SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ý☒ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year endedThe Fiscal Year Ended December 31, 2013
OR
¨☐TRANSITION REPORT UNDER SECTION 13 OR 15(D)15(d) OF SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission File Number 001-14039
Callon Petroleum Company
(Exact Name of Registrant as Specified in Its Charter)
Delaware (State or Other Jurisdiction of Incorporation or Organization) | 64-0844345 (IRS Employer Identification No.) | |
200 North Canal Street Natchez, Mississippi (Address of Principal Executive Offices) | 39120 (Zip Code) | |
601-442-1601
(Registrant’s Telephone Number, Including Area Code): 601-442-1601
Securities registered pursuant to Section 12(b) of the Act: | |||
Title of Each Class | Name of Each Exchange on Which Registered | ||
Common Stock, $.01 par value | New York Stock Exchange | ||
10.0% Series A Cumulative Preferred Stock | New York Stock Exchange | ||
Securities registered pursuant to section 12 (g) of the Act: None | |||
Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
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
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
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):
Large accelerated filer | ☐ | Accelerated filer | ☒ | |
Non-accelerated filer | ☐ | (Do not check if smaller reporting company) | Smaller reporting company | ☐ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 20132014 was approximately $129.6 million.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after
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2
All statements, other than statements of 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-Q10-K identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.
You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:
· | the timing and extent of changes in market conditions and prices for oil, natural gas and NGLs (including regional basis differentials), |
· | our ability to transport our production to the most favorable markets or at all, |
· | the timing and extent of our success in discovering, developing, producing and estimating reserves, |
· | our ability to fund our planned capital investments, |
· | the impact of government regulation, including regulation of endangered species, any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over-the-counter derivatives, |
· | the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services, |
· | our future property acquisition or divestiture activities, |
· | the effects of weather, |
· | increased competition, |
· | the financial impact of accounting regulations and critical accounting policies, |
· | the comparative cost of alternative fuels, |
· | conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed, |
· | credit risk relating to the risk of loss as a result of non-performance by our counterparties, and |
· | any other factors listed in the reports we have filed and may file with the SEC. |
We caution you that the forward-looking statements contained in this Form 10-K are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K for the year ended
December 31,Should one or more of the risks or uncertainties described above or elsewhere in thisour 2014 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.
All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
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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. |
· | Bcf: Billion cubic feet of natural gas. |
· | BOE: barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas. |
· | BBtu: billion Btu. |
· | BOE/d: BOE per day. |
· | BLM: Bureau of Land Management. |
· | Btu: a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. |
· | DOI: Department of Interior. |
· | EPA: Environmental Protection Agency. |
· | FASB: Financial Accounting Standards Board. |
· | GAAP: Generally Accepted Accounting Principles in the United States. |
· | GHG: greenhouse gases. |
· | LIBOR: London Interbank Offered Rate. |
· | LOE: lease operating expense, including workover expense. |
· | MBbls: thousand barrels of oil. |
· | MBOE: thousand BOE. |
· | MBOE/d: Mboe per day. |
· | Mcf: thousand cubic feet of natural gas. |
· | MMBbls: million barrels of oil. |
· | MMBOE: million BOE. |
· | MMBtu: million Btu. |
· | MMcf: million cubic feet of natural gas. |
· | MMcf/d: MMcf per day. |
· | NGL or NGLs: natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. |
· | NYMEX: New York Mercantile Exchange. |
· | Oil: includes crude oil and condensate. |
· | PDPs: proved developed producing reserves. |
· | PDNPs: proved developed non-producing reserves. |
· | PUDs: proved undeveloped reserves. |
· | RSU: restricted stock units. |
· | SEC: United States Securities and Exchange Commission. |
With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.
4
Overview
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
In 2013, we completed our onshore strategic repositioning that began in 2009, shifting our operations from the lawsoffshore waters in the Gulf of the state of Delaware in 1994 and succeededMexico to the business ofonshore Permian Basin in West Texas. Our asset base is concentrated exclusively in the Midland Basin, a publicly traded limited partnership, a joint venture with a consortium of European investorssub-basin located within the broader Permian Basin, characterized by high drilling success rates, high oil content, multiple vertical and an independent energy company partially owned by a member of current management.horizontal productive intervals, and extensive production history. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.
Our net daily production for calendar year 2014 was 5,648 BOE/d (approximately 82% oil), representing an onshore operator with an asset base concentrated exclusively in the Midland Basin, a sub-basin contained in the broader Permian Basin.
As of
December 31,Our Business Strategy
Our goal is to enhance stockholder value through the execution of the following strategy:
Drive production and maximize resource recovery and reserve growth through horizontal development of our resource base. We believe our horizontal development efforts provide improved returns relative to vertical development of our resource base. Our initial drilling efforts in the Permian Basin targeted thevertical development of multiple zones with vertical wells as part of the “Wolfberry” play. As part of this drilling program, we amassedprograms allowed us to amass a database related to the subsurface geology and rock characteristics over the last several years. This information, combined with our review of industry activity and best practices, provided the foundation for Callonus to initiate the horizontal development of our resource base in 2012. Importantly,2012 and further increase horizontal activity in recent quarters. As of December 31, 2014, we believehad 49 gross producing horizontal developmentwells, all 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.which we operate. During the fourth quarter of 2013,2014, approximately 44%70% of our total Permian production was sourced from horizontal wells. We expect to grow the contribution of horizontal production volumes, both from our existing properties and from properties acquired in recent acquisitions, as we continue to increase with the recent expansion of ourexecute a resource development program almost exclusively focused on horizontal development efforts to four fields as part of our current two-rig drilling program.development.
Expand our drilling portfolio through evaluation of existing acreage. Our horizontal development drilling efforts to date have been primarily focused on the Upper and Lower Wolfcamp B shales, establishing production from both zones in the Southern Midland Basin.zones. We have been focused on these development zones to reduce drilling risk as we continue to grow our asset base in the Permian Basin.Basin, though we have continued to expand our development focus on a measured basis. Most recently, we drilled three Lower Spraberry wells in the Southern and Central Midland Basin in the second half of 2014, complementing three Wolfcamp A wells placed on production in the Southern Midland Basin since the third quarter of 2013. We believe additionalincremental opportunities exist to selectively target various other prospective zones across various positions of our acreage, including the Jo-Mill, LowerClearfork, Jo Mill, Middle 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,(in order of relative depth). In addition, we will continue to monitor the efficiency of our horizontal wells related to reservoir drainage over time, and will pursue downspacing initiatives within target zones if we believe overall returns canwould 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.
Pursue selective acquisitions in the Permian Basin. We have demonstratedDuring 2014, we continued to demonstrate our ability to acquire and trade acreage in the Midland Basin. Specifically,Most significantly, we addedacquired 6,230 gross (3,862 net) acres located in Midland and Andrews Counties, which are in close proximity to our Taylor Draw field in 2012existing Carpe Diem and Garrison Draw Field in 2013Pecan Acres fields, for a total of $23 million, includingapproximately $210 million. Due to its close proximity to our existing fields, we believe this acquired production and proved reserves. These two fields are now part ofacreage can be efficiently integrated into our coreongoing horizontal development plan.activity. The acquisition added 194 gross (121.6 net) potential horizontal drilling locations targeting the currently producing Wolcamp B, Lower Spraberry and Middle Spraberry zones, and additional potential horizontal drilling locations targeting four other prospective zones that are producing in offsetting fields. We also expanded our asset base in existing core development
5
fields by acquiring 1,527 net acres for approximately $8.2 million through a “bolt-on” strategy whereby we identify and pursue smaller blocks of offsetting acreage that are potentially inefficient for the current owner to develop, but have builtvalue to Callon based on theseits location relative to our acreage. These smaller scale acquisitions with recent acquisitionsgenerally provide acreage at costs significantly below the value assigned to larger blocks of acreage nearacreage. While remaining mindful about our existing East Bloxom (see Recent Developments below), as well as completing an acreage trade at Garrison Draw which added contiguous acreage for effective long lateral horizontal development. Weliquidity, we will continue to pursue leasehold acquisitions in the Permian Basin, and primarily in the Midland Basin, that have horizontal resource potential that can be further augmented by bolt-on acreage“bolt-on acreage” acquisitions and acreage trades over time.
CapitalizeMaintain financial liquidity and capacity to capitalize on opportunities to further reduce cost of capital.growth opportunities. Following the disposition ofWe believe that our offshore properties, we haveasset base provides the opportunity to recapitalize the Company withdeploy a lower costsignificant amount of capital commensuratefor horizontal development in the coming years. We have focused on positioning ourselves to supplement our cash flow from operations with an improved credit risk profile as a purely onshore operator. As part of an ongoing effort to reduce our cost of capital,debt capital. In conjunction with our acquisition completed in the fourth quarter of 2014, we have redeemed nearly $90raised approximately $430 million in gross proceeds through a combination of common equity and long-term debt securities to support the acquisition and our 13% Senior Notes due 2016 (the “Senior Notes”) since 2011 and recently called forongoing development efforts in 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).Midland Basin.
Our Strengths
Established resource base and acreage position in the Permian Basin. Our production is exclusively from the Permian Basin in West Texas, an area that has supported production since the 1940s. The basin has well-established infrastructure from historical operations, and we believe the basinBasin also benefits from a relatively stable regulatory environment that has been established over time. We have assembled a position of approximately 13,60018,065 net surface acres in the Southern and Central Midland Basin that are prospective for multiple oil-bearing intervals that have been produced by us and other industry participants. As of December 31, 2013,2014, our estimated net proved reserves were comprised of approximately 80%78% oil and 20%22% 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.
Multi-year drilling inventory. Our current acreage position in the Permian Basin provides visible growth potential from a horizontal drilling inventory of almostapproximately 525 locations, or 20 years based onunder our current two-rig horizontal drilling program. Asprogram, based solely on four currently producing zones, which include the Lower Spraberry, the Wolfcamp A and the Upper and Lower Wolfcamp B. This drilling inventory increases to over 1,000 drilling locations, with the addition of December 31, 2013,drilling locations from other prospective zones, which include the Clearfork, Middle Spraberry, Jo Mill, Wolfcamp C and the Cline (or Wolfcamp D). Our identified well locations across our Southern and Central Midland Basin acreage are based upon the results of horizontal wells drilled by us and other offsetting operators, and our analysis of core data and historical vertical well performance, we have identified an inventory of approximately 540 potential horizontal well locations in multiple horizons across our Southern 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.performance.
Experienced team operating in the Permian Basin. We have assembled a management team experienced in acquisitions, exploration, development and production in the Midland Basin. Reflective of this experience, we have realized improvements in our drilling and capital efficiency since launching our horizontal drilling program in 2012. For example, our average drill time for a typical 7,800 foot lateral Wolfcamp shale well decreased2012 and drilling more than 50 horizontal wells with lengths varying from approximately 30 days at the start of our drilling program in 20125,000 feet to under 20daysas of February 2014.10,000 feet. We continue to evaluate our completion techniques, and downspacing initiatives that we believe have the potential to improve resource recovery and contribute to enhanced returns on capital. In addition, we regularly evaluate our operating results against those of other operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices.
High degree of operational control. We operate nearly all of our Permian Basin acreage providingand have limited continuous drilling requirements across our acreage. For example, only 10% of our planned development drilling activity in 2015 is required to satisfy acreage commitments, with decreasing obligations in future years. This acreage status, combined with our control as an operator across the majority of our properties, provides us the opportunity to modify our operational plans to respond to changes in operational and commodity price environments. This operating control also allows usIn addition, we have the ability to modifychange our drilling and completion techniques, and change drilling schedulesschedule 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 (“HSE”) department dedicated to our operations in the Permian Basin. This group is responsible for monitoring the activitydeveloping and implementing work processes to mitigate safety compliance ofand environmental risks associated with our work activities. With emphasis on planning, training and communication, and empowering both our employees as well asand third party service providers with Stop Work Authority, we continue to improve operational performance. Callon has enhanced Management of Change, routine inspections and consultants.compliance action tracking methods with the implementation of a HSE management system software program. This department also coordinates closely with our operational team to ensure effective communication with appropriate regulatory bodies as well as landowners. We believe that our proactive efforts in this area have made a positive impact on our operations and culture. As an example, we were recently awarded the Midland Bruno Hanson/Midland College Award for Environmental Excellence which is given to companies that demonstrate strong environmental stewardship in the Permian Basin.
6
Exploration and Development Activities
Our 20132014 total capital expenditures, on a cash basis and including acquisitions, were
Southern Midland Basin | $ | 160.3 | |
Central Midland Basin | 56.9 | ||
Northern Midland Basin | 0.5 | ||
Total operational expenditures | 217.7 | ||
Capitalized general and administrative costs allocated directly to exploration and development projects | 12.5 | ||
Capitalized interest | 2.4 | ||
Total capitalized general and administrative and interest costs | 14.9 | ||
Total operational expenditures inclusive of capitalized general and administrative and interest costs | 232.6 | ||
Acquisitions | 222.9 | ||
Total capital expenditures | $ | 455.5 |
| Southern Midland Basin | $ | 111 | ||
| Central Midland Basin | 20 | |||
| Northern Midland Basin | 7 | |||
| Other | 7 | |||
| Total capital expenditures | 145 | |||
| Capitalized general and administrative costs allocated directly to exploration and development projects | 11 | |||
| Capitalized interest | 4 | |||
| Total capitalized expenses | 15 | |||
| Total operational expenditures | 160 | |||
| Acquisitions | 11 | |||
| Total capital expenditures, including acquisitions | $ | 171 | ||
In late 2014, 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.six fields. We expect our 20142015 horizontal drilling program will be primarily focused on development of established Upper and Lower Wolfcamp zones in the Southern and Central Midland Basin. We also expect to drill twofive wells in the Southern and Central Midland Basin to evaluate the Wolfcamp A shale and a test oftargeting the Lower Spraberry shale formation in the Central Midland Basin. Planned vertical drilling activity is anticipated to be limited to five deep Wolfberry wells in the Pecan Acres field and one well intargeting the Garrison Draw field. In addition, our plans include threeWolfcamp A shale formation.
Recent Developments
We are currently operating two horizontal drilling rigs, complemented by an additional vertical exploration wells inrig that is being used to drill the Northern Midland Basin, the timing and locationvertical section of which being subject to change as results are evaluated during the course of 2014.
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.
As of December 31, 2013,2014, our estimated net proved reserves totaled 14.932.8 MMBOE and included 11.925.7 MMBbls of oil and 17.842.5 Bcf, of natural gas with a pre-tax present value, discounted at 10%, of $301.1 million.$629.7 million. Pre-tax present value is a non-GAAP financial measure, which we reconcile to the GAAP measure of standardized measure of $283.9$579.5 million in note (d) to the table below. Oil constituted approximately 80%78% of our total estimated equivalent net proved reserves and approximately 80%77% of our total estimated equivalent proved developed reserves.
7
The following table sets forth certain information about our estimated net proved reserves prepared by our independent petroleum reserve engineers by major area and for all other properties combined at December 31, 2013: 2014:
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| Estimated Net Proved Reserves |
| Present | ||||||||
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| Natural Gas |
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| Value |
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| (b)(c)(d) |
Southern Midland Basin |
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| 16,973 |
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| 26,102 |
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| 21,323 |
| $ | 416,463 |
Central Midland Basin |
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| 8,736 |
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| 16,337 |
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| 11,459 |
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| 219,286 |
Northern Midland Basin |
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| 24 |
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| 109 |
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| 42 |
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| 803 |
Other |
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| — |
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| — |
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| — |
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| (6,872) |
Total |
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| 25,733 |
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| 42,548 |
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| 32,824 |
| $ | 629,680 |
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 BOE using a conversion ratio of six Mcf to one Bbl. This ratio, which is typical in the industry and represents the approximate energy equivalent of a Mcf to a Bbl, does not reflect to market price equivalence of Mcf of natural gas compared with a Bbl of oil or NGLs. On a market price equivalence basis, a barrel of oil or NGLs has a substantially higher price than six Mcf of natural gas. |
(b) | Represents the present value of future net cash flows before deduction of federal income taxes, discounted at 10%, attributable to estimated net proved reserves as of December 31, |
(c) | Includes a reduction for estimated plugging and abandonment costs that |
(d) | The Company uses the financial measure “Pre Tax Discounted Present Value” which is a non-GAAP financial measure. The Company believes that Pre Tax Discounted Present Value, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The total standardized measure calculated in accordance with the guidance issued by the FASB for disclosures about oil and gas producing activities for our proved reserves as of December 31, |
8
Permian Basin
As of
December 31,Southern Midland Basin
· | Counties (fields) |
o | Upton (East Bloxom and Opal) |
o | Reagan (Taylor Draw and Garrison Draw) |
o | Crockett (Block 5) |
· | 10,790 net acres as of December 31, 2014 |
· | 59 gross (54 net) vertical and 39 gross (36 net) horizontal producing wells as of December 31, 2014 |
· | Initiated horizontal development in 2012 |
· | 4th quarter |
The Southern Midland Basin is our largest operating area in terms of production. Following recently completed acquisitions in the first quarter of 2014, weWe currently have approximately 10,20010,790 net acres in this area. We commenced horizontal drilling efforts at our East Bloxom field in 2012 and have expanded our efforts to two additional fields in the Southern Midland Basin using pad development. Our horizontal wells are currently producing from three zones of the Wolfcamp shale (Upper Wolfcamp B, Lower Wolfcamp B and Wolfcamp A). We plan to continue focusing on these intervals acrossin 2015 and also place our entire positionfirst Lower Spraberry well on production in the Southern Midland Basin in 2014 and expect to test additional zones in future years.
Central Midland Basin
· | Counties (fields) |
o | Midland (Carpe Diem, Pecan Acres, Casselman and Bohannon) |
o | Ector (Kayleigh and Bohannon) |
o | Andrews (Bohannon) |
o | Martin (Casselman) |
· | 7,275 net acres as of December 31, 2014 |
· | 218 gross (144 net) vertical and 11 gross (8 net) horizontal producing wells as of December 31, 2014 |
· | Initiated horizontal development in 2013 |
· | 4th quarter |
The Central Midland Basin has historically been the focus of our high-graded vertical drilling program, targeting multiple zones down to the Woodford shale. We have recently shifted our focus to horizontal development of the Carpe Diem field. Our firstin this area with our initial Wolfcamp B wells were placed on production in the first quarter of 2014 and we plan to addin our Carpe Diem field. We have continued with program development of both the Wolfcamp B and Lower Spraberry zones in this field over the course of the year and are currently expanding our horizontal development to the Pecan Acres field. Importantly, we recently completed our last vertical well in the area and have no plans or obligations to drill any future vertical wells within our Permian Basin property base.
In addition to this organic drilling activity, in October 2014 we acquired 6,230 gross (3,862 net) acres located in Midland, Andrews and Martin Counties, which are in close proximity to our core development fields going forward. This area is prospective for multiple horizontal development zonesexisting Carpe Diem and Pecan Acres fields. Since the closing of the acquisition, we plan to target thehave placed two Wolfcamp B and one Lower Spraberry in 2014 as we delineate zones outside of the Wolfcamp B.
Northern Midland Basin
We acquired 21,617 net acres in Borden and Lynn Counties.Counties in 2012. We currently own approximately
9
For additional details regarding our Permian wells and related information, please see “Present Activities and Productive Wells” included below within this Item.
Other Property
We own a leasehold in approximately 65,00037,326 net acres located in various counties in Nevada. These leases are with the Bureau of Land Management and carry a primary termterms that expiresexpire in 2018.2018 and 2019. We are evaluating this acreage in conjunction with a third-party consultant and developing options for future activity. Callon does not have any drilling commitments related to this acreage during the primary term.
Estimates of volumes of proved reserves at year-end, net to our interest, are presented in MBbls for oil and in MMcf for natural gas, including NGLs, at a pressure base of 15.025 pounds per square inch. Total equivalent volumes are presented in BOE. For the BOE computation, 6,000 cubic feet of gas are the equivalent of one barrel of oil. The ratio of six Mcf of gas to one BOE is typically used in the oil and gas business and represents the approximate energy equivalent of a barrel of oil and ana Mcf of natural gas. The price of a barrel of oil is much higher than the price of six Mcf of natural gas, so the ratio of six Mcf to one BOE does not reflect the economic equivalent of a barrel of oil to six Mcf of gas.
The following table sets forth certain information about our estimated net proved reserves. All of our proved reserves are currently located in the continental United States and also included volumes in federal and state waters in the Gulf of Mexico at year-end 2011 and 2012.
