UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark  One)

 

 

 

 

 

 

 

 

þ

 

 

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR

 

 

 

 

 

 

 

 

15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

 

 

 

 

 

 

For the fiscal year ended December 31, 2013

 

 

 

 

 

 

 

 

 

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

ü

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

ü

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

ü

No

    

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

Yes

ü

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.   ü  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

Large accelerated filer

 ü

 

Accelerated filer

 

 

Non-accelerated filer

 

 

Smaller reporting company

 

 

 

 

 

 

 

(Do not check if smaller reporting company)

 

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

Yes

 

No

ü

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 30, 2013 (the last business day of the registrant’s most recently completed second fiscal quarter), was $705.7 million.

As of February 26, 2014, there were 47,837,224 shares of common stock of the registrant outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Definitive Proxy Statement for the 2014 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, 2013

CONTENTS

 

Item

 

 

 

Page

 

 

 

Part I

 

 

 

 

 

 

Cautionary Note Regarding Forward-Looking Statements

 

2

 

 

 

Definitions

 

3

 

1 and 2.

  

 

Business and Properties

 

6

 

1A.

 

 

Risk Factors

 

29

 

1B.

 

 

Unresolved Staff Comments

 

41

 

3.

 

 

Legal Proceedings

 

41

 

4.

 

 

Mine Safety Disclosures

 

41

 

 

 

Part II

 

 

 

 

5.

 

 

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

 

42

 

6.

 

 

Selected Financial Data

 

44

 

7.

 

 

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

 

45

 

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;

·

the availability of exploration and development opportunities;

·

amount, nature and timing of capital expenditures;

·

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

·

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;

·

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

·

hostilities in the Middle East and other sustained military campaigns and acts of terrorism or sabotage that impact the supply of crude oil and natural gas.

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 and produce oil or natural gas reserves not classified as proved, 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.

“GAAP” means generally accepted accounting principles in the United States of America.

“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.

“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.

“PV 10 Value” means the present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with the Securities and Exchange Commission 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 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, the use of a pre-tax measure is helpful to investors when comparing companies in our industry.

“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.

4


 

“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.

“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.

“Reserve replacement” means the calculation derived by dividing additions to reserves from acquisitions, extensions, discoveries and revisions of previous estimates in a year 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.

“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 engaged in the acquisition, development, production and exploration of oil and natural gas. Our common stock is listed and traded on the New York Stock Exchange. In May 2013, we divested all of our oil and gas properties in West Texas and, accordingly, the discussion which follows pertains solely to our continuing oil and gas operations.

Our oil and gas operations are concentrated in Texas and Louisiana. Our oil and natural gas properties are estimated to have proved reserves of 585 Bcfe with an estimated PV 10 Value of $1.1 billion as of December 31, 2013 and a standardized measure of discounted future net cash flows of $0.8 billion. Our proved oil and natural gas reserve base is 77% natural gas and 23% oil and are 73% developed as of December 31, 2013.

Our proved reserves at December 31, 2013 and our 2013 average daily production are summarized below:

 

 

  

Proved Reserves at December 31, 2013

 

  

2013 Average Daily Production

 

 

  

Oil
(MMBbls)

 

  

Natural
Gas
(Bcf)

 

  

Total
(Bcfe)

 

  

% of
Total

 

  

Oil
(MBbls/d)

 

  

Natural
Gas
(MMcf/d)

 

  

Total
(MMcfe/d)

 

  

% of
Total

 

 

East Texas / North Louisiana

 

 

0.4

 

 

 

341.3

 

 

 

343.8

 

 

 

58.8

%

 

 

0.1

 

 

 

128.4

 

 

 

129.5

 

 

 

68.0

%

South Texas

 

 

21.5

 

 

 

98.6

 

 

 

227.6

 

 

 

38.9

%

 

 

6.1

 

 

 

19.7

 

 

 

56.3

 

 

 

29.5

%

Other Regions

 

 

0.1

 

 

 

12.8

 

 

 

13.1

 

 

 

2.3

%

 

 

0.1

 

 

 

4.5

 

 

 

4.8

 

 

 

2.5

%

Total

 

 

22.0

 

 

 

452.7

 

 

 

584.5

 

 

 

100.0

%

 

 

6.3

 

 

 

152.6

 

 

 

190.6

 

 

 

100.0

%

Strengths

High Quality Properties.     Our operations are currently focused in two operating areas: East Texas/North Louisiana and South Texas. Our properties have an average reserve life of approximately 8.4 years and have extensive development and exploration potential. In response to the low natural gas price environment in recent years, we have focused our drilling activity primarily on oil projects and limited our natural gas drilling to wells required to hold acreage. Our Eagleville field includes 31,755 acres (25,316 net to us) located in the oil window of the Eagle Ford shale in South Texas. In 2013 94% of our drilling and completion expenditures were related to our Eagleville field development. During 2013, we acquired acreage in two additional areas that are prospective for oil, including 33,624 acres (21,034 net to us) in the oil window of the Eagleford shale in or near Burleson County, Texas, and 53,470 acres (51,017 net to us) in Mississippi and Louisiana that are prospective for development in the Tuscaloosa Marine shale. Our properties in the East Texas/North Louisiana region, which are primarily prospective for natural gas, include 84,875 acres (72,232 net to us) in the Haynesville or Bossier shale formations.

Successful Exploration and Development Program.     In 2013 we spent $481.1 million on exploration and development activities. We spent $338.0 million on drilling and completing wells in 2013. We drilled 77 wells (53.6 net to us) and completed 67 wells (44.1 net to us). We also spent $137.1 million in 2013 to acquire additional leasehold, $0.4 million to acquire seismic data and $5.6 million for recompletions, workovers, abandonment, and production facilities. Of our 2013 capital expenditures, 95% were directed towards oil projects. Our drilling activities in 2013 added 13.2 MMBOE to our proved reserves and increased our oil production in 2013 by 29% from 2012's oil production.

Efficient Operator.     We operated 95% of our proved reserve base as of December 31, 2013. As operator we are better able to control operating costs, the timing and plans for future development, the

6


 

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.

Successful Acquisitions.   We have had significant growth over the years as a result of our acquisition activity. In recent years we have focused primarily on acquiring undrilled acreage rather than producing properties. We apply strict economic and reserve risk criteria in evaluating acquisitions. Over the last twenty years, we have added 1.1 Tcfe of proved oil and natural gas reserves from 38 acquisitions of producing oil and gas properties at an average cost of $1.17 per Mcfe. Our application of strict economic and reserve risk criteria have enabled us to successfully evaluate and integrate acquisitions.

Business Strategy

 

Pursue Exploration Opportunities.   Each year, we conduct exploration activities to grow our reserve base and to replace our production. In recent years we have been focused on oil development, and we limited our drilling on natural gas properties due to weak natural gas prices.

