10-K 1 cpe-20141231x10k.htm 10-K 20141231 10K

 

 

 

 

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

 

 

 

 

FORM 10-K

 

 

 

 

 

 

 

ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For The Fiscal Year Ended December 31, 2014

OR

TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________ to ____________

Commission File Number 001-14039

 

 

 

 

 

 

 

 

Callon Petroleum Company

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

 

 

 

 

 

 

 

 

Delaware

(State or Other Jurisdiction of

Incorporation or Organization)

 

64-0844345

(IRS Employer

Identification No.)

200 North Canal Street

Natchez, Mississippi

(Address of Principal Executive Offices)

 

39120

(Zip Code)

601-442-1601

(Registrant’s Telephone Number, Including Area Code)

 

 

 

 

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

 

Title of Each Class

 

Name of Each Exchange on Which Registered

Common Stock, $.01 par value

 

New York Stock Exchange

10.0% Series A Cumulative Preferred Stock

 

New York Stock Exchange

 

Securities registered pursuant to section 12 (g) of the Act: None

 

 

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.      Yes       No  

Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.      Yes       No  

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.      Yes       No  

Indicate by check mark whether the registrant has submitted electronically 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       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 registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     

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

 

 

 

 

 

Large accelerated filer

 

Accelerated filer

 

 

 

 

 

Non-accelerated filer

(Do not check if smaller reporting company)

Smaller reporting company

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).      Yes       No  

Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2014 was approximately $456.3 million. The Registrant had 55,510,729 shares of common stock outstanding  as of  February 27, 2015.  

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2014) relating to the Annual Meeting of Stockholders to be held on May 14, 2015, which are incorporated into Part III of this Form 10-K.

 

 


 

 

 

 

 

 

Table of Contents

 

TABLE OF CONTENTS

 

 

 

 

 

 

Special Note Regarding Forward-Looking Statements 

Definitions 

Part I 

 

 

 

Items 1 and 2. 

Business and Properties

 

 

Acquisitions and Divestitures

69

 

 

Oil and Natural Gas Properties

7

 

 

Reserves and Production

10

 

 

Production Wells and Leasehold Acreage

14

 

 

Other

16

 

 

Regulations

17

 

 

Available Information

17

Item 1A. 

Risk Factors

25 

Item 1B. 

Unresolved Staff Comments

37 

Item 3. 

Legal Proceedings

37 

Item 4. 

Mine Safety Disclosures

37 

Part II 

 

 

 

Item 5. 

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

38 

 

 

Performance Graph

39 

Item 6. 

Selected Financial Data

40 

Item 7. 

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

41 

 

 

Overview and Outlook

41

 

 

Liquidity and Capital Resources

43

 

 

Results of Operations

46

 

 

Significant Accounting Policies and Critical Accounting Estimates

53

 

 

Subsequent Events

55

Item 7A. 

Quantitative and Qualitative Disclosures About Market Risk

56 

Item 8. 

Financial Statements and Supplementary Data

58 

 

Report of Independent Registered Public Accounting Firm

59 

 

 

Consolidated Balance Sheets 

60 

 

 

Consolidated Statements of Operations

61 

 

 

Consolidated Statements of Comprehensive Income

62 

 

 

Consolidated Statements of Stockholders’ Equity

63 

 

 

Consolidated Statements of Cash Flows

64 

 

 

Notes to Consolidated Financial Statements

65 

Item 9. 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

89 

Item 9A. 

Controls and Procedures

89 

Item 9B. 

Other Information

89 

 

 

Report of Independent Registered Public Accounting Firm

90 

Part III 

 

 

 

Item 10. 

Directors and Executive Officers and Corporate Governance

91 

Item 11. 

Executive Compensation

91 

Item 12. 

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

91 

Item 13. 

Certain Relationships and Related Transactions and Director Independence

91 

Item 14. 

Principal Accountant Fees and Services

91 

Part IV 

 

 

 

Item 15. 

Exhibits

92 

Signatures 

 

 

95 

 

 

 

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Special Note Regarding Forward Looking Statements

 

All statements, other than statements of historical fact, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve quantities, present value and growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance.

 

Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10-K identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.

 

You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

 

·

the timing and extent of changes in market conditions and prices for oil, natural gas and NGLs (including regional basis differentials),

·

our ability to transport our production to the most favorable markets or at all,

·

the timing and extent of our success in discovering, developing, producing and estimating reserves,

·

our ability to fund our planned capital investments,

·

the impact of government regulation, including regulation of endangered species, any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over-the-counter derivatives,

·

the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services,

·

our future property acquisition or divestiture activities,

·

the effects of weather,

·

increased competition,

·

the financial impact of accounting regulations and critical accounting policies,

·

the comparative cost of alternative fuels,

·

conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed,

·

credit risk relating to the risk of loss as a result of non-performance by our counterparties, and

·

any other factors listed in the reports we have filed and may file with the SEC.

 

We caution you that the forward-looking statements contained in this Form 10-K are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2014 (the “2014 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto.

 

Should one or more of the risks or uncertainties described above or in our 2014 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

 

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

 

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DEFINITIONS

 

All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document:

 

·

AROasset retirement obligation.

·

Bbl or Bbls: barrel or barrels of oil or natural gas liquids.

·

Bcf: Billion cubic feet of natural gas.

·

BOE: barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.

·

BBtu: billion Btu.

·

BOE/d: BOE per day.

·

BLM: Bureau of Land Management.

·

Btu: a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

·

DOI: Department of Interior.

·

EPA: Environmental Protection Agency.

·

FASB: Financial Accounting Standards Board.

·

GAAP: Generally Accepted Accounting Principles in the United States.

·

GHG: greenhouse gases.

·

LIBOR: London Interbank Offered Rate.

·

LOE: lease operating expense, including workover expense.

·

MBbls: thousand barrels of oil.

·

MBOE: thousand BOE.

·

MBOE/d: Mboe per day.

·

Mcf: thousand cubic feet of natural gas.

·

MMBbls: million barrels of oil.

·

MMBOE: million BOE.

·

MMBtu: million Btu.

·

MMcf: million cubic feet of natural gas.

·

MMcf/d: MMcf per day.

·

NGL or NGLs: natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.

·

NYMEX: New York Mercantile Exchange.

·

Oil: includes crude oil and condensate.

·

PDPs: proved developed producing reserves.

·

PDNPs: proved developed non-producing reserves.

·

PUDs: proved undeveloped reserves.

·

RSU: restricted stock units.

·

SEC: United States Securities and Exchange Commission.

 

With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.

 

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PART I.

Items 1 and 2 – Business and Properties

 

Overview

 

Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. 

 

In 2013, we completed our onshore strategic repositioning that began in 2009, shifting our operations from the offshore waters in the Gulf of Mexico to the onshore Permian Basin in West Texas. Our asset base is concentrated exclusively in the Midland Basin, a sub-basin located within the broader Permian Basin, characterized by high drilling success rates, high oil content, multiple vertical and horizontal productive intervals, and extensive production history. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.

