UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON,Washington, D.C. 20549
Form 10-K
for the year ended
December 31, 2012
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[X] | Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2012, or |
[ ] | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from____ to____ | |
Commission File Number 001-14039
CALLON PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
ýANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
OR
¨ TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-14039
Callon Petroleum Company
(Exact Name of Registrant as Specified in Its Charter) |
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Delaware (State or other jurisdictionOther Jurisdiction of incorporation Incorporation or organization)Organization) | | 64-0844345 (I.R.S.IRS Employer Identification No.) |
200 North Canal Street Natchez, Mississippi (Address of principal executive offices)Principal Executive Offices) | | 39120 (Zip Code) |
601-442-1601
(Registrant's telephone number, including area code)Registrant’s Telephone Number, Including Area Code): 601-442-1601
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| Securities registered pursuant to Section 12(b) of the Act: |
Title of each class:Each Class | | Name of each exchangeEach Exchange on which registered: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 ý
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 ý
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 ýNo ¨
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).
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):
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Large accelerated filer [ ]
| Accelerated filer [ X ]
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Non-accelerated filer [ ]
| Smaller reporting company [ ]
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Large accelerated filer ¨Accelerated filer ýNon-accelerated filer ¨ 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 The aggregateAggregate market value of the voting and non-voting common equity stock held by non-affiliates of the registrant was $162.0 millionas of June 30, 20122013 was approximately $129.6 million.
As of March 8, 201310, 2014, 39,870,13640,465,227 shares of the Registrant’s common stock, par value $.01 per share, were outstanding.
Documents Incorporated by ReferenceDOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 20122013) relating to the Annual Meeting of Stockholders to be held on May 16, 201315, 2014, which are incorporated into Part III of this Form 10-K.
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| Special Note Regarding Forward-Looking Statements | |
| Definitions | |
| Part I | |
| Items 1 and 2. | | |
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| Part II | | | |
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| Part III | | | |
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| Part IV | | | |
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Special Note Regarding Forward Looking Statements
All statements, other than historical fact or present financial information, 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. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.
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-K10-Q 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 commodities (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 respond to low natural gas prices,
our ability to fund our planned capital investments,
the impact of government regulation, including 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 Securities and Exchange Commission (“SEC”).Commission.
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, 20122013 and all quarterly reports on Form 10-Q filed subsequently thereto (“Form 10-Qs”).thereto.
Should one or more of the risks or uncertainties described above or elsewhere in this 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.
DEFINITIONS
All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. As used in this document:
ARO: Asset Retirement Obligation.
Bbl or Bbls: barrel or barrels of oil or natural gas liquids.
BoeBOE: 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.
Boe/BOE/d: BoeBOE per day.
BLM: Bureau of Land Management.
BOEM: Bureau of Ocean Energy Management, Regulation and Enforcement; formerly the Minerals Management Service ("MMS").Service.
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.
BSEE: Bureau of Safety and Environmental Enforcement.
DOI: Department of Interior.
EPA: Environmental Protection Agency.
LIBOR: London Interbank Offered Rate.
MbblsLOE: lease operating expense.
MBbls: thousand barrels of oil.
Mboe/MBOE/d: Mboe per day.
Mcf: thousand cubic feet of natural gas.
Mcfe: thousand cubic feet of natural gas equivalents.
MMbblsMMBbls: million barrels of oil.
MMboeMMBOE: million boe.BOE.
MMcf: million cubic feet of natural gas.
MMS: Minerals Management Service.
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.
OCS: outer continental shelf.
Oiloil: includes crude oil and condensate.
ONRR: Office of Natural Resources Revenue.
PDPs: proved developed producing reserves.
PDNPs: proved developed non-producing reserves.
PUDs: proved undeveloped reserves.
Reserve life:RSU a measurement of the time it will take to produce our proved reserves calculated by dividing our estimate net equivalent reserves at December 31, 2012 by our total production during 2012 on an equivalent basis.: restricted stock units.
SEC: United States Securities and Exchange Commission.
US GAAP: Generally Accepted Accounting Principles in the United States
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.
PART I.
Items 1 and 2 - Business and Properties
Overview and Business Strategy
Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. 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.
In 2009,2013, the Company completed its onshore strategic repositioning that began to shiftin 2009, shifting its operational focusoperations from exploration, development and productionthe offshore waters in the Gulf of Mexico to the acquisition and development of onshore, properties. Currently, our onshore properties located in the Permian Basin in Texas areTexas. In the foundationfourth quarter of 2013, the Company sold its interest in its only remaining deepwater property, the Medusa field, in addition to the sale of the Medusa spar facility and substantially all remaining offshore shelf properties. Previously, Callon sold its interest in its deepwater Habanero field in the fourth quarter of 2012. Collectively, these transactions completed the Company’s transition to an onshore operator with an asset base concentrated exclusively in the Midland Basin, a sub-basin contained in the broader Permian Basin.
Callon exited 2013 with average Permian production in the month of December of 3,611 BOE/d (approximately 84% oil), a 129% increase over our onshore strategy.exit rate in 2012. We believe that the Company’s transition to a horizontal development program, which was expanded from two fields to four fields in late 2013, has improved Callon’s overall capital efficiency and has contributed to a net increase of 59% in the Company’s Permian proven reserve base.
The Company operates 100% of its Permian acreage, which provides additional flexibility to modify development plans to address potential changes in the operating and commodity price environments. As of December 31, 20122013, we had estimated net proved reserves of 10.8 MMbbls11.9 MMBbls and 19.817.8 Bcf, or 14.1 MMboe. Of these reserves and on an MMboe basis, approximately 68%14.9 MMBOE, all of which were located onshore in the Permian Basin, compared with approximately 61%67% located onshorein the Permian Basin at December 31, 20112012. Additionally,77% 80% of our proved reserve volumesreserves were crude oil and 50% were proved developed at year-end 20122013 compared to 63%at year-end 2011., on a BOE basis.
Our Business Strategy
Our goal is to increaseenhance stockholder value by:through the execution of the following strategy:
ContinuingDrive production and reserve growth through horizontal development of our resource base.Our initial drilling efforts in the Permian Basin targeted the development of multiple zones with vertical wells as part of the “Wolfberry” play. As part of this drilling program, we amassed a database related to buildthe subsurface geology and rock characteristics over the last several years. This information, combined with our onshorereview of industry activity and best practices, provided the foundation for Callon to initiate the horizontal development of our resource base in 2012. Importantly, we believe horizontal development of our resource base will provide the opportunity to improve returns relative to vertical drilling by accessing a larger base of reserves in target zone with a lateral wellbore. During the fourth quarter of 2013, approximately 44% of our total Permian production base through:was sourced from horizontal wells. We expect the contribution of horizontal production volumes from our existing properties to increase with the recent expansion of our horizontal development efforts to four fields as part of our current two-rig drilling program.
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◦ | conversion of our existing Permian acreage position to production |
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◦ | leveraging our technical and operational teams across a larger production base |
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◦ | pursuing opportunistic producing property and leasehold acquisitions |
FocusingExpand our drilling portfolio through evaluation of existing acreage. Our horizontal development drilling efforts to date have been primarily focused on capitalthe Upper and Lower Wolfcamp B shales, establishing production from both zones in the Southern Midland Basin. We have been focused on these development zones to reduce drilling risk as we continue to grow our asset base in the Permian Basin. We believe additional opportunities exist to selectively target various other prospective zones including the Jo-Mill, Lower Spraberry, Wolfcamp A, Wolfcamp C and Cline formations, and plan to selectively drill potential identified locations to complement our core development efforts in the Wolfcamp B. Moreover, we will monitor the efficiency through:of our horizontal wells related to reservoir drainage over time and pursue downspacing initiatives within target zones if overall returns can be enhanced. We recently transitioned to closer spacing of our horizontal laterals in the Southern Midland Basin in both the Upper and Lower Wolfcamp B shales.
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◦ | exploiting Permian resources through repeatable program drilling |
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◦ | continuing to invest in supporting infrastructure |
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◦ | high-grading of capital allocation across our expanded drilling portfolio continuing to refine our vertical and horizontal completion techniques and target zones |
DeliveringOutside of our core development areas in the Southern and Central Midland Basin, we maintain an exploration position in the Northern Midland Basin. Our current activity in the Northern Midland Basin is limited to vertical drilling in order to assess resource potential and economic returns. If our exploration concept is proven to economically produce hydrocarbons on asset growth potential through:a repeatable basis from vertical wells, we will then determine whether the testing of horizontal development concepts is warranted.
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◦ | focusing on an established production base from vertical Wolfberry wells |
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◦ | the drilling inventory of horizontal locations identified in 2012 from our evaluation efforts in the southern Midland basin from horizontal locations developed in 2012 |
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◦ | exploration activities on our acreage in the northern Midland basin |
Capitalize on opportunities to further reduce cost of capital. Following the disposition of our offshore properties, we have the opportunity to recapitalize the Company with a lower cost of capital commensurate with an improved credit risk profile as a purely onshore operator. As part of an ongoing effort to reduce our cost of capital, we have redeemed nearly $90 million of our 13% Senior Notes due 2016 (the “Senior Notes”) since 2011 and recently called for the redemption of the remaining $49 million of principal to occur in April 2014, replacing these Senior Notes with lower cost financing. Additionally, we believe the demonstrated growth in our proved developed reserve base provides the foundation for a meaningful expansion of our borrowing base capacity under our revolving credit agreement. We recently increased the notional amount and reduced the interest expense related to our revolving credit agreement, evidencing another step in reducing our overall cost of capital (see Recent Developments below).
Our Strengths
WeEstablished 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 we are well positioned to achieve our business objectives and to execute our strategy due to the following factors:
has been established over time. We have assembled a Permian leasehold position of over approximately 13,60032,900net acres in the Southern and Central Midland Basin that are prospective for the exploration, development and exploitation of multiple oil-bearing intervals through both vertical and horizontal drilling.
Our initial horizontal drilling efforts commenced in 2012that have resulted in a large inventory of drillable locations in the southern Midland basin for future development of two zones of the Wolfcamp shale, complementing our existing vertical drilling program. We continue to evaluate other intervals prospective for horizontal development that may add to this inventory depending on evaluation resultsbeen produced by us and other industry players.participants. As of December 31, 2013, our estimated net proved reserves were comprised of approximately 80% oil and 20% natural gas, which includes NGLs in the production stream. This oil exposure provides us the opportunity to benefit from currently more favorable prices as compared to natural gas.
We continue to replace high decline-rate, natural gas productionMulti-year drilling inventory. Our current acreage position in the Permian Basin provides visible growth potential from a horizontal drilling inventory of almost 20 years based on our current two-rig horizontal drilling program. As of December 31, 2013, based upon the Gulfresults of Mexico shelf area with longer reserve life, liquids-rich production fromhorizontal wells drilled by us and other offsetting operators, and our Permian drilling programs. As a result,analysis of core data and historical vertical well performance, we have increasedidentified an inventory of approximately 540 potential horizontal well locations in multiple horizons across our reserve lifeSouthern and Central Midland Basin acreage. Of these potential locations, approximately 225 are identified in the Upper Wolfcamp B, Lower Wolfcamp B and Wolfcamp A zones which have been drilled on our acreage and are currently producing.185% to 8.9 years at year-end 2012 from 4.8 years at year-end 2008.
Our offshore properties generate substantial cash flow, which we can redeployExperienced team operating in the acquisition, exploration and development of onshore properties. Since initiating our onshore transition strategy in 2009, we have invested nearly Permian Basin.$263 million of offshore cash flow into our onshore initiatives.
Effective December 28, 2012, we sold our interest in the Habanero field for net cash consideration of $39.4 million, accelerating our cash flows from this offshore property and monetizing the value of additional undeveloped reserve potential. These proceeds allowed us to substantially reduce the outstanding balance on our Senior Secured Revolving Credit Facility (the "Credit Facility"), strengthening our liquidity in 2013 to support our Permian-focused capital development program.
On December 31, 2012, our total liquidity position was approximately $56.1 million, including $1.1 million of available cash and $55 million of unused borrowing base available under our Credit Facility. The $65 million borrowing base at December 31, 2012 increased by $20 million or 44% over the base at December 31, 2011.
We have assembled a management team experienced in oil and natural gas acquisitions, exploration, development and production in the areasMidland Basin. Reflective of this experience, we have realized improvements in which we focus our operations, with andrilling and capital efficiency since launching our horizontal drilling program in 2012. For example, our average drill time for a typical 7,800 foot lateral Wolfcamp shale well decreased from approximately 30 days at the start of 28 yearsour drilling program in 2012 to under 20daysas of experience in their relevant fields of expertise. Our technical and operational teamsFebruary 2014. We continue to benefit fromevaluate our completion techniques, and downspacing initiatives that we believe have the knowledge gained frompotential to improve resource recovery and contribute to enhanced returns on capital. In addition, we regularly evaluate our increased leveloperating results against those of activityother 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 all of our Permian Basin acreage, providing us the opportunity to modify our operational plans to respond to changes in operational and commodity price environments. This operating control also allows us to modify drilling and completion techniques, and change drilling schedules 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 established a Health, Safety and Environmental department dedicated to our operations in the Permian basinBasin. This group is responsible for monitoring the activity and fromsafety compliance of both our employees as well as third party service providers and consultants. 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. As an example, we were recently awarded the additionMidland Bruno Hanson/Midland College Award for Environmental Excellence which is given to companies that demonstrate strong environmental stewardship in the Permian Basin.
Financial flexibility to fund growth initiatives. We bolstered our capital structure in 2013 with the issuance of new employeesSeries A Cumulative Preferred Stock and the sale of our offshore assets. We have continued to build upon these transactions with significant industry experience.the recent completion of the Amended Credit Facility and Second Lien Facility as described in Recent Developments.
Exploration and Development Activities
Our 20122013 total capital expenditures, approximatedon a cash basis and including acquisitions, were $147171 million, and representedrepresenting a 39%17% increase over 20112012 actual capital expenditures. Of the $147171 million, approximately 88%$145 million was allocated to onshore drilling, development and leasehold acquisition activity in the Permian basin. During 20122013, capital expenditures on an accrual basis for exploration and development costs related to oil and natural gas properties included the following expenditures (in millions):
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| Southern Midland basin | | $ | 70.3 |
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| Northern Midland basin | | 21.4 |
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| Leasehold acquisitions and seismic | | 37.2 |
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| Plugging and abandonment costs in the Gulf of Mexico | | 2.3 |
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| Capitalized interest | | 2.0 |
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| Capitalized general and administrative costs allocated directly to exploration and development projects | | 13.3 |
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| Total capital expenditures | | $ | 146.5 |
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| Southern Midland Basin | | $ | 111 |
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| Central Midland Basin | | 20 |
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| Northern Midland Basin | | 7 |
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| Other | | 7 |
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| Total capital expenditures | | 145 |
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| Capitalized general and administrative costs allocated directly to exploration and development projects | | 11 |
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| Capitalized interest | | 4 |
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| Total capitalized expenses | | 15 |
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| Total operational expenditures | | 160 |
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| Acquisitions | | 11 |
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| Total capital expenditures, including acquisitions | | $ | 171 |
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WithWe expanded our continued operational focus onshore,horizontal pad development efforts from two to four fields in late 2013, adding Carpe Diem in Midland County and Garrison Draw in Reagan County. We expect our 2014 horizontal drilling program will be primarily focused on development of established Upper and Lower Wolfcamp zones in the Permian basin, weSouthern and Central Midland Basin. We also expect that over 92%to drill two wells in the Southern Midland Basin to evaluate the Wolfcamp A shale and a test of our 2013 capital expenditures willthe Lower Spraberry shale formation in the Central Midland Basin. Planned vertical drilling activity is anticipated to be focused onlimited to five deep Wolfberry wells in the acquisition, exploration, developmentPecan Acres field and operation of onshore properties, with only 8% of capital expenditures directed towards our offshore properties, excludingone well in the capital required for the subsea development project discussed below.Garrison Draw field. In addition, to the 2013 capital program, which is outlined within Management's Discussion and Analysis (Part II, Item 7), we have received various long-lead time requests for capital expenditures related to the proposed subsea development of the Medusa field, and we expect to receive additional requests throughout 2013. The operatorour plans to begin drilling these
include three vertical exploration wells will begin in the first quarterNorthern Midland Basin, the timing and location of 2014. For additional information, please referwhich being subject to our Offshore - Deepwater discussion, which is also located within Management's Discussion and Analysis.change as results are evaluated during the course of 2014.
Recent Developments
Credit facilities
On March 11, 2014, we entered into an amended senior secured revolving credit facility (the “Amended Credit Facility”) in the amount of $500 million with JPMorgan Chase Bank, N.A. as Administrative Agent (“J.P. Morgan”). The Credit Facility will have an initial borrowing base amount of $95 million and a maturity date of March 11, 2019. In conjunction with the Amended Credit Facility, we entered into a senior secured second lien term loan facility (the “Second Lien Facility”) in an aggregate amount of up to $125 million with J.P. Morgan as Administrative Agent and with a maturity date of September 11, 2019. See Note 4 for additional information.
Acquisitions
During the first quarter of 2012, the Company acquired approximately 16,233 gross (14,653 net)2014, we added 1,280 net acres in Borden county, Texas, which is located in the northern Midland basin. The northern Midland basin has had limited drilling activity compared with the southern Midland basin (whereUpton County near our current production is located), increasing the risk of successexisting core development fields for these drilling activities. Thean aggregate purchase price of $14.5 million was funded$7.0 million. This acreage added an estimated 96 gross potential horizontal well locations from seven prospective zones to our drilling inventory. In addition, we expect to leverage existing cash balances. During the third quarter of 2012, we acquired an additional 8,095 gross acres (6,964 net) in this area for a total consideration of $4.8 million.
During the second quarter of 2012, the Company signed a purchase and sale agreement to acquire 2,319 gross (1,762 net) acres in southern Reagan county, Texas for a total purchase price of $12.0 million, which was financed with a draw on the Company's Credit Facility. The transaction had an effective date of May 1, 2012 and closed on July 5, 2012.
Divestitures
On December 28, 2012, we closed the sale ofinfrastructure from our 11.25% working interestEast Bloxom field in the Habanero field (Garden Banks Block 341)development of this new acreage. See Notes 6 and 12 to Shell Offshore Inc., a subsidiary of Royal Dutch Shell Plc,our financial statements for an estimated net cash consideration of $39.4 million after customary purchase price adjustments. We used the proceeds from the sale to reduce outstanding borrowings on our Credit Facility, providing additional liquidity to fund our 2013 capital program. The borrowing base under our Credit Facility was revised to $65 million following the Habanero sale, and was redetermined as scheduled in the first quarter of 2013 based upon the evaluation of year-end proved reserves.information regarding acquisitions.
Crude Divestitures
Effective December 5, 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field (Mississippi Canyon blocks 582 and 538), our 10.0% membership interest in Medusa Spar LLC, and substantially all of our remaining Gulf of Mexico shelf properties. The Company sold these assets to W&T Offshore, Inc., an unrelated third-party, for total net cash consideration of approximately $100 million before customary purchase price adjustments. The Medusa field had production net to Callon of 582 MBOE in 2013. Also during the fourth quarter of 2013, the Company closed on the sale of its 69% interest in the Swan Lake field for $2 million. This field included 429 net acres and produced approximately 107 MMcf during the year ended December 31, 2013. This was the Company’s only field in the Haynesville shale. See Note 12 to our financial statements for additional information.
Oil and Natural Gas Properties
As of December 31, 20122013, our estimated net proved reserves totaled 14.114.9 MMBoeMMBOE and included 10.811.9 MMBbls and 19.817.8 Bcf, with a pre-tax present value, discounted at 10%, of $250.1301.1 million. Pre-tax present value is a non-US GAAPnon-GAAP financial measure, which we reconcile to the US GAAP measure of standardized measure of $231.1$283.9 million in note (d) to the table below. Oil constitutesconstituted approximately 77%80% of our total estimated equivalent net proved reserves and approximately 48%80% of our total estimated equivalent proved developed reserves.
The following table sets forth certain information about our estimated net proved reserves prepared by our independent petroleum reserve engineers by major fieldarea and for all other properties combined at December 31, 20122013:
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| | | | Estimated Net Proved Reserves | | Present |
| | Operator | | Oil (MBbls) | | Natural Gas (MMcf) | | Total (MBoe) | | Value ($000) |
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| Onshore: | | | | | | | | | |
| Permian basin | Callon | | 7,209 |
| | 13,242 |
| | 9,416 |
| | $ | 78,950 |
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| Haynesville shale | Callon | | — |
| | 1,231 |
| | 205 |
| | $ | 666 |
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| Total Onshore | | | 7,209 |
| | 14,473 |
| | 9,621 |
| | $ | 79,616 |
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| Gulf of Mexico Deepwater: | | | | | | | | | |
| Mississippi Canyon 538/582 | | | | | | | | | |
| “Medusa” | Murphy | | 3,551 |
| | 2,083 |
| | 3,898 |
| | $ | 179,967 |
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| Total Gulf of Mexico Deepwater | | | 3,551 |
| | 2,083 |
| | 3,898 |
| | $ | 179,967 |
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| Gulf of Mexico Shelf and Other: | | | | | | | | | |
| West Cameron Block 295 | Apache | | 5 |
| | 954 |
| | 164 |
| | $ | 1,081 |
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| East Cameron Block 2 | Apache | | 5 |
| | 487 |
| | 86 |
| | 633 |
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| East Cameron Block 257 | SandRidge Energy | | — |
| | 1,182 |
| | 197 |
| | (718 | ) |
| Other (c) | Various | | 10 |
| | 574 |
| | 106 |
| | (10,482 | ) |
| Total Gulf of Mexico Shelf and Other | | | 20 |
| | 3,197 |
| | 553 |
| | $ | (9,486 | ) |
| | | | | | | | | | |
| Total Net Proved Reserves | | | 10,780 |
| | 19,753 |
| | 14,072 |
| | $ | 250,097 |
|
|
| | | | | | | | | | | | | |
| | | | | | | | | Pre-tax Discounted |
| | | Estimated Net Proved Reserves | | Present |
| | | Oil (MBbls) | | Natural Gas (MMcf) | | Total (MBOE) | | Value ($000) |
| | | | | | | (a) | | (b)(c)(d) |
| Southern Midland Basin | | 10,103 |
| | 15,021 |
| | 12,607 |
| | $ | 267,216 |
|
| Central Midland Basin | | 1,699 |
| | 2,730 |
| | 2,154 |
| | 39,336 |
|
| Northern Midland Basin | | 96 |
| | — |
| | 96 |
| | 3,921 |
|
| Other (c) | | — |
| | — |
| | — |
| | (9,329 | ) |
| Total | | 11,898 |
| | 17,751 |
| | 14,857 |
| | $ | 301,144 |
|
| |
| (a) | We convert Mcf to BoeBOE 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 an 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, 20122013, as set forth in the Company’s reserve reports prepared by its independent petroleum reserve engineers, Huddleston & Co., Inc. |
| |
| (c) | Includes a reduction for estimated plugging and abandonment costs that isare reflected as a liability on our balance sheet at December 31, 20122013, 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, with most of such obligations estimated to occur within the next five years.flows. |
| |
| (d) | The Company uses the financial measure “Pre Tax Discounted Present Value” which is a non-US GAAPnon-GAAP financial measure. The Company believes that Pre Tax Discounted Present Value, while not a financial measure in accordance with US 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, 20122013 was $231.1283.9 million inclusive of the $18.917.2 million discounted estimated future income taxes relating to such future net revenues. The projected per Mcf natural gas price of $4.815.45 used in the 20122013 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 $94.6892.16 used in the 20122013 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. |
Onshore Properties
Onshore proved reserves accounted for approximately 68% of year-end 2012 proved reserves on a Boe basis as compared to 61% of 2011 reserves on a Boe basis, consistent with our strategy of using our offshore cash flow to explore and develop our onshore properties and following the sale of our offshore interest in the Habanero field.
Permian Basin
As of December 31, 20122013, we owned approximately 32,96231,829 net acres in the Permian basin, where we are exclusively focused on the Midland sub-basin.Basin. Our reserves in the Permian basinBasin represent approximately 67%all of our total proved reserves at year-end 20122013 as compared to 48%67% at year-end 2011.2012. Average net production from the Company'sCompany’s Permian basinBasin properties increased 67%38% to 1,614 Boe/2,227 BOE/d in 20122013 from 967 Boe/1,619 BOE/d in 2011.2012. As of December 2013, our average daily net production from the Permian Basin was 3,611 BOE/d.
We describeSouthern Midland Basin
Counties (fields): Upton (East Bloxom), Reagan (Taylor Draw and Garrison Draw) and Crockett (Block 5)
8,904 net acres as of December 31, 2013
77 producing wells (17 horizontal)
Initiated horizontal development in 2012
| |
| • | 4th quarter 2013 net production: 2,334 BOE/d (72% horizontal) |
The Southern Midland Basin is our activitieslargest operating area in terms of production. Following recently completed acquisitions in the Permian basin basedfirst quarter of 2014, we currently have approximately 10,200 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 two geographic areas,these intervals across our entire position in the southernSouthern Midland Basin in 2014 and northern Midland basin, given their relative stages of development.expect to test additional zones in future years.
Central Midland Basin
Counties (fields): Midland (Carpe Diem and Pecan Acres) and Ector (Kayleigh)
3,359 net acres as of December 31, 2013
50 producing vertical wells
Initiated horizontal development in 2013
| |
| • | 4th quarter 2013 net production: 564 BOE/d |
The southern portionCentral Midland Basin has been the focus of our position (located in Texas counties of Crockett, Upton, Midland, Ector, Reagan and Glasscock) representshigh-graded vertical drilling program, targeting multiple zones down to the vast majority of our current Permian production.Woodford shale. We have been pursuing a verticalrecently shifted our focus to horizontal development programof the Carpe Diem field. Our first Wolfcamp B wells were placed on production in thisthe first quarter of 2014 and we plan to add Carpe Diem to our core development fields going forward. This area since our entry intois prospective for multiple horizontal development zones and we plan to target the PermianLower Spraberry in 2009, drilling 71 gross (63 net) vertical wells over that period. In 2012,2014 as we commenced the horizontal drillingdelineate zones outside of our properties in Upton and Reagan counties, drilling three net wells targeting the Wolfcamp B shale.B.
Northern Midland Basin
Counties (fields): Borden (Black Magic and Baird Ranch) and Lynn (Tahoka Prospect)
19,566 net acres as of December 31, 2013
One producing vertical well
Ongoing going exploration and delineation activity
Our northernNorthern Midland basinBasin position was established in 2012 with the acquisition of 24,328 gross (21,617 net) net acres in Borden and Lynn counties.Counties. We currently own approximately 17,433 net acres following our decision to allow certain acreage in the Northern Midland Basin to expire as we refine our targeted areas for exploration. We began our exploration program in Borden countyCounty during the second half of 2012,, drilling one gross (0.8(0.75 net) vertical and two gross (1.8(1.5 net) horizontal wells, targeting the Cline and Mississippi lime. We have subsequently focused our exploration activity on the Mississippi chat, drilling a vertical well (Lacey Newton 2801) in late 2013. We plan to further evaluate the areal extent of this prospective play with at least one vertical exploration well in Borden County in 2014. We also plan to drill our first exploration well in Lynn County in the first half of 2014, testing several prospective zones, including the Spraberry.
The following table summarizesFor additional details regarding our Permian wells drilled and completed by area during 2012:
|
| | | | | | | | | | | | |
| Property | | Drilling | | Completion |
| | | Gross | | Net | | Gross | | Net |
| Southern Midland basin vertical wells | | 15 |
| | 10.7 |
| | 22 |
| | 16.0 |
|
| Southern Midland basin horizontal wells | | 3 |
| | 2.8 |
| | 2 |
| | 2.0 |
|
| Total | | 18 |
| | 13.5 |
| | 24 |
| | 18.0 |
|
| | | | | | | | | |
| Property | | Drilling | | Completion |
| | | Gross | | Net | | Gross | | Net |
| Northern Midland basin vertical wells | | 1 |
| | 0.8 |
| | — |
| | — |
|
| Northern Midland basin horizontal wells | | 2 |
| | 1.8 |
| | 1 |
| | 1.0 |
|
| Total | | 3 |
| | 2.6 |
| | 1 |
| | 1.0 |
|
Other
We own a 69% working interest in a 429 net acre unit of the Haynesville shale natural gas unit located in southern Bossier parish, Louisiana. As of December 31, 2012, our Haynesville shale proved reserves were reduced by 90% compared to year-end 2011 due to low natural gas prices. During 2012, our one producing well produced 3% of our total production on an equivalent basis. Also during 2012,related information, please see “Present Activities and Productive Wells” included below within this well was shut-in for a combined 112 days during the fourth quarter of 2011 and the first quarter of 2012 due to well interference from an offsetting well. Production was restored in mid-March 2012 following a successful remediation operation and, as of December 31, 2012, our Haynesville well was producing approximately 751 Mcf of natural gas per day. We currently have no drilling obligations related to this lease position and will wait for natural gas prices to return to a level that would justify capital allocation within our portfolio before recommencing our development of the field.Item.
Gulf of Mexico DeepwaterOther Property
Medusa, Mississippi Canyon Blocks 538/582
The Medusa field, in which weWe own a 15% working interest, isleasehold in approximately 65,000 net acres located in 2,235 feetvarious counties in Nevada. These leases are with the Bureau of water approximately 50 miles offshore Louisiana,Land Management and currently produces from eight existing wellbores. Murphy Exploration & Production Company (“Murphy”), the operator, ownscarry a 60% working interest and ENI Deepwater, LLC, owns the remaining 25% working interest. Since the field entered productionprimary term that expires in 2003, cumulative gross volumes have approximated 58 MMBoe.
During 2012, the Medusa field produced 464 MBoe net to Callon from eight wells which accounted for 29% of our total production. Six of the field's wells continue to produce from their initial completions as of December 31, 2012.2018. We project that 1.1 MMBoe of net PDNPs can be accessed by recompletions in the existing wells. These up-hole recompletions in existing wellbores are expected to occur as existing completions deplete to a level that is uneconomic to justify continued production. We anticipate the development of our current net 1.3 MMBoe of PUD reservesevaluating this acreage in conjunction with a subsea development programthird-party consultant and developing options for future activity. Callon does not have any drilling commitments related to be commencedthis acreage during 2014.the primary term.
Gulf of Mexico Shelf
Approximately 4% of our year-end 2012 proved reserves were attributable to the shelf area of the Gulf of Mexico and other properties. We own interests in 14 producing wells in eight oil and natural gas fields in the shelf area of the Gulf of Mexico area. These wells produced 340 MBoe net to our interest in 2012, which accounted for 22% of our total production.
For additional information regarding the Company's properties, including its 2013 capital expenditures program and future development plans, please refer to the Properties discussion within Management's Discussion and Analysis, which is located in Part II, Item 7 of this filing.
Proved Reserves
Estimates of volumes of proved reserves at year-end, net to our interest, at year end 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 MBoe.BOE. For the MBoeBOE 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 an 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.Mexico at year-end 2011 and 2012.
| | | | | Years Ended December 31, | | Years Ended December 31, |
| | | 2012 | | 2011 | | 2010 | | 2013 | | 2012 | | 2011 |
| Proved developed: | | | | | | | | | | | | |
| Oil (MBbls) | | 4,955 |
| | 5,069 |
| | 4,503 |
| | 5,960 |
| | 4,955 |
| | 5,069 |
|
| Natural gas (MMcf) | | 10,680 |
| | 11,605 |
| | 12,715 |
| | 9,059 |
| | 10,680 |
| | 11,605 |
|
| MBoe | | 6,735 |
| | 7,003 |
| | 6,622 |
| |
| MBOE | | | 7,470 |
| | 6,735 |
| | 7,003 |
|
| Proved undeveloped: | | | | | | | | | | | | |
| Oil (MBbls) | | 5,825 |
| | 5,006 |
| | 3,645 |
| | 5,938 |
| | 5,825 |
| | 5,006 |
|
| Natural gas (MMcf) | | 9,073 |
| | 23,513 |
| | 20,241 |
| | 8,692 |
| | 9,073 |
| | 23,513 |
|
| MBoe | | 7,337 |
| | 8,925 |
| | 7,019 |
| |
| MBOE | | | 7,387 |
| | 7,337 |
| | 8,925 |
|
| Total proved: | | | | | | | | | | | | |
| Oil (MBbls) | | 10,780 |
| | 10,075 |
| | 8,149 |
| | 11,898 |
| | 10,780 |
| | 10,075 |
|
| Natural gas (MMcf) | | 19,753 |
| | 35,118 |
| | 32,957 |
| | 17,751 |
| | 19,753 |
| | 35,118 |
|
| MBoe | | 14,072 |
| | 15,928 |
| | 13,641 |
| |
| MBOE | | | 14,857 |
| | 14,072 |
| | 15,928 |
|
| Financial Information: | | | | | | | |
| Estimated pre-tax future net cash flows (a) | | $ | 592,424 |
| | $ | 568,798 |
| | $ | 379,448 |
| | $ | 680,627 |
| | $ | 592,424 |
| | $ | 568,798 |
|
| Pre-tax discounted present value (a) (b) | | $ | 250,097 |
| | $ | 309,890 |
| | $ | 205,532 |
| | $ | 301,144 |
| | $ | 250,097 |
| | $ | 309,890 |
|
| Standardized measure of discounted future net cash flows(a) (b) | | $ | 231,148 |
| | $ | 270,357 |
| | $ | 198,916 |
| |
| Standardized measure of discounted future net cash flows (a) (b) | | | $ | 283,946 |
| | $ | 231,148 |
| | $ | 270,357 |
|
| |
| (a) | Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 20122013, in accordance with accounting for asset retirement obligations rules. |
| |
| (b) | The Company uses the financial measure “Pre-tax discounted present value” which is a non-US GAAPnon-GAAP financial measure. The Company believes that Pre-tax discounted present value, while not a financial measure in accordance with US GAAP, is an important financial measure used by investors and independent oil and gas producers for evaluating the relative value of crude 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, 20122013 was $231.1283.9 million inclusive of the $18.917.2 million discounted estimated future income taxes relating to such future net revenues. The natural gas Mcf prices of $4.815.45 used in the 20122013 reserve estimates have been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected crude oil prices of $94.6892.16 used in the 20122013 reserve estimates have 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 1412 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.
EstimatedThe Company’s estimated net proved reserves increased 6% to 14,857 MBOE from 14,072 MBOE at December 31, 2013 and 2012, represented a 12% decrease over 2011 year-end estimated net proved reservesrespectively. Additions during the year were 9,979 MBOE, primarily due to the sale of the Company's interest in the Habanero field and the downward revision of our Haynesville Shale undeveloped reserves at year-end 2012, which were reduced due to low natural gas pricing assumptions. These decreases were partially offset by the Company'sCompany’s horizontal development of a portion of its Permian basin, on which it added 7Basin properties. These increases were partially offset by (1) 4,057 MBOE related to the sale of the Company’s Gulf of Mexico assets and Haynesville field, (2) 3,724 MBOE of reductions in the Company’s PUD reserves, primarily related to the reclassification of certain vertical PUD locations to the horizontal probable category, and a small amount to the horizontal PDP and 19PUD wellscategories at year end and (3) 1,413 MBOE related to the Company’s production during 2012.2013. The reclassified vertical PUDs include Wolfberry PUD locations that included certain target zones that are now expected to be more efficiently developed by the Company’s multi-level horizontal drilling programs initiated in 2012. The vast majority of these previously booked vertical PUDs are now internally classified as horizontal probable reserves, with a small amount now captured in horizontal PDPs and PUDs.
Proved Undeveloped Reserves ("PUDs")(PUDs)
Annually, the Company reviews its PUDs to ensure appropriate plans exist for development. Except as noted below,PUD reserves are recognized as PUDsrecorded only if the Company has plans to convert the PUDsthese reserves into PDPs within five years of the date they are first recorded as PUDs. The basis for ourrecorded. Our development plans include the allocation of capital to projects included within our 20132014 capital budget and, in subsequent years, the allocation of capital within our long-range business plan. Generally,plan to convert PUDs to PDPs within this five year period. In general, our 20132014 capital budget and our long-range capital plans are primarily governed by our expectations of internally generated cash flow and Credit Facilitycredit 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:
|
| | | | | | | | |
| | PUDs (MBoe) at December 31, |
| | 2012 | | 2011 | | 2010 |
| Permian basin | 6,040 |
| | 4,861 |
| | 2,928 |
|
| Haynesville shale | — |
| | 1,730 |
| | 1,757 |
|
| Total Onshore PUDs | 6,040 |
| | 6,591 |
| | 4,685 |
|
| Medusa | 1,297 |
| | 1,186 |
| | 1,186 |
|
| Habanero (a) | — |
| | 1,148 |
| | 1,148 |
|
| Total Deepwater PUDs | 1,297 |
| | 2,334 |
| | 2,334 |
|
| Total PUDs | 7,337 |
| | 8,925 |
| | 7,019 |
|
|
| | | | | | | | |
| | PUDs (MBOE) at December 31, |
| | 2013 | | 2012 | | 2011 |
| Permian Basin | 7,387 |
| | 6,040 |
| | 4,861 |
|
| Haynesville shale | — |
| | — |
| | 1,730 |
|
| Total Onshore | 7,387 |
| | 6,040 |
| | 6,591 |
|
| Medusa (a) | — |
| | 1,297 |
| | 1,186 |
|
| Habanero (b) | — |
| | — |
| | 1,148 |
|
| Total Offshore | — |
| | 1,297 |
| | 2,334 |
|
| Total | 7,387 |
| | 7,337 |
| | 8,925 |
|
| |
| (a) | Effective July 1, 2013, we sold our interest in the Medusa field. See Note 12 for additional information. |
| |
| (b) | Effective December 28, 2012, we sold our interest in the Habanero field. See Note 12 for additional information. |
The Company'sOur PUDs decreasedincreased 18%1% to 7,3377,387 MBoeMBOE from 8,925 MBoe7,337 MBOE at December 31, 20122013 and 20112012, respectively. Additions during the yearWe added 2,344 MBoe5,168 MBOE to the Company'sCompany’s PUDs, primarily from the continued horizontal development of our Permian Basin properties. The increase in Permian Basin PUDs was partially offset by (1)the reclassification of 5573,724 MBoe primarily comprisedMBOE, or 51% of transfers to PDPs as a result of our development program, (2) 1,148 MBoevolumes included in year-end 2012 PUD reserves related to vertical PUD locations that were moved to the sale of Habanero,horizontal probable category, and (3) 2,227 MBoe relateda small amount to reductions inthe horizontal PDP and PUD categories, as we believe the previously booked Wolfberry PUD locations included certain target zones that we now expect can be more effectively developed over the next five years by our multi-level horizontal drilling program that was commenced during 2012. Also offsetting our PUD reserves, primarily related toadditions was the Haynesville Shale, by amounts no longer deemed to be economic PUDs at year-end. Of our year-end 2011 PUD reserves, 6% were converted to proved developed producing reserves by year end 2012, at a total cost of approximately $19 million, net.
Our 1,297 MBoe of deepwater PUDs have been classified as PUDs for more than five years, though we expect to develop these PUDs within the next two years. Our decision to classify these reserves as PUDs was primarily based on (1) our ongoing development planning in the area, (2) our historical record of completing development of comparable long-term projects, (3) the amount of time which we have maintained the leases or booked reserves without significant development activities and (4) the extent to which we have followed previously adopted development plans. Our discussions with the field's operator have resulted in the modification of certain development plans for Medusa to drill or sidetrack PUDs within a shorter period of time than originally estimated. The Company expects to drill a new well in 2014 within the Medusa field to access the PUD reservessale of 1,297 MBoe.MBOE, or 18% included in the year-end 2012 PUD reserves related to our Medusa field, and the conversion of a small portion of our 2012 PUD reserves to PDPs during 2013 from vertical drilling for a net cost of approximately $6 million. Most of our PUDs at year-end 2012 were attributable to vertical well locations. During 2012,2013, our drilling program was predominantly focused on horizontal wells as we continued to delineate our acreage for horizontal development of multiple zones that were previously the Company didtarget of vertical development wells. Based on our horizontal drilling results and subsequent capital allocation decisions, only three of the vertical wells previously included as PUDs in our 2012 reserve report were drilled in 2013. Our horizontal drilling program converted 4,431 MBOE of reserves that were not convert any offshore PUDsclassified as proved at year end 2012 to PDPs. proved developed reserves at year end 2013.
The Company'sCompany plans to develop its onshore, Permian basinBasin PUDs as part of a multi-year drilling program, which is expectedprogram. At December 31, 2013, we had no reserves that remained undeveloepd for five or more years, and all PUD drilling locations are currently scheduled to be completed on existing acreagedrilled within three to five years of thetheir initial recording of any PUD.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 3035 years of industry experience including 2526 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 Huddleston & Co., Inc. ("Huddleston"(“Huddleston”), a Texas registered engineering firm, as our independent petroleum and geological firm. The Company provided to Huddleston information about our oil and gas properties, including production profiles, prices and costs, and Huddleston prepared its own estimates of the reserves attributable to the Company’s properties. All of the information regarding reserves in this annual report is derived from Huddleston’s report. Huddleston'sHuddleston’s reserve report letter is included as an Exhibit to this annual report. The principal engineer at Huddleston who is
responsible for preparing the Company’s reserve estimates has over 30 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.
To further enhance the control environment over the reserve estimation process, our Board of Directors includes a Strategic Planning Committee whose purpose, as stated in the Committee'sCommittee’s charter, includes assisting management and the Board with its oversight of the integrity of the determination of the Company'sCompany’s oil natural gas and natural gas liquids reserves and the work of the Huddleston. The Committee'sCommittee’s charter also specifies that the Committee shall perform, in consultation with the Company'sCompany’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"“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.
Production Volumes, Average Sales Prices and Average 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 crude oil and natural gas for the periods indicated.
