

We could also incur substantial losses as a result of:

 

injury or loss of life;

 

severe damage to and destruction of property, natural resources and equipment;

 

pollution and other environmental damage;

 

clean-up responsibilities;

 

regulatory investigation and penalties;

 

suspension of our operations; and

 

repairs to resume operations.

We maintain insurance against "sudden and accidental" occurrences, which may cover some, but not all, of the risks described above. Most significantly, the insurance we maintain will not cover the risks described above which occur over a sustained period of time. Further, there can be no assurance that such insurance will continue to be available to cover all such cost or that such insurance will be available at a cost that would justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations.

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We operate in a highly competitive industry, and our failure to remain competitive with our competitors, many of which have greater resources than we do, could adversely affect our results of operations.

The oil and natural gas industry is highly competitive in the search for and development and acquisition of reserves. Our competitors often include companies that have greater financial and personnel resources than we do. These resources could allow those competitors to price their products and services more aggressively than we can, which could hurt our profitability. Moreover, our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to close transactions in a highly competitive environment.

If oil and natural gas prices decline further or remain low for an extended period of time, we may be required to further write-down the carrying values and/or the estimates of total reserves of our oil and natural gas properties, which would constitute a non-cash charge to earnings and adversely affect our results of operations.

Accounting rules applicable to us require that we periodically review the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We recognized impairments that totaled $27.1 million and $44.0 million in 2016 and 2017, respectively, which reduced the carrying value of our oil and natural gas properties.  We may incur additional non-cash charges in the future, which could have a material adverse effect on our results of operations in the period taken. We may also reduce our estimates of the reserves that may be economically recovered, which could have the effect of reducing the total value of our reserves.

Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve estimates are to some degree imprecise, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas prices may all differ materially from those assumed in these estimates. The information regarding the present value of future net cash flows attributable to our proved oil and natural gas reserves is only an estimate and should not be construed as the current market value of the oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding year's estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Any future downward revisions could adversely affect our financial condition, our borrowing ability, our future prospects and the value of our common stock.

As of December 31, 2018, 71% of our total proved reserves were undeveloped and 2% were developed non-producing. These reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced at the time periods we have planned, at the costs we have budgeted, or at all. As a result, we may not find

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commercially viable quantities of oil and natural gas, which in turn may result in a material adverse effect on our results of operations.

Some of our undeveloped leasehold acreage is subject to leases that will expire unless production is established on units containing the acreage.

Leases on oil and gas properties normally have a term of three to five years and will expire unless, prior to expiration of the lease term, production in paying quantities is established.  If the leases expire and we are unable to renew them, we will lose the right to develop the leased properties.  Our drilling plans for these areas are subject to change based upon various factors, including drilling results, commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

We pursue acquisitions as part of our growth strategy and there are risks associated with such acquisitions.

Our growth has been attributable in part to acquisitions of producing properties and companies. More recently we have been focused on acquiring acreage for our drilling program. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. However, we cannot assure you that suitable acquisition candidates will be identified in the future, or that we will be able to finance such acquisitions on favorable terms. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will successfully acquire any material property interests. Further, we cannot assure you that future acquisitions by us will be integrated successfully into our operations or will increase our profits.

The successful acquisition of producing properties requires an assessment of numerous factors beyond our control, including, without limitation:

 

recoverable reserves;

 

exploration potential;

 

future oil and natural gas prices;

 

operating costs; and

 

potential environmental and other liabilities.

In connection with such assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. The resulting assessments are inexact and their accuracy uncertain, and such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is made.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics or geographic location than our existing properties. While our current operations are focused in Texas and Louisiana, we may pursue acquisitions or properties located in other geographic areas.

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If we are unsuccessful at marketing our oil and natural gas at commercially acceptable prices, our profitability may decline.

Our ability to market oil and natural gas at commercially acceptable prices depends on, among other factors, the following:

 

the availability and capacity of gathering systems and pipelines;

 

federal and state regulation of production and transportation;

 

changes in supply and demand; and

 

general economic conditions.