 

Our net daily production for calendar year 2014 was 5,648 BOE/d (approximately 82% oil), representing an approximately 155% increase over comparable net daily Permian production in 2013. The increase is primarily attributed to our increased focus on horizontal development initiated in 2012. We currently operate two horizontal drilling rigs focused on four prospective zones for development.

 

As of December 31, 2014, we had estimated net proved reserves of 25.7 MMBbls and 42.5 Bcf, or 32.8 MMBOE, all of which were located in the Midland Basin. Additionally, 78% of our proved reserves were crude oil and 55% were proved developed at year-end 2014 on a BOE basis.

 

Our Business Strategy

 

Our goal is to enhance stockholder value through the execution of the following strategy:

 

Drive production and maximize resource recovery and reserve growth through horizontal development of our resource base. We believe our horizontal development efforts provide improved returns relative to vertical development of our resource base. Our initial vertical development programs allowed us to amass a database related to the subsurface geology and rock characteristics over the last several years. This information, combined with our review of industry activity and best practices, provided the foundation for us to initiate the horizontal development of our resource base in 2012 and further increase horizontal activity in recent quarters. As of December 31, 2014, we had 49 gross producing horizontal wells, all of which we operate. During the fourth quarter of 2014, approximately 70% of our total Permian production was sourced from horizontal wells. We expect to grow the contribution of horizontal production volumes, both from our existing properties and from properties acquired in recent acquisitions, as we continue to execute a resource development program almost exclusively focused on horizontal development.

 

Expand our drilling portfolio through evaluation of existing acreage. Our horizontal development drilling efforts to date have been primarily focused on the Upper and Lower Wolfcamp B zones. We have focused on these development zones to reduce drilling risk as we continue to grow our asset base in the Permian Basin, though we have continued to expand our development focus on a measured basis. Most recently, we drilled three Lower Spraberry wells in the Southern and Central Midland Basin in the second half of 2014, complementing three Wolfcamp A wells placed on production in the Southern Midland Basin since the third quarter of 2013. We believe incremental opportunities exist to selectively target other prospective zones across various positions of our acreage, including the Clearfork, Jo Mill, Middle Spraberry, Wolfcamp C and Cline formations (in order of relative depth). In addition, we will continue to monitor the efficiency of our horizontal wells related to reservoir drainage over time, and will pursue downspacing initiatives within target zones if we believe overall returns would be enhanced.

 

Pursue selective acquisitions in the Permian Basin. During 2014, we continued to demonstrate our ability to acquire and trade acreage in the Midland Basin. Most significantly, we acquired 6,230 gross  (3,862 net) acres located in Midland and Andrews Counties, which are in close proximity to our existing Carpe Diem and Pecan Acres fields, for approximately $210 million. Due to its close proximity to our existing fields, we believe this acquired acreage can be efficiently integrated into our ongoing horizontal development activity. The acquisition added 194 gross (121.6 net) potential horizontal drilling locations targeting the currently producing Wolcamp B, Lower Spraberry and Middle Spraberry zones, and additional potential horizontal drilling locations targeting four other prospective zones that are producing in offsetting fields. We also expanded our asset base in existing core development

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fields by acquiring 1,527 net acres for approximately $8.2 million through a “bolt-on” strategy whereby we identify and pursue smaller blocks of offsetting acreage that are potentially inefficient for the current owner to develop, but have value to Callon based on its location relative to our acreage. These smaller scale acquisitions generally provide acreage at costs significantly below the value assigned to larger blocks of acreage. While remaining mindful about our liquidity, we will continue to pursue leasehold acquisitions in the Permian Basin, and primarily in the Midland Basin, that have horizontal resource potential that can be further augmented by “bolt-on acreage” acquisitions and acreage trades over time.

 

Maintain financial liquidity and capacity to capitalize on growth opportunities. We believe that our asset base provides the opportunity to deploy a significant amount of capital for horizontal development in the coming years. We have focused on positioning ourselves to supplement our cash flow from operations with an improved cost of debt capital. In conjunction with our acquisition completed in the fourth quarter of 2014, we raised approximately $430 million in gross proceeds through a combination of common equity and long-term debt securities to support the acquisition and our ongoing development efforts in the Midland Basin.

 

Our Strengths

 

Established resource base and acreage position in the Permian Basin.  Our production is exclusively from the Permian Basin in West Texas, an area that has supported production since the 1940s. The basin has well-established infrastructure from historical operations, and we believe the Basin also benefits from a relatively stable regulatory environment that has been established over time. We have assembled a position of approximately 18,065 net surface acres in the Southern and Central Midland Basin that are prospective for multiple oil-bearing intervals that have been produced by us and other industry participants. As of December 31, 2014,  our estimated net proved reserves were comprised of approximately 78% oil and 22% natural gas, which includes NGLs in the production stream.

 

Multi-year drilling inventory.  Our current acreage position in the Permian Basin provides visible growth potential from a horizontal drilling inventory of approximately 525 locations, or 20 years under our current two-rig horizontal drilling program, based solely on four currently producing zones, which include the Lower Spraberry, the Wolfcamp A and the Upper and Lower Wolfcamp B. This drilling inventory increases to over 1,000 drilling locations, with the addition of drilling locations from other prospective zones, which include the Clearfork, Middle Spraberry, Jo Mill, Wolfcamp C and the Cline (or Wolfcamp D). Our identified well locations across our Southern and Central Midland Basin acreage are based upon the results of horizontal wells drilled by us and other offsetting operators, and our analysis of core data and historical vertical well performance.

 

Experienced team operating in the Permian Basin. We have assembled a management team experienced in acquisitions, exploration, development and production in the Midland Basin. Reflective of this experience, we have realized improvements in our drilling and capital efficiency since launching our horizontal drilling program in 2012 and drilling more than 50 horizontal wells with lengths varying from approximately 5,000 feet to 10,000 feet. We continue to evaluate our completion techniques, and downspacing initiatives that we believe have the potential to improve resource recovery and contribute to enhanced returns on capital. In addition, we regularly evaluate our operating results against those of other operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices.

 

High degree of operational control.  We operate nearly all of our Permian Basin acreage and have limited continuous drilling requirements across our acreage. For example, only 10% of our planned development drilling activity in 2015 is required to satisfy acreage commitments, with decreasing obligations in future years. This acreage status, combined with our control as an operator across the majority of our properties, provides us the opportunity to modify our operational plans to respond to changes in operational and commodity price environments. In addition, we have the ability to change our drilling schedule as needed to manage the assimilation of newly acquired acreage that may have drilling commitments.

 

Operating culture focused on safety and the environment.  We have a Health, Safety and Environmental (“HSE”) department dedicated to our operations in the Permian Basin. This group is responsible for developing and implementing work processes to mitigate safety and environmental risks associated with our work activities. With emphasis on planning, training and communication, and empowering both our employees and third party service providers with Stop Work Authority, we continue to improve operational performance. Callon has enhanced Management of Change, routine inspections and compliance action tracking methods with the implementation of a HSE management system software program. This department also coordinates closely with our operational team to ensure effective communication with appropriate regulatory bodies as well as landowners. We believe that our proactive efforts in this area have made a positive impact on our operations and culture.