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2012 | | 2011 | | 2010 |
| | (in thousands, except per unit data) |
| Production | | | | | |
| Natural gas and NGLs (Mcf) | 3,588 |
| | 5,081 |
| | 4,892 |
|
| Crude oil (MBbl) | 977 |
| | 996 |
| | 859 |
|
| Total (MBoe) | 1,575 |
| | 1,843 |
| | 1,674 |
|
| | | | | | |
| Revenues | |
| | |
| | |
|
| Natural gas and NGL sales | $ | 14,149 |
| | $ | 26,682 |
| | 24,639 |
|
| Crude oil sales | 96,584 |
| | 100,962 |
| | 65,243 |
|
| Total revenues | $ | 110,733 |
| | $ | 127,644 |
| | $ | 89,882 |
|
| | | | | | |
| Lease Operating Expenses | |
| | |
| | |
|
| Production costs | $ | 22,981 |
| | $ | 17,693 |
| | $ | 15,770 |
|
| Severance/production taxes | 2,430 |
| | 1,826 |
| | 816 |
|
| Gathering | 349 |
| | 592 |
| | 802 |
|
| Ad Valorem | 794 |
| | 236 |
| | 324 |
|
| Total lease operating expenses | $ | 26,554 |
| | $ | 20,347 |
| | $ | 17,712 |
|
| | | | | | |
| Realized prices | |
| | |
| | |
|
| Natural gas ($/Mcf, including realized gains (losses) on derivatives) (a) | $ | 3.94 |
| | $ | 5.25 |
| | $ | 5.04 |
|
| Natural gas ($/Mcf, excluding realized gains (losses) on derivatives) (a) | 3.94 |
| | 5.25 |
| | 4.91 |
|
| Crude oil ($/Bbl, including realized gains (losses) on derivatives) (b) | 98.86 |
| | 101.34 |
| | 75.97 |
|
| Crude oil ($/Bbl, excluding realized gains (losses) on derivatives) (b) | 97.41 |
| | 101.72 |
| | 75.97 |
|
| | | | | | |
| Operating costs per Boe - Total Consolidated | |
| | |
| | |
|
| Production costs | $ | 14.59 |
| | $ | 9.60 |
| | $ | 9.61 |
|
| Severance/production taxes | 1.54 |
| | 0.99 |
| | 0.49 |
|
| Gathering | 0.22 |
| | 0.32 |
| | 0.48 |
|
| Ad Valorem | 0.50 |
| | 0.13 |
| | 0.19 |
|
| Total operating costs per Boe | $ | 16.85 |
| | $ | 11.04 |
| | $ | 10.77 |
|
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | (in thousands, except per unit data) |
| Production | | | | | |
| Oil (MBbls) | 911 |
| | 977 |
| | 996 |
|
| Natural gas (Mcf) | 3,011 |
| | 3,588 |
| | 5,081 |
|
| Total (MBOE) | 1,413 |
| | 1,575 |
| | 1,843 |
|
| | | | | | |
| Revenues | |
| | |
| | |
|
| Oil sales | $ | 88,960 |
| | $ | 96,584 |
| | $ | 100,962 |
|
| Natural gas sales | 13,609 |
| | 14,149 |
| | 26,682 |
|
| Total revenues | $ | 102,569 |
| | $ | 110,733 |
| | $ | 127,644 |
|
| | | | | | |
| Operating costs | |
| | |
| | |
|
| Lease operating expense | $ | 19,779 |
| | $ | 23,330 |
| | $ | 18,285 |
|
| Production taxes | 4,133 |
| | 3,224 |
| | 2,062 |
|
| Total operating costs | $ | 23,912 |
| | $ | 26,554 |
| | $ | 20,347 |
|
| | | | | | |
| Realized prices | |
| | |
| | |
|
| Oil ($/Bbl, including realized gains (losses) on derivatives) (a) | $ | 97.65 |
| | $ | 98.86 |
| | $ | 101.34 |
|
| Oil ($/Bbl, excluding realized gains (losses) on derivatives) (a) | 97.65 |
| | 97.41 |
| | 101.72 |
|
| Natural gas ($/Mcf, including realized gains (losses) on derivatives) (b) | 4.52 |
| | 3.94 |
| | 5.25 |
|
| Natural gas ($/Mcf, excluding realized gains (losses) on derivatives) (b) | 4.52 |
| | 3.94 |
| | 5.25 |
|
| | | | | | |
| Operating costs per BOE | |
| | |
| | |
|
| Lease operating expense | $ | 14.00 |
| | $ | 14.81 |
| | $ | 9.92 |
|
| Production taxes | 2.92 |
| | 2.05 |
| | 1.12 |
|
| Total operating costs per BOE | $ | 16.92 |
| | $ | 16.86 |
| | $ | 11.04 |
|
| |
| (a) | Oil prices for production from our two divested deepwater fields reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production, prior to the sale of Medusa in December 2013, and Argus Bonita WTI differential for Habanero production, prior to the sale of Habanero during December 2012. |
| |
| (b) | Natural gas prices exceeded the related NYMEX prices, which are quoted on an MMBtu basis, primarily due to the value of the NGLs in our liquids-rich natural gas stream, primarily from our Permian basin and deepwater production. |
| |
(b) | Crude oil prices for production from our two deepwater fields reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production and Argus Bonita WTI differential for Habanero production, prior to the sale of Habanero during December 2012. |
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 and in federal and state waters in the Gulf of Mexico.States. At December 31, 20122013, the Company was in the process of drilling one exploratory well (which is excluded from the table below) and had four wells awaiting fracture stimulation.
|
| | | | | | | | | | | | | | | | | |
| | Years ended December 31, |
| | 2012 | | 2011 | | 2010 |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Development: | | | | | | | | | | | |
| Crude oil | 14 |
| | 9.70 |
| | 36 |
| | 32.77 |
| | 20 |
| | 19.37 |
|
| Natural gas | — |
| | — |
| | — |
| | — |
| | 1 |
| | 0.69 |
|
| Non-productive | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total | 14 |
| | 9.70 |
| | 36 |
| | 32.77 |
| | 21 |
| | 20.06 |
|
| | | | | | | | | | | | |
| Exploration: | | | | | | | | | | | |
| Crude oil | 7 |
| | 6.20 |
| | — |
| | — |
| | — |
| | — |
|
| Natural gas | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Non-productive | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total | 7 |
| | 6.20 |
| | — |
| | — |
| | — |
| | — |
|
|
| | | | | | | | | | | | | | | | | | |
| | | Drilled | | Completed (a) | | Awaiting Completion |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Southern Midland Basin | | | | | | | | | | | | |
| Vertical wells | | 1 |
| | 1.0 |
| | 1 |
| | 1.0 |
| | — |
| | — |
|
| Horizontal wells | | 17 |
| | 15.5 |
| | 15 |
| | 13.5 |
| | 3 |
| | 3.0 |
|
| Total | | 18 |
| | 16.5 |
| | 16 |
| | 14.5 |
| | 3 |
| | 3.0 |
|
| | | | | | | | | | | | | |
| Central Midland Basin | | | | | | | | | | | | |
| Vertical wells | | 5 |
| | 3.0 |
| | 7 |
| | 4.4 |
| | — |
| | — |
|
| Horizontal wells | | 2 |
| | 1.7 |
| | — |
| | — |
| | 2 |
| | 1.7 |
|
| Total | | 7 |
| | 4.7 |
| | 7 |
| | 4.4 |
| | 2 |
| | 1.7 |
|
| | | | | | | | | | | | | |
| Northern Midland Basin | | | | | | | | | | | | |
| Vertical wells | | 1 |
| | 1.0 |
| | 2 |
| | 1.8 |
| | — |
| | — |
|
| Horizontal wells | | — |
| | — |
| | 1 |
| | 0.8 |
| | — |
| | — |
|
| Total | | 1 |
| | 1.0 |
| | 3 |
| | 2.5 |
| | — |
| | — |
|
| | | | | | | | | | | | | |
| Total | | 26 |
| | 22.2 |
| | 26 |
| | 21.4 |
| | 5 |
| | 4.7 |
|
| | | | | | | | | | | | | |
| Total vertical wells | | 7 |
| | 5.0 |
| | 10 |
| | 7.1 |
| | — |
| | — |
|
| Total horizontal wells | | 19 |
| | 17.2 |
| | 16 |
| | 14.3 |
| | 5 |
| | 4.7 |
|
| | | | | | | | | | | | | |
| Total | | 26 |
| | 22.2 |
| | 26 |
| | 21.4 |
| | 5 |
| | 4.7 |
|
(a) Completions include wells drilled prior to 2013.
The following table sets forth the Company’s drilled and completed wells, none of which were natural gas or nonproductive for the periods reflected: |
| | | | | | | | | | | | | | | | | | |
| | | 2013 | | 2012 | | 2011 |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Oil | | | | | | | | | | | | |
| Development | | 25 |
| | 21.2 |
| | 14 |
| | 9.7 |
| | 36 |
| | 32.8 |
|
| Exploratory | | 1 |
| | 1.0 |
| | 7 |
| | 6.2 |
| | — |
| | — |
|
| Total | | 26 |
| | 22.2 |
| | 21 |
| | 15.9 |
| | 36 |
| | 32.8 |
|
Wells drilled within the productive boundaries of statistical plays, such as on our southernSouthern Midland basinBasin acreage, have been classified as development wells.
The following table sets forth productive wells as of December 31, 20122013:
| | | | Crude Oil Wells | | Natural Gas Wells | Oil Wells | | Natural Gas Wells |
| | Gross | | Net | | Gross | | Net | Gross | | Net | | Gross | | Net |
| Working interest | 103 |
| | 84.50 |
| | 10 |
| | 4.30 |
| 128 |
| | 107.7 |
| | — |
| | — |
|
| Royalty interest | 3 |
| | 0.10 |
| | 2 |
| | 0.08 |
| 3 |
| | 0.1 |
| | — |
| | — |
|
| Total | 106 |
| | 84.60 |
| | 12 |
| | 4.38 |
| 131 |
| | 107.8 |
| | — |
| | — |
|
A well is categorized as a crudean oil well or a natural gas well based upon the ratio of crude oil to natural gas reserves on a Mcfe basis. However, somemost of our wells produce both crude oil and natural gas.
For the periods presented, the following table sets forth by major field(s) net production volumes and estimated proved reserves:
|
| | | | | | | | | | | | | | | | | | |
| | | Year ended December 31, |
| | | Production Volumes (MBoe) | | % of Total Proved Reserves at 12/31/2012 |
| Offshore - Gulf of Mexico: | | 2012 | | 2011 | | 2010 | | 2012 | | 2011 | | 2010 |
| Medusa | | 464 |
| | 641 |
| | 593 |
| | 28 | % | | 27 | % | | 33 | % |
| Habanero | | 134 |
| | 197 |
| | 233 |
| | — | % | | 8 | % | | 10 | % |
| Shelf and other | | 340 |
| | 551 |
| | 616 |
| | 4 | % | | 4 | % | | 7 | % |
| Total offshore: | | 938 |
| | 1,389 |
| | 1,442 |
| | 32 | % |
| 39 | % | | 50 | % |
| | | | | | | | | | | | | |
| Onshore: | | | | | | | | | | | | |
| Permian basin | | 591 |
| | 353 |
| | 150 |
| | 67 | % | | 48 | % | | 33 | % |
| Haynesville shale | | 46 |
| | 101 |
| | 82 |
| | 1 | % | | 13 | % | | 17 | % |
| Total onshore: | | 637 |
| | 454 |
| | 232 |
| | 68 | % |
| 61 | % | | 50 | % |
| | | | | | | | | | | | | |
| Total | | 1,575 |
| | 1,843 |
| | 1,674 |
| | 100 | % |
| 100 | % | | 100 | % |
|
| | | | | | | | | | | | | | | | | | |
| | | Year ended December 31, |
| | | Production Volumes (MBOE) | | % of Total Proved Reserves |
| | | 2013 | | 2012 | | 2011 | | 2013 | | 2012 | | 2011 |
| Onshore | | | | | | | | | | | | |
| Permian Basin | | | | | | | | | | | | |
| Southern Midland Basin | | 612 |
| | 402 |
| | 254 |
| | 85 | % | | 51 | % | | 31 | % |
| Central Midland Basin | | 193 |
| | 189 |
| | 99 |
| | 14 | % | | 16 | % | | 17 | % |
| Northern Midland Basin | | 8 |
| | — |
| | — |
| | 1 | % | | — | % | | — | % |
| Total Permian Basin | | 813 |
| | 591 |
| | 353 |
| | 100 | % | | 67 | % | | 48 | % |
| | | | | | | | | | | | | |
| Haynesville shale | | 18 |
| | 46 |
| | 101 |
| | — | % | | 1 | % | | 13 | % |
| Total onshore | | 831 |
| | 637 |
| | 454 |
| | 100 | % | | 68 | % | | 61 | % |
| | | | | | | | | | | | | |
| Offshore | | | | | | | | | | | | |
| Medusa | | 302 |
| | 464 |
| | 641 |
| | — | % | | 28 | % | | 27 | % |
| Habanero | | — |
| | 134 |
| | 197 |
| | — | % | | — | % | | 8 | % |
| Gulf of Mexico shelf and other | | 280 |
| | 340 |
| | 551 |
| | — | % | | 4 | % | | 4 | % |
| Total offshore | | 582 |
| | 938 |
| | 1,389 |
| | — | % | | 32 | % | | 39 | % |
| | | | | | | | | | | | | |
| Total | | 1,413 |
| | 1,575 |
| | 1,843 |
| | 100 | % | | 100 | % | | 100 | % |
Leasehold Acreage
The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 20122013.
| | | | Developed | | Undeveloped | | Total | Developed | | Undeveloped | | Total |
| | Gross | | Net | | Gross | | Net | | Gross | | Net | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Louisiana | 1,741 |
| | 681 |
| | 233 |
| | 167 |
| | 1,974 |
| | 848 |
| 1,091 |
| | 158 |
| | 233 |
| | 167 |
| | 1,324 |
| | 325 |
|
| Texas (a) | 10,891 |
| | 8,914 |
| | 27,236 |
| | 24,048 |
| | 38,127 |
| | 32,962 |
| 13,038 |
| | 11,144 |
| | 22,889 |
| | 20,685 |
| | 35,927 |
| | 31,829 |
|
| Federal onshore (b) | — |
| | — |
| | 64,963 |
| | 64,963 |
| | 64,963 |
| | 64,963 |
| — |
| | — |
| | 64,963 |
| | 64,963 |
| | 64,963 |
| | 64,963 |
|
| Federal waters (c) | 44,920 |
| | 17,136 |
| | 23,715 |
| | 7,599 |
| | 68,635 |
| | 24,735 |
| |
| Total | 57,552 |
| | 26,731 |
| | 116,147 |
| | 96,777 |
| | 173,699 |
| | 123,508 |
| 14,129 |
| | 11,302 |
| | 88,085 |
| | 85,815 |
| | 102,214 |
| | 97,117 |
|
| |
| (a) | A portion of our Texas acreage requires continued 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'sCompany’s lease of this acreage, located in Nevada, has approximately sixfour years remaining, and had a carrying value at December 31, 20122013 of approximately $2.6 million included in the Company'sCompany’s unevaluated properties balance. 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. |
| |
(c) | The Company's federal waters acreage is held by production. |
Undeveloped Acreage Expirations
The following table sets forth by geographic area as of December 31, 2013 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 |
| | | 2014 | | 2015 | | 2016 | | Total | | |
| Texas: | | | | | | | | | | |
| Southern Permian Basin | | 165 |
| | — |
| | — |
| | 165 |
| | 165 |
|
| Central Permian Basin | | — |
| | — |
| | — |
| | — |
| | — |
|
| Northern Permian Basin (a) | | 10,586 |
| | 7,282 |
| | 327 |
| | 18,195 |
| | 19,755 |
|
| Nevada: (b) | | — |
| | — |
| | — |
| | — |
| | — |
|
| Total acreage | | 10,751 |
| | 7,282 |
| | 327 |
| | 18,360 |
| | 19,920 |
|
(a) 2,133 net acres have expired as of March 7, 2014. 16,062 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.
The expiring acreage set forth in the table above accounts for 21% of our net undeveloped acreage (85,815 total net acres). 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 the expiration of undeveloped acreage that occurs in the normal course of our business.
Title to Properties
The Company believes that the title to its crude 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'sCompany’s properties are typically subject, in one degree or another, 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'sCompany’s rights to production revenues, these characteristics have been taken into account in calculating Callon'sCallon’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'sCompany’s insurance policies include coverage for general liability insuring both onshore and offshore operations (including sudden and accidental pollution), physical damage to its offshore oil and natural gas properties, aviation liability, auto liability, worker'sworker’s compensation, employer's liability, and maritime employersemployer’s liability. The company carries control of well insurance for all offshore wells, though unlessonly those onshore operations that it is contractually bound to do so, the Company does not carry control of well insurance for onshore operations.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 environmental liability coverage for the effects of pollution on third parties
arising from its operations. The Company'sCompany’s insurance policies contain high policy limits, and in most cases, deductibles (generally ranging from $0 to $1.5 million)$250,000) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, 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.
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'sprovider’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'sCompany’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'sCompany’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 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 ended:
| | | | December 31, | December 31, |
| | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Enterprise Crude Oil, LLC | | 38 | % | | 32 | % | | 16 | % |
| Shell Trading Company | 39 | % | | 45 | % | | 44 | % | 31 | % | | 39 | % | | 45 | % |
| Plains Marketing, L.P. | 15 | % | | 17 | % | | 20 | % | 15 | % | | 15 | % | | 17 | % |
| Enterprise Crude Oil, LLC | 32 | % | | 16 | % | | — | % | |
| Louis Dreyfus Energy Services | 2 | % | | 4 | % | | 13 | % | |
| Other | 12 | % | | 18 | % | | 23 | % | 16 | % | | 14 | % | | 22 | % |
| Total | 100 | % | | 100 | % | | 100 | % | 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 8794 employees as of December 31, 20122013, which included 13 petroleum engineers and four petroleum geoscientists.. 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. TheOil 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 subject to regulation at the federal, state and local level, and somecontinuously being reviewed for amendment or expansion. Some of the laws, rules and regulations that govern our operationsthese requirements carry substantial penalties for non-compliance. Rules and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and the potential for financial sanctions for noncompliance. This regulatory burden increases our cost of doing business and, consequently, affects our profitability.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 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
the valuation and payment of royalties.
For instance, our OCS leases in federal waters are administered by three Bureaus of the Department of Interior "DOI". In response to concerns that the former MMS revenue-generating and resource development functions were at odds with its safety and environmental regulatory functions, the DOI reorganized the MMS into three separate agencies: the BOEM, to be the resource manager for conventional and renewable energy and mineral resources on the OCS; the BSEE, to promote and enforce safety in offshore energy exploration and production operations; and the ONRR, to collect and distribute royalties, rents, fees and other revenues, including the development of regulations with respect to revenue valuation and collection and enforcement activities. In this “Exploration and Production” section, we refer to actions of one or more of the foregoing agencies as actions of “the DOI Bureaus”.
The DOI Bureaus require compliance with detailed regulations and orders. Lessees must obtain DOI Bureau approval for exploration, exploitation and production plans and applications for permits to drill prior to the commencement of such operations. Since the April 20, 2010 blowout and oil spill at the BP Deepwater Horizon Macondo oil well, the DOI Bureaus have issued numerous rules, Notices to Lessees and other guidance documentsaugmenting the existing regulations with more stringent safety, engineering and environmental requirements. The DOI Bureaus have also issued a rule requiring that all operators in the OCS formulate detailed Safety and Environmental Management Systems to improve the safety of their operations on the OCS. Current DOI Bureau regulations restrict the flaring or venting of natural gas, and prohibit the flaring of liquid hydrocarbons and oil without prior authorization. The DOI Bureaus are considering whether to require flaring rather than venting, where practical, to reduce the potential effect of greenhouse gas emissions.
DOI Bureau policies concerning the volume of production that a lessee must have to maintain an offshore lease beyond its primary term also are applicable to Callon. Similarly, the DOI Bureaus have promulgated other regulations and Notices to Lessees governing the plugging and abandonment of wells located offshore and the installation and decommissioning of production facilities. To cover the various obligations of lessees on the OCS, the DOI Bureaus generally requires that lessees post bonds, letters of credit, or other acceptable assurances that such obligations will be met. The cost of these bonds or other surety can be substantial, and there is no assurance that bonds or other surety can be obtained in all cases. Under some circumstances, the DOI Bureaus may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial conditions and results of operations.
As stated above, the April 20, 2010 blowout and oil spill at the BP Deepwater Horizon oil rig has prompted the federal government to impose heightened regulation of oil and natural gas exploration and production on the OCS. Especially with respect to deepwater operations, the DOI Bureaus have issued rules that are more stringent than the rules issued by the MMS, and have announced their intention to issue additional safety rules and be more scrupulous in implementing existing environmental requirements in the future. Legislation has been introduced in the United States Congress to toughen the regulation of oil and natural gas exploration and production on the OCS. In addition, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, whose members were appointed by President Obama, issued a report proposing, among other things, fundamental reform of the regulation of oil and natural gas exploration and production on the OCS. The tightening of regulation on the OCS could impose
higher costs on, and render it more difficult to timely obtain regulatory approval of our proposed activities on the OCS, especially as to deepwater projects.
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 DOIDepartment 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 RegulationMatters and Regulation. . Various federal, stateOur oil and local laws and regulations concerning the release of contaminants into the environment, including the discharge of contaminants into water and the emission of contaminants into the air, the generation, storage, treatment, transportation and disposal of wastes, and the protection of public health, welfare, and safety, and the environment, including natural resources, affect ourgas exploration, development and production operations including operationsare subject to stringent laws and regulations governing the discharge of our processing facilities. We must takematerials into account the costenvironment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency, or the 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 complyinga permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with environmental regulations in planning, designing, drilling, constructing, operating and abandoning wells. Regulatory requirements relate to, among other things, the handling and disposal of drilling and production waste products,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 controlsuspension or revocation of waternecessary permits, licenses and airauthorizations, require that additional pollution controls be installed and the removal, investigation, and remediation of petroleum-product contamination. In addition,impose substantial liabilities for pollution resulting from our operations may requireor 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 to obtain permitsregardless of fault. Moreover, it is not uncommon for among other things,
air emissions,
discharges into surface waters (including wetlands), and
the construction and operations of underground injection wells or surface pits to treat, re-use or dispose of produced waterneighboring landowners and other nonhazardous oilfield wastes.
In the event of an unauthorized discharge (e.g.,third parties to land or water), emission (e.g., to air) or other activity, we may be liablefile claims for among other things, penalties, costspersonal injury and damages, and subject to injunctive relief, and we could be required to cleanup or mitigate the environmental impacts of those discharges, emissions or activities. Also, under federal, and certain state, laws, the present and certain past owners and operators of a site, and persons that treated, disposed of or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, forproperty damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environmentenvironment. Changes in environmental laws anddamage to natural resources caused by such release. The Environmental Protection Agency, state environmental agencies regulations occur frequently, and any changes that result in some cases third parties are authorized to take actions in response to threats to human healthmore stringent and costly pollution control or the environment and to seek to recover from responsible classes of persons the costs of such actions. We therefore could be required to remove or remediate previously disposed wastes and remediate contamination, including contamination in surface water, soil or groundwater, caused by disposal of that waste irrespective of whetherhandling, storage, transport, disposal or release wereunlawful. Wecleanup requirements could be responsible for wastes disposed of or released by us or prior owners or operators at properties owned or leased by us or at locations where wastes have been taken for disposal also irrespective of whether disposal or release were authorized. We could also be required to suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or cleanups to prevent future contamination.
Federal, and certain state, laws also impose duties and liabilities on certain “responsible parties” related specifically to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. These laws assign liability, which generally is joint and several, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses and limitations exist to the liability imposed under these laws, they are limited. In the event of an oil discharge or substantial threat of discharge, we could be liable for costs and damages.
The Environmental Protection Agency and various state agencies have limited the disposal options for hazardous and nonhazardous wastes thereby increasing the costs of disposal. Furthermore, certain wastes generated by our oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements.
Federal and state occupational safety and health laws require us to organize information about hazardous materials used, released or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.
There are federal and certain state laws that impose restrictions on activitiesmaterially adversely affecting the habitat of certain plant and animal species. In the event of an unauthorized impact or taking of a protected species or its habitat, we could be liable for penalties, costs and damages, and subject to injunctive relief, and we could be required to mitigate those impacts. A critical habitat or suitable habitat designation also could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development.
Oil and natural gas exploration and production activities are being subjected to additional regulatory scrutiny under the Clean Air Act (“CAA”). On April 17, 2012, the EPA issued final rules to subject oil and gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured gas wells and also existing gas wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from certain compressors, controllers, dehydrators, storage tanks, natural gas processing plants and other equipment based upon equipment types, locations, and emission thresholds. These rules may require changes toaffect our operations including the installation of new equipment to control emissions.
We have made and will continue to make expenditures to comply with environmental regulations and requirements. These are necessary costs of doing business withinfinancial position, as well as the oil and natural gas industry. Althoughindustry in general. Our management believes that we are not fully insured against all environmental risks, we maintain insurance coverage which we believe is customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensivesubstantial compliance with applicable environmental laws and regulations as well as claims for damages to property or persons resultingand we have not experienced any material adverse effect from company operations, could result in substantial costs and liabilities. We believecompliance with these
environmental requirements. Our management believes that we are in substantial compliance with existingapplicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements.
Waste Handling. The Resource Conservation and Recovery Act, as amended, or RCRA, 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, such wastes may constitute “solid wastes” that absentare subject to the occurrenceless stringent requirements of an extraordinary eventnon-hazardous waste provisions may not be exempt under state programs. However, we cannot assure you that the effect of which cannot be predicted, any noncomplianceEPA 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 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. 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 earnings.regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
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, or 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, 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 the state. 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 certain activity in 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. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. The EPA stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for coalbed methane and shale gas in 2014. 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. 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. 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 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 existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 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. 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”)(GHG) Regulation. Although federal legislation regarding the control of greenhouse gasses, or GHGs, thus far has been unsuccessful, the EPA has moved forward with rulemaking to regulate GHGs as pollutants under the CAA. These GHG regulations may require us to incur increased operating costs and may have an adverse effect on demand for the oil and natural gas we produce.
The EPA, as of January 2, 2011, requires the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs in a multi-step process, with the largest sources first subject to permitting. Those permitting provisions,should they become applicable to our operations, could require controls or other measures to reduce GHG emissions from new or modified sources, and we could incur additional costs to satisfy those requirements. On November 30, 2010, EPA publishedhas adopted a rule establishing GHG reporting requirements for sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions if the total emissions within a basin exceed 25,000 metric tons CO2 equivalent per year. Although this rule does not limit the amount of GHGs that can be emitted, it will requirerequires us to incur costs to monitor, keep records of, and potentially report GHG emissions associated with our operations if the reporting threshold is reached with production growth.
In addition to 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"“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. The 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.
Hydraulic Fracturing. ApplicationHydraulic fracturing is an important common practice that is used to stimulate production of the Safe Drinking Water Act to Hydraulic Fracturing.Congress has considered but has not passed legislation to amend the federal Safe Drinking Water Act to remove the exemption for hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil andhydrocarbons, particularly natural gas, industry in the hydraulic fracturing process. Hydraulic fracturingfrom tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into rock formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or 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. 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, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, 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.
On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production. Sponsorsproduction and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards 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 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 will 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 billsrules 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. For example, on April 12, 2013, the EPA published a proposed amendment extending compliance dates for certain storage vessels. The final revised 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 on May 24, 2013 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 disclsoure 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, the results of which are expected in 2014. 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, have assertedadopted, 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.
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 adversely affect drinking water supplies. A number of state, local and regional regulatory authorities have or are consideringgroundwater. In addition, if hydraulic fracturing regulation. For example, Texas has adopted regulations requiringis further regulated at the disclosure of hydraulicfederal or state level, our fracturing chemicals. Potential federal as well as existingactivities 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 state regulationincreases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the requirementconsequences of any failure to comply by us could negatively affect our ability to conduct fracturing activitieshave a material adverse effect on our assets.
In addition,financial condition and results of operations. At this time, it is not possible to estimate the EPA has recently been taking actions to assertimpact on our business of newly enacted or potential federal regulatory authority overor state legislation governing hydraulic fracturing using diesel under the Safe Drinking Water Act's Underground Injection Control Program. Further, in March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. A progress report was issued in December 2012, with final results expected in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming. This study remains subject to review. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Consequently, these studies and initiatives could spur further legislative or regulatory action regarding hydraulic fracturing or other production operations. Further, the BLM has indicated that it will engage in rulemaking to regulate hydraulic fracturing on federal lands.
Further, EPA has announced an initiative under the Toxic Substances Control Act (“TSCA”) to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals.
All of the acreage and undeveloped reserves within the Permian basin are subject to hydraulic fracturing procedures as the process is required to economically develop the Wolfberry formation. The hydraulic fracturing process is integral to the Company's overall drilling and completion costs in the Permian basin and represented approximately 34% or $0.8 million of the total drilling/completion costs per vertical well drilled during 2012.
The hydraulic fracturing activity is limited to the oil and natural gas bearing formations, which are found at depths ranging between 6,000 and 12,000 feet from the surface in Midland, Ector and Upton counties, Texas. The Railroad Commission of Texas has defined potable water sources in this area as usable-quality ground water from the surface to a depth of 250 feet for our acreage in Midland and Ector counties and to a depth of 425 feet for our acreage in Upton counties.
The Company diligently reviews best practices and industry standards, and complies with all regulatory requirements in the protection of these potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time, and disposing of all non-commercially produced fluids in certified disposal wells at depths below the potable water sources.
Based on current drilling techniques, a typical fracturing procedure for a vertical well in the Wolfberry formation uses approximately 1.8 million gallons of fresh water, approximately 1.2 million pounds of sand and other elements including enzymes and guar, a common food additive. Horizontal wells typically use 9.5 million gallons of water and approximately 6.2 million pounds of sand.
In compliance with the law enacted in Texas in June 2011 and regulations adopted in December 2011, the Company will disclose hydraulic fracturing data to the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission chemical registry effective January 2, 2012. This disclosure is required for each chemical ingredient that is subject to the requirements of OSHA regulations, as well as the total volume of water used in the hydraulic fracturing treatment. A copy of the completed form is uploaded into the Chemical Disclosure Registry also known as FracFocus, which is a publically accessible website.
There have not been any incidents, citations or suits related to the Company's hydraulic fracturing activities involving environmental concerns.
The Federal Water Pollution Control Act, also known as the “Clean Water Act” and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S.
Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and cleanup and response costs.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, or 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’ 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, it may adversely impact the value of the affected leases.
Mineral LeaseLeasing 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"(“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 interestsan interest in numerous federal onshore oil and natural gas leases.leaseholds in Nevada. It is possible that holders of the Company'sCompany’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 RegulationsRegulation of the Oil and Natural Gas Industry. . If we conduct operations on federal, state or IndianThe oil and natural gas leases,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 and sale for resale 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 the price and 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 prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas 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 and 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 release of our 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 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 comply with numerousbe 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.
Oil and NGLs Sales and Transportation. Sales of oil and condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory restrictions,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.
State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including various nondiscrimination statutes, royaltyimposing severance taxes and related valuation requirements. Certainrequirements 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 operations mustregulations may be conducted pursuant to certain on-site securitylimit 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.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and other appropriate permits issued by the BLM, the Bureaulaws. Some of Ocean Energy Management, the Bureau of Safetythose laws relate to resource conservation and Environmental Enforcement, or other appropriate federal, state, or tribal agencies.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'sCompany’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 policespolicies included, and claims for damages to property, employees, other persons, and the environment resulting from the Company'sCompany’s operations could have on its activities. See Note 1513 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'sSEC’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. 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 Facility;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.
Natural gas prices have been depressed recentlyAny substantial and haveextended decline in the potential to remain depressed for the next several years, which may have an adverse effect on our financial condition and resultsprice of operations. Natural gas prices have been depressed for the last several years as a result of over-supply caused by, among other things, increased drilling in unconventional reservoirs, reduced economic activity associated with a recession and weather conditions. We expectoil or natural gas prices to be depressed during the foreseeable future. Approximately 23% of our estimated net proved reserves at December 31, 2012 are natural gas, and 38% of our production in 2012 was natural gas. A sustained reduction in natural gas prices could have an adverse effect on our results of operationsborrowing capacity, our ability to obtain additional capital, and financial condition.our revenues, profitability and cash flows.
If oil and natural gas prices decrease orand remain depressed for extended periods of time, we may be required to take additional writedowns of the carrying value of our oil and natural gas properties. We may be required to writedown the carrying value of our oil and natural gas properties when oil and natural gas prices are low or if we have substantial downward adjustments to our estimated net proved reserves, increases in our estimates of development costs or if we experience deterioration in our exploration results.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'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'stockholders’ equity. We review the carrying value of our properties quarterly based on the pricing noted above. Onceand once incurred, a writedown of oil and natural gas properties is not reversible at a later date, even if prices increase. See Note 1412 to our Consolidated Financial Statements.
Our actual recovery of reserves may substantially differ from our proved reserve estimates.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. Additionally, our interpretationsIn addition, drilling, testing and production data acquired since the date of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities.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 based on historical performance and expected future operation investment activities;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 producingestimated net proved reserves contained in this Form 10-K represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 20122013 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, 20122013, approximately 14%33% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented 52%50% of total proved reserves by volume, and approximately 18% of our PUDs were attributable to our deepwater property.volume. Recovery of undeveloped reservesPUDs 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 are ablereplace 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 that we have produced,through drilling or acquisitions, our production, revenues, reserve quantities and cash flows and production will decrease over time. The high-rate production characteristics of our Gulf of Mexico properties subject us to high reserve replacement needs.decline. In general, the volume of production from oil and natural gas properties declines as reserves are depleted. Thedepleted, with the rate of decline rates dependdepending on reservoir characteristics. GulfOur ability to make the necessary capital investment to maintain or expand our asset base of Mexico reservoirs tendoil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be recovered quickly through production with associated steep declines, while declinessuccessful in other regions after initial flush production tend to be relatively low. Our Gulf of Mexico, deepwater properties accountedexploring for, approximately 38% of our production which included the Habanero property during 2012 and 28% of our estimated proved reserves at December 31, 2012 excluding the Habanero property. Similarly, our Gulf of Mexico shelf properties accounted for approximately 22% of our production during 2012 and 4% of our estimated proved reserves at December 31, 2012. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future natural gas and oil production is highly dependent upon our level of success in findingdeveloping or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices. Without successful exploration or acquisition activities, our reserves, production and revenues will decline.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. The incrementalIf 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 2013, our total capital expenditures, including expenditures for leasehold interests and property acquisitions, drilling, seismic and infrastructure, were approximately $171 million. Our 2014 capital budget for drilling, completion and infrastructure is estimated to be approximately $185 million. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, greater measured depthsamong 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 hydraulic fracture stages in horizontal wellbores. We cannot assure you thatcapital 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 future exploitation, exploration, development, and acquisition activities willrevolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in additionala 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 ablerequired to drill productive wells at acceptable costs. We cannot assure youuse 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 0.75% 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 facility bears interest at a rate of LIBOR plus 7.75%. If interest rates increase, so will be able to findour interest costs, which may have a material adverse effect on our results of operations and develop or acquire additional reserves at an acceptable cost.financial condition.
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. Our industry is cyclical and, fromFrom time to time, there isour 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.
A significant portionOur 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 productiondrilling and reserves is concentratedhydraulic fracturing processes. Historically, we have been able to secure water from local landowners and other sources for use in our deepwater offshore property,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 any production problems or inaccuracieshydraulic fracturing to protect the local water supply. If we are unable to obtain water to use in reserve estimates relatedour operations from local sources, we may be unable to this property would adversely impacteconomically produce oil, NGLs and natural gas, which could have an adverse effect on our business. During 2012, approximately 29%business, financial condition and results of our daily production came from our Medusa field, which is currently our only deepwater propertyoperations.
Our producing properties are located in the GulfPermian Basin of Mexico.West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, atwe have a large amount of proved reserves attributable to a small number of producing horizons within this area. December 31, 2012, approximately 28%All of our total net proved reserves were located within this field. If mechanical problems, storms or other events curtailedproducing properties are geographically concentrated in the Permian Basin of West Texas. As a substantial portionresult 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 iftransportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the actual reserves associatedprocessing 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 this producing property are less thangreater frequency or magnify the effects of these conditions. Due to the concentrated nature of our estimated reserves,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 andthan 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 could be adversely affected.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. During 2012, we purchased 24,32821,419 net acres in the northern portion of theNorthern Midland basin, an area that has seen only limited developmentdrilling activity. We expect to conduct substantialcontinue exploration of this acreage over the next several years. Although we have been successful in exploration in the past, we cannot assure you that we will continueyears, although our position is subject to increase reservesmeaningful lease expirations through exploration or at an acceptable cost. Additionally, we are often uncertain as to the future costs and timing of drilling, completing and producing wells.2015. 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;
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;
our ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks;
decisions of our joint working interest owners; 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. Our ability to achieve our target results are dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.
In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. The cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling, and 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.
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 business segment or 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'smanagement’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.
There is competition for available oil and natural gas properties. Our competitors include major oil and gas companies, independent oil and gas companies and financial buyers. Some of our competitors may have greater and more diverse resources than we do. High commodity prices and stiff competition for acquisitions have in the past, and may in the future, significantly increase the cost of available properties. The increased competition and rising prices for available properties could limit or impede our ability to identify acquisition opportunities that are economic for a company our size and that are necessary to grow our reserves or replace reserves produced.
We do not operate and have limited influence over the operations of our deepwater property. Our lack of control could result in the following:
the operator may initiate exploration or development at a faster or slower pace than we prefer or that we anticipate in preparing our reserve estimates;
the operator may propose to drill more wells or build more facilities on a project than we have funds for or that we deem appropriate, which may mean that we are unable to participate in the project or share in the revenues generated by the project even though we paid our share of exploration costs; and
if an operator refuses to initiate a project, we may be unable to pursue the project.
Any of these events could materially impact the value of our non-operated properties.
Weather, unexpectedUnexpected 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;
hurricanes, 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.
If we experience any of these problems, it could affect well bores, platforms, 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.
Offshore operations are also subject to a variety of additional operating risks peculiar to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for development or leasehold acquisitions, or result in loss of equipment and properties.
We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells for which we are the operator. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under federal and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. In March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. A progress report was issued in December 2012, with final results expected in 2014. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative, could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
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;
the proximity of the natural gas production to natural gas and NGL pipelines;
the availability of pipeline capacity;
the demand for oil and natural gas by utilities and other end users;
the availability of alternative fuel sources;
the effects of inclement weather;
state and federal regulation of oil and natural gas marketing; and
federal regulation of natural gas sold or transported in interstate commerce.
In particular, in areas with increasing non-conventional shale drilling activity, capacity may be limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built.
Part of our strategy involves drilling in new or emerging shale formations using horizontal drilling and completion techniques. The results of our planned drilling program in these formations may be subject to more uncertainties than conventional drilling programs in more established formations and may not meet our expectations for reserves or production. The results of our recent horizontal drilling efforts in new or emerging formations, including the Wolfcamp shale, Cline shale, and Mississippian lime in the Permian basin, are generally more uncertain than drilling results in areas that are developed and have established production. Because new or emerging formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis predict our future drilling results. The ultimate success of these drilling and completion strategies and techniques will be better evaluated over time as more wells are drilled and production profiles are better established. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated
or we are unable to execute our drilling program because of capital constraints, access to gathering systems and takeaway capacity or otherwise, and/or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material writedowns of unevaluated properties and the value of our undeveloped acreage could decline in the future.
The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas from proved properties and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees and our third party consultants, none of whom are subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.
We may not be insured against all of the operating risks to which our business inis exposed. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover losses or liabilities. We experienced Gulf of Mexico production interruption in 2005, 2006, 2007, and 2012 from Hurricanes Katrina, Rita, and Isaac and in 2008 and 2009 from Hurricanes Gustav and Ike for which we had no production interruption insurance. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable and may elect none or minimal insurance coverage. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse affecteffect on our financial condition and operations.
Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous independents,financial buyers, including many that have significantly greater resources. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. Factors that affect our ability to compete in the marketplace include:
our access to the capital necessary to drill wells and acquire properties;
our ability to acquire and analyze seismic, geological and other information relating to a property;
our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;
our ability to procure materials, equipment and services required to explore, develop and operate our properties, including the ability to procure fracture stimulation services on wells drilled; and
our ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production.
Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
During 2010, the President signed into lawTitle VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”). Among other things, the Act establishes federal oversight and regulation of over-the-counter derivatives and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market.
In its rulemaking under the new legislation, the CFTC has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions); the CFTC'sCFTC’s final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the CFTC to resolve ambiguity as to whether statutory requirements for such limits to be determined
necessary and appropriate were satisfied. As a result, the rule has not yet taken effect, althoughThe CFTC appealed this ruling but subsequently withdrew its appeal. On November 5, 2013, the CFTC has indicated that it intendsapproved a Notice of Proposed Rulemaking designed to appeal the court's decision and that it believes the Dodd-Frank Act requires it to imposeimplement new position limits.limits regulation. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions.
In addition, theThe Act does not explicitly exemptprovides a limited exception to end users (such as us) from the requirement to use cleared exchanges, rather than hedging over-the-counter and authorizes the CFTC to set requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when the CFTC will finalize certain other related rules and regulations, the Act and related regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although whether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain
capital levels, the cost of which could be passed through to us, or impose other requirements that are more burdensome than current regulations, our hedging transactions in the future would become more expensive andthan we may decide to alter our hedging strategy.
The financial reform legislation may also requireexperienced in the counterparties to derivative instruments to spin off some of their derivative activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts reduce the availability of derivatives to protect against risks we encounter, restrict our flexibility in conducting trading and hedging activity and increase our exposure to less creditworthy counterparties. If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural-gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.past.