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|
|
|
|
|
|
|
|
| For the Year Ended December 31, | ||||||
|
|
| 2014 (a) |
|
| 2013 (a) |
|
| 2012 (a) |
Proved developed |
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
| 14,006 |
|
| 5,960 |
|
| 4,955 |
Natural gas (MMcf) |
|
| 25,171 |
|
| 9,059 |
|
| 10,680 |
MBOE |
|
| 18,201 |
|
| 7,470 |
|
| 6,735 |
Proved undeveloped |
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
| 11,727 |
|
| 5,938 |
|
| 5,825 |
Natural gas (MMcf) |
|
| 17,377 |
|
| 8,692 |
|
| 9,073 |
MBOE |
|
| 14,623 |
|
| 7,387 |
|
| 7,337 |
Total proved |
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
| 25,733 |
|
| 11,898 |
|
| 10,780 |
Natural gas (MMcf) |
|
| 42,548 |
|
| 17,751 |
|
| 19,753 |
MBOE |
|
| 32,824 |
|
| 14,857 |
|
| 14,072 |
Financial Information |
|
|
|
|
|
|
|
|
|
Estimated pre-tax future net cash flows (b) |
| $ | 1,330,628 |
| $ | 680,627 |
| $ | 592,424 |
Pre-tax discounted present value (b) (c) |
| $ | 629,680 |
| $ | 301,144 |
| $ | 250,097 |
Standardized measure of discounted future net cash flows (b) (c) |
| $ | 579,542 |
| $ | 283,946 |
| $ | 231,148 |
| Years Ended December 31, | ||||||||||||
| 2013 | 2012 | 2011 | ||||||||||
| Proved developed: | ||||||||||||
| Oil (MBbls) | 5,960 | 4,955 | 5,069 | |||||||||
| Natural gas (MMcf) | 9,059 | 10,680 | 11,605 | |||||||||
| MBOE | 7,470 | 6,735 | 7,003 | |||||||||
| Proved undeveloped: | ||||||||||||
| Oil (MBbls) | 5,938 | 5,825 | 5,006 | |||||||||
| Natural gas (MMcf) | 8,692 | 9,073 | 23,513 | |||||||||
| MBOE | 7,387 | 7,337 | 8,925 | |||||||||
| Total proved: | ||||||||||||
| Oil (MBbls) | 11,898 | 10,780 | 10,075 | |||||||||
| Natural gas (MMcf) | 17,751 | 19,753 | 35,118 | |||||||||
| MBOE | 14,857 | 14,072 | 15,928 | |||||||||
| Financial Information: | ||||||||||||
| Estimated pre-tax future net cash flows (a) | $ | 680,627 | $ | 592,424 | $ | 568,798 | ||||||
| Pre-tax discounted present value (a) (b) | $ | 301,144 | $ | 250,097 | $ | 309,890 | ||||||
| Standardized measure of discounted future net cash flows (a) (b) | $ | 283,946 | $ | 231,148 | $ | 270,357 | ||||||
(a) | The Company’s estimated proved reserves as of December 31, 2014 were prepared by DeGolyer and MacNaughton and estimated proved reserves as of December 31, 2013 and 2012 were prepared by Huddleston & Co. |
(b) | Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2014 and 2013, |
(c) | The Company uses the financial measure 10 |
has been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. |
See
NoteThe Company’s estimated net proved reserves increased 6%121% to 14,85732.8 MBOE from 14,07214.9 MBOE at
Proved Undeveloped Reserves (PUDs)
Annually, the Company reviews its PUDs to ensure appropriate plans exist for development. PUD reserves are recorded only if the Company has plans to convert these reserves into PDPs within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our
The following table summarizes the Company’s recorded PUDs:PUDs (in MBOE):
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | ||||
|
| 2014 |
| 2013 |
| 2012 |
Permian Basin |
| 14,623 |
| 7,387 |
| 6,040 |
Medusa (a) |
| — |
| — |
| 1,297 |
Total |
| 14,623 |
| 7,387 |
| 7,337 |
| 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 |
Our PUDs increased
The Company plans to develop its Permian Basin PUDs as part of a multi-year drilling program. At December 31, 2013,2014, we had no reserves that remained undeveloepdundeveloped for five or more years, and all PUD drilling locations are currently scheduled to be drilled within three to five years of their initial recording.
Controls Over Reserve Estimates
Compliance as it relates to reporting the Company’s reserves is the responsibility of our Senior Vice President of Operations, who has over 35 years of industry experience including 2627 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”),DeGolyer and MacNaughton, a Texas registered engineering firm, as our independent petroleum and geological firm. The Company provided to HuddlestonDeGolyer and MacNaughton information about our oil and gas properties, including production profiles, prices and costs, and HuddlestonDeGolyer and MacNaughton prepared its own estimates of the reserves attributable to the Company’s properties. All of the information regarding 2014 reserves in this annual report is derived from Huddleston’sDeGolyer and MacNaughton’s report. Huddleston’sDeGolyer and MacNaughton’s reserve report letter is included as an Exhibit to this annual
11
report. The principal engineer at HuddlestonDeGolyer and MacNaughton who is responsible for preparingcertified the Company’s reserve estimates has over 3040 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.
All of the information regarding 2013 and 2012 reserves in this annual report is derived from reserve reports prepared by Huddleston & Co., Inc., a Texas engineering firm.
To further enhance the control environment over the reserve estimation process, our Strategic Planning Committee, a committee of the Board of Directors, includes a Strategic Planning Committee whose purpose, as stated in the Committee’s charter, includes assistingassists management and the Board with its oversight of the integrity of the determination of the Company’s oil and natural gas reserves and the work of Huddleston.our independent reserve engineer. The Committee’s charter also specifies that the Committee shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities:
· | Oversee the appointment, qualification, independence, compensation and retention of the independent petroleum and geological firm (the “Firm”) engaged by the Company (including resolution of material disagreements between management and the Firm regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Committee shall review any proposed changes in the appointment of the Firm, determine the reasons for such proposal, and whether there have been any disputes between the Firm and management. |
· | Review the Company’s significant reserves engineering principles and policies and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure. |
· | Review with management and the Firm the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii) reviewing key assumptions used or relied upon by the Firm; (iii) evaluating the quality of the reserve estimates prepared by both the Firm and the Company relative to the Company’s peers in the industry; and (iv) reviewing any material reserves adjustments and significant differences between the Company’s and Firm’s estimates. |
· | If the Committee deems it necessary, it shall meet in executive session with management and the Firm to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves. |
During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of total proved net oil and natural gas reserves.
12
Production Volumes, Average Sales Prices and Operating Costs
The following table sets forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, the Company’s sale of oil and natural gas for the periods indicated.indicated (dollars in thousands, except per unit data).
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | |||||||
|
| 2014 |
| 2013 |
| 2012 | |||
Production |
|
| |||||||
Oil (MBbl) |
|
| 1,692 |
|
| 911 |
|
| 977 |
Natural gas (MMcf) |
|
| 2,220 |
|
| 3,011 |
|
| 3,588 |
Total (MBoe) |
|
| 2,062 |
|
| 1,413 |
|
| 1,575 |
Revenues |
|
|
|
|
|
|
|
|
|
Oil sales |
| $ | 139,374 |
| $ | 88,960 |
| $ | 96,584 |
Natural gas sales |
|
| 12,488 |
|
| 13,609 |
|
| 14,149 |
Total |
| $ | 151,862 |
| $ | 102,569 |
| $ | 110,733 |
Operating costs |
|
|
|
|
|
|
|
|
|
Lease operating expense |
| $ | 22,372 |
| $ | 19,779 |
| $ | 23,330 |
Production taxes |
|
| 8,973 |
|
| 4,133 |
|
| 3,224 |
Total |
| $ | 31,345 |
| $ | 23,912 |
| $ | 26,554 |
Average realized sales price |
|
|
|
|
|
|
|
|
|
Oil (Bbl) (excluding impact of cash settled derivatives) |
| $ | 82.37 |
| $ | 97.65 |
| $ | 97.41 |
Oil (Bbl) (including impact of cash settled derivatives) |
|
| 84.85 |
|
| 99.32 |
|
| 98.86 |
Natural gas (Mcf) (excluding impact of cash settled derivatives) |
|
| 5.63 |
|
| 4.52 |
|
| 3.94 |
Natural gas (Mcf) (including impact of cash settled derivatives) |
|
| 5.59 |
|
| 4.47 |
|
| 3.94 |
Total (BOE) (excluding impact of cash settled derivatives) |
|
| 73.65 |
|
| 72.59 |
|
| 69.43 |
Total (BOE) (including impact of cash settled derivatives) |
|
| 75.64 |
|
| 73.56 |
|
| 70.41 |
Operating costs per BOE |
|
|
|
|
|
|
|
|
|
Lease operating expense |
| $ | 10.85 |
| $ | 14.00 |
| $ | 14.81 |
Production taxes |
|
| 4.35 |
|
| 2.92 |
|
| 2.05 |
Total |
| $ | 15.20 |
| $ | 16.92 |
| $ | 16.86 |
13
| 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 | |||||
The following table sets forth the wells drilled and completed during the periods indicated. All such wells were drilled in the continental United States. At December 31, 2013, the Company had four wells awaiting fracture stimulation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Drilled |
| Completed (a) |
| Awaiting Completion | ||||||
|
| Gross |
| Net |
| Gross |
| Net |
| Gross |
| Net |
Southern Midland Basin |
|
|
|
|
|
|
|
|
|
|
|
|
Vertical wells |
| 1 |
| 1.0 |
| 1 |
| 1.0 |
| — |
| — |
Horizontal wells |
| 22 |
| 20.1 |
| 22 |
| 20.1 |
| 3 |
| 3.0 |
Total |
| 23 |
| 21.1 |
| 23 |
| 21.1 |
| 3 |
| 3.0 |
Central Midland Basin |
|
|
|
|
|
|
|
|
|
|
|
|
Vertical wells |
| 4 |
| 1.8 |
| 3 |
| 1.3 |
| 1 |
| 0.4 |
Horizontal wells |
| 5 |
| 4.3 |
| 9 |
| 7.2 |
| — |
| — |
Total |
| 9 |
| 6.1 |
| 12 |
| 8.5 |
| 1 |
| 0.4 |
Northern Midland Basin |
|
|
|
|
|
|
|
|
|
|
|
|
Vertical wells |
| 2 |
| 1.5 |
| 1 |
| 0.8 |
| — |
| — |
Total |
| 2 |
| 1.5 |
| 1 |
| 0.8 |
| — |
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total vertical wells |
| 7 |
| 4.3 |
| 5 |
| 3.1 |
| 1 |
| 0.4 |
Total horizontal wells |
| 27 |
| 24.4 |
| 31 |
| 27.3 |
| 3 |
| 3.0 |
Total |
| 34 |
| 28.7 |
| 36 |
| 30.4 |
| 4 |
| 3.4 |
(a) | Completions include wells drilled prior to 2014. |
| 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 | ||||||||||||
The following table sets forth the Company’s drilled and completed wells, none of which were natural gas or nonproductive for the periods reflected:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2014 (a) |
| 2013 |
| 2012 | ||||||
|
| Gross |
| Net |
| Gross |
| Net |
| Gross |
| Net |
Oil wells |
|
|
|
|
|
|
|
|
|
|
|
|
Development |
| 19 |
| 15.5 |
| 19 |
| 17.2 |
| 14 |
| 9.7 |
Exploratory |
| 13 |
| 11.7 |
| 7 |
| 5.0 |
| 7 |
| 6.2 |
Total |
| 32 |
| 27.2 |
| 26 |
| 22.2 |
| 21 |
| 15.9 |
(a) | Does not include two gross (two net) non-producing exploratory wells. |
| 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 | ||||||||||||
The following table sets forth productive wells as of
December 31,
|
|
|
|
|
|
|
|
|
|
| Oil Wells |
| Natural Gas Wells | ||||
|
| Gross |
| Net |
| Gross |
| Net |
Working interest |
| 328 |
| 243.0 |
| — |
| — |
Royalty interest |
| 3 |
| 0.1 |
| — |
| — |
Total |
| 331 |
| 243.1 |
| — |
| — |
| Oil Wells | Natural Gas Wells | ||||||||||
| Gross | Net | Gross | Net | ||||||||
| Working interest | 128 | 107.7 | — | — | |||||||
| Royalty interest | 3 | 0.1 | — | — | |||||||
| Total | 131 | 107.8 | — | — | |||||||
A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a McfeBOE basis. However, most of our wells produce both oil and natural gas.
14
For the periods presented, the following table sets forth by major field(s) net production volumes and percentage of estimated proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | ||||||||||
|
| Production Volumes (MBOE) |
| % of Total Proved Reserves | ||||||||
|
| 2014 |
| 2013 |
| 2012 |
| 2014 |
| 2013 |
| 2012 |
Permian Basin: |
|
|
|
|
|
|
|
|
|
|
|
|
Southern Midland Basin |
| 1,497 |
| 612 |
| 402 |
| 65% |
| 85% |
| 51% |
Central Midland Basin |
| 549 |
| 193 |
| 189 |
| 35% |
| 14% |
| 16% |
Northern Midland Basin |
| 16 |
| 8 |
| — |
| 0% |
| 1% |
| 0% |
Total |
| 2,062 |
| 813 |
| 591 |
| 100% |
| 100% |
| 67% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Offshore and other (a) |
| — |
| 600 |
| 984 |
| 0% |
| 0% |
| 33% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
| 2,062 |
| 1,413 |
| 1,575 |
| 100% |
| 100% |
| 100% |
(a) | In late 2013, we sold the remaining interests in our producing offshore fields and in the Haynesville shale. |
| 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,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Developed |
| Undeveloped |
| Total | ||||||
|
| Gross |
| Net |
| Gross |
| Net |
| Gross |
| Net |
Louisiana |
| 936 |
| 200 |
| 188 |
| 55 |
| 1,124 |
| 255 |
Texas (a) |
| 20,991 |
| 16,487 |
| 12,498 |
| 10,879 |
| 33,489 |
| 27,366 |
Federal onshore (b) |
| — |
| — |
| 37,626 |
| 37,326 |
| 37,626 |
| 37,326 |
Total |
| 21,927 |
| 16,687 |
| 50,312 |
| 48,260 |
| 72,239 |
| 64,947 |
| Developed | Undeveloped | Total | |||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Louisiana | 1,091 | 158 | 233 | 167 | 1,324 | 325 | |||||||||||
| Texas (a) | 13,038 | 11,144 | 22,889 | 20,685 | 35,927 | 31,829 | |||||||||||
| Federal onshore (b) | — | — | 64,963 | 64,963 | 64,963 | 64,963 | |||||||||||
| Total | 14,129 | 11,302 | 88,085 | 85,815 | 102,214 | 97,117 | |||||||||||
(a) | A portion of our Texas acreage requires |
(b) | The Company’s lease of this acreage, located in Nevada, |
Undeveloped Acreage Expirations
The following table sets forth by geographic area as of December 31, 20132014 the number of our leased gross and net undeveloped acres that will expire over the next three years unless production begins before lease expiration dates. Gross amounts may be more than net amounts in a particular year due to timing of expirations.
|
|
|
|
|
|
|
|
|
|
|
|
| Net |
| Gross | ||||||
|
| 2015 |
| 2016 |
| 2017 |
| Total |
|
|
Texas |
|
|
|
|
|
|
| �� |
|
|
Southern Permian Basin |
| 165 |
| — |
| — |
| 165 |
| 165 |
Central Permian Basin |
| — |
| — |
| — |
| — |
| — |
Northern Permian Basin (a) |
| 7,307 |
| 648 |
| — |
| 7,955 |
| 10,575 |
Nevada (b) |
| — |
| — |
| — |
| — |
| — |
Total |
| 7,472 |
| 648 |
| — |
| 8,120 |
| 10,740 |
(a) | 7,916 of the total remaining net acres include extension options that would allow us to extend the primary term for a period of two years. |
(b) | The Company’s lease of this acreage does not expire until 2018 and 2019. |
| 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 | ||||||||||
The expiring acreage set forth in the table above accounts for 21%17% of our net undeveloped acreage (85,815(48,260 total net acres). and there are no PUD reserves attributable to such acreage. We are continually engaged in a combination of drilling and development and discussions with mineral lessors for lease extensions, renewals, new drilling and development units and new leases to address theany potential expiration of undeveloped acreage that occurs in the normal course of our business.
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The Company believes that the title to its oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. The Company’s properties are typicallypotentially 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’s rights to production revenues, these characteristics have been taken into account in calculating Callon’s net revenue interests and in estimating the size and value of its reserves. The Company believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon.
Insurance
In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. While not all inclusive, the Company’s insurance policies include coverage for general liability insuring onshore operations (including sudden and accidental pollution), aviation liability, auto liability, worker’s compensation, and employer’s liability. The company carries control of well insurance for only those onshore operations that it is contractually bound to do so. At the depths and in the areas in which the Company operates, and in light of the vertical and horizontal drilling that it undertakes, the Company typically does not encounter high pressures or extreme drilling conditions onshore.
Currently, the Company has general liability insurance coverage up to $1 million per occurrence and $2 million per policy in the aggregate, which includes sudden and accidental environmentalpollution liability coverage for the effects of pollution on third parties arising from its operations. The Company’s insurance policies contain high policy limits, and in most cases, deductibles (generally ranging from $0 to $250,000) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, theThe 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’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company and the Company’s other contractors. Additionally, each party generally is responsible for damage to its own property.
The third-party contractors that perform hydraulic fracturing operations for the Company sign master service agreements generally containing the indemnification provisions noted above. The Company does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, the Company believes its general liability and excess liability insurance policies would cover foreseeable third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies.
The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company’s risk analysis, it believes that it is properly insured, no assurance can be given that the Company will be able to maintain insurance in the
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future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.
Major Customers
Our production is sold generally on month-to-month contracts at prevailing prices. The following table identifies customers to whom we sold a significant percentage of our total oil and natural gas production, on an equivalent basis, during each of the 12-month periods ended:indicated:
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| For the Year Ended December 31, | |||||
| 2014 |
| 2013 |
| 2012 | |
Enterprise Crude Oil, LLC |
| 51% |
| 38% |
| 32% |
Plains Marketing, L.P. |
| 22% |
| 15% |
| 15% |
Sunoco |
| 10% |
| 0% |
| 0% |
Shell Trading Company |
| 0% |
| 31% |
| 39% |
Other |
| 17% |
| 16% |
| 14% |
Total |
| 100% |
| 100% |
| 100% |
| December 31, | ||||||||
| 2013 | 2012 | 2011 | ||||||
| Enterprise Crude Oil, LLC | 38 | % | 32 | % | 16 | % | ||
| Shell Trading Company | 31 | % | 39 | % | 45 | % | ||
| Plains Marketing, L.P. | 15 | % | 15 | % | 17 | % | ||
| Other | 16 | % | 14 | % | 22 | % | ||
| Total | 100 | % | 100 | % | 100 | % | ||
Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on Callon’s ability to market future oil and natural gas production. We are not currently committed to provide a fixed and determinable quantity of oil or gas in the near future under our contracts.
Corporate Offices
The Company’s headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned space. We also maintain leased business offices in Houston and Midland, Texas. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures.
Employees
Callon had 94109 employees as of
Regulations
General. Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for amendment and/or expansion. Some of these requirements carry substantial penalties for failure to comply.
Exploration and Production. Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are:
· | the location and spacing of wells; |
· | the method of drilling and completing and operating wells; |
· | the rate and method of production; |
· | the surface use and restoration of properties upon which wells are drilled and other exploration activities; |
· | notice to surface owners and other third parties; |
· | the venting or flaring of natural gas; |
· | the plugging and abandoning of wells; |
· | the discharge of contaminants into water and the emission of contaminants into air; |
· | the disposal of fluids used or other wastes obtained in connection with operations; |
· | the marketing, transportation and reporting of production; and |
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· | the valuation and payment of royalties. |
Operations conducted on federal or state oil and natural gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Department of the Interior (“DOI”) Bureaus or other appropriate federal or state agencies.
Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity.
Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. The industry historically has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.
We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position.
Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency or the EPA,(“EPA”) issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantialFurther, the EPA has identified environmental compliance with applicableby the energy extraction sector as one of its enforcement initiatives for 2014-2016 and, as a general matter, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental laws and regulations and we have not experienced any material adverse effect from compliance with these
Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), 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 suchand its state analogs, it is possible that some wastes we generate presently or in the future may constitute “solid wastes” that arebe subject to the less stringent requirements of non-hazardous waste provisions may not be exemptregulation under RCRA and state programs. However,analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in
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Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.
Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.
Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages.
We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.
Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act or OPA,(“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands), as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state.applicable state analog. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activitythe discharge of dredge or fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. 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.
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Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.
The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.
Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. We believe we are in material compliance with the requirements of each of these laws.
Air Emissions. The federal Clean Air Act, as amended, and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16,April 17, 2012, the EPA published final regulations under the federal Clean Air Act
Greenhouse Gas (GHG)(“GHG”) Regulation. Although federal legislation regardingMore stringent laws and regulations relating to climate change and GHGs may be adopted in 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 requirefuture and could cause us to incur increased operating costs and may have an adverse effectmaterial expenses in complying with them. In the absence of comprehensive federal legislation on demand forGHG emission control, the oil and natural gas we produce.
The EPA has adopted a rule establishingestablished GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions if the total emissions within a basin exceed 25,000 metric tons CO2 equivalent per year.emissions. Although this rule doesthese requirements do not limit the amount of GHGs that can be emitted, it requiresthey could require us to incur significant costs to monitor, keep records of, and potentially report GHG emissions associated with our operations if the reporting threshold is reached with production growth.
In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential regional and state initiatives may result in so-called “Cap-and-Trade programs”, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, such as by being required to purchase or to surrender allowances for GHGs resulting from our operations. TheThese federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.
Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act or SDWA,(“SDWA”), regulates the underground injection of substances through the Underground Injection Control or UIC,(“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.commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing
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activities (except where diesel is a component of the fracturing fluid, as further discussed below). Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing 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.
The EPA approved finalhas adopted regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards for hydraulically fractured natural gas wells to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured gas wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules 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 rules from
In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, most notably the EPA’s study on the environmental impacts of hydraulic fracturing, the final results of which are expected in 2014.not yet available.. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities.
Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (OSHA)(“OSHA”) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.
Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some case impose a moratorium on hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water. Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could
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adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.
Surface Damage Statutes (“SDAs”). In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments to the operator in connection with exploration and operating activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.
National Environmental Policy Act and Endangered Species Act. Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act or NEPA,(“NEPA”), which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.
The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat
Mineral Leasing Act of 1920 (“Mineral Act”). The Mineral Act prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign corporation except through stock ownership in a corporation formed under the laws of the United States or of any U.S. state or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or corporations of the United States. If these restrictions are violated, the oil and gas lease or leases can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the Bureau of Land Management (“BLM”) (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. The Company owns an interest in federal leaseholds in Nevada. It is possible that holders of the Company’s equity interests may be citizens of foreign countries, which could be determined to be citizens of a non-reciprocal country under the Mineral Act. In such event, the federal onshore oil and gas leases held by the Company could be subject to cancellation based on such determination.
Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation 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
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the pricerates and other terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.
Although oil and natural gas sales prices are currently unregulated, Congressthe federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate, 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
Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.
Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.
FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all
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purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.
The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In August 2011, the PHMSA issued an Advance Notice of Proposed Rulemaking regarding pipeline safety, including questions regarding the modification of regulations applicable to gathering lines in rural areas.
Oil and NGLs Sales and Transportation. Sales of oil, 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.
The Company’s sales of oil salesand natural gas liquids are also affected by the availability, terms and costcosts of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil in common carrierand natural gas liquids by pipelines is also subject to rate regulation.are regulated by the FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and intrastatenatural gas liquids pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Any transportation of the Company’s crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.
State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.