In 2013 our Eagleville field in South Texas was the primary focus of our drilling activity. From 2010 through 2013, we spent approximately $169.5 million leasing acreage in McMullen, Atascosa, Frio, La Salle, Karnes and Wilson Counties in South Texas, which we believe to be prospective for oil in the Eagle Ford shale formation. In 2012 we entered into a joint venture arrangement to allow us to accelerate the development of this field. Our joint venture partner participates for a one-third interest in the wells that we drill in exchange for paying $25,000 per net acre that is earned by their participation. Through December 31, 2013, we have drilled 128 wells (94.3 net to us) in our Eagleville field including 75 wells (51.6 net to us) drilled in 2013. Our joint venture partner participated in 96 of these wells and contributed $61.3 million through December 31, 2013 for acreage and an additional $5.0 million to reimburse us for a portion of common production facilities. In 2013, we added 6.1 MMBOE to our proved reserves from our drilling activity in Eagleville. We have budgeted to spend $344.0 million in 2014, net of reimbursements from our joint venture partner, to drill 59 wells (40.2 net to us) and to complete 18 wells (13.3 net to us) that were drilled in 2013.

In May 2013 we completed the divestiture of our West Texas properties that were acquired in 2011.  We received proceeds of $823.1 million from the sale and recognized a gain of $230.0 million ($148.6 million after income taxes).  We divested of the properties due to the substantial drilling required to maintain the leases, the opportunity to earn a substantial profit from our investment and the low returns we were realizing from our 2012 drilling activity.  The divestiture allowed us to repay $722.0 million of our long-term debt and to accelerate the development of our Eagleville field.

We spent $67.4 million in 2013 to lease 33,624 acres (21,034 net to us) in or near Burleson County,  Texas which are prospective for oil in the Eagle Ford shale formation, and we spent $53.3 million to acquire 53,470 acres (51,017 net to us) in Louisiana and Mississippi, which are prospective for oil in the Tuscaloosa Marine shale.  We have budgeted $77.0 million in 2014 for drilling 12 wells (7.4 net to us) on the new acreage.

We have a significant acreage position of 84,875 acres (72,232 net to us) in East Texas and North Louisiana with Haynesville or Bossier shale natural gas potential, but in 2013 we elected to defer most of our drilling operations until natural gas prices improve. We drilled two Haynesville and Bossier shale horizontal wells (2.0 net to us) in 2013, which added 37 Bcfe to our proved reserves.

Exploit Existing Reserves.   We seek to maximize the value of our oil and gas properties by increasing production and recoverable reserves through development drilling and workover, recompletion and exploitation activities. We utilize advanced industry technology, including 3-D seismic data, horizontal drilling, enhanced logging tools, and formation stimulation techniques.

7


 

Maintain Flexible Capital Expenditure Budget.   The timing of most of our capital expenditures is discretionary because we have not made any significant long-term capital expenditure commitments except for contracted drilling and completion services. We operate most of the drilling projects in which we participate. Consequently, we have a significant degree of flexibility to adjust the level of such expenditures according to market conditions. We have budgeted to spend approximately $450.0 million in 2014 on our development and exploration projects and $28.0 million for lease acquisition activity.

Acquire High Quality Properties at Attractive Costs.   Historically, we have had a successful track record of increasing our oil and natural gas reserves through opportunistic acquisitions. Over the last twenty years, we have added 1.1 Tcfe of proved oil and natural gas reserves from 38 acquisitions of producing oil and gas properties at a total cost of $1.3 billion, or $1.17 per Mcfe. The acquisitions were acquired at an average of 67% of their PV 10 Value in the year the acquisitions were completed. In evaluating acquisitions, we apply strict economic and reserve risk criteria. We target properties in our core operating areas with established production and low operating costs that also have potential opportunities to increase production and reserves through exploration and exploitation activities. We also evaluate our existing properties and consider divesting of non-strategic assets when market conditions are favorable.

Primary Operating Areas

The following table summarizes the estimated proved oil and natural gas reserves for our fifteen largest field areas as of December 31, 2013:

 

 

 

Oil
(MBbls)

 

 

Natural
Gas
(MMcf)

 

 

Total
(MMcfe)(1)

 

 

%

 

 

PV 10 
Value
(2)
(000’s)

 

 

%

 

East Texas / North Louisiana:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Logansport

 

 

28

 

 

 

232,642

 

 

 

232,811

 

 

 

39.8

%

 

$

169,649

 

 

 

16.1

%

Toledo Bend

 

 

 

 

 

31,071

 

 

 

31,071

 

 

 

5.3

%

 

 

31,503

 

 

 

3.0

%

Beckville

 

 

142

 

 

 

29,762

 

 

 

30,616

 

 

 

5.2

%

 

 

30,663

 

 

 

2.9

%

Waskom

 

 

66

 

 

 

12,285

 

 

 

12,678

 

 

 

2.2

%

 

 

13,435

 

 

 

1.3

%

Blocker

 

 

47

 

 

 

11,864

 

 

 

12,146

 

 

 

2.1

%

 

 

12,513

 

 

 

1.2

%

Mansfield

 

 

 

 

 

7,092

 

 

 

7,092

 

 

 

1.2

%

 

 

4,934

 

 

 

0.5

%

Douglass

 

 

 

 

 

3,584

 

 

 

3,584

 

 

 

0.6

%

 

 

2,007

 

 

 

0.2

%

Darco

 

 

8

 

 

 

2,724

 

 

 

2,772

 

 

 

0.5

%

 

 

2,403

 

 

 

0.2

%

Other

 

 

114

 

 

 

10,301

 

 

 

10,988

 

 

 

1.9

%

 

 

11,433

 

 

 

1.0

%

 

 

 

405

 

 

 

341,325

 

 

 

343,758

 

 

 

58.8

%

 

 

278,540

 

 

 

26.4

%

 

South Texas:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Eagleville

 

 

21,324

 

 

 

18,669

 

 

 

146,613

 

 

 

25.1

%

 

 

688,227

 

 

 

65.3

%

Fandango

 

 

 

 

 

45,405

 

 

 

45,405

 

 

 

7.8

%

 

 

32,520

 

 

 

3.1

%

Rosita

 

 

 

 

 

16,283

 

 

 

16,283

 

 

 

2.8

%

 

 

10,315

 

 

 

1.0

%

Javelina

 

 

34

 

 

 

7,552

 

 

 

7,757

 

 

 

1.3

%

 

 

10,497

 

 

 

1.0

%

Las Hermanitas

 

 

 

 

 

5,736

 

 

 

5,736

 

 

 

1.0

%

 

 

5,124

 

 

 

0.5

%

Lopeno

 

 

31

 

 

 

2,298

 

 

 

2,483

 

 

 

0.4

%

 

 

4,624

 

 