We may not have production to offset hedges; by hedging, we may not benefit from price increases.hedges. Part of our business strategy is to reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged. Additionally, we are required to pay the difference between the floating price and the fixed price when the floating price exceeds the fixed price regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of production.
By hedging, we may not benefit from price increases. Hedging will alsocan prevent us from receiving the full advantage of increases in oil or natural gas prices above the fixed amount specified in a hedge transaction in the hedge.
case of a swap. We also enter into price “collars” to reduce the risk of changes in oil and natural gas prices. Under a collar, no payments are due by either party so long as the market price is above a floor set in the collar and below a ceiling. If the price falls below the floor, the counter-party to the collar pays the difference to us and if the price is above the ceiling, we pay the counter-party the difference. Another type of hedging contract we have entered into is a put contract. Under a put, if the price falls below the set floor price, the counter-party to the contract pays the difference to us. See “Quantitative and Qualitative Disclosures About Market Risks” for a discussion of our hedging practices.
Our hedging transactions expose us to counterparty credit risk.Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.
The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results. Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production, which we market to energy marketing companies, refineries and affiliates, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 38% of our total oil and natural gas revenues for the year ended December 31, 2013. We do not require any of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Joint interest receivables arise from billing entities who own a partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells.
Compliance with environmental and other government regulations could be costly and could negatively impact production. Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment or otherwise relating to environmental protection. For a discussion of the material regulations applicable to us, see “Regulations.” These laws and regulations may:
require that we acquire permits before commencing drilling;
impose operational, emissions control and other conditions on our activities;
restrict the substances that can be released into the environment in connection with drilling and production activities;
limit or prohibit drilling activities on protected areas such as wetlands and wilderness areas or coral reefs;areas; and
require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned production facilities.
Under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of and increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. We could also be affected by more stringent laws and regulations adopted in the future, including any related climate change, greenhouse gases and hydraulic fracturing. Under the common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from properties in the event of environmental incidents.
Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for the oil and natural gas we produce. The EPA has adopted its so-called "GHG“GHG tailoring rule"rule” that will phasephases in federal PSD permit requirements for greenhouse gasGHG emissions from new sources and modification of existing sources, federal Title V operating permit requirements for all sources, based upon their potential to emit specific quantities of GHGs. These permitting provisions to the extent applicable to our operations could require us to implement emission controls or other measures to reduce GHG emissions and we could incur additional costs to satisfy those requirements.
In addition, on October 30, 2009,, the EPA published a final rule requiringrequires the reporting of greenhouse gasGHG emissions from specified large greenhouse gasGHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. OnIn November 30, 2010, the EPA published its amendments to the greenhouse gasGHG reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. Reporting of greenhouse gasGHG emissions from such facilities is required on an annual basis, beginning in 2012 for emissions occurring in 2011, if the total emissions within a basin exceed 25,000 metric tons CO2 equivalent per year. year. We will have to incur costs associated with this monitoring obligation and potentially additional reporting costs if production growth triggers the emission threshold.
In addition, the United States Congress has considered legislation to reduce emissions of GHGs and many states have already taken or have considered legal measures to reduce or measure GHG emissions, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs would require major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. These allowances would be expected to escalate significantly in cost over time. The adoption and implementation of any legislation or regulatory programs imposing GHG reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGS associated with our operations or could adversely affect demand for the oil and natural gas that we produce.
Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects. In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanesstorms and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect affect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. Should drought conditions occur, our ability to obtain water in sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.
Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions but is not subject to regulation at the federal level (except for fracturing activity involving the use of diesel). TheWe engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells for which we are the operator. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result
in fines, penalties, and remediation costs, among other sanctions and liabilities under federal and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. In March 2010, the EPA has commencedannounced that it would conduct a wide-ranging study ofon the potential environmental impactseffects of hydraulic fracturing activities.on drinking water resources. A progress report was issued in December 2012, andwith final results anticipatedexpected in 2014. In addition,The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative, could result in December 2011, the EPA published an unrelated draft report concludingadditional regulatory scrutiny that could make it difficult to perform hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming; this study remains subject to review. and increase our costs of compliance and doing business.
A committee of the U.S. House of Representatives conducted an investigation of hydraulic fracturing practices. Legislation was introduced before Congress, but not passed to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states and local or regional regulatory authorities have adopted or are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has imposed a de facto moratorium on the issuance of permits for high-volume, horizontal hydraulic fracturing until state-administered environmental studies are finalized. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. While we have no operations in either New York or Pennsylvania, any other new laws or regulations that significantly restrict hydraulic fracturing in areas in which we do operate could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect the determination of whether a well is commercially viable. Further, EPA has announced an initiativeinitiatives under the CWA to establish standards of wastewater from hydraulic fracturing and under TSCA to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals, and the BLM has indicated that it will continue with rulemaking to regulate hydraulic fracturing on federal lands. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional
permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.
Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation. In recent years, the Obama administration'sadministration’s budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for U.S. production activities and (4) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect the Company'sCompany’s financial condition and results of operations.
There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected. Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.
We have no plans to pay cash dividends on our common stock in the foreseeable future.We have no plans to pay cash dividends in the foreseeable future. Any future determination as to the declaration and payment of cash dividends will be at the discretion of our board of directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our board of directors. In addition, the terms of our credit facilities prohibit us from paying dividends and making other distributions.
Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations. Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.
While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.
ITEM 1B. Unresolved Staff Comments
None.
ITEM 3. Legal Proceedings
We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our financial position or results of operations.
ITEM 4. Mine Safety Disclosures
Not applicable.
PART II.
ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The Company’sMarket Information
Our common stock trades on the New York Stock Exchange under the symbol "CPE"“CPE”. The following table sets forth the high and low sale prices per share as reported for the periods indicated.
| | | | | | | | | | | | | Stock Price |
| | | | | | | Stock Price | | 2013 | | 2012 |
| | | 2012 | | | | High | | Low | | High | | Low | | High | | Low |
| First quarter | | ended | | March 31, 2012 | | $ | 7.95 |
| | $ | 5.09 |
| | $ | 5.82 |
| | $ | 3.62 |
| | $ | 7.95 |
| | $ | 5.09 |
|
| Second quarter | | ended | | June 30, 2012 | | 6.45 |
| | 3.80 |
| | 4.00 |
| | 3.19 |
| | 6.45 |
| | 3.80 |
|
| Third quarter | | ended | | September 30, 2012 | | 6.55 |
| | 4.11 |
| | 5.49 |
| | 3.40 |
| | 6.55 |
| | 4.11 |
|
| Fourth quarter | | ended | | December 31, 2012 | | 6.36 |
| | 4.05 |
| | 7.60 |
| | 5.18 |
| | 6.36 |
| | 4.05 |
|
| | | | | | |
| | | 2011 | | | | |
| | |
| |
| First quarter | | ended | | March 31, 2011 | | $ | 9.36 |
| | $ | 5.81 |
| |
| Second quarter | | ended | | June 30, 2011 | | 8.04 |
| | 5.93 |
| |
| Third quarter | | ended | | September 30, 2011 | | 7.73 |
| | 3.79 |
| |
| Fourth quarter | | ended | | December 31, 2011 | | 5.99 |
| | 3.02 |
| |
Holders
As of March 1, 201310, 2014 the Company had approximately 3,2293,111 common stockholders of record.
The Company has neverDividends
We have not paid any cash dividends on itsour common stock to date and intendspresently do not expect to retain itsdeclare or pay any cash flow fromdividends on our common stock in the foreseeable future as we intend to reinvest our cash flows and earnings into our business. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors.
Holders of our Series A preferred stock are entitled to a cumulative dividend whether or not declared, of $5.00 per annum, payable quarterly, equivalent to 10% of the liquidation preference of $50.00 per share. Unless the full amount of the dividends for the future operation and development of its business.Series A Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock. In addition, the Company’s Credit Facility and the termscertain of our outstanding debt prohibitfacilities contain restrictions on the payment of cash dividends onto the holders of our common stock.
During the fourth quarter of 20122013, neither the Company nor any affiliated purchasers made repurchases of Callon’s equity securities.
Equity Compensation Plan Information
The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 20122013 (securities amounts are presented in thousands).
| | | | | Outstanding Options | | | | Outstanding Options | | |
| Plan Category | | Number of securities to be issued upon exercise of outstanding options | | Weighted-average exercise price of outstanding options | | Number of securities remaining available for future issuance under equity compensation plans | | Number of securities to be issued upon exercise of outstanding options | | Weighted-average exercise price of outstanding options | | Number of securities remaining available for future issuance under equity compensation plans |
| Equity compensation plans approved by security holders | | 37 |
| | $ | 13.51 |
| | 1,669 |
| | 37 |
| | $ | 13.51 |
| | 1,192 |
|
| Equity compensation plans not approved by security holders | | 30 |
| | 7.90 |
| | — |
| | 15 |
| | 14.37 |
| | — |
|
| Total | | 67 |
| | 11.82 |
| | 1,669 |
| | 52 |
| | 13.75 |
| | 1,192 |
|
For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 87 and 98 to the Consolidated Financial Statements.
Performance Graph
The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to twofour broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The
Consistent with the Company’s prior year performance graph, the graph below compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the New York Stock Exchange Market Index and of the Morningstar GroupNew York Stock Exchange Market Index (consisting of independent oil and gas drilling and exploration companies) from December 31, 20072008, through December 31, 20122013. The Company plans to replace these indexes with S&P 500 Index and the SIG Oil Exploration & Production Index, which is believes provides a more meaningful comparison and is reflective of the indexes more commonly used by the Company’s peer group. Consequently, these indexes have also been added to the graph below, and we expect will be used in future year’s performance graphs.
The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.
Comparison of Five Year Cumulative Total Return
Assumes Initial Investment of $100
December 2013
| | | | | For the Year Ended December 31, | | For the Year Ended December 31, |
| Company/Market/Peer Group | | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | | 2013 |
| Callon Petroleum Company | | $ | 100.00 |
| | $ | 15.81 |
| | $ | 9.12 |
| | $ | 35.99 |
| | $ | 30.21 |
| | $ | 28.57 |
| | $ | 100.00 |
| | $ | 57.69 |
| | $ | 227.69 |
| | $ | 191.15 |
| | $ | 180.77 |
| | $ | 251.15 |
|
| S&P 500 Index - Total Returns | | | 100.00 |
| | 126.46 |
| | 145.51 |
| | 148.59 |
| | 172.37 |
| | 228.19 |
|
| NYSE Composite Index | | 100.00 |
| | 60.86 |
| | 78.25 |
| | 88.89 |
| | 85.63 |
| | 99.47 |
| | 100.00 |
| | 128.95 |
| | 146.69 |
| | 141.46 |
| | 164.45 |
| | 207.85 |
|
| SIG Oil Exploration & Production Index | | | 100.00 |
| | 161.62 |
| | 198.98 |
| | 180.95 |
| | 168.41 |
| | 213.16 |
|
| Morningstar Group Index | | 100.00 |
| | 39.51 |
| | 71.28 |
| | 74.52 |
| | 64.64 |
| | 71.97 |
| | 100.00 |
| | 185.22 |
| | 194.51 |
| | 167.95 |
| | 189.60 |
| | 216.25 |
|
ITEM 6. Selected Financial Data
The following table sets forth, as of the dates and for the periods indicated, selected financial information about us. The financial information for each of the five years in the period ended December 31, 20122013 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations"Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results. The information included in this table for the year ended December 31, 2011 include the effects of corrections on the previously reported financial statements, as further discussed in Note 1 to the Consolidated Financial Statements included in Part II, Item 8 of this filing.
| | | | For the year ended December 31, | For the year ended December 31, |
| | 2012 | | 2011 | | 2010 | | 2009 | | 2008 | 2013 | | 2012 | | 2011 | | 2010 | | 2009 |
| Statement of Operations Data: | (In thousands, except per share amounts) | (In thousands, except per share amounts) |
| Operating revenues: | | | | | | | | | | | | | | | | | | |
| Oil and natural gas sales | $ | 110,733 |
| | $ | 127,644 |
| | $ | 89,882 |
| | $ | 101,259 |
| | $ | 141,312 |
| $ | 102,569 |
| | $ | 110,733 |
| | $ | 127,644 |
| | $ | 89,882 |
| | $ | 101,259 |
|
| Medusa BOEM royalty recoupment (a) | — |
| | — |
| | — |
| | 40,886 |
| | — |
| — |
| | — |
| | — |
| | — |
| | 40,886 |
|
| Total operating revenues | $ | 110,733 |
| | $ | 127,644 |
| | $ | 89,882 |
| | $ | 142,145 |
| | $ | 141,312 |
| $ | 102,569 |
| | $ | 110,733 |
| | $ | 127,644 |
| | $ | 89,882 |
| | $ | 142,145 |
|
| Operating expenses: | | | | | | | | | | |
| Non-impairment related operating expenses | $ | 100,043 |
| | $ | 88,022 |
| | $ | 68,703 |
| | $ | 68,692 |
| | $ | 97,497 |
| |
| Impairment of oil and gas properties (b) | — |
| | — |
| | — |
| | — |
| | 485,498 |
| |
| Total operating expenses | $ | 100,043 |
| | $ | 88,022 |
| | $ | 68,703 |
| | $ | 68,692 |
| | $ | 582,995 |
| $ | 91,905 |
| | $ | 100,043 |
| | $ | 88,022 |
| | $ | 68,692 |
| | $ | 68,692 |
|
| Income (loss) from continuing operations | 10,690 |
| | 39,622 |
| | 21,179 |
| | 73,453 |
| | (441,683 | ) | 10,664 |
| | 10,690 |
| | 39,622 |
| | 21,179 |
| | 73,453 |
|
| Net income (loss) (c) | 2,747 |
| | 106,396 |
| | 8,386 |
| | 46,796 |
| | (438,893 | ) | |
| Net income (loss) (b) | | 4,304 |
| | 2,747 |
| | 106,396 |
| | 8,386 |
| | 46,796 |
|
| Earnings (loss) per share ("EPS"): | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Basic | $ | 0.07 |
| | $ | 2.81 |
| | $ | 0.29 |
| | $ | 2.12 |
| | $ | (20.68 | ) | $ | (0.01 | ) | | $ | 0.07 |
| | $ | 2.81 |
| | $ | 0.29 |
| | $ | 2.12 |
|
| Diluted | $ | 0.07 |
| | $ | 2.76 |
| | $ | 0.28 |
| | $ | 2.11 |
| | $ | (20.68 | ) | $ | (0.01 | ) | | $ | 0.07 |
| | $ | 2.76 |
| | $ | 0.28 |
| | $ | 2.11 |
|
| Weighted average number of shares outstanding for Basic EPS | 39,522 |
| | 37,908 |
| | 28,817 |
| | 22,072 |
| | 21,222 |
| 40,133 |
| | 39,522 |
| | 37,908 |
| | 28,817 |
| | 22,072 |
|
| Weighted average number of shares outstanding for Diluted EPS | 40,337 |
| | 38,582 |
| | 29,476 |
| | 22,200 |
| | 21,222 |
| 40,133 |
| | 40,337 |
| | 38,582 |
| | 29,476 |
| | 22,200 |
|
| Statement of Cash Flows Data: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Net cash provided by operating activities | $ | 51,290 |
| | $ | 79,167 |
| | $ | 100,102 |
| | $ | 19,698 |
| | $ | 89,054 |
| $ | 54,329 |
| | $ | 51,290 |
| | $ | 79,167 |
| | $ | 100,102 |
| | $ | 19,698 |
|
| Net cash used in investing activities | (93,703 | ) | | (91,511 | ) | | (59,738 | ) | | (43,189 | ) | | (4,511 | ) | (79,804 | ) | | (93,703 | ) | | (91,511 | ) | | (59,738 | ) | | (43,189 | ) |
| Net cash provided by (used in) financing activities | (243 | ) | | 38,703 |
| | (26,252 | ) | | 10,000 |
| | (120,667 | ) | 27,348 |
| | (243 | ) | | 38,703 |
| | (26,252 | ) | | 10,000 |
|
| Balance Sheet Data: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Oil and natural gas properties, net | $ | 269,521 |
| | $ | 215,912 |
| | $ | 168,868 |
| | $ | 130,608 |
| | $ | 159,252 |
| |
| Oil and gas properties, net | | $ | 324,187 |
| | $ | 269,521 |
| | $ | 215,912 |
| | $ | 168,868 |
| | $ | 130,608 |
|
| Total assets | 378,173 |
| | 369,707 |
| | 218,326 |
| | 227,991 |
| | 266,090 |
| 423,953 |
| | 378,173 |
| | 369,707 |
| | 218,326 |
| | 227,991 |
|
| Long-term debt (d) | 120,668 |
| | 125,345 |
| | 165,504 |
| | 179,174 |
| | 272,855 |
| |
| Stockholder' equity (deficit) | 205,971 |
| | 201,202 |
| | 15,810 |
| | (80,854 | ) | | (129,804 | ) | |
| Long-term debt (c) | | 75,748 |
| | 120,668 |
| | 125,345 |
| | 165,504 |
| | 179,174 |
|
| Stockholders' equity (deficit) | | 279,094 |
| | 205,971 |
| | 201,202 |
| | 15,810 |
| | (80,854 | ) |
| Proved Reserves Data: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Total oil (MMBbls) | 10,780 |
| | 10,075 |
| | 8,149 |
| | 6,479 |
| | 6,027 |
| 11,898 |
| | 10,780 |
| | 10,075 |
| | 8,149 |
| | 6,479 |
|
| Total natural gas (MMcf) | 19,753 |
| | 35,118 |
| | 32,957 |
| | 19,103 |
| | 18,652 |
| 17,751 |
| | 19,753 |
| | 35,118 |
| | 32,957 |
| | 19,103 |
|
| Total proved reserves (MBoe) | 14,072 |
| | 15,928 |
| | 13,641 |
| | 9,663 |
| | 9,136 |
| |
| Standardized measure | $ | 231,148 |
| | $ | 270,357 |
| | $ | 198,916 |
| | $ | 135,921 |
| | $ | 86,305 |
| |
| Total proved reserves (MBOE) | | 14,857 |
| | 14,072 |
| | 15,928 |
| | 13,641 |
| | 9,663 |
|
| Standardized measure (d) | | $ | 283,946 |
| | $ | 231,148 |
| | $ | 270,357 |
| | $ | 198,916 |
| | $ | 135,921 |
|
| |
| (a) | Following the decisions resulting from several court cases brought by another oil and gas company, the court ruled that the BOEM was not entitled to receive these royalty payments. The amount above reflects royalty recoupments for production from the fields 2003 inception through December 31, 2008, which were accrued at December 31, 2009 and paid by the BOEM during 2010. |
| |
| (b) | In 2008, the Company recorded a $485.5 million impairment of oil and gas properties as a result of the ceiling test. See Notes 2 and 12 to the Consolidated Financial Statements for a description of the relevant accounting policy and the Company’s oil and gas properties disclosures, respectively.
|
| |
(c) | Net income for 2011 includes $69.3 million of income tax benefit related to the reversal of the Company'sCompany’s deferred tax asset valuation allowance. See Note 1110 for additional information. |
| |
(d)(c) | 20122013 and 20112012 long-term debt includes a non-cash deferred credit of $13,7075,267 and $18,38413,707, respectively that will be amortized into earnings as a reduction to interest expense over the life of the 13% Senior Notes due 2016. See Note 54 for additional information.
|
| |
| (d) | Standardized measure is the future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet. Prices are based on either the preceding 12-months’ average price, based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. Future production and development costs are based on current estimates with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% discount rate. |
ITEM 7. Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations
General
The following management'smanagement’s discussion and analysis is intended to assist in understanding the principal factors affecting the Company'sCompany’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing.
We have been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. In 2009, we began to shift our operational focus from exploration in the Gulf of Mexico to building an onshore asset portfolio in order to provide a multi-year, low-risk drilling program in both oil and natural gas basins. This onshore transition has been, and is expected to continue to be, primarily funded by reinvesting the cash flows from our Gulf of Mexico properties including, as previously discussed, the proceeds from the monetization of our interest in the deepwater Habanero field in the fourth quarter of 2012.
Well count information is presented gross unless otherwise indicated.
Overview and Outlook
During 2012, Callon realized net income and fully diluted earnings per share of $2.7 million and $0.07, respectively, compared to net income of $106.4 million and fully diluted earnings per share of $2.76, respectively for 2011. Net income during 2011 benefited significantly from an income tax benefit of $69.3 million, that related primarily to the full reversal of a valuation allowance we previously recorded against our deferred tax assets (see Note 11 for additional information). The Company’s earnings, and the drivers of these earnings, are discussed in greater detail within the “Results of Operations” section included below.
During 2012, the Company continued to transition its asset base from primarily offshore to primarily onshore, seeking to replace high volume offshore production with long-lived onshore crude oil production. In addition to building upon its portfolio of unconventional drilling opportunities with a crude oil focus, the Company continued to expand upon its expertise as an onshore operator in the Permian basin while maintaining a strong financial position to facilitate future growth. Significant accomplishments for 20122013 include:
Increased 20122013 Permian basinBasin annual production by 67%38% to 591 Mboe813 MBOE as compared to 20112012,;
Exceeded our “exit rate” target production rate for 2013, producing 3,611 BOE/d from our Permian operations in the month of December;
Increased 20122013 Permian basinBasin proved reserves by 24%58% to 9.4 MMboe14.9 MMBOE as compared to 20112012,;
Increased 2012Replaced 708% of Permian basin leasehold position by 246% to 32,962production with net Permian proved reserve additions, net of revisions;
Drilled a total of 17 horizontal wells in the Southern Midland Basin, producing from two established zones in the Wolfcamp B and the Wolfcamp A;
Acquired our Garrison Draw field inclusive of 2,186 net acres as comparedand associated production in Reagan County for $11 million, which further added to 2011,
Commenced theour inventory of horizontal development of our East Bloxom field in the southern portion of the Midland basin, withwell locations. Subsequently, we expanded this acreage position to accommodate the drilling of two horizontal wells targeting the Wolfcamp B shale. The average initial (24-hour) production rate from these two wells was 801 Boe per day, with an oil composition of 83%,
long laterals;Commenced the evaluation of our newly acquired northern Midland acreage position, testing numerous vertical and horizontal development concepts,
Accelerated offshore cash flows for onshore redeployment with the sale of our interest in the Habanero fieldMedusa and our remaining shelf fields for $39.4$100 million, before customary purchase price adjustments, and
Raised $70.0 million from the issuance of Series A Cumulative Preferred Stock,
ExpandedRetired 50% of our lending bank groupSenior Notes, improving our cost of capital, and
Received the Midland Bruno Hanson/Midland College Award for Environmental Excellence recognizing our commitment to five institutions and increased our Credit Facility size by $20.0 million or 44% as compared to December 31, 2011.
strong environmental stewardship in the Permian Basin.
Permian Production Growth and Well Counts
|
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
HighlightsFollowing the sale of our onshore activityremaining offshore and Gulf of Mexico operations include:
Onshore - Permian Basin
We expect that our production and reserve growth initiatives will continue to focus primarily on the Permian basin, in which we own approximately 38,127 gross (32,962 net) acres as of December 31, 2012.
Southern Portion: We currently own approximately 11,345 net acres in the southern portion of the Permian basin, an increase of 19% since year-end 2011. Our current production in the southern Midland basin (Crockett, Ector, Glasscock, Midland, and Upton counties in Texas) is primarily from the Wolfberry play, although we added production volumes from the horizontal development of the Wolfcamp B shale during 2012.
During 2012, we drilled 15 vertical wells and completed 22 vertical wells. As part of this program, we tested deeper target zones below the AtokaHaynesville properties in the fourth quarter of 2012. Based on the results2013, all of this test, weour producing properties are currently planning to add these deeper zones to our ongoing vertical Wolfberry-type drilling and completion program at our Pecan Acres and Carpe Diem fields.
In addition to this vertical drilling program, we commenced a horizontal oil shale drilling program at our East Bloxom fieldlocated in the second quarter of 2012, initially targetingPermian Basin. Our production in the Wolfcamp B formation. In 2012, we drilled and completed two horizontal wells on this acreage position, each with a lateral length of over 7,100 feet. In the first quarter of 2013, we drilled an additional three horizontal Wolfcamp shale wells at East Bloxom, with two wells targeting the Wolfcamp B shale and one targeting the Wolfcamp A shale.
In order to increase our exposure to horizontal development of the Wolfcamp B shale, we acquired 2,319 gross (1,762 net) acres in southern Reagan county, Texas, which closed on July 5, 2012, and is now referred to as our Taylor Draw field. We finished the drilling of our initial horizontal well, targeting the Wolfcamp B shale, in December 2012, completed the well in February 2013, and are currently evaluating the well results that include some positive indications.
Based on our initial results and the results of other industry participants, we are planning to increase our level of horizontal drilling activityPermian grew 38% in 2013 compared to 2012, increasing to 813 MBOE from 591 MBOE, respectively. Production in this portion of the basin, drilling a total of 14 wells. Given this level of sustained activity, we are planning on executing these wells2013 continued to benefit from drilling pads using batch completions in an effort to maximize capital efficiency. These development plans are currently expected to be focused on our East Bloxom and Taylor Draw fields.
Northern Portion: We currently own approximately 21,617 net acres in the northern portion of the Permian basin, which includes the 14,653 net acres in Borden county, Texas and an additional 6,964 net acres in Lynn county, Texas. These leasehold positions were acquired during the course of 2012 for a total consideration of $19.4 million, or $896 per net acre. These positions represent our effort to expand our drilling inventory in the Midland basin with exploration upside potential at a reasonable cost of entry.
After completing a 3-D seismic survey on our acreage position, we commenced the drilling of an exploratory vertical well in July 2012, followed by the drilling of two horizontal wells. The first horizontal well was drilled in the Cline shale and was completed in December 2012. The hydrocarbons from this well did not produce in economic quantities and the well was temporarily abandoned in February 2013. We drilled the second horizontal well, targeting the Mississippian lime interval, in November 2012, completed the well in February 2013 and are currently evaluating the well results.
Although the area has experienced a recent increase in drilling activity, the northern Midland basin has had limited drilling activity compared with the southern basin (where our current production is located), which significantly increases the risk associated with successful drilling activities in this area.
In addition to the $29.6 million consideration paid for each of the above referenced leasehold additions, the Company's unevaluated property balance of $68.8 million at December 31, 2012 includes $29.7 million of exploration and facility costs incurred in 2012 on these properties and $9.5 million of other related items. See Note 12 for additional information. Based on the Company's present development plans, the Company expects the majority of the exploration and facility costs will be transferred to evaluated properties during 2013.
|
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Offshore - Deepwater
Our net interest in the Habanero field produced an average of 366 Boe per day for 2012. The field was shut-in for approximately 50 days during the year for scheduled maintenance, and hurricane-related issues. On December 28, 2012, we completed the sale of our interest in the Habanero field to Shell Offshore Inc., a subsidiary of Royal Dutch Shell Plc, for net cash consideration of $39.4 million.
Our remaining deepwater property, our 15% interest in the Medusa field, continues to play a key role in our portfolio. Our net interest in the Medusa field produced an average of 1,268 Boe per day during 2012, approximately 87% being crudehigh oil that receives pricing based on Mars WTI crude. The Medusa platform was shut-in for 28 days during the second quarter of 2012 for planned construction activities on the West Delta 143 oil pipeline through which Medusa's production is transported. Due to Hurricane Isaac, the platform was once again shut-in from August 27, 2012 to September 4, 2012.
We anticipate that the future cash flows from Medusa will continue to contribute to the funding of our onshore activity. In addition, we believe that additional reserve potential exists as part of this project. The operator of the field, Murphy Oil Corporation, has sanctioned a two well subsea development for the Medusa field. One of these wells will be targeting the development of reserves associated with our existing PUD reserves in the T-4B sand with an uphole recomplete to the T-0A and T-0B sand. The remaining well will target probable reserves. We anticipate that the drilling of these wells will begin in the first quarter of 2014.
Offshore – Shelf & Other Properties
We own interests in 14 producing wells in eight crudeconcentrations including 64% oil and 36% natural gas, fields in the shelf area of the Gulf of Mexico. These wells produced 340 MBoe netwhich we anticipate to our interest in 2012, which accounted for 22% of our total production. Production from the East Cameron Block 257 field, which contributed an average of 175 Boe per day of production prior to being shut-in in November 2011, is expected to recommence once the Stingray Pipeline is brought back online. The restart of flows on the pipeline is currently anticipated to occur in the second quarter of 2013.
Liquidity and Capital Resources
Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. Cash and cash equivalents decreased by $42.7 million during 2012 to $1.1 million compared to $43.8 million at December 31, 2011. The decrease in our cash balance is primarily attributable to 2012 capital expenditures of $133.3 million, representing a $33.1 million or 33%further increase over the amount spent during the same period in 2011. While at December 31, 2012, our Balance Sheet reflects a working capital deficiency of $18.6 million, which is reflective of our current capital investment-driven growth strategy within our Permian properties, we believe that as discussed below our operating cash flows combined with the borrowing availability under our Credit Facility provides the liquidity necessary to meet our operational cashflow needs.
Senior Secured Credit Facility (the "Credit Facility")
On June 20, 2012, Regions Bank increased the Company's Credit Facility to $200 million with an associated borrowing base under the Credit Facility of $60 million and a maturity of July 31, 2014. Subsequently and in October 2012, the Credit Facility was further amended to increase the borrowing base to $80 million, extend the maturity to March 15, 2016 and add Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. Regions Bank continues to serve as Administrative Agent for the Credit Facility.
As of December 31, 2012 the borrowing base was revised to $65 million following the sale of our interest in the deepwater Habanero field. Proceeds from the sale, net cash consideration of $39.4 million after customary purchase price adjustments, were used to reduce outstanding borrowings on our Credit Facility. The borrowing base will be redetermined as scheduled in the first quarter of 2013 based upon the evaluation of year-end proved reserves.
Amounts borrowed under the Credit Facility may not exceed a borrowing base, which is generally reviewed on a semi-annual basis and is then eligible for re-determination. The Credit Facility is secured by mortgages covering the Company's major producing fields.
As of December 31, 2012, the balance outstanding under the Credit Facility was $10.0 million with a weighted average interest rate on the Credit Facility of 2.72% , calculated as the London Interbank Offered Rate (“LIBOR”) plus a tiered rate ranging from 2.5% to 3.0%, which is based on utilization of the Credit Facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly. As of March 13, 2013 , the balance outstanding
|
| | |
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
on the Credit Facility was $25 million as the Company drew an additional $15 million in support of the Company's ongoing capital development program.
Senior Notes due 2016
At December 31, 2012, following a $10 million principal redemption in June 2012, we had approximately $97 million principal amount of 13% Senior Notes due 2016 outstanding with interest payable quarterly.
2013 Capital Expenditures
For 2013, we designed a flexible capital spending program, which we plan to fund from cash on hand and cash flows from operations in addition to borrowings under our Credit Facility. However, depending on macroeconomic conditions or the Company's operational results, our capital budget may be adjusted up or down during the year.
Our 2013 capital budget has been established at $125.0 million with over 90% of our budgeted operating expenditures (including drilling, completion, infrastructure, and plugging and abandonment) allocated to our Midland basin operations.. The 15%decrease in total capital from 2011 reflects our primary focus on drilling and completion activities in the Permian basin and reduced emphasis on acreage acquisitions that were budgeted in 2012 to expand the Company's presence in the basin. Our budget includes further exploration and development of our Permian basin properties with plans to complete approximately 26 gross wells including 14 horizontal wells and 12 vertical wells. Components of the 2013 capital budget include (in millions):
|
| | | |
| Midland basin | $ | 97 |
|
| Gulf of Mexico | 10 |
|
| Total projected operations budget | 107 |
|
| | |
| Capitalized general and administrative costs | 14 |
|
| Capitalized interest and other | 4 |
|
| Total projected capital expenditures budget | $ | 125 |
|
Our total liquidity at December 31, 2012 was $56.1 million, including $1.1 million of cash available and $55.0 million of availability under our Credit Facility. We believe that this liquidity position, combined with our expected operating cash flow based on current commodity prices and forecasted production, will be adequate to meet our forecasted capital expenditures, interest payments, and operating requirements for 2013.
offshore assets.
|
| | |
| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
The following table includes |
| | | | | | | | | | | | |
| | | Net Production (MBOE) |
| | | Twelve Months Ended December 31, |
| | | 2013 | | 2012 | | Change | | % Change |
| Onshore: | | | | | | | | |
| Southern Midland Basin | | 612 |
| | 402 |
| | 210 |
| | 52 | % |
| Central Midland Basin | | 193 |
| | 189 |
| | 4 |
| | 2 | % |
| Northern Midland Basin | | 8 |
| | — |
| | 8 |
| | 100 | % |
| Total Permian | | 813 |
| | 591 |
| | 222 |
| | 38 | % |
| | | | | | | | | |
| Offshore: | | | | | | | | |
| Medusa | | 302 |
| | 464 |
| | (162 | ) | | (35 | )% |
| Habanero | | — |
| | 134 |
| | (134 | ) | | (100 | )% |
| Total offshore | | 302 |
| | 598 |
| | (296 | ) | | (49 | )% |
| | | | | | | | | |
| Other: | | | | | | | | |
| Haynesville shale | | 18 |
| | 46 |
| | (28 | ) | | (61 | )% |
| Gulf of Mexico shelf and other | | 280 |
| | 340 |
| | (60 | ) | | (18 | )% |
| Total other | | 298 |
| | 386 |
| | (88 | ) | | (23 | )% |
| | | | | | | | | |
| Total | | 1,413 |
| | 1,575 |
| | (162 | ) | | (10 | )% |
On average, we operated 1.4 horizontal rigs and one vertical rig in 2013, and drilled a total of 26 gross (22.2 net) wells, of which 1 gross (0.4 net) well was recompleted during the Company’s contractual obligationsyear and purchase commitments5 gross (4.7 net) were awaiting completion at December 31, 2013.
|
| | | | | | | | | | | | | | | | | | |
| | | Drilled | | Completed (a) | | Awaiting Completion |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Southern Midland Basin | | | | | | | | | | | | |
| Vertical wells | | 1 |
| | 1.0 |
| | 1 |
| | 1.0 |
| | — |
| | — |
|
| Horizontal wells | | 17 |
| | 15.5 |
| | 15 |
| | 13.5 |
| | 3 |
| | 3.0 |
|
| Total | | 18 |
| | 16.5 |
| | 16 |
| | 14.5 |
| | 3 |
| | 3.0 |
|
| | | | | | | | | | | | | |
| Central Midland Basin | | | | | | | | | | | | |
| Vertical wells | | 5 |
| | 3.0 |
| | 7 |
| | 4.4 |
| | — |
| | — |
|
| Horizontal wells | | 2 |
| | 1.7 |
| | — |
| | — |
| | 2 |
| | 1.7 |
|
| Total | | 7 |
| | 4.7 |
| | 7 |
| | 4.4 |
| | 2 |
| | 1.7 |
|
| | | | | | | | | | | | | |
| Northern Midland Basin | | | | | | | | | | | | |
| Vertical wells | | 1 |
| | 1.0 |
| | 2 |
| | 1.8 |
| | — |
| | — |
|
| Horizontal wells | | — |
| | — |
| | 1 |
| | 0.8 |
| | — |
| | — |
|
| Total | | 1 |
| | 1.0 |
| | 3 |
| | 2.5 |
| | — |
| | — |
|
| | | | | | | | | | | | | |
| Total | | 26 |
| | 22.2 |
| | 26 |
| | 21.4 |
| | 5 |
| | 4.7 |
|
| | | | | | | | | | | | | |
| Total vertical wells | | 7 |
| | 5.0 |
| | 10 |
| | 7.1 |
| | — |
| | — |
|
| Total horizontal wells | | 19 |
| | 17.2 |
| | 16 |
| | 14.3 |
| | 5 |
| | 4.7 |
|
| | | | | | | | | | | | | |
| Total | | 26 |
| | 22.2 |
| | 26 |
| | 21.4 |
| | 5 |
| | 4.7 |
|
(a) Completions include wells drilled prior to 2013.
Permian Reserve Growth
As of December 31, 2013, our estimated Permian proved reserves increased 58% to 14.9 MMBOE compared to 9.4 MMBOE of Permian proved reserves at year-end 2012. In total, proved reserves increased 6%, or 0.8 MMBOE, to 14.9 MMBOE from 14.1 MMBOE for as of the same date in 2012 as our significant growth in Permian proved reserves was largely offset by the sale of our offshore and Haynesville properties and by the reclassification of previously recorded Permian vertical development proved undeveloped reserves as we focus on horizontal development. Our Permian Basin proved reserves at year-end 2013 were 80% oil and 20% natural gas, compared to 76% oil and 24% natural gas at year-end 2012.
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| | |
| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
2013 Preferred Equity Offering
On May 30, 2013, the Company issued $75.0 million of 10.0% Series A Cumulative Preferred Stock (the “Preferred Stock”) and received $70.0 million net proceeds after deducting the underwriting commissions and offering expenses. We used the proceeds of this equity offering to repay outstanding borrowings under our revolving Credit Facility, to fund accelerated capital expenditures to further develop and evaluate our Permian asset base, and for general corporate purposes.
Liquidity and Capital Resources
Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties. Cash and cash equivalents increased $1.9 million during 2013 to $3.0 million compared to $1.1 million at December 31, 2012, at which date. We recently entered into the Company had no product delivery commitments:Amended Credit Facility and Second Lien Facility to support the funding of our ongoing operations. For additional information, see Note 4 to the Consolidated Financial Statements. We believe that, as discussed below, our operating cash flows combined with our bank borrowing ability provides the liquidity necessary to meet our operational cash flow needs.
Liquidity and cash flow:
|
| | | | | | | | | | | | | | | | | | | | |
| (amounts in thousands) | | Payments due by Period |
| | | Total | | < 1 Year | | Years 2 - 3 | | Years 4 - 5 | | >5 Years |
| 13% Senior Notes | | $ | 96,961 |
| | $ | — |
| | $ | — |
| | $ | 96,961 |
| | $ | — |
|
| Office space lease commitments | | 3,012 |
| | 384 |
| | 785 |
| | 719 |
| | 1,124 |
|
| Drilling rig leases and related (a) | | 11,512 |
| | 9,235 |
| | 2,277 |
| | — |
| | — |
|
| Other | | 40 |
| | 13 |
| | 27 |
| | — |
| | — |
|
| Total | | $ | 111,525 |
| | $ | 9,632 |
| | $ | 3,089 |
| | $ | 97,680 |
| | $ | 1,124 |
|
| |
(a) | The agreement includes early termination provisions that would reduce the minimum rentals under the agreement, assuming the lessor is unable to re-charter the rig and staffing personnel to another lessee, as follows: <1 year of $5.8 million and 2-3 years of $1.4 million.
|
Summary cash flow information is provided as follows: |
| | | | | | | | | |
| | | For the Year Ended December 31, |
| | | 2013 | | 2012 | | 2011 |
| | | | | | | |
| Net cash provided by operating activities | | 54.3 |
| | 51.3 |
| | 79.2 |
|
| Net cash used in investing activities | | (79.8 | ) | | (93.7 | ) | | (91.5 | ) |
| Net cash provided by (used in) financing activities | | 27.3 |
| | (0.3 | ) | | 38.7 |
|
| Net change in cash | | 1.8 |
| | (42.7 | ) | | 26.4 |
|
Operating Activities. For the year ended December 31, 20122013, net cash provided by operating activities was $51.354.3 million, compared to $79.251.3 million for the same period in 20112012. The decrease relatesincrease was related primarily to lower revenues from a 2%15% decrease in crude oil production, a 29%decrease in natural gas production and a 31%increase in lease operating expenses partially offset bycoupled with a 2%3% increase in the average sales price on an equivalent basis.basis partially offset by lower revenues as oil and natural gas production decreased 7% and 16%, respectively. Production and realized prices are discussed below in Results of Operations.
Investing Activities. For the year ended December 31, 20122013, net cash used in investing activities was $93.779.8 million as compared to $91.593.7 million for the same period in 20112012. The net $2.213.9 million increasedecrease in cash used in investing activities is primarily attributable to a $33.150.1 million increase in proceeds from the sale of mineral interests and equipment offset by a 26.4 million increase in capital expenditures related to development activity on our Permian basin acreage and $2.110.9 million for producing property acquisitions. These expenditures were largely offset by aThe $32.350.1 million year-over-year increase in the previously mentioned proceeds received forrelates to the proceeds in 2013 of $90.0 million, primarily attributable to the sale of certain mineral interests includingour Medusa and offshore properties compared to proceeds in 2012 of $39.9 million, primarily related to the late 2012 sale of our interest in the deepwater Habanero fieldoffshore property, which are both discussed below and in Note 12 to the financial statements. The $33.126.4 million increase in capital expenditures includesincluded the costs associated with expanding to a two-rig drilling program and the acquisition of additional acreage in Borden and Lynn counties located in the northern Midland basin, additional acreage in Reagan county in the southern Midland basin and costs associated with the horizontal drilling activity.Garrison Draw property.
2014 Budgeted Capital Expenditures
In early February 2014, we announced our operational capital budget for 2014:
|
| | | | | | | | |
| | | | | Gross Wells |
| Category | | ($ millions) | | Drill | | Complete |
| Horizontal wells | | $ | 155 |
| | 27 | | 26 |
| Vertical wells | | 15 |
| | 9 | | 8 |
| Facilities and equipment | | 15 |
| | |
| Total operational capital | | $ | 185 |
| | |
|
| | |
| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
We expanded our horizontal pad development efforts from two to four fields in late 2013, adding Carpe Diem in Midland County and Garrison Draw in Reagan County. We expect our 2014 horizontal drilling program will be primarily focused on program development of established Upper and Lower Wolfcamp zones in the Southern and Central Midland Basin, but will also include two wells in the Southern Midland Basin to evaluate the Wolfcamp A shale and a test of the Lower Spraberry shale formation in the Central Midland Basin. In addition, we anticipate the average lateral length of our horizontal wells in 2014 to be approximately 7,000’ per well.