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The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
Commitments and Contingencies
The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from the Company’s operations could have on its activities. See
NoteAvailable
We make available free of charge on our Internet web site (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like Callon, that file electronically with the SEC.
We also make available within the Investors section of our Internet web site our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation and Nominating and Governance Committee Charters, which have been approved by our board of directors. We will make timely disclosure by a Current Report on Form 8-K and on our web site of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: Chief Financial Officer, Callon Petroleum Company, P.O. Box 1287, Natchez, MS 39121.
Depressed oil and natural gas prices may adversely affect our results of operations and financial condition. Our success is highly dependent on prices for oil and natural gas, which are extremely volatile, and the oil and natural gas markets are cyclical. Approximately 80% of our anticipated 2015 production, on a BOE basis, is oil. Starting in the second half of 2014, the NYMEX price for a barrel of oil has fallen sharply, from a price of $105.37 on June 30, 2014 to $49.76 on February 27, 2015. In addition, NYMEX prices for natural gas have been low compared with historical prices. Extended periods of low prices for oil or natural gas will have a material adverse effect on us. The prices of oil and natural gas depend on factors we cannot control such as weather, economic conditions, and levels of production, actions by OPEC and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business:
· | our revenues, cash flows and earnings; |
· | the amount of oil and natural gas that we are economically able to produce; |
· | our ability to attract capital to finance our operations and the cost of the capital; |
· | the amount we are allowed to borrow under our credit facilities; |
· | the profit or loss we incur in exploring for and developing our reserves; and |
· | the value of our oil and natural gas properties. |
Any substantial and extended decline in the price of oil or natural gas could have an adverse effect on our borrowing capacity, our ability to obtain additional capital, and our revenues, profitability and cash flows.
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If oil and natural gas prices decrease and remain depressed for extended periods of time, we may be required to take additional writedownswrite-downs of the carrying value of our oil and natural gas properties. We may be required to writedownwrite-down the carrying value of our oil and natural gas properties when oil and natural gas prices are low. Under the full-costfull cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and natural gas properties exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. Because the oil price we are required to use to estimate our future net cash flows is the average price over the 12 months prior to the date of determination of future net cash flows, the full effect of falling prices may not be reflected in our estimated net cash flows for several quarters. We review the carrying value of our properties quarterly and once incurred, a writedownwrite-down of oil and natural gas properties is not reversible at a later date, even if prices increase. See Note 1213 to our Consolidated Financial Statements.
Our actual recovery of reserves may substantially differ from our proved reserve estimates and our proved reserve estimates may change over time. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. In addition, drilling, testing and production data acquired since the date of an estimate may justify revising an estimate.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas. We incorporate many factors and assumptions into our estimates including:
· | Expected reservoir characteristics based on geological, geophysical and engineering assessments; |
· | Future production rates; |
· | Future oil and natural gas prices and quality and locational differences; and |
· | Future development and operating costs. |
You should not assume that any present value of future net cash flows from our estimated net proved reserves contained in this Form 10-K represents the market value of our oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at
December 31,Information about reserves constitutes forward-looking information. See “Forward-Looking Statements” for information regarding forward-looking information.
Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is
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reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves.
Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, or acquire additional reserves, or may not be able to make the necessary capital investments to develop our reserves, if our cash flows from operations decline or external sources of capital become limited or unavailable. As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures, currently expected to be in excess of three times the cost, as compared to the drilling of a traditional vertical well. If we do not replace the reserves we produce, our reserves revenues and cash flow will decrease over time, which will have an adverse effect on our business.
Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all. Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings under our credit facility and public debt and equity financings. In 2013,2014, our total capital expenditures, including expenditures for leasehold interests and property acquisitions, drilling, seismic and infrastructure, were approximately $171 million.$455.5 million. Our 20142015 capital budget for drilling, completion and infrastructure is estimated to be approximately $185 million.$150 to $165 million. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
If the borrowing base under our revolving credit facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations.
Our revolving credit facility and second lien term loan facility contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities. Our credit facilities restrictive covenants that limit our ability to, among other things:
· | incur additional indebtedness; |
· | create additional liens; |
· | sell assets; |
· | merge or consolidate with another entity; |
· | pay dividends or make other distributions; |
· | engage in transactions with affiliates; and |
· | enter into certain swap agreements. |
In addition, we will be required to use substantial portions of our future cash flow to repay principal and interest on our indebtedness. Our credit facilities require us to maintain certain financial ratios and tests, including a minimum asset value coverage ratio of total debt. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes
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%1.75% to 2.75% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. Our second lien term loan facility bears interest at a
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rate of LIBOR, subject to a floor of 1%, plus 7.75%7.50%. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.
The borrowing base under our revolving credit facility may be reduced below the amount of borrowings outstanding under such facilities.
The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget. From time to time, our industry has experiences a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies or qualified personnel can materially and adversely affect our operations and profitability.
Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of our drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local landowners and other sources for use in our operations. During the last few years, West Texas has experienced extreme drought conditions. As a result of the severe drought, some local water districts may begin restricting the use of water under their jurisdiction for drilling and hydraulic fracturing to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, NGLs and natural gas, which could have an adverse effect on our business, financial condition and results of operations.
Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area. All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
Our exploration projects increase the risks inherent in our oil and natural gas activities. We may seek to replace reserves through exploration, where the risks are greater than in acquisitions and development drilling. During 2012, we purchased 21,419 net acres in the Northern Midland basin, an area that has seen only limited drilling activity. We expect to continue exploration of this acreage over the next several years, although our position is subject to meaningful lease expirations through 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; |
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· | material changes in oil or natural gas prices; |
· | the costs and availability of drilling rigs; |
· | the success or failure of wells drilled in similar formations or which would use the same production facilities; |
· | availability and cost of capital; |
· | changes in the estimates of the costs to drill or complete wells; and |
· | changes to governmental regulations. |
Delays in exploration, cost overruns or unsuccessful drilling results could have a material adverse effect on our business and future growth.
Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive deposits will not be discovered. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return.
In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including:
· | unexpected drilling conditions; |
· | pressure or irregularities in formations; |
· | equipment failures or accidents and shortages or delays in the availability of drilling rigs and the delivery of equipment; and |
· | compliance with governmental requirements. |
Failure to conduct our oil and gas operations in a profitable manner may result in write downswrite-downs of our proved reserves quantities, impairment of our oil and gas properties, and a write downwrite-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows.
Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Approximately 45% of our total estimated proved reserves as of December 31, 2014, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.
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We may be unable to integrate successfully the operations of future acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. Our business may include producing property acquisitions that would include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions may involve numerous risks, including:
· | operating a larger combined organization and adding operations; |
· | difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area; |
· | risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated; |
· | loss of significant key employees from the acquired business: |
· | diversion of management’s attention from other business concerns; |
· | failure to realize expected profitability or growth; |
· | failure to realize expected synergies and cost savings; |
· | coordinating geographically disparate organizations, systems and facilities; and |
· | coordinating or consolidating corporate and administrative functions. |
Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisition and current operations, which in turn, could negatively impact our results of operations.
We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating and capital costs and potential environmental and other liabilities. Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.
Unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our ability to conduct business. There are many operating hazards in exploring for and producing oil and natural gas, including:
· | our drilling operations may encounter unexpected formations or pressures, which could cause damage to equipment or personal injury; |
· | we may experience equipment failures which curtail or stop production; |
· | we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other corrective action to be taken; |
· | storms and other extreme weather conditions could cause damages to our production facilities or wells. |
Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas-leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures.
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If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of:
· | injury or loss of life; |
· | severe damage to and destruction of property, natural resources and equipment; |
· | pollution and other environmental damage; |
· | clean-up responsibilities; |
· | regulatory investigation and penalties; |
· | suspension of our operations; and |
· | repairs to resume operations. |
We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations.
Factors beyond our control affect our ability to market production and our financial results. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. These factors could negatively affect our ability to market all of the oil or natural gas we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce. These factors include:
· | the extent of domestic production and imports of oil and natural gas; |
· | federal regulations generally prohibiting the export of U.S. crude oil; |
· | federal regulations applicable to exports of liquefied natural gas (LNG); |
· | the proximity of hydrocarbon production to |
· | 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.
The marketability of our production is dependent upon oil and condensate trucking facilities owned and operated by third parties, and the unavailability of these facilities would have a material adverse effect on our revenue. Our ability to market our production depends in substantial part on the availability and capacity of oil and condensate trucking operations owned and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases.
The disruption of third party trucking facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil and condensate. The third parties control when, or if, such trucking facilities are restored and what prices will be charged. In the past, we have experienced disruptions in our ability to market oil and condensate from bad weather. We may experience similar interruptions as we continue to explore and develop our Permian Basin properties in the future. If we were required to shut in our production for long periods of time due to lack of trucking capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows.
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
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our recent horizontal drilling efforts in new or emerging formations, including certain intervals in the Wolfcamp shale, Clinethe Spraberry shale and Mississippian limethe Cline shale 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. 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 writedownswrite-downs 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 is 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. 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 effect 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 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 |
· | 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.
Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of its rulemaking proceedings still pending under the new legislation,Dodd-Frank Act, the CFTC has issuedapproved on November 5, 2013, a finalproposed rule onimposing position limits for certain futures and option contracts in the major energy marketsvarious commodities (including natural gas) and for swaps that are their economic equivalents (with exemptions for certain bona fideequivalents. Certain specified types of hedging transactions);transactions are exempt from these position limits, provided that such hedging transactions satisfy the CFTC’s final rule was set aside by the U.S. District Courtrequirements for the District of Columbia on September 28, 2012 and remanded to“bona fide hedging” transactions or positions. Similarly, the CFTC to resolve ambiguity as to whether statutoryhas issued a proposed rule on margin requirements for such limitsswap transactions, which proposes an exemption for commercial end-users, entering into uncleared swaps in order to be determinedhedge commercial risks affecting
32
their 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.
While it is not possible at this time to predict when the CFTC will finalize certain other relatedissue final rules and regulations,applicable to position limits or margin requirements, depending on the ActCompany’s ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, these rules and related regulations may require us to comply with position limits, margin requirements and with certain clearing and trade-execution requirements in connection with our financial 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 oractivities. The Dodd-Frank Act may require our current counterparties to hold marginpost additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of commercial end-users to have access to financial derivatives to hedge or maintain capital levels,mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could be passed throughadversely affect our available capital for other commercial operations purposes), materially alter the terms of future swaps relative to us, or impose otherthe terms of our existing bilaterally negotiated financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter.
If we reduce our use of derivative contracts as a result of the new requirements, that are more burdensome than current regulations, hedging transactions in the future wouldour results of operations may become more expensive than we experiencedvolatile 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 past.
We may not have production to offset 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 physical production.
By hedging, we may not benefit from price increases. Hedging can 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 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. During periods of falling commodity prices, our hedging transactions expose us to risk of financial loss if our counterparty to a derivatives transaction fails to perform its obligations under a derivatives transaction (e.g., our counterparty fails to perform its obligation to make payments to us under the derivatives transaction when the market (floating) price under such derivative falls below the specified fixed price). We are unable to predict sudden changes in a counterparty’s
33
creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
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%51% of our total oil and natural gas revenues for the year ended December 31, 2013.2014. 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; 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. Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. We could also be affected by more stringent laws and regulations adopted in the future, including any related to 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” (“GHG”) could result in increased operating costs and reduced demand for the oil and natural gas we produce. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. The EPA has adoptedrecently announced its so-called “GHG tailoring rule” that phasesintention to take measures to require or encourage reductions in federal PSD permit requirementsmethane emissions, including from oil and natural gas operations. Those measures include the development of NSPS regulations in 2016 for GHG emissionsreducing methane from new and modified oil and gas production 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 emissionsnatural gas processing and we could incur additional costs to satisfy those requirements.transmission sources.
In addition, , the EPA requires the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published its amendments to the GHG reporting rule to includeincluding 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 GHG 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 CO
In addition, the United States Congress has considered (but not passed) 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
34
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 storms and floods), 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 affecteffect 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 and local 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 isHydraulic fracturing activities are typically regulated by state oil and gas commissions but is not subject to regulation at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except forwhere diesel is a component of the fracturing activity involving the use of diesel)fluid). 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
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, horizontalannounced that it will ban high volume hydraulic fracturing until state-administered environmental studies are finalized.fracturing. 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, the EPA has announced initiatives 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 isbecomes further 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.costs and potential liabilities. 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.
35
We are now subject to regulation under NSPS and NESHAPS programs, which could result in increased operating costs. On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and the NESHAP 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 newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions.
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’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’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.
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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.
None.
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.
Not applicable.
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ITEM 5. MarketMarket for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common stock trades on the New York Stock Exchange under the symbol “CPE”. The following table sets forth the high and low sale prices per share as reported for the periods indicated.
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| Common Stock Price | ||||||||||
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| 2014 |
| 2013 | ||||||||
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| High |
| Low |
| High |
| Low | ||||
First quarter |
| $ | 9.00 |
| $ | 6.13 |
| $ | 5.82 |
| $ | 3.62 |
Second quarter |
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| 11.75 |
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| 8.15 |
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| 4.00 |
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| 3.19 |
Third quarter |
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| 12.09 |
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| 8.46 |
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| 5.49 |
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| 3.40 |
Fourth quarter |
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| 8.99 |
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| 4.09 |
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| 7.60 |
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| 5.18 |
| Stock Price | ||||||||||||||||
| 2013 | 2012 | |||||||||||||||
| High | Low | High | Low | |||||||||||||
| First quarter | $ | 5.82 | $ | 3.62 | $ | 7.95 | $ | 5.09 | ||||||||
| Second quarter | 4.00 | 3.19 | 6.45 | 3.80 | ||||||||||||
| Third quarter | 5.49 | 3.40 | 6.55 | 4.11 | ||||||||||||
| Fourth quarter | 7.60 | 5.18 | 6.36 | 4.05 | ||||||||||||
Holders
As of
Dividends
We have not paid any cash dividends on our common stock to date and presently do not expect to declare or pay any cash dividends 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%10.0% of the liquidation preference of $50.00 per share. Unless the full amount of the dividends for the Series A Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock. In addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock.
During the fourth quarter of
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,
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Plan Category |
| Number of securities to be issued upon exercise of outstanding options |
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| Weighted-average exercise price of outstanding options, warrants and rights |
| Number of securities remaining available for future issuance under equity compensation plans |
Equity compensation plans approved by security holders |
| 15 |
| $ | 13.71 |
| 1,132 |
Equity compensation plans not approved by security holders |
| 15 |
| $ | 14.37 |
| - |
Total |
| 30 |
| $ | 14.04 |
| 1,132 |
| 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 | |||||||
| Equity compensation plans approved by security holders | 37 | $ | 13.51 | 1,192 | ||||||
| Equity compensation plans not approved by security holders | 15 | 14.37 | — | |||||||
| Total | 52 | 13.75 | 1,192 | |||||||
For additional information regarding the Company’s benefit plans and share-based compensation expense, see
Notes38
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 four 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 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 New York Stock Exchange Market Index from
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.
Assumes Initial Investment of $100
December 20132014
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Company/Market/Peer Group |
| 2009 |
| 2010 |
| 2011 |
| 2012 |
| 2013 |
| 2014 | ||||||
Callon Petroleum Company |
| $ | 100.00 |
| $ | 394.67 |
| $ | 331.33 |
| $ | 313.33 |
| $ | 435.33 |
| $ | 363.33 |
S&P 500 Index - Total Returns |
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| 100.00 |
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| 115.06 |
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| 117.49 |
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| 136.30 |
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| 180.44 |
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| 205.14 |
SIG Oil Exploration & Production Index |
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| 100.00 |
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| 123.12 |
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| 111.96 |
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| 104.20 |
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| 131.89 |
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| 94.56 |
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| For the Year Ended December 31, | ||||||||||||||||||||||||
| Company/Market/Peer Group | 2008 | 2009 | 2010 | 2011 | 2012 | 2013 | ||||||||||||||||||
| Callon Petroleum Company | $ | 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 | 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 | 185.22 | 194.51 | 167.95 | 189.60 | 216.25 | ||||||||||||||||||
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, 20132014 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results.results (dollars in thousands, except per share amounts).
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| For the Year Ended December 31, | |||||||||||||
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| 2014 |
| 2013 |
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| 2012 |
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| 2011 |
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| 2010 | ||
Statement of Operations Data |
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Operating revenues |
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Oil and natural gas sales |
| $ | 151,862 |
| $ | 102,569 |
| $ | 110,733 |
| $ | 127,644 |
| $ | 89,882 |
Operating expenses |
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Total operating expenses |
| $ | 113,592 |
| $ | 91,905 |
| $ | 100,043 |
| $ | 88,022 |
| $ | 68,703 |
Income from continuing operations |
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| 38,270 |
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| 10,664 |
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| 10,690 |
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| 39,622 |
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| 21,179 |
Net income (a) |
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| 37,766 |
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| 4,304 |
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| 2,747 |
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| 106,396 |
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| 8,386 |
Earnings (loss) per share ("EPS") |
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Basic |
| $ | 0.67 |
| $ | (0.01) |
| $ | 0.07 |
| $ | 2.81 |
| $ | 0.29 |
Diluted |
| $ | 0.65 |
| $ | (0.01) |
| $ | 0.07 |
| $ | 2.76 |
| $ | 0.28 |
Weighted average number of shares outstanding for Basic EPS |
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| 44,848 |
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| 40,133 |
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| 39,522 |
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| 37,908 |
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| 28,817 |
Weighted average number of shares outstanding for Diluted EPS |
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| 45,961 |
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| 40,133 |
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| 40,337 |
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| 38,582 |
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| 29,476 |
Statement of Cash Flows Data |
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|
|
|
|
|
|
|
|
Net cash provided by operating activities |
| $ | 94,387 |
| $ | 54,475 |
| $ | 51,290 |
| $ | 79,167 |
| $ | 100,102 |
Net cash used in investing activities |
|
| (452,501) |
|
| (79,804) |
|
| (93,703) |
|
| (91,511) |
|
| (59,738) |
Net cash provided by (used in) financing activities |
|
| 356,070 |
|
| 27,202 |
|
| (243) |
|
| 38,703 |
|
| (26,252) |
Balance Sheet Data |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas properties |
| $ | 742,155 |
| $ | 324,187 |
| $ | 269,521 |
| $ | 215,912 |
| $ | 168,868 |
Total assets |
|
| 876,770 |
|
| 423,953 |
|
| 378,173 |
|
| 369,707 |
|
| 218,326 |
Long-term debt (b) |
|
| 335,000 |
|
| 75,748 |
|
| 120,668 |
|
| 125,345 |
|
| 165,504 |
Stockholders' equity |
|
| 433,735 |
|
| 279,094 |
|
| 205,971 |
|
| 201,202 |
|
| 15,810 |
Proved Reserves Data |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil (MBbls) |
|
| 25,733 |
|
| 11,898 |
|
| 10,780 |
|
| 10,075 |
|
| 8,149 |
Total natural gas (MMcf) |
|
| 42,548 |
|
| 17,751 |
|
| 19,753 |
|
| 35,118 |
|
| 32,957 |
Total (MBOE) |
|
| 32,824 |
|
| 14,857 |
|
| 14,072 |
|
| 15,928 |
|
| 13,641 |
Standardized measure (c) |
| $ | 579,542 |
| $ | 283,946 |
| $ | 231,148 |
| $ | 270,357 |
| $ | 198,916 |
| For the year ended December 31, | |||||||||||||||||||
| 2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
| Statement of Operations Data: | (In thousands, except per share amounts) | ||||||||||||||||||
| Operating revenues: | |||||||||||||||||||
| Oil and natural gas sales | $ | 102,569 | $ | 110,733 | $ | 127,644 | $ | 89,882 | $ | 101,259 | |||||||||
| Medusa BOEM royalty recoupment (a) | — | — | — | — | 40,886 | ||||||||||||||
| Total operating revenues | $ | 102,569 | $ | 110,733 | $ | 127,644 | $ | 89,882 | $ | 142,145 | |||||||||
| Total operating expenses | $ | 91,905 | $ | 100,043 | $ | 88,022 | $ | 68,692 | $ | 68,692 | |||||||||
| Income (loss) from continuing operations | 10,664 | 10,690 | 39,622 | 21,179 | 73,453 | ||||||||||||||
| Net income (loss) (b) | 4,304 | 2,747 | 106,396 | 8,386 | 46,796 | ||||||||||||||
| Earnings (loss) per share ("EPS"): | |||||||||||||||||||
| Basic | $ | (0.01 | ) | $ | 0.07 | $ | 2.81 | $ | 0.29 | $ | 2.12 | ||||||||
| Diluted | $ | (0.01 | ) | $ | 0.07 | $ | 2.76 | $ | 0.28 | $ | 2.11 | ||||||||
| Weighted average number of shares outstanding for Basic EPS | 40,133 | 39,522 | 37,908 | 28,817 | 22,072 | ||||||||||||||
| Weighted average number of shares outstanding for Diluted EPS | 40,133 | 40,337 | 38,582 | 29,476 | 22,200 | ||||||||||||||
| Statement of Cash Flows Data: | |||||||||||||||||||
| Net cash provided by operating activities | $ | 54,329 | $ | 51,290 | $ | 79,167 | $ | 100,102 | $ | 19,698 | |||||||||
| Net cash used in investing activities | (79,804 | ) | (93,703 | ) | (91,511 | ) | (59,738 | ) | (43,189 | ) | |||||||||
| Net cash provided by (used in) financing activities | 27,348 | (243 | ) | 38,703 | (26,252 | ) | 10,000 | ||||||||||||
| Balance Sheet Data: | |||||||||||||||||||
| Oil and gas properties, net | $ | 324,187 | $ | 269,521 | $ | 215,912 | $ | 168,868 | $ | 130,608 | |||||||||
| Total assets | 423,953 | 378,173 | 369,707 | 218,326 | 227,991 | ||||||||||||||
| 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) | 11,898 | 10,780 | 10,075 | 8,149 | 6,479 | ||||||||||||||
| Total natural gas (MMcf) | 17,751 | 19,753 | 35,118 | 32,957 | 19,103 | ||||||||||||||
| 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) |
Net income for 2011 includes $69.3 million of income tax benefit related to the reversal of the Company’s deferred tax asset valuation allowance. See Note 10 for additional information. |
(b) | See Note 4 for additional information. |
(c) | 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. |
40
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation |
ITEM 7. Management’sManagement’s Discussion and Analysis of Financial Condition and Results of Operations
General
The following management’s discussion and analysis is intended to assist in understandingdescribes the principal factors affecting the Company’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 ofare an independent oil and natural gas properties sincecompany established in 1950.