Our inability to respond appropriately to changes in these factors could negatively affect our profitability.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and processing facilities. Our ability to market our production depends in a substantial part on the availability and capacity of gathering systems, pipelines and processing facilities, which, in some cases, may be owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to a lack of market demand or because of the inadequacy or unavailability of pipelines or gathering system capacity. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.

We are subject to extensive governmental laws and regulations that may adversely affect the cost, manner or feasibility of doing business.

Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and natural gas, as well as the safe operations thereof. Future laws or regulations, adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with present and future governmental laws and regulations, such as:

 

lease permit restrictions;

 

drilling bonds and other financial responsibility requirements, such as plug and abandonment bonds;

 

spacing of wells;

 

unitization and pooling of properties;

 

safety precautions;

 

regulatory requirements; and

 

taxation.

Under these laws and regulations, we could be liable for:

 

personal injuries;

 

property and natural resource damages;

 

well reclamation costs; and

 

governmental sanctions, such as fines and penalties.

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Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.

 

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from various sources for use in our operations. If we are unable to obtain water from local sources to use in our operations, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

Our operations may incur substantial liabilities due to compliance with environmental laws and regulations.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment and otherwise relating to environmental protection. These laws and regulations:

 

require the acquisition of one or more permits before drilling commences;

 

impose limitations on where drilling can occur and/or requires mitigation before authorizing drilling in certain locations;

 

restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

 

require reporting of significant releases, and annual reporting of the nature and quantity of emissions, discharges and other releases into the environment;

 

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

 

impose substantial liabilities for pollution resulting from our operations.

Failure to comply with these laws and regulations may result in:

 

the assessment of administrative, civil and criminal penalties;

 

the incurrence of investigatory and/or remedial obligations; and

 

the imposition of injunctive relief.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly restrictions on emissions, and/or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination, even if our operations met previous industry standards at the time they were performed. Future environmental laws and regulations, including proposed legislation regulating GHGs or climate change, may negatively impact our industry. The costs of compliance with these requirements may have an adverse impact on our financial condition, results of operations and cash flows.

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Our hedging transactions could result in financial losses or could reduce our income. To the extent we have hedged a significant portion of our expected production and our actual production is lower than we expected or the costs of goods and services increase, our profitability would be adversely affected.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we have entered into and may continue to enter into hedging transactions for certain of our expected oil and natural gas production. These transactions could result in both realized and unrealized hedging losses. Further, these hedges may be inadequate to protect us from continuing and prolonged declines in the price of oil and natural gas. To the extent that the prices of oil and natural gas remain at current levels or declines further, we will not be able to hedge future production at the same level as our current hedges, and our results of operations and financial condition would be negatively impacted.

The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we utilize are primarily based on NYMEX futures prices, which may differ significantly from the actual crude oil and gas prices we realize in our operations. Furthermore, we have adopted a policy that requires, and our revolving credit facility also requires, that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we will continue to have direct commodity price exposure on the portion of our production volumes not covered by these derivative financial instruments.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions. If our actual future production is higher than we estimated, we will have greater commodity price exposure than we intended. If our actual future production is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution in our profitability and liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

In addition, our hedging transactions are subject to the following risks:

 

we may be limited in receiving the full benefit of increases in oil and gas prices as a result of these transactions;

 

a counterparty may not perform its obligation under the applicable derivative financial instrument or may seek bankruptcy protection;

 

there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

 

the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risks, interest rate risks and other risks associated with our business.

In 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank"), was enacted that established federal oversight regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.  Dodd-Frank requires the Commodities Futures Trading Commission, or CFTC, the SEC and

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other regulators to promulgate rules and regulations implementing the new legislation. The final rules adopted under Dodd-Frank identify the types of products and the classes of market participants subject to regulation and will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption from such requirements). While most of the regulations have been finalized, it is not possible at this time to predict with certainty the full effects of Dodd-Frank and CFTC rules on us or the timing of such effects.  We believe that Dodd-Frank and associated regulations could significantly increase the cost of derivative contracts from additional recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity.  If we reduce our use of derivatives as a result of Dodd-Frank and associated regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. These consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as restrict our access to our oil and gas reserves.