 

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Exploration and Development Activities

 

Our 2014 total capital expenditures, including acquisitions, were $455.5 million, representing a 166% increase over 2013 capital expenditures. Of the $455.5 million, $217.7 million was allocated to drilling, development and leasehold acquisition activity in the Permian Basin. During 2014,  we drilled 27 gross  (24.4 net) horizontal and 7 gross  (4.3 net) vertical wells, while completing 31 gross  (27.3 net) horizontal and 5 gross  (3.1 net) vertical wells. Capital expenditures for 2014 included the following expenditures (in millions):

 

 

 

 

 

Southern Midland Basin

 

$

160.3 

Central Midland Basin

 

 

56.9 

Northern Midland Basin

 

 

0.5 

  Total operational expenditures

 

 

217.7 

 

 

 

 

Capitalized general and administrative costs allocated directly to exploration and development projects

 

 

12.5 

Capitalized interest

 

 

2.4 

  Total capitalized general and administrative and interest costs

 

 

14.9 

 

 

 

 

Total operational expenditures inclusive of capitalized general and administrative and interest costs

 

 

232.6 

 

 

 

 

Acquisitions

 

 

222.9 

  Total capital expenditures

 

$

455.5 

 

In late 2014, we expanded our horizontal pad development efforts to six fields. We expect our 2015 horizontal drilling program will be primarily focused on development of established Upper and Lower Wolfcamp zones in the Southern and Central Midland Basin. We also expect to drill five wells in the Southern and Central Midland Basin targeting the Lower Spraberry shale formation and one well targeting the Wolfcamp A shale formation.

 

Recent Developments

 

We are currently operating two horizontal drilling rigs, complemented by an additional vertical rig that is being used to drill the vertical section of horizontal wells. Based on current commodity market conditions, the Company has elected to release the vertical rig in mid-March and focus on a two-rig horizontal program for the balance of 2015.

 

Oil and Natural Gas Properties

 

As of December 31, 2014, our estimated net proved reserves totaled 32.8 MMBOE and included 25.7 MMBbls of oil and 42.5 Bcf, of natural gas with a pre-tax present value, discounted at 10%, of $629.7 million. Pre-tax present value is a non-GAAP financial measure, which we reconcile to the GAAP measure of standardized measure of $579.5 million in note (d) to the table below. Oil constituted approximately 78% of our total estimated equivalent net proved reserves and approximately 77% of our total estimated equivalent proved developed reserves.

 

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The following table sets forth certain information about our estimated net proved reserves prepared by our independent petroleum reserve engineers by major area and for all other properties combined at December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pre-tax
Discounted

 

 

Estimated Net Proved Reserves

 

Present

 

 

 

Oil
(MBbls)

 

 

Natural Gas
(MMcf)

 

 

Total
(MBoe)

 

 

Value
($000)

 

 

 

 

 

 

 

 

 

(a)

 

 

(b)(c)(d)

Southern Midland Basin

 

 

16,973 

 

 

26,102 

 

 

21,323 

 

$

416,463 

Central Midland Basin

 

 

8,736 

 

 

16,337 

 

 

11,459 

 

 

219,286 

Northern Midland Basin

 

 

24 

 

 

109 

 

 

42 

 

 

803 

Other

 

 

 

 

 

 

 

 

(6,872)

  Total

 

 

25,733 

 

 

42,548 

 

 

32,824 

 

$

629,680 

(a)

We convert Mcf to BOE using a conversion ratio of six Mcf to one Bbl. This ratio, which is typical in the industry and represents the approximate energy equivalent of a Mcf to a Bbl, does not reflect to market price equivalence of Mcf of natural gas compared with a Bbl of oil or NGLs. On a market price equivalence basis, a barrel of oil or NGLs has a substantially higher price than six Mcf of natural gas.

(b)

Represents the present value of future net cash flows before deduction of federal income taxes, discounted at 10%, attributable to estimated net proved reserves as of December 31, 2014, as set forth in the Company’s reserve reports prepared by its independent petroleum reserve engineers, DeGolyer and MacNaughton.

(c)

Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2014, in accordance with accounting for asset retirement obligations rules. These obligations were retained following the sale of our offshore operations. The negative Pre-Tax Discounted Present Value of the “Other” reflects plugging and abandonment obligations exceeding the future net cash flows.

(d)

The Company uses the financial measure “Pre Tax Discounted Present Value” which is a non-GAAP financial measure. The Company believes that Pre Tax Discounted Present Value, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The total standardized measure calculated in accordance with the guidance issued by the FASB for disclosures about oil and gas producing activities for our proved reserves as of December 31, 2014 was $579.5 million inclusive of the $50.1 million discounted estimated future income taxes relating to such future net revenues. The projected per Mcf natural gas price of $6.38 used in the 2014 reserve estimates has been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected per barrel oil price of $86.30 used in the 2014 reserve estimates has been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.

 

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Permian Basin

 

As of December 31, 2014, we owned leaseholds in 27,366 net acres in the Permian Basin. Average net production from the Company’s Permian Basin properties increased 155% to 5,648  BOE/d in 2014 from 2,227 BOE/d in 2013.  

 

Southern Midland Basin

 

·

Counties (fields)

o

Upton (East Bloxom and Opal)

o

Reagan (Taylor Draw and Garrison Draw)

o

Crockett (Block 5)

·

10,790 net acres as of December 31, 2014

·

59 gross  (54 net) vertical and 39 gross  (36 net) horizontal producing wells as of December 31, 2014

·

Initiated horizontal development in 2012

·

4th quarter 2014 net production: 4,519 BOE/d  (90% horizontal)

 

The Southern Midland Basin is our largest operating area in terms of production. We  currently have 10,790 net acres in this area. We commenced horizontal drilling efforts at our East Bloxom field in 2012 and have expanded our efforts to two additional fields in the Southern Midland Basin using pad development. Our horizontal wells are currently producing from three zones of the Wolfcamp shale (Upper Wolfcamp B, Lower Wolfcamp B and Wolfcamp A). We plan to continue focusing on these intervals in 2015 and also place our first Lower Spraberry well on production in the first quarter of 2015.

 

Central Midland Basin 

 

·

Counties (fields)

o

Midland (Carpe Diem, Pecan Acres, Casselman and Bohannon)

o

Ector (Kayleigh and Bohannon)

o

Andrews  (Bohannon)

o

Martin (Casselman)

·

7,275 net acres as of December 31, 2014

·

218 gross (144 net) vertical and 11 gross (8 net) horizontal producing wells as of December 31, 2014

·

Initiated horizontal development in 2013

·

4th quarter 2014 net production: 2,736 BOE/d

 

The Central Midland Basin has historically been the focus of our high-graded vertical drilling program, targeting multiple zones down to the Woodford shale. We shifted our focus to horizontal development in this area with our initial Wolfcamp B wells placed on production in the first quarter of 2014 in our Carpe Diem field. We have continued with program development of both the Wolfcamp B and Lower Spraberry zones in this field over the course of the year and are currently expanding our horizontal development to the Pecan Acres field. Importantly, we recently completed our last vertical well in the area and have no plans or obligations to drill any future vertical wells within our Permian Basin property base.  