Significant accomplishments for 20132014 include:
· | Acquired 6,230 gross (3,862 net) surface acres in Midland, Andrews, Martin and Ector Counties for approximately $210 million, which added over 1,300 BOE/d of production and approximately 194 gross (121.6 net) potential horizontal drilling locations (see below); |
· | Expanded our existing core development areas in Upton and Reagan Counties by acquiring 1,527 net acres for $8.2 million; |
· | Increased Permian Basin annual production in 2014 by 155% to 2,062 MBOE as compared to 2013; |
· | Increased 2014 proved reserves by 121% to 32.8 MMBOE as compared to 2013; |
· | Placed a total of 31 gross horizontal wells on production from four distinct intervals; |
· | Increased the Credit Facility’s borrowing base to $250 million with a syndicate of 10 lending institutions; |
· | Retired the remaining $48.5 million of the 13% Senior Notes, improving our cost of capital; and |
· | Completed a common stock offering for $129.4 million in gross proceeds and entered into a new $300 million second lien term loan to partially fund the previously mentioned acquisition and planned capital expenditures. |
Acquisition activity
In the first quarter of 2014, the Company acquired 1,527 net acres in Upton and Reagan Counties, Texas, which are located in the Southern Midland Basin producing from two established zones in the Wolfcamp B and the Wolfcamp A;
On October 8, 2014, the Company completed the acquisition of undeveloped acreage and producing oil and gas properties located in Midland, Andrews, Martin and Ector Counties, Texas. Including estimated purchase price adjustments, and
Key attributes of the issuance of Series A Cumulative Preferred Stock,
· | 6,230 gross (3,862 net) surface acres, 95% of which are located in Midland and Andrews Counties, in close proximity to the Company’s existing Carpe Diem and Pecan Acres fields in Midland County |
· | 194 gross (121.6 net) potential horizontal drilling locations targeting the Wolfcamp B, Lower Spraberry and Middle Spraberry zones which are currently producing in offsetting fields |
· | 255 gross (159.9 net) additional potential horizontal drilling locations targeting four other prospective zones including the Wolfcamp A, Wolfcamp D (Cline), Clearfork and Jo Mill |
· | 100% of targeted horizontal zones held by production |
41
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation |
The Company assumed operatorship of the properties November 1, 2014 and Well Counts
Operational Highlights
Following the sale of our remaining producing offshore and Haynesville properties in the fourth quarter of 2013, all of our producing properties are located in the Permian Basin. As a result of our acquisition and horizontal development efforts, our Permian production grew 154% in 2014 compared to 2013, increasing to 2,062 MBOE from 813 MBOE, respectively. Our production in 2014 was approximately 82% oil and 18% natural gas.
|
|
|
|
|
|
|
|
|
|
| Net Production (MBOE) | ||||||
|
| Twelve Months Ended December 31, | ||||||
|
| 2014 |
| 2013 |
| Change |
| % Change |
Permian |
|
|
|
|
|
|
|
|
Southern Midland Basin |
| 1,497 |
| 612 |
| 885 |
| 145% |
Central Midland Basin |
| 549 |
| 193 |
| 356 |
| 184% |
Northern Midland Basin |
| 16 |
| 8 |
| 8 |
| 100% |
Total |
| 2,062 |
| 813 |
| 1,249 |
| 154% |
Offshore and other |
|
|
|
|
|
|
|
|
Medusa |
| — |
| 302 |
| (302) |
| (100)% |
Haynesville shale |
| — |
| 18 |
| (18) |
| (100)% |
Gulf of Mexico shelf and other |
| — |
| 280 |
| (280) |
| (100)% |
Total |
| — |
| 600 |
| (600) |
| (100)% |
|
|
|
|
|
|
|
|
|
Total |
| 2,062 |
| 1,413 |
| 649 |
| 46% |
During 2014 we operated two horizontal rigs and one vertical rig. The following table summarizes the Company’s drilling activity in the Permian grew 38% in 2013 compared to 2012, increasing to 813 MBOE from 591 MBOE, respectively. Production in 2013 continued to benefit from high oil concentrations including 64% oil and 36% natural gas, which we anticipate to further increase followingBasin for the sale of our offshore assets.
year ended December 31, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Drilled |
| Completed (a) |
| Awaiting Completion | ||||||
|
| Gross |
| Net |
| Gross |
| Net |
| Gross |
| Net |
Southern Midland Basin |
|
|
|
|
|
|
|
|
|
|
|
|
Vertical wells |
| 1 |
| 1.0 |
| 1 |
| 1.0 |
| — |
| — |
Horizontal wells |
| 22 |
| 20.1 |
| 22 |
| 20.1 |
| 3 |
| 3.0 |
Total |
| 23 |
| 21.1 |
| 23 |
| 21.1 |
| 3 |
| 3.0 |
Central Midland Basin |
|
|
|
|
|
|
|
|
|
|
|
|
Vertical wells |
| 4 |
| 1.8 |
| 3 |
| 1.3 |
| 1 |
| 0.4 |
Horizontal wells |
| 5 |
| 4.3 |
| 9 |
| 7.2 |
| — |
| — |
Total |
| 9 |
| 6.1 |
| 12 |
| 8.5 |
| 1 |
| 0.4 |
Northern Midland Basin |
|
|
|
|
|
|
|
|
|
|
|
|
Vertical wells |
| 2 |
| 1.5 |
| 1 |
| 0.8 |
| — |
| — |
Total |
| 2 |
| 1.5 |
| 1 |
| 0.8 |
| — |
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total vertical wells |
| 7 |
| 4.3 |
| 5 |
| 3.1 |
| 1 |
| 0.4 |
Total horizontal wells |
| 27 |
| 24.4 |
| 31 |
| 27.3 |
| 3 |
| 3.0 |
Total |
| 34 |
| 28.7 |
| 36 |
| 30.4 |
| 4 |
| 3.4 |
(a) | Completions include wells drilled prior to 2014. |
Permian Reserve Growth
As of December 31, 2014, our estimated proved reserves increased 121% to 32.8 MMBOE compared to 14.9 MMBOE of proved reserves at year-end 2013. Our significant growth in proved reserves was primarily attributable to our horizontal development and acquisition efforts. Our proved reserves at year-end 2014 were 78% oil and 22% natural gas, compared to 80% oil and 20% natural gas at year-end 2013.
42
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of |
| 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 | )% | ||||||
| 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 | ||||||||||||
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.securities and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and explorationexploitation of oil and natural gas properties. Cashproperties, in addition to refinancing of debt instruments.
During the third and cash equivalents increased $1.9 million during 2013 to $3.0 million compared to $1.1 million at December 31, 2012. We recentlyfourth quarters of 2014, we amended the borrowing base under our Credit Facility, entered into the Amended Credit Facilitya second lien term loan and Second Lien Facilitycompleted a common stock offering to support the funding of our Central Midland Basin acquisition completed in October 2014 and our ongoing operations. For additional information, see Note 4 and acquisition initiatives which are discussed in greater detail in Notes 5, 10 and 14 in the Footnotes to the Consolidated Financial Statements. WeIn addition, we regularly evaluate other sources of capital to complement our cash flow from operations and other sources of capital as we pursue our long-term growth plans in the Permian Basin.
Based upon current commodity price expectations for 2015, we believe that as discussed below, our operatingcash flow from operations and borrowings under our Credit Facility and Second Lien Loan will be sufficient to fund our operations for 2015, including any deficiencies in the Company’s current net working capital. However, future cash flows combined withare subject to a number of variables, including forecast production volumes and commodity prices. Approximately 95% of our bank borrowing ability providescurrent 2015 capital program is allocated to properties we operate and, as a result, the amount and timing of a substantial portion of our planned capital expenditures is largely discretionary in the event we determine it prudent to curtail drilling and completion operations due to capital constraints or reduced returns on investment in periods of commodity price weakness.
Cash and cash equivalents decreased $2.0 million in the year ended December 31, 2014 to $1.0 million compared to $3.0 million at December 31, 2013. As of February 27, 2015, our available liquidity necessary to meet our operational cash flow needs.
Liquidity and cash flow:flow
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | |||||||
|
| 2014 |
| 2013 |
| 2012 | |||
Net cash provided by operating activities |
| $ | 94.4 |
| $ | 54.5 |
|
| 51.3 |
Net cash used in investing activities |
|
| (452.5) |
|
| (79.8) |
|
| (93.7) |
Net cash provided by (used in) financing activities |
|
| 356.1 |
|
| 27.2 |
|
| (0.3) |
Net change in cash |
| $ | (2.0) |
| $ | 1.9 |
| $ | (42.7) |
| 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.activities.For the year ended December 31, 2013,2014, net cash provided by operating activities was $54.3$94.4 million,, compared to $51.3$54.5 million for the same period in 2012.2013. The increase was related primarily due to a 15%decreasean increase in lease operating expenses coupled with a 3%oil sales and an increase in gains on the average sales price on an equivalent basissettlement of derivative contracts, partially offset by lower revenues as oilan increase in production taxes and natural gas production decreased 7% and 16%, respectively.lease operating expense. Production and realized prices are discussed below in Results of Operations. See Notes 6 and 7 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.
Investing Activities. activities. For the year ended December 31, 2013,2014, net cash used in investing activities was $79.8$452.5 million as compared to $93.7$79.8 million for the same period in 2012. The net $13.9 milliondecrease in2013. Net cash used in investing activities isduring the year included $232.6 million in capital expenditures (not including acquisition costs), an increase of $72.9 million over 2013, primarily attributable to our drilling and completion activities in the Permian Basin, driven by the addition of a $50.1second horizontal drilling rig in August 2013. Net cash used in investing activities also included $222.9 million in acquisition costs, an increase inof $212.0 million over 2013. Net cash provided by investing activities included proceeds of $3.0 million received from the sale of mineral interestscertain properties and equipment, offset by a 26.4an $87.0 million increase in capital expenditures related to development activity on our Permian basin acreage and $10.9 million for producing property acquisitions. The $50.1 million increase in the previously mentioned proceeds relates decrease compared to the proceedssame period in 2013, when the Company received proceeds of $90.0$90.0 million, primarily attributable to from the sale of our Medusa and our other offshore properties compared to proceedsproperties. See Note 3 in 2012 of $39.9 million, primarily relatedthe Footnotes to the sale of our Habanero offshore property, which are both discussed belowFinancial Statements for additional information on acquisitions and in Note 12 to the financial statements. The dispositions.$26.4 millionincrease in capital expenditures included the costs associated with expanding to a two-rig drilling program and the acquisition of the Garrison Draw property.
| Gross Wells | ||||||||
| Category | ($ millions) | Drill | Complete | |||||
| Horizontal wells | $ | 155 | 27 | 26 | ||||
| Vertical wells | 15 | 9 | 8 | |||||
| Facilities and equipment | 15 | |||||||
| Total operational capital | $ | 185 | ||||||
43
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of |
2015 Capital Plan
In early February 2015, we announced an operational capital budget for 2015 in the range of $150 to four fields$165 million. This represents a reduction of approximately 25%-30% to the comparable 2014 budgeted amounts in late 2013, adding Carpe Diem in Midland Countyresponse to a lower oil and Garrison Draw in Reagan County. natural gas price environment.
We expect our 20142015 horizontal drilling program will be primarily focused on program development of established Upper and Lower Wolfcamp B zones and the Lower Spraberry zones in the Southern and Central Midland Basin but will also include two wells in the Southern Midland Basinwith lateral lengths ranging from approximately 5,000’ 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.
In addition to the operational capital expenditures above, we budgeted approximately $25$17.2 million for capitalized general and administrative expenses and certain retained plugging and abandonment expenses related to divested Gulf of Mexico shelf assets.
We are the operator for approximately 95% of our 2015 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 currently expect to fund our 20142015 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, 2013,2014, net cash provided by financing activities was $27.3$356.1 million compared to cash usedprovided by financing activities of $0.3$27.2 million during the same period of 2012.2013. Net cash provided by financing activities for 2013during the year ended December 31, 2014 included $122.5 million of net proceeds from the issuance of $70.4 million, net from our Preferred Stock offering (see Note 9 for additional information)common stock and a $12net $291.6 million draw, netof borrowings on our Credit Facility and Second Lien Loan, offset by the $50a $50.1 million redemption of our Senior Notes, andNotes. In addition, the Company paid approximately $4.6$7.9 million in preferred stock dividends. See Notes 5 and 10 in the Footnotes to the Financial Statements for additional information about the Company’s debt and equity offering.
Senior Securedsecured revolving credit facility (“Credit Facility”)
On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility (“Credit Facility”)
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, weCompany entered into a senior secured second lien term loan facility (the “Second Lien Facility”) in an aggregate amount of up to $125 million, including initial commitments of $100 million and additional availability of $25 million subject to the consent of two-thirds of the lenders and compliance with J.P. Morgan as Administrative Agent and withfinancial covenants after giving effect to such increase. The term loan had a maturity date of September 11, 2019. See
On October 8, 2014, the
44
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of |
prepayment amount is (i) 102% if the prepayment event occurs prior to October 8, 2015, and (ii) 101% if the prepayment event occurs on or after October 8, 2015 but before October 8, 2016, and (iii) 100% for prepayments made on or after October 8, 2016. The Second Lien Loan is secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders.
13% Senior Notes due 2016 (the “Senior Notes”) and deferred credit
On April 11, 2014, the Company completed the full redemption of the remaining $48.5 million principal amount of outstanding Senior Notes using proceeds from the term loan issued on March 11, 2014. The redemption resulted in a net $3.2 million gain on the early extinguishment of debt (including $4.8 million of accelerated deferred credit amortization). The gain represents the difference between the $50.1 million paid for the redemption of the Senior Notes ($1.6 million of redemption costs, primarily the call premium) and the carrying value of the remaining Senior Notes of $53.3 million (inclusive of $4.8 million of deferred credit). The Company also paid $0.2 million in accrued interest through the redemption date. Upon the redemption, the indenture governing the Senior Notes was discharged in accordance with its terms.
Common Stock Offering
On September 15, 2014, the Company completed an equity offering for $129.4 million in gross proceeds. The offering consisted of 12,500,000 shares of the Company’s common stock at a price to the public of $9.00 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,875,000 additional shares of common stock at $9.00 per share. See Note 10 in the Footnotes to the Financial Statements for additional information about the Company’s equity offering.
Contractual Obligations
The following table includes the Company’s current contractual obligations and purchase commitments, at which time the Company had no product delivery commitments:
|
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|
| Payments due by Period | |||||||||||||
|
| Total |
| < 1 Year |
| Years 2 - 3 |
| Years 4 - 5 |
| >5 Years | |||||
Second Lien Loan |
| $ | 300,000 |
| $ | — |
| $ | — |
| $ | — |
| $ | 300,000 |
Credit Facility |
|
| 35,000 |
|
| — |
|
| — |
|
| 35,000 |
|
| — |
Drilling rig leases and related (a) |
|
| 45,333 |
|
| 16,893 |
|
| 21,930 |
|
| 6,510 |
|
| — |
Office space lease and other commitments |
|
| 3,130 |
|
| 637 |
|
| 1,219 |
|
| 855 |
|
| 419 |
Total |
| $ | 383,463 |
| $ | 17,530 |
| $ | 23,149 |
| $ | 42,365 |
| $ | 300,419 |
| (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 |
Income Taxes
The Company’s income tax expense varies from the statutory rate primarily due to the effect of state income taxes non deductibleand non-deductible executive 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 million in 2011 resulted primarily from the reversal of the valuation allowance established in 2008 against our net deferred tax assets.expenses. For additional information, see the Income Tax discussion included below in Results of Operations and
45
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of |
Results of Operations
The following table sets forth certain unaudited operating information with respect to the Company’s oil and natural gas operations for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | ||||||||||||||||||
|
|
| 2014 |
|
| 2013 |
|
| Change |
| % Change |
| 2012 |
| Change |
| % Change | |||
Net production: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
| 1,692 |
|
| 911 |
|
| 781 |
| 86% |
|
| 977 |
|
| (66) |
|
| (7)% |
Natural gas (MMcf) |
|
| 2,220 |
|
| 3,011 |
|
| (791) |
| (26)% |
|
| 3,588 |
|
| (577) |
|
| (16)% |
Total (MBOE) |
|
| 2,062 |
|
| 1,413 |
|
| 649 |
| 46% |
|
| 1,575 |
|
| (162) |
|
| (10)% |
Average daily production (BOE/d) |
|
| 5,648 |
|
| 3,871 |
|
| 1,777 |
| 46% |
|
| 4,303 |
|
| (432) |
|
| (10)% |
% oil (BOE basis) |
|
| 82% |
|
| 64% |
|
|
|
|
|
|
| 62% |
|
|
|
|
|
|
Average realized sales price: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) (excluding impact of cash settled derivatives) |
| $ | 82.37 |
| $ | 97.65 |
| $ | (15.28) |
| (16)% |
| $ | 97.41 |
| $ | 0.24 |
|
| — |
Oil (Bbl) (including impact of cash settled derivatives) |
|
| 84.85 |
|
| 99.32 |
|
| (14.46) |
| (15)% |
|
| 98.86 |
|
| 0.46 |
|
| — |
Natural gas (Mcf) (excluding impact of cash settled derivatives) |
| $ | 5.63 |
| $ | 4.52 |
| $ | 1.11 |
| 24% |
| $ | 3.94 |
| $ | 0.58 |
|
| 15% |
Natural gas (Mcf) (including impact of cash settled derivatives) |
|
| 5.59 |
|
| 4.47 |
|
| 1.12 |
| 25% |
|
| 3.94 |
|
| 0.53 |
|
| 13% |
Total (BOE) (excluding impact of cash settled derivatives) |
| $ | 73.65 |
| $ | 72.59 |
| $ | 1.06 |
| 1% |
| $ | 69.43 |
| $ | 3.16 |
|
| 5% |
Total (BOE) (including impact of cash settled derivatives) |
|
| 75.64 |
|
| 73.56 |
|
| 2.08 |
| 3% |
|
| 70.41 |
|
| 3.15 |
|
| 4% |
Oil and natural gas revenues (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue |
| $ | 139,374 |
| $ | 88,960 |
| $ | 50,414 |
| 57% |
| $ | 96,584 |
| $ | (7,624) |
|
| (8)% |
Natural gas revenue |
|
| 12,488 |
|
| 13,609 |
|
| (1,121) |
| (8)% |
|
| 14,149 |
|
| (540) |
|
| (4)% |
Total |
| $ | 151,862 |
| $ | 102,569 |
| $ | 49,293 |
| 48% |
| $ | 110,733 |
| $ | (8,164) |
|
| (7)% |
Additional per BOE data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales price |
| $ | 73.65 |
| $ | 72.59 |
| $ | 1.06 |
| 1% |
| $ | 69.43 |
| $ | 3.16 |
|
| 5% |
Lease operating expense |
|
| 10.85 |
|
| 14.00 |
|
| (3.15) |
| (23)% |
|
| 14.81 |
|
| (0.81) |
|
| (5)% |
Production taxes |
|
| 4.35 |
|
| 2.92 |
|
| 1.43 |
| 49% |
|
| 2.05 |
|
| 0.87 |
|
| 42% |
Operating margin |
| $ | 58.45 |
| $ | 55.67 |
| $ | 2.78 |
| 5% |
| $ | 52.57 |
| $ | 3.10 |
|
| 6% |
| For the Year Ended December 31, | |||||||||||||||||||||||||
| 2013 | 2012 | Change | % Change | 2011 | Change | % Change | |||||||||||||||||||
| Net production: | |||||||||||||||||||||||||
| Oil (MBbls) | 911 | 977 | (66 | ) | (7 | )% | 996 | (19 | ) | (2 | )% | ||||||||||||||
| Natural gas (MMcf) | 3,011 | 3,588 | (577 | ) | (16 | )% | 5,081 | (1,493 | ) | (29 | )% | ||||||||||||||
| 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): | |||||||||||||||||||||||||
| Oil (Bbl) | $ | 97.65 | $ | 98.86 | $ | (1.21 | ) | (1 | )% | $ | 101.34 | $ | (2.48 | ) | (2 | )% | |||||||||
| Natural gas (Mcf) | 4.52 | 3.94 | 0.58 | 15 | % | 5.25 | (1.31 | ) | (25 | )% | |||||||||||||||
| 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 | 13,609 | 14,149 | (540 | ) | (4 | )% | 26,682 | (12,533 | ) | (47 | )% | ||||||||||||||
| Total | $ | 102,569 | $ | 110,733 | $ | (8,164 | ) | (7 | )% | $ | 127,644 | $ | (16,911 | ) | (13 | )% | |||||||||
| Additional per BOE data: | |||||||||||||||||||||||||
| Sales price | $ | 72.59 | $ | 70.31 | $ | 2.28 | 3 | % | $ | 69.26 | $ | 1.05 | 2 | % | |||||||||||
| Lease operating expense | (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 | $ | 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 Bbl of oil and Mcf of natural gas: | |||||||||||||||||||||||||
| Average NYMEX oil price ($/Bbl) | $ | 97.96 | $ | 94.19 | $ | 3.77 | 4 | % | $ | 95.14 | $ | (0.95 | ) | (1 | )% | ||||||||||
| Basis differential and quality adjustments (a) | 0.12 | 3.97 | (3.85 | ) | (97 | )% | 7.58 | (3.61 | ) | (48 | )% | ||||||||||||||
| Transportation | (0.43 | ) | (0.75 | ) | 0.32 | 43 | % | (1.00 | ) | 0.25 | (25 | )% | |||||||||||||
| Hedging (b) | — | 1.45 | (1.45 | ) | 100 | % | (0.38 | ) | 1.83 | 100 | % | ||||||||||||||
| Average realized oil price ($/Bbl) | $ | 97.65 | $ | 98.86 | $ | (1.21 | ) | (1 | )% | $ | 101.34 | $ | (2.48 | ) | (2 | )% | |||||||||
| Average NYMEX natural gas price ($/MMBtu) | $ | 3.73 | $ | 2.82 | $ | 0.91 | 32 | % | $ | 4.03 | $ | (1.21 | ) | (30 | )% | ||||||||||
| Basis differential and quality adjustments (c) | 0.79 | 1.12 | (0.33 | ) | (29 | )% | 1.22 | (0.10 | ) | (8 | )% | ||||||||||||||
| Average realized natural gas price ($/Mcf) | $ | 4.52 | $ | 3.94 | $ | 0.58 | 15 | % | $ | 5.25 | $ | (1.31 | ) | (25 | )% | ||||||||||
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 changesand in the underlying commodity prices, andas well as the impact of our hedge program. (in thousands)program for the year ended December 31, 2012 when we had designated our derivative contracts as accounting hedges.