Planned vertical drilling activity is anticipated to be limited to five deep Wolfberry wells in the Pecan Acres field, one well in the Garrison Draw field. We have included three vertical exploration wells in the Northern Midland Basin, the timing and location of which being subject to change as results are evaluated during the course of 2014.
In addition to the operational capital expenditures above, we budgeted approximately $25 million for capitalized expenses and certain retained plugging abandonment expenses related to divested Gulf of Mexico shelf assets.
Our 2014 capital program is 100% operated and, as a result, the amount and timing of these capital expenditures are largely discretionary depending on commodity prices and other factors. We expect to fund our 2014 capital program through a combination of cash flow from operations, bank borrowings and term debt issuance, including our recently executed Second Lien Facility.
Financing Activities.Activities. For the year ended December 31, 20122013, net cash used in financing activities was $0.2 million compared to cash provided by financing activities was $27.3 million compared to cash used by financing activities of $38.70.3 million during the same period of 20112012. Net cash used for 2012provided by financing activities for 2013 included proceeds of $70.4 million, net from our Preferred Stock offering (see Note 9 for additional information) and a net $10$12 million draw, net on our Credit Facility offset by the $10.2$50 million redemption of our Senior Notes. Net cash providedNotes, and approximately $4.6 million in preferred stock dividends.
Senior Secured Credit Facility (“Credit Facility”)
The Company’s $200 million Credit Facility, for which Regions Bank serves as the Administrative Agent, matures March 15, 2016 and includes Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. As of December 31, 2013, the Company’s Credit Facility had an approved borrowing base at December 31, 2013 of $83 million. The Credit Facility was secured by 2011 financing activities included $73.8mortgages covering the Company’s major producing fields. As of December 31, 2013, the balance outstanding on the Credit Facility was $22 million with an interest rate of net proceeds2.92%, calculated as the London Interbank Offered Rate (LIBOR), plus a tiered rate ranging from an equity offering offset2.5% to 3.0%, which is determined by approximately $35.1 million used to redeemutilization of the facility. In addition, the Credit Facility carries a $31 million principalcommitment fee of 0.5% per annum on the unused portion of our outstanding the borrowing base, which is payable quarterly.
Subsequent to December 31, 2013, the Company amended its existing Credit Facility as discussed below. Additionally, the Company executed the Second Lien Facility also discussed below.
Amended Credit Facility (the “Amended Credit Facility”) and Second Lien Term Loan Facility (the “Second Lien Facility”)
On March 11, 2014, we entered into an amended senior secured revolving credit facility (the “Amended Credit Facility”) in the amount of $500 million with JPMorgan Chase Bank, N.A. as Administrative Agent (“J.P. Morgan”). The Credit Facility will have an initial borrowing base amount of $95 million and a maturity date of March 11, 2019. In conjunction with the Amended Credit Facility, we entered into a senior secured second lien term loan facility (the “Second Lien Facility”) in an aggregate amount of up to $125 million with J.P. Morgan as Administrative Agent and with a maturity date of September 11, 2019. See Note 4 for additional information.
13% Senior Notes due 2016 (the “Senior Notes”) and to payDeferred Credit
As of December 31, 2013, following a $48.5 million principal redemption in December 2013, we had approximately $48.5 million principal amount of the $4.0 million call premium13% Senior Notes due 2016 outstanding with interest payable quarterly.
|
| | |
| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Contractual Obligations
The following table includes the Company’s current contractual obligations and other redemption expenses. purchase commitments, at which time the Company had no product delivery commitments:
|
| | | | | | | | | | | | | | | | | | | | |
| (amounts in thousands) | | Payments due by Period |
| | | Total | | < 1 Year | | Years 2 - 3 | | Years 4 - 5 | | >5 Years |
| 13% Senior Notes | | $ | 48,481 |
| | $ | — |
| | $ | 48,481 |
| | $ | — |
| | $ | — |
|
| Drilling rig leases and related (a) | | 42,482 |
| | 19,732 |
| | 22,750 |
| | — |
| | — |
|
| Office space lease and other commitments | | 3,208 |
| | 618 |
| | 1,096 |
| | 717 |
| | 777 |
|
| Total | | $ | 94,171 |
| | $ | 20,350 |
| | $ | 72,327 |
| | $ | 717 |
| | $ | 1,124 |
|
| |
(a) | The <1 Year column includes $2,055 related to the early termination provisions of one of the Company’s horizontal drilling rigs (See Note 13), which the Company replaced with a different horizontal rig, and the amount assumes the lessor is unable to re-charter the rig and staffing personnel to another lessee. Should the lessor re-charter the rig and its related personnel to a new lessee, the $2,055 would be reduced by the value of the new lessee’s rentals. Also includes an anticipated contract renewal of our Cactus 1 Rig lease. |
Income Taxes
The Company’s income tax expense varies from the statutory rate primarily due to the effect of state taxes, non deductible compensation under Section 162(m) and restricted stock offset by percentage depletion. Prior to 2012, we carried a full valuation allowance against our net deferred tax asset. The income tax benefit of $69.3$69.3 million in 2011 resulted primarily from the reversal of the valuation allowance established in 2008 against our net deferred tax assets. As a result of reporting net income from 2009 to 2011, we achieved income on an aggregate basis for the three-year period ended December 31, 2011. Additionally we expect to generate sufficient taxable income necessary to fully utilize all of the deferred tax assets prior to their expiration. Consequently, we reversed the $69.3 million valuation allowance at December 31, 2011. For additional information, see the Income Tax discussion included below in Results of Operations and Note 1110 to the Consolidated Financial Statements.
Global Settlement with Joint Interest Partner
During the second quarter of 2011, we entered into a final project wind-down agreement with a former joint interest partner in a deepwater project. The agreement provided for the extinguishment of all existing agreements and commitments between the parties as it relates to the past development of the deepwater project. The agreement also included a formal extinguishment of the non-recourse credit agreement between the parties and the assignment to us of the joint interest partner's 50% rights to the remaining project assets, which included primarily the unsold, residual equipment and all engineering data. For additional information regarding the settlement, please refer to Note 3 included in Item II, Part 8 of this filing.
|
| | |
| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Results of Operations
The following table sets forth certain unaudited operating information with respect to the Company'sCompany’s oil and natural gas operations for the periods indicated:
| | | | For the year ended December 31, | For the Year Ended December 31, |
| | 2012 | | 2011 | | Change | | % Change | | 2010 | | Change | | % Change | 2013 | | 2012 | | Change | | % Change | | 2011 | | Change | | % Change |
| Net production: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude oil (MBbls) | 977 |
| | 996 |
| | (19 | ) | | (2 | )% | | 859 |
| | 137 |
| | 16 | % | |
| Oil (MBbls) | | 911 |
| | 977 |
| | (66 | ) | | (7 | )% | | 996 |
| | (19 | ) | | (2 | )% |
| Natural gas (MMcf) | 3,588 |
| | 5,081 |
| | (1,493 | ) | | (29 | )% | | 4,892 |
| | 189 |
| | 4 | % | 3,011 |
| | 3,588 |
| | (577 | ) | | (16 | )% | | 5,081 |
| | (1,493 | ) | | (29 | )% |
| Total production (MBoe) | 1,575 |
| | 1,843 |
| | (268 | ) | | (15 | )% | | 1,674 |
| | 169 |
| | 10 | % | |
| Average daily production (Boe) | 4,303 |
| | 5,049 |
| | (746 | ) | | (15 | )% | | 4,587 |
| | 462 |
| | 10 | % | |
| Total production (MBOE) | | 1,413 |
| | 1,575 |
| | (162 | ) | | (10 | )% | | 1,843 |
| | (268 | ) | | (15 | )% |
| Average daily production (BOE) | | 3,871 |
| | 4,303 |
| | (432 | ) | | (10 | )% | | 5,049 |
| | (746 | ) | | (15 | )% |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Average realized sales price (see below): | |
| | |
| | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Crude oil (Bbl) | $ | 98.86 |
| | $ | 101.34 |
| | $ | (2.48 | ) | | (2 | )% | | $ | 75.97 |
| | $ | 25.37 |
| | 33 | % | |
| Oil (Bbl) | | $ | 97.65 |
| | $ | 98.86 |
| | $ | (1.21 | ) | | (1 | )% | | $ | 101.34 |
| | $ | (2.48 | ) | | (2 | )% |
| Natural gas (Mcf) | 3.94 |
| | 5.25 |
| | (1.31 | ) | | (25 | )% | | 5.04 |
| | 0.21 |
| | 4 | % | 4.52 |
| | 3.94 |
| | 0.58 |
| | 15 | % | | 5.25 |
| | (1.31 | ) | | (25 | )% |
| Total (Boe) | 70.31 |
| | 69.26 |
| | 1.05 |
| | 2 | % | | 53.69 |
| | 15.57 |
| | 29 | % | |
| Crude oil and natural gas revenues (in thousands): | |
| | |
| | |
| | |
| | |
| | |
| | |
| |
| Crude oil revenue | $ | 96,584 |
| | $ | 100,962 |
| | $ | (4,378 | ) | | (4 | )% | | $ | 65,243 |
| | $ | 35,719 |
| | 55 | % | |
| Total (BOE) | | 72.59 |
| | 70.31 |
| | 2.28 |
| | 3 | % | | 69.26 |
| | 1.05 |
| | 2 | % |
| Oil and natural gas revenues (in thousands): | | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Oil revenue | | $ | 88,960 |
| | $ | 96,584 |
| | $ | (7,624 | ) | | (8 | )% | | $ | 100,962 |
| | $ | (4,378 | ) | | (4 | )% |
| Natural gas revenue | 14,149 |
| | 26,682 |
| | (12,533 | ) | | (47 | )% | | 24,639 |
| | 2,043 |
| | 8 | % | 13,609 |
| | 14,149 |
| | (540 | ) | | (4 | )% | | 26,682 |
| | (12,533 | ) | | (47 | )% |
| Total | $ | 110,733 |
| | $ | 127,644 |
| | $ | (16,911 | ) | | (13 | )% | | $ | 89,882 |
| | $ | 37,762 |
| | 42 | % | $ | 102,569 |
| | $ | 110,733 |
| | $ | (8,164 | ) | | (7 | )% | | $ | 127,644 |
| | $ | (16,911 | ) | | (13 | )% |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Additional per Boe data: | |
| | |
| | |
| | |
| | |
| | |
| | |
| |
| Additional per BOE data: | | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Sales price | $ | 70.31 |
| | $ | 69.26 |
| | $ | 1.05 |
| | 2 | % | | $ | 53.69 |
| | $ | 15.57 |
| | 29 | % | $ | 72.59 |
| | $ | 70.31 |
| | $ | 2.28 |
| | 3 | % | | $ | 69.26 |
| | $ | 1.05 |
| | 2 | % |
| Lease operating expense | (16.86 | ) | | (11.04 | ) | | (5.82 | ) | | (53 | )% | | (10.58 | ) | | (0.46 | ) | | 4 | % | (14.00 | ) | | (14.81 | ) | | 0.81 |
| | 5 | % | | (9.92 | ) | | (4.89 | ) | | 49 | % |
| Production taxes | | (2.92 | ) | | (2.05 | ) | | (0.87 | ) | | (42 | )% | | (1.12 | ) | | (0.93 | ) | | 83 | % |
| Operating margin | $ | 53.45 |
| | $ | 58.22 |
| | $ | (4.77 | ) | | (8 | )% | | $ | 43.11 |
| | $ | 15.11 |
| | 35 | % | $ | 55.67 |
| | $ | 53.45 |
| | $ | 2.22 |
| | 4 | % | | $ | 58.22 |
| | $ | (4.77 | ) | | (8 | )% |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil and Mcf of natural gas: | |
| Below is a reconciliation of the average NYMEX price to the average realized sales price per Bbl of oil and Mcf of natural gas: | | Below is a reconciliation of the average NYMEX price to the average realized sales price per Bbl of oil and Mcf of natural gas: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Average NYMEX oil price ($/Bbl) | $ | 94.19 |
| | $ | 95.14 |
| | $ | (0.95 | ) | | (1 | )% | | $ | 79.52 |
| | $ | 15.62 |
| | 20 | % | $ | 97.96 |
| | $ | 94.19 |
| | $ | 3.77 |
| | 4 | % | | $ | 95.14 |
| | $ | (0.95 | ) | | (1 | )% |
| Basis differential and quality adjustments (a) | 3.97 |
| | 7.58 |
| | (3.61 | ) | | (48 | )% | | (2.39 | ) | | 9.97 |
| | (417 | )% | 0.12 |
| | 3.97 |
| | (3.85 | ) | | (97 | )% | | 7.58 |
| | (3.61 | ) | | (48 | )% |
| Transportation | (0.75 | ) | | (1.00 | ) | | 0.25 |
| | 25 | % | | (1.16 | ) | | 0.16 |
| | (14 | )% | (0.43 | ) | | (0.75 | ) | | 0.32 |
| | 43 | % | | (1.00 | ) | | 0.25 |
| | (25 | )% |
| Hedging (b) | 1.45 |
| | (0.38 | ) | | 1.83 |
| | 482 | % | | — |
| | (0.38 | ) | | 100 | % | — |
| | 1.45 |
| | (1.45 | ) | | 100 | % | | (0.38 | ) | | 1.83 |
| | 100 | % |
| Average realized oil price ($/Bbl) | $ | 98.86 |
| | $ | 101.34 |
| | $ | (2.48 | ) | | (2 | )% | | $ | 75.97 |
| | $ | 25.37 |
| | 33 | % | $ | 97.65 |
| | $ | 98.86 |
| | $ | (1.21 | ) | | (1 | )% | | $ | 101.34 |
| | $ | (2.48 | ) | | (2 | )% |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Average NYMEX natural gas price ($/Mcf) | $ | 2.82 |
| | $ | 4.03 |
| | $ | (1.21 | ) | | (30 | )% | | $ | 4.40 |
| | $ | (0.37 | ) | | (8 | )% | |
| Average NYMEX natural gas price ($/MMBtu) | | $ | 3.73 |
| | $ | 2.82 |
| | $ | 0.91 |
| | 32 | % | | $ | 4.03 |
| | $ | (1.21 | ) | | (30 | )% |
| Basis differential and quality adjustments (c) | 1.12 |
| | 1.22 |
| | (0.10 | ) | | (8 | )% | | 0.51 |
| | 0.71 |
| | 139 | % | 0.79 |
| | 1.12 |
| | (0.33 | ) | | (29 | )% | | 1.22 |
| | (0.10 | ) | | (8 | )% |
| Hedging (b) | — |
| | — |
| | — |
| | n/a |
| | 0.13 |
| | (0.13 | ) | | (100 | )% | |
| Average realized natural gas price ($/Mcf) | $ | 3.94 |
| | $ | 5.25 |
| | $ | (1.31 | ) | | (25 | )% | | $ | 5.04 |
| | $ | 0.21 |
| | 4 | % | $ | 4.52 |
| | $ | 3.94 |
| | $ | 0.58 |
| | 15 | % | | $ | 5.25 |
| | $ | (1.31 | ) | | (25 | )% |
| |
| (a) | Crude oilOil prices for production from our two divested deepwater fields includereflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production, prior to the sale of Medusa in December 2013, and Argus Bonita WTI differential for Habanero production.production, prior to the sale of Habanero during December 2012. |
| |
| (b) | As discussed in Note 65, the Company discontinued hedge accounting beginning with derivative contracts executed on January 1, 2012. Consequently, the realized portion ofgain or loss on derivative contracts, settled is now included in the statement of operations within GainLoss (Gain) on derivative contracts. The amounts reported above reflect the realized portion of derivative contracts designated as cash flow hedges. |
| |
| (c) | Natural gas prices exceeded the related NYMEX prices, which are quoted on an MMBtu basis, primarily due to the value of the NGLs in our liquids-rich natural gas stream, primarily from our Permian basin and deepwater production. |
|
| | |
| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Revenues
The following tables are intended to reconcile the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume, changes in the underlying commodity prices and the impact of our hedge programprogram. (in thousands):
| | | | | Oil | | Natural Gas | | Total | |
| Revenues for the year ended December 31, 2009 | | $ | 73,842 |
| | $ | 27,417 |
| | $ | 101,259 |
| |
| | | | | | | | |
| Volume decrease | | (11,164 | ) | | (4,050 | ) | | (15,214 | ) | |
| Price increase | | 2,556 |
| | 649 |
| | 3,205 |
| |
| Impact of hedges increase | | 9 |
| | 623 |
| | 632 |
| |
| Net decrease during the year | | (8,599 | ) | | (2,778 | ) | | (11,377 | ) | |
| | | | | | | | | Oil | | Natural Gas | | Total |
| Revenues for the year ended December 31, 2010 | | $ | 65,243 |
| | $ | 24,639 |
| | $ | 89,882 |
| | $ | 65,243 |
| | $ | 24,639 |
| | $ | 89,882 |
|
| | | | | | | | | | | | | |
| Volume increase | | 10,406 |
| | 952 |
| | 11,358 |
| | 10,406 |
| | 952 |
| | 11,358 |
|
| Price increase | | 25,688 |
| | 1,091 |
| | 26,779 |
| | 25,688 |
| | 1,091 |
| | 26,779 |
|
| Impact of hedges decrease | | (375 | ) | | — |
| | (375 | ) | | (375 | ) | | — |
| | (375 | ) |
| Net increase during the year | | 35,719 |
| | 2,043 |
| | 37,762 |
| |
| Net increase in 2011 | | | 35,719 |
| | 2,043 |
| | 37,762 |
|
| | | | | | | | | | | | | |
| Revenues for the year ended December 31, 2011 | | $ | 100,962 |
| | $ | 26,682 |
| | $ | 127,644 |
| | $ | 100,962 |
| | $ | 26,682 |
| | $ | 127,644 |
|
| | | | | | | | | | | | | |
| Volume decrease | | (1,926 | ) | | (7,840 | ) | | (9,766 | ) | | (1,926 | ) | | (7,840 | ) | | (9,766 | ) |
| Price decrease | | (3,872 | ) | | (4,693 | ) | | (8,565 | ) | | (3,872 | ) | | (4,693 | ) | | (8,565 | ) |
| Impact of hedges increase | | 1,420 |
| | — |
| | 1,420 |
| | 1,420 |
| | — |
| | 1,420 |
|
| Net decrease during the year | | (4,378 | ) | | (12,533 | ) | | (16,911 | ) | |
| Net decrease in 2012 | | | (4,378 | ) | | (12,533 | ) | | (16,911 | ) |
| | | | | | | | | | | | | |
| Revenues for the year ended December 31, 2012 | | $ | 96,584 |
| | $ | 14,149 |
| | $ | 110,733 |
| | $ | 96,584 |
| | $ | 14,149 |
| | $ | 110,733 |
|
| | | | | | | | |
| Volume decrease | | | (10,065 | ) | | (540 | ) | | (10,605 | ) |
| Price increase | | | 2,441 |
| | — |
| | 2,441 |
|
| Net decrease in 2013 | | | (7,624 | ) | | (540 | ) | | (8,164 | ) |
| | | | | | | | |
| Revenues for the year ended December 31, 2013 | | | $ | 88,960 |
| | $ | 13,609 |
| | $ | 102,569 |
|
Crude Oil Revenue
For the year ended December 31, 20122013, crude oil revenues of $96.689.0 million decreased $4.47.6 million, or 4%8%, compared to revenues of $101.096.6 million for the year ended December 31, 20112012. Lower production from our offshore properties, primarily related to the sale of Habanero field in December 2012 and our Medusa and shelf properties in the fourth quarter of 2013, drove the revenue decline. Also contributing to the production decline were 20 days of down time for scheduled downstream pipeline maintenance at our Medusa field in the second quarter of 2013, approximately five days of production downtime at our key producing Permian Basin fields in the fourth quarter of 2013 due to severe winter weather causing electricity outages and the extended curtailment of trucking capacity to transport offtake and due to normal and expected declines from other producing wells. Collectively, these declines were offset by the 222 MBbls increase in our oil production from our Permian properties.
For the year ended December 31, 2012, oil revenues of $96.6 million decreased $4.4 million, or 4%, compared to revenues of $101.0 million for the year ended December 31, 2011. A decrease in commodity prices and production resulted in decreased oil revenue. The average price realized decreased2% to $98.86$98.86 per barrel compared to $101.34$101.34 for the same period of 2011. Similarly, production decreased by 2% to 977 MBbls compared to 996 MBbls during the same period in 2011. Crude oilOil prices for production from our two deepwater fields are adjusted and reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production and Bonita WTI differential for Habanero production. Production decreases relate primarily to the down-time at the Habanero and Medusa fields and the normal and expected declines from our other offshore properties. These production declines were offset by production from our new Permian wells, 22 vertical and two horizontal, brought onto production during 2012.
For the year ended December 31, 2011, crude oil revenues of $101.0 million increased $35.7 million or 55% compared to revenues of $65.2 million for the year ended December 31, 2010. An increase in commodity prices and production resulted in increased crude oil revenue. The average price realized increased 33% to $101.34 per barrel compared to $75.97 for the same period of 2010. Similarly, production increased by 16% to 996 MBbls compared to 859 MBbls during the same period in 2010. Crude oil prices for production from our two deepwater fields are adjusted and reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production and Bonita WTI differential for Habanero production. Production increases relate primarily to progress in developing our Permian basin properties and a successful recompletion at our Medusa field, partially offset by the downtime experienced at our deepwater fields and due to normal and expected declines in our other properties.
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| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Natural Gas Revenue
For the year ended December 31, 20122013, natural gas revenues of $13.6 million represented a decrease of 4%, or $0.5 million, compared to natural gas revenues of $14.1 million for the year ended December 31, 2012. While the average realized price increased15%, a 16% decrease in production reduced total revenue. The production declines were primarily attributable to the shut-in of production of our Mobile Bay 908 property, the sale of our offshore fields, the sale of our Haynesville well in the fourth quarter of 2013 as well as normal and expected declines from our existing wells. Offsetting these declines was a 248 MMcf increase in horizontal well production from our Permian properties.
For the year ended December 31, 2012, natural gas revenues of $14.1 million represented a decrease of 47%, or $12.5$12.5 million, when compared to natural gas revenues of $26.7$26.7 million for the year ended December 31, 2011.2011. Natural gas production decreased29%, driven primarily by down time at our Haynesville well, which was shut-in for 70 days during the first quarter of 2012 due to well interference from an offsetting well, and due to down time at our East Cameron 257 well, which was suspended in the fourth quarter of 2011 due to a natural gas leak in an upstream section of the Stingray Pipeline that transports production volumes from the field. Production from our East Cameron 257 well is expected to resume once the pipeline is brought back online during the second quarter of 2013. Also contributing to the decline was the previously discussed down-time at our Habanero and Medusa fields and normal and expected declines in natural gas production from our offshore and Haynesville wells. In addition to production decreases,, the average realized price decreased25% to $3.94$3.94 per Mcf compared to an average realized price of $5.25$5.25 per Mcf in 2011.2011. Our natural gas prices on an MMBtu equivalent basis exceeded the related NYMEX prices primarily due to the value of the NGLs in our natural gas stream, primarily from our Permian basin and deepwater production.
Operating Expenses
Principal components of our cost structure
Lease operating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.
For the year ended December 31, 2011,Production taxes. Production taxes include severance and ad valorem taxes. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of $26.7 million represented an increaseour oil and gas properties.
Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of 8% or $2.0 million when compared toproduction basis based on proved oil and natural gas revenuesreserve quantities. We calculate depletion on the following types of $24.6 millioncosts: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the year ended December 31, 2010. Natural gasestimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.
General and administrative. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production increased 4%, primarily driven by production from our Haynesville Shale natural gas well, which was placedand development operations, franchise taxes, audit and other fees for professional services and legal compliance.
Accretion expense. The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on production during September 2010, and due to down time at our East Cameron #2 field, which was shut-in during the first quarter of 2010 for repairs to the host facility and did not return to production until December 2010. In addition to production increases, the average realized price increased 4% to $5.25 per Mcf compared to an average realized price of $5.04 per Mcf in 2010. Our natural gas prices on an MMBtu equivalent basis exceeded the related NYMEX prices primarily due to thepresent value of the NGLsasset retirement obligations and reported as accretion expense within operating expenses in our natural gas stream, primarily from our Permian basin and deepwater production. Offsetting the increases in production are normal and expected declines in production from our other natural gas properties and a 35-day shut-in, asconsolidated statements of December 31, 2011, of our Haynesville well due to interference caused by an offsetting well. The Haynesville well returned to production in mid-March 2012.operations.
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| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Operating Expenses
| | | | | For the year ended December 31, | | For the Year Ended December 31, |
| | | | | | | | | | | Total Change | | Boe Change | | | | | | | | | | Total Change | | BOE Change |
| | | 2012 | | Per Boe | | 2011 | | Per Boe | | $ | | % | | $ | | % | | 2013 | | Per BOE | | 2012 | | Per BOE | | $ | | % | | $ | | % |
| Lease operating expenses | | $ | 26,554 |
| | $ | 16.86 |
| | $ | 20,347 |
| | $ | 11.04 |
| | $ | 6,207 |
| | 31 | % | | $ | 5.82 |
| | 53 | % | | $ | 19,779 |
| | $ | 14.00 |
| | $ | 23,330 |
| | $ | 14.81 |
| | $ | (3,551 | ) | | (15 | )% | | $ | (0.81 | ) | | (5 | )% |
| Production taxes | | | 4,133 |
| | 2.92 |
| | 3,224 |
| | 2.05 |
| | 909 |
| | 28 | % | | 0.87 |
| | 42 | % |
| Depreciation, depletion and amortization | | 49,701 |
| | 31.56 |
| | 48,701 |
| | 26.42 |
| | 1,000 |
| | 2 | % | | 5.14 |
| | 19 | % | | 43,967 |
| | 31.12 |
| | 49,701 |
| | 31.56 |
| | (5,734 | ) | | (12 | )% | | (0.44 | ) | | (1 | )% |
| General and administrative | | 20,358 |
| | 12.93 |
| | 16,636 |
| | 9.03 |
| | 3,722 |
| | 22 | % | | 3.9 |
| | 43 | % | | 20,534 |
| | 14.53 |
| | 20,358 |
| | 12.93 |
| | 176 |
| | 1 | % | | 1.6 |
| | 12 | % |
| Accretion expense | | 2,253 |
| | 1.43 |
| | 2,338 |
| | 1.27 |
| | (85 | ) | | (4 | )% | | 0.16 |
| | 13 | % | | 1,785 |
| | 1.26 |
| | 2,253 |
| | 1.43 |
| | (468 | ) | | (21 | )% | | (0.17 | ) | | (12 | )% |
| Impairment of other property and equipment (See Note 3) | | 1,177 |
| | 0.75 |
| | — |
| | — |
| | 1,177 |
| | 100 | % | | 0.75 |
| | 100 | % | |
| Impairment of other property and equipment | | | 1,707 |
| | 1.21 |
| | 1,177 |
| | 0.75 |
| | 530 |
| | 45 | % | | 0.46 |
| | 100 | % |
| Total operating expenses | | $ | 100,043 |
| | | | $ | 88,022 |
| | | | | | | | | | | | $ | 91,905 |
| | | | $ | 100,043 |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the year ended December 31, | | For the Year Ended December 31, |
| | | | | | | | | | | Total Change | | Boe Change | | | | | | | | | | Total Change | | BOE Change |
| | | 2011 | | Per Boe | | 2010 | | Per Boe | | $ | | % | | $ | | % | | 2012 | | Per BOE | | 2011 | | Per BOE | | $ | | % | | $ | | % |
| Lease operating expenses | | $ | 20,347 |
| | $ | 11.04 |
| | $ | 17,712 |
| | $ | 10.58 |
| | 2,635 |
| | 15 | % | | $ | 0.46 |
| | 4 | % | | $ | 23,330 |
| | $ | 14.81 |
| | $ | 18,285 |
| | $ | 9.92 |
| | $ | 5,045 |
| | 28 | % | | $ | 4.89 |
| | 49 | % |
| Production taxes | | | 3,224 |
| | 2.05 |
| | 2,062 |
| | 1.12 |
| | 1,162 |
| | 56 | % | | 0.93 |
| | 83 | % |
| Depreciation, depletion and amortization | | 48,701 |
| | 26.42 |
| | 31,805 |
| | 19.00 |
| | 16,896 |
| | 53 | % | | 7.42 |
| | 39 | % | | 49,701 |
| | 31.56 |
| | 48,701 |
| | 26.42 |
| | 1,000 |
| | 2 | % | | 5.14 |
| | 19 | % |
| General and administrative | | 16,636 |
| | 9.03 |
| | 16,507 |
| | 9.86 |
| | 129 |
| | 1 | % | | (0.83 | ) | | (8 | )% | | 20,358 |
| | 12.93 |
| | 16,636 |
| | 9.03 |
| | 3,722 |
| | 22 | % | | 3.90 |
| | 43 | % |
| Accretion expense | | 2,338 |
| | 1.27 |
| | 2,446 |
| | 1.46 |
| | (108 | ) | | (4 | )% | | (0.19 | ) | | (13 | )% | | 2,253 |
| | 1.43 |
| | 2,338 |
| | 1.27 |
| | (85 | ) | | (4 | )% | | 0.16 |
| | 13 | % |
| Acquisition expense | | — |
| | — |
| | 233 |
| | 0.14 |
| | (233 | ) | | (100 | )% | | (0.14 | ) | | (100 | )% | |
| Impairment of other property and equipment | | | 1,177 |
| | 0.75 |
| | — |
| | — |
| | 1,177 |
| | 100 | % | | 0.75 |
| | 100 | % |
| Total operating expenses | | $ | 88,022 |
| | | | $ | 68,703 |
| | | | | | | | | | | | $ | 100,043 |
| | | | $ | 88,022 |
| | | | | | | | | | |
Lease Operating Expenses (LOE)
For the year ended December 31, 20122013, lease operating expenses ("LOE")LOE of $26.619.8 million increaseddecreased 31%15%, or $6.23.6 million, compared to $20.323.3 million for the year ended December 31, 20112012. The decrease was primarily due to $3.4 million of remediation costs on our Haynesville well in 2012, for which we had no similar costs in 2013, and an estimated decrease of $3.2 million of LOE resulting from the previously discussed sale of our interests in Habanero, Medusa, the Medusa Spar LLC, our Haynesville property and substantially all our remaining shelf properties. These decreases were partially offset by $3.0 million in LOE costs related to the growth in Permian production and operations, including an increase in workover expenses associated with accelerated horizontal well activity.
For the year ended December 31, 2012, LOE of $23.3 million increased 28%, or $5.0 million, compared to $18.3 million for the year ended December 31, 2011. The increase was primarily due to $4.2$3.0 million in costs related to significant growth in the number of wells now producing in ourfrom Permian basinBasin properties and $3.3 million associated with thein remediation work on theat our Haynesville well.well in 2012 for which we had no similar costs in 2011. These increases were partially offset by a $1.3 million decline in LOE for our deepwater properties due to lower throughput charges as a result of reduced production volumes discussed previously.volumes.
Production Taxes
For the year ended December 31, 2013, production taxes of $4.1 millionincreased28%, or $0.9 million, compared to $3.2 million for the year ended December 31, 2012. The increase was predominantly attributable to an increase of onshore production subject to these taxes and a decline in offshore production, resulting from the sale of our Gulf of Mexico position in 2013, which is exempt from production taxes.
For the year ended December 31, 2011, lease operating expenses ("LOE")2012, production taxes of $20.33.2 millionincreased by 56%15%, or $2.61.2 million, compared to $17.72.1 million for the year ended December 31, 2010.2011. The significant growth in the number of wells now producing in our Permian basin properties and our Haynesville Shale well increased total LOE approximately $3.6 million , or $1.95 on a per Boe basis, compared to the corresponding period of 2010. Additionally, total LOE increased approximately $0.5 million related to Medusa Spar maintenance work, the increased production from the Medusa A6 well following the well recompletion, and increased $0.8 million due to processing fees at our East Cameron #2 well, which resumed production in December 2010 after being shut-in for repairs on the host facility during the first quarter of 2010. Partially offsetting these increasesincrease was a mix of lower LOE related primarily to our shelf properties.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization (“DD&A”) for the year ended December 31, 2012increased19% per Boe to $31.56 per Boe compared to $26.42 per Boe for the year ended December 31, 2011. The prior period DD&A rates were effectively reduced by the impact of a $486 million 2008 impairment charge following a ceiling test writedown. This significant oil and natural gas property impairment charge resulted in a lower, prospective DD&A rate for the then existing reserves. Increases in the DD&A rate subsequent to that impairment arepredominantly attributable to our planned exploration and development expenditures relatedan increased proportion of onshore production subject to our onshore reserve development including the ongoing onshore development cost increases in the Permian basin area. We currently estimate that a normalized DD&A rate for our properties will approximate $36.00 per Boe.these taxes relative to offshore production, which was predominantly exempt from production taxes.
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| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Depreciation, depletionDepletion and amortization (“DD&A”) for the year ended December 31, 2011 increased 39% per Boe to $26.42 per Boe compared to $19.00 per Boe for the year ended December 31, 2010. Onshore development cost increases account for nearly all of the increase.
General and Administrative, net of amounts capitalizedAmortization (DD&A)
For the year ended December 31, 20122013, generalDD&A of $31.12 per BOE was relatively flat compared to $31.56 per BOE for the year ended December 31, 2012.
DD&A for the year ended December 31, 2012 increased 19% per BOE to $31.56 per BOE compared to $26.42 per BOE for the year ended December 31, 2011. Increases in the DD&A rate are attributable to our planned exploration and administrative (“G&A”) expenses,development expenditures related to our onshore reserve development including the ongoing onshore development cost increases in the Permian Basin area.
General and Administrative, net of amounts capitalized increased(G&A)
G&A remained relatively flat at $20.5 million (including $6.4 million non-cash) for the year ended $3.7 millionDecember 31, 2013 or 22%compared to $20.4$20.4 million from $16.6 (including $4.7 million non-cash) for the same period of 20112012.The $0.1 million increase was due to an increase in non-cash charges of $1.7 million related to incentive compensation share-based instruments offset by a $1.6 million decrease primarily related to non-recurring employee-related expenses including early retirement and severance expense incurred in 2012. The non-cash portions primarily relate to our liability-based incentive compensation share based instruments (see Notes 7 and 8 ) and to depreciation and amortization expense (see Note 2).
For the year ended December 31, 2012, G&A, increased $3.7 million, or 22%, to $20.4 million (including $4.7 million non-cash) from $16.6 million (including $3.2 million non-cash) for the same period of 2011. The increase is due mainly to$1.6 $1.6 million in costs for non-recurring employee-related expenses including early retirement and severance expense for which we had no expense during the same period of 2011. Additionally, we incurred an increase in non-cash charges of $1.2 million related to incentive compensation share-based instruments awarded during 2012. The remaining increase relatesrelated primarily to higher compensation-related expenses including the costs associated with employing staff to support our onshore growth and 100% operated Permian production, as well as relocation and related costs.
For the year ended December 31, 2011, G&A expenses of $16.6 million, net of amounts capitalized, was relatively flat compared to $16.5 million for the year ended 2010.
Accretion Expense (ARO)
Accretion expense related to our asset retirement obligation decreased 4%decreased21% for the year ended December 31, 20122013 compared to the same periods of 2011.2012. Accretion expense correlates directionally with the Company's asset retirement obligation (“ARO”). AtCompany’s ARO which was $6.7 million at December 31, 2013 versus $13.3 million at December 31, 2012, our ARO of $13.3 million was lower than the $13.9 million ARO at December 31, 2011. See Note 1311 for additional information regarding the Company'sCompany’s ARO.
For the year ended December 31, 2011,2012, accretion expense decreased 4% for the year ended December 31, 20112012 compared to the same periods of 2010. The Company's accretion expense decreases as its ARO decreases.2011. At December 31, 2011,2012, our ARO of $13.9$13.3 million was lower than the $15.9$13.9 million ARO at December 31, 2010. See Note 13 for additional information regarding the Company's ARO.2011.
Impairment of Other Property and Equipment
During 2012 and 2013, the Company recorded a write-down of the value of certain assets acquired in 2011 as part of a settlement reached with a former joint interest partner on a deepwater project. For information concerning the impairment of these assets, which are currently classified as available for sale, please see Note 313 to the Consolidated Financial Statements.
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Other (Income) Expense
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the year ended December 31, |
| | | 2012 | | 2011 | | $ Change | | % Change | | 2010 | | $ Change | | % Change |
| Interest expense | | $ | 9,108 |
| | $ | 11,717 |
| | $ | (2,609 | ) | | (22 | )% | | $ | 13,312 |
| | $ | (1,595 | ) | | (12 | )% |
| (Gain) loss on early extinguishment of debt | | (1,366 | ) | | (1,942 | ) | | 576 |
| | 30 | % | | 339 |
| | (2,281 | ) | | (673 | )% |
| Gain on acquired assets (See Note 3) | | — |
| | (5,041 | ) | | 5,041 |
| | 100 | % | | — |
| | (5,041 | ) | | (100 | )% |
| Gain on derivative contracts | | (1,717 | ) | | — |
| | (1,717 | ) | | (100 | )% | | — |
| | — |
| | — | % |
| Other (income) expense | | (79 | ) | | (1,426 | ) | | 1,347 |
| | 94 | % | | (257 | ) | | (1,169 | ) | | (455 | )% |
| Total other expenses,net | | $ | 5,946 |
| | $ | 3,308 |
| | | | | | $ | 13,394 |
| | | | |
| | | | | | | | | | | | | | | |
| Income tax expense (benefit) | | $ | 2,223 |
| | $ | (69,283 | ) | | $ | 71,506 |
| | 103 | % | | $ | (174 | ) | | $ | (69,109 | ) | | (39,718 | )% |
| Equity in earnings of Medusa Spar LLC | | 226 |
| | 799 |
| | (573 | ) | | (72 | )% | | 427 |
| | 372 |
| | 87 | % |
Interest Expense
Interest expense on Callon's debt obligations decreased22%expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our credit facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to $9.1 million forour lender in interest expense. In addition, we include the year ended December 31, 2012 comparedamortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense. The amortization of the deferred credit related to $11.7 million for the same period of 2011. The decrease relates primarily to the redemption of $10 million principal ofour 13% Senior Notes during June 2012 in additionis recorded as an offset to a $1.5 millionincrease in capitalized interest compared to 2011, partially offset by interest expense related to increased borrowings under our Credit Facility and decreases in the deferred credit amortization. The increase in capitalized interest relates to a higher balance year-over-year in average unevaluated oil and natural gas properties following the purchase of additional unevaluated acreage with exploration costs in the Permian basin.
Interest expense on Callon's debt obligations decreased 12% to $11.7 million for the year ended December 31, 2011 compared to $13.3 million for the same period of 2010. The decrease relates primarily to the redemption of $31 million principal of 13% Senior Notes during March 2011. This early redemption reduced interest expense by approximately $3.2 million for the current year compared to 2010. Additionally, 2010 interest expense included approximately $0.5 million related to the remaining outstanding $16.1 million of 9.75% Senior Notes, which were redeemed on April 30, 2010 and were therefore not included in 2011 interest expense. Offsetting these declines in interest expense is a $1.4 million drop in capitalized interest in 2011 compared to 2010, and relates to a lower balance year-over-year in average unevaluated oil and natural gas properties following the transfer to evaluated earlier in 2011 of certain leases, primarily offshore, that the Company elected not to renew. Further offsetting the declines discussed above are slight decreases in the deferred credit amortization recorded in 2011 compared to 2010.
(Gain) Loss on Early Extinguishment of Debt
During June 2012, the Company redeemed $10 million of its Senior Notes with a carrying value of $11.6 million , including $1.6 million of the Notes’ deferred credit, in exchange for $10.2 million , comprised of the $10 million principal of the Notes and $0.2 million of redemption expenses, which resulted in a $1.4 million net gain on the early extinguishment of debt.
During March 2011, using a portion of the proceeds from the Company's February 2011 equity offering, the Company redeemed 13% Senior Notes with a carrying value of $37 million, including $6.0 million of the Notes' deferred credit, in exchange for $35.1 million, comprised of the $31 million principal of the notes, the $4.0 million call premium and miscellaneous redemption expenses, which resulted in a $1.9 million net gain on the early extinguishment of debt.
Gain on Acquired Assets
During 2011 and related to the 2012 activity mentioned above, we entered into a settlement with a former deepwater joint interest partner, which included the transfer of certain assets and liabilities to Callon with estimated net fair values of $8.7 million. The assets acquired consisted primarily of the surplus project equipment while the liabilities assumed consisted of deferred tax liabilities associated with the basis difference of the equipment. The adjusted fair market value of the net assets acquired was recorded during 2011 as a $5.0 million gain and a $3.7 million adjustment to our full cost pool of oil and gas properties. The gain recognition was required as a result of our acquiring the joint interest partner's former share of the assets, and the full cost pool adjustment was required to reflect our share of the assets held prior to the deconsolidation of a related subsidiary in 2010. See Note 3 for additional information concerning the gain on acquired assets.
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Gain on Derivative Contracts
As discussed in Note 6 and beginning with derivative contracts executed in 2012, the Company elected to no longer designate its derivative contracts as accounting hedges. For the year ended December 31, 2012, unrealized losses and gains on mark-to-market derivative instruments, net were $1.7 milliongain, compared to none in 2011 when all derivative contracts were designated as hedges for accounting purposes. See Notes 6 and 7 for disclosures related to derivative instruments including their composition and valuation.
Income Tax Expense (Benefit)
The income tax expense of $2.2 million in 2012 resulted primarily from pre-tax income earnings of $4.7 million. See Note 11 for a discussion of our effective tax rate.