 

0.4

%

Other

 

 

113

 

 

 

2,622

 

 

 

3,299

 

 

 

0.5

%

 

 

7,874

 

 

 

0.7

%

 

 

 

21,502

 

 

 

98,565

 

 

 

227,576

 

 

 

38.9

%

 

 

759,181

 

 

 

72.0

%

 

Other:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

 

 

 

 

San Juan Basin

 

 

8

 

 

 

2,796

 

 

 

2,846

 

 

 

0.5

%

 

 

3,720

 

 

 

0.4

%

Other

 

 

61

 

 

 

9,967

 

 

 

10,331

 

 

 

1.8

%

 

 

12,554

 

 

 

1.2

%

 

 

 

69

 

 

 

12,763

 

 

 

13,177

 

 

 

2.3

%

 

 

16,274

 

 

 

1.6

%

Total

 

 

21,976

 

 

 

452,653

 

 

 

584,511

 

 

 

100.0

%

 

 

1,053,995

 

 

 

100.0

%

Discounted Future Income Taxes

 

 

(246,778

)

 

 

 

 

Standardized Measure of Discounted Future Cash Flows

 

$

807,217

 

 

 

 

 

________________

(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 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 the 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 natural gas reserves after income tax, discounted at 10%.

8


 

East Texas/North Louisiana Region

Approximately 59% or 343.8 Bcfe of our proved reserves are located in East Texas and North Louisiana where we own interests in 956 producing wells (584.8 net to us) in 28 field areas. We operate 662 of these wells. The largest of our fields in this region are the Logansport, Toledo Bend, Beckville, Waskom, Blocker, Mansfield, Douglass and Darco fields. Production from this region averaged 128 MMcf of natural gas per day and 175 barrels of oil per day during 2013 or 130 MMcfe per day. Most of the reserves in this area produce from the upper Jurassic aged Haynesville or Bossier shale or Cotton Valley formations and the Cretaceous aged Travis Peak/Hosston formation. In 2013, we spent $16.7 million drilling two wells (2.0 net to us) and $2.3 million on workovers and recompletions in this region. The two wells we drilled in 2013 were Bossier shale horizontal wells. We have not budgeted to drill any wells in this region in 2014.

Logansport

The Logansport field located in DeSoto Parish, Louisiana primarily produces from the Haynesville and Bossier shale formations at a depth of 11,100 to 11,500 feet and from multiple sands in the Cotton Valley and Hosston formations at an average depth of 8,000 feet. Our proved reserves of 232.8 Bcfe in the Logansport field represent approximately 40% of our proved reserves. We own interests in 252 wells (161.9 net to us) and operate 178 of these wells in this field.

Toledo Bend

The Toledo Bend field in DeSoto and Sabine Parishes, Louisiana was discovered in 2008 with our first horizontal Haynesville shale well. Production from the Haynesville shale in the Toledo Bend field ranges from 11,400 to 11,800 feet and from 10,880 to 11,300 feet in the Bossier shale. Our proved reserves of 31.1 Bcfe in the Toledo Bend field represent approximately 5% of our reserves. We own interests in 76 producing wells (39.3 net to us) and operate 41 of these wells in this field. During 2013 we drilled two horizontal wells (2.0 net to us) at Toledo Bend and we completed two wells (0.1 net to us) that were drilled in 2012.

Beckville

The Beckville field, located in Panola and Rusk Counties, Texas, has estimated proved reserves of 30.6 Bcfe which represents approximately 5% of our proved reserves. We operate 191 wells in this field and own interests in 78 additional wells for a total of 269 wells (159.3 net to us). The Beckville field produces primarily from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet. The field is also prospective for future Haynesville shale development.

Waskom

The Waskom field, located in Harrison and Panola Counties in Texas, represents approximately 2% (12.7 Bcfe) of our proved reserves as of December 31, 2013. We own interests in 63 wells in this field (39.8 net to us) and operate 47 wells in this field. The Waskom field produces from the Cotton Valley formation at depths ranging from 9,000 to 10,000 feet and from the Haynesville shale formation at depths of 10,800 to 10,900 feet.

Blocker

Our proved reserves of 12.1 Bcfe in the Blocker field located in Harrison County, Texas represent approximately 2% of our proved reserves. We own interests in 77 wells (71.0 net to us) and operate 71 of these wells. Most of this production is from the Cotton Valley formation between 8,600 and 10,150 feet and the Haynesville shale formation between 11,100 and 11,450 feet.

9


 

Mansfield

The Mansfield field is located in DeSoto Parish, Louisiana and produces from the Haynesville shale between 12,250 and 12,350 feet. We own interests in 17 wells (4.6 net to us) and operate 4 of these wells. Our proved reserves in this field of 7.1 Bcfe represent approximately 1% of our total reserves.

Douglass

The Douglass field is located in Nacogdoches County, Texas and is productive from stratigraphically trapped reservoirs in the Pettet Lime and Travis Peak formations. These reservoirs are found at depths from 9,200 to 10,300 feet. Our proved reserves of 3.6 Bcfe in the Douglass field represent less than 1% of our reserves. We own interests in 40 wells (25.8 net to us) and operate 33 of these wells.

Darco

The Darco field is located in Harrison County, Texas and produces from the Cotton Valley formation at depths from approximately 9,800 to 10,200 feet.  Our proved reserves of 2.8 Bcfe in the Darco field represent less than 1% of our reserves.  We own interests in 23 wells (18 net to us) and operate all of these wells.  

South Texas Region

Approximately 39%, or 37.9 MMBOE (227.6 Bcfe), of our proved reserves are located in South Texas, where we own interests in 240 producing wells (151.7 net to us). We own interests in 13 field areas in the region, the largest of which are the Eagleville, Fandango, Rosita, Javelina, Las Hermanitas and Lopeno fields. Net daily production rates from this region averaged 6,110 barrels of oil and 20 MMcf of natural gas during 2013 or 9,388 BOE per day. We spent $325.0 million in 2013 to drill 75 oil wells (51.6 net to us) targeting the Eagle Ford shale and for other development activity. We also spent $77.2 million in this region in 2013 to acquire acreage, including $67.4 million for 33,624 acres (21,034 net to us) in or near Burleson County, Texas which are prospective in the Eagle Ford shale formation.   We plan to spend approximately $264.0 million in 2014 to drill 59 horizontal wells (40.2 net to us) in our Eagleville field, $50.0 million to drill ten wells (5.6 net to us) in our newly acquired Eagle Ford shale acreage, $80.0 million to complete 18 Eagleville wells (13.3 net to us) that were drilled in 2013 and $25.0 million on facilities, recompletions and other capital projects.