Hydraulic fracturing is an essential and common practice that is used to stimulate production of oil and natural gas from dense subsurface rock formations such as shale and tight sands. We routinely apply hydraulic fracturing techniques in completing our wells. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. The use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from many reservoirs including the Haynesville shale, Bossier shale, Eagle Ford shale, Tuscaloosa Marine shale, Cotton Valley and other tight natural gas and oil reservoirs. Substantially all of our proved oil and gas reserves that are currently not producing and our undeveloped acreage require hydraulic fracturing to be productive. All of the wells currently being drilled by us utilize hydraulic fracturing in their completion and hydraulic fracturing services comprise approximately 45% of our capital budget in 2019.

The use of hydraulic fracturing in our well completion activities could expose us to liability for negative environmental effects that might occur. Although we have not had any incidents related to hydraulic fracturing operations that we believe have caused any negative environmental effects, we have established operating procedures to respond and report any unexpected fluid discharge which might occur during our operations, including plans to remediate any spills that might occur. In the event that we were to suffer a loss related to hydraulic fracturing operations, our insurance coverage will be net of a deductible per occurrence and our ability to recover costs will be limited to a total aggregate policy limit of $26.0 million, which may or may not be sufficient to pay the full amount of our losses incurred.

Drilling and completion activities are typically regulated by state oil and natural gas commissions. Our drilling and completion activities are conducted primarily in Louisiana and Texas. Texas adopted a law in June 2012 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition, Congress has considered legislation that, if implemented, would subject the process of hydraulic fracturing to regulation under the Safe Drinking Water Act. In June 2015, the EPA released a draft report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there may be above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report was finalized in December 2016. Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating

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various other aspects of hydraulic fracturing. These ongoing or proposed studies have the potential to impact the likelihood or scope of future legislation or regulation.

State and federal regulatory agencies have recently focused on a possible connection between the hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma, and Texas, have modified their regulations to account for induced seismicity. Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity; and a 2015 report by researchers at the University of Texas has suggested that the link between seismic activity and wastewater disposal may vary by region. In 2015, the United States Geological Survey identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. More recently, in March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Texas, Colorado, Oklahoma, Kansas, New Mexico, and Arkansas.  In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing.

Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could have a material adverse effect on our results of operations, financial condition, or cash flows.

We make judgments regarding the utilization of existing income tax credits and the potential tax effects of various financial transactions and results of operations to estimate our obligations to taxing authorities.  Tax obligations include income, franchise, real estate, sales and use, and employment-related taxes.  These judgments include reserves for potential adverse outcomes regarding tax positions that have been taken.  Changes in federal, state, or local tax laws, adverse tax audit results, or adverse tax rulings on positions taken by us could have a material adverse effect on our results of operations, financial condition, or cash flows.

The Budget Reconciliation Act, commonly referred to as the Tax Cuts and Jobs Act (hereinafter "Tax Cuts and Jobs Act"), was signed into law on December 22, 2017.  The Tax Cuts and Jobs Act resulted in a net tax benefit to us of approximately $20.4 million, which is attributable primarily to the termination of the corporate alternative minimum tax.  The Tax Cuts and Jobs Act is expected to have a favorable impact on our effective tax rate and net income as reported under generally accepted accounting principles in future reporting periods to which the Tax Cuts and Jobs Act is effective.  However, we are still assessing the full impact of the Tax Cuts and Jobs Act, including the impact on state taxes, and there can be no assurances that it will have a favorable impact on us or our future financial results.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data.  If any of these programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include loss of our communication links, our inability to find, produce, process and sell oil and natural gas and the inability to automatically process commercial

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transactions or engage in similar automated or computerized business activities.  Any of these consequences could have a material effect on our business.

Our business could be negatively impacted by security threats, including cyber-security threats and other disruptions.