 

In addition to this organic drilling activity, in October 2014 we acquired 6,230 gross  (3,862 net) acres located in Midland, Andrews and Martin Counties, which are in close proximity to our existing Carpe Diem and Pecan Acres fields. Since the closing of the acquisition, we have placed two Wolfcamp B and one Lower Spraberry wells on production.

 

Northern Midland Basin

 

We acquired 21,617 net acres in Borden and Lynn Counties in 2012. We currently own 9,301 net acres following our decision to allow acreage in the Northern Midland Basin to expire as we refined our targeted areas for exploration. At this time, we have no plans for future activity and anticipate that our Northern Midland Basin acreage will expire in its entirety by 2016. As such, we reclassed approximately $25 million of the carrying value of our Northern Midland acreage that were classified as unevaluated properties to evaluated properties. We have no PUDs attributable to this acreage. At December 31, 2014, we had one gross (one net) producing vertical well in this area.

 

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For additional details regarding our Permian wells and related information, please see “Present Activities and Productive Wells” included below within this Item.

 

Other Property

 

We own a leasehold in 37,326 net acres located in various counties in Nevada. These leases are with the Bureau of Land Management and carry primary terms that expire in 2018 and 2019. We are evaluating this acreage in conjunction with a third-party consultant and developing options for future activity. Callon does not have any drilling commitments related to this acreage during the primary term. However, we reclassed approximately $3 million of the carrying value of our Nevada acreage that were classified as unevaluated properties to evaluated properties. We have no PUDs or drilling commitments attributable to this acreage. We own additional immaterial properties in Louisiana.

 

Proved Reserves 

 

Estimates of volumes of proved reserves at year-end, net to our interest, are presented in MBbls for oil and in MMcf for natural gas, including NGLs, at a pressure base of 15.025 pounds per square inch. Total equivalent volumes are presented in BOE. For the BOE computation, 6,000 cubic feet of gas are the equivalent of one barrel of oil. The ratio of six Mcf of gas to one BOE is typically used in the oil and gas business and represents the approximate energy equivalent of a barrel of oil and a Mcf of natural gas. The price of a barrel of oil is much higher than the price of six Mcf of natural gas, so the ratio of six Mcf to one BOE does not reflect the economic equivalent of a barrel of oil to six Mcf of gas.

 

The following table sets forth certain information about our estimated net proved reserves.  All of our proved reserves are currently located in the continental United States and also included volumes in federal and state waters in the Gulf of Mexico at year-end 2012.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31,

 

 

 

2014 (a)

 

 

2013 (a)

 

 

2012 (a)

Proved developed

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

14,006 

 

 

5,960 

 

 

4,955 

Natural gas (MMcf)

 

 

25,171 

 

 

9,059 

 

 

10,680 

  MBOE

 

 

18,201 

 

 

7,470 

 

 

6,735 

Proved undeveloped

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

11,727 

 

 

5,938 

 

 

5,825 

Natural gas (MMcf)

 

 

17,377 

 

 

8,692 

 

 

9,073 

  MBOE

 

 

14,623 

 

 

7,387 

 

 

7,337 

Total proved

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

25,733 

 

 

11,898 

 

 

10,780 

Natural gas (MMcf)

 

 

42,548 

 

 

17,751 

 

 

19,753 

  MBOE

 

 

32,824 

 

 

14,857 

 

 

14,072 

Financial Information

 

 

 

 

 

 

 

 

 

Estimated pre-tax future net cash flows (b)

 

$

1,330,628 

 

$

680,627 

 

$

592,424 

Pre-tax discounted present value (b) (c)

 

$

629,680 

 

$

301,144 

 

$

250,097 

Standardized measure of discounted future net cash flows (b) (c)

 

$

579,542 

 

$

283,946 

 

$

231,148 

(a)

The Company’s estimated proved reserves as of December 31, 2014 were prepared by DeGolyer and MacNaughton and estimated proved reserves as of December 31, 2013 and 2012 were prepared by Huddleston & Co.

(b)

Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2014 and 2013,  in accordance with accounting for asset retirement obligations rules.

(c)

The Company uses the financial measure “pre-tax discounted present value” which is a non-GAAP financial measure. The Company believes that pre-tax discounted present value, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The total standardized measure calculated in accordance with the guidance issued by the FASB for disclosures about oil and gas producing activities for our proved reserves as of December 31, 2014 was $579.5 million inclusive of the $50.1 million discounted estimated future income taxes relating to such future net revenues. The projected per Mcf natural gas price of $6.38 used in the 2014 reserve estimates has been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected per barrel oil price of $86.30 used in the 2014 reserve estimates

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has been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.

 

See Note 13 of our Consolidated Financial Statements for the additional information regarding the Company’s reserves including its estimates of proved reserves, PDPs, PUDs and the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves.

 

The Company’s estimated net proved reserves increased 121% to 32.8 MBOE from 14.9 MBOE at December 31, 2014 and 2013, respectively. Additions during the year were due to (1) 15.7 MMBOE related to the Company’s horizontal development of a portion of its Permian Basin properties and (2) 4.7 MMBOE related to acquired properties in the Permian Basin. These increases were partially offset by (1) 2.1 MMBOE related to the Company’s production during 2014 and (2) 0.3 MMBOE of net revisions, including 0.8 MMBOE of positive performance-related revisions that were offset by 1.1 MMBOE of PUD reclassifications.

 

Proved Undeveloped Reserves (PUDs)

 

Annually, the Company reviews its PUDs to ensure appropriate plans exist for development. PUD reserves are recorded only if the Company has plans to convert these reserves into PDPs within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our 2015 capital budget and, in subsequent years, the allocation of capital within our long-range business plan to convert PUDs to PDPs within this five year period. In general, our 2015 capital budget and our long-range capital plans are primarily governed by our expectations of internally generated cash flow and credit facility borrowing availability. Reserve calculations at any end-of-year period are representative of our development plans at that time. Changes in commodity pricing, oilfield service costs and availability, and other economic factors may lead to changes in development plans.

 

The following table summarizes the Company’s recorded PUDs (in MBOE):

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31,

 

 

2014

 

2013

 

2012

Permian Basin

 

14,623 

 

7,387 

 

6,040 

Medusa (a)

 

 

 

1,297 

  Total

 

14,623 

 

7,387 

 

7,337 

(a)

Effective July 1, 2013, we sold our interest in the Medusa field. See Note 3 for additional information.

 

Our PUDs increased 98% to 14.6 MMBOE from 7.4 MMBOE at December 31, 2014  and 2013, respectively. We added 10.1 MMBOE to our PUDs, net of revisions, primarily from the continued horizontal development of our Permian Basin properties. The increase in PUDs was partially offset by the reclassification of 1.8 MMBOE, or 24%, included in the year-end 2013 PUD reserves, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $34.6 million, net. Also offsetting the increase was the removal of 1.1 MMBOE of PUDs, including the impact from the reclassification of previous vertical PUDs to the horizontal probable category given our focus on horizontal development. 