PriorGain/Loss on derivative instruments. We utilize commodity derivative financial instruments to 2012, we carriedreduce our exposure to fluctuations in the price of oil. This amount represents the (i) gain (loss) related to derivatives, net of settlement that relate to our open derivative contracts as commodity prices change and commodity derivative contracts expire or new ones are entered into and (ii) gains (losses) on derivatives, settled that is equal to the summation of gains and losses on positions that have settled within the period. We provide a full valuation allowance against our net deferred tax asset. The income tax benefit of $69.3 million in 2011 resulted primarily from the reversalreconciliation of the valuation allowance established in 2008 against our net deferred tax assets. As a result of reporting net income from 2009 to 2011, we achieved income on an aggregate basis for the three-year period ended December 31, 2011. Additionally we expect to generate sufficient taxable income necessary to fully utilize allthese components of the deferred tax assets prior to their expiration. Consequently, we reversed the $69.3 million valuation allowance at December 31, 2011. For additional information, seegain/loss on derivative contracts in Note 115 to the Consolidated Financial Statements..
Off-Balance Sheet Arrangements
The Company holds a 10% ownership interest in Medusa Spar LLC (“LLC”), which is accounted for underIncome tax expense. We use the equityasset and liability method of accounting for investments. The LLC owns a 75% undivided ownership interest inincome taxes, under which deferred tax assets and liabilities are recognized for the deepwater spar production facilities atfuture tax consequences of (1) temporary differences between the Company’s Medusa field in the Gulf of Mexico. The LLC earns a tariff based upon production volume throughput from the Medusa area. Callon is obligated to process through the spar production facilities its share of production from the Medusa fieldfinancial statement carrying amounts and any future discoveries in the area. The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. and Murphy Oil Corporation.
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| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized.
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| | | For the Year Ended December 31, |
| | | 2013 | | 2012 | | $ Change | | % Change | | 2011 | | $ Change | | % Change |
| Interest expense | | $ | 6,094 |
| | $ | 9,108 |
| | $ | (3,014 | ) | | (33 | )% | | $ | 11,717 |
| | $ | (2,609 | ) | | (22 | )% |
| Gain on early extinguishment of debt | | (3,696 | ) | | (1,366 | ) | | (2,330 | ) | | 171 | % | | (1,942 | ) | | 576 |
| | (30 | )% |
| Gain on acquired equipment | | — |
| | — |
| | — |
| | — | % | | (5,041 | ) | | 5,041 |
| | (100 | )% |
| Loss (gain) on derivative contracts | | 1,360 |
| | (1,717 | ) | | 3,077 |
| | (179 | )% | | — |
| | (1,717 | ) | | 100 | % |
| Other income | | (485 | ) | | (79 | ) | | (406 | ) | | 514 | % | | (1,426 | ) | | 1,347 |
| | (94 | )% |
| Total other expenses, net | | $ | 3,273 |
| | $ | 5,946 |
| | | | | | $ | 3,308 |
| | | | |
| | | | | | | | | | | | | | | |
| Income tax expense (benefit) | | $ | 3,104 |
| | $ | 2,223 |
| | $ | 881 |
| | (40 | )% | | $ | (69,283 | ) | | $ | 71,506 |
| | 103 | % |
| Equity in earnings of Medusa Spar LLC | | 17 |
| | 226 |
| | (209 | ) | | (92 | )% | | 799 |
| | (573 | ) | | (72 | )% |
| Preferred stock dividends | | (4,627 | ) | | — |
| | (4,627 | ) | | 100 | % | | — |
| | — |
| | — | % |
Interest Expense
Interest expense on Callon’s debt obligations decreased 3.0 million to $6.1 million for the year ended December 31, 2013 compared to $9.1 million for the same period of 2012. The decrease was related primarily to an additional $2.3 million of interest capitalized in 2013 versus 2012, to approximately $0.3 million of reduced interest payments attributable to the redemption of $48.5 million principal of the Company’s Senior Notes in December 2013 and to $0.1 million of additional deferred credit amortization recognized in 2013 compared with 2012. The additional capitalized interest was related to a higher balance year-over-year in average unevaluated oil and natural gas properties following the purchase of additional unevaluated acreage with exploration costs in the Permian Basin.
Interest expense on Callon’s debt obligations decreased 22% to $9.1 million for the year ended December 31, 2012 compared to $11.7 million for the same period of 2011. The decrease was related primarily to the redemption of $10 million principal of Senior Notes during June 2012 in addition to a $1.5 million increase in capitalized interest compared to 2011, partially offset by interest expense related to increased borrowings under our Credit Facility and decreases in the deferred credit amortization. The increase in capitalized interest was related to a higher balance year-over-year in average unevaluated oil and natural gas properties, mentioned above.
(Gain) Loss on Early Extinguishment of Debt
During December 2013, the Company redeemed $53.8 million carrying value of its Senior Notes using a portion of the proceeds from the Company’s May 2013 preferred equity offering. The $53.8 million of carrying value included $48.5 million of principal value and $5.3 million of unamortized deferred credit. The Company recognized a net gain of $3.7 million on the early extinguishment of debt, comprised of the recognition of $5.3 million in deferred credit, offset by $1.6 million of redemption expenses. See Note 4 for additional information concerning the gain on early extinguishment of debt.
During June 2012, the Company redeemed $10 million of its Senior Notes with a carrying value of $11.6 million, including $1.6 million of the Senior Notes’ deferred credit. The Company recognized a net gain of $1.4 million on the early extinguishment of debt, comprised of the recognition of $1.6 million in deferred credit, offset by $0.2 million of redemption expenses.
Gain on Acquired Equipment
See Note 13 for additional information concerning the gain on acquired equipment.
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| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Loss (Gain) on Derivative Contracts
Beginning in 2012, the Company elected to no longer designate its derivative contracts as accounting hedges. For the year ended December 31, 2013, net losses on mark-to-market derivative instruments, net of settlements were $1.4 million, compared to $1.7 million gain in 2012. See Notes 5 and 6 for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.
Income Tax Expense (Benefit)
The income tax expense of $3.1 million in 2013 resulted primarily from pre-tax income earnings of $7.4 million. The effective tax rate of 42% in 2013 and 47% in 2012 differed from the federal income tax rate of 35% primarily due to the effect of state taxes, non-deductible compensation under Section 162(m) and restricted stock offset by percentage depletion. See Note 10 for a discussion of our effective tax rate. Prior to 2012, we carried a full valuation allowance against our net deferred tax asset. The income tax benefit of $69.3 million in 2011 resulted primarily from the reversal of the valuation allowance established in 2008 against our net deferred tax assets as we achieved income on an aggregate basis for a cumulative three-year period and expect to generate the taxable income necessary to fully utilize the deferred tax assets prior to their expiration. For additional information, see Note 11 to the Consolidated Financial Statements.
Preferred Stock Dividends
Preferred Stock dividends for the year ended December 31, 2013 increased $4.6 million compared to the same period of 2012 in which we had no dividend expense. The expense is reflective of the Preferred Stock being outstanding only since its issuance on May 30, 2013, resulting in a reduced stub period payment during the second quarter of 2013.
Summary of Significant Accounting Policies and Critical Accounting Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been use. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See Note 2 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K for a discussion of additional accounting policies and estimates made by management.
Property and Equipment
The Company utilizes the full-cost method of accounting for its oil and natural gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves, including certain overhead costs, are capitalized into the “full-cost pool.” The amounts capitalized into the full-cost pool are depleted (charged against earnings) using the unit-of-production method. The full-cost method of accounting for our proved oil and natural gas properties requires that the Company makes estimates based on its assumptions of future events that could change. These estimates are described below.
Depreciation, Depletion and Amortization (DD&A) of Oil and Natural Gas Properties
The Company calculates depletion by using the depletable base, equal to the net capitalized costs in our full-cost pool plus estimated future development costs, and the estimated net proved reserve quantities. Capitalized costs added to the full-cost pool include the following:
costs of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay rentals and other costs related to exploration and development of our crude oil and natural gas properties;
payroll costs including the related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of crude oil and natural gas properties as well as other directly identifiable general and administrative costs
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| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
associated with such activities. Such capitalized costs do not include any costs related to the production of crude oil and natural gas or general corporate overhead;
costs associated with unevaluated properties, those lacking proved reserves, are excluded from the depletable base. These unevaluated property costs are added to the depletable base at such time as wells are completed on the properties, the properties are sold or the Company determines these costs have been impaired. The Company’s determination that a property has or has not been impaired (which is discussed below) requires assumptions about future events;
estimated costs to dismantle, abandon and restore properties that are capitalized to the full-cost pool when the related liabilities are incurred (see also the discussion below regarding Asset Retirement Obligations);
estimated future costs to develop proved properties are added to the full-cost pool for purposes of the DD&A computation. The Company uses assumptions based on the latest geologic, engineering, regulatory and cost data available to it to estimate these amounts. However, the estimates made are subjective and may change over time. The Company’s estimates of future development costs are reviewed at least annually and as additional information becomes available; and
capitalized costs included in the full-cost pool plus estimated future development costs are depleted and charged against earnings using the unit-of-production method. Under this method, the Company estimates the proved reserves quantities at the beginning of each accounting period. For each McfeBOE produced during the period, the Company records a depletion charge equal to the amount included in the depletable base (net of accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve quantities.
Because the Company uses estimates and assumptions to calculate proved reserves (as discussed below) and the amounts included in the depletable base, our depletion rates may materially change if actual results differ from these estimates.
Ceiling Test
Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved crude oil and natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized costs of proved crude oil and natural gas properties exceed the estimated discounted (at 10%) future net cash flows from proved reserves, the Company is required to write-down the value of its crude oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are based on a twelve-month average pricing assumption and include consideration of existing cash flow hedges. Given the volatility of crude oil and natural gas prices, it is reasonably possible that the Company’s estimates of discounted future net cash flows from proved
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
crude oil and natural gas reserves could change in the near term. If crude oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of crude oil and natural gas properties could occur in the future. See Notes 2 and 12 for additional information regarding the Company’s crude oil and natural gas properties.
Estimating Reserves and Present Value of Estimated Future Net Cash Flows
Estimates of quantities of proved crude oil and natural gas reserves, including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These assumptions include:
the prices at which the Company can sell its crude oil and natural gas production in the future. Crude oilOil and natural gas prices are volatile, but we are required to assume that they remain constant.constant, using the twelve-month average pricing assumption. In general, higher crude oil and natural gas prices will increase quantities of proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts; and
the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are depleted. These costs are likely to change over time.time, but we are required to assume that they remain constant. Increases in costs will reduce estimated crude oil and natural gas quantities and the present value of estimated future net cash flows, while decreases in costs will increase such amounts.
Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated quantities of oil and natural gas reserves for the Company’s properties that have relatively short productive lives.
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| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
In addition, the process of estimating proved crude oil and natural gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of crude oil and natural gas prices under “Risk Factors.”
Sales of crude oil and natural gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.
Unproved Properties
Costs, including capitalized interest, associated with properties that do not have proved reserves are excluded from the depletable base, and are included in the line item “Unevaluated properties excluded from amortization.” Unproved property costs are transferred to the depletable base when wells are completed on the properties or the properties are sold. In addition, the Company is required to determine whether its unproved properties are impaired and, if so, include the costs of such properties in the depletable base. The Company determines whether an unproved property is impaired by periodically reviewing its exploration program on a property-by-property basis. This determination may require the exercise of substantial judgment by management.
Asset Retirement Obligations
We are required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligation and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. See Note 1311 for additional information.
Derivatives
To manage crude oil and natural gas price risk on a portion of our planned future production, we have historically utilized commodity derivative instruments (including collars, swaps, puts, and other structures) on approximately 50% of our projected production volumes in any given year. We do not use these instruments for trading purposes. Settlement of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other cash or futures index price.
Beginning in 2012, we elected to no longer designate derivative contracts executed after January 1, 2012 as accounting hedges under FASB ASC 815-20-25. As such and beginning with derivative contracts executed during 2012, all derivative positions are carried at their fair value on the balance sheet and are marked-to-market through earnings at the end of each period. Realized gains (losses) related to cash settlementsGains and losses on these contractsderivatives that are not designated as hedges are recorded in the Statementearnings as a component of Operations as an increase or decrease in crude oil and natural gas sales. Unrealized gains (losses) related to ourgain (loss) on derivative contracts. Within gain (loss) on derivative contracts not designated as accounting hedges
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Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
are recordedline in the Statementstatement of Operations as an increase or decrease in Unrealizedoperations are gains (losses) on mark-to-market derivative instruments.derivatives, net of settlement and gains (losses) on derivatives, settled.
Derivative contracts that existedwere entered into at and prior to December 31, 2011 were accounted for as cash flow hedges, and were recorded at fair market value on its consolidated balance sheet. Changes in fair value were recorded through other comprehensive income (loss), net of tax, in stockholders’ equity. The changes in fair value related to ineffective derivative contracts arewere recognized as derivative expense (income). The estimated fair value of our derivative contracts is based upon closing exchange prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding derivatives and their fair values, see Notes 65 and 76 to the Consolidated Financial Statements and Part II, Item 7A Commodity Price Risk.
Income Taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing crude oil and natural gas prices). See Note 1110 for additional information regarding Income Taxes.
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| Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
Recent Accounting Standards
Various accounting standards and interpretations were issued in 20122013 with effective dates subsequent to December 31, 20122013. We have evaluated the recently issued accounting pronouncements that are effective in 20132014 and believe that none of them will have a material effect on our financial position, results of operations or cash flows when adopted. For a discussion of recently issued accounting standards, see Note 2 to the Consolidated Financial Statements.
In February 2013, the Financial Accounting Standards Board issued an Accounting Standards Update (ASU) that clarified the reclassification requirements from accumulated other comprehensive income to net income. This ASU requires disclosure of amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present either on the face of the financial statements or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount is reclassified in its entirety to net income in the same reporting period. For amounts not reclassified in their entirety to net income, an entity is required to cross-reference to the related note on the face of the financial statements for additional information. Callon adopted this guidance effective January 1, 2013, which did not have a material impact on its financial statements.
49
ITEM 7A. Quantitative and Qualitative Disclosures about Market Risks
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.
Commodity Price Risk
The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil and natural gas, which have historically been very volatile due to unpredictable events such as economicaleconomic growth or retraction, weather and climate, changes in supply and government actions. Crude oilOil and natural gas price declines and volatility could adversely affect the Company’s revenues, cash flows and profitability. Price volatility is expected to continue. Using the Company'sCompany’s annual sales volumes for 20122013, excluding the effects of the Company’s hedging program, a 10% decline in the NYMEX price of crude oil and natural gas would have reduced our revenues by approximately $9.18.9 million and $1.31.2 million, respectively.
While the Company does not enter into derivative transactions for speculative purposes, in order to limit its exposure to this risk, the Company sometimes utilizes price "collars,"collars, swaps, puts and other structures to reduce the risk of changes in crude oil and natural gas prices. Under a collar arrangements, no payments are due by either party as long as the market price is above the floor price and below the ceiling price set in the collar. If the price falls below the floor, the counterparty to the collar pays the difference to Callon, and if the price rises above the ceiling, Callon pays the difference to the counterparty. Fixed price “swaps”swaps reduce the Company'sCompany’s exposure to decreases in commodity prices, while simultaneously limiting the benefit the Company might otherwise have received from any increases in commodity prices. The Company’s derivatives policy also allows Callon to, at its discretion, purchase or sale “puts.”sell puts. Purchased "puts"puts reduce the Company'sCompany’s exposure to decreases in prices of the hedged commodity while allowing realization of the full benefit from any increases those prices. If the commodity price falls below the "put"put price, the counter-party pays the difference to Callon. Conversely, sold "puts"puts expose the Company to risk whereby Callon would pay its counter-party if prices fall below the "put"put price. See Note 65 to the Consolidated Financial Statements for a description of our hedged position at December 31, 20122013.
Interest Rate Risk
On December 31, 20122013, the majority of the Company'sCompany’s debt consisted of its fixed-rate 13% Senior Notes. However, we are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility and our Second Lien Facility into which we entered during March 2014. As of December 31, 2013, the Company’sweighted average interest rate on our Credit Facility with Regions Bank includes a variable interest rate, and as such fluctuates based on short-term interest rates. Although the Company had $10 millionborrowings outstanding at December 31, 2012 under its Credit Facility, were the Company to fully draw its available $65 million borrowing base at the beginningwas 2.9%. An increase or decrease of the year, a 100 basis point change1% in the variable interest rate would have a corresponding decrease or increase in our net income of approximately $0.2 million based on the Company’s annual interest expense by $0.65 million. For additional information, see Note 5$22 million tooutstanding in the Consolidated Financial Statements additional information regarding the Company’saggregate under our Credit Facility and other borrowings at on December 31, 2012.2013.
Counterparty and Customer Credit Risk
Our principal exposures to credit risk are through receivables resulting from derivatives financial contracts, joint interest receivables and the receivables from the sale of our oil and natural gas production, which we market to energy marketing companies.
At December 31, 2013 our receivables resulting from derivative financial contracts was approximately $0.1 million. Our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. The counterparties on our derivative instruments currently in place are lenders under our revolving credit facility. We are likely to enter into additional derivative instruments with these or other lenders under our revolving credit facility, representing institutions with an investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. At December 31, 2013 we had a net derivative asset position of $0.1 million and a net derivative liability position of $1.1 million.
Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2013 our joint interest receivables were approximately $4.4 million.
We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require any of our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the year ended December 31, 2013, three purchasers accounted for more than 10% of our revenue: Enterprise Crude Oil, LLC (38%); Shell Trading Company (31%); and Plains Marketing, L.P. (15%). At December 31, 2013 our receivables from the sale of our oil and natural gas production were approximately $13.2 million in total.
ITEM 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Callon Petroleum Company
We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of December 31, 20122013 and 2011,2012, and the related consolidated statements of operations, comprehensive income, stockholders'stockholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2012.2013. These financial statements are the responsibility of the Company'sCompany’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Callon Petroleum Company as of December 31, 20122013 and 2011,2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012,2013, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Callon Petroleum Company’s internal control over financial reporting as of December 31, 2012,2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated March 14, 201312, 2014, expressed an unqualified opinion thereon.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 14, 201312, 2014
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
| | | | December, 31 | For the Year Ended December, 31 |
| | 2012 | | 2011 | 2013 | | 2012 |
| ASSETS | | | | | | |
| Current assets: | | | | | | |
| Cash and cash equivalents | $ | 1,139 |
| | $ | 43,795 |
| $ | 3,012 |
| | $ | 1,139 |
|
| Accounts receivable | 15,608 |
| | 15,181 |
| 20,586 |
| | 15,608 |
|
| Fair market value of derivatives | 1,674 |
| | 2,499 |
| 60 |
| | 1,674 |
|
| Deferred tax asset, current | | 3,843 |
| | — |
|
| Other current assets | 1,502 |
| | 1,601 |
| 2,063 |
| | 1,502 |
|
| Total current assets | 19,923 |
| | 63,076 |
| 29,564 |
| | 19,923 |
|
| Crude oil and natural gas properties, full-cost accounting method: | | | | |
| Oil and natural gas properties, full-cost accounting method: | | | | |
| Evaluated properties | 1,497,010 |
| | 1,421,640 |
| 1,701,577 |
| | 1,497,010 |
|
| Less accumulated depreciation, depletion and amortization | (1,296,265 | ) | | (1,208,331 | ) | (1,420,612 | ) | | (1,296,265 | ) |
| Net oil and natural gas properties | 200,745 |
| | 213,309 |
| 280,965 |
| | 200,745 |
|
| Unevaluated properties excluded from amortization | 68,776 |
| | 2,603 |
| 43,222 |
| | 68,776 |
|
| Total oil and natural gas properties | 269,521 |
| | 215,912 |
| 324,187 |
| | 269,521 |
|
| Other property and equipment, net | 10,058 |
| | 10,512 |
| 7,255 |
| | 10,058 |
|
| Restricted investments | 3,798 |
| | 3,790 |
| 3,806 |
| | 3,798 |
|
| Investment in Medusa Spar LLC | 8,568 |
| | 9,956 |
| — |
| | 8,568 |
|
| Deferred tax asset | 64,383 |
| | 65,743 |
| 57,765 |
| | 64,383 |
|
| Other assets, net | 1,922 |
| | 718 |
| 1,376 |
| | 1,922 |
|
| Total assets | $ | 378,173 |
| | $ | 369,707 |
| $ | 423,953 |
| | $ | 378,173 |
|
| LIABILITIES AND STOCKHOLDERS' EQUITY | | | | | | |
| Current liabilities: | | | | | | |
| Accounts payable and accrued liabilities | $ | 36,016 |
| | $ | 26,057 |
| $ | 57,637 |
| | $ | 36,016 |
|
| Asset retirement obligations | 2,336 |
| | 1,260 |
| 4,120 |
| | 2,336 |
|
| Fair market value of derivatives | 125 |
| | — |
| 1,036 |
| | 125 |
|
| Total current liabilities | 38,477 |
| | 27,317 |
| 62,793 |
| | 38,477 |
|
| 13% Senior Notes: | | | | | | |
| Principal outstanding | 96,961 |
| | 106,961 |
| 48,481 |
| | 96,961 |
|
| Deferred credit, net of accumulated amortization of $17,800 and $13,123, respectively | 13,707 |
| | 18,384 |
| |
| Deferred credit, net of accumulated amortization of $20,814 and $17,800, respectively | | 5,267 |
| | 13,707 |
|
| Total 13% Senior Notes | 110,668 |
| | 125,345 |
| 53,748 |
| | 110,668 |
|
| | | | | | | |
| Senior secured revolving credit facility | 10,000 |
| | — |
| |
| Credit facility | | 22,000 |
| | 10,000 |
|
| Asset retirement obligations | 10,965 |
| | 12,678 |
| 2,612 |
| | 10,965 |
|
| Other long-term liabilities | 2,092 |
| | 3,165 |
| 3,706 |
| | 2,092 |
|
| Total liabilities | 172,202 |
| | 168,505 |
| 144,859 |
| | 172,202 |
|
| Stockholders' equity: | | | | | | |
| Preferred Stock, $.01 par value, 2,500,000 shares authorized; | — |
| | — |
| |
| Common Stock, $.01 par value, 60,000,000 shares authorized; 39,800,548 and 39,398,416 shares outstanding at December 31, 2012 and 2011, respectively | 398 |
| | 394 |
| |
| Preferred Stock, series A cumulative, $.01 par value and $50.00 liquidation preference, 2,500 shares authorized; 1,579 and 0 shares outstanding, respectively | | 16 |
| | — |
|
| Common Stock, $.01 par value, 60,000 shares authorized; 40,345 and 39,801 shares outstanding at December 31, 2013 and 2012, respectively | | 404 |
| | 398 |
|
| Capital in excess of par value | 328,116 |
| | 324,474 |
| 401,540 |
| | 328,116 |
|
| Other comprehensive income | — |
| | 1,624 |
| |
| Retained deficit | (122,543 | ) | | (125,290 | ) | (122,866 | ) | | (122,543 | ) |
| Total stockholders' equity | 205,971 |
| | 201,202 |
| 279,094 |
| | 205,971 |
|
| Total liabilities and stockholders' equity | $ | 378,173 |
| | $ | 369,707 |
| $ | 423,953 |
| | $ | 378,173 |
|
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
|
| | | | | | | | | | | |
| | For the year ended December 31, |
| | 2012 | | 2011 | | 2010 |
| Operating revenues: | |
| | | | |
| Crude oil sales | $ | 96,584 |
| | $ | 100,962 |
| | $ | 65,243 |
|
| Natural gas sales | 14,149 |
| | 26,682 |
| | 24,639 |
|
| Total operating revenues | 110,733 |
| | 127,644 |
| | 89,882 |
|
| Operating expenses: | |
| | |
| | |
|
| Lease operating expenses | 26,554 |
| | 20,347 |
| | 17,712 |
|
| Depreciation, depletion and amortization | 49,701 |
| | 48,701 |
| | 31,805 |
|
| General and administrative | 20,358 |
| | 16,636 |
| | 16,507 |
|
| Accretion expense | 2,253 |
| | 2,338 |
| | 2,446 |
|
| Acquisition expense | — |
| | — |
| | 233 |
|
| Impairment of other property and equipment (See Note 3) | 1,177 |
| | — |
| | — |
|
| Total operating expenses | 100,043 |
| | 88,022 |
| | 68,703 |
|
| Income from operations | 10,690 |
| | 39,622 |
| | 21,179 |
|
| Other (income) expenses: | |
| | |
| | |
|
| Interest expense | 9,108 |
| | 11,717 |
| | 13,312 |
|
| (Gain) loss on early extinguishment of debt | (1,366 | ) | | (1,942 | ) | | 339 |
|
| Gain on acquired assets (See Note 3) | — |
| | (5,041 | ) | | — |
|
| Gain on derivative contracts | (1,717 | ) | | — |
| | — |
|
| Other income, net | (79 | ) | | (1,426 | ) | | (257 | ) |
| Total other expenses, net | 5,946 |
| | 3,308 |
| | 13,394 |
|
| Income before income taxes | 4,744 |
| | 36,314 |
| | 7,785 |
|
| Income tax expense (benefit) | 2,223 |
| | (69,283 | ) | | (174 | ) |
| Income before equity in earnings of Medusa Spar LLC | 2,521 |
| | 105,597 |
| | 7,959 |
|
| Equity in earnings of Medusa Spar LLC | 226 |
| | 799 |
| | 427 |
|
| Net income available to common shares | $ | 2,747 |
| | $ | 106,396 |
| | $ | 8,386 |
|
| Net income per common share: | |
| | |
| | |
|
| Basic | $ | 0.07 |
| | $ | 2.81 |
| | $ | 0.29 |
|
| Diluted | $ | 0.07 |
| | $ | 2.76 |
| | $ | 0.28 |
|
| Shares used in computing net income per common share: | |
| | |
| | |
|
| Basic | 39,522 |
| | 37,908 |
| | 28,817 |
|
| Diluted | 40,337 |
| | 38,582 |
| | 29,476 |
|
CALLON PETROLEUM COMPANY
CONSOLIDATE STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
|
| | | | | | | | | | | |
| | For the year ended December 31, |
| | 2012 | | 2011 | | 2010 |
| Net income | $ | 2,747 |
| | $ | 106,396 |
| | $ | 8,386 |
|
| Other comprehensive income (loss): | | | | | |
| Change in fair value of derivatives designated as accounting hedges | (1,624 | ) | | 2,561 |
| | (1,082 | ) |
| Total other comprehensive income | $ | 1,123 |
| | $ | 108,957 |
| | $ | 7,304 |
|
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
(In thousands)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Preferred Stock | | Common Stock | | Capital in Excess of Par | | Accumulated Other Comprehensive Income (Loss) | | Retained Earnings (Deficit) | | Total Stockholders' Equity (Deficit) |
| Balance at December 31, 2009 | $ | — |
| | $ | 287 |
| | $ | 243,898 |
| | $ | 145 |
| | $ | (325,184 | ) | | $ | (80,854 | ) |
| Deconsolidation of subsidiary | — |
| | — |
| | — |
| | — |
| | 85,095 |
| | 85,095 |
|
| Comprehensive income: | |
| | |
| | |
| | |
| | |
| | |
|
| Net income | — |
| | — |
| | — |
| | — |
| | 8,386 |
| | |
|
| Other comprehensive loss | — |
| | — |
| | — |
| | (1,082 | ) | | — |
| | |
|
| Total comprehensive income | |
| | |
| | |
| | |
| | |
| | 7,304 |
|
| Shares issued pursuant to employee benefit plans | — |
| | 1 |
| | 192 |
| | — |
| | — |
| | 193 |
|
| Restricted stock | — |
| | 2 |
| | 4,070 |
| | — |
| | — |
| | 4,072 |
|
| Balance at December 31, 2010 | $ | — |
| | $ | 290 |
| | $ | 248,160 |
| | $ | (937 | ) | | $ | (231,703 | ) | | $ | 15,810 |
|
| Comprehensive income: | |
| | |
| | |
| | |
| | |
| | |
|
| Net income | — |
| | — |
| | — |
| | — |
| | 106,396 |
| | |
|
| Other comprehensive income | — |
| | — |
| | — |
| | 2,561 |
| | — |
| | |
|
| Total comprehensive income | |
| | |
| | |
| | |
| | |
| | 108,957 |
|
| Shares issued pursuant to employee benefit plans | — |
| | — |
| | 207 |
| | — |
| | — |
| | 207 |
|
| Restricted stock | — |
| | 3 |
| | 2,446 |
| | — |
| | — |
| | 2,449 |
|
| Common stock issued | — |
| | 101 |
| | 73,661 |
| | — |
| | — |
| | 73,762 |
|
| Reconsolidate subsidiary | — |
| | — |
| | — |
| | — |
| | 17 |
| | 17 |
|
| Balance at December 31, 2011 | $ | — |
| | $ | 394 |
| | $ | 324,474 |
| | $ | 1,624 |
| | $ | (125,290 | ) | | $ | 201,202 |
|
| Comprehensive income: | |
| | |
| | |
| | |
| | | | |
|
| Net income | — |
| | — |
| | — |
| | — |
| | 2,747 |
| | |
|
| Other comprehensive loss | — |
| | — |
| | — |
| | (1,624 | ) | | — |
| | |
|
| Total comprehensive income | |
| | |
| | |
| | |
| | |
| | 1,123 |
|
| Shares issued pursuant to employee benefit plans | — |
| | — |
| | 235 |
| | — |
| | — |
| | 235 |
|
| Restricted stock | — |
| | 4 |
| | 3,407 |
| | — |
| | — |
| | 3,411 |
|
| Balance at December 31, 2012 | $ | — |
| | $ | 398 |
| | $ | 328,116 |
| | $ | — |
| | $ | (122,543 | ) | | $ | 205,971 |
|
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Operating revenues: | |
| | | | |
| Oil sales | $ | 88,960 |
| | $ | 96,584 |
| | $ | 100,962 |
|
| Natural gas sales | 13,609 |
| | 14,149 |
| | 26,682 |
|
| Total operating revenues | 102,569 |
| | 110,733 |
| | 127,644 |
|
| Operating expenses: | |
| | |
| | |
|
| Lease operating expenses | 19,779 |
| | 23,330 |
| | 18,285 |
|
| Production taxes | 4,133 |
| | 3,224 |
| | 2,062 |
|
| Depreciation, depletion and amortization | 43,967 |
| | 49,701 |
| | 48,701 |
|
| General and administrative | 20,534 |
| | 20,358 |
| | 16,636 |
|
| Accretion expense | 1,785 |
| | 2,253 |
| | 2,338 |
|
| Impairment of other property and equipment | 1,707 |
| | 1,177 |
| | — |
|
| Total operating expenses | 91,905 |
| | 100,043 |
| | 88,022 |
|
| Income from operations | 10,664 |
| | 10,690 |
| | 39,622 |
|
| Other (income) expenses: | |
| | |
| | |
|
| Interest expense | 6,094 |
| | 9,108 |
| | 11,717 |
|
| Gain on early extinguishment of debt | (3,696 | ) | | (1,366 | ) | | (1,942 | ) |
| Gain on acquired equipment | — |
| | — |
| | (5,041 | ) |
| Loss (gain) on derivative contracts | 1,360 |
| | (1,717 | ) | | — |
|
| Other income | (485 | ) | | (79 | ) | | (1,426 | ) |
| Total other expenses | 3,273 |
| | 5,946 |
| | 3,308 |
|
| Income before income taxes | 7,391 |
| | 4,744 |
| | 36,314 |
|
| Income tax expense (benefit) | 3,104 |
| | 2,223 |
| | (69,283 | ) |
| Income before equity in earnings of Medusa Spar LLC | 4,287 |
| | 2,521 |
| | 105,597 |
|
| Equity in earnings of Medusa Spar LLC, net of tax | 17 |
| | 226 |
| | 799 |
|
| Net income | 4,304 |
| | 2,747 |
| | 106,396 |
|
| Preferred stock dividends | (4,627 | ) | | — |
| | — |
|
| Income (loss) available to common shareholders | $ | (323 | ) | | $ | 2,747 |
| | $ | 106,396 |
|
| Income (loss) per common share: | |
| | |
| | |
|
| Basic | $ | (0.01 | ) | | $ | 0.07 |
| | $ | 2.81 |
|
| Diluted | $ | (0.01 | ) | | $ | 0.07 |
| | $ | 2.76 |
|
| Shares used in computing income per common share: | |
| | |
| | |
|
| Basic | 40,133 |
| | 39,522 |
| | 37,908 |
|
| Diluted | 40,133 |
| | 40,337 |
| | 38,582 |
|
CALLON PETROLEUM COMPANY
CONSOLIDATEDCONSOLIDATE STATEMENTS OF CASH FLOWSCOMPREHENSIVE INCOME
(In thousands)
|
| | | | | | | | | | | |
| | For the year ended December 31, |
| | 2012 | | 2011 | | 2010 |
| Cash flows from operating activities: | | | | | |
| Net income | $ | 2,747 |
| | $ | 106,396 |
| | $ | 8,386 |
|
| Adjustments to reconcile net income to | |
| | |
| | |
|
| cash provided by operating activities: | |
| | |
| | |
|
| Depreciation, depletion and amortization | 51,043 |
| | 49,753 |
| | 32,629 |
|
| Accretion expense | 2,253 |
| | 2,338 |
| | 2,446 |
|
| Amortization of non-cash debt related items | 402 |
| | 461 |
| | 397 |
|
| Amortization of deferred credit | (3,086 | ) | | (3,155 | ) | | (3,670 | ) |
| Equity in earnings of Medusa Spar LLC | (226 | ) | | (799 | ) | | (427 | ) |
| Deferred income tax expense | 2,223 |
| | 10,928 |
| | 1,503 |
|
| Valuation allowance | — |
| | (80,211 | ) | | (1,503 | ) |
| Unrealized gain on derivative contracts | (1,683 | ) | | — |
| | — |
|
| Impairment of other property and equipment | 1,176 |
| | — |
| | — |
|
| Gain on acquired assets | — |
| | (4,995 | ) | | — |
|
| Non-cash gain for early debt extinguishment | (1,366 | ) | | (1,942 | ) | | 339 |
|
| Non-cash expense related to equity share-based awards | 1,697 |
| | 1,337 |
| | 2,347 |
|
| Change in the fair value of liability share-based awards | 1,620 |
| | 761 |
| | 760 |
|
| Payments to settle asset retirement obligations | (1,314 | ) | | (2,563 | ) | | (2,486 | ) |
| Changes in current assets and liabilities: | |
| | |
| | |
|
| Accounts receivable | (883 | ) | | (3,734 | ) | | 59,527 |
|
| Other current assets | 100 |
| | 180 |
| | (209 | ) |
| Current liabilities | 1,753 |
| | 4,695 |
| | 907 |
|
| Payments to settle vested liability share-based awards | (3,383 | ) | | — |
| | — |
|
| Change in natural gas balancing receivable | 51 |
| | 252 |
| | 347 |
|
| Change in natural gas balancing payable | (102 | ) | | (115 | ) | | (300 | ) |
| Change in other long-term liabilities | 205 |
| | 100 |
| | (115 | ) |
| Change in other assets, net | (1,937 | ) | | (520 | ) | | (776 | ) |
| Cash provided by operating activities | 51,290 |
| | 79,167 |
| | 100,102 |
|
| Cash flows from investing activities: | |
| | |
| | |
|
| Capital expenditures | (133,299 | ) | | (100,243 | ) | | (59,908 | ) |
| Acquisitions | (2,075 | ) | | — |
| | (995 | ) |
| Proceeds from sale of mineral interests and equipment | 39,936 |
| | 7,615 |
| | — |
|
| Investment in restricted assets related to plugging and abandonment | — |
| | (150 | ) | | (375 | ) |
| Distribution from Medusa Spar LLC | 1,735 |
| | 1,267 |
| | 1,540 |
|
| Cash used in investing activities | (93,703 | ) | | (91,511 | ) | | (59,738 | ) |
| Cash flows from financing activities: | |
| | |
| | |
|
| Borrowings on senior secured revolving credit facility | 53,000 |
| | — |
| | — |
|
| Payments on senior secured revolving credit facility | (43,000 | ) | | — |
| | (10,000 | ) |
| Redemption of remaining 9.75% senior notes | — |
| | — |
| | (16,212 | ) |
| Redemption of 13% senior notes | (10,225 | ) | | (35,062 | ) | | — |
|
| Issuance of common stock | — |
| | 73,765 |
| | — |
|
| Taxes paid related to exercise of employee stock options | (18 | ) | | — |
| | (40 | ) |
| Cash (used in) provided by financing activities | (243 | ) | | 38,703 |
| | (26,252 | ) |
| Net change in cash and cash equivalents | (42,656 | ) | | 26,359 |
| | 14,112 |
|
| Cash and cash equivalents: | |
| | |
| | |
|
| Balance, beginning of period | 43,795 |
| | 17,436 |
| | 3,635 |
|
| Less: Cash held by subsidiary deconsolidated at January 1, 2010 | — |
| | — |
| | (311 | ) |
| Balance, end of period | $ | 1,139 |
| | $ | 43,795 |
| | $ | 17,436 |
|
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Net income | $ | 4,304 |
| | $ | 2,747 |
| | $ | 106,396 |
|
| Other comprehensive income (loss): | | | | | |
| Change in fair value of derivatives designated as hedges, net of tax | — |
| | (1,624 | ) | | 2,561 |
|
| Comprehensive income | 4,304 |
| | 1,123 |
| | 108,957 |
|
| Preferred stock dividends | (4,627 | ) | | — |
| | — |
|
| Comprehensive income (loss) available to common shareholders | $ | (323 | ) | | $ | 1,123 |
| | $ | 108,957 |
|
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Preferred Stock | | Common Stock | | Capital in Excess of Par | | Accumulated Other Comprehensive Income (Loss) | | Retained Earnings (Deficit) | | Total Stockholders’ Equity |
| Balance at 12/31/2010 | $ | — |
| | $ | 290 |
| | $ | 248,160 |
| | $ | (937 | ) | | $ | (231,703 | ) | | $ | 15,810 |
|
| Comprehensive income: | |
| | |
| | |
| | |
| | |
| | |
|
| Net income | — |
| | — |
| | — |
| |
|
| | 106,396 |
| |
|
|
| Other comprehensive income | | | | | | | 2,561 |
| | | | |
| Total comprehensive income | | | | | | | | | | | 108,957 |
|
| Shares issued pursuant to employee benefit plans | — |
| | — |
| | 207 |
| | — |
| | — |
| | 207 |
|
| Restricted stock | — |
| | 3 |
| | 2,446 |
| | — |
| | — |
| | 2,449 |
|
| Common stock issued | — |
| | 101 |
| | 73,661 |
| | — |
| | — |
| | 73,762 |
|
| Reconsolidated subsidiary (See Note 13) | — |
| | — |
| | — |
| | — |
| | 17 |
| | 17 |
|
| Balance at 12/31/2011 | $ | — |
| | $ | 394 |
| | $ | 324,474 |
| | $ | 1,624 |
| | $ | (125,290 | ) | | $ | 201,202 |
|
| Comprehensive income: | |
| | |
| | |
| | |
| | |
| | |
|
| Net income | — |
| | — |
| | — |
| |
|
| | 2,747 |
| |
|
|
| Other comprehensive loss | | | | | | | (1,624 | ) | | | | |
| Total comprehensive income | | | | | | | | | | | 1,123 |
|
| Shares issued pursuant to employee benefit plans | — |
| | — |
| | 235 |
| | — |
| | — |
| | 235 |
|
| Restricted stock | — |
| | 4 |
| | 3,407 |
| | — |
| | — |
| | 3,411 |
|
| Balance at 12/31/2012 | $ | — |
| | $ | 398 |
| | $ | 328,116 |
| | $ | — |
| | $ | (122,543 | ) | | $ | 205,971 |
|
| Comprehensive income: | |
| | |
| | |
| | |
| | | | |
|
| Net income and comprehensive income | — |
| | — |
| | — |
| | — |
| | 4,304 |
| | 4,304 |
|
| Shares issued pursuant to employee benefit plans | — |
| | — |
| | 243 |
| | — |
| | — |
| | 243 |
|
| Restricted stock | — |
| | 6 |
| | 3,162 |
| | — |
| | — |
| | 3,168 |
|
| Preferred stock issued | 16 |
| | | | 70,019 |
| | | | | | 70,035 |
|
| Preferred stock dividend | | | | | | | | | (4,627 | ) | | (4,627 | ) |
| Balance at 12/31/2013 | $ | 16 |
| | $ | 404 |
| | $ | 401,540 |
| | $ | — |
| | $ | (122,866 | ) | | $ | 279,094 |
|
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Cash flows from operating activities: | | | | | |
| Net income | $ | 4,304 |
| | $ | 2,747 |
| | $ | 106,396 |
|
| Adjustments to reconcile net income to cash provided by operating activities: | |
| | |
| | |
|
| Depreciation, depletion and amortization | 45,393 |
| | 51,043 |
| | 49,753 |
|
| Accretion expense | 1,785 |
| | 2,253 |
| | 2,338 |
|
| Amortization of non-cash debt related items | 471 |
| | 402 |
| | 461 |
|
| Amortization of deferred credit | (3,164 | ) | | (3,086 | ) | | (3,155 | ) |
| Equity in earnings of Medusa Spar LLC | (17 | ) | | (226 | ) | | (799 | ) |
| Deferred income tax expense | 2,778 |
| | 2,223 |
| | 10,928 |
|
| Valuation allowance | — |
| | — |
| | (80,211 | ) |
| Net loss (gain) on derivatives, net of settlements | 2,730 |
| | (1,683 | ) | | — |
|
| Impairment of other property and equipment | 1,707 |
| | 1,176 |
| | — |
|
| Gain on acquired equipment | — |
| | — |
| | (4,995 | ) |
| Non-cash gain for early debt extinguishment | (3,696 | ) | | (1,366 | ) | | (1,942 | ) |
| Non-cash expense related to equity share-based awards | 2,092 |
| | 1,697 |
| | 1,337 |
|
| Change in the fair value of liability share-based awards | 2,903 |
| | 1,620 |
| | 761 |
|
| Payments to settle asset retirement obligations | (721 | ) | | (1,314 | ) | | (2,563 | ) |
| Changes in current assets and liabilities: | |
| | |
| | |
|
| Accounts receivable | (3,497 | ) | | (883 | ) | | (3,734 | ) |
| Other current assets | (560 | ) | | 100 |
| | 180 |
|
| Current liabilities | 3,583 |
| | 1,753 |
| | 4,695 |
|
| Payments to settle vested liability share-based awards | (239 | ) | | (3,383 | ) | | — |
|
| Change in natural gas balancing receivable | 22 |
| | 51 |
| | 252 |
|
| Change in natural gas balancing payable | (527 | ) | | (102 | ) | | (115 | ) |
| Change in other long-term liabilities | (206 | ) | | 205 |
| | 100 |
|
| Change in other assets, net | (812 | ) | | (1,937 | ) | | (520 | ) |
| Net cash provided by operating activities | 54,329 |
| | 51,290 |
| | 79,167 |
|
| Cash flows from investing activities: | |
| | |
| | |
|
| Capital expenditures | (159,724 | ) | | (133,299 | ) | | (100,243 | ) |
| Acquisitions | (10,885 | ) | | (2,075 | ) | | — |
|
| Proceeds from sale of mineral interests and equipment | 89,992 |
| | 39,936 |
| | 7,615 |
|
| Investment in restricted assets related to plugging and abandonment | — |
| | — |
| | (150 | ) |
| Distribution from Medusa Spar LLC | 813 |
| | 1,735 |
| | 1,267 |
|
| Net cash used in investing activities | (79,804 | ) | | (93,703 | ) | | (91,511 | ) |
| Cash flows from financing activities: | |
| | |
| | |
|
| Borrowings on credit facility | 80,000 |
| | 53,000 |
| | — |
|
| Payments on credit facility | (68,000 | ) | | (43,000 | ) | | — |
|
| Redemption of 13% Senior Notes | (50,060 | ) | | (10,225 | ) | | (35,062 | ) |
| Issuance of preferred stock | 70,035 |
| | — |
| | — |
|
| Issuance of common stock | — |
| | — |
| | 73,765 |
|
| Payment of preferred stock dividends | (4,627 | ) | | — |
| | — |
|
| Taxes paid related to exercise of employee stock options | — |
| | (18 | ) | | — |
|
| Net cash provided by (used in) financing activities | 27,348 |
| | (243 | ) | | 38,703 |
|
| Net change in cash and cash equivalents | 1,873 |
| | (42,656 | ) | | 26,359 |
|
| Cash and cash equivalents: | |
| | |
| | |
|
| Balance, beginning of period | 1,139 |
| | 43,795 |
| | 17,436 |
|
| Balance, end of period | $ | 3,012 |
| | $ | 1,139 |
| | $ | 43,795 |
|
|
| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except share,well, acreage, per-share and per-hedgeper-derivative instrument data) | |
| | | Note | | Description | | Note | | Description | | Description | | Note | | Description |
| | Description of Business and Basis of Presentation | | | | Share-Based Compensation | | Description of Business and Basis of Presentation | | | | Share-Based Compensation |
| | Summary of Significant Accounting Policies | | | | Equity Transactions | | Summary of Significant Accounting Policies | | | | Equity Transactions |
| | Global Settlement with Joint Interest Partner | | | | Income Taxes | | Earnings (loss) per Share | | | | Income Taxes |
| | Earnings per Share | | | | Crude Oil and Natural Gas Properties | | Borrowings | | | | Asset Retirement Obligations |
| | Borrowings | | | | Asset Retirement Obligations | | Derivative Instruments and Hedging Activities | | | | Supplemental Information on Oil and Natural Gas Operations (Unaudited) |
| | Derivative Instruments and Hedging Activities | | | | Supplemental Crude Oil and Natural Gas Reserve Data (unaudited) | | Fair Value Measurements | | | | Other |
| | Fair Value Measurements | | | | Other | | Employee Benefit Plans | | | | Summarized Quarterly Financial Information (Unaudited) |
| | Employee Benefit Plans | | | | Summarized Quarterly Financial Information (unaudited) | |
NOTE 1 – Description of Business and Basis of Presentation
Callon Petroleum Company is an independent crude oil and natural gas company established in 1950, which since 1950 has been focused on building reserves and production both onshore and offshore through efficient operations and low finding and development costs. Today,In 2013, the Company's principal developmentCompany completed the onshore strategic repositioning it initiated in 2009, shifting its operations are infrom the Permian basin in West Texas. The Company's producing assetsoffshore waters in the Gulf of Mexico provide significant cash flow to execute Callon's current onshore development operations. Following the DecemberPermian Basin region in Texas. The Company has built seasoned technical and operational teams with extensive experience in the Permian Basin to manage and progress its growth plan. In the fourth quarter of 2012, Callon sold its interest in its deepwater Habanero field. Similarly, in the fourth quarter of 2013, the Company sold its interest in its only remaining deepwater property, the Medusa field, including the sale of our deepwater Gulfthe Medusa Spar facility and substantially all remaining offshore shelf properties. These transactions completed the Company’s long-term strategic goal of Mexico property, discussed later within Note 12,becoming an onshore operator with an asset base concentrated in the Company has one remaining deepwater Gulf of Mexico property, along with several Gulf of Mexico shelf properties, providing cash flow to support Callon's onshore development operations.Permian Basin.