Eagleville

We have 31,755 acres (25,316 net to us) in McMullen, Atascosa, Frio, La Salle, Karnes and Wilson Counties which comprise our Eagleville field. The Eagle Ford shale is found between 7,500 feet and 11,500 feet across our acreage position. At December 31, 2013 we had 101 wells (74.6 net to us) producing in the Eagleville field. Our proved reserves in this field are estimated to be 24.4 MMBOE (146.6 Bcfe) (87% oil) and represent 25% of our total proved reserves. We plan to spend approximately $264.0 million in 2014 to drill 59 horizontal wells (40.2 net to us) and $80.0 million to complete wells that were drilled in 2013 in the Eagleville field.

Fandango

We own interests in 19 wells (19.0 net to us) in the Fandango field located in Zapata County, Texas. We operate all of these wells which produce from the Wilcox formation at depths from approximately 13,000 to 18,000 feet. Our proved reserves of 45.4 Bcfe in this field represent approximately 8% of our total proved reserves.

10


 

Rosita

We own interests in 29 wells (15.7 net to us) in the Rosita field, located in Duval County, Texas. We operate 28 of these wells which produce from the Wilcox formation at depths from approximately 9,300 to 17,000 feet. Our proved reserves of 16.3 Bcfe in this field represent approximately 3% of our total proved reserves.

Javelina

We own interests in and operate 18 wells (18.0 net to us) in the Javelina field in Hidalgo County in South Texas. These wells produce primarily from the Vicksburg formation at a depth of approximately 10,900 to 12,500 feet. Proved reserves attributable to our interests in the Javelina field are 7.8 Bcfe, which represents approximately 1% of our total proved reserves.

Las Hermanitas

We own interests in and operate 11 natural gas wells (11.0 net to us) in the Las Hermanitas field, located in Duval County, Texas. These wells produce from the Wilcox formation at depths from approximately 11,400 to 11,800 feet. Our proved reserves of 5.7 Bcfe in this field represent approximately 1% of our total proved reserves.

Lopeno

The Lopeno Field located in Zapata County, Texas has estimated proved reserves of 2.5 Bcfe which represents less than 1% of our total company proved reserves.  Production is from shallow Queen City sands between 2,200 feet and 2,600 feet and deeper Wilcox sands between 6,400 feet and 12,500 feet.  We own interests in 17 wells (2.7 net to us) and operate one of these wells.  

Other Regions

Approximately 2%, or 13.1 Bcfe, of our proved reserves are in other regions, primarily in New Mexico and the Mid-Continent region. We own interests in 339 producing wells (85.3 net to us) in 15 fields within these regions. The field with the largest proved reserves is our San Juan Basin properties in New Mexico. Net daily production from our other regions during 2013 totaled 5 MMcf of natural gas and 54 barrels of oil or 5 MMcfe per day.

During 2013, we spent $53.3 million to acquire 53,470 acres (51,017 net to us) in Louisiana and Mississippi which are prospective for oil in the Tuscaloosa Marine shale.  We have budgeted $27.0 million in 2014 to drill two wells (1.8 net to us) on this acreage.

San Juan

Our San Juan Basin properties are located in the west-central portion of San Juan County, New Mexico. These wells produce from multiple sands of the Cretaceous Dakota formation and the Fruitland Coal seams. The Dakota is generally found at about 6,000 feet with the shallower Fruitland seams encountered at 2,500 to 3,000 feet. Our proved reserves of 2.8 Bcfe in the San Juan field represent less than 1% of our reserves. We own interests in 92 wells (14.0 net to us) in this field.

Major Property Acquisitions

As a result of our acquisitions of producing oil and gas properties, we have added 1.1 Tcfe of proved oil and natural gas reserves since 1991. Our ten largest acquisitions include the following:

Delaware Basin Acquisition.   In December 2011, we acquired certain oil and gas properties from Eagle Oil & Gas Co. and other third parties for $348.7 million. The properties acquired had estimated

11


 

proved reserves of approximately 151.2 Bcfe and included approximately 65,000 exploratory acres (39,100 net to us). We divested of these properties in May 2013.

Shell Wilcox Acquisition.   In December 2007, we completed the acquisition of certain oil and natural gas properties and related assets from SWEPI LP, an affiliate of Shell Oil Company for $160.1 million. The properties acquired had estimated proved reserves of approximately 70.1 Bcfe. Major fields acquired in the acquisition include the Fandango and Rosita fields.

Javelina Acquisition.   In June 2007, we acquired additional working interests in oil and gas properties in the Javelina field in South Texas from Abaco Operating LLC for $31.2 million. The properties acquired had estimated proved reserves of approximately 9.1 Bcfe.

Denali Acquisition.   In September 2006, we acquired proved and unproved oil and gas properties in the Las Hermanitas field in South Texas from Denali Oil & Gas Partners LP and other working interest owners for $67.2 million. The properties acquired had estimated proved reserves of approximately 16.5 Bcfe.

Ensight Acquisition.   In May 2005, we completed the acquisition of certain oil and natural gas properties and related assets from Ensight Energy Partners, L.P., Laurel Production, LLC, Fairfield Midstream Services, LLC and Ensight Energy Management, LLC (collectively, “Ensight”) for $190.9 million. We also purchased additional interests in those properties from other owners for $10.9 million in July 2005. The properties acquired had estimated proved reserves of approximately 121.5 billion cubic feet of natural gas equivalent and included 312 active wells, of which 119 are operated by us. Major fields acquired include the Darco, Douglass, Cadeville, and Laurel fields. We divested of the Laurel field in 2010.

Ovation Energy Acquisition.   In October 2004, we acquired producing oil and gas properties in the East Texas, Arkoma, Anadarko and San Juan basins from Ovation Energy, L.P. for $62.0 million. The properties acquired had estimated proved reserves of approximately 41.0 billion cubic feet of gas equivalent and included 165 active wells, of which 69 were operated by us.

DevX Energy Acquisition.   In December 2001, we completed the acquisition of DevX Energy, Inc. by acquiring 100% of the common stock of DevX for $92.6 million. The total purchase price including debt and other liabilities assumed in the acquisition was $160.8 million. The acquisition included 600 producing wells located onshore primarily in East and South Texas, Kentucky, Oklahoma and Kansas with 1.2 MMBbls of oil reserves and 156.5 Bcf of natural gas reserves at the time of the acquisition.

Bois d’Arc Acquisition.   In December 1997, Comstock acquired working interests in certain producing offshore Louisiana oil and gas properties as well as interests in undeveloped offshore oil and natural gas leases for approximately $200.9 million from Bois d’Arc Resources and certain of its affiliates and working interest partners. We acquired interests in 43 wells (29.6 net to us) and eight separate production complexes located in the Gulf of Mexico offshore of Plaquemines and Terrebonne Parishes, Louisiana. The acquisition included interests in the Louisiana state and federal offshore areas of Main Pass Block 21, Ship Shoal Blocks 66, 67, 68 and 69 and South Pelto Block 1. The net proved reserves acquired in this acquisition were estimated at 14.3 MMBbls of oil and 29.4 Bcf of natural gas. We divested of these offshore properties in 2008.