 

The Company plans to develop its PUDs as part of a multi-year drilling program. At December 31, 2014, we had no reserves that remained undeveloped for five or more years, and all PUD drilling locations are currently scheduled to be drilled within three to five years of their initial recording.

 

Controls Over Reserve Estimates

 

Compliance as it relates to reporting the Company’s reserves is the responsibility of our Senior Vice President of Operations, who has over 35 years of industry experience including 27 years as a manager and is our principal engineer.  In addition to his years of experience, our principal engineer holds a degree in petroleum engineering and is experienced in asset evaluation and management.

 

Callon’s controls over reserve estimates included retaining DeGolyer and MacNaughton, a Texas registered engineering firm, as our independent petroleum and geological firm. The Company provided to DeGolyer and MacNaughton information about our oil and gas properties, including production profiles, prices and costs, and DeGolyer and MacNaughton prepared its own estimates of the reserves attributable to the Company’s properties. All of the information regarding 2014 reserves in this annual report is derived from DeGolyer and MacNaughton’s report. DeGolyer and MacNaughton’s reserve report letter is included as an Exhibit to this annual

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report. The principal engineer at DeGolyer and MacNaughton who certified the Company’s reserve estimates has over 40 years of experience in the oil and gas industry and is a Texas Licensed Professional Engineer. Further professional qualifications include a degree in petroleum engineering and membership in the International Society of Petroleum Engineers and the American Association of Petroleum Geologists.

 

All of the information regarding 2013 and 2012 reserves in this annual report is derived from reserve reports prepared by Huddleston & Co., Inc., a Texas engineering firm. 

 

To further enhance the control environment over the reserve estimation process, our Strategic Planning Committee, a committee of the Board of Directors, assists management and the Board with its oversight of the integrity of the determination of the Company’s oil and natural gas reserves and the work of our independent reserve engineer.  The Committee’s charter also specifies that the Committee shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities:

 

·

Oversee the appointment, qualification, independence, compensation and retention of the independent petroleum and geological firm (the “Firm”) engaged by the Company (including resolution of material disagreements between management and the Firm regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Committee shall review any proposed changes in the appointment of the Firm, determine the reasons for such proposal, and whether there have been any disputes between the Firm and management.

 

·

Review the Company’s significant reserves engineering principles and policies and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure.

 

·

Review with management and the Firm the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii) reviewing key assumptions used or relied upon by the Firm; (iii) evaluating the quality of the reserve estimates prepared by both the Firm and the Company relative to the Company’s peers in the industry; and (iv) reviewing any  material  reserves adjustments  and significant differences between  the  Company’s  and Firm’s estimates.

 

·

If the Committee deems it necessary, it shall meet in executive session with management and the Firm to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves.

 

During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of total proved net oil and natural gas reserves.

 

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Production Volumes, Average Sales Prices and Operating Costs

 

The following table sets forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, the Company’s sale of oil and natural gas for the periods indicated (dollars in thousands, except per unit data).

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31,

 

 

2014

 

2013

 

2012

Production

 

 

Oil (MBbl)

 

 

1,692 

 

 

911 

 

 

977 

Natural gas (MMcf)

 

 

2,220 

 

 

3,011 

 

 

3,588 

  Total (MBoe)

 

 

2,062 

 

 

1,413 

 

 

1,575 

Revenues

 

 

 

 

 

 

 

 

 

Oil sales

 

$

139,374 

 

$

88,960 

 

$

96,584 

Natural gas sales

 

 

12,488 

 

 

13,609 

 

 

14,149 

  Total

 

$

151,862 

 

$

102,569 

 

$

110,733 

Operating costs

 

 

 

 

 

 

 

 

 

Lease operating expense

 

$

22,372 

 

$

19,779 

 

$

23,330 

Production taxes

 

 

8,973 

 

 

4,133 

 

 

3,224 

  Total

 

$

31,345 

 

$

23,912 

 

$

26,554 

Average realized sales price

 

 

 

 

 

 

 

 

 

Oil (Bbl) (excluding impact of cash settled derivatives)

 

$

82.37 

 

$

97.65 

 

$

97.41 

Oil (Bbl) (including impact of cash settled derivatives)

 

 

84.85 

 

 

99.32 

 

 

98.86 

Natural gas (Mcf) (excluding impact of cash settled derivatives)

 

 

5.63 

 

 

4.52 

 

 

3.94 

Natural gas (Mcf) (including impact of cash settled derivatives)

 

 

5.59 

 

 

4.47 

 

 

3.94 

  Total (BOE) (excluding impact of cash settled derivatives)

 

 

73.65 

 

 

72.59 

 

 

69.43 

  Total (BOE) (including impact of cash settled derivatives)

 

 

75.64 

 

 

73.56 

 

 

70.41 

Operating costs per BOE

 

 

 

 

 

 

 

 

 

Lease operating expense

 

$

10.85 

 

$

14.00 

 

$

14.81 

Production taxes

 

 

4.35 

 

 

2.92 

 

 

2.05 

  Total

 

$

15.20 

 

$

16.92 

 

$

16.86 

 

 

 

 

 

 

 

 

 

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Present Activities and Productive Wells

 

The following table sets forth the wells drilled and completed during the periods indicated. All such wells were drilled in the continental United States.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Drilled

 

Completed (a)

 

Awaiting Completion

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

Southern Midland Basin

 

 

 

 

 

 

 

 

 

 

 

 

Vertical wells

 

 

1.0 

 

 

1.0 

 

 

Horizontal wells

 

22 

 

20.1 

 

22 

 

20.1 

 

 

3.0 

  Total

 

23 

 

21.1 

 

23 

 

21.1 

 

 

3.0 

Central Midland Basin

 

 

 

 

 

 

 

 

 

 

 

 

Vertical wells

 

 

1.8 

 

 

1.3 

 

 

0.4 

Horizontal wells

 

 

4.3 

 

 

7.2 

 

 

  Total

 

 

6.1 

 

12 

 

8.5 

 

 

0.4 

Northern Midland Basin

 

 

 

 

 

 

 

 

 

 

 

 

Vertical wells

 

 

1.5 

 

 

0.8 

 

 

  Total

 

 

1.5 

 

 

0.8 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total vertical wells

 

 

4.3 

 

 

3.1 

 

 

0.4 

Total horizontal wells

 

27 

 

24.4 

 

31 

 

27.3 

 

 

3.0 

  Total

 

34 

 

28.7 

 

36 

 

30.4 

 

 

3.4 

(a)

Completions include wells drilled prior to 2014.

 

The following table sets forth the Company’s drilled and completed wells, none of which were natural gas or nonproductive for the periods reflected: 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014 (a)

 

2013

 

2012

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

Oil wells

 

 

 

 

 

 

 

 

 

 

 

 

Development

 

19 

 

15.5 

 

19 

 

17.2 

 

14 

 

9.7 

Exploratory

 

13 

 

11.7 

 

 

5.0 

 

 

6.2 

  Total

 

32 

 

27.2 

 

26 

 

22.2 

 

21 

 

15.9 

 

(a)

Does not include two gross (two net) non-producing exploratory wells.