The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. 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.
The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also includes the subsidiaries Callon Offshore Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to presentation in the current year. To the extent these amounts are material, we have either footnoted them within the Company'sCompany’s disclosures or have noted the items within this footnote. The Company reclassified on its 2012 and 2011 Consolidated Statements of Operations $3,224 and $2,062, respectively, from “Lease operating expenses” to “Production taxes” to conform to current year presentation.
Unless otherwise indicated, all amounts included within the footnotes to the financial statements are presented in thousands, except for share, per-sharewell, acreage and per-hedgeper-derivative instrument data.
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Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
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Correction of an Immaterial Error
During the second quarter of 2012, the Company determined that its December 31, 2011 financial statements reflected a misstatement caused by an error in adjusting the Company's deferred tax position at December 31, 2011. Management concluded that the impact of this error was immaterial on the prior reporting period. However, because the adjustment to correct the error in 2012 would have had a material impact on the 2012 financial statements, we corrected the prior period financial statements in the second quarter 2012 Form 10-Q and within the December 31, 2012 Form 10-K in accordance with SEC guidance. The adjustment had no effect on the Company's cash flow, and the information included in this Form 10-K sets forth the effects of this correction on the previously reported Balance Sheet and Income Statement as of and for the year ended December 31, 2011 as follows:
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| | | | | | | | | | | | |
| | | Year ended December 31, 2011 |
| | | As Reported | | Adjustment | | As Adjusted |
| Balance Sheet: | | | | | | |
| Deferred tax asset | | $ | 63,496 |
| | $ | 2,247 |
| | $ | 65,743 |
|
| Total assets | | 367,460 |
| | 2,247 |
| | 369,707 |
|
| Retained deficit | | (127,537 | ) | | 2,247 |
| | (125,290 | ) |
| Total stockholders' equity | | 198,955 |
| | 2,247 |
| | 201,202 |
|
| Total liabilities and stockholders' equity | | 367,460 |
| | 2,247 |
| | 369,707 |
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| | | | | | | |
| Income Statement: | | | | | | |
| Income tax benefit | | $ | (67,036 | ) | | $ | (2,247 | ) | | $ | (69,283 | ) |
| Net income available to common shares | | 104,149 |
| | 2,247 |
| | 106,396 |
|
| Net income per common share - Basic | | 2.75 |
| | 0.06 |
| | 2.81 |
|
| Net income per common share - Diluted | | 2.70 |
| | 0.06 |
| | 2.76 |
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NOTE 2 – Summary of Significant Accounting Policies
The preparation of financial statements in conformity with United States generally accepted accounting principles (“US GAAP”)(GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
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| B. | Cash and Cash Equivalents |
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Accounts receivable consists primarily of accrued crude oil and natural gas production receivables. The balance in the reserve for doubtful accounts netted within accounts receivable was $3473 and $3634 at December 31, 20122013 and 20112012, respectively. During 20122013, 20112012, and 20102011 the Company recorded $045, $(281)0 and $281(281), respectively of bad debt expense in general and administrative expenses.expense. The negative bad debt expense in 2011 relates to the collection of an amount charged to bad debt expense during 2010.
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| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
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| D. | Revenue Recognition and Natural Gas Balancing |
The Company recognizes revenue under the entitlement method of accounting. Under this method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the lower of cost or market. The revenue we receive from the sale of natural gas liquidsNGLs is included in natural gas sales. Natural gas balancing receivables were $9371 and $14493 as of 20122013 and 20112012, respectively. Natural gas balancing payables were $653126 and $756653 as of 20122013 and 20112012, respectively.
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Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
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The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold a significant percentage (>greater than 10%) of its total crude oil and natural gas production during each of the years ended:
| | | | December 31, | For the Year Ended December 31, |
| | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Enterprise Crude Oil, LLC | | 38 | % | | 32 | % | | 16 | % |
| Shell Trading Company | 39 | % | | 45 | % | | 44 | % | 31 | % | | 39 | % | | 45 | % |
| Plains Marketing, L.P. | 15 | % | | 17 | % | | 20 | % | 15 | % | | 15 | % | | 17 | % |
| Enterprise Crude Oil, LLC | 32 | % | | 16 | % | | — | % | |
| Louis Dreyfus Energy Services | 2 | % | | 4 | % | | 13 | % | |
| Other | 12 | % | | 18 | % | | 23 | % | 16 | % | | 14 | % | | 22 | % |
| Total | 100 | % | | 100 | % | | 100 | % | 100 | % | | 100 | % | | 100 | % |
Because alternative purchasers of crude 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 its ability to market future crude oil and natural gas production.
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| F. | Crude Oil and Natural Gas Properties |
The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. The Company capitalized $13,33114,753, $11,85713,331 and $11,82911,857 of these internal costs during 20122013, 20112012 and 20102011, respectively.
When applicable, proceeds from the sale or disposition of crude oil and natural gas properties are accounted for as a reduction to capitalized costs unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized in income.
Costs of crude oil and natural gas properties, including future development costs, which have proved reserves and properties which have been determined to be worthless, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or management determines that these costs have been impaired.
Under the SEC's full costfull-cost accounting rules we reviewof the SEC, the Company reviews the carrying value of our crudeits proved oil and natural gas properties each quarter. Under these rules, we comparecapitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value discounted at 10%, of estimated future net cash flows from proved crude oil and natural gas reserves, todiscounted at 10%, plus the capitalized costslower of crudecost or fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas properties (netprices based on closing prices on the first day of accumulated depreciation, depletioneach month and amortization and related deferred income taxes) which may not exceedrequire a “ceiling”.
These rules generally require that we price our future crude oil and natural gas production atwrite-down if the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Our reference prices are the West Texas Intermediate, or WTI, for crude oil and the Henry Hub spot price for natural gas. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. The reserve estimates exclude the effect of any derivatives we have in place. The rules require an impairment if our capitalized costs exceed this “ceiling”. is exceeded. See NotesNote 12 and 14 for additional information regarding the Company’s crude oil and natural gas properties.
Upon the acquisition or discovery of crude oil and natural gas properties, the Company estimates by using available geological, engineering and regulatory data the future net costs to dismantle, abandon and restore the property.property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance issued by the FASB, such costs are capitalized to the full-cost pool when the related liabilities are incurred. In accordance with SEC's rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject
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| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except share,well, acreage, per-share and per-hedgeper-derivative instrument data) | |
by the FASB, such costs are capitalized to the full-cost pool when the related liabilities are incurred. In accordance with SEC’s rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject to the full-cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full-cost ceiling amount.
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| G. | Other Property and Equipment |
The Company depreciates its other property and equipment of $6,4247,255 and $3,9986,424 at December 31, 20122013 and 20112012, respectively, using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $760750, $645760 and $446645 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 20122013, 20112012 and 20102011, respectively. The accumulated depreciation on other property and equipment was $13,23813,240 and $12,68813,238 as of December 31, 20122013 and 20112012, respectively. Included withinAs discussed in Note 13, during 2013, the Company's other property and equipment, and excluded from depreciation, are certainCompany recorded an impairment charge to reduce to zero the carrying values of its assets held for sale, which were valued at $3,634 and $6,514 as of December 31, 2012 and 2011, respectively.sale. The Company reviews its other property and equipment for impairment when indicators of impairment exist. See Note 7 for additional information regarding the assets held for sale and their fair values.
The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization (e.g. unevaluated properties). Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2013, 2012 and 2011, the Company capitalized $4,410, $2,109 and $573 of interest expense.
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| I. | Asset Retirement Obligations |
The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations. See Note 1311 for additional information.
The Company’s derivative contracts executed prior to 2012 were designated as cash flow hedges, and were recorded at fair market value with the changes in fair value recorded net of tax through other comprehensive income (loss) (“OCI”) in stockholders’ equity. Ineffective derivative contracts or ineffective portions of contractcontracts designated as cash flow hedges arewere recognized as derivative expense (income). The last of the Company'sCompany’s derivative contracts designated as cash flow hedges expired on December 31, 2012. Derivative contracts executed during 20122013 and outstanding as of December 31, 2012 are2013 were not designated as accounting hedges, and are also carried on the balance sheet at their fair market value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 65 and 76 for additional information regarding the Company'sCompany’s derivative contracts.
Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for crude oil and natural gas properties for financial reporting purposes and income tax purposes. US GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforward and tax credit carryforwards, net of a valuation allowance. A valuation allowance is provided for that portion, if any, of the asset for which it is deemed more likely than not that it will not be realized. See Note 1110 for additional information.
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K.L. | Share-Based Compensation |
The Company grants to directors and employees stock options, restricted stock awards ("(“RS awards"awards”), and restricted stock unit awards ("(“RSU awards"awards”) that may be settled in cash or common stock at the option of the Company and RSU awards that may only be settled in cash (“Cash-settleable RSU awards”).
Stock Options. For stock options the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years).
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| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
RS awards, RSU awards and Cash-settleable RSU awards. For RS and RSU awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). For Cash-settleable RSU awards that the Company expects or is required to settle in cash, share-based compensation expense is based on the fair value remeasured at each reporting period as calculated using a Monte Carlo pricing model, because vesting of these awards is subject to a market condition, with the estimated value recognized over the vesting period (generally three years) and classified as Accounts payable and accrued liabilities for the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder classified as Other long-term liabilities.
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Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
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L.M. | Statements of Cash Flows Supplemental Information |
During the three year period ended 20122013, the Company paid no federal income taxes. During the years ended December 31, 20122013, 20112012 and 20102011, the company made cash interest payments of $13,92013,189, $14,92213,920 and $18,57914,922, respectively.
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M.N. | Off-Balance Sheet Investment in Medusa Spar LLC |
TheDuring the fourth quarter of 2013, the Company holds a 10% ownershipclosed on the sale of its 15.0% working interest in the Medusa field, its 10.0% membership interest in Medusa Spar LLC (“LLC”), which isand substantially all of its remaining Gulf of Mexico shelf properties. Prior to the sale, the Company’s ownership interest in the LLC was accounted for under the equity method of accounting for investments. The LLC ownsheld a 75% undivided ownership interest in the deepwater spar production facilities at the Company’s Medusa field in the Gulf of Mexico. The LLC earnsMexico and earned a tariff based upon production volume throughput from the Medusa area. Callon isThe Company was obligated to process through the spar production facilities its share of production from the Medusa field and any future discoveries in the area. The balance of Medusa Sparthe LLC iswas owned by Oceaneering International, Inc. and Murphy Oil Corporation. See Note 12 for additional information on the Medusa divestiture.
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N.O. | Consolidation of Variable Interest Entities |
In June 2009, the FASB issued an accounting standard which became effective for and was adopted by the Company on January 1, 2010, and which amended US GAAP as follows:
to require an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a Variable Interest Entity (“VIE”), identifying the primary beneficiary of a VIE;
to require ongoing reassessment of whether an enterprise is the primary beneficiary of a VIE, rather than only when specific events occur;
to eliminate the quantitative approach previously required for determining the primary beneficiary of a VIE;
to amend certain guidance for determining whether an entity is a VIE;
to add an additional reconsideration event when changes in facts and circumstances pertinent to a VIE occur;
to eliminate the exception for troubled debt restructuring regarding VIE reconsideration; and
to require advanced disclosures that will provide users of financial statements with more transparent information about an enterprise’s involvement in a VIE.
The Company adopted the pronouncement for consolidation of variable interest entities on January 1, 2010. Upon adoption, and as discussed in Note 3, the Company reevaluated its interest in its subsidiary, Callon Entrada. Based on the evaluation performed, management concluded that a VIE reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for which the Company is not the primary beneficiary. Therefore, effective January 1, 2010, Callon Entrada was deconsolidated from the consolidated financial statements of the Company. During the second quarter of 2011 and through the formal execution of a wind-down agreement with its former joint interest partner in the Entrada deepwater project, which resulted in Callon gaining the power to direct the activities of Callon Entrada, the Company became the primary beneficiary of Callon Entrada. Consequently, effective April 29, 2011, Callon Entrada was reconsolidated in the Company'sCompany’s financial statements. For additional information, see Note 3.Callon Entrada was later dissolved in 2011.
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O.P. | Earnings per Share ("EPS")(EPS) |
The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS, using the treasury-stock method, reflects the potential dilution usingcaused by the treasury-stock method, which assumes thatexercise of all options were exercisedand vesting of all restricted stock and restricted stock was fully vested. Diluted EPS also includes the impact of unvested share appreciation plans. For awardsunits settleable in which the share price goals have already been achieved, shares are included in diluted EPS using the treasury-stock method. For those awards in which the share price goals have not been achieved, the number of contingently issuable shares included in the diluted EPS is based on the number of shares, if any, using the treasury-stock method, that would be issuable if the market price of the Company’s stock at the end of the reporting period exceeded the share price goals under the terms of the plan.shares.
The Company applies the weighted-average-cost method of accounting for treasury stock transactions and held 29 treasury shares as of December 31, 2012.
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Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
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| Q. | Recent Accounting Pronouncements |
From time to time, new accounting pronouncements are issued by FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.
NOTE 3 - Global Settlement with Joint Interest Partner
During May 2011,In February 2013, the Financial Accounting Standards Board issued an Accounting Standards Update (ASU) that clarified the reclassification requirements from accumulated other comprehensive income to net income and required disclosure of amounts reclassified out of accumulated other comprehensive income by component. In addition, it requires that the Company entered into a final project wind-down agreement (the "Agreement") with CIECO. As a resultpresent either on the face of this Agreement, which included both the assignment of the rights to the Entrada assets (including the rights to 50% of the assets previously held by CIECO and the rights to 50% of the assets held by Callon Entrada) and the proceeds from the ultimate sale of such assets, the Company gained the power to direct the activities related to the sale of the remaining assets, and therefore became the primary beneficiary of Callon Entrada. Therefore, Callon Entrada was consolidatedits financial statements or in the Company's consolidated financial statements, effective April 29, 2011. Upon consolidating Callon Entrada, the Company estimated the fair valuesnotes, significant amounts reclassified out of the assets acquired to be $11,349 and liabilities assumed, primarily deferred tax liabilities associated with the tax basis difference in the assets, of Callon Entrada to be $2,681as a result of this Agreement. Also in connection with this Agreement, Callon Entrada agreed to pay to CIECO approximately $438, which represented the net balance of joint interest billings due to CIECO and which had been previously accrued. The agreement also included joint releases of each party from any further liabilities or obligations to theaccumulated other party in connection with the Entrada project. The adjusted fair market value of the net assets acquired of approximately $8,759 were recorded during 2011 as a $5,041 gain and $3,718 as an adjustment to the Company's full cost pool of crude oil and natural gas properties.
While the Company continues to actively market these assets, its inability to complete a transaction over the past several quarters constituted an impairment indicator, which prompted the Company to reevaluate the remaining value of the assets. As of December 31, 2012, the remaining unsold assets, which are included in the Company's balance sheet as a component of Other property and equipment, net had carrying values of $3,634. During the year ended December 31, 2012, the Company sold assets valued at $527, and recorded an impairment charge of $1,177 to its Statement of Operations as a result of the Company's December 31, 2012 impairment analysis. The Company continues to actively market these assets, and will continue to monitor the assets for additional impairment. See Note 7 for additional information regarding the determination of the assets' fair values.
NOTE 4 - Earnings per Share
Basic net income per common share was computed by dividing netcomprehensive income by the weighted average numberrespective line items of shares of common stock outstanding during the year. Diluted net income, per common share was determinedbut only if the amount is reclassified in its entirety to net income in the same reporting period. For amounts not reclassified in their entirety to net income, the Company is required to cross-reference to the related note on a weighted average basis using common shares issued and outstanding adjusted for the effect of stock options and restricted stock considered common stock equivalents computed using the treasury stock method.
A reconciliationface of the basic and diluted net income per share computation is as follows (in thousands, except per share amounts):
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| | For the year ended December 31, |
| | 2012 | | 2011 | | 2010 |
| (a) Net income | $ | 2,747 |
| | $ | 106,396 |
| | $ | 8,386 |
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| | | | | | |
| (b) Weighted average shares outstanding | 39,522 |
| | 37,908 |
| | 28,817 |
|
| Dilutive impact of stock options | 8 |
| | 18 |
| | 108 |
|
| Dilutive impact of restricted stock | 807 |
| | 656 |
| | 551 |
|
| (c) Weighted average shares outstanding | |
| | |
| | |
|
| for diluted net income per share | 40,337 |
| | 38,582 |
| | 29,476 |
|
| | | | | | |
| Basic net income per share (a/b) | $ | 0.07 |
| | $ | 2.81 |
| | $ | 0.29 |
|
| Diluted net income per share (a/c) | $ | 0.07 |
| | $ | 2.76 |
| | $ | 0.28 |
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| | | | | | |
| The following were excluded from the diluted EPS calculation because their effect would be anti-dilutive: |
| Stock options | 52 |
| | 67 |
| | 122 |
|
| Restricted stock | 123 |
| | 816 |
| | 5 |
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| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except share,well, acreage, per-share and per-hedgeper-derivative instrument data) | |
NOTE 53 - Earnings (loss) per Share
Basic earnings (loss) per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares and unexercised options outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. A reconciliation of the basic and diluted net income per share computation is as follows (in thousands, except per share amounts):
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| | For the year ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Net income | $ | 4,304 |
| | $ | 2,747 |
| | $ | 106,396 |
|
| Preferred stock dividends | (4,627 | ) | | — |
| | — |
|
| (a) Income (loss) available to common shareholders | $ | (323 | ) | | $ | 2,747 |
| | $ | 106,396 |
|
| | | | | | |
| (b) Weighted average shares outstanding | 40,133 |
| | 39,522 |
| | 37,908 |
|
| Dilutive impact of stock options | — |
| | 8 |
| | 18 |
|
| Dilutive impact of restricted stock | — |
| | 807 |
| | 656 |
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| (c) Weighted average shares outstanding | |
| | |
| | |
|
| for diluted net income (loss) per share (1) | 40,133 |
| | 40,337 |
| | 38,582 |
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| Basic Income (loss) per share (a/b) | $ | (0.01 | ) | | $ | 0.07 |
| | $ | 2.81 |
|
| Diluted Income (loss) per share (a/c) | $ | (0.01 | ) | | $ | 0.07 |
| | $ | 2.76 |
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| The following were excluded from the diluted EPS calculations because their effect would be anti-dilutive: |
| Stock options | 52 |
| | 52 |
| | 67 |
|
| Restricted stock | 398 |
| | 123 |
| | 816 |
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| (1) | Because the Company reported a loss for the year ended December 31, 2013, no unvested stock awards were included in computing loss per share because the effect was anti-dilutive. |
NOTE 4 - Borrowings
| | | | For the year ended December 31, | For the year ended December 31, |
| | 2012 | | 2011 | 2013 | | 2012 |
| Principal components: | | | | | | |
| Credit Facility | $ | 10,000 |
| | $ | — |
| $ | 22,000 |
| | $ | 10,000 |
|
| 13% Senior Notes due 2016, principal | 96,961 |
| | 106,961 |
| 48,481 |
| | 96,961 |
|
| Total principal outstanding | $ | 106,961 |
| | $ | 106,961 |
| $ | 70,481 |
| | $ | 106,961 |
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| Non-cash components: | | | | | | |
| 13% Senior Notes due 2016 unamortized deferred credit | 13,707 |
| | 18,384 |
| 5,267 |
| | 13,707 |
|
| Total carrying value of borrowings | $ | 120,668 |
| | $ | 125,345 |
| $ | 75,748 |
| | $ | 120,668 |
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Senior Secured Revolving Credit Facility (the “Credit Facility”)
On June 20, 2012, Regions Bank increased the Company's Credit Facility toThe Company’s $200,000 with an associated borrowing base under the Credit Facility, of $60,000 and a maturity of July 31, 2014. In October 2012,for which Regions Bank serves as the Credit Facility was further amended to increase the borrowing base to $80,000, extend the maturity toAdministrative Agent, matures March 15, 2016 and addincludes Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. Regions Bank continues to serve as Administrative Agent for theThe Company’s Credit Facility.
Following the sale of our interest in the deepwater Habanero field and as of December 31, 2012, the borrowing base was revised to $65,000, representing a 44% increase over the $45,000Facility had an approved borrowing base at December 31, 2011. The $39,410 proceeds from this sale, net2013 of customary purchase price adjustments, were used to reduce outstanding borrowings on the Credit Facility to the $10,000 reflected on the Company's Consolidated Balance Sheet as of December 31, 2012.
Amounts borrowed under the Credit Facility may not exceed a borrowing base, which is generally reviewed on a semi-annual basis and is then eligible for re-determination. The next redetermination is scheduled for the first quarter of 2013, and will be based upon year-end 2012 proved reserves.$83,000. The Credit Facility iswas secured by mortgages covering the Company'sCompany’s major producing fields.
As of December 31, 2012,2013, the balance outstanding on the Credit Facility was $10,000$22,000 with an interest rate on the Credit Facility of 2.72%2.92%, calculated as the London Interbank Offered Rate ("LIBOR")(LIBOR), plus a tiered rate ranging from 2.5% to 3.0%, which is based ondetermined by utilization of the amount drawn on the Credit Facility.facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly. As
Subsequent to December 31, 2013, the Company amended its existing Credit Facility as discussed below. Additionally, the Company executed the Second Lien Facility also discussed below.
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| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
Amended Credit Facility (“the Amended Credit Facility”)
On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement million with JPMorgan Chase Bank, National Association as Administrative Agent.
The Amended Credit Facility includes the following key provisions:
$500,000 notional amount, with an initial borrowing base of $95,000;
Maturity date of March 13, 2013,11, 2019;
First redetermination scheduled with an effective date of May 30, 2014, with subsequent redeterminations occurring every six months beginning on September 1, 2014;
Pricing grid providing from Eurodollar-based draws ranging from LIBOR plus 1.75% to 2.75% depending on utilization;
A quarterly commitment fee equal to 0.5% per year of the balance outstandingunused portion of the borrowing base; and
Secured by mortgages covering all major producing fields.
The Amended Credit Facility contains various affirmative and restrictive covenants.
Second Lien Term Loan Facility (the “Second Lien Facility”)
In conjunction with the Amended Credit Facility, the Company entered into the Second Lien Facility in an aggregate amount of up to $125,000 with JPMorgan Chase Bank, National Association as Administrative Agent. The Second Lien Facility is structured as a multiple advance term loan facility, with initial commitments of $100,000. If any portion of the committed Second Lien Facility remains undrawn on the first anniversary of the closing date, then the unfunded commitments under the Second Lien Facility, if any, will terminate on such date.
The Second Lien Facility includes the following key provisions:
$125,000 master note, with initial commitments $100,000 and additional availability of $25,000 with consent of 66 2/3% of the lenders and compliance with financial covenants after giving effect to such increase;
Maturity date of September 11, 2019;
No mandatory prepayments unless new debt is issued;
Prepayable at any time. The prepayment premium shall be applicable to the amount of the applicable prepayment multiplied by (i) 102% if such prepayment event occurs prior to the first anniversary of the Closing Date and (ii) 101% if such prepayment event occurs on or after the first but prior to the second anniversary of the Closing Date. No such prepayment premium shall be payable for prepayments made on or after the second anniversary of the closing date;
Interest expense at a rate of LIBOR plus 7.75%, calculated on a per annum basis;
A commitment fee equal to 0.5% calculated on a per annum basis on the unused portion of the initial commitment amount until March 11, 2015;
The amounts funded on the initial draw date shall be issued with an original issue discount of 1.00% and each subsequent draw shall be subject to the same 1.00% original issue discount on the drawn amount, applied on the date such draw is funded; and
Secured by junior liens on properties mortgaged under the Amended Credit Facility, was $25,000 as the Company drewsubject to an additional $15,000 in support of the Company's ongoing capital development program.intercreditor agreement.
The Second Lien Facility contains various affirmative and restrictive covenants.
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| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
13% Senior Notes due 2016 (“Senior(the “Senior Notes”) and Deferred Credit
As of December 31, 20122013, the Company had principal outstanding of $96,96148,481 related to its 13% Senior Notes due 2016.Notes. The interest coupon is payable on the last day of each quarter.
Certain of the Company’s subsidiaries guarantee the Company’s obligations under the unsecured Senior Notes. The subsidiary guarantors are 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations, and any subsidiaries of the parent company other than the subsidiary guarantors are minor. Upon issuing the Senior Notes duringin November 2009, the Company reduced the carrying amount of the Old Notes by the fair value of the common and preferred stock issued in the amount of $11,527. The $31,507 difference between the adjusted carrying amount of the Old Notes and the face value of the Senior Notes was recorded as a deferred credit, which is being amortized as a reduction in interest expense over the life of the Senior Notes at an 8.5% effective interest rate.
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| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
| |
The following table summarizes the Company’s deferred credit balance at December 31, 20122013:
| | | Gross Carrying Amount | | Accumulated Amortization | | Carrying Value | | Amortization Recorded during Current Year (a) | | Estimated Annual Amortization Expense Expected to be Recognized in 2013 (b) | |
| Gross Carrying | | | Accumulated Amortization at | | Carrying Value at | | Amortization Recorded during Current Year | | Estimated Annual Amortization Expense Expected to be Recognized in |
| Amount | | | December 31, 2013 | | December 31, 2013 | | (a) | | 2014 |
| $31,507 | | $17,800 | | $13,707 | | $4,677 | | $3,300 | | $26,240 | | $5,267 | | $8,440 | | $5,267 |
| |
| (a) | Of the amount recorded as amortization during the current year, $3,0863,165 was recorded as a reduction of interest expense and $1,5915,275 (discussed below) was recorded as a component of the gain on early extinguishment of debt. |
| |
(b) | Deferred credit amortization expected to be recorded as a reduction in interest expense during, 2014, 2015 and 2016 is $3,592, $3,910, and $2,905, respectively.Using a portion of the proceeds from the sale of our interest in Medusa on December 17, 2013, the Company redeemed $48,481 of its Senior Notes, which resulted in a net $3,696 gain on the early extinguishment of debt. The gain represents the difference between the $50,057 paid (inclusive of $1,576 of redemption expenses, primarily the call premium) for Senior Notes with a carrying value of $53,756 (inclusive of the $5,275 of accelerated deferred credit amortization). |
In June 2012, the Company redeemed $10,000 of its Senior Notes, which resulted in a net $1,366 gain on the early extinguishment of debt. The gain represents the difference between the $10,225 paid (inclusive of $225 of redemption expenses)expenses, primarily the call premium) for Senior Notes with a carrying value of $11,591 (inclusive of the $1,591 of accelerated deferred credit amortization).
Following the completion of an equity offering during FebruaryIn March 2011, the Company redeemed $31,000 of the Notes. This redemption was completed in Marchits Senior Notes using proceeds from its February 2011 andequity offering, which resulted in a$1,974 gain on the early extinguishment of debt of $1,974.debt. The gain represents the difference between the $35,062 paid (inclusive of the$4,062 of redemption expenses, primarily the call premium) for Senior Notes with a carrying value of $37,004 (including $31,000 principal amount(inclusive of the notes plus $6,004 of accelerated deferred credit amortization) carrying value of the Notes, offset by the $4,030 charge related to the 13% call premium required by the terms of the call option and $32 of redemption expenses..
CertainOn March 11, the Company provided notice to holders of its outstanding Senior Notes that it expects to redeem those notes on April 11, 2014 using proceeds from the previously discussed Second Lien Facility. The redemption will result in the acceleration of the Company’s subsidiaries guarantee the Company’s obligations under the Senior Notes. The subsidiary guarantors are 100% owned, allamortization of the guarantees are full and unconditional and joint and several,remaining $5,267 of deferred credit as reflected in the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantors are minor.table above.
Restrictive Covenants
The Indenture governing our Senior Notes and the Company’s Credit Facility contains various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, Callon’s Credit Facility contains covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 20122013.
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| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
NOTE 65 – Derivative Instruments and Hedging Activities
Objectives and Strategies for Using Derivative Instruments
The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its crude oil and natural gas production. The Company utilizes primarily collarsa mix of collar, swap, put and swapcall derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.
Counterparty Riskrisk and offsetting
The use of derivative transactions exposes the Company to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. To reduceWhile the Company’s risk in this area, counterparties to the Company’s commodity derivative instruments predominantly include a large, well-known financial institution and/or a large, well-known oil and gas company. The Company monitors counterparty creditworthiness on an ongoing basis; however,basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices. Counterparty credit risk is considered when determining a derivative instruments’ fair value; See Note 6 for additional information regarding fair value.
The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.
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| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
| |
Financial statement presentation and settlements
Settlements of the Company'sCompany’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a New York Mercantile Exchange ("NYMEX"(“NYMEX”) price. The fair value of the Company'sCompany’s derivative instruments, depending on the type of instruments, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. See Note 76 for additional information regarding fair value.
DuringBeginning in 2012, the Company elected not to designate its executed derivative contracts, nor does it expect to designate future derivative contracts, as an accounting hedge under FASB ASC 815. Consequently, any derivative contract not designated as an accounting hedge will be carried at its fair value on the balance sheet and marked-to-market at the end of each period, with the change in value reflected as a gain or loss on the statement of operations. Gains and losses on derivatives that are not designated as hedges are recorded in earnings as a component of gain (loss) on derivative contracts. Within the gain (loss) on derivative contracts line of the statement of operations are gains (losses) on derivatives, net of settlement and gains (losses) on derivatives, settled.
Prior to 2012, the Company'sCompany’s derivative contracts recorded on the Consolidated Balance Sheets were designated as cash flow hedges, and were recorded at fair market value with the changes in fair value recorded net of tax through OCI in stockholders'stockholders’ equity. The future cash settlements on effective derivative contracts were recorded as an increase or decrease in crude oil and natural gas sales. Both changes in fair value and cash settlements on effective derivative contracts were recognized as derivative expense (income).
The following table reflects the fair values of the Company'sCompany’s derivative instruments for the periods indicated:
presented (none of which were designated as hedging instruments under ASC 815):
| | | | | Balance Sheet Presentation | | Asset Fair Value | | Liability Fair Value | | Net Derivative Fair Value | | Balance Sheet Presentation | | Asset Fair Value | | Liability Fair Value | | Net Derivative Fair Value |
| Commodity | | Classification | | Line Description | | 12/31/12 | | 12/31/11 | | 12/31/12 | | 12/31/11 | | 12/31/12 | | 12/31/11 | | Classification | | Line Description | | 12/31/13 | | 12/31/12 | | 12/31/13 | | 12/31/12 | | 12/31/13 | | 12/31/12 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Derivatives not designated as Hedging Instruments under ASC 815 | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas | | Current | | Fair market value of derivatives | | $ | — |
| | $ | — |
| | $ | (125 | ) | | $ | — |
| | $ | (125 | ) | | $ | — |
| | Current | | Fair market value of derivatives | | $ | 60 |
| | $ | — |
| | $ | — |
| | $ | (125 | ) | | $ | 60 |
| | $ | (125 | ) |
| Natural gas | | Non-current | | Other long-term liabilities | | — |
| | — |
| | (116 | ) | | — |
| | (116 | ) | | — |
| | Non-current | | Other long-term liabilities | | — |
| | — |
| | (72 | ) | | (116 | ) | | (72 | ) | | (116 | ) |
| Crude oil | | Current | | Fair market value of derivatives | | 1,674 |
| | — |
| | — |
| | — |
| | 1,674 |
| | — |
| |
| Crude oil | | Non-current | | Other long-term assets | | 250 |
| | — |
| | — |
| | — |
| | 250 |
| | — |
| |
| Oil | | | Current | | Fair market value of derivatives | | — |
| | 1,674 |
| | (1,036 | ) | | — |
| | (1,036 | ) | | 1,674 |
|
| Oil | | | Non-current | | Other long-term assets | | — |
| | 250 |
| | — |
| | — |
| | — |
| | 250 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Subtotals | | $ | 1,924 |
| | $ | — |
| | $ | (241 | ) | | $ | — |
| | $ | 1,683 |
| | $ | — |
| | Totals | | $ | 60 |
| | $ | 1,924 |
| | $ | (1,108 | ) | | $ | (241 | ) | | $ | (1,048 | ) | | $ | 1,683 |
|
| | | | | | | | | | | | | | |
| Derivatives designated as Hedging Instruments under ASC 815 | |
| | | | | | | | | | | | | | |
| Natural gas | | Current | | Fair market value of derivatives | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Natural gas | | Non-current | | Other long-term assets | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
| Crude oil | | Current | | Fair market value of derivatives | | — |
| | — |
| | — |
| | 2,499 |
| | — |
| | 2,499 |
| |
| Crude oil | | Non-current | | Other long-term liabilities | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
| | | | | | | | | | | | | | |
| | | Subtotals | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,499 |
| | $ | — |
| | $ | 2,499 |
| |
| | | | | | | | | | | | | | |
| | | Totals | | | $ | 1,924 |
| | $ | — |
| | $ | (241 | ) | | $ | 2,499 |
| | $ | 1,683 |
| | $ | 2,499 |
| |
|
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| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except share,well, acreage, per-share and per-hedgeper-derivative instrument data) | |
The Company’s derivative contracts are subject to netting arrangements and, being representative of the way in which the contracts settle, are presented in the balance sheet at their fair values on a net basis based on the underlying commodity being hedged. The following presents the impact of this presentation to the Company’s recognized assets and liabilities at December 31, 2013:
|
| | | | | | | | | | | | |
| | | Presented without | | | | As Presented with |
| | | Effects of Netting | | Effects of Netting | | Effects of Netting |
| Current assets: Fair value of hedging contracts | | $ | 8 |
| | $ | 52 |
| | $ | 60 |
|
| Long-term assets: Fair value of hedging contracts | | — |
| | — |
| | — |
|
| Current liabilities: Fair value of hedging contracts | | 1,088 |
| | (52 | ) | | 1,036 |
|
| Long-term liabilities: Fair value of hedging contracts | | (72 | ) | | — |
| | (72 | ) |
Derivatives not designated as hedging instruments under ASC 815
For the periods indicated, the Company recorded the following related to its derivative instruments that were not designated as accounting hedges and are recorded in the Statement of Operations as the gain or loss on derivative contracts:
|
| | | | | | | | | | | | |
| | | For the year ended December 31, |
| | | 2012 | | 2011 | | 2010 |
| Natural gas derivatives | | | | | | |
| Realized gain, net | | $ | 34 |
| | $ | — |
| | $ | — |
|
| Unrealized loss, net | | (241 | ) | | — |
| | — |
|
| Subtotal loss, net | | $ | (207 | ) | | $ | — |
| | $ | — |
|
| | | | | | | |
| Crude oil derivatives | | | | | | |
| Realized gain, net | | $ | — |
| | $ | — |
| | $ | — |
|
| Unrealized gain, net | | 1,924 |
| | — |
| | — |
|
| Subtotal gain, net | | $ | 1,924 |
| | $ | — |
| | $ | — |
|
| | | | | | | |
| Total gain on derivative instruments, net | | $ | 1,717 |
| | $ | — |
| | $ | — |
|
|
| | | | | | | | | | | |
| | For the year ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Natural gas derivatives | | | | | |
| Net (loss) gain on derivatives, settled | $ | (147 | ) | | $ | 34 |
| | $ | — |
|
| Net gain (loss) on derivatives, net of settlements | 229 |
| | (241 | ) | | — |
|
| Subtotal gain (loss), net | $ | 82 |
| | $ | (207 | ) | | $ | — |
|
| | | | | | |
| Oil derivatives | | | | | |
| Net gain, on derivatives, settled | $ | 1,518 |
| | $ | — |
| | $ | — |
|
| Net (loss) gain on derivatives, net of settlements | (2,960 | ) | | 1,924 |
| | — |
|
| Subtotal (loss) gain, net | $ | (1,442 | ) | | $ | 1,924 |
| | $ | — |
|
| | | | | | |
| Total (loss) gain on derivative instruments included in Statement of Operations | $ | (1,360 | ) | | $ | 1,717 |
| | $ | — |
|
Derivatives designated as hedging instruments under ASC 815
The tablestable below presentpresents the effect of the Company’s derivative financial instruments on the consolidated statements of operations as an increase (decrease) to crude oil and natural gas sales:sales for the effective portion and as an increase (decrease) to other (income) expense for the ineffective portion and amounts excluded from effectiveness testing:
| | | | For the year ended December 31, | For the year ended December 31, |
| | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Amount of gain (loss) reclassified from OCI into income (effective portion) | $ | 1,420 |
| | $ | (375 | ) | | $ | 632 |
| $ | — |
| | $ | 1,420 |
| | $ | (375 | ) |
| Amount of gain (loss) recognized in income (ineffective portion and amount excluded from effectiveness testing) | — |
| | — |
| | — |
| — |
| | — |
| | — |
|
Derivative positions
Listed in the table below are the outstanding oil and natural gas derivative contracts as of December 31, 2012:
|
| | | | | | | | | | | | | | | |
| Product | Instrument | | Average Volumes per Month | | Quantity Type | | Average Floor Price per Hedge | | Average Ceiling Price per Hedge | | Period |
| Crude oil (a) (b) | Collar | | 40 | | Bbls | | $ | 90.00 |
| | $ | 116.00 |
| | Jan13 - Dec13 |
| | | | | | | | | | | | |
| Product | Instrument | | Average Volumes per Month | | Quantity Type | | Put/Call Price | | Fixed-Price Swap | | Period |
| Natural gas (c) | Swap | | 91 | | MMbtu | | n/a |
| | $ | 3.52 |
| | Jan13 - Dec13 |
| Natural gas (c) | Put Option | | 91 | | MMbtu | | $ | 3.00 |
| | n/a |
| | Jan13 - Dec13 |
| Natural gas (c) | Call Option | | 38 | | MMbtu | | $ | 4.75 |
| | n/a |
| | Jan14 - Dec14 |
| |
(a) | See "Subsequent Event" discussion below regarding the replacement of this crude oil derivative contract in January 2013. |
| |
(b) | A collar is a combination of a sold call option (ceiling) and a purchased put option (floor). |
| |
(c) | The natural gas swap, put and call option were executed contemporaneously. The "above market" $3.52/MMbtu swap price the Company received was offset by the value of the two options sold by the Company. The short natural gas put option, when combined with the swap, creates the potential for a reduction in the effective swap price if NYMEX natural gas prices are below $3.00/MMbtu in 2013. The short natural gas call option, when combined with the Company's long production position, represents a "covered call," and creates a $4.75/MMbtu ceiling during the covered period.
|
|
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| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except share,well, acreage, per-share and per-hedgeper-derivative instrument data) | |
Subsequent Event:Derivative positions
In the first quarter of 2013, the Company monetized the remaining portion of its 2013 oil collar positions (for the period February - December 2013) of 40 Bbls per month. The proceeds from this transaction, combined with the proceeds from the sale of the below listed put for 30 Bbls per month, were used to finance the uplift in the oil swap for the period February - December 2013.