Black Stone Acquisition.   In May 1996, we acquired 100% of the capital stock of Black Stone Oil Company and interests in producing and undeveloped oil and gas properties located in South Texas for $100.4 million. We acquired interests in 19 wells (7.7 net to us) that were located in the Double A Wells field in Polk County, Texas and we became the operator of most of the wells in the field. The net proved

12


 

reserves acquired in this acquisition were estimated at 5.9 MMBbls of oil and 100.4 Bcf of natural gas. We divested of these properties in 2012.

Sonat Acquisition.   In July 1995, we purchased interests in certain producing oil and gas properties located in East Texas and North Louisiana from Sonat Inc. for $48.1 million. We acquired interests in 319 producing wells (188.0 net to us). The acquisition included interests in the Logansport, Beckville, Waskom, Hico-Knowles, and Blocker fields. The net proved reserves acquired in this acquisition were estimated at 0.8 MMBbls of oil and 104.7 Bcf of natural gas. We divested of the Hico-Knowles field in 2012.

Oil and Natural Gas Reserves

The following table sets forth our estimated proved oil and natural gas reserves and the PV 10 Value as of December 31, 2013:

 

 

 

Oil
  (MBbls)

 

Natural  
Gas
(MMcf)

 

Total
  (MMcfe)

 

PV 10 Value
(000’s)

 

Proved Developed:

 

 

 

 

 

 

 

 

 

 

Producing

 

10,526

 

290,260

 

353,418

 

$

787,095

 

Non-producing

 

3,388

 

54,018

 

74,346

 

 

188,596

 

Total Proved Developed

 

13,914

 

344,278

 

427,764

 

 

975,691

 

Proved Undeveloped

 

8,062

 

108,375

 

156,747

 

 

78,304

 

Total Proved

 

21,976

 

452,653

 

584,511

 

 

1,053,995

 

Discounted Future Income Taxes

 

 

(246,778

)

Standardized Measure of Discounted Future Net Cash Flows(1)

 

$

807,217

 

 

____________

(1)

The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10%. Although it is a non-GAAP measure, we believe that the presentation of the 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 natural 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:

 

 

 

2011

 

 

2012

 

 

2013

 

 

 

Oil
(MBbls)

 

 

Natural Gas
(MMcf)

 

 

Oil
(MBbls)

 

 

Natural Gas
(MMcf)

 

 

Oil
(MBbls)

 

 

Natural Gas
(MMcf)

 

 

Proved Developed

 

 

6,499

 

 

 

546,627

 

 

 

8,389

 

 

 

362,426

 

 

 

13,914

 

 

 

344,278

 

Proved Undeveloped

 

 

6,735

 

 

 

534,017

 

 

 

10,510

 

 

 

75,019

 

 

 

8,062

 

 

 

108,375

 

Total Proved Reserves

 

 

13,234

 

 

 

1,080,644

 

 

 

18,899

 

 

 

437,445

 

 

 

21,976

 

 

 

452,653

 

 

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, but are not limited to, 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

13


 

revision of such estimate. Accordingly, reserves 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:

 

 

Year Ended December 31,

 

 

2011

 

 

2012

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil Price - $/Bbl

 

$95.73

 

 

 

$101.09

 

 

 

$100.20

 

Natural Gas Price - $/Mcf

 

$3.91

 

 

 

$2.49

 

 

 

$3.38

 

Lifting costs - $/Mcfe

 

$0.82

 

 

 

$0.96

 

 

 

$1.22

 

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)

 

 

 

 

 

 

 

 

 

 

2011

 

 

$94.73

 

 

 

$4.01

 

2012

 

 

$101.75

 

 

 

$2.58

 

2013

 

 

$104.38

 

 

 

$3.37

 

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 December 31, 2013 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. 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, 2013, our proved undeveloped reserves included 8.1 MMBbls of oil and 108.4 Bcf of natural gas, for a total of 157 Bcfe of undeveloped reserves. All of our undeveloped oil reserves   and 5 Bcf of natural gas of our proved undeveloped reserves were associated with our Eagleville properties in South Texas. The proved undeveloped reserves associated with our Haynesville and Bossier shale properties represented approximately 87 Bcf of our proved undeveloped natural gas reserves at December 31, 2013. The remaining proved undeveloped natural gas reserves are primarily associated with developing reserves in our Wilcox and Vicksburg reservoirs in South Texas. In 2013, we focused on drilling oil properties due to the weak natural gas prices. 28 of the Eagle Ford shale wells we drilled in 2013 resulted in conversions of proved undeveloped reserves to proved developed producing reserves at December 31, 2013. Our proved undeveloped oil reserves decreased by 2.4 MMBbls during 2013. This decrease was primarily due to converting 3.0 MMBbls of our proved undeveloped oil reserves to developed in 2013 and new reserves additions of 0.6 MMBbls. Our proved undeveloped natural gas reserves increased by 33 Bcf at December 31, 2013 as compared with December 31, 2012. This increase was primarily related to reserve additions of 36 Bcf of natural gas which were partially offset by undeveloped reserves converted to developed reserves of 3 Bcf.

14


 

As of December 31, 2012, our proved undeveloped reserves included 10.5 MMBbls of oil and 75 Bcf of natural gas, for a total of 138 Bcfe of undeveloped reserves. All of our undeveloped oil reserves and 7 Bcf of natural gas were associated with our Eagleville shale properties in South Texas. The proved undeveloped natural gas reserves associated with our Haynesville and Bossier shale properties represented approximately 55 Bcf of our total natural gas proved undeveloped reserves at December 31, 2012. The remaining proved undeveloped reserves are primarily associated with developing reserves in our Cotton Valley and Hosston sand reservoirs in East Texas/North Louisiana and our Wilcox and Vicksburg reservoirs in South Texas. In 2012, we focused on drilling oil wells due to the weak natural gas prices. Seven of the Eagleville  wells we drilled in 2012 resulted in conversions of proved undeveloped reserves to proved developed producing reserves at December 31, 2012. Our oil proved undeveloped reserves increased by 3.8 MMBbls during 2012. This increase was primarily due to our drilling program which added 8.1 MMBbls in the Eagle Ford shale.  Sales of oil reserves in 2012 of 3.1 MMbls and conversions of proved developed oil reserves of 1.3 MMBbls partially offset the increase from reserve adds.  Our natural gas proved undeveloped reserves decreased by 459 Bcf during 2012. This decrease was primarily related to the decline of natural gas prices which caused 465 Bcf of our natural gas proved undeveloped reserves to become uneconomical under the natural gas prices used to determine proved reserves in 2012.