|
|
|
|
|
|
|
|
|
|
(in thousands) |
| Oil |
| Natural Gas |
| Total | |||
Revenues for the year ended December 31, 2011 |
| $ | 100,962 |
| $ | 26,682 |
| $ | 127,644 |
Volume increase (decrease) |
|
| (1,926) |
|
| (7,840) |
|
| (9,766) |
Price increase (decrease) |
|
| (3,872) |
|
| (4,693) |
|
| (8,565) |
Impact of hedges |
|
| 1,420 |
|
| — |
|
| 1,420 |
Net increase (decrease) in 2012 |
|
| (4,378) |
|
| (12,533) |
|
| (16,911) |
Revenues for the year ended December 31, 2012 |
| $ | 96,584 |
|
| 14,149 |
|
| 110,733 |
Volume increase (decrease) |
|
| (6,528) |
|
| (2,278) |
|
| (8,806) |
Price increase (decrease) |
|
| (1,096) |
|
| 1,738 |
|
| 642 |
Net increase (decrease) in 2013 |
|
| (7,624) |
|
| (540) |
|
| (8,164) |
Revenues for the year ended December 31, 2013 |
| $ | 88,960 |
| $ | 13,609 |
| $ | 102,569 |
Volume increase (decrease) |
|
| 76,237 |
|
| (3,575) |
|
| 72,662 |
Price increase (decrease) |
|
| (25,823) |
|
| 2,454 |
|
| (23,369) |
Net increase (decrease) in 2014 |
|
| 50,414 |
|
| (1,121) |
|
| 49,293 |
Revenues for the year ended December 31, 2014 |
| $ | 139,374 |
| $ | 12,488 |
| $ | 151,862 |
46
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation |
| Oil | Natural Gas | Total | ||||||||||
| Revenues for the year ended December 31, 2010 | $ | 65,243 | $ | 24,639 | $ | 89,882 | ||||||
| Volume increase | 10,406 | 952 | 11,358 | |||||||||
| Price increase | 25,688 | 1,091 | 26,779 | |||||||||
| Impact of hedges decrease | (375 | ) | — | (375 | ) | |||||||
| Net increase in 2011 | 35,719 | 2,043 | 37,762 | |||||||||
| Revenues for the year ended December 31, 2011 | $ | 100,962 | $ | 26,682 | $ | 127,644 | ||||||
| Volume decrease | (1,926 | ) | (7,840 | ) | (9,766 | ) | ||||||
| Price decrease | (3,872 | ) | (4,693 | ) | (8,565 | ) | ||||||
| Impact of hedges increase | 1,420 | — | 1,420 | |||||||||
| Net decrease in 2012 | (4,378 | ) | (12,533 | ) | (16,911 | ) | ||||||
| Revenues for the year ended December 31, 2012 | $ | 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 | ||||||
Oil Revenue
For the year ended
December 31,For the year ended
December 31,Natural gas revenue (including NGLs)
Natural gas revenues of $12.5 million decreased $1.1 million, or 8%, during the year ended December 31, 2012, oil2014 compared to $13.6 million for the same period of 2013.The average realized price increased to $5.63 per Mcf from $4.52 per Mcf, or 24%, while total production decreased 26%. The decrease in production was primarily attributable to a 1,919 MMcf decrease in production due to the sale of our offshore fields and Haynesville property in the fourth quarter of 2013. Offsetting the production decline was a 1,128 MMcf increase in production from our Permian properties resulting from an increased number of producing wells as mentioned above.
Natural gas revenues of $96.6$13.6 million decreased $4.4$0.5 million, or 4%, compared to revenues of $101.0 million forduring the year ended December 31, 2011. A decrease in commodity prices and production resulted in decreased oil revenue. The average price realized decreased 2% to $98.86 per barrel2013 compared to $101.34$14.1 million for the same period of 2011. Similarly, production decreased by 2% to 977 MBbls compared to 996 MBbls during the same period in 2011. 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 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.
47
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation |
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | ||||||||||||||||||
|
|
|
|
| Per |
|
|
|
| Per |
| Total Change |
| BOE Change | ||||||
|
| 2014 |
| BOE |
| 2013 |
| BOE |
| $ |
| % |
| $ |
| % | ||||
Lease operating expenses |
| $ | 22,372 |
| $ | 10.85 |
| $ | 19,779 |
| $ | 14.00 |
| 2,593 |
| 13% |
| (3.15) |
| (22)% |
Production taxes |
|
| 8,973 |
|
| 4.35 |
|
| 4,133 |
|
| 2.92 |
| 4,840 |
| 117% |
| 1.43 |
| 49% |
Depreciation, depletion and amortization |
|
| 56,724 |
|
| 27.51 |
|
| 43,967 |
|
| 31.12 |
| 12,757 |
| 29% |
| (3.61) |
| (12)% |
General and administrative |
|
| 25,109 |
|
| 12.18 |
|
| 20,534 |
|
| 14.53 |
| 4,575 |
| 22% |
| (2.35) |
| (16)% |
Accretion expense |
|
| 826 |
|
| 0.40 |
|
| 1,785 |
|
| 1.26 |
| (959) |
| (54)% |
| (0.86) |
| (68)% |
Gain on sale of other property and equipment |
|
| (1,080) |
|
| (0.52) |
|
| — |
|
| — |
| (1,080) |
| — |
| (0.52) |
| — |
Impairment of other property and equipment |
|
| — |
|
| — |
|
| 1,707 |
|
| 1.21 |
| (1,707) |
| (100)% |
| (1.21) |
| (100)% |
Acquisition expense |
|
| 668 |
|
| 0.32 |
|
| — |
|
| — |
| 668 |
| — |
| 0.32 |
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | ||||||||||||||||||
|
|
|
|
| Per |
|
|
|
| Per |
| Total Change |
| BOE Change | ||||||
|
| 2013 |
| BOE |
| 2012 |
| BOE |
| $ |
| % |
| $ |
| % | ||||
Lease operating expenses |
| $ | 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 |
|
| 43,967 |
|
| 31.12 |
|
| 49,701 |
|
| 31.56 |
| (5,734) |
| (12)% |
| (0.44) |
| (1)% |
General and administrative |
|
| 20,534 |
|
| 14.53 |
|
| 20,358 |
|
| 12.93 |
| 176 |
| 1% |
| 1.60 |
| 12% |
Accretion expense |
|
| 1,785 |
|
| 1.26 |
|
| 2,253 |
|
| 1.43 |
| (468) |
| (21)% |
| (0.17) |
| (12)% |
Impairment of other property and equipment |
|
| 1,707 |
|
| 1.21 |
|
| 1,177 |
|
| 0.75 |
| 530 |
| 45% |
| 0.46 |
| 61% |
Lease operating expenses.expenses (“LOE”). These are daily costs incurred to bringextract oil and natural gas out of the ground and deliver 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.
LOE for the year ended December 31, 2014 increased by 13% to $22.4 million compared to $19.8 million for the same period of 2013primarily due to $9.7 million in costs related to the growth in Permian production and operations, including an increase in workover expenses associated with the impact of accelerated horizontal well activity on surrounding producing wells. These increases were partially offset by a decrease in costs of $7.1 million resulting from the sale of our deep water Medusa field and our other offshore fields. LOE per BOE for the year ended December 31, 2014 decreased by 22% to $10.85 per BOE from $14.00 per BOE for the same period of 2013. The 22% decrease is primarily attributable to a 46% increase in production while keeping expenses in line.
LOE for the year ended December 31, 2013 decreased by 15% to $19.8 million compared to $23.3 million for the same period of 2012. The decrease was primarily due to $3.4 million of remediation costs on our Haynesville property in 2012, for which we had no similar costs in 2013, and an estimated decrease of $3.2 million of LOE resulting from the sale of our interests in Habanero, Medusa, the Medusa Spar facilities, 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.
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 our oil and gas properties.
For the year ended December 31, 2014, production taxes increased 117%, or $4.9 million, to $9.0 million compared to $4.1 million for the same period of 2013. The increase was predominantly attributable to an increase in onshore production subject to these taxes accompanied by a decline in offshore production, resulting from the sale of our Gulf of Mexico position in 2013, which was exempt from production taxes.
For the year ended December 31, 2013 production taxes of $4.1 million increased 28%, or $0.9 million, compared to $3.2 million for the same period of 2012. The increase was predominantly attributable to the previously mentioned increase in onshore production
48
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation |
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.
Depreciation, depletion and amortization.amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of productionunits-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unprovedunevaluated properties, and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the estimated 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.
For the year ended December 31, 2014, DD&A increased 29% from $44.0 million compared to $56.7 million for the same period of 2013. The increase is primarily attributable to a 46% increase in production, offset by a 12% decrease in our per BOE DD&A rate. For the year ended December 31, 2014, DD&A on a per unit basis decreased to $27.51 per BOE compared to $31.12 per BOE for the same period of 2013 as a result of our increase in our estimated proved reserves relative to our depreciable base as a result of our efforts on development, exploration, and exploitation of onshore oil and natural gas reserves in the Permian Basin.
For the year ended December 31, 2013, DD&A of $31.12 per BOE remained relatively flat compared to $31.56 per BOE for the same period of 2012.
General and administrative, net of amounts capitalized (“G&A”). . These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, depreciation of corporate level assets, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other fees for professional services and legal compliance.
G&A for the year ended December 31, 2014 increased to $25.1 million (including $3.1 million in fair value adjustment of cash-settled RSU awards) compared to $20.5 million (including $2.9 million in fair value adjustment of cash-settled RSU awards) for the same period of 2013. The increase was primarily related to the following items:
· | $1.4 million in non-recurring, cash expenses related to a threatened proxy contest incurred in 2014 |
· | $2.5 million in non-recurring expenses (both cash and non-cash components) primarily related to the accelerated vesting of outstanding equity awards for early retirement of employees |
· | an increase of $0.2 million related to the fair value adjustment of cash-settled RSU awards |
G&A for the year ended December 31, 2013 remained relatively flat at $20.5 million (including $2.9 million in fair value adjustment of cash-settled RSU awards) compared to $20.4 million (including $1.6 million in fair value adjustment of cash-settled RSU awards) for the same period of 2012. The $0.1 million increase was related to the following items:
· | an increase of $1.3 million related to the fair value adjustment of cash-settled RSU awards |
· | a decrease of $1.6 million primarily related to non-recurring employee-related expenses including early retirement and severance expense incurred in 2012 |
Accretion expense.The Company is required to record its estimate of the estimated 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 (“ARO”) and reported as accretion expense within operating expenses in the consolidated statements of operations.
Accretion expense related to our ARO decreased 54% for the year ended December 31, 2014 compared to the same period of 2013. The decrease in accretion expense correlates with the Company’s average ARO, which was $6.5 million during 2014 versus $11.5 million during 2013. The reduction in our average ARO was primarily a result of the divestiture of our offshore fields in the fourth quarter of 2013. See Note 12 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO.
49
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of |
| For the Year Ended December 31, | ||||||||||||||||||||||||||||||
| Total Change | BOE Change | |||||||||||||||||||||||||||||
| 2013 | Per BOE | 2012 | Per BOE | $ | % | $ | % | |||||||||||||||||||||||
| Lease operating expenses | $ | 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 | 43,967 | 31.12 | 49,701 | 31.56 | (5,734 | ) | (12 | )% | (0.44 | ) | (1 | )% | ||||||||||||||||||
| General and administrative | 20,534 | 14.53 | 20,358 | 12.93 | 176 | 1 | % | 1.6 | 12 | % | ||||||||||||||||||||
| Accretion expense | 1,785 | 1.26 | 2,253 | 1.43 | (468 | ) | (21 | )% | (0.17 | ) | (12 | )% | ||||||||||||||||||
| Impairment of other property and equipment | 1,707 | 1.21 | 1,177 | 0.75 | 530 | 45 | % | 0.46 | 100 | % | ||||||||||||||||||||
| Total operating expenses | $ | 91,905 | $ | 100,043 | ||||||||||||||||||||||||||
| For the Year Ended December 31, | ||||||||||||||||||||||||||||||
| Total Change | BOE Change | |||||||||||||||||||||||||||||
| 2012 | Per BOE | 2011 | Per BOE | $ | % | $ | % | |||||||||||||||||||||||
| Lease operating expenses | $ | 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 | 49,701 | 31.56 | 48,701 | 26.42 | 1,000 | 2 | % | 5.14 | 19 | % | ||||||||||||||||||||
| General and administrative | 20,358 | 12.93 | 16,636 | 9.03 | 3,722 | 22 | % | 3.90 | 43 | % | ||||||||||||||||||||
| Accretion expense | 2,253 | 1.43 | 2,338 | 1.27 | (85 | ) | (4 | )% | 0.16 | 13 | % | |||||||||||||||||||
| Impairment of other property and equipment | 1,177 | 0.75 | — | — | 1,177 | 100 | % | 0.75 | 100 | % | ||||||||||||||||||||
| Total operating expenses | $ | 100,043 | $ | 88,022 | ||||||||||||||||||||||||||
Accretion expense related to the growth in Permian production and operations, including an increase in workover expenses associated with accelerated horizontal well activity.
Acquisition expense
Acquisition expense of $0.7 million for the year ended December 31, 2011. The increase was primarily due2014 relates to $3.0 million inacquisition related costs relatedwith respect to growthour acquisition efforts in the numberPermian Basin. See Note 3 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.
Gain on sale of wells producing from Permian Basin propertiesother property and $3.3 millionequipment
See Note 14 in remediation work at our Haynesville well in 2012the Footnotes to the Financial Statements 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 resultdiscussion of reduced production volumes.
Impairment of Mexico positionother property and equipment
See Note 14 in 2013, which is exempt from production taxes.
50
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of |
Other Income and Amortization (DD&A)
Interest 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 our lender in interest expense.expense, net of capitalized amounts. In addition, we include the amortization 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 our 13% Senior Notes iswas recorded as an offset to interest expense.
Gain/Loss on derivative instrumentsinstruments.. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of oil.oil and natural gas. This amount represents the (i) gain (loss) related to derivatives, net of settlement that relate tofair value adjustments on 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 summationsettlements of gains and losses onderivative contracts for positions that have settled within the period. We provide a reconciliation of the these components of the gain/loss on derivative contracts in Note 55..
Income tax expense.We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | |||||||||
|
| 2014 |
| 2013 |
|
| $ Change |
| % Change | ||
Interest expense |
| $ | 9,772 |
| $ | 6,094 |
| $ | 3,678 |
| 60% |
Gain on early extinguishment of debt |
|
| (151) |
|
| (3,696) |
|
| 3,545 |
| (96)% |
(Gain) loss on derivative contracts |
|
| (31,736) |
|
| 1,360 |
|
| (33,096) |
| (2,434)% |
Other income, net |
|
| (515) |
|
| (485) |
|
| (30) |
| 6% |
Total |
| $ | (22,630) |
| $ | 3,273 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense |
| $ | 23,134 |
| $ | 3,104 |
| $ | 20,030 |
| 645% |
Equity in earnings of Medusa Spar LLC |
|
| — |
|
| 17 |
|
| (17) |
| (100)% |
Preferred stock dividends |
|
| (7,895) |
|
| (4,627) |
|
| (3,268) |
| 71% |
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | |||||||||
|
| 2013 |
| 2012 |
|
| $ Change |
| % Change | ||
Interest expense |
| $ | 6,094 |
| $ | 9,108 |
|
| (3,014) |
| (33)% |
Gain on early extinguishment of debt |
|
| (3,696) |
|
| (1,366) |
|
| (2,330) |
| 171% |
Loss (gain) on derivative contracts |
|
| 1,360 |
|
| (1,717) |
|
| 3,077 |
| (179)% |
Other income, net |
|
| (485) |
|
| (79) |
|
| (406) |
| 514% |
Total |
| $ | 3,273 | - | $ | 5,946 | - |
|
| - |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense |
| $ | 3,104 |
| $ | 2,223 |
| $ | 881 |
| (40)% |
Equity in earnings of Medusa Spar LLC |
|
| 17 |
|
| 226 |
|
| (209) |
| (92)% |
Preferred stock dividends |
|
| (4,627) |
|
| — |
|
| (4,627) |
| — |
| 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
51
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation |
Interest expense incurred during the year ended December 31, 2013 decreased $3.0 million to $6.1 million compared to $9.1 million for the same period of 2012. The decrease was related primarily to an additional
(Gain) loss on Callon’searly extinguishment of debt obligations decreased 22% to $9.1 million for
During April 2014, the year ended December 31, 2012 compared to $11.7 million for the same period of 2011. The decrease was related primarily to theCompany completed a full redemption of $10the remaining $53.3 million principalcarrying value of its outstanding Senior Notes during June 2012using proceeds from the issuance of a secured second lien term loan. The carrying value included $48.5 million of principal value and $4.8 million of unamortized deferred credit. The Company recognized a net $3.2 million gain on early extinguishment of debt, comprised of the recognition of $4.8 million in addition to a $1.5 million increase in capitalized interest compared to 2011, partiallydeferred credit, offset by interest expense related to increased borrowings under our Credit Facility$1.6 million of redemption expenses. See Note 5 for additional information concerning the gain on early extinguishment of debt.
During October 2014, the Company repaid in full the existing term loan using proceeds from the Second Lien Loan resulting in a loss on early extinguishment of debt of $3.1 million. The loss was comprised of a $1.7 million prepayment premium 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.
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
Loss (gain) on Acquired Equipment
For the year ended
December 31,For the year ended December 31, 2013, the net loss on derivative instruments was $1.4 million, compared to a $1.7 million net gain in 2012.
Income Tax Expense (Benefit)
The effective tax rate of 38% in 2014 and 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 executive compensation under Section 162(m)expenses and restricted stock offset by percentage depletion. See
Preferred Stock Dividends
Preferred Stockstock dividends for the year ended December 31, 20132014 increased
52
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation |
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.used. 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.
Oil and Equipment
The Company utilizes the full-costfull 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“full cost pool.” The amounts capitalized into the full-costfull cost pool are depleted (charged against earnings) using the unit-of-production method. The full-costfull 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, Depletiondepletion and Amortizationamortization (DD&A) of Oiloil and Natural Gas Properties
The Company calculates depletionDD&A by using the depletable base, which is equal to the net capitalized costs in our full-costfull cost pool plus estimated future development costs, and the estimated net proved reserve quantities. Capitalized costs added to the full-costfull 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 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 oil and natural gas properties as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized costs do not include any costs related to the production of 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 or management 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 BOE produced during the period, the Company records a DD&A 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. |
53
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of |
Because the Company uses estimates and assumptions to calculatedetermine 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 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 oil and natural gas properties exceed the estimated discounted (at a 10%) annualized rate) future net cash flows from proved reserves, the Company is required to write-down the value of its 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.assumption. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimates of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices remain at current levels or decline significantly,further, even if only for a short period of time, it is possible that write-downs of oil and natural gas properties could occur in the future. See
Estimating Reservesreserves and Present Valuepresent value of Estimated Future Net Cash Flows
Estimates of quantities of proved 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 oil and natural gas production in the future. Oil and natural gas prices are volatile, but we are required to assume that they remain constant, using the twelve-month average pricing assumption. In general, higher 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, but we are required to assume that they remain constant. Increases in costs will reduce estimated 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.
In addition, the process of estimating proved 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 oil and natural gas prices under “Risk Factors.”
Sales of 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.properties.” UnprovedUnevaluated property costs are transferred to the depletable base when wells are completed on the properties or the properties are sold.management determines that these costs have been impaired. In addition, the Company is required to determine whether its unprovedunevaluated properties are impaired and, if so, include the costs of such properties in the depletable base. The Company determines whether an unprovedunevaluated 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.
54
Callon Petroleum Company | Management’s Discussion and Analysis of Financial Condition and Results of Operation |
Asset Retirement Obligations
We are required to record itsour 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 obligationobligations and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. See
Derivatives
To manage 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% to 75% 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.
We elected to no longer designate derivative contracts executed after January 1, 2012 as accounting hedges under FASB ASC 815-20-25. Asand as such and beginning with derivative contracts executed during 2012, allour derivative positions are carried at their fair value on the balance sheet and are marked-to-marketwith changes in fair value recorded through earnings at the end of each period. 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 gain (loss) on derivative contracts line in the statement of operations are gains (losses) on derivatives, net of settlement and gains (losses) on derivatives, settled.
Derivative contracts that were entered into at and prior to December 31, 2011 were accounted for as cash flow hedges, and were recorded at fair market value on itsour 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 were 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
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 oil and natural gas prices). See
NoteIn May 2014, the FASB issued accounting standards update (“ASU”) No. 2014-09, Revenue from Contracts with Customers. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. The guidance in ASU No. 2014-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. Early adoption is not permitted. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.
55
Various accounting standards and interpretations were issued in Item 7A. Quan2013 with effective dates subsequent to December 31, 2013. We have evaluated the recently issued accounting pronouncements that are effective in 2014 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.
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 rateare derived from the sale of growth are highly dependent on the prices we receive for ourits oil and natural gas which have historically been veryproduction. The prices for oil and natural gas remain extremely volatile due to unpredictable events suchand sometimes experience large fluctuations as economic growth or retraction, weather and climate,a result of relatively small changes in supply, weather conditions, economic conditions and government actions. OilFrom time to time, the Company enters into derivative financial instruments to manage oil and natural gas price declinesrisk. The total volumes which we hedge through the use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately 50% to 75% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and volatility could adversely affect the Company’s revenues, cash flowsobjectives may change significantly with movements in commodities prices or futures prices, in addition to modification of our capital spending plans related to operational activities and profitability. Price volatility isacquisitions.