 

The following table sets forth productive wells as of  December 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

Oil Wells

 

Natural Gas Wells

 

 

Gross

 

Net

 

Gross

 

Net

Working interest

 

328 

 

243.0 

 

 

Royalty interest

 

 

0.1 

 

 

  Total

 

331 

 

243.1 

 

 

 

A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both oil and natural gas.

 

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For the periods presented, the following table sets forth by major field(s) net production volumes and percentage of estimated proved reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31,

 

 

Production Volumes (MBOE)

 

% of Total Proved Reserves

 

 

2014

 

2013

 

2012

 

2014

 

2013

 

2012

Permian Basin:

 

 

 

 

 

 

 

 

 

 

 

 

Southern Midland Basin

 

1,497 

 

612 

 

402 

 

65% 

 

85% 

 

51% 

Central Midland Basin

 

549 

 

193 

 

189 

 

35% 

 

14% 

 

16% 

Northern Midland Basin

 

16 

 

 

 

0% 

 

1% 

 

0% 

  Total

 

2,062 

 

813 

 

591 

 

100% 

 

100% 

 

67% 

 

 

 

 

 

 

 

 

 

 

 

 

 

Offshore and other (a)

 

 

600 

 

984 

 

0% 

 

0% 

 

33% 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Total

 

2,062 

 

1,413 

 

1,575 

 

100% 

 

100% 

 

100% 

(a)

In late 2013, we sold the remaining interests in our producing offshore fields and in the Haynesville shale.

 

Leasehold Acreage

 

The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2014.  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed

 

Undeveloped

 

Total

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

Louisiana

 

936 

 

200 

 

188 

 

55 

 

1,124 

 

255 

Texas (a)

 

20,991 

 

16,487 

 

12,498 

 

10,879 

 

33,489 

 

27,366 

Federal onshore (b)

 

 

 

37,626 

 

37,326 

 

37,626 

 

37,326 

  Total

 

21,927 

 

16,687 

 

50,312 

 

48,260 

 

72,239 

 

64,947 

(a)

A portion of our Texas acreage requires continuous drilling to hold the acreage for which we have included in our development plans, though the cost to renew this acreage, if necessary, is not considered material.

(b)

The Company’s lease of this acreage, located in Nevada, expires in 2018 and 2019. The lease requires no drilling activity to hold the acreage, and we continue to evaluate our position and monitor the activity of other operators conducting drilling in the area. 

 

Undeveloped Acreage Expirations

 

The following table sets forth by geographic area as of  December 31, 2014 the number of our leased gross and net undeveloped acres that will expire over the next three years unless production begins before lease expiration dates. Gross amounts may be more than net amounts in a particular year due to timing of expirations.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net

 

Gross

 

 

2015

 

2016

 

2017

 

Total

 

 

Texas

 

 

 

 

 

 

 

 

 

 

Southern Permian Basin

 

165 

 

 

 

165 

 

165 

Central Permian Basin

 

 

 

 

 

Northern Permian Basin (a)

 

7,307 

 

648 

 

 

7,955 

 

10,575 

Nevada (b)

 

 

 

 

 

  Total

 

7,472 

 

648 

 

 

8,120 

 

10,740 

 

(a)

7,916 of the total remaining net acres include extension options that would allow us to extend the primary term for a period of two years. 

(b)

The Company’s lease of this acreage does not expire until 2018 and 2019.

 

The expiring acreage set forth in the table above accounts for 17% of our net undeveloped acreage  (48,260 total net acres) and there are no PUD reserves attributable to such acreage. We are continually engaged in a combination of drilling and development and discussions with mineral lessors for lease extensions, renewals, new drilling and development units and new leases to address any potential expiration of undeveloped acreage that occurs in the normal course of our business.

 

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Title to Properties

 

The Company believes that the title to its oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. The Company’s properties are potentially subject to one or more of the following:

 

·

royalties and other burdens and obligations, express or implied, under oil and natural gas leases;

·

overriding royalties and other burdens created by us or our predecessors in title;

·

a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements; farm-out agreements, production sales contracts and other agreements that may affect the properties or their titles;

·

back-ins and reversionary interests existing under purchase agreements and leasehold assignments;

·

liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements;

·

pooling, unitization and communitization agreements, declarations and orders; and

·

easements, restrictions, rights-of-way and other matters that commonly affect property.

 

To the extent that such burdens and obligations affect the Company’s rights to production revenues, these characteristics have been taken into account in calculating Callon’s net revenue interests and in estimating the size and value of its reserves.  The Company believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon.

 

Insurance

 

In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. While not all inclusive, the Company’s insurance policies include coverage for general liability insuring onshore operations (including sudden and accidental pollution), aviation liability, auto liability, worker’s compensation, and employer’s liability. The company carries control of well insurance for only those onshore operations that it is contractually bound to do so. At the depths and in the areas in which the Company operates, and in light of the vertical and horizontal drilling that it undertakes, the Company typically does not encounter high pressures or extreme drilling conditions onshore.

 

Currently, the Company has general liability insurance coverage up to $1 million per occurrence and $2 million per policy in the aggregate, which includes sudden and accidental pollution liability coverage for the effects of pollution on third parties arising from its operations. The Company’s insurance policies contain high policy limits, and in most cases, deductibles (generally ranging from $0 to $250,000) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. The Company maintains up to $100 million in excess liability coverage, which is in addition to and triggered if the underlying liability limits have been reached. In addition, the company purchases pollution legal liability coverage in the amount of $5  million, which is excess and difference in conditions of the liability coverage.

 

The Company requires all of its third-party contractors to sign master service agreements in which they agree to indemnify the Company for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company and the Company’s other contractors. Additionally, each party generally is responsible for damage to its own property.

 

The third-party contractors that perform hydraulic fracturing operations for the Company sign master service agreements generally containing the indemnification provisions noted above. The Company does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, the Company believes its general liability and excess liability insurance policies would cover foreseeable third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies.

 

The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company’s risk analysis, it believes that it is properly insured, no assurance can be given that the Company will be able to maintain insurance in the

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future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.

 

Major Customers

 

Our production is sold generally on month-to-month contracts at prevailing prices. The following table identifies customers to whom we sold a significant percentage of our total oil and natural gas production, on an equivalent basis, during each of the 12-month periods indicated:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31,

 

2014

 

2013

 

2012

Enterprise Crude Oil, LLC

 

51% 

 

38% 

 

32% 

Plains Marketing, L.P.

 

22% 

 

15% 

 

15% 

Sunoco

 

10% 

 

0% 

 

0% 

Shell Trading Company

 

0% 

 

31% 

 

39% 

Other

 

17% 

 

16% 

 

14% 

  Total

 

100% 

 

100% 

 

100% 

 

Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on Callon’s ability to market future oil and natural gas production. We are not currently committed to provide a fixed and determinable quantity of oil or gas in the near future under our contracts.

 

Corporate Offices

 

The Company’s headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned space. We also maintain leased business offices in Houston and Midland, Texas. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures.

 

Employees

 

Callon had 109 employees as of December 31, 2014. None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees.

 

Regulations

 

General.    Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for amendment and/or expansion. Some of these requirements carry substantial penalties for failure to comply.