The following table presents the changes in our estimated proved undeveloped oil and natural gas reserves for the years ended December 31, 2011, 2012 and 2013:

 

 

 

Proved Undeveloped Reserves

 

 

 

2011

 

 

2012

 

 

2013

 

 

  

Oil
(MBbls)

 

  

Natural Gas
(MMcf)

 

 

Oil
(MBbls)

 

 

Natural Gas
(MMcf)

 

 

Oil
(MBbls)

  

 

Natural Gas
(MMcf)

 

Beginning Balance

 

 

1,258

 

 

 

518,824

 

 

 

6,735

 

 

 

534,017

 

 

 

10,510

 

 

 

75,019

 

Sales and Disposals

 

 

 

 

 

 

 

 

(3,143

)

 

 

(16,125

)

 

 

 

 

 

 

Acquisitions

 

 

 

 

 

11,651

 

 

 

 

 

 

 

 

 

 

 

 

 

Extension & Discoveries

 

 

5,151

 

 

 

66,978

 

 

 

8,142

 

 

 

7,007

 

 

 

583

 

 

 

36,578

 

Conversions from undeveloped to developed

 

 

 

 

 

(39,761

)

 

 

(1,341

)

 

 

(1,095

)

 

 

(3,060

)

 

 

(2,930

)

Price, Performance and Other Revisions

 

 

326

 

 

 

(23,675

)

 

 

117

 

 

 

(448,785

)

 

 

29

 

 

 

(292

)

Total Change

 

 

5,477

 

 

 

15,193

 

 

 

3,775

 

 

 

(458,998

)

 

 

(2,448

)

 

 

33,356

 

Ending Balance

 

 

6,735

 

 

 

534,017

 

 

 

10,510

 

 

 

75,019

 

 

 

8,062

 

 

 

108,375

 

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

 

 

 

Proved Undeveloped Reserves

 

 

 

2011

 

 

2012

 

 

2013

 

Year ended December 31,

  

Oil
(MBbls)

 

 

Natural Gas
(MMcf)

 

  

Oil
(MBbls)

 

  

Natural Gas
(MMcf)

 

  

Oil
(MBbls)

  

 

Natural Gas
(MMcf)

 

2012

 

 

4,275

 

 

 

43,084

 

 

 

 

 

 

 

 

 

 

 

 

 

2013

 

 

1,169

 

 

 

256,989

 

 

 

2,205

 

 

 

11,832

 

 

 

 

 

 

 

2014

 

 

1,000

 

 

 

198,903

 

 

 

988

 

 

 

27,581

 

 

 

6,392

 

 

 

4,617

 

2015

 

 

291

 

 

 

35,041

 

 

 

845

 

 

 

17,624

 

 

 

1,328

 

 

 

369

 

2016

 

 

 

 

 

 

 

 

3,933

 

 

 

14,896

 

 

 

342

 

 

 

1,242

 

2017

 

 

 

 

 

 

 

 

2,539

 

 

 

3,086

 

 

 

 

 

 

56,129

 

2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

46,018

 

Total

 

 

6,735

 

 

 

534,017

 

 

 

10,510

 

 

 

75,019

 

 

 

8,062

 

 

 

108,375

 

 

Our estimates of oil and natural gas reserves at December 31, 2013 include 47 Bcfe related to undrilled wells that have positive undiscounted future cash flows but which, based upon oil and natural

15


 

gas prices that we use to prepare the proved reserve estimates, have a rate of return that is less than the 10% discount rate used in the Standardized Measure of Discounted Future Cash Flows attributable to the proved reserve estimates. We intend to drill the proved undeveloped wells in the time frame reflected in the estimates of proved oil and natural gas reserves as of December 31, 2013 based upon the oil and natural gas prices that we used to prepare the reserve estimates. We anticipate drilling such proved undeveloped locations based on our current development plans for our properties. Certain of these wells may be drilled to retain leasehold interests or to properly manage reservoir performance. To the extent that actual oil or natural gas prices are substantially weaker, we may have to modify our development plans or we may not fully recover our investment in drilling these wells from future cash flows.

The following table presents the estimated timing of our estimated future development capital costs to be incurred for the years ended December 31, 2011, 2012 and 2013:

 

 

  

Future Development Costs
Total Proved Undeveloped Reserves

 

Year ended December 31,

  

2011

 

  

2012

 

  

2013

 

 

  

(in millions)

 

 

2012

 

$

240.2

 

 

$

 

 

$

 

2013

 

 

572.3

 

 

 

73.6

 

 

 

 

2014

 

 

452.5

 

 

 

53.3

 

 

 

265.2

 

2015

 

 

85.2

 

 

 

91.8

 

 

 

70.6

 

2016

 

 

 

 

 

130.0

 

 

 

24.1

 

2017

 

 

 

 

 

104.7

 

 

 

98.1

 

2018

 

 

 

 

 

 

 

 

85.2

 

Total

 

$

1,350.2

 

 

$

453.4

 

 

$

543.2

 

 

The following table presents the changes in our estimated future development costs for the years ended December 31, 2012 and 2013:

 

 

 

Haynesville

/Bossier

Shale

 

 

Eagle Ford

Shale

 

 

All Other

Properties

 

 

Total

 

 

 

(in millions)

 

 

Total as of December 31, 2011

 

$

886.1

 

 

$

218.0

 

 

$

246.1

 

 

$

1,350.2

 

 

Development Costs Incurred

 

 

(24.7

)

 

 

(43.4

)

 

 

 

 

 

(68.1

)

Sales and Disposals

 

 

 

 

 

 

 

 

(48.1

)

 

 

(48.1

)

Additions and Revisions

 

 

(777.5

)

 

 

174.2

 

 

 

(177.3

)

 

 

(780.6

)

Total Changes

 

 

(802.2

)

 

 

130.8

 

 

 

(225.4

)

 

 

(896.8

)

Total as of December 31, 2012

 

 

83.9

 

 

 

348.8

 

 

 

20.7

 

 

 

453.4

 

 

Development Costs Incurred

 

 

 

 

 

(105.7

)

 

 

 

 

 

(105.7

)

Additions and Revisions

 

 

68.2

 

 

 

114.5

 

 

 

12.8

 

 

 

195.5

 

Total Changes

 

 

68.2

 

 

 

8.8

 

 

 

12.8

 

 

 

89.8

 

Total as of December 31, 2013

 

$

152.1

 

 

$

357.6

 

 

$

33.5

 

 

$

543.2

 

Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2013 of $543.2 million increased by $89.8 million from our estimated future capital costs of $453.4 million as of December 31, 2012. We incurred approximately $105.7 million during 2013 to develop proved undeveloped reserves, primarily in our Eagle Ford shale properties. Our oil focused future capital expenditures increased by $114.5 million and our natural gas focused capital expenditures increased by $68.2 million.