As of February 27, 2015, we had commodity contracts covering approximately 63% and 62% of our expected to continue. Using the Company’s annual sales volumes for
The Company may utilize fixed price rises above the ceiling, Callon pays the difference to the counterparty. Fixed price swaps, which reduce the Company’s exposure to decreases in commodity prices while simultaneously limitingand limit the benefit the Company might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales. Additionally, the Company may sell put options or call options in conjunction with a swap and use the proceeds to increase the fixed price received.
The Company’s derivatives policy also allows CallonCompany may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counterparty receives the difference from the Company. Additionally, the Company may sell put options at its discretion,a price lower than the floor price in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices.
The Company may purchase or sell puts. Purchased putsput options, which reduce the Company’s exposure to decreases in oil and natural gas prices of the hedged commodity while allowing realization of the full benefit from any increases thosein oil and natural gas prices. If the commodity price falls below the put price,floor, the counter-partycounterparty pays the difference to Callon. Conversely, sold puts expose the Company.
The Company enters into these various agreements from time to risk whereby Callon would pay its counter-party iftime to reduce the effects of volatile oil and natural gas prices fall belowand does not enter into derivative transactions for speculative purposes. Presently, none of the put price. See
Interest rate risk
On December 31, 2013
56
Counterparty and Customer Credit Risk
The Company’s 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 marketjoint interest receivables and receivables resulting from derivative financial contracts.
The Company markets receivables from the sale of our oil and natural gas production to energy marketing companies.
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 have or intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2014 our joint interest receivables were approximately $6.9 million.
At December 31, 2014 our receivables resulting from derivative financial contracts waswere approximately
57
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.
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58
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, 20132014 and 2012,2013, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2013.2014. These financial statements are the responsibility of the Company’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, 20132014 and 2012,2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013,2014, 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, 2013,2014, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992(2013 framework) and our report dated
/s/Ernst & Young LLP
New Orleans, Louisiana
March 12, 2014
59
Part I. Financial Information
Item I. Financial Statements
Callon Petroleum Company
(Inin thousands, except par and per share values and share data)
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| December 31, 2014 |
| December 31, 2013 | ||
ASSETS |
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Current assets: |
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|
|
Cash and cash equivalents | $ | 968 |
| $ | 3,012 |
Accounts receivable |
| 30,198 |
|
| 20,586 |
Deferred tax asset |
| — |
|
| 3,843 |
Fair value of derivatives |
| 27,850 |
|
| 60 |
Other current assets |
| 1,441 |
|
| 2,063 |
Total current assets |
| 60,457 |
|
| 29,564 |
Oil and natural gas properties, full cost accounting method: |
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|
|
Evaluated properties |
| 2,077,985 |
|
| 1,701,577 |
Less accumulated depreciation, depletion and amortization |
| (1,478,355) |
|
| (1,420,612) |
Net oil and natural gas properties |
| 599,630 |
|
| 280,965 |
Unevaluated properties |
| 142,525 |
|
| 43,222 |
Total oil and natural gas properties |
| 742,155 |
|
| 324,187 |
Other property and equipment, net |
| 7,118 |
|
| 7,255 |
Restricted investments |
| 3,810 |
|
| 3,806 |
Deferred tax asset |
| 44,688 |
|
| 57,765 |
Deferred financing costs |
| 18,200 |
|
| 1,098 |
Other assets, net |
| 342 |
|
| 278 |
Total assets | $ | 876,770 |
| $ | 423,953 |
LIABILITIES AND STOCKHOLDERS’ EQUITY |
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Current liabilities: |
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Accounts payable and accrued liabilities | $ | 76,753 |
| $ | 53,447 |
Accrued interest |
| 5,993 |
|
| 17 |
Cash-settled restricted stock unit awards |
| 3,856 |
|
| 4,173 |
Asset retirement obligations |
| 4,747 |
|
| 4,120 |
Deferred tax liability |
| 6,214 |
|
| — |
Fair value of derivatives |
| 1,249 |
|
| 1,036 |
Total current liabilities |
| 98,812 |
|
| 62,793 |
13% senior notes: |
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|
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Principal outstanding |
| — |
|
| 48,481 |
Deferred credit, net of accumulated amortization of $0 and $26,239, respectively |
| — |
|
| 5,267 |
Total 13% senior notes |
| — |
|
| 53,748 |
Senior secured revolving credit facility |
| 35,000 |
|
| 22,000 |
Secured second lien term loan |
| 300,000 |
|
| — |
Asset retirement obligations |
| 1,927 |
|
| 2,612 |
Cash-settled restricted stock unit awards |
| 7,175 |
|
| 3,409 |
Other long-term liabilities |
| 121 |
|
| 297 |
Total liabilities |
| 443,035 |
|
| 144,859 |
Stockholders’ equity: |
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Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,578,948 and 1,578,948 shares outstanding, respectively |
| 16 |
|
| 16 |
Common stock, $0.01 par value, 110,000,000 and 60,000,000 shares authorized; 55,225,288 and 40,345,456 shares outstanding, respectively |
| 552 |
|
| 404 |
Capital in excess of par value |
| 526,162 |
|
| 401,540 |
Accumulated deficit |
| (92,995) |
|
| (122,866) |
Total stockholders’ equity |
| 433,735 |
|
| 279,094 |
Total liabilities and stockholders’ equity | $ | 876,770 |
| $ | 423,953 |
| For the Year Ended December, 31 | |||||||
| 2013 | 2012 | ||||||
| ASSETS | |||||||
| Current assets: | |||||||
| Cash and cash equivalents | $ | 3,012 | $ | 1,139 | |||
| Accounts receivable | 20,586 | 15,608 | |||||
| Fair market value of derivatives | 60 | 1,674 | |||||
| Deferred tax asset, current | 3,843 | — | |||||
| Other current assets | 2,063 | 1,502 | |||||
| Total current assets | 29,564 | 19,923 | |||||
| Oil and natural gas properties, full-cost accounting method: | |||||||
| Evaluated properties | 1,701,577 | 1,497,010 | |||||
| Less accumulated depreciation, depletion and amortization | (1,420,612 | ) | (1,296,265 | ) | |||
| Net oil and natural gas properties | 280,965 | 200,745 | |||||
| Unevaluated properties excluded from amortization | 43,222 | 68,776 | |||||
| Total oil and natural gas properties | 324,187 | 269,521 | |||||
| Other property and equipment, net | 7,255 | 10,058 | |||||
| Restricted investments | 3,806 | 3,798 | |||||
| Investment in Medusa Spar LLC | — | 8,568 | |||||
| Deferred tax asset | 57,765 | 64,383 | |||||
| Other assets, net | 1,376 | 1,922 | |||||
| Total assets | $ | 423,953 | $ | 378,173 | |||
| LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
| Current liabilities: | |||||||
| Accounts payable and accrued liabilities | $ | 57,637 | $ | 36,016 | |||
| Asset retirement obligations | 4,120 | 2,336 | |||||
| Fair market value of derivatives | 1,036 | 125 | |||||
| Total current liabilities | 62,793 | 38,477 | |||||
| 13% Senior Notes: | |||||||
| Principal outstanding | 48,481 | 96,961 | |||||
| Deferred credit, net of accumulated amortization of $20,814 and $17,800, respectively | 5,267 | 13,707 | |||||
| Total 13% Senior Notes | 53,748 | 110,668 | |||||
| Credit facility | 22,000 | 10,000 | |||||
| Asset retirement obligations | 2,612 | 10,965 | |||||
| Other long-term liabilities | 3,706 | 2,092 | |||||
| Total liabilities | 144,859 | 172,202 | |||||
| Stockholders' equity: | |||||||
| 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 | 401,540 | 328,116 | |||||
| Retained deficit | (122,866 | ) | (122,543 | ) | |||
| Total stockholders' equity | 279,094 | 205,971 | |||||
| Total liabilities and stockholders' equity | $ | 423,953 | $ | 378,173 | |||
The accompanying notes are an integral part of these consolidated financial statements.
60
Callon Petroleum Company
(Inin thousands, except per share amounts)data)
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| For the Year Ended December 31, | |||||||
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| 2014 |
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| 2013 |
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| 2012 |
Operating revenues: |
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Oil sales |
| $ | 139,374 |
| $ | 88,960 |
| $ | 96,584 |
Natural gas sales |
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| 12,488 |
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| 13,609 |
|
| 14,149 |
Total operating revenues |
|
| 151,862 |
|
| 102,569 |
|
| 110,733 |
Operating expenses: |
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Lease operating expenses |
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| 22,372 |
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| 19,779 |
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| 23,330 |
Production taxes |
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| 8,973 |
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| 4,133 |
|
| 3,224 |
Depreciation, depletion and amortization |
|
| 56,724 |
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| 43,967 |
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| 49,701 |
General and administrative |
|
| 25,109 |
|
| 20,534 |
|
| 20,358 |
Accretion expense |
|
| 826 |
|
| 1,785 |
|
| 2,253 |
Gain on sale of other property and equipment |
|
| (1,080) |
|
| — |
|
| — |
Impairment of other property and equipment |
|
| — |
|
| 1,707 |
|
| 1,177 |
Acquisition expense |
|
| 668 |
|
| — |
|
| — |
Total operating expenses |
|
| 113,592 |
|
| 91,905 |
|
| 100,043 |
Income from operations |
|
| 38,270 |
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| 10,664 |
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| 10,690 |
Other (income) expenses: |
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Interest expense |
|
| 9,772 |
|
| 6,094 |
|
| 9,108 |
Gain on early extinguishment of debt |
|
| (151) |
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| (3,696) |
|
| (1,366) |
(Gain) loss on derivative contracts |
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| (31,736) |
|
| 1,360 |
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| (1,717) |
Other income |
|
| (515) |
|
| (485) |
|
| (79) |
Total other (income) expense |
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| (22,630) |
|
| 3,273 |
|
| 5,946 |
Income before income taxes |
|
| 60,900 |
|
| 7,391 |
|
| 4,744 |
Income tax expense |
|
| 23,134 |
|
| 3,104 |
|
| 2,223 |
Income before equity in earnings of Medusa Spar LLC |
|
| 37,766 |
|
| 4,287 |
|
| 2,521 |
Equity in earnings of Medusa Spar LLC |
|
| — |
|
| 17 |
|
| 226 |
Net income |
|
| 37,766 |
|
| 4,304 |
|
| 2,747 |
Preferred stock dividends |
|
| (7,895) |
|
| (4,627) |
|
| — |
Income (loss) available to common stockholders |
| $ | 29,871 |
| $ | (323) |
| $ | 2,747 |
Income (loss) per common share: |
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Basic |
| $ | 0.67 |
| $ | (0.01) |
| $ | 0.07 |
Diluted |
| $ | 0.65 |
| $ | (0.01) |
| $ | 0.07 |
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Shares used in computing income (loss) per common share: |
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Basic |
|
| 44,848 |
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| 40,133 |
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| 39,522 |
Diluted |
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| 45,961 |
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| 40,133 |
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| 40,337 |
| 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 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.statements.
61
Callon Petroleum Company
(in thousands)
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| For the Year Ended December 31, | |||||||
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| 2014 |
| 2013 |
| 2012 | |||
Net income |
| $ | 37,766 |
| $ | 4,304 |
| $ | 2,747 |
Other comprehensive income (loss): |
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Change in fair value of derivatives designated as hedges, net of tax |
|
| — |
|
| — |
|
| (1,624) |
Comprehensive income |
|
| 37,766 |
|
| 4,304 |
|
| 1,123 |
Preferred stock dividends |
|
| (7,895) |
|
| (4,627) |
|
| — |
Comprehensive income (loss) available to common shareholders |
| $ | 29,871 |
| $ | (323) |
| $ | 1,123 |
| 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 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
62
Callon Petroleum Company
Consolidated Statem
ents of Stockholders’ Equity
(in thousands)
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| Preferred Stock |
| Common Stock |
| Capital in Excess of Par |
| Accumulated Other Comprehensive Income (Loss) |
| Retained Earnings (Deficit) |
| Total Stockholders' Equity | ||||||
Balance at 12/31/2011 |
| $ | — |
| $ | 394 |
| $ | 324,474 |
| $ | 1,624 |
| $ | (125,290) |
| $ | 201,202 |
Comprehensive income: |
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Net income |
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| — |
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| — |
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| — |
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| — |
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| 2,747 |
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Other comprehensive loss |
|
| — |
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| — |
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| — |
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| (1,624) |
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| — |
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Total comprehensive income |
|
| — |
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| — |
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| — |
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| — |
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| — |
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| 1,123 |
Shares issued pursuant to employee benefit plans |
|
| — |
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| — |
|
| 235 |
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| — |
|
| — |
|
| 235 |
Restricted stock |
|
| — |
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| 4 |
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| 3,407 |
|
| — |
|
| — |
|
| 3,411 |
Balance at 12/31/2012 |
| $ | — |
| $ | 398 |
| $ | 328,116 |
| $ | — |
| $ | (122,543) |
| $ | 205,971 |
Comprehensive income: |
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Net income and comprehensive income |
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| — |
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| — |
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| — |
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| — |
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| 4,304 |
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| 4,304 |
Shares issued pursuant to employee benefit plans |
|
| — |
|
| — |
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| 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 |
Comprehensive income: |
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|
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Net income and comprehensive income |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 37,766 |
|
| 37,766 |
Shares issued pursuant to employee benefit plans |
|
| — |
|
| — |
|
| 262 |
|
| — |
|
| — |
|
| 262 |
Restricted stock |
|
| — |
|
| 4 |
|
| 2,054 |
|
| — |
|
| — |
|
| 2,058 |
Common stock issued |
|
| — |
|
| 144 |
|
| 122,306 |
|
| — |
|
| — |
|
| 122,450 |
Preferred stock dividend |
|
| — |
|
| — |
|
| — |
|
| — |
|
| (7,895) |
|
| (7,895) |
Balance at 12/31/2014 |
| $ | 16 |
| $ | 552 |
| $ | 526,162 |
| $ | — |
| $ | (92,995) |
| $ | 433,735 |
| 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 | ||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
63
Callon Petroleum Company
Consolidated Statem
ents of Cash Flows
(in thousands)
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| For the Year Ended December 31, | |||||||
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| 2014 |
|
| 2013 |
|
| 2012 |
Cash flows from operating activities: |
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Net income |
| $ | 37,766 |
| $ | 4,304 |
| $ | 2,747 |
Adjustments to reconcile net income to cash provided by operating activities: |
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Depreciation, depletion and amortization |
|
| 58,014 |
|
| 45,393 |
|
| 51,043 |
Accretion expense |
|
| 826 |
|
| 1,785 |
|
| 2,253 |
Amortization of non-cash debt related items |
|
| 1,272 |
|
| 471 |
|
| 402 |
Amortization of deferred credit |
|
| (487) |
|
| (3,164) |
|
| (3,086) |
Equity in earnings of Medusa Spar LLC |
|
| — |
|
| (17) |
|
| (226) |
Deferred income tax expense |
|
| 23,134 |
|
| 2,778 |
|
| 2,223 |
Net loss (gain) on derivatives, net of settlements |
|
| (27,650) |
|
| 2,730 |
|
| (1,683) |
Impairment of other property and equipment |
|
| — |
|
| 1,707 |
|
| 1,176 |
Gain on sale of other property and equipment |
|
| (1,080) |
|
| — |
|
| — |
Non-cash gain on early debt extinguishment |
|
| (151) |
|
| (3,696) |
|
| (1,366) |
Non-cash expense related to equity share-based awards |
|
| 1,126 |
|
| 2,092 |
|
| 1,697 |
Change in the fair value of liability share-based awards |
|
| 3,936 |
|
| 2,903 |
|
| 1,620 |
Payments to settle asset retirement obligations |
|
| (3,808) |
|
| (721) |
|
| (1,314) |
Changes in current assets and liabilities: |
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
| (7,915) |
|
| (3,497) |
|
| (883) |
Other current assets |
|
| 622 |
|
| (560) |
|
| 100 |
Current liabilities |
|
| 12,805 |
|
| 3,583 |
|
| 1,753 |
Payments to settle vested liability share-based awards |
|
| (3,469) |
|
| (239) |
|
| (3,383) |
Change in other long-term liabilities |
|
| (106) |
|
| (711) |
|
| 103 |
Change in other assets, net |
|
| (448) |
|
| (666) |
|
| (1,886) |
Net cash provided by operating activities |
|
| 94,387 |
|
| 54,475 |
|
| 51,290 |
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
| (232,596) |
|
| (159,724) |
|
| (133,299) |
Acquisition |
|
| (222,883) |
|
| (10,885) |
|
| (2,075) |
Proceeds from sales of mineral interest and equipment |
|
| 2,978 |
|
| 89,992 |
|
| 39,936 |
Distribution from Medusa Spar LLC |
|
| — |
|
| 813 |
|
| 1,735 |
Net cash used in investing activities |
|
| (452,501) |
|
| (79,804) |
|
| (93,703) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
Borrowings on credit facility |
|
| 132,500 |
|
| 80,000 |
|
| 53,000 |
Borrowings on term loan |
|
| 382,500 |
|
| — |
|
| — |
Payments on credit facility |
|
| (119,500) |
|
| (68,000) |
|
| (43,000) |
Payments on term loan |
|
| (84,149) |
|
| — |
|
| — |
Payment of deferred financing costs |
|
| (19,779) |
|
| (146) |
|
| — |
Redemption of 13% senior notes |
|
| (50,057) |
|
| (50,060) |
|
| (10,225) |
Issuance of preferred stock |
|
| — |
|
| 70,035 |
|
| — |
Issuance of common stock |
|
| 122,450 |
|
| — |
|
| — |
Payment of preferred stock dividends |
|
| (7,895) |
|
| (4,627) |
|
| — |
Taxes paid related to exercise of employee stock options |
|
| — |
|
| — |
|
| (18) |
Net cash provided by (used in) financing activities |
|
| 356,070 |
|
| 27,202 |
|
| (243) |
Net change in cash and cash equivalents |
|
| (2,044) |
|
| 1,873 |
|
| (42,656) |
Balance, beginning of period |
|
| 3,012 |
|
| 1,139 |
|
| 43,795 |
Balance, end of period |
| $ | 968 |
| $ | 3,012 |
| $ | 1,139 |
| 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 | |||||
64
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except |
| Note | Description | Note | Description | |||
| Description of Business and Basis of Presentation | Share-Based Compensation | |||||
| Summary of Significant Accounting Policies | Equity Transactions | |||||
| Earnings (loss) per Share | Income Taxes | |||||
| Borrowings | Asset Retirement Obligations | |||||
| Derivative Instruments and Hedging Activities | Supplemental Information on Oil and Natural Gas Operations (Unaudited) | |||||
| Fair Value Measurements | Other | |||||
| Employee Benefit Plans | Summarized Quarterly Financial Information (Unaudited) | |||||
INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
Description of Business and Basis of Presentation | Asset Retirement Obligations | ||
Summary of Significant Accounting Policies | Equity Transactions | ||
Acquisitions and Dispositions | Income Taxes | ||
Earnings (Loss) Per Share | Asset Retirement Obligations | ||
Borrowings | Supplemental Information on Oil and Natural Gas Operations (Unaudited) | ||
Derivative Instruments and Hedging Activities | Other | ||
Fair Value Measurements | Summarized Quarterly Financial Information (Unaudited) | ||
Employee Benefit Plans |
|
|
NOTE Note 1 – - Description of BusinessBusiness and Basis of Presentation
Description of business
Callon Petroleum Company is an independent oil and natural gas company established in 1950, which has been focused on building reserves and production both onshore and offshore through efficient operations and low finding and development costs. In 2013, the Company completed the onshore strategic repositioning it initiated in 2009, shifting its operations from the offshore waters in the Gulf of Mexico to the Permian 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 the Medusa Spar facility and substantially all remaining offshore shelf properties. These transactions completed the Company’s long-term strategic goal of becoming an onshore operator with an asset base concentrated in the Permian Basin.
Callon is focused on the acquisition, development, exploration and exploitation of unconventional, onshore, oil and natural gas reserves in the Permian Basin in West Texas, and more specifically, the Midland Basin. The Company’s operations to date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the Wolfcamp formation. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through acreage purchases, joint ventures and asset swaps.
Basis of presentation
Unless otherwise indicated, all dollar amounts included within the footnotes to the financial statements are presented in thousands, except for per share and per unit data.
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. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, the results of its operations and its cash flows for the periods indicated. 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’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.
A. | Use of Estimates |
The preparation of financial statements in conformity with United States generally accepted accounting principles (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.
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.
65
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit data) |
C. | Accounts Receivable |
Accounts receivable consists primarily of accrued oil and natural gas production receivables. The balance in the reserve for doubtful accounts netted within accounts receivable was
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 NGLs is included in natural gas sales. Natural gas balancing receivables and payables were
E. | Major Customers |
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 greater than 10% of its total oil and natural gas production during each of the years ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | |||||
| 2014 |
| 2013 |
| 2012 | |
Enterprise Crude Oil, LLC |
| 51% |
| 38% |
| 32% |
Plains Marketing, L.P. |
| 22% |
| 15% |
| 15% |
Sunoco |
| 10% |
| 0% |
| 0% |
Shell Trading Company |
| 0% |
| 31% |
| 39% |
Other |
| 17% |
| 16% |
| 14% |
Total |
| 100% |
| 100% |
| 100% |
| For the Year Ended December 31, | ||||||||
| 2013 | 2012 | 2011 | ||||||
| Enterprise Crude Oil, LLC | 38 | % | 32 | % | 16 | % | ||
| Shell Trading Company | 31 | % | 39 | % | 45 | % | ||
| Plains Marketing, L.P. | 15 | % | 15 | % | 17 | % | ||
| Other | 16 | % | 14 | % | 22 | % | ||
| Total | 100 | % | 100 | % | 100 | % | ||
Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production.