As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security or operation of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts.  Cyber-security attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data.  Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing.  If any of these events were to materialize, either to the Company or a third party upon which we rely, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities, essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.

We are exposed to the credit risk of our customers and counterparties, and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business.  Our credit procedures and policies may not be adequate to fully eliminate customer and counterparty credit risk particularly in light of the sustained declines in oil and natural gas prices since mid-2014.  We cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers' and counterparties' creditworthiness.  If we fail to adequately assess the creditworthiness of existing or future customers and counterparties, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write-down or write-off doubtful accounts.  Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur and, if significant, could have a material adverse effect on our business, results of operations, cash flows and financial condition.

Substantial exploration and development activities could require significant outside capital, which could dilute the value of our common shares and restrict our activities. Also, we may not be able to obtain needed capital or financing on satisfactory terms, which could lead to a limitation of our future business opportunities and a decline in our oil and natural gas reserves.

We expect to expend substantial capital in the acquisition of, exploration for and development of oil and natural gas reserves. In order to finance these activities, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of non-strategic assets or other means. The issuance of additional equity securities could have a dilutive effect on the value of our common shares, and may not be possible on terms acceptable to us given the current volatility in the financial markets. The issuance of additional debt would likely require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions, dividends and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Our cash flow from operations and access to capital is subject to a number of variables, including:

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our estimated proved reserves;

 

the level of oil and natural gas we are able to produce from existing wells;

 

our ability to extract natural gas liquids from the natural gas we produce;

 

the prices at which oil, natural gas liquids and natural gas are sold; and

 

our ability to acquire, locate and produce new reserves.

If our revenues decrease as a result of lower oil or natural gas prices, operating difficulties or declines in reserves, our ability to obtain the capital necessary to undertake or complete future exploration and development programs and to pursue other opportunities may be limited, which could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could result in a decline in our oil and natural gas reserves.

The unavailability or high cost of drilling rigs, equipment, supplies, qualified personnel and oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry has experienced a shortage of drilling rigs, equipment, supplies and qualified personnel in prior years as the result of higher demand for these services. Shortages of drilling rigs, equipment, supplies or qualified personnel in the areas in which we operate could delay or restrict our exploration and development operations, which in turn could adversely affect our financial condition and results of operations because of our concentration in those areas.

We depend on our key personnel and the loss of any of these individuals could have a material adverse effect on our operations.

We believe that the success of our business strategy and our ability to operate profitably depend on the continued employment of M. Jay Allison, our Chief Executive Officer, and Roland O. Burns, our President and Chief Financial Officer, and a limited number of other senior management personnel. Loss of the services of Mr. Allison, Mr. Burns or any of those other individuals could have a material adverse effect on our operations.

Our insurance coverage may not be sufficient or may not be available to cover some liabilities or losses that we may incur.

If we suffer a significant accident or other loss, our insurance coverage will be net of our deductibles and may not be sufficient to pay the full current market value or current replacement value of our lost investment, which could result in a material adverse impact on our operations and financial condition. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third party drilling contractors are used to drill our wells, we may not realize the full benefit of workers' compensation laws in dealing with their employees. In addition, some risks, including pollution and environmental risks, generally are not fully insurable.

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Provisions of our restated articles of incorporation, bylaws and Nevada law will make it more difficult to effect a change in control of us, which could adversely affect the price of our common stock.

Nevada corporate law and our restated articles of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us. These provisions include:

 

allowing for authorized but unissued shares of common and preferred stock;

 

requiring special stockholder meetings to be called only by our chairman of the board, our chief executive officer, a majority of the board, a majority of our executive committee or the holders of a majority of our outstanding stock;

 

requiring removal of directors by a supermajority stockholder vote;

 

prohibiting cumulative voting in the election of directors; and

 

Nevada control share laws that may limit voting rights in shares representing a controlling interest in us.

These provisions could make an acquisition of us by means of a tender offer or proxy contest or removal of our incumbent directors more difficult. As a result, these provisions could make it more difficult for a third party to acquire us, even