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Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2012 of $453.4 million decreased by $896.8 million from our estimated future capital costs of $1.4 billion as of December 31, 2011. During 2012, we incurred approximately $43.4 million to develop proved undeveloped reserves in our Eagle Ford shale properties. Our oil focused future capital expenditures increased by $174.2 million and our natural gas focused capital expenditures decreased by $954.8 million. Approximately $749.0 million of the reduction in our estimated future development costs in 2012 was associated with wells that, as of December 31, 2011, had positive undiscounted cash flows but had a rate of return of less than 10%.

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 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 BS Degree and a Masters Degree in Petroleum Engineering, is a Registered Professional Engineer and has over thirty-five 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 years ended December 31, 2011, 2012 or 2013 to any federal authority or agency, other than the SEC.

17


 

Drilling Activity Summary

During the three-year period ended December 31, 2013, we drilled development and exploratory wells as set forth in the table below:

 

 

  

2011

 

 

2012

 

 

2013

 

 

  

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

 

17

 

 

 

16.2

 

 

 

78

 

 

 

51.0

 

 

 

75

 

 

 

51.6

 

Gas

 

 

61

 

 

 

26.6

 

 

 

7

 

 

 

3.2

 

 

 

2

 

 

 

2.0

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

78

 

 

 

42.8

 

 

 

85

 

 

 

54.2

 

 

 

77

 

 

 

53.6

 

Exploratory:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

 

3

 

 

 

3.0

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas

 

 

6

 

 

 

1.9

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9

 

 

 

4.9

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

87

 

 

 

47.7

 

 

 

85

 

 

 

54.2

 

 

 

77

 

 

 

53.6

 

 

In 2014 to the date of this report, we have drilled eleven wells (8.6 net to us) and we have nine wells (6.0 net to us) in the process of being drilled.

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, 2013:

 

 

 

Oil

 

 

Natural Gas

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Arkansas

 

 

 

 

 

 

 

 

15

 

 

 

8.0

 

Kansas

 

 

 

 

 

 

 

 

9

 

 

 

5.0

 

Louisiana

 

 

17

 

 

 

5.4

 

 

 

452

 

 

 

252.4

 

New Mexico

 

 

1

 

 

 

 

 

 

91

 

 

 

14.0

 

Oklahoma

 

 

10

 

 

 

1.2

 

 

 

132

 

 

 

18.5

 

Texas

 

 

121

 

 

 

79.1

 

 

 

661

 

 

 

436.3

 

Wyoming

 

 

 

 

 

 

 

 

26

 

 

 

1.9

 

Total

 

 

149

 

 

 

85.7

 

 

 

1,386

 

 

 

736.1

 

 

We operate 895 of the 1,535 producing wells presented in the above table. As of December 31, 2013, we owned interests in 14 wells containing multiple completions, which means that a well is producing from more than one completed zone. Wells with more than one completion are reflected as one well in the table above.

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Acreage

The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2013, 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

 

Arkansas

 

 

1,280

 

 

 

684

 

 

 

 

 

 

 

Kansas

 

 

6,400

 

 

 

4,064

 

 

 

 

 

 

 

Louisiana

 

 

95,138

 

 

 

60,726

 

 

 

34,699

 

 

 

30,298

 

Mississippi

 

 

 

 

 

 

 

 

34,616

 

 

 

32,455

 

New Mexico

 

 

10,240

 

 

 

1,896

 

 

 

 

 

 

 

Oklahoma

 

 

38,080

 

 

 

5,707

 

 

 

 

 

 

 

Texas

 

 

110,761

 

 

 

68,454

 

 

 

43,044

 

 

 

27,816

 

Wyoming

 

 

13,440

 

 

 

927

 

 

 

 

 

 

 

Total

 

 

275,339

 

 

 

142,458

 

 

 

112,359

 

 

 

90,569

 

Our undeveloped acreage expires as follows:

 

Expires in 2014

 

13

%

Expires in 2015

 

11

%

Expires in 2016

 

15

%

Thereafter

 

61

%

 

 

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 bank credit facility. As is customary in the oil and 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. We anticipate retaining ownership of a substantial amount of the acreage with primary terms expiring in 2014 through drilling activity or by extending the leases.

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 87% of our 2013 natural gas sales were priced utilizing first of the month index prices and approximately 13% were priced utilizing daily spot prices. BP Energy Company and its subsidiaries and Shell Oil Company and its subsidiaries accounted for 51% and 36%, respectively, of our total 2013 sales. The loss of either 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.

19


 

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 certain agreements with a major natural gas marketing company to provide us with firm transportation for 55,000 MMBtus per day for our North Louisiana natural gas production on the long-haul pipelines. These agreements expire from 2015 to 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 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

20


 

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 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.

21


 

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. However, 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. 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 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

22


 

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.

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. On September 23, 2013, 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).  We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. 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 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 2012, EPA issued draft guidance on when UIC permitting requirements apply to fracking fluids containing diesel. We are not able to predict at this time the effect on our operations should EPA impose changes to the UIC permitting program when utilizing diesel as a fracking agent. 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.

23


 

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.

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 (“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. We have determined that these reporting requirements apply to us and we believe we have met all of the EPA required reporting deadlines and strive to ensure accurate and consistent emissions data reporting. Other EPA actions with respect to the reduction of greenhouse gases (such as EPA’s Greenhouse Gas Endangerment Finding, and

24


 

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.

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.

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.

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.

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 $118,934, which escalates to $124,466 beginning August 1, 2014. This lease expires on December 31, 2021. We also own production offices and pipe yard facilities near Marshall, Pleasanton and Zapata, Texas and Logansport, Louisiana.

Employees

As of December 31, 2013, we had 131 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

  

58

Roland O. Burns

  

President, Chief Financial Officer, Secretary and Director

  

53

Mark A. Williams

  

Chief Operating Officer and Vice President of Operations

  

52

Gerry L. Blackshear

  

Vice President of Exploration

  

55

D. Dale Gillette

  

Vice President of Land and General Counsel

  

68

Michael D. McBurney

  

Vice President of Marketing

  

58

Daniel K. Presley

  

Vice President of Accounting, Controller and Treasurer

  

53

Russell W. Romoser

  

Vice President of Reservoir Engineering

  

62

Richard D. Singer

  

Vice President of Financial Reporting

  

59

Blaine M. Stribling

  

Vice President of Corporate Development

  

43

David K. Lockett

  

Director

  

59

Cecil E. Martin

  

Director

  

72

Frederic D. Sewell

  

Director

  

79

David W. Sledge

  

Director

  

57

Nancy E. Underwood

  

Director

  

62

Executive Officers

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

M. Jay Allison has been a director since 1987, and our Chief Executive Officer since 1988. Mr. Allison was elected Chairman of the board of directors in 1997. From 1988 to 2013, Mr. Allison served as our President and before that he served as our Vice President and Secretary. From 1981 to 1987, he was a practicing oil and gas attorney with the firm of Lynch, Chappell & Alsup in Midland, Texas. Mr. Allison was Chairman of the Board of Directors of Bois d’Arc Energy, Inc. from the time of its formation in 2004 until its merger with Stone Energy Corporation in 2008. He received B.B.A., M.S. and J.D. degrees from Baylor University in 1978, 1980 and 1981, respectively. Mr. Allison also currently serves as a Director of Tidewater, Inc. and is 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 was a director, Senior Vice President and the Chief Financial Officer of Bois d’Arc Energy, Inc. from the time of its formation in 2004 until its merger with Stone Energy Corporation in 2008. 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 University of Mississippi Foundation and the Cotton Bowl Athletic Association.