F. | Oil and Natural Gas Properties |
The Company uses the full-costfull 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 propertyoil and equipment.gas properties. 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
When applicable, proceeds from the sale or disposition of 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.
Historical and estimated future development costs of oil and natural gas properties including future development costs, which have been evaluated and contain proved reserves, andas well as the historical cost of properties which have been determined to be worthless,have no future economic value, 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 managementthe Company determines that these costs have been impaired.
Under the full-costfull cost accounting rules, of the SEC, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of 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 oil and natural gas reserves,
66
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit data) |
discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full-costfull cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average 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.net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. See Note 1213 for additional information regarding the Company’s oil and natural gas properties.
Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle, abandon and restore the 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
G. | Other Property and Equipment |
The Company depreciates its other property and equipment of
H. | Capitalized Interest |
The Company capitalizes interest on expenditures made in connection with explorationunevaluated oil 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.gas properties. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2014, 2013 2012 and 2011,2012, the Company capitalized
I. | Deferred Financing Costs |
Deferred financing costs are stated at cost, net of amortization, which is computed using the straight-line method over the life of the loan, which is reflective of the effective interest rate method. Deferred financing costs of $18,200 and $1,098 as of December 31, 2014 and 2013, respectively, net of accumulated amortization. Amortization of deferred financing costs of $1,272, $471 and $402 was recorded for the years ended December 31, 2014, 2013 and 2012, respectively.
J. | 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
NoteK. | Derivatives |
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 contracts designated as cash flow hedges were recognized as gain or loss on derivative expense (income).contracts. The last of the Company’s derivative contracts designated as cash flow hedges expired on December 31, 2012. Derivative contracts executed during
67
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit data) |
L. | Income Taxes |
Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforwardcarryforwards 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
M. | Share-Based Compensation |
The Company grants to directors and employees stock options and restricted stock awards (“RS awards”), and. The Company also grants restricted stock unit awards (“RSU 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).
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).
N. | Statements of Cash Flows Supplemental Information |
During the three year period ended
2013,O. | Investment in Medusa Spar LLC |
During the fourth quarter of
2013,P. |
Earnings per Share (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 caused by the exercise of all options and vesting of all restricted stock and restricted stock units settleable in shares.
Q. | Recent Accounting Pronouncements |
In February 2013,May 2014, the Financial Accounting Standards Board issued accounting standards update (“ASU”) No. 2014-09, Revenue from Contracts with Customers. The standard requires an Accounting Standards Update (ASU)entity to recognize revenue in a manner that clarifieddepicts the reclassification requirements from accumulated other comprehensive incometransfer of goods or services to net income and required disclosure of amounts reclassified out of accumulated other comprehensive income by component. In addition, it requirescustomers at an amount that reflects the Company present either onconsideration to which the face of its financial statementsentity expects to be entitled in exchange for those goods 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, the Company is required to cross-reference to the related note on the faceservices. ASU No. 2014-09 will replace most of the financial statementsexisting revenue recognition requirements in GAAP when it becomes effective. The guidance in ASU No. 2014-09 is effective for additional information. Callon adopted this guidance effective January 1, 2013, which did not have a material impact on its financial statements.
68
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except |
including interim periods therein. Early adoption is not permitted. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.
Note 3 – Acquisitions and Dispositions
2014 acquisitions
In the first quarter of 2014, the Company acquired 1,527 net acres in Upton and Reagan Counties, Texas, which are located in the southern portion of the Midland Basin near its existing core development fields, for an aggregate cash purchase price of $8,200. The properties bear a working interest of 100% and an average net revenue interest of 78%.
On October 8, 2014, the Company completed the acquisition of certain undeveloped acreage and producing oil and gas properties located in Midland, Andrews, Ector and Martin Counties, Texas (the “Central Midland Basin Acquisition”) for an aggregate cash purchase price of $210,205, including estimated purchase price adjustments of $2,367 based on an effective date of May 1, 2014. The Company assumed operatorship of the properties on November 1, 2014, and acquired a 62% working interest (46.5% net revenue interest) in the Central Midland Basin Acquisition. The aggregate cash purchase price was funded with a combination of the net proceeds from an equity offering of $122,450 and a portion of the proceeds from borrowings under the Second Lien Loan. For additional information on the debt transactions and equity offering, see Notes 5 and 10, respectively.
The Central Midland Basin Acquisition was accounted for under the purchase method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed. The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired:
Oil and natural gas properties | $ | 91,895 | |
Unevaluated oil and natural gas properties | 118,450 | ||
Asset retirement obligations | (140) | ||
Net assets acquired | $ | 210,205 |
The following unaudited summary pro forma financial information for the year ended December 31, 2014 and 2013 has been presented for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Central Midland Basin Acquisition had occurred as presented, or to project the Company’s results of operations for any future periods. The pro forma financial information was prepared assuming the Central Midland Basin Acquisition and the debt transactions and equity offering discussed in Notes 5 and 10, respectively, occurred as of January 1, 2013. The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest.
|
|
|
|
|
|
|
|
| For the Years Ended December 31, | ||||
|
| 2014 |
| 2013 | ||
Revenues |
| $ | 180,458 |
| $ | 151,766 |
Income from operations |
|
| 53,526 |
|
| 36,002 |
Income available to common stockholders |
|
| 33,674 |
|
| 4,033 |
|
|
|
|
|
|
|
Net income per common share |
|
|
|
|
|
|
Basic |
| $ | 0.57 |
| $ | 0.07 |
Diluted |
| $ | 0.56 |
| $ | 0.07 |
2013 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 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 10).
69
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit data) |
2012 acquisitions
During the first quarter of 2012, the Company acquired 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.
2013 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 for 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. The proceeds from these sales were accounted for as a reduction to capitalized costs as the sales did not significantly alter the relationship between capitalized costs and proved reserves.
2012 dispositions
During 2012, the Company closed on the sale of its 11.25% working interest in the Habanero field (Garden Banks Block 341) for net cash consideration of $39,410 after customary purchase price adjustments. 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.
Basic earnings (loss) per share is computed by dividing income (loss) 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):follows:
70
| 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 | ||||||||
| (c) Weighted average shares outstanding | |||||||||||
| for diluted net income (loss) per share (1) | 40,133 | 40,337 | 38,582 | ||||||||
| 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 | ||||
| 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 | ||||||||
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit data) |
The following table sets forth the computation of basic and diluted earnings per share:
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|
|
|
|
|
|
| For the Year Ended December 31, | |||||||
|
|
| 2014 |
|
| 2013 |
|
| 2012 |
Net income (loss) |
| $ | 37,766 |
| $ | 4,304 |
| $ | 2,747 |
Preferred stock dividends |
|
| (7,895) |
|
| (4,627) |
|
| — |
Income (loss) available to common stockholders |
| $ | 29,871 |
| $ | (323) |
| $ | 2,747 |
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding |
|
| 44,848 |
|
| 40,133 |
|
| 39,522 |
Dilutive impact of stock options |
|
| — |
|
| — |
|
| 8 |
Dilutive impact of restricted stock |
|
| 1,113 |
|
| — |
|
| 807 |
Weighted average shares outstanding for diluted income (loss) per share (a) |
|
| 45,961 |
|
| 40,133 |
|
| 40,337 |
|
|
|
|
|
|
|
|
|
|
Basic income (loss) per share |
| $ | 0.67 |
| $ | (0.01) |
| $ | 0.07 |
Diluted income (loss) per share |
| $ | 0.65 |
| $ | (0.01) |
| $ | 0.07 |
|
|
|
|
|
|
| |||
The following were excluded from the diluted earnings per share calculation because their effect would be anti-dilutive: | |||||||||
Stock options |
|
| 30 |
|
| 52 |
|
| 52 |
Restricted stock |
|
| 317 |
|
| 398 |
|
| 123 |
(a) | Because the Company reported a loss available to common stockholders for the year ended December 31, 2013, no unvested stock awards were included in computing loss per share because the effect was anti-dilutive. |
The Company’s borrowings consisted of the following at:
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | ||||
|
| 2014 |
| 2013 | ||
Principal components: |
|
|
|
|
|
|
Senior secured revolving credit facility |
| $ | 35,000 |
| $ | 22,000 |
Secured second lien term loan |
|
| 300,000 |
|
| — |
13% Senior Notes, principal |
|
| — |
|
| 48,481 |
Total principal outstanding |
|
| 335,000 |
|
| 70,481 |
13% Senior Notes, unamortized deferred credit |
|
| — |
|
| 5,267 |
Total carrying value of borrowings |
| $ | 335,000 |
| $ | 75,748 |
| For the year ended December 31, | |||||||
| 2013 | 2012 | ||||||
| Principal components: | |||||||
| Credit Facility | $ | 22,000 | $ | 10,000 | |||
| 13% Senior Notes due 2016, principal | 48,481 | 96,961 | |||||
| Total principal outstanding | $ | 70,481 | $ | 106,961 | |||
| Non-cash components: | |||||||
| 13% Senior Notes due 2016 unamortized deferred credit | 5,267 | 13,707 | |||||
| Total carrying value of borrowings | $ | 75,748 | $ | 120,668 | |||
Senior Secured Revolving Credit Facilitysecured revolving credit facility (the “Credit Facility”)
On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility for whichwith a maturity date of March 11, 2019. JPMorgan Chase Bank, N.A. is Administrative Agent, and participating lenders include Regions Bank, serves as the Administrative Agent, matures March 15, 2016 and includes Citibank, NA, IberiaBank,N.A., Capital One, N.A., KeyBank, N.A., Whitney Bank, andIberiaBank, N.A., OneWest Bank, FSB as participating lenders.N.A., SunTrust Bank and Royal Bank of Canada. The Company’stotal notional amount available under the Credit Facility had an approvedis $500,000. Amounts borrowed under the Credit Facility may not exceed the borrowing base, at December 31, 2013 of $83,000.which is generally reviewed on a semi-annual basis. The Credit Facility wasis secured by first preferred mortgages covering the Company’s major producing fields. properties. In conjunction with the closing of the Acquisition on October 8, 2014, the borrowing base on the Company’s Credit Facility was amended to $250,000.
As of December 31, 2013,2014, the balance outstanding on the Credit Facility was $22,000$35,000 with ana weighted-average interest rate of 2.92%1.91%, calculated as the London Interbank Offered Rate (LIBOR),LIBOR plus a tiered rate ranging from 2.5%1.75% to 3.0%2.75%, which is determined bybased on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the borrowing base, which is payable quarterly.
71
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except |
Term loans
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.
On October 8, 2014, the term loan described above was repaid in full using proceeds from a new secured second lien term loan (the “Second Lien Loan”) in conjunction with the closing of the Acquisition, resulting in a loss on early extinguishment of debt of $3,054. The Second Lien Loan has a maturity date of October 8, 2021. On October 8, 2014, the Company drew an initial amount of $300,000 with a discount of 2.0% and an interest rate of 8.5%, calculated at a rate of LIBOR (subject to a floor rate of 1.0%) plus 7.5% per annum. The Second Lien Loan may be prepaid at the Company’s option, subject to a prepayment premium. The prepayment amount is (i) 102% if the prepayment event occurs prior to October 8, 2015, and (ii) 101% if the prepayment event occurs on or after October 8, 2015 but before October 8, 2016, and (iii) 100% for prepayments made on or after October 8, 2016. The Second Lien Loan is secured by junior liens on properties mortgaged under the Credit Facility, contains various affirmativesubject to an intercreditor agreement. The Royal Bank of Canada is Administrative Agent, and restrictive covenants.
13% senior notes due 2016 (“Senior Notes”) and deferred credit
On April 11, 2014, the Company completed a full redemption of the remaining $48,481 principal amount of outstanding Senior Notes due 2016 (the “Senior Notes”) and Deferred Credit
| 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 | $26,240 | $5,267 | $8,440 | $5,267 | ||||
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
In June 2012, the Company redeemed
Restrictive Covenants
The Indenture governing our Senior Notes and the Company’s Credit Facility containsand Second Lien Loan contain various covenants including restrictions on additional indebtedness, and payment of cash dividends. In addition, Callon’s Credit Facility contains covenants fordividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at
Note 6 - Der.
Objectives and Strategiesstrategies for Using Derivative Instruments
The Company is exposed to fluctuations in oil and natural gas prices on the majority ofreceived for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes primarily a mix of collar, swap, put
72
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit data) |
collars, swaps, puts, calls and callsimilar 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 risk and offsetting
The use of derivative transactionsinstruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing 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.prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instruments’ fair value; See
The Company executes commodity derivative transactionscontracts 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.
Financial statement presentation and settlements
Settlements of the Company’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”)benchmark price, such as the NYMEX price. TheTo determine the fair value of the Company’s derivative instruments, depending on the type of instruments, was determined by the use ofCompany utilizes present value methods or standard option valuation models withthat include assumptions about commodity prices based on those observed in underlying markets. See
Derivatives not designated as hedging instruments
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.hedges for contracts executed subsequent to December 31, 2012. Consequently, anythe Company records its derivative contract not designated as an accounting hedge will be carriedcontracts at its fair value onin the consolidated balance sheet and marked-to-market at the end of each period, with the changerecords changes in fair value reflected as a gain or loss on derivative contracts in the consolidated statement of operations. Gains and losses on derivatives thatCash settlements are not designatedalso recorded as hedges are recorded in earnings as a component of gain (loss) on derivative contracts. Within the gain (loss)or loss on derivative contracts line ofin the consolidated statement of operations are gains (losses) on derivatives, net of settlement and gains (losses) on derivatives, settled.
The following table reflects the fair valuesvalue of the Company’s derivative instruments for the periods presented (none of which were designated as hedging instruments under ASC 815):presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance Sheet Presentation |
| Asset Fair Value |
| Liability Fair Value |
| Net Derivative Fair Value | ||||||||||||||
Commodity |
| Classification |
| Line Description |
| 12/31/2014 |
| 12/31/2013 |
| 12/31/2014 |
| 12/31/2013 |
| 12/31/2014 |
| 12/31/2013 | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as Hedging Instruments under ASC 815 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
| Current |
| Fair value of derivatives |
| $ | 1,262 |
| $ | 60 |
| $ | (7) |
| $ | — |
| $ | 1,255 |
| $ | 60 |
Natural gas |
| Non-current |
| Other long-term liabilities |
|
| — |
|
| — |
|
| — |
|
| (72) |
|
| — |
|
| (72) |
Oil |
| Current |
| Fair value of derivatives |
|
| 26,588 |
|
| — |
|
| (1,242) |
|
| (1,036) |
|
| 25,346 |
|
| (1,036) |
|
| Total |
|
|
| $ | 27,850 |
| $ | 60 |
| $ | (1,249) |
| $ | (1,108) |
| $ | 26,601 |
| $ | (1,048) |
| Balance Sheet Presentation | Asset Fair Value | Liability Fair Value | Net Derivative Fair Value | |||||||||||||||||||||||||
| Commodity | 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 | $ | 60 | $ | — | $ | — | $ | (125 | ) | $ | 60 | $ | (125 | ) | ||||||||||||
| Natural gas | Non-current | Other long-term liabilities | — | — | (72 | ) | (116 | ) | (72 | ) | (116 | ) | ||||||||||||||||
| Oil | Current | Fair market value of derivatives | — | 1,674 | (1,036 | ) | — | (1,036 | ) | 1,674 | ||||||||||||||||||
| Oil | Non-current | Other long-term assets | — | 250 | — | — | — | 250 | ||||||||||||||||||||
| Totals | $ | 60 | $ | 1,924 | $ | (1,108 | ) | $ | (241 | ) | $ | (1,048 | ) | $ | 1,683 | |||||||||||||
73
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except |
As previously discussed, the Company’s derivative contracts are subject to master netting arrangements and, being representativearrangements. The Company’s policy is to present the fair value of the way in which thederivative contracts settle, are presented in the balance sheet at their fair values on a net basis based onin the underlying commodity being hedged.consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities at
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, 2014 | |||||||
|
| Presented without |
|
|
| As Presented with | |||
|
| Effects of Netting |
| Effects of Netting |
| Effects of Netting | |||
Current assets: Fair value of derivatives |
| $ | 27,850 |
| $ | — |
| $ | 27,850 |
Current liabilities: Fair value of derivatives |
| $ | (1,249) |
| $ | — |
| $ | (1,249) |
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, 2013 | |||||||
|
| Presented without |
|
|
| As Presented with | |||
|
| Effects of Netting |
| Effects of Netting |
| Effects of Netting | |||
Current assets: Fair value of derivatives |
| $ | 8 |
| $ | 52 |
| $ | 60 |
Current liabilities: Fair value of derivatives |
|
| 1,088 |
|
| (52) |
|
| 1,036 |
Long-term liabilities: Fair value of derivatives |
| $ | (72) |
| $ | — |
| $ | (72) |
| 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 recordedderivatives in the Statementconsolidated statement of Operationsoperations as gain or loss on derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | |||||||
|
|
| 2014 |
|
| 2013 |
|
| 2012 |
Natural gas derivatives |
|
|
|
|
|
|
|
|
|
Net gain (loss) on settlements |
| $ | (84) |
| $ | (148) |
| $ | 34 |
Net gain (loss) on fair value adjustments |
|
| 1,267 |
|
| 230 |
|
| (241) |
Total gain (loss) |
| $ | 1,183 |
| $ | 82 |
| $ | (207) |
Oil derivatives |
|
|
|
|
|
|
|
|
|
Net gain (loss) on settlements |
| $ | 4,170 |
| $ | 1,518 |
| $ | — |
Net gain (loss) on fair value adjustments |
|
| 26,383 |
|
| (2,960) |
|
| 1,924 |
Total gain (loss) |
| $ | 30,553 |
| $ | (1,442) |
| $ | 1,924 |
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivative contracts |
| $ | 31,736 |
| $ | (1,360) |
| $ | 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 Company’s derivative contracts executed prior to December 31, 2012 were designated as accounting hedges. The table below presents the effect of the Company’s derivative financial instruments on the consolidated statements of operations as an increase (decrease) to oil and natural gas sales for the effective portion and as an increase (decrease) to other (income) expense for the ineffective portion and amounts excluded from effectiveness testing:sales:
|
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|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | |||||||
|
| 2014 |
| 2013 |
| 2012 | |||
Amount of gain reclassified from OCI into income |
| $ | — |
| $ | — |
| $ | 1,420 |
| For the year ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Amount of gain (loss) reclassified from OCI into income (effective portion) | $ | — | $ | 1,420 | $ | (375 | ) | ||||
| Amount of gain (loss) recognized in income (ineffective portion and amount excluded from effectiveness testing) | — | — | — | ||||||||
74
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except |
Derivative positions
Listed in the tabletables below are the outstanding oil and natural gas derivative contracts as of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended | ||||||||||
|
| March 31, |
| June 30, |
| September 30, |
| December 31, | ||||
Oil contracts |
| 2015 |
| 2015 |
| 2015 |
| 2015 | ||||
Collar contracts combined with short puts (three-way collar): |
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MBbls) |
|
| 158 |
|
| 159 |
|
| — |
|
| — |
Price per Bbl |
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling (short call) |
| $ | 99.10 |
| $ | 99.10 |
| $ | — |
| $ | — |
Floor (long put) |
| $ | 90.00 |
| $ | 90.00 |
| $ | — |
| $ | — |
Short put |
| $ | 75.00 |
| $ | 75.00 |
| $ | — |
| $ | — |
Swap contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
Total volume (MBbls) |
|
| 171 |
|
| 136 |
|
| 129 |
|
| 74 |
Weighted average price per Bbl |
| $ | 92.25 |
| $ | 92.18 |
| $ | 92.25 |
| $ | 92.20 |
Put spreads: |
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MBbls) |
|
| — |
|
| — |
|
| 138 |
|
| 138 |
Long put price per Bbl |
| $ | — |
| $ | — |
| $ | 90.00 |
| $ | 90.00 |
Short put price per Bbl |
| $ | — |
| $ | — |
| $ | 75.00 |
| $ | 75.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended | ||||||||||
|
| March 31, |
| June 30, |
| September 30, |
| December 31, | ||||
Natural gas contracts |
| 2015 |
| 2015 |
| 2015 |
| 2015 | ||||
Collar contracts combined with short |
|
|
|
|
|
|
|
|
|
|
|
|
puts (three-way collar): |
|
|
|
|
|
|
|
|
|
|
|
|
Volume (BBtu) |
|
| 248 |
|
| 227 |
|
| 207 |
|
| 161 |
Weighted average price per MMBtu |
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling (short call) |
| $ | 4.67 |
| $ | 4.32 |
| $ | 4.32 |
| $ | 4.32 |
Floor (long put) |
| $ | 4.00 |
| $ | 3.85 |
| $ | 3.85 |
| $ | 3.85 |
Short put |
| $ | 3.50 |
| $ | 3.25 |
| $ | 3.25 |
| $ | 3.25 |
Swap contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
Total volume (BBtu) |
|
| 271 |
|
| 237 |
|
| 219 |
|
| 228 |
Weighted average price per MMBtu |
| $ | 3.98 |
| $ | 3.98 |
| $ | 3.98 |
| $ | 3.96 |
Short call contract: |
|
|
|
|
|
|
|
|
|
|
|
|
Short call volume (BBtu) |
|
| 108 |
|
| 109 |
|
| 110 |
|
| 111 |
Short call price per MMBtu |
| $ | 5.00 |
| $ | 5.00 |
| $ | 5.00 |
| $ | 5.00 |
| 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 | ||||||||||||
Subsequent Event Activity:
| 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 | ||||||||
In addition, the Company recently entered into basis differential swaps that provide for a fixed price spread between the Midland and NYMEX prices for West Texas Intermediate oil. The Company hedged an average of approximately 4,120 barrels of oil per day from March 2015 to December 2015 at a weighted average Midland swap spread of ($2.39) per barrel.