 

Exploration and Production.  Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are:

 

·

the location and spacing of wells;

·

the method of drilling and completing and operating wells;

·

the rate and method of production;

·

the surface use and restoration of properties upon which wells are drilled and other exploration activities;

·

notice to surface owners and other third parties;

·

the venting or flaring of natural gas;

·

the plugging and abandoning of wells;

·

the discharge of contaminants into water and the emission of contaminants into air;

·

the disposal of fluids used or other wastes obtained in connection with operations;

·

the marketing, transportation and reporting of production; and

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·

the valuation and payment of royalties.

 

Operations conducted on federal or state oil and natural gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Department of the Interior (“DOI”) Bureaus or other appropriate federal or state agencies.

 

Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity.

 

Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. The industry historically has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.

 

We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position.

 

Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”) issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Further, the EPA has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for 2014-2016 and, as a general matter, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. Although such laws and regulations can increase the cost of planning, designing, installing and operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace.

 

Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in

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Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

 

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes.

 

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

 

Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum.  We may also be the owner or operator of sites on which hazardous substances have been released.  To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages.

 

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

 

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands), as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit the discharge of dredge or fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities.

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Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

 

The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

 

Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.

 

Air Emissions. The federal Clean Air Act, as amended, and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on April 17, 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “Regulation of Hydraulic Fracturing.” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

 

Greenhouse Gas (GHG) Regulation. More stringent laws and regulations relating to climate change and GHGs may be adopted in the future and could cause us to incur material expenses in complying with them.  In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.

 

The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount of GHGs that can be emitted, they could require us to incur significant costs to monitor, keep records of, and potentially report GHG emissions associated with our operations if the reporting threshold is reached with production growth.  The EPA recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations.  Those measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and gas production sources and natural gas processing and transmission sources.

 

In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs.  These potential regional and state initiatives may result in so-called “Cap-and-Trade programs”, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, such as by being required to purchase or to surrender allowances for GHGs resulting from our operations.  These federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

 

Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”), regulates the underground injection of substances through the Underground Injection Control (“UIC”), program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing

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activities (except where diesel is a component of the fracturing fluid, as further discussed below). Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing have been proposed in recent sessions of Congress but have not passed.

 

The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA has commenced a study of the potential impacts of hydraulic fracturing activities on drinking water resources. The EPA has announced that it plans to propose standards in 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

 

The EPA has adopted regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards for hydraulically fractured natural gas wells to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured gas wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA may issue revised rules that are likely responsive to some of these requests. If revised, these rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. In addition, the U.S. Department of the Interior published a revised proposed rule that would update existing regulation for hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. EPA has announced that it is considering regulations under the Toxic Substance Control Act to require evaluation and disclosure of hydraulic fracturing.

 

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, most notably the EPA’s study on the environmental impacts of hydraulic fracturing, the final results of which are not yet available.. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities.

 

Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.

 

Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some case impose a moratorium on hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water.  Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could

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adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

 

Surface Damage Statutes (“SDAs”).  In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments to the operator in connection with exploration and operating activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

 

National Environmental Policy Act and Endangered Species Act.  Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

 

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If the Company were to have a portion of its leases designated as critical or suitable habitat or a protected species were located on a lease, it may adversely impact the value of the affected leases.

 

Mineral Leasing Act of 1920 (“Mineral Act”)The Mineral Act prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign corporation except through stock ownership in a corporation formed under the laws of the United States or of any U.S. state or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or corporations of the United States. If these restrictions are violated, the oil and gas  lease or leases can be canceled in a proceeding instituted by the United States Attorney General.  Although the regulations of the Bureau of Land Management (“BLM”) (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. The Company owns an interest in federal leaseholds in Nevada. It is possible that holders of the Company’s equity interests may be citizens of foreign countries, which could be determined to be citizens of a non-reciprocal country under the Mineral Act. In such event, the federal onshore oil and gas leases held by the Company could be subject to cancellation based on such determination.

 

Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

 

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern

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the rates and other terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

 

Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate, oil and natural gas liquids are not currently regulated and are made at market prices.

 

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

·

the location of wells;

·

the method of drilling and casing wells;

·

the timing of construction or drilling activities, including seasonal wildlife closures;

·

the rates of production or “allowables”;

·

the surface use and restoration of properties upon which wells are drilled;

·

the plugging and abandoning of wells; and

·

notice to, and consultation with, surface owners and other third parties.

 

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.

 

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

 

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

 

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all

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purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

 

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.

 

The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.  The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet.  In August 2011, the PHMSA issued an Advance Notice of Proposed Rulemaking regarding pipeline safety, including questions regarding the modification of regulations applicable to gathering lines in rural areas.

 

Oil and NGLs Sales and Transportation. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

 

The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

 

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

 

Any transportation of the Company’s crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.

 

State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

 

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The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

 

Commitments and Contingencies

 

The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from the Company’s operations could have on its activities. See Note 14 for additional information.

 

Available Information

 

We make available free of charge on our Internet web site (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like Callon, that file electronically with the SEC.

 

We also make available within the Investors section of our Internet web site our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation and Nominating and Governance Committee Charters, which have been approved by our board of directors. We will make timely disclosure by a Current Report on Form 8-K and on our web site of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: Chief Financial Officer, Callon Petroleum Company, P.O. Box 1287, Natchez, MS 39121.

 

Item 1A.  Risk Factors

 

Risk Factors

 

Depressed oil and natural gas prices may adversely affect our results of operations and financial condition.   Our success is highly dependent on prices for oil and natural gas, which are extremely volatile, and the oil and natural gas markets are cyclical. Approximately 80% of our anticipated 2015 production, on a BOE basis, is oil. Starting in the second half of 2014, the NYMEX price for a barrel of oil has fallen sharply, from a price of $105.37 on June 30, 2014 to $49.76 on February 27, 2015. In addition, NYMEX prices for natural gas have been low compared with historical prices. Extended periods of low prices for oil or natural gas will have a material adverse effect on us. The prices of oil and natural gas depend on factors we cannot control such as weather, economic conditions, and levels of production, actions by OPEC and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business:

 

·

our revenues, cash flows and earnings;

·

the amount of oil and natural gas that we are economically able to produce;

·

our ability to attract capital to finance our operations and the cost of the capital;

·

the amount we are allowed to borrow under our credit facilities;

·

the profit or loss we incur in exploring for and developing our reserves; and

·

the value of our oil and natural gas properties.

 

Any substantial and extended decline in the price of oil or natural gas could have an adverse effect on our borrowing capacity, our ability to obtain additional capital, and our revenues, profitability and cash flows.

 

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If oil and natural gas prices remain depressed for extended periods of time, we may be required to take additional write-downs of the carrying value of our oil and natural gas properties.  We may be required to write-down the carrying value of our oil and natural gas properties when oil and natural gas prices are low. Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and natural gas properties exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. Because the oil price we are required to use to estimate our future net cash flows is the average price over the 12 months prior to the date of determination of future net cash flows, the full effect of falling prices may not be reflected in our estimated net cash flows for several quarters. We review the carrying value of our properties quarterly and once incurred, a write-down of oil and natural gas properties is not reversible at a later date, even if prices increase. See Note 13 to our Consolidated Financial Statements.