DerivativeListed in the table below are the outstanding oil and natural gas derivative contracts executed subsequent to as of December 31, 2012 include the following:2013:
|
| | | | | | | | | | | | | | | |
| Product | Instrument | | Average Volumes per Month | | Quantity Type | | Put Price | | Fixed-Price Swap | | Period |
| Crude oil (a) | Swap | | 40 | | Bbls | | n/a |
| | $ | 101.30 |
| | Feb13 - Dec13 |
| Crude oil | Swap | | 30 | | Bbls | | n/a |
| | $ | 93.35 |
| | Jan14 - Dec14 |
| Crude oil (a) | Put | | 30 | | Bbls | | $ | 70.00 |
| | n/a |
| | Jan14 - Dec14 |
|
| | | | | | | | | | | | | | | | | | | | |
| Commodity | | Instrument | | Average Notional Volumes per Month | | Quantity Type | | Put/Call Price | | Fixed-Price Swap | | Period | | Designation under ASC 815 | | |
| Natural gas | | Call Option | | 38 | | MMBtu | | $ | 4.75 |
| | n/a |
| | Jan14 - Mar14 | | Not Designated | | |
| Natural gas | | Swap | | 60 | | MMBtu | | n/a |
| | $ | 4.36 |
| | Jan14 - Mar14 | | Not Designated | | |
| Natural gas | | Call Option | | 38 | | MMBtu | | $ | 4.75 |
| | n/a |
| | Jan14 - Dec14 | | Not Designated | | (a) |
| Oil | | Swap | | 30 | | Bbls | | n/a |
| | $ | 93.35 |
| | Jan14 - Dec14 | | Not Designated | | |
| Oil | | Put Option | | 30 | | Bbls | | $ | 70.00 |
| | n/a |
| | Jan14 - Dec14 | | Not Designated | | |
| Oil | | Swap | | 9 | | Bbls | | n/a |
| | $ | 94.58 |
| | Jan14 - Dec14 | | Not Designated | | |
| Natural gas | | Swap | | 46 | | MMBtu | | n/a |
| | $ | 4.25 |
| | Apr14 - Dec14 | | Not Designated | | |
| Natural gas | | Call Option | | 38 | | MMBtu | | $ | 4.75 |
| | n/a |
| | Apr14 - Dec14 | | Not Designated | | |
| Natural gas | | Call Option | | 37 | | MMBtu | | $ | 5.00 |
| | n/a |
| | Jan15 - Dec15 | | Not Designated | | |
| |
| (a) | During January 2013, the Company monetized the remaining portion (Feb13-Dec13) of its 2013 crude oil collar positions of 40 Bbls per month reflected in previous table. The proceeds from this transaction,short natural gas call option, when combined with the proceeds fromCompany’s long production position, represents a “covered call,” and creates a $4.75/MMbtu ceiling during the sale of the listed put for 30 Bbls per month, were used to finance the uplift in the crude oil swap for the period Feb13-Dec13.covered period.
|
Subsequent Event Activity:
Derivative contracts executed subsequent to December 31, 2013 include the following:
|
| | | | | | | | | | | | | | | | |
| Commodity | | Instrument | | Average Notional Volumes per Month | | Quantity Type | | Put/Call Price | | Fixed-Price Swap | | Period | | Designation under ASC 815 |
| Oil | | Swap | | 15 | | Bbls | | n/a | | $ | 94.15 |
| | Feb14 - Mar14 | | Not Designated |
| Oil | | Swap | | 15 | | Bbls | | n/a | | $ | 92.80 |
| | Apr14 - Jun14 | | Not Designated |
| Oil | | Swap | | 15 | | Bbls | | n/a | | $ | 90.40 |
| | Jul14 - Sep14 | | Not Designated |
| Oil | | Swap | | 15 | | Bbls | | n/a | | $ | 88.64 |
| | Oct14 - Dec14 | | Not Designated |
NOTE76 – Fair Value Measurements
Fair value is defined within the accounting rules as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The rules established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:
|
| |
| Level 1 | Valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority. |
| Level 2 | Valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability. |
| Level 3 | Valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority. |
|
| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
Fair Value of Financial Instruments
Cash, Cash Equivalents, and Short-Term Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.
Debt. The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheet. The fair value of Callon’s fixed-rate debt, which is valued using Level 2 inputs, is based upon estimates provided by an independent investment banking firm. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.
The following table summarizes the respective carrying and fair values at:
| | | | For the year ended December 31, | For the year ended December 31, |
| | 2012 | | 2011 | 2013 | | 2012 |
| | Carrying Value | | Fair Value | | Carrying Value | | Fair Value | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| Credit Facility | $ | 10,000 |
| | $ | 10,000 |
| | $ | — |
| | $ | — |
| $ | 22,000 |
| | $ | 22,000 |
| | $ | 10,000 |
| | $ | 10,000 |
|
| 13% Senior Notes due 2016 (a) | 110,668 |
| | 100,112 |
| | 125,345 |
| | 110,571 |
| 53,748 |
| | 50,299 |
| | 110,668 |
| | 100,112 |
|
| Total | $ | 120,668 |
| | $ | 110,112 |
| | $ | 125,345 |
| | $ | 110,571 |
| $ | 75,748 |
| | $ | 72,299 |
| | $ | 120,668 |
| | $ | 110,112 |
|
| |
| (a) | 20122013 and 20112012 Fair value isfair values are calculated only in relation to the $96,96148,481 and $106,96196,961 face value outstanding of the 13% Senior Notes, respectively. The remaining $13,7075,267 and $18,38413,707, respectively represents the Company'sCompany’s deferred credits and have been excluded from the fair value calculation. See Note 54 for additional information.
|
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis (unless otherwise noted below) in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
| |
Commodity Derivative Instruments. Callon’s derivative policy allows for commodity derivative instruments to consist of collars, natural gas and crude oil basis swaps, and similar commodity instrument structures. The fair value of these derivativescommodity derivative instruments is derived using a valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract, and the values are corroborated by quotes obtained from counterparties to the agreements. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair-value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 65 for additional information regarding the Company’s derivative instruments.
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis for each hierarchy level:
| | | December 31, 2012 | | Balance Sheet Presentation | | Level 1 | | Level 2 | | Level 3 | | Total | |
| December 31, 2013 | | | Balance Sheet Presentation | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | | | | | | |
| Derivative financial instruments - current Portion | | Fair market value of derivatives | | $ | — |
| | $ | 1,674 |
| | $ | — |
| | $ | 1,674 |
| | Fair market value of derivatives | | $ | — |
| | $ | 60 |
| | $ | — |
| | $ | 60 |
|
| Derivative financial instruments - non-current | | Other assets, net | | — |
| | 250 |
| | — |
| | 250 |
| | Other assets, net | | — |
| | — |
| | — |
| | — |
|
| Sub-total assets | | $ | — |
| | $ | 1,924 |
| | $ | — |
| | $ | 1,924 |
| | $ | — |
| | $ | 60 |
| | $ | — |
| | $ | 60 |
|
| | | | | | | | | | | | | | | | | |
| Liabilities | | | | |
| | |
| | |
| | |
| | | | |
| | |
| | |
| | |
|
| Derivative financial instruments - current portion | | Fair market value of derivatives | | $ | — |
| | $ | 125 |
| | $ | — |
| | $ | 125 |
| | Fair market value of derivatives | | $ | — |
| | $ | 1,036 |
| | $ | — |
| | $ | 1,036 |
|
| Derivative financial instruments - non-current | | Other long-term liabilities | | — |
| | 116 |
| | — |
| | 116 |
| | Other long-term liabilities | | — |
| | 72 |
| | — |
| | 72 |
|
| Sub-total liabilities | | $ | — |
| | $ | 241 |
| | $ | — |
| | $ | 241 |
| | $ | — |
| | $ | 1,108 |
| | $ | — |
| | $ | 1,108 |
|
| | | | | | | | | | | | | | | | | |
| Total | | | | $ | — |
| | $ | 1,683 |
| | $ | — |
| | $ | 1,683 |
| | | | $ | — |
| | $ | (1,048 | ) | | $ | — |
| | $ | (1,048 | ) |
|
| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
| | | December 31, 2011 | | Balance Sheet Presentation | | Level 1 | | Level 2 | | Level 3 | | Total | |
| December 31, 2012 | | | Balance Sheet Presentation | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | | | | | | | | | | | | | | | | | | | | |
| Derivative financial instruments - current Portion | | Fair market value of derivatives | | $ | — |
| | $ | 2,499 |
| | $ | — |
| | $ | 2,499 |
| |
| Derivative financial instruments - current portion | | | Fair market value of derivatives | | $ | — |
| | $ | 1,674 |
| | $ | — |
| | $ | 1,674 |
|
| Derivative financial instruments - non-current | | Other assets, net | | — |
| | — |
| | — |
| | — |
| | Other assets, net | | — |
| | 250 |
| | — |
| | 250 |
|
| Sub-total assets | | | $ | — |
| | $ | 1,924 |
| | $ | — |
| | $ | 1,924 |
|
| | | | | | | | | | |
| Liabilities | | | | | | | | | |
| Derivative financial instruments - current portion | | | Fair market value of derivatives | | $ | — |
| | $ | 125 |
| | $ | — |
| | $ | 125 |
|
| Derivative financial instruments - non-current | | | Other long-term liabilities | | — |
| | 116 |
| | — |
| | 116 |
|
| Sub-total liabilities | | | $ | — |
| | $ | 241 |
| | $ | — |
| | $ | 241 |
|
| | | | | | | | | | |
| Total | | $ | — |
| | $ | 2,499 |
| | $ | — |
| | $ | 2,499 |
| | $ | — |
| | $1,683 | | $ | — |
| | $1,683 |
The derivative fair values above are based on analysis of each contract. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. See Note 65 for a discussion of net amounts recorded in the Consolidated Balance Sheet at December 31, 20122013.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a nonrecurring basis in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:
Asset Retirement Obligations IncurredOther Property and Equipment. As discussed in Current Period. Callon estimatesNote 13, the fair valueCompany’s decision to abandon certain of AROs based on discounted cash flow projections using numerous estimates, assumptionsits other property and judgments regarding such factorsequipment, that had been classified as (1)held for sale, resulted in an impairment charge of $1,707 which is included in the existenceCompany’s Statement of a legal obligation for an ARO, (2) amounts and timing of settlements, (3) the credit-adjusted risk-free rate to be used and (4) inflation rates. AROs incurredOperations for the year ended December 31, 20122013 and resulting in fair value measurement, including upward revisions to ARO liabilities of $81, were Level. The impairment charge was valued using level 3 fair value measurements. See Note 13 for a summary of changes in the Company’s ARO liability.inputs.
Other Property and Equipment.Acquisition. See Note 3 for additional information regarding the global settlement with Callon’s former joint interest partner on the project. During the second quarter of 2011, Callon2013, the Company acquired 100%approximately 2,468 gross (2,186 net) acres in Reagan and Upton Counties, Texas, which is located in the southern portion of the rights to all remainingMidland Basin for a purchase price of $11,000. The acquisition also included seven gross vertical wells and 1,301 barrels of oil equivalent proved reserves. The Company valued the acquired assets related to onein accordance with the method described below. In accordance with the acquisition method of accounting, the purchase price of the Company's deepwater projects, which primarily consisted of surplus equipment.
As Callon is requiredCompany’s acquisition during the period has been allocated to measure the assets acquired at fair value, Callon estimated each asset’s fair valueand liabilities assumed based on several factors including (1) historical prices received fortheir estimated fair values on the acquisition date. In valuing the acquired assets sold, (2)and liabilities assumed, fair values were based on expected future cash flows based on estimated reserve quantities; costs to produce and develop reserves; and oil and gas forward prices. The purchase price of the similarity of unsold assetsCompany’s acquisition during the period was $11,000 with approximately $2,000 allocated to those previously soldunevaluated oil and gas properties and approximately $9,000 allocated to evaluated oil and gas properties. Asset retirement obligations assumed in connection with the sales prices for those similar assets, (3) the number of market participants expectedtransaction were insignificant due to have an interest in the assets, (4) the degree to which the asset has been customized and would require modification by a purchaser for use, and (5) the nature of the asset being
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
| |
held for sale (i.e. whether the asset is highly specialized, built-for-purpose, etc.). We also obtained certain information that was considered in the valuation of this equipment from an independent firm that is in the business of manufacturing and selling this equipment.
Values assigned to equipment sold priorproperties acquired are immaterial to the June 30, 2011 reporting date and for which the exit price, as defined by US GAAP, became readily determinable, represented Level 2Company’s financial statements. The fair value measurements equal to $3,954 of the total $11,349 acquired through the agreement. The remaining $7,395 of acquired assets represented Level 3 fair value measurementswere based on significant inputs not observable in the limited ability of market pricing information for either identical or similar items. Certain assets were assigned no value in instances where the fair value was indeterminable due to the built-for-purpose or highly specialized nature of the assets. Also asand thus represent a result of this settlement agreement, the Company assumed $2,681 of liabilities, which consisted entirely of a deferred tax liability associated with the basis difference of the equipment.
AtDecember 31, 2012, the Company evaluated for impairment the unsold surplus equipment, noting the passage of time without significant sales activity, as an indicator of impairment. The Company followed the process described above to reevaluate the assets fair values. As a result of this analysis, the Company recorded an impairment charge of $1,177 , which was recorded as a loss on the Statement of Operations. The carrying value of the remaining unsold equipment is $3,634, at December 31, 2012, is recorded on the Consolidated Balance Sheet within Other Property and Equipment, net and represents a Levellevel 3 fair value measurement. See Note 3 for additional information.
NOTE 87 – Employee Benefit Plans
The Company utilizes various forms of incentive compensation designed to align the interest of the executives and employees with those of its stockholders. Tabular disclosures related to the share-based awards are presented in Note 98. The narrative that follows provides a brief description of each plan, summarizes the overall status of each plan and discusses current year awards under each plan:
Savings and Protection Plan
The Savings and Protection Plan (“401-K Plan”) provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee'semployee’s deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company Common Stock to employees. The amounts held under the 401-K Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401-K Plan. The total amounts contributed by the Company, including the value of the common stock contributed, were $918923, $811918 and $690811 in the years 20122013, 20112012 and 20102011, respectively.
|
| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
2011 Omnibus Incentive Plan (the “2011 Plan”)
The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for issuance 2,300 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2011 Plan is the Company'sCompany’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the Company'sCompany’s previous share-based incentive plans became issuable under the 2011 Plan. This transfer provision resulted in the transfer of an additional 841 shares into the plan, increasing the quantity authorized and reserved for issuance under the Plan to 3,141 at the inception of the plan. Another provision provided that shares which would otherwise become available for issue under the previous plans as a result of vesting and/or forfeiture of any equity awards existing as of May 12, 2012, would also increase the authorized shares available to the 2011 Plan. As of December 31, 20122013, the 2011 Plan had 1,6691,192 shares remaining and eligible for future issuance.
Equity awards issued under this plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. Any vested but unexercised options contractually expire 10 years from the date of grant. Equity awards under the 2011 Plan generally vest over time but may also be subject to attaining a specified performance metrics and may be immediate or cliff vest at a specified date. The Company will recognize expense on the grant date for all immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. For performance-based awards, the Company recognizes expense based on its analysis of the performance criteria, and records or reverses expense as necessary based on its analysis. For market-based awards, the Company recognizes expense based on its analysis of the market criteria, and records expense as necessary based on its analysis. Awards with a market-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded.
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
| |
Stock Incentive Award for Inducement of Employment
In April 2012 and as an inducement of employment, the Company awarded 100 restricted stock units to its Senior Vice President of Finance. The restricted stock units vest in one-third increments on each award anniversary date beginning July 1, 2013, and are being expensed ratably over the vesting period.
Following the Chief Operating Officer's ("COO") September 2010 departure from the Company, the COO forfeited his previously awarded 200 restricted and performance-based shares and 333 of his unvested performance-based stock options. Prior to his departure in 2010, the Company achieved the first of three performance metrics specified in the performance-based stock options agreement resulting in the COO vesting in 167 options, for which the Company recorded approximately $180 of compensation expense.
In April 2010 and as an inducement of employment, the Company awarded 50 restricted stock units to its Senior Vice President of Operations. The restricted stock units cliff vested on January 1, 2011, and were fully expensed as of December 31, 2010.
Cash-Settleable RSU Awards
Certain of the Company'sCompany’s RSUs awarded require cash-settlement. Cash-settleable RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash, and are recorded in the Company'sCompany’s consolidated balance sheet for the ratable portion of their fair values. The fair value of the Company’s market-based RSU is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. See Note 7 for additional information regarding fair value of cash-settleable awards.
Market-based RSUs: A significant portion of the Company'sCompany’s cash-settleable RSU awards include a market-based vesting condition and may ultimately vest at a quantity different than the base RSUs awarded. The number of RSUs that cliff-vest is based on a calculation that compares the Company'sCompany’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded.
As of December 31, 20122013, the Company had the following cash-settleable RSU awards outstanding:outstanding (including those that are not based on a market condition):
| | | | | Base Units | | Potential Minimum | | Potential Maximum | | Base Units | | Potential Minimum | | Potential Maximum |
| | | Outstanding at | | Units at Vesting at | | Units at Vesting at | | Outstanding at | | Units at Vesting at | | Units at Vesting at |
| | | December 31, 2012 | | December 31, 2012 | | December 31, 2012 | |
| Vesting in 2013 | | 348 |
| | 79 |
| | 483 |
| |
| Vesting in 2014 | | 569 |
| | 62 |
| | 1,077 |
| | 510 |
| | 45 |
| | 975 |
|
| Vesting in 2015 | | 72 |
| | 72 |
| | 72 |
| | 909 |
| | 60 |
| | 1,758 |
|
| Vesting in 2016 | | | 66 |
| | 66 |
| | 66 |
|
| Other | | — |
| | — |
| | — |
| | 92 |
| | 92 |
| | 92 |
|
| Total cash-settleable RSU awards | | 989 |
| | 213 |
| | 1,632 |
| | 1,577 |
| | 263 |
| | 2,891 |
|
For the year ended December 31, 20122013, 364260 market-based cash-settleable RSUs subject to the peer market-based vesting described above vested at 100% of their maximum potential unit vestingissued units, resulting in a cash payment of 546$1,669. Also during 2013, 65 non-market-based cash settleable RSUs vested, resulting in a cash payment of $239. During 2012, 364 units,market-based cash-settleable RSUs vested at 150%, resulting in a cash payment of $2,626. Additionally, 144 cash-settleableAlso during 2012, 143 non-market-based cash settleable RSUs vested, during 2012, resulting in a cash payment of $757.$763. See Note 98 for additional information regarding cash-settleable RSUs.
|
| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
NOTE 98 - Share-Based Compensation
As discussed in Note 87, the Company grants various forms of share-based compensation awards to employees of the Company and its subsidiaries and to non-employee members of the Board of Directors.At December 31, 20122013, shares available for future share-based awards, including stock options or restricted stock grants, under the Company'sCompany’s only active plan, the 2011 Plan, were 1,6691,192.
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
| |
The following table presents share-based compensation expense for each respective period:
| | | | For the year ended December 31, | For the year ended December 31, |
| | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Share-based compensation expense for: | Equity-based |
| | Liability-based | | Equity-based | | Liability-based | | Equity-based | | Liability-based | Equity-based |
| | Liability-based | | Equity-based | | Liability-based | | Equity-based | | Liability-based |
| Options | $ | — |
| | $ | — |
| | $ | 24 |
| | $ | — |
| | $ | 206 |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 24 |
| | $ | — |
|
| RSU equity awards | 4,210 |
| | — |
| | 2,832 |
| | — |
| | 3,898 |
| | — |
| 3,975 |
| | — |
| | 4,210 |
| | — |
| | 2,832 |
| | — |
|
| Cash-settleable RSU awards | — |
| | 2,916 |
| | — |
| | 1,335 |
| | — |
| | 1,396 |
| — |
| | 5,347 |
| | — |
| | 2,916 |
| | — |
| | 1,335 |
|
| 401(k) contributions in shares | 218 |
| | — |
| | 202 |
| | — |
| | 201 |
| | — |
| 219 |
| | — |
| | 218 |
| | — |
| | 202 |
| | — |
|
| Total share-based compensation expense (a) | $ | 4,428 |
| | $ | 2,916 |
| | $ | 3,058 |
| | $ | 1,335 |
| | $ | 4,305 |
| | $ | 1,396 |
| $ | 4,194 |
| | $ | 5,347 |
| | $ | 4,428 |
| | $ | 2,916 |
| | $ | 3,058 |
| | $ | 1,335 |
|
| |
| (a) | The portion of this share-based compensation expense that was included in general and administrative expense totaled $4,0815,751, $2,5024,081 and $3,1072,502 for the same years respectively, and the portion capitalized to oil and gas properties was $3,2633,791, $1,8913,263 and $2,5941,891, respectively. |
The following table presents the specified share-based compensation expense for the indicated periods:
|
| | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| Unrecognized compensation costs related to: | 2012 | | 2011 | | 2010 |
| Unvested options | | | $ | — |
| | | | $ | — |
| | | | $ | 57 |
|
| Unvested RSU equity awards | | | 6,320 |
| | | | 5,748 |
| | | | 3,353 |
|
| Unvested cash-settleable RSU awards | | | 2,826 |
| | | | 2,498 |
| | | | 2,676 |
|
| | | | | | | | | | | | |
| Future expected share-based compensation expense for: | | | 2013 | | 2014 | | 2015 | | Thereafter | | Total |
| RSU equity awards | | | 3,565 |
| | 2,182 |
| | 573 |
| | — |
| | 6,320 |
|
| Cash-settleable RSU awards | | | 1,862 |
| | 937 |
| | 27 |
| | — |
| | 2,826 |
|
|
| | | | | | | | |
| | For the year ended December 31, |
| Unrecognized compensation costs related to: | 2013 | | 2012 | | 2011 |
| Unvested RSU equity awards | 5,331 |
| | 6,320 |
| | 5,748 |
|
| Unvested cash-settleable RSU awards | 7,669 |
| | 2,826 |
| | 2,498 |
|
The Company’s future expected share-based compensation cost related to unvested RSU and cash-settleable RSU awards is expected to be recognized over a weighted-average period of 1.4 years.
The following table summarizes the Company'sCompany’s cash-settleable RSU awards for the periods indicated:
| | | Consolidated Balance Sheets Classification | | 2012 | | 2011 | | 2010 | | 2013 | | 2012 | | 2011 |
| Accounts payable and accrued liabilities - current portion | | $ | 1,429 |
| | $ | 604 |
| | $ | — |
| | $ | 4,173 |
| | $ | 1,429 |
| | $ | 604 |
|
| Other long-term liabilities - non-current portion | | 1,017 |
| | 2,309 |
| | 1,578 |
| | 3,409 |
| | 1,017 |
| | 2,309 |
|
| Total cash-settleable RSU awards | | $ | 2,446 |
| | $ | 2,913 |
| | $ | 1,578 |
| | $ | 7,582 |
| | $ | 2,446 |
| | $ | 2,913 |
|
Stock Options
The Company uses the Black-Scholes option pricing model to estimate the fair value of stock option awards with the following weighted-average assumptions for the indicated periods. However, the Company issued no stock options for the past three years and had no options vestedvest or forfeit during 2012. 2013. Additionally, no options were exercised, 15 options expired unexercised during the year. As of December 31, 2013, the Company had 52 options outstanding and exercisable at a weighted average exercise price per option of $13.75, with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.3 years.
As of December 31, 2012, the Company had 67 options outstanding and exercisable at a weighted average exercise price per option of $11.82, with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.7 years. During 2012, 31 options were exercised at a weighted average exercise price per option of $3.72 and with an aggregate intrinsic value of $56. Also During 2012, 60 options expired unexercised and 15 options were forfeited. As of December 31, 2011, the Company had 173 options outstanding and exercisable at a weighted average exercise price per option of $8.66, with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.0 years. The Company net-share settles option exercises and therefore receives no cash proceeds from the exercise of stock options.
|
| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except share,well, acreage, per-share and per-hedgeper-derivative instrument data) | |
Restricted Stock Units
The following table represents unvested restricted stock activity for the year ended December 31, 20122013:
| | | | Weighted average | Weighted average |
| | Number of Shares | | Grant-Date Fair Value per Share | | Period over which expense is expected to be recognized | Number of Shares | | Grant-Date Fair Value per Share | | Period over which expense is expected to be recognized |
| Outstanding at the beginning of the period | 1,918 |
| | $ | 5.16 |
| | | 2,295 |
| | $ | 5.58 |
| | |
| Granted | 1,008 |
| | 5.22 |
| | 944 |
| | 3.82 |
| |
| Vested (a) | (530 | ) | | 3.29 |
| | (754 | ) | | 5.10 |
| |
| Forfeited | (101 | ) | | 5.88 |
| | (223 | ) | | 5.37 |
| |
| Outstanding at the end of the period | 2,295 |
| | $ | 5.58 |
| | 1.5 | 2,262 |
| | $ | 5.03 |
| | 1.5 |
| |
| a. | The fair value of shares vested was $2,817. $2,689. |
NOTE 109 – Equity Transactions
On May 30, 2013, the Company issued 78,947 of 10.0% Series A Cumulative Preferred Stock (the “Preferred Stock”) and received $70,035 net proceeds after deducting the underwriting commissions and offering expenses. The sale consisted of 1,579 shares of Preferred Stock, par value $0.01 per share, public offering price of $47.50 per share and liquidation preference of $50.00 per share in an underwritten public offering. The Preferred Stock ranks senior to the Company’s common stock with respect to the payment of dividends and distribution of assets upon liquidation or dissolution. The Preferred Stock has no stated maturity and is not subject to mandatory redemption or any sinking fund. The Preferred Stock will remain outstanding indefinitely unless repurchased by the Company or converted into Callon common stock in connection with certain changes in control as defined in the Preferred Stock prospectus.
Holders of the Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors (the “Board”), out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board. The first dividend date for the Preferred Stock was June 30, 2013, and these dividends were paid on June 28, 2013 (as June 30 fell on a weekend) in the amount of $0.43 per share or $679 for the stub period beginning with the issuance on May 30, 2013 through the dividend date on June 30, 2013. For the subsequent quarters ended September 30 and December 31, 2013, the Board of Directors declared for each quarter a dividend of $1.25 per share, or a total of $1,974, on the Company’s Preferred Stock, resulting in total dividend expense recognized in 2013 of $4,627.
Beginning on May 30, 2018, the Company may, solely at its option, redeem the Preferred Stock in whole at any time, or in part from time to time, for cash at a redemption price of $50.00 per share, plus accrued and unpaid dividends (whether or not declared) to the redemption date. The Company may redeem the Preferred Stock following certain changes of control as defined in the Preferred Stock prospectus, in whole or in part, within 120 days after the date on which the change of control has occurred, for cash at $50.00 per share, plus accrued and unpaid dividends (whether or not declared) to the redemption date. If the Company elects not to exercise this option, the holders of the Preferred Stock have the option to convert each share of Preferred Stock into a predefined number of Company common shares, subject to certain adjustments.
As defined in a provision of the Preferred Stock prospectus, the common shares reserved for issuance vary based on the number of authorized common shares. Based on the Company’s 60,000 authorized shares at December 31, 2013, 16,800 shares were reserved for a potential conversion. Subsequent to December 31, 2013, via a majority shareholder vote, the number of authorized shares of common stock was increased from 60,000 to 110,000 with a corresponding increase in the number of common shares reserved for a potential conversion to a maximum of 42,200 shares. Based on the Company’s closing common stock price of $6.53 per share on December 31, 2013, the Company reserved 12,090 shares to satisfy the potential conversion.
Except as required by law, holders of the Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such dividends in arrears are paid in full, the holders will be entitled to elect two directors to the Board, which will increase in size by that same number of directors.
|
| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
During February, 2011, the Company received $73,72073,765 in net proceeds from the public offering of 10.1 million shares of its common stock, which included the issuance of 1.1 million shares pursuant to the underwriters'underwriters’ over-allotment option. The Company used $35,062 of the proceeds to repurchase $31,000 principal amount of its Senior Notes, with the remaining proceeds intended for general corporate purposes including the planned development of the Company'sCompany’s Permian basin and other onshore assets. The Company completed the redemption in March 2011, which resulted in a gain on the early extinguishment of debt of $1,974. The gain represents the difference between the $35,062 paid for the $37,004 (including the $31,000 principal amount of the notes plus $6,004 of accelerated deferred credit amortization) carrying value of the Notes, offset by the $4,030 charge related to the 13% call premium required by the terms of the call option and $32 of redemption expenses.
NOTE 1110 – Income Taxes
The following table presents Callon’s net tax benefits relating to its reported net losses and other temporary differences from operations:
| | | | For the year ended December 31 | For the Year Ended December 31 |
| | 2012 | | 2011 | 2013 | | 2012 |
| Deferred tax asset: | | | | |
| Deferred tax asset | | | | |
| Federal net operating loss carryforward | $ | 87,774 |
| | $ | 89,457 |
| $ | 70,365 |
| | $ | 87,774 |
|
| Statutory depletion carryforward | 8,184 |
| | 7,032 |
| 8,880 |
| | 8,184 |
|
| Alternative minimum tax credit carryforward | 208 |
| | 208 |
| 208 |
| | 208 |
|
| Asset retirement obligations | 3,357 |
| | 3,552 |
| 1,024 |
| | 3,357 |
|
| Other | 9,571 |
| | 9,182 |
| 7,575 |
| | 9,571 |
|
| Total deferred tax asset | 109,094 |
| | 109,431 |
| 88,052 |
| | 109,094 |
|
| Deferred tax liability: | | | | |
| Crude oil and natural gas properties | 41,336 |
| | 40,782 |
| |
| Deferred tax liability | | | | |
| Oil and natural gas properties | | 26,412 |
| | 41,336 |
|
| Other | 3,375 |
| | 2,906 |
| 32 |
| | 3,375 |
|
| Total deferred tax liability | 44,711 |
| | 43,688 |
| 26,444 |
| | 44,711 |
|
| Net deferred tax asset | $ | 64,383 |
| | $ | 65,743 |
| $ | 61,608 |
| | $ | 64,383 |
|
Prior to 2012, the Company carried a full valuation allowance against its net deferred tax assets. The Company considered both the positive and negative evidence in determining whether it was more likely than not that its deferred tax assets were recoverable. The Company incurred a loss in 2008, primarily as a result of a write-down of its crude oil and natural gas properties following the ceiling test, which created a loss on an aggregate basis for the three-year period ended December 31, 2008. Primarily as a result of recent cumulative losses, the Company established a full valuation allowance as of December 31, 2008, and continued to carry the full valuation allowance each reporting period until December 31, 2011.
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
| |
The Company reported At December 31, 2011, after considering all available positive and negative evidence, including the Company’s profitable operations from 2009 to 2012, and had2011 which resulted in income on an aggregate basis for the three-year periods year period ended December 31, 2011, and 2012. After considering all available positive and negative evidence,future operating results based on proved reserves, the Company believeddetermined that it was more likely than not that it would fully utilize its deferred tax assets recorded at December 31, 2011 and 2012. Among other factors, the Company believed its recent cumulative income, together with its future operating results using current proved reserves, provided sufficient positive evidence to reach this conclusion. Based upon this analysis,2011. Therefore, the Company reversed its related valuation allowance at December 31, 2011.
If not utilized, the Company’s federal operating loss ("NOL"(“NOL”) carryforwards will expire as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Year Expiring |
| | | Total | | 2013-2018 |
| | 2019-2021 | | 2022-2024 | | 2025-2027 | | 2028-2031 |
| Federal NOL carryforwards | | $ | 250,783 |
| | $ | — |
| | $ | 56,929 |
| | $ | 101,495 |
| | $ | 39,714 |
| | $ | 52,645 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Year Expiring |
| | | Total | | 2014-2019 |
| | 2020-2022 | | 2023-2025 | | 2026-2028 | | 2029-2033 |
| Federal NOL carryforwards | | $ | 201,042 |
| | $ | — |
| | $ | 48,986 |
| | $ | 65,878 |
| | $ | 32,714 |
| | $ | 53,464 |
|
The Company has limited state taxable income. Accordingly, the Company has established a full valuation allowance on the tax benefitbenefits associated with the state net operating loss carryforwards of approximately $169,672approximately$167,795 which expire in years through 2032,2033, as the Company does not anticipate generating taxable state income in the states in which these carryforwards apply. These amounts are not included in the deferred tax summary table above.
In 2009, the Company began to shift its operational focus from exploration, development and production in the Gulf of Mexico to the acquisition and development of onshore properties. This shift in exploration and development activity resulted in an increase in Texas income from production by the end of 2012.production. This, coupled with the Company’s exit from the Gulf of Mexico (the sale of one of the Company's primary federal offshore producing properties,its interest in the Habanero field in December 2012 and the Medusa field in December 2013), results in a change in the projected future Texas state tax rate beyond 20122013 as a component of overall anticipated future taxes.
|
| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
The Company had no significant unrecognized tax benefits at December 31, 20122013. Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. Tax periods for years 20002001 through 20122013 remain open to examination by the federal and state taxing jurisdictions to which the Company is subject.
In addition, the NOL carryback provision of the Internal Revenue Code was amended on November 6, 2009, as part of The Worker, Homeownership and Business Assistance Act of 2009 (the “WHB Act”). The WHB Act allows businesses with NOLs for 2008 and 2009 to carry back losses for up to five years and suspends the 90% limitation on the use of any alternative minimum tax NOL deduction attributable to carrybacks of the applicable NOL. There would be no limit on the NOL carrybacks for the first four preceding years of the carryback period, but for the fifth preceding year, the NOL carryback would be limited to fifty percent of a company’s taxable income in that year. In applying the new five-year NOL carryback rule, the Company was able to file during 2010 for a refund claim to recover approximately $174.
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
| |
Below is a reconciliation of the reported amount of income tax expense attributable to continuing operations to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations. | | | | | For the years ended December 31, | | For the Years Ended December 31, |
| Component of Income Tax Rate Reconciliation | | 2012 | | 2011 | | 2010 | | 2013 | | 2012 | | 2011 |
| Income tax expense computed at the statutory federal income tax rate | | 35 | % | | 35 | % | | 35 | % | | 35 | % | | 35 | % | | 35 | % |
| Change in valuation allowance | | — | % | | (227 | )% | | (18 | )% | | — | % | | — | % | | (227 | )% |
| Percentage depletion carryforward | | (22 | )% | | (3 | )% | | (15 | )% | | (8 | )% | | (22 | )% | | (3 | )% |
| State taxes net of federal benefit | | 6 | % | | — | % | | — | % | | 4 | % | | 6 | % | | — | % |
| Section 162m | | 22 | % | | — | % | | — | % | |
| Restricted stock and stock options | | 2 | % | | — | % | | — | % | | 5 | % | | 2 | % | | — | % |
| Section 162(m) | | | 6 | % | | 22 | % | | — | % |
| Other | | 4 | % | | 4 | % | | — | % | | — | % | | 4 | % | | 4 | % |
| Effective income tax rate | | 47 | % | | (191 | )% | | 2 | % | | 42 | % | | 47 | % | | (191 | )% |
| | | | | | | | | | | | | |
| | | For the years ended December 31, | | For the Years Ended December 31, |
| Components of Income Tax Expense | | 2012 | | 2011 | | 2010 | | 2013 | | 2012 | | 2011 |
| Current federal income tax benefit | | $ | — |
| | $ | — |
| | $ | (174 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
| Current state income tax expense | | 110 |
| | — |
| | — |
| | 326 |
| | 110 |
| | — |
|
| Deferred federal income tax expense | | 1,777 |
| | 13,176 |
| | 1,503 |
| | 2,652 |
| | 1,777 |
| | 13,176 |
|
| Change in deferred rate | | 336 |
| | — |
| | — |
| |
| Deferred state income tax expense | | | 126 |
| | 336 |
| | — |
|
| Valuation allowance | | — |
| | (82,459 | ) | | (1,503 | ) | | — |
| | — |
| | (82,459 | ) |
| Total income tax expense (benefit) | | $ | 2,223 |
| | $ | (69,283 | ) | | $ | (174 | ) | | $ | 3,104 |
| | $ | 2,223 |
| | $ | (69,283 | ) |
NOTE 1211 – Crude Oil and Natural Gas PropertiesAsset Retirement Obligations
The following table discloses certain financial data relatingsummarizes the activity for the Company’s asset retirement obligations:
|
| | | | | | | |
| | For the Year Ended December 31, |
| | 2013 | | 2012 |
| Asset retirement obligations at beginning of the period | $ | 13,301 |
| | $ | 13,938 |
|
| Accretion expense | 1,785 |
| | 2,253 |
|
| Liabilities incurred | 679 |
| | 205 |
|
| Liabilities settled | (457 | ) | | (1,073 | ) |
| Liabilities related to oil and gas properties sold | (4,765 | ) | | (877 | ) |
| Revisions to estimate | (3,811 | ) | | (1,145 | ) |
| Asset retirement obligations at end of period | 6,732 |
| | 13,301 |
|
| Less: current asset retirement obligations | (4,120 | ) | | (2,336 | ) |
| Long-term asset retirement obligations at the end of the period | $ | 2,612 |
| | $ | 10,965 |
|
Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets at December 31, 2013 as long-term restricted investments were $3,806. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company's crudeCompany’s oil and natural gas activities,properties.
On December 5, 2013, the Company closed on its agreement to sell its interest in the Medusa field, Medusa Spar LLC, and substantially all of which are located inits Gulf of Mexico shelf properties to W&T Offshore, Inc. (“W&T”). Under the United States.
|
| | | | | | | | | | | |
| | For the year ended December 31, |
| | 2012 | | 2011 | | 2010 |
| Capitalized costs incurred: | | | | | |
| Evaluated Properties- | | | | | |
| Beginning of period balance | $ | 1,421,640 |
| | $ | 1,316,677 |
| | $ | 1,593,884 |
|
| Deconsolidation of Subsidiary January 1, 2010 | — |
| | — |
| | (364,589 | ) |
| Capitalized G&A | 12,148 |
| | 11,205 |
| | 10,676 |
|
| Property acquisition costs | 2,075 |
| | — |
| | — |
|
| Exploration costs | 22,703 |
| | 5,473 |
| | 14,739 |
|
| Development costs | 38,444 |
| | 88,285 |
| | 61,967 |
|
| End of period balance | $ | 1,497,010 |
| | $ | 1,421,640 |
| | $ | 1,316,677 |
|
| | | | | | |
| Unevaluated Properties (excluded from amortization): | |
| | |
| | |
|
| Beginning of period balance | $ | 2,603 |
| | $ | 8,106 |
| | $ | 25,442 |
|
| Acquisitions | 29,590 |
| | 2,422 |
| | 1,374 |
|
| Exploration | 34,674 |
| | 1,372 |
| | 2,187 |
|
| Capitalized interest | 2,109 |
| | 573 |
| | 2,000 |
|
| Transfers to evaluated | (200 | ) | | (9,870 | ) | | (22,897 | ) |
| End of period balance | $ | 68,776 |
| | $ | 2,603 |
| | $ | 8,106 |
|
| | | | | | |
| Accumulated depreciation, depletion and amortization: | |
| | |
| | |
|
| Beginning of period balance | $ | 1,208,331 |
| | $ | 1,155,915 |
| | $ | 1,488,718 |
|
| Provision charged to expense | 48,524 |
| | 52,416 |
| | 31,786 |
|
| Deconsolidation of Subsidiary January 1, 2010 | — |
| | — |
| | (364,589 | ) |
| Sale of mineral interests | 39,410 |
| | — |
| | — |
|
| End of period balance | $ | 1,296,265 |
| | $ | 1,208,331 |
| | $ | 1,155,915 |
|
|
| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except share,well, acreage, per-share and per-hedgeper-derivative instrument data) | |
The Company’s total revisions to estimates of $3,811 for the year ended December 31, 2013 relate to downward revisions related to the changes in the expecting timing of the abandonment.