Mark A. Williams has been our Chief Operating Officer since 2012. From 2011 to early 2012, he served as Vice President of Operations. From 2007 to 2011, he served as our Engineering and Operations Manager. From 1996 until 2007, Mr. Williams served as our Drilling Manager and as our South Texas District Engineer. Prior to joining Comstock Mr. Williams was a production engineer at Mitchell Energy Corporation and Citation Oil & Gas. Mr. Williams received a B.S. degree in Petroleum Engineering from Texas A&M University in 1984.

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Gerry L. Blackshear has been our Vice President of Exploration since 2012. From 2007 to early 2012 Mr. Blackshear served as our Geoscience Manager. Prior to joining us, Mr. Blackshear was a lead geologist at Encana Oil & Gas from 2004 to 2007. Prior to 2004 he worked as a senior geologist for several large independent oil and gas exploration and development companies. Mr. Blackshear received a B.S. degree in Geology from East Texas State University in 1981 and is a Certified Petroleum Geologist.

D. Dale Gillette has been our Vice President of Land and General Counsel since 2006. Prior to joining us, Mr. Gillette practiced law extensively in the energy sector for 34 years, most recently as a partner with Gardere Wynne Sewell LLP, and before that with Locke Liddell & Sapp LLP (now known as Locke Lord LLP). During that time he represented independent exploration and production companies and large financial institutions in numerous oil and gas transactions. Mr. Gillette has also served as corporate counsel in the legal department of Mesa Petroleum Co. and in the legal department of Enserch Corp. Mr. Gillette holds B.A. and J.D. degrees from the University of Texas and is a member of the State Bar of Texas.

Michael D. McBurney was named our Vice President of Marketing in July 2013. Mr. McBurney has over 32 years of energy industry experience within the oil, natural gas, LNG, and power segments. For the past seven years 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 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 was named our Treasurer in 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 35 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.

Richard D. Singer has been our Vice President of Financial Reporting since 2005. Mr. Singer has over 35 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 early 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.

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Outside Directors

David K. Lockett has served as a director since 2001. Mr. Lockett was a Vice President with Dell Inc. and held executive management positions in several divisions within Dell from 1991 until his retirement from Dell in 2012. Mr. Lockett, who has over 35 years of experience in the technology industry, is presently providing consulting services to small and mid-size companies. Mr. Lockett was a director of Bois d’Arc Energy, Inc. from May 2005 until its merger with Stone Energy Corporation in August 2008. Mr. Lockett received a B.B.A. degree from Texas A&M University in 1976.

Cecil E. Martin has served as a director since 1989 and is currently the chairman of our audit committee and our Lead Director. Mr. Martin is an independent commercial real estate investor who has primarily been managing his personal real estate investments since 1991. From 1973 to 1991, he also served as chairman of a public accounting firm in Richmond, Virginia. Mr. Martin was a director and chairman of the Audit Committee of Bois d’Arc Energy, Inc. from May 2005 until its merger with Stone Energy Corporation in August 2008. Mr. Martin also serves on the board of directors of Crosstex Energy, Inc. and Crosstex Energy, L.P. and on the Board of Directors and Audit Committee of Garrison Capital, a privately held business development company. Mr. Martin holds a B.B.A. degree from Old Dominion University and is a Certified Public Accountant.

Frederic D. Sewell has served as a director since May 2012. Mr. Sewell has extensive experience in the oil and gas industry, where he has had a distinguished career as an executive leader and a petroleum engineer. Mr. Sewell was the co-founder of Netherland, Sewell & Associates, Inc., a worldwide oil and gas consulting firm, where he served as the chairman and chief executive officer until his retirement in 2008. Mr. Sewell is presently the President and Chief Executive Officer of Sovereign Resources LLC, an exploration and production company that he founded. Mr. Sewell holds a B.S. Degree in Petroleum Engineering from the University of Texas.

David W. Sledge has served as a director since 1996. Mr. Sledge is the Chief Operating Officer of ProPetro Services, Inc. Mr. Sledge was President and Chief Operating Officer of Sledge Drilling Company until it was acquired by Basic Energy Services, Inc. in April 2007 and served as a Vice President of Basic Energy Services, Inc. from April 2007 to February 2009. He served as an area operations manager for Patterson-UTI Energy, Inc. from May 2004 until January 2006. From March 2009 through October 2011, and from October 1996 until May 2004, Mr. Sledge managed his personal investments in oil and gas exploration activities. Mr. Sledge was a director of Bois d’Arc Energy, Inc. from May 2005 until its merger with Stone Energy Corporation in August 2008. Mr. Sledge is a past director of the International Association of Drilling Contractors and is a past chairman of the Permian Basin chapter of this association. He received a B.B.A. degree from Baylor University in 1979.

Nancy E. Underwood has served as a director since 2004. Ms. Underwood is owner and President of Underwood Financial Ltd., a position she has held since 1986. Ms. Underwood holds B.S. and J.D. degrees from Emory University and practiced law at an Atlanta, Georgia based law firm before joining River Hill Development Corporation in 1981. Ms. Underwood currently serves on the Executive Board and Campaign Steering Committee of the Southern Methodist University Dedman School of Law and on the Board of Directors of Texas Health Presbyterian Foundation.

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 public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference

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Room by calling the SEC at 1-800-SEC-0330. In addition, 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.

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition, cash flow, liquidity or results of operations and our ability to meet our capital expenditure obligations and financial commitments and to implement our business strategy.

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. Prices for oil remained strong in 2013, and our realized natural gas prices increased by 36% in 2013 to $3.38 per Mcf. However natural gas prices by historical standards remain low.  

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

·

the domestic and foreign supply of oil 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.

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We pursue acquisitions as part of our growth strategy and there are risks in connection with 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 an assessment, 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, Louisiana and Mississippi, we may pursue acquisitions or properties located in other geographic areas.

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, however, 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 and that has what our geoscientists believe, based on available seismic and geological information, to be an indication of

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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 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 future success will depend 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;

·