 

Our actual recovery of reserves may substantially differ from our proved reserve estimates and our proved reserve estimates may change over time.  This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. In addition, drilling, testing and production data acquired since the date of an estimate may justify revising an estimate.

 

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates.  Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report.  Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas.  We incorporate many factors and assumptions into our estimates including:

 

·

Expected reservoir characteristics based on geological, geophysical and engineering assessments;

·

Future production rates;

·

Future oil and natural gas prices and quality and locational differences; and

·

Future development and operating costs.

 

You should not assume that any present value of future net cash flows from our estimated net proved reserves contained in this Form 10-K represents the market value of our oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2014 on average 12-month prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. At December 31, 2014, approximately 25% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented 45% of total proved reserves by volume. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these undeveloped reserves and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general.

 

Information about reserves constitutes forward-looking information. See “Forward-Looking Statements” for information regarding forward-looking information.

 

Unless we replace our oil and gas reserves, our reserves and production will decline.    Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is

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reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves.

 

Exploring for, developing, or acquiring reserves is capital intensive and uncertain.  We may not be able to economically find, develop, or acquire additional reserves, or may not be able to make the necessary capital investments to develop our reserves, if our cash flows from operations decline or external sources of capital become limited or unavailable. As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures, currently expected to be in excess of three times the cost, as compared to the drilling of a traditional vertical well. If we do not replace the reserves we produce, our reserves revenues and cash flow will decrease over time, which will have an adverse effect on our business.

 

Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all.  Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings under our credit facility and public debt and equity financings. In 2014, our total capital expenditures, including expenditures for leasehold interests and property acquisitions, drilling, seismic and infrastructure, were approximately $455.5 million. Our 2015 capital budget for drilling, completion and infrastructure is estimated to be approximately $150 to $165 million. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.

 

If the borrowing base under our revolving credit facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations.

 

Our revolving credit facility and second lien term loan facility contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.    Our credit facilities restrictive covenants that limit our ability to, among other things:

 

·

incur additional indebtedness;

·

create additional liens;

·

sell assets;

·

merge or consolidate with another entity;

·

pay dividends or make other distributions;

·

engage in transactions with affiliates; and

·

enter into certain swap agreements.

 

In addition, we will be required to use substantial portions of our future cash flow to repay principal and interest on our indebtedness. Our credit facilities require us to maintain certain financial ratios and tests, including a minimum asset value coverage ratio of total debt. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

 

Our borrowings under our revolving credit facility and second lien term loan facility expose us to interest rate risk.  Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.75% to 2.75% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. Our second lien term loan bears interest at a

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rate of LIBOR,  subject to a floor of 1%, plus 7.50%. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

 

The borrowing base under our revolving credit facility may be reduced below the amount of borrowings outstanding under such facilities. Under the terms of our revolving credit facility, our borrowing base is subject to redeterminations at least semi-annually based in part on prevailing oil and gas prices. A negative adjustment could occur if the estimates of future prices used by the banks in calculating the borrowing base are significantly lower than those used in the last redetermination. The next redetermination of our borrowing base is scheduled to occur on or about March 31, 2015. In addition, the portion of our borrowing base made available to us is subject to the terms and covenants of the revolving credit facility including, without limitation, compliance with the financial performance covenants of such facility. In the event the amount outstanding under our revolving credit facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess or (ii) repay such excess borrowings over five monthly installments.   We may not have sufficient funds to make any required repayment.  If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our revolving credit facility.

 

The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.  From time to time, our industry has experiences a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies or qualified personnel can materially and adversely affect our operations and profitability.

 

Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner.  Water is an essential component of our drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local landowners and other sources for use in our operations. During the last few years, West Texas has experienced extreme drought conditions. As a result of the severe drought, some local water districts may begin restricting the use of water under their jurisdiction for drilling and hydraulic fracturing to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, NGLs and natural gas, which could have an adverse effect on our business, financial condition and results of operations.

 

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.  All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

 

Our exploration projects increase the risks inherent in our oil and natural gas activities. We may seek to replace reserves through exploration, where the risks are greater than in acquisitions and development drilling. Our exploration drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

·

the results of our exploration drilling activities;

·

receipt of additional seismic data or other geophysical data or the reprocessing of existing data;

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·

material changes in oil or natural gas prices;

·

the costs and availability of drilling rigs;

·

the success or failure of wells drilled in similar formations or which would use the same production facilities;

·

availability and cost of capital;

·

changes in the estimates of the costs to drill or complete wells; and

·

changes to governmental regulations.

 

Delays in exploration, cost overruns or unsuccessful drilling results could have a material adverse effect on our business and future growth.

 

Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns.  Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive deposits will not be discovered. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return.

 

In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including:

 

·

unexpected drilling conditions;

·

pressure or irregularities in formations;

·

equipment failures or accidents and shortages or delays in the availability of drilling rigs and the delivery of equipment; and

·

compliance with governmental requirements.

 

Failure to conduct our oil and gas operations in a profitable manner may result in write-downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows.

 

Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling.  Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.

 

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Approximately 45% of our total estimated proved reserves as of December 31, 2014, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

 

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We may be unable to integrate successfully the operations of future acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions.  Our business may include producing property acquisitions that would include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions successfully could adversely affect our financial condition and results of operations.  Our acquisitions may involve numerous risks, including:

 

·

operating a larger combined organization and adding operations;

·

difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area;

·

risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;

·

loss of significant key employees from the acquired business:

·

diversion of management’s attention from other business concerns;

·

failure to realize expected profitability or growth;

·

failure to realize expected synergies and cost savings;

·

coordinating geographically disparate organizations, systems and facilities; and

·

coordinating or consolidating corporate and administrative functions.

 

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition.  If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisition and current operations, which in turn, could negatively impact our results of operations.

 

We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.  We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating and capital costs and potential environmental and other liabilities. Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.

 

Unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our ability to conduct business.  There are many operating hazards in exploring for and producing oil and natural gas, including:

 

·

our drilling operations may encounter unexpected formations or pressures, which could cause damage to equipment or personal injury;

·

we may experience equipment failures which curtail or stop production;

·

we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other corrective action to be taken;

·

storms and other extreme weather conditions could cause damages to our production facilities or wells.

 

Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas-leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures.

 

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If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations.  We could also incur substantial losses in excess of our insurance coverage as a result of:

 

·

injury or loss of life;

·

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

·

pollution and other environmental damage;

·

clean-up responsibilities;

·

regulatory investigation and penalties;

·

suspension of our operations; and

·

repairs to resume operations.

 

We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations.

 

Factors beyond our control affect our ability to market production and our financial results.  The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. These factors could negatively affect our ability to market all of the oil or natural gas we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce. These factors include:

 

·

the extent of domestic production and imports of oil and natural gas;

·

federal regulations generally prohibiting the export of U.S. crude oil;

·

federal regulations applicable to exports of liquefied natural gas (LNG);

·

the proximity of hydrocarbon production to pipelines;

·

the availability of pipeline capacity;

·