NOTE 12 – Supplemental Information on Oil and Natural Gas Operations (Unaudited)
Oil and Natural Gas Properties
The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States.
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| Capitalized costs incurred: | 2013 | | 2012 | | 2011 |
| Evaluated Properties- | | | | | |
| Beginning of period balance | $ | 1,497,010 |
| | $ | 1,421,640 |
| | $ | 1,316,677 |
|
| Capitalized G&A | 10,014 |
| | 12,148 |
| | 11,205 |
|
| Property acquisition costs | 10,885 |
| | 2,075 |
| | — |
|
| Exploration costs | 147,164 |
| | 22,703 |
| | 5,473 |
|
| Development costs | 36,504 |
| | 38,444 |
| | 88,285 |
|
| End of period balance | $ | 1,701,577 |
| | $ | 1,497,010 |
| | $ | 1,421,640 |
|
| | | | | | |
| Unevaluated Properties (excluded from amortization): | |
| | |
| | |
|
| Beginning of period balance | $ | 68,776 |
| | $ | 2,603 |
| | $ | 8,106 |
|
| Acquisitions | 2,259 |
| | 29,590 |
| | 2,422 |
|
| Exploration | 10,767 |
| | 34,674 |
| | 1,372 |
|
| Capitalized interest | 4,410 |
| | 2,109 |
| | 573 |
|
| Transfers to evaluated | (42,990 | ) | | (200 | ) | | (9,870 | ) |
| End of period balance | $ | 43,222 |
| | $ | 68,776 |
| | $ | 2,603 |
|
| | | | | | |
| Accumulated depreciation, depletion and amortization: | |
| | |
| | |
|
| Beginning of period balance | $ | 1,296,265 |
| | $ | 1,208,331 |
| | $ | 1,155,915 |
|
| Provision charged to expense | 42,251 |
| | 48,524 |
| | 52,416 |
|
| Sale of mineral interests | 82,096 |
| | 39,410 |
| | — |
|
| End of period balance | $ | 1,420,612 |
| | $ | 1,296,265 |
| | $ | 1,208,331 |
|
Unevaluated property costs primarily include lease acquisition costs incurred at federal and state lease sales, unevaluated drilling costs, seismic, capitalized interest and certain overhead costs related to exploration and development. Collectively, these costs are excluded from the amortizable evaluated property base, and consisted of $66,173 incurred in 2012, $841 in 2011, and $1,762 in 2010 . These costs are directly related to the acquisition and evaluation of unproved properties and major development projects. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The Company expects that the majority of these costs will be evaluated over the next three but within five years. The Company’s unevaluated property balance increaseddecreased by $66,17325,554 to $68,77643,222 at December 31, 20122013 compared to December 31, 20112012. A significant portion of this increasedecrease relates to the purchasetransfer of leases, primarily indrilling and completion costs from the Midland basin and exploration costs associated with evaluating our new acreage.unevaluated property base to the evaluated property base.
Subsequent to December 31, 20122013 and through March 8, 201310, 2014, the Company completed twosix horizontal exploration wells, and two vertical exploration wells and is evaluating the results. The Company also drilled threefour horizontal wells and had onetwo in progress. Additionally, the Company drilled two vertical exploratory wells and will be evaluating the results.
Depletion per unit-of-production (Boe)(BOE) amounted to $31.5631.12, $26.4231.56 and $19.0026.42 for the years ended December 31, 20122013, 20112012, and 20102011, respectively. Lease operating expense or production costs, per unit-of-production (Boe)(BOE) amounted to $16.8614.00, $11.0414.81, and $10.589.92 for the years ended December 31, 20122013, 20112012, and 20102011, respectively.
|
| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its proved crude oil and natural gas properties each quarter. Under these rules, capitalized costs of crude oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved crude oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average crude oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the “ceiling” is exceeded. Given the volatility of crude oil and natural gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash flows from proved crude oil and natural gas reserves could change in the near term. If crude oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of crude oil and natural gas properties could occur in the future. For the years ended December 31, 20122013, 20112012, and 20102011, the Company recorded no impairment charges related to its crude oil and natural gas properties as a result of this calculation.
Property Acquisitions and Dispositions
Acquisitions:Estimated Reserves
During the first quarter of 2012, the Company acquired approximately 16,233 gross (14,653 net) acres in Borden county, which is located in the northern Midland basin. The northern Midland basin has had limited drilling activity compared with the southern Midland basin (where our current production is located), increasing the economic risk related to these drilling activities. The purchase price of $14,538 was funded from existing cash balances. During the third quarter of 2012, we acquired an additional 8,095 gross acres (6,964 net) in this area for a total consideration of $4,835.
During the second quarter of 2012, the Company signed a purchase and sale agreement to acquire 2,319 gross (1,762 net) acres in southern Reagan county, Texas for a total purchase price of $12,012, which was financed with a draw on the Credit Facility. The transaction had an effective date of May 1, 2012 and closed on July 5, 2012.
Dispositions:
Effective December 28, 2012, the Company closed on the sale of its 11.25% working interest in the Habanero field (Garden Banks Block 341). The Company sold its interest in Habanero to Shell Offshore Inc., a subsidiary of Royal Dutch Shell Plc, for an estimated net cash consideration of USD $39,410 after customary purchase price adjustments. As discussed in Note 2, the proceeds from the sale were accounted for as a reduction to capitalized costs as the sale did not significantly alter the relationship between capitalized costs and proved reserves.
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
| |
NOTE 13 – Asset Retirement Obligations
The following table summarizes the activity for the Company’s asset retirement obligations:
|
| | | | | | | |
| | For the year ended December 31, |
| | 2012 | | 2011 |
| Asset retirement obligations at beginning of the period | $ | 13,938 |
| | $ | 15,925 |
|
| Accretion expense | 2,253 |
| | 2,338 |
|
| Liabilities incurred | 205 |
| | 36 |
|
| Liabilities settled | (1,950 | ) | | (3,797 | ) |
| Revisions to estimate | (1,145 | ) | | (564 | ) |
| Asset retirement obligations at end of period | 13,301 |
| | 13,938 |
|
| Less: current asset retirement obligations | (2,336 | ) | | (1,260 | ) |
| Long-term asset retirement obligations at the end of the period | $ | 10,965 |
| | $ | 12,678 |
|
Certain of the Company's operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets at December 31, 2012 as long-term restricted investments were $3,798. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.
NOTE 14 – Supplemental Crude Oil and Natural Gas Reserve Data (unaudited))
The Company's proved oil and natural gas reserves at December 31, 20122013, 20112012 and 20102011 have been estimated by Huddleston & Co., Inc., the Company’s independent petroleum engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions.
There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company'sCompany’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.
|
| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except share,well, acreage, per-share and per-hedgeper-derivative instrument data) | |
Estimated Reserves
Changes in the estimated net quantities of crude oil and natural gas reserves, all of which are located onshore within the continental United States and offshore within the Gulf of Mexico, are as follows:
| | | | Reserve Quantities For the year ended December 31, | Reserve Quantities For the year ended December 31, |
| | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Proved developed and undeveloped reserves: | | | | | | | | | | |
| Crude Oil (MBbls): | | | | | | |
| Oil (MBbls): | | | | | | |
| Beginning of period | 10,075 |
| | 8,149 |
| | 6,479 |
| 10,780 |
| | 10,075 |
| | 8,149 |
|
| Revisions to previous estimates | (488 | ) | | (110 | ) | | 423 |
| (2,540 | ) | | (488 | ) | | (110 | ) |
| Change in ownership | — |
| | — |
| | — |
| |
| Purchase of reserves in place | 38 |
| | — |
| | — |
| 150 |
| | 38 |
| | — |
|
| Sale of reserves in place | (504 | ) | | (30 | ) | | — |
| (3,294 | ) | | (504 | ) | | (30 | ) |
| Extensions and discoveries | 2,636 |
| | 3,062 |
| | 2,106 |
| 7,713 |
| | 2,636 |
| | 3,062 |
|
| Production | (977 | ) | | (996 | ) | | (859 | ) | (911 | ) | | (977 | ) | | (996 | ) |
| End of period | 10,780 |
| | 10,075 |
| | 8,149 |
| 11,898 |
| | 10,780 |
| | 10,075 |
|
| Natural Gas (MMcf): | | | | | | | | | | |
| Beginning of period | 35,118 |
| | 32,957 |
| | 19,103 |
| 19,753 |
| | 35,118 |
| | 32,957 |
|
| Revisions to previous estimates | (10,838 | ) | | 486 |
| | 354 |
| (5,351 | ) | | (10,838 | ) | | 486 |
|
| Change in ownership | — |
| | — |
| | — |
| |
| Purchase of reserves in place | 115 |
| | — |
| | — |
| 317 |
| | 115 |
| | — |
|
| Sale of reserves in place | (4,404 | ) | | (308 | ) | | — |
| (4,576 | ) | | (4,404 | ) | | (308 | ) |
| Extensions and discoveries | 3,350 |
| | 7,064 |
| | 18,392 |
| 10,619 |
| | 3,350 |
| | 7,064 |
|
| Production | (3,588 | ) | | (5,081 | ) | | (4,892 | ) | (3,011 | ) | | (3,588 | ) | | (5,081 | ) |
| End of period | 19,753 |
| | 35,118 |
| | 32,957 |
| 17,751 |
| | 19,753 |
| | 35,118 |
|
| | | | | | | | | | | |
| Proved developed reserves: | | | | | | | | | | |
| Crude Oil (MBbls): | | | | | | |
| Oil (MBbls): | | | | | | |
| Beginning of period | 5,069 |
| | 4,503 |
| | 4,346 |
| 4,955 |
| | 5,069 |
| | 4,503 |
|
| End of period | 4,955 |
| | 5,069 |
| | 4,503 |
| 5,960 |
| | 4,955 |
| | 5,069 |
|
| Natural Gas (MMcf): | | | | | | | | | | |
| Beginning of period | 11,605 |
| | 12,715 |
| | 12,301 |
| 10,680 |
| | 11,605 |
| | 12,715 |
|
| End of period | 10,680 |
| | 11,605 |
| | 12,715 |
| 9,059 |
| | 10,680 |
| | 11,605 |
|
| MBoe: | | | | | | |
| MBOE: | | | | | | |
| Beginning of period | 7,003 |
| | 6,622 |
| | 6,396 |
| 6,735 |
| | 7,003 |
| | 6,622 |
|
| End of period | 6,735 |
| | 7,003 |
| | 6,622 |
| 7,470 |
| | 6,735 |
| | 7,003 |
|
| Proved undeveloped reserves: | | | | | | | | | | |
| Crude Oil (MBbls): | | | | | | |
| Oil (MBbls): | | | | | | |
| Beginning of period | 5,006 |
| | 3,645 |
| | 2,133 |
| 5,825 |
| | 5,006 |
| | 3,645 |
|
| End of period | 5,825 |
| | 5,006 |
| | 3,645 |
| 5,938 |
| | 5,825 |
| | 5,006 |
|
| Natural Gas (MMcf): | | | | | | | | | | |
| Beginning of period | 23,513 |
| | 20,241 |
| | 6,802 |
| 9,073 |
| | 23,513 |
| | 20,241 |
|
| End of period | 9,073 |
| | 23,513 |
| | 20,241 |
| 8,692 |
| | 9,073 |
| | 23,513 |
|
| MBoe | | | | | | |
| MBOE | | | | | | |
| Beginning of period | 8,925 |
| | 7,019 |
| | 3,267 |
| 7,337 |
| | 8,925 |
| | 7,019 |
|
| End of period | 7,337 |
| | 8,925 |
| | 7,019 |
| 7,387 |
| | 7,337 |
| | 8,925 |
|
Total Proved Reserves: The Company ended 2013 with estimated net proved reserves of 14,857 MBOE, representing a 6% increase over 2012 withyear-end estimated net proved reserves of 14,072 MBoe, representing a 12% decrease over 2011 year-end estimated net proved reserves of 15,928 MBoe.MBOE. The decreaseincrease is primarily due to the sale of the Company's interest in the Habanero field and the downward revision of our Haynesville Shale undeveloped reserves at year-end 2012, which were reduced due to low natural gas prices. These decreases were partially offset by the Company’s development of a portion of its Permian basin, on which it drilled a total of 2726 oil wells during 20122013. The increase is offset by the sale of the Company’s interest in the Medusa field and due to the Company’s reclassification of certain vertical PUD locations to the horizontal probable and PUD categories.
Extrapolation of performance history and material balance estimates were utilized by the Company'sCompany’s independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing
|
| | |
Callon Petroleum Company | Notes to the Consolidated Financial Statements
(All amounts in thousands, except share, per-share and per-hedge data)
| |
properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production.production, and to a small extent, horizontal PDP and PUD categories.
|
| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
Proved Undeveloped Reserves: The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s onshore properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. The Company'sCompany’s PUDs decreasedincreased 18%1% to 7,3377,387 MBoeMBOE from 8,925 MBoe7,337 MBOE at December 31, 20122013 and 20112012, respectively. The Company added 5,168 MBOE to its PUDs, primarily from the continued horizontal development of its Permian Basin properties. The increase in Permian Basin PUDs was partially offset by the reclassification of 3,724 MBOE, or 51%, included in the year-end 2012 PUD reserves related to vertical PUD locations that were reclassified to the horizontal probable, and to a small extent, horizontal PDP and PUD categories. The reclassified vertical PUDs include Wolfberry PUD locations that included certain target zones that are now expected to be more efficiently developed by the Company’s multi-level horizontal drilling programs initiated in 2012. Also offsetting the Permian Basin PUD growth were the sale of 1,297 MBOE, or 18%, included in the year-end 2012 PUD reserves related to our Medusa field and the conversion of a small portion of 2012 PUD reserves to PDPs during 2013 from the drilling of vertical wells.
The Company’s PUDs decreased 18% to 7,337 MBOE from 8,925 MBOE at December 31, 2012 and 2011, respectively. Additions during the year added 2,344 MBoe MBOE to the Company'sCompany’s PUDs, offset by (1) 557 MBoe MBOE primarily comprised of transfers to PDPs as a result of our development program, (2) 1,148 MBoe MBOE related to the sale of Habanero, and (3) 2,227 MBoe MBOE related to reductions in our PUD reserves, primarily related to the Haynesville Shale, by amounts no longer deemed to be economic PUDs at year-end. Of the Company'sCompany’s year-end 2011 PUD reserves, 6% were converted to proved developed producing reserves by year end 2012,, at a total cost of approximately $19$19 million,, net.
Of the Company's Company’s 2012 PUDs, 1,297 MBoe are MBOE were attributable to the Company’s offshore properties in the Medusa fieldsfield in the Gulf of Mexico. The Company's deepwater PUDs have been classified as PUDs for more than five years, though we expect to develop these PUDs withinAs previously noted, the next two years. Callon's decision to classify these reserves as PUDs was primarily based on (1)Company sold its ongoing development activitiesinterest in the area, (2) its historical record of completing development of comparable long-term projects, (3) the amount of time which Callon have maintained the leases or booked reserves without significant development activities and (4) the extent to which Callon have followed previously adopted development plans. Callon's discussions with the field's operator have resulted in the modification of certain development plans for Medusa to drill or sidetrack PUDs within a shorter period of time than originally estimated. The Company expects to develop its Medusa PUDs by drilling a new well by the first quarter of 2014. The Company did not convert any offshore, deepwater PUDs to proved developed in 2012.field during 2013.
Standardized Measure
The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 20122013. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on either the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods:
| | | | | 2012 | | 2011 | | 2010 | | 2013 | | 2012 | | 2011 |
| Average 12-month price, net of differentials, per Mcf of natural gas | | $ | 4.81 |
| | $ | 5.60 |
| | $ | 5.10 |
| | $ | 5.45 |
| | $ | 4.81 |
| | $ | 5.60 |
|
| Average 12-month price, net of differentials, per barrel of crude oil | | 94.68 |
| | 98.98 |
| | 78.07 |
| |
| Average 12-month price, net of differentials, per barrel of oil | | | $ | 92.16 |
| | 94.68 |
| | 98.98 |
|
Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.
Natural gas production from our deepwater and Permian basinBasin properties has a high BTUBtu content of separator natural gas. The natural gas Mcf prices of $4.81$5.45 and $5.60$4.81 used in the 20122013 and 20112012 reserve estimates include adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected oil prices of $94.68$92.16 and $98.98$94.68 used in the 20122013 and 20112012 reserve estimates have been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.
|
| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except share,well, acreage, per-share and per-hedgeper-derivative instrument data) | |
| | | | Standardized Measure For the year ended December 31, | Standardized Measure For the year ended December 31, |
| | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Future cash inflows | $ | 1,115,570 |
| | $ | 1,194,079 |
| | $ | 804,111 |
| $ | 1,193,299 |
| | $ | 1,115,570 |
| | $ | 1,194,079 |
|
| Future costs - | | | | | | | | | | |
| Production | (249,329 | ) | | (356,653 | ) | | (277,793 | ) | (357,005 | ) | | (249,329 | ) | | (356,653 | ) |
| Development and net abandonment | (273,817 | ) | | (268,628 | ) | | (146,870 | ) | (155,667 | ) | | (273,817 | ) | | (268,628 | ) |
| Future net inflows before income taxes | 592,424 |
| | 568,798 |
| | 379,448 |
| 680,627 |
| | 592,424 |
| | 568,798 |
|
| Future income taxes | (55,772 | ) | | (78,813 | ) | | (24,719 | ) | (68,239 | ) | | (55,772 | ) | | (78,813 | ) |
| Future net cash flows | 536,652 |
| | 489,985 |
| | 354,729 |
| 612,388 |
| | 536,652 |
| | 489,985 |
|
| 10% discount factor | (305,504 | ) | | (219,628 | ) | | (155,813 | ) | (328,442 | ) | | (305,504 | ) | | (219,628 | ) |
| Standardized measure of discounted future net cash flows | $ | 231,148 |
| | $ | 270,357 |
| | $ | 198,916 |
| $ | 283,946 |
| | $ | 231,148 |
| | $ | 270,357 |
|
| | | | | | | | | | | |
| | Changes in Standardized Measure For the year ended December 31, | Changes in Standardized Measure For the year ended December 31, |
| | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Standardized measure at the beginning of the period | $ | 270,357 |
| | $ | 198,916 |
| | $ | 135,921 |
| $ | 231,148 |
| | $ | 270,357 |
| | $ | 198,916 |
|
| Changes | | | | | | |
| Sales and transfers, net of production costs | (84,044 | ) | | (107,297 | ) | | (72,171 | ) | (78,661 | ) | | (84,044 | ) | | (107,297 | ) |
| Net change in sales and transfer prices, net of production costs | 47,261 |
| | 125,518 |
| | 126,571 |
| (46,088 | ) | | 47,261 |
| | 125,518 |
|
| Net change due to purchases and sales of in place reserves | (35,665 | ) | | 1,275 |
| | 621 |
| (145,711 | ) | | (35,665 | ) | | 1,275 |
|
| Extensions, discoveries, and improved recovery, net of future production and development costs incurred | 53,446 |
| | 22,598 |
| | 23,739 |
| 212,431 |
| | 53,446 |
| | 22,598 |
|
| Changes in future development cost | 39,815 |
| | (83,110 | ) | | (68,960 | ) | 153,983 |
| | 39,815 |
| | (83,110 | ) |
| Revisions of quantity estimates | (77,322 | ) | | (949 | ) | | 23,295 |
| (68,958 | ) | | (77,322 | ) | | (949 | ) |
| Accretion of discount | 30,989 |
| | 68,384 |
| | 10,597 |
| 25,010 |
| | 30,989 |
| | 68,384 |
|
| Net change in income taxes | 13,969 |
| | (32,918 | ) | | (5,170 | ) | 1,751 |
| | 13,969 |
| | (32,918 | ) |
| Changes in production rates, timing and other | (27,658 | ) | | 77,940 |
| | 24,473 |
| (959 | ) | | (27,658 | ) | | 77,940 |
|
| Aggregate change | (39,209 | ) | | 71,441 |
| | 62,995 |
| 52,798 |
| | (39,209 | ) | | 71,441 |
|
| Standardized measure at the end of period | $ | 231,148 |
| | $ | 270,357 |
| | $ | 198,916 |
| $ | 283,946 |
| | $ | 231,148 |
| | $ | 270,357 |
|
NOTE1513 – Other
Commitments and Contingencies: The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company.
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 are not expected to 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 policespolicies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities.
Operating Leases:Global Settlement with Joint Interest Partner: In FebruaryDuring 2011, the Company and a joint interest partner entered into a settlement agreement related to various disputes. All matters were settled and as result of the settlement agreement the Company received an interest in other specialized deep water property and equipment. The Company recognized a gain of $5,041as a result of the settlement and classified the property and equipment received as held for sale assets, included within other property and equipment since the Company had no use for this type of equipment in its operations. Since the settlement with its joint interest partner, the Company has sold a portion of these assets and has continued to actively market the remaining assets throughout 2012 we contracted a drilling rig for a termand 2013. During 2012, after selling assets valued at $527 during the year, the Company determined that certain equipment components were not usable without additional rework and thus recorded an impairment charge to its Statement of Operations of two$1,177 years to support our horizontal drilling program in the Permian basin. The drilling rig was delivered in April 2012, and lease costs recorded during 2012 was $6,609. Lease payments will approximate $9,235 in 2013 and $2,277 in 2014. The agreement includes early termination provisions that would reduce the minimum rentals under the agreement, assuming the lessor is unable to re-charter the rig and staffing personnel to another lessee, to $5,784 in 2013 and $1,350 in 2014. Should the lessor be able to re-charter the rig, these minimum rentals would be further reduced by the re-chartered lease payments.
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| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except share,well, acreage, per-share and per-hedgeper-derivative instrument data) | |
2012. During 2013, after selling assets value at $114 during the year, the Company has made a decision to abandon the equipment. As such the Company recorded an impairment charge of $1,707 to its Statement of Operations, representing the remaining value of this equipment.
Operating Leases: In April 2012, the Company took delivery of a drilling rig (the “Cactus 1 Rig”) for a term of two years, which it subsequently renewed on March 6, 2014 for an additional two year term ending April 2016. On August 1, 2013, the Company contracted a second horizontal drilling rig (the “Patterson Rig”) for a one-year term, though the Company provided notice on February 17, 2014 that it will cancel its Patterson rig contract on or about March 17, 2014. Under the early termination provisions of the agreement, estimated termination payments for this rig will be approximately $2,055 in 2014. Should the lessor be able to re-charter the rig, the termination payments would be reduced. To replace the Patterson Rig, the Company contracted a replacement rig (the “Cactus 2 Rig”) for a term of two years, which is scheduled to commence operations on April 1, 2014. Similar to the Patterson Rig, the Cactus 1 and 2 Rig lease agreements also include early termination provisions that would reduce the minimum rentals under the agreement, assuming the lessor is unable to re-charter the rig and staffing personnel to another lessee. Lease costs recorded during 2013 were $12,860. Lease payments as of December 31, 2013 will approximate $13,954, $9,308 and $2,295 in 2014, 2015 and 2016, respectively. Including the additional lease commitments executed subsequent to December 31, 2013, the Company’s drilling rig lease commitments as of March 10, 2014 are $19,732, $18,250 and $4,500 in 2014, 2015, and 2016, respectively.
Property Acquisitions and Dispositions
Acquisitions
During the second quarter of 2013, the Company acquired approximately 2,468 gross (2,186 net) acres in Reagan and Upton Counties, Texas, which is located in the southern portion of the Midland Basin and which is prospective for both horizontal and vertical drilling. The acquisition also included seven gross vertical wells and 1,301 barrels of oil equivalent proved reserves. The purchase price of $11,000 was funded using a portion of the proceeds from the preferred stock offering (discussed in Note 9).
During the first quarter of 2012, the Company acquired approximately 16,233 gross (14,653 net) acres in Borden County, which is located in the northern Midland basin. The northern Midland basin has had limited drilling activity compared with the southern Midland basin (where our current production is located), increasing the economic risk related to these drilling activities. The purchase price of $14,538 was funded from existing cash balances. During the third quarter of 2012, we acquired an additional 8,095 gross acres (6.964 net) in this area for a total consideration of $4,835.
During the second quarter of 2012, the Company signed a purchase and sale agreement to acquire 2,319 gross (1.762 net) acres in southern Reagan County, Texas for a total purchase price of $12,012, which was financed with a draw on the Credit Facility. The transaction had an effective date of May 1, 2012 and closed on July 5, 2012.
Dispositions
During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field (Mississippi Canyon blocks 582 and 538), our 10.0% membership interest in Medusa Spar LLC, and substantially all of our remaining Gulf of Mexico shelf properties. The Company sold its interest in Medusa to W&T, an unrelated third-party, for a total net cash consideration of approximately $88,000 after customary purchase price adjustments. Also during the fourth quarter of 2013, the Company closed on the sale of its 69% interest in the Swan Lake field for $2,000. This was the Company’s only field in the Haynesville shale. Consistent with the Company’s accounting policy discussed in Note 2, the proceeds from these sales were accounted for as a reduction to capitalized costs as the sale did not significantly alter the relationship between capitalized costs and proved reserves.
Effective December 28, 2012, the Company closed on the sale of its 11.25% working interest in the Habanero field (Garden Banks Block 341). The Company sold its interest in Habanero to Shell Offshore Inc., a subsidiary of Royal Dutch Shell Plc, for an estimated net cash consideration of $39,410 after customary purchase price adjustments. As noted above, the proceeds from this sale were accounted for as a reduction to capitalized costs as the sale did not significantly alter the relationship between capitalized costs and proved reserves.
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| | |
| Callon Petroleum Company | Notes to the Consolidated Financial Statements (All amounts in thousands, except well, acreage, per-share and per-derivative instrument data) | |
NOTE 1614 – Summarized Quarterly Financial Information (unaudited)(Unaudited)
|
| | | | | | | | | | | | | | | | |
| 2012 | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| Total revenues | | $ | 29,294 |
| | $ | 25,360 |
| | $ | 27,402 |
| | $ | 28,677 |
|
| Income from operations | | 2,716 |
| | 2,759 |
| | 2,563 |
| | 2,652 |
|
| Net income (loss) | | 488 |
| | 3,799 |
| | (1,105 | ) | | (435 | ) |
| Net income (loss) per common share - basic | | 0.01 |
| | 0.10 |
| | (0.03 | ) | | (0.01 | ) |
| Net income (loss) per common share - diluted | | 0.01 |
| | 0.09 |
| | (0.03 | ) | | (0.01 | ) |
| | | | | | | | | |
| 2011 | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| Total revenues | | $ | 25,449 |
| | $ | 36,834 |
| | $ | 33,550 |
| | $ | 31,811 |
|
| Income from operations | | 5,789 |
| | 14,201 |
| | 10,524 |
| | 9,108 |
|
| Net income (loss) | | 4,164 |
| | 19,877 |
| | 8,406 |
| | 73,949 |
|
| Net income (loss) per common share - basic | | 0.12 |
| | 0.51 |
| | 0.21 |
| | 1.88 |
|
| Net income (loss) per common share - diluted | | 0.12 |
| | 0.50 |
| | 0.21 |
| | 1.85 |
|
The amounts reported in the table for 2011 have been amended to adjust for the matter discussed in Note 1. |
| | | | | | | | | | | | | | | | |
| 2013 | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| Total revenues | | $ | 22,541 |
| | $ | 22,760 |
| | $ | 30,797 |
| | $ | 26,471 |
|
| Income from operations | | 898 |
| | 957 |
| | 6,345 |
| | 2,464 |
|
| Net income (loss) | | (800 | ) | | 758 |
| | 1,082 |
| | 3,264 |
|
| Income (loss) available to common shares | | (800 | ) | | 78 |
| | (892 | ) | | 1,291 |
|
| Income (loss) per common share - basic | | $ | (0.02 | ) | | $ | 0.00 |
| | $ | (0.02 | ) | | $ | 0.03 |
|
| Income (loss) per common share - diluted | | $ | (0.02 | ) | | $ | 0.00 |
| | $ | (0.02 | ) | | $ | 0.03 |
|
| | | | | | | | | |
| 2012 | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| Total revenues | | $ | 29,294 |
| | $ | 25,360 |
| | $ | 27,402 |
| | $ | 28,677 |
|
| Income from operations | | 2,716 |
| | 2,759 |
| | 2,563 |
| | 2,652 |
|
| Income (loss) available to common shares | | 488 |
| | 3,799 |
| | (1,105 | ) | | (435 | ) |
| Income (loss) per common share - basic | | $ | 0.01 |
| | $ | 0.10 |
| | $ | (0.03 | ) | | $ | (0.01 | ) |
| Income (loss) per common share - diluted | | $ | 0.01 |
| | $ | 0.09 |
| | $ | (0.03 | ) | | $ | (0.01 | ) |
ITEM 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
There have been no disagreements with the independent auditors on any matters of accounting principles or practices, financial statement disclosure, or auditing scope or procedures.
ITEM 9A. Controls and Procedures
Disclosure Controls and Procedures.Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer'sissuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. The Company'sCompany’s principal executive and principal financial officers have concluded that the Company'sCompany’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were effective as of December 31, 20122013.
Management’s Report on Internal Control over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 20122013 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission.Commission (1992 framework)(the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 20122013.
Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company'sCompany’s independent registered public accounting firm has issued an attestation report regarding its assessment of the Company'sCompany’s internal control over financial reporting as of December 31, 20122013, which follows Part II, Item 9B of this filing. Additionally, the financial statements for each of the years covered in this Annual Report on Form 10-K have been audited by an independent registered public accounting firm, Ernst & Young LLP whose report is presented immediately preceding the Company'sCompany’s financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.
Changes in Internal Control over Financial Reporting. There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.
ITEM 9A (T). Controls and Procedures
See Item 9A.
ITEM 9B. Other Information
Submissions of Matters to a Vote of the Security Holders
None.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Callon Petroleum Company
We have audited Callon Petroleum Company'sCompany’s internal control over financial reporting as of December 31, 20122013 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the(1992 framework)(the COSO criteria). Callon Petroleum Company'sCompany’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management'sManagement’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company'sCompany’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company'scompany’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company'scompany’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company'scompany’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Callon Petroleum Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012,2013, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Callon Petroleum Company as of December 31, 20122013 and 2011,2012, and the related statements of operations, comprehensive income, cash flow, and changes in stockholders'stockholders’ equity (deficit) for each of the three years in the period ended December 31, 2012,2013, and our report dated March 14, 201312, 2014 expressed an unqualified opinion thereon.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 14, 201312, 2014
PART III.
ITEM 10. Directors, Executive Officers and Corporate Governance
For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 16, 201315, 2014 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
The Company has adopted a code of ethics that applies to the Company’s chief executive officer, chief financial officer and chief accounting officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com, and is available free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at 200 North Canal Street,mailing address Post Office Box 1287, Natchez, Mississippi 39120.39121.
ITEM 11. Executive Compensation
For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 16, 201315, 2014 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 16, 201315, 2014 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
ITEM 13. Certain Relationships and Related Transactions and Director Independence
For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 16, 201315, 2014 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
ITEM 14. Principal Accountant Fees and Services
For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 16, 201315, 2014 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
PART IV.
ITEM 15. Exhibits
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| Exhibit | | Description |
| 1 | | | | | | The following is an index to the financial statements and financial statement schedules that are filed as partin Part II, Item 8 of this report on Form 10-K on pages 51 through 80. 10-K. |
| | | | | | | Report of Independent Registered Public Accounting Firm |
| | | | | | | Consolidated Balance Sheets as of December 31, 20122013 and 20112012 |
| | | | | | | Consolidated Statements of Operations for each of the three years in the period ended December 31, 20122013 |
| | | | | | | Consolidated Statements of Stockholders'Stockholders’ Equity (Deficit) for each of the three years in the Period Ended December 31, 20122013 |
| | | | | | | Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 20122013 |
| | | | | | | Notes to Consolidated Financial Statements |
| 2 | | | | | | Schedules other than those listed above are omitted because they are not required, not applicable or the required information is included in the financial statements or notes thereto. |
| 3 | | | | Exhibits | | |
| | | 2 | | | | Plan of acquisition, reorganization, arrangement, liquidation or succession* |
| | | 3 | | | | Articles of Incorporation and Bylaws |
| | | | | 3.1 | | Certificate of Incorporation of the Company, as amended (incorporated by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039) |
| | | | | 3.2 | | Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company'sCompany’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) |
| | | | | 3.3 | | Certificate of Amendment to Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039) |
| | | | | 3.4 | | Certificate of Amendment to the Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.4 of the Company'sCompany’s Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-14039) |
| | | 4 | | | | Instruments defining the rights of security holders, including indentures |
| | | | | 4.1 | | Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company'sCompany’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) |
| | | | | 4.2 | | Rights Agreement between Callon Petroleum Company and American Stock Transfer & Trust Company, Rights Agent, dated March 30, 2000 (incorporated by reference from Exhibit 99.1 of the Company’s Registration Statement on Form 8-A, filed April 6, 2000, File No. 001-14039) |
| | | | | 4.3 | | Indenture for the Company’s 13.00% Senior Notes due 2016, dated November 24, 2009, between Callon Petroleum Company, the subsidiary guarantors described therein, Regions Bank and American Stock Transfer & Trust Company (incorporated by reference to Exhibit T3C to the Company’s Form T3, filed November 19, 2009, File No. 022-28916) |
| | | | | 4.4 | | Certificate of Designations of 10% Cumulative Preferred Stock (incorporated by reference to Exhibit 3.5 of the Company’s Form 8-A filed May 23, 2013) |
| | | | 4.5 | | Certificate for the Company’s 10% Cumulative Preferred Stock (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-A filed May 23, 2013 |
| | | | 4.6 | | Amendment to the Certificate of Incorporation increasing the number of authorized shares of common stock [Filed herewith] |
| | 9 | | | | Voting trust agreement |
| | | | | | | None |
| | | 10 | | | | Material contracts |
| | | | | 10.1 | | Callon Petroleum Company 1994 Stock Incentive Plan (incorporated by reference from Exhibit 10.5 of the Company'sCompany’s Registration Statement on Form 8-B, filed October 3, 1994) |
| | | | | 10.2 | | Callon Petroleum Company 1996 Stock Incentive Plan as amended on May 9, 2000 (incorporated by reference from Appendix I of the Company’s Definitive Proxy Statement on Schedule 14A, filed March 28, 2000, File No. 001-14039) |
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| | | | | 10.3 | | Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.13 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-14039) |
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| | | | | 10.4 | | Medusa Spar Agreement dated as of August 8, 2003, among Callon Petroleum Operating Company, Murphy Exploration & Production Company-USA and Oceaneering International, Inc. (incorporated by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039) |
| | | | 10.5 | | Amendment No. 3 to the Callon Petroleum Company 1996 Stock Incentive Plan (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) |
| | | | | 10.610.5 | | Amendment No. 1 to the Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference from Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) |
| | | | | 10.710.6 | | Callon Petroleum Company Amended and Restated 2006 Stock Incentive Plan (incorporated by reference from Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) |
| | | | | 10.810.7 | | Callon Petroleum Company 2009 Stock Incentive Plan effective as of April 30, 2009 (incorporated by reference from Exhibit A to the Company’s Definitive Proxy Statement on Schedule 14A, filed March 30, 2009, File No. 001-14039) |
| | | | | 10.910.8 | | Amendment to the Callon Petroleum Company 1996 Stock Incentive Plan effective as of August 7, 2009 (incorporated by reference from Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2009, File No. 001-14039) |
| | | | | 10.10 |
10.9 | | Callon Petroleum Company 2010 Phantom Share Plan, adopted May 4, 2010 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on May 7, 2010) |
| | | | | 10.11 |
10.10 | | Form of Callon Petroleum Company Phantom Share Award Agreement, adopted May 4, 2010 (incorporated by reference to Exhibit 10.2 of the Company’s current Report on Form 8-K filed on May 7 , 2010) |
| | | | | 10.12 |
10.11 | | Deferred Compensation Plan for Outside Directors; Callon Petroleum Company (effective as of January 1, 2011) (incorporated by reference to Exhibit 10.17 of the Company'sCompany’s Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-14039) |
| | | | | 10.13 |
10.12 | | Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between Fred L. Callon and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company'sCompany’s Current Report on Form 8-K filed on March 18, 2011)
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| | | | | 10.14 |
10.13 | | Form of Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between Callon Petroleum Company and its executive officers (incorporated by reference to Exhibit 10.2 of the Company'sCompany’s Current Report on Form 8-K filed on March 18, 2011)
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| | | | | 10.15 |
10.14 | | Severance Compensation Agreement, dated as of September 21, 2011, by and between Gary A. Newberry and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company'sCompany’s Current Report on Form 8-K filed on September 21, 2011)
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| | | | | 10.16 |
| | Severance Compensation Agreement, dated as of September 21, 2011, by and between Vince Borrello and Callon Petroleum Company
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| | | | 10.17 |
10.15 | | Fourth Amended and Restated Credit Agreement dated as of June 20, 2012, by and among the Company, the "Lenders"“Lenders” described therein, and Regions Bank as the sole arranger and administrative agent (incorporated by reference from Exhibit 10.1 on Form 8-K, filed June 25, 2012, File No. 001-14039) |
| | | | | 10.18 |
10.16 | | Fourth Amended and Restated Revolving Promissory Note dated June 20, 2012 (incorporated by reference from Exhibit 10.1 on Form 8-K, filed June 25, 2012, File No. 001-14039) |
| | | | | 10.19 |
10.17 | | Fourth Amended and Restated Guaranty Agreement dated June 20, 2012 (incorporated by reference from Exhibit 10.1 on Form 8-K, filed June 25, 2012, File No. 001-14039) |
| | | | | 10.20 |
10.18 | | Master Assignment, Agreement and Amendment No. 1 to the Fourth Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 on Form 8-K, filed October 16, 2012, File No. 001-14039) |
| | | | | 10.21 |
10.19 | | Purchase and Sale Agreement by and between Shell Offshore Inc. and Callon Petroleum Operating Company dated as of November 27, 2012. |
| | | | | 10.22 |
| | Resignation/Retirement Agreement and Release between Stephen Woodcock and Callon Petroleum Company dated September 7, 2012 (incorporated by reference from Exhibit 10.1 on Form 8-K, filed September 12, 2012, File No. 14039) |
| | | | 10.23 |
10.20 | | Callon Petroleum Company 2011 Omnibus Incentive Plan (incorporated by reference from Exhibit A of the Company'sCompany’s Definitive Proxy Statement on Schedule 14A filed March 21, 2011, File No. 14039) |
| | | 11 | | 10.21 | | Purchase and Sale Agreement by and between W&T Offshore, Inc. and Callon Petroleum Company dated as of December 5, 2013 |
| | | | Statement re computation10.22 | | Underwriting Agreement relating to the Company’s 10% Cumulative Preferred Stock (incorporated by reference to Exhibit 1.1 of per share earnings*the Company’s Form 8-K filed on May 28, 2013). |
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| | | | 10.23 | | Agreement, dated March 9, 2014, among the Company and Lone Star Value Investors, L.P., Lone Star Value Co-Invest I, L.P., Lone Star Value Investors GP, LLC, Lone Star Value Management, LLC, Jeffery E. Eberwein and Matthew R. Bob (incorporated by reference from Exhibit 10.1 on Form 8-K, filed on March 10, 2014, File No. 001-14039)
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| | 11 | | | | Statement re computation of per share earnings* |
| | | 12 | | | | Statements re computation of ratios* |
| | | 13 | | | | Annual Report to security holders, Form 10-Q or quarterly reports* |
| | | 14 | | | | Code of Ethics |
| | | | | 14.1 | | Code of Ethics for Chief Executive Officers and Senior Financial Officers (incorporated by reference to Exhibit 14.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039) |
| | | 16 | | | | Letter re change in certifying accountant* |
| | | 18 | | | | Letter re change in accounting principles* |
| | | 21 | | | | Subsidiaries of the Company |
| | | | | 21.1 | | Subsidiaries of the Company |
| | | 22 | | | | Published report regarding matters submitted to vote of security holders* |
| | | 23 | | | | Consents of experts and counsel |
| | | | | 23.1 | | Consent of Ernst & Young LLP |
| | | | | 23.2 | | Consent of Huddleston & Co., Inc. |
| | | 24 | | | | Power of attorney* |
| | | 31 | | | | Rule 13a-14(a) Certifications |
| | | | | 31.1 | | Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) |
| | | | | 31.2 | | Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) |
| | | 32 | | | | Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b) |
| | | 99 | | | | Additional Exhibits |
| | | | | 99.1 | | Reserve Report Summary prepared by Huddleston and Co. as of December 31, 2012.2013 |
| | | 101 | | | | Interactive Data Files ** |
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| | | * | | | | Not applicable to this filing |
| | | ** | | | | Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability.
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SIGNATURES
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| Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. |
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| Date: | | March 14, 201312, 2014 | | /s/ Fred L. Callon |
| | | | | Fred L. Callon (principal executive officer, director) |
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| Date: | | March 14, 201312, 2014 | | /s/ B. F. Weatherly |
| | | | | B. F. Weatherly (principal financial officer, director) |
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| Date: | | March 14, 201312, 2014 | | /s/ Rodger W. Smith |
| | | | | Rodger W. Smith (principal accounting officer) |
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| Date: | | March 14, 201312, 2014 | | /s/ L. Richard Flury |
| | | | | L. Richard Flury (director) |
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| Date: | | March 14, 201312, 2014 | | /s/ John C. Wallace |
| | | | | John C. Wallace (director) |
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| Date: | | March 14, 201312, 2014 | | /s/ Anthony J. Nocchiero |
| | | | | Anthony J. Nocchiero (director) |
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| Date: | | March 14, 201312, 2014 | | /s/ Larry D. McVay |
| | | | | Larry McVay (director) |
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| Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. |
| Date: | | March 14, 201312, 2014 | | /s/ B. F. Weatherly |
| | | | | B. F. Weatherly, Executive Vice President and |
| | | | | Chief Financial Officer (Principal Financial Officer) |