75
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except |
The following derivative contracts for oil were executed subsequent to December 31, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Three Months Ended | ||||||||||
|
| March 31, |
| June 30, |
| September 30, |
| December 31, | ||||
Oil contracts |
| 2015 |
| 2015 |
| 2015 |
| 2015 | ||||
Swap contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
Total volume (MBbls) |
|
| 231 |
|
| 273 |
|
| 253 |
|
| 253 |
Weighted average price per Bbl |
| $ | 60.77 |
| $ | 60.09 |
| $ | 59.83 |
| $ | 59.83 |
Swap contracts (Differentials): |
|
|
|
|
|
|
|
|
|
|
|
|
Total volume (MBbls) |
|
| 152 |
|
| 400 |
|
| 382 |
|
| 326 |
Weighted average price per Bbl |
| $ | (2.41) |
| $ | (2.40) |
| $ | (2.39) |
| $ | (2.38) |
Note 7 - Fair Value Measurements
The fair value hierarchy outlined in the relevant accounting guidance gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority.
Fair Value of Financial Instruments
Cash, Cash Equivalents, and Short-Term Investments.cash equivalents, restricted 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.in the consolidated balance sheet. The carrying amount of floating-rate debt approximatesapproximated fair value because the interest rates arewere variable and reflective of market rates.
The following table summarizes the respective carrying and fair values at:
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ` |
|
|
|
|
| December 31, | ||||||||||
|
| 2014 |
| 2013 | ||||||||
|
| Carrying Value |
| Fair Value |
|
| Carrying Value |
| Fair Value | |||
Credit Facility |
| $ | 35,000 |
| $ | 35,000 |
| $ | 22,000 |
| $ | 22,000 |
Second Lien Loan |
|
| 300,000 |
|
| 300,000 |
|
| — |
|
| — |
13% Senior Notes due 2016 (a) |
|
| — |
|
| — |
|
| 53,748 |
|
| 50,299 |
Total |
| $ | 335,000 |
| $ | 335,000 |
| $ | 75,748 |
| $ | 72,299 |
| For the year ended December 31, | |||||||||||||||
| 2013 | 2012 | ||||||||||||||
| Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||||
| Credit Facility | $ | 22,000 | $ | 22,000 | $ | 10,000 | $ | 10,000 | |||||||
| 13% Senior Notes due 2016 (a) | 53,748 | 50,299 | 110,668 | 100,112 | |||||||||||
| Total | $ | 75,748 | $ | 72,299 | $ | 120,668 | $ | 110,112 | |||||||
(a) | The fair |
Assets and Liabilities Measuredliabilities measured at Fair Valuefair 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 consolidated balance sheet. The following methods and assumptions were used to estimate the fair values:
Commodity Derivative Instruments.derivative instruments. The fair value of commodity derivative instruments is derived using aan income approach 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.contract. 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 56 for additional information regarding the Company’s derivative instruments.
76
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit data) |
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis for each hierarchy level:basis:
|
|
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|
|
|
|
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|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
| Balance Sheet Presentation |
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments (current) |
| Fair value of derivatives |
| $ | — |
| $ | 27,850 |
| $ | — |
| $ | 27,850 |
Derivative financial instruments (non-current) |
| Other assets, net |
|
| — |
|
| — |
|
| — |
|
| — |
Sub-total assets |
|
|
| $ | — |
| $ | 27,850 |
| $ | — |
| $ | 27,850 |
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments (current) |
| Fair value of derivatives |
| $ | — |
| $ | (1,249) |
| $ | — |
| $ | (1,249) |
Derivative financial instruments (non-current) |
| Other long-term liabilities |
|
| — |
|
| — |
|
| — |
|
| — |
Sub-total liabilities |
|
|
| $ | — |
| $ | (1,249) |
| $ | — |
| $ | (1,249) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net assets (liabilities) |
|
|
| $ | — |
| $ | 26,601 |
| $ | — |
| $ | 26,601 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013 |
| Balance Sheet Presentation |
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments (current) |
| Fair value of derivatives |
| $ | — |
| $ | 60 |
| $ | — |
| $ | 60 |
Derivative financial instruments (non-current) |
| Other assets, net |
|
| — |
|
| — |
|
| — |
|
| — |
Sub-total assets |
|
|
| $ | — |
| $ | 60 |
| $ | — |
| $ | 60 |
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments (current) |
| Fair value of derivatives |
| $ | — |
| $ | (1,036) |
| $ | — |
| $ | (1,036) |
Derivative financial instruments (non-current) |
| Other long-term liabilities |
|
| — |
|
| (72) |
|
| — |
|
| (72) |
Sub-total liabilities |
|
|
| $ | — |
| $ | (1,108) |
| $ | — |
| $ | (1,108) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net assets (liabilities) |
|
|
| $ | — |
| $ | (1,048) |
| $ | — |
| $ | (1,048) |
| December 31, 2013 | Balance Sheet Presentation | Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| Assets | ||||||||||||||||||
| Derivative financial instruments - current Portion | Fair market value of derivatives | $ | — | $ | 60 | $ | — | $ | 60 | |||||||||
| Derivative financial instruments - non-current | Other assets, net | — | — | — | — | |||||||||||||
| Sub-total assets | $ | — | $ | 60 | $ | — | $ | 60 | ||||||||||
| Liabilities | ||||||||||||||||||
| Derivative financial instruments - current portion | Fair market value of derivatives | $ | — | $ | 1,036 | $ | — | $ | 1,036 | |||||||||
| Derivative financial instruments - non-current | Other long-term liabilities | — | 72 | — | 72 | |||||||||||||
| Sub-total liabilities | $ | — | $ | 1,108 | $ | — | $ | 1,108 | ||||||||||
| Total | $ | — | $ | (1,048 | ) | $ | — | $ | (1,048 | ) | ||||||||
| December 31, 2012 | 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 | |||||||||
| Derivative financial instruments - non-current | 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 | $ | — | $1,683 | $ | — | $1,683 | ||||||||||||
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Acquisition. On October 8, 2014, the Company completed the Acquisition as discussed in Note 3. The Company determined the fair value of the assets acquired using the income approach based on a nonrecurring basisexpected future cash flows from estimated reserve quantities; costs to produce and develop reserves; and oil and gas forward prices. Asset retirement obligations assumed in Callon’s Consolidated Balance Sheet.connection with the Central Midland Basin Acquisition were determined in accordance with applicable accounting standards. The following methodsfair value measurements were based on level 2 and assumptions were used to estimatelevel 3 inputs. For more information on the Acquisition see Note 3.
During the second quarter of 2013, the Company completed an acquisition as discussed in Note 3. The Company determined the fair values:
Other Property and Equipment. As discussed in Note 13,14, the Company’s decision to abandon certain of its other property and equipment, that had been classified as held for sale, resulted in an impairment charge of $1,707 which is included in the Company’s Statement of Operations for the year ended December 31, 2013.2013. The impairment charge was valued using level 3 inputs.
$11,000Note 8 – Emplo with approximately $2,000 allocated to unevaluated oil and gas properties and approximately $9,000 allocated to evaluated oil and gas properties. Asset retirement obligations assumed in connection with the transaction were insignificant due to the nature of the properties acquired. The unaudited pro forma results of the properties acquired are immaterial to the Company’s financial statements. The fair value measurements were based on significant inputs not observable in the market and thus represent a level 3 measurement.
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
Note77
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit data) |
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’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
2011 Omnibus Incentive Plan (the “2011 Plan”)
The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for 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 mayCash-Settled RSU Awards
Certain of the Company’s RSUs awarded require cash-settlement. Cash-settleablecash settlement. Cash-settled 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’s consolidated balance sheet for the ratable portion of their fair values.cash. The fair value of the Company’s market-based RSU awards 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.
Market-based RSUsRSUs: : A significant portion of the Company’s cash-settleablecash-settled RSU awards include a market-based vesting condition and maythat determines the actual number of units that will ultimately vest at a quantity different than the base RSUs awarded.vest. The number of RSUs that cliff-vestvest is based on a calculation that compares the Company’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.
78
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit data) |
As of December 31, 2013,2014, the Company had the following cash-settleable RSU awards outstanding (including those that are not based on a market condition):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(shares in 000s) |
| Base Units Outstanding |
| Potential Minimum Units Vesting |
| Potential Maximum Units Vesting |
Vesting in 2015 |
| 837 |
| 52 |
| 1,622 |
Vesting in 2016 |
| 416 |
| 60 |
| 772 |
Vesting in 2017 |
| 24 |
| 24 |
| 24 |
Other |
| 137 |
| 137 |
| 137 |
Total cash-settleable RSU awards |
| 1,414 |
| 273 |
| 2,555 |
| Base Units | Potential Minimum | Potential Maximum | |||||||
| Outstanding at | Units at Vesting at | Units at Vesting at | |||||||
| Vesting in 2014 | 510 | 45 | 975 | ||||||
| Vesting in 2015 | 909 | 60 | 1,758 | ||||||
| Vesting in 2016 | 66 | 66 | 66 | ||||||
| Other | 92 | 92 | 92 | ||||||
| Total cash-settleable RSU awards | 1,577 | 263 | 2,891 | ||||||
For the year ended
December 31,Note 9 - Shar
As discussed in
NoteThe following table presents share-based compensation expense for each respective period:
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|
|
|
|
|
|
|
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|
|
|
|
|
|
|
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|
|
|
|
| For the Year Ended December 31, | |||||||||||||||
|
|
| 2014 |
|
| 2013 |
|
| 2012 | |||||||||
Share-based compensation cost for: |
| Equity-based |
| Liability-based |
| Equity-based |
| Liability-based |
| Equity-based |
| Liability-based | ||||||
RSU equity awards |
| $ | 4,223 |
| $ | — |
| $ | 3,975 |
| $ | — |
| $ | 4,210 |
| $ | — |
Cash-settleable RSU awards |
|
| — |
|
| 6,918 |
|
| — |
|
| 5,347 |
|
| — |
|
| 2,916 |
401(k) contributions in shares |
|
| 270 |
|
| — |
|
| 219 |
|
| — |
|
| 218 |
|
| — |
Total share-based compensation cost (a) |
| $ | 4,493 |
| $ | 6,918 |
| $ | 4,194 |
| $ | 5,347 |
| $ | 4,428 |
| $ | 2,916 |
| For the year ended December 31, | |||||||||||||||||||||||
| 2013 | 2012 | 2011 | |||||||||||||||||||||
| Share-based compensation expense for: | Equity-based | Liability-based | Equity-based | Liability-based | Equity-based | Liability-based | |||||||||||||||||
| Options | $ | — | $ | — | $ | — | $ | — | $ | 24 | $ | — | |||||||||||
| RSU equity awards | 3,975 | — | 4,210 | — | 2,832 | — | |||||||||||||||||
| Cash-settleable RSU awards | — | 5,347 | — | 2,916 | — | 1,335 | |||||||||||||||||
| 401(k) contributions in shares | 219 | — | 218 | — | 202 | — | |||||||||||||||||
| Total share-based compensation expense (a) | $ | 4,194 | $ | 5,347 | $ | 4,428 | $ | 2,916 | $ | 3,058 | $ | 1,335 | |||||||||||
(a) | The portion of this share-based compensation |
The following table presents the specified share-basedunrecognized compensation expensecost for the indicated periods:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | ||||||||
Unrecognized compensation cost related to: |
| 2014 |
| 2013 |
| 2012 | |||
Unvested RSU equity awards |
| $ | 3,979 |
| $ | 5,331 |
| $ | 6,320 |
Unvested cash-settleable RSU awards |
|
| 4,977 |
|
| 7,669 |
|
| 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-basedunrecognized compensation cost related to unvested RSU and cash-settleable RSU awards is expected to be recognized over a weighted-average period of
The following table summarizes the Company’s cash-settleableliability for cash-settled RSU awards for the periods indicated:
|
|
|
|
|
|
|
| December 31, | |||||
Consolidated Balance Sheets Classification |
| 2014 |
| 2013 | ||
Cash-settled restricted stock unit awards - current |
| $ | 3,856 |
| $ | 4,173 |
Cash-settled restricted stock unit awards - non-current |
|
| 7,175 |
|
| 3,409 |
Total cash-settled RSU awards |
| $ | 11,031 |
| $ | 7,582 |
79
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit data) |
| Consolidated Balance Sheets Classification | 2013 | 2012 | 2011 | |||||||||
| Accounts payable and accrued liabilities - current portion | $ | 4,173 | $ | 1,429 | $ | 604 | ||||||
| Other long-term liabilities - non-current portion | 3,409 | 1,017 | 2,309 | |||||||||
| Total cash-settleable RSU awards | $ | 7,582 | $ | 2,446 | $ | 2,913 | ||||||
Stock Options
The Company issued no stock options for the past
three years and had no options vest or forfeit duringAs of
December 31,Restricted Stock Units
The following table represents unvested restricted stock activity for the year ended
December 31,
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|
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|
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|
|
|
|
|
|
|
|
| Weighted average | |||||
(shares in 000s) |
| 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 |
| 2,262 |
| $ | 5.03 |
|
|
Granted |
| 333 |
|
| 9.67 |
|
|
Vested (a) |
| (684) |
|
| 6.34 |
|
|
Forfeited |
| (43) |
|
| 4.11 |
|
|
Outstanding at the end of the period |
| 1,868 |
| $ | 5.40 |
| 1.2 |
| Weighted average | ||||||||
| 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 | 2,295 | $ | 5.58 | |||||
| Granted | 944 | 3.82 | ||||||
| Vested (a) | (754 | ) | 5.10 | |||||
| Forfeited | (223 | ) | 5.37 | |||||
| Outstanding at the end of the period | 2,262 | $ | 5.03 | 1.5 | ||||
(a) | The fair value of shares vested was |
For the year ended December 31, 2013, the Company issued 78,947granted 944,000 RSUs with a weighted average grant-date fair value of 10.0%$3.82 per share. The fair value of shares vested during 2013 was $2,689. For the year ended December 31, 2012, the Company granted 1,008,000 RSUs with a weighted average grant-date fair value of $5.22 per share. The fair value of shares vested during 2012 was $2,817.
10% Series A Cumulative Preferred Stock (the “Preferred(“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 Company’s 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 theBoard of Directors. Preferred Stock was June 30, 2013, and these dividends were paid on June 28,$7,895 and $4,627 in 2014 and 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’srespectively.
The Preferred Stock resulting in total dividend expense recognized in 2013 of $4,627.
Following a change of control, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash, 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 electsdoes not exercise its option to exercise this option,redeem the Preferred Stock upon a change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on December 31, 2014, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of the common stock on such date ($5.45) as the value of a share of common stock, each share of Preferred Stock into a predefined number of Company common shares, subject to certain adjustments.
80
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except |
into approximately 9.2 shares of common stock. If the Company received
Common Stock
On September 15, 2014 the Company completed an underwritten public offering of
The Company provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and other onshore assets.
The following table presents Callon’s netdeferred tax benefits relatingassets and liabilities with respect to its reported net lossescarryforwards and other temporary differences from operations:differences:
|
|
|
|
|
|
|
|
| As of December 31, | ||||
|
| 2014 |
| 2013 | ||
Deferred tax asset |
|
|
|
|
|
|
Federal net operating loss carryforward |
| $ | 86,629 |
| $ | 70,365 |
Statutory depletion carryforward |
|
| 8,876 |
|
| 8,880 |
Alternative minimum tax credit carryforward |
|
| 208 |
|
| 208 |
Asset retirement obligations |
|
| 1,003 |
|
| 1,024 |
Other |
|
| 6,621 |
|
| 7,575 |
Total deferred tax asset |
|
| 103,337 |
|
| 88,052 |
Deferred tax liability |
|
|
|
|
|
|
Oil and natural gas properties |
|
| 54,723 |
|
| 26,412 |
Other |
|
| 10,140 |
|
| 32 |
Total deferred tax liability |
|
| 64,863 |
|
| 26,444 |
Net deferred tax asset |
| $ | 38,474 |
| $ | 61,608 |
| For the Year Ended December 31 | |||||||
| 2013 | 2012 | ||||||
| Deferred tax asset | |||||||
| Federal net operating loss carryforward | $ | 70,365 | $ | 87,774 | |||
| Statutory depletion carryforward | 8,880 | 8,184 | |||||
| Alternative minimum tax credit carryforward | 208 | 208 | |||||
| Asset retirement obligations | 1,024 | 3,357 | |||||
| Other | 7,575 | 9,571 | |||||
| Total deferred tax asset | 88,052 | 109,094 | |||||
| Deferred tax liability | |||||||
| Oil and natural gas properties | 26,412 | 41,336 | |||||
| Other | 32 | 3,375 | |||||
| Total deferred tax liability | 26,444 | 44,711 | |||||
| Net deferred tax asset | $ | 61,608 | $ | 64,383 | |||
If not utilized, the Company’s federal operating loss (“NOL”) carryforwards will expire as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Year Expiring | |||||||||||||
|
| Total |
| 2015-2020 |
| 2021-2023 |
| 2024-2026 |
| 2027-2029 |
| 2030-2034 | ||||||
Federal NOL carryforwards |
| $ | 247,513 |
| $ | — |
| $ | 111,415 |
| $ | 14,408 |
| $ | 41,379 |
| $ | 80,311 |
| 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,Company’s current operations are located in Texas and are subject to the Texas margin tax. The Company has established a full valuation allowance on the tax benefits associated with the state net operating loss carryforwards of approximately$167,795approximately $171,907, which expire in years through 2033, as2034, related to other states in which the Company does not anticipate generating taxable state income in the states in which these carryforwards apply.income. These amounts are not included in the deferred tax summary table above.
The Company had no significant unrecognized tax benefits at
December 31,81
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit 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 Year Ended December 31, | |||||||
Components of income tax rate reconciliation |
| 2014 |
| 2013 |
| 2012 | |||
Income tax expense computed at the statutory federal income tax rate |
|
| 35% |
|
| 35% |
|
| 35% |
Percentage depletion carryforward |
|
| —% |
|
| (8)% |
|
| (22)% |
State taxes net of federal benefit |
|
| 1% |
|
| 4% |
|
| 6% |
Restricted stock and stock options |
|
| —% |
|
| 5% |
|
| 2% |
Section 162(m) |
|
| 2% |
|
| 6% |
|
| 22% |
Other |
|
| —% |
|
| —% |
|
| 4% |
Effective income tax rate |
|
| 38% |
|
| 42% |
|
| 47% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | |||||||
Components of income tax expense |
| 2014 |
| 2013 |
| 2012 | |||
Current state income tax expense |
| $ | — |
| $ | 326 |
| $ | 110 |
Deferred federal income tax expense |
|
| 22,373 |
|
| 2,652 |
|
| 1,777 |
Deferred state income tax expense |
|
| 761 |
|
| 126 |
|
| 336 |
Total income tax expense |
| $ | 23,134 |
| $ | 3,104 |
| $ | 2,223 |
Note 12 - Asset Reti
| For the Years Ended December 31, | ||||||||||||
| Component of Income Tax Rate Reconciliation | 2013 | 2012 | 2011 | |||||||||
| Income tax expense computed at the statutory federal income tax rate | 35 | % | 35 | % | 35 | % | ||||||
| Change in valuation allowance | — | % | — | % | (227 | )% | ||||||
| Percentage depletion carryforward | (8 | )% | (22 | )% | (3 | )% | ||||||
| State taxes net of federal benefit | 4 | % | 6 | % | — | % | ||||||
| Restricted stock and stock options | 5 | % | 2 | % | — | % | ||||||
| Section 162(m) | 6 | % | 22 | % | — | % | ||||||
| Other | — | % | 4 | % | 4 | % | ||||||
| Effective income tax rate | 42 | % | 47 | % | (191 | )% | ||||||
| For the Years Ended December 31, | ||||||||||||
| Components of Income Tax Expense | 2013 | 2012 | 2011 | |||||||||
| Current federal income tax benefit | $ | — | $ | — | $ | — | ||||||
| Current state income tax expense | 326 | 110 | — | |||||||||
| Deferred federal income tax expense | 2,652 | 1,777 | 13,176 | |||||||||
| Deferred state income tax expense | 126 | 336 | — | |||||||||
| Valuation allowance | — | — | (82,459 | ) | ||||||||
| Total income tax expense (benefit) | $ | 3,104 | $ | 2,223 | $ | (69,283 | ) | |||||
The following table below summarizes the activity for the Company’s asset retirement obligations:
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | ||||
| 2014 |
| 2013 | |||
Asset retirement obligations at January 1, 2014 |
| $ | 6,732 |
| $ | 13,301 |
Accretion expense |
|
| 826 |
|
| 1,785 |
Liabilities incurred |
|
| 638 |
|
| 679 |
Liabilities assumed |
|
| 140 |
|
| — |
Liabilities settled |
|
| (2,130) |
|
| (457) |
Liabilities related to oil and gas properties sold |
|
| — |
|
| (4,765) |
Revisions to estimate |
|
| 468 |
|
| (3,811) |
Asset retirement obligations at end of period |
|
| 6,674 |
|
| 6,732 |
Less: Current asset retirement obligations |
|
| (4,747) |
|
| (4,120) |
Long-term asset retirement obligations at December 31, 2014 |
| $ | 1,927 |
| $ | 2,612 |
| 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 31,82
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except |
NOTE 12Note 13 – Supplemental Information on Oil and NaturalNatural Gas OperationsProperties (Unaudited)
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.
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| For the Year Ended December 31, | |||||||
|
| 2014 |
| 2013 |
| 2012 | |||
Evaluated Properties |
|
|
|
|
|
|
|
|
|
Beginning of period balance |
| $ | 1,701,577 |
| $ | 1,497,010 |
| $ | 1,421,640 |
Capitalized G&A |
|
| 10,071 |
|
| 10,014 |
|
| 12,148 |
Property acquisition costs (a) |
|
| 94,541 |
|
| 10,885 |
|
| 2,075 |
Exploration costs |
|
| 118,251 |
|
| 147,164 |
|
| 22,703 |
Development costs |
|
| 153,545 |
|
| 36,504 |
|
| 38,444 |
End of period balance |
| $ | 2,077,985 |
| $ | 1,701,577 |
| $ | 1,497,010 |
Unevaluated Properties |
|
|
|
|
|
|
|
|
|
Beginning of period balance |
| $ | 43,222 |
| $ | 68,776 |
| $ | 2,603 |
Property acquisition costs (a) |
|
| 128,342 |
|
| 2,259 |
|
| 29,590 |
Exploration costs |
|
| 11,177 |
|
| 10,767 |
|
| 34,674 |
Capitalized interest |
|
| 4,295 |
|
| 4,410 |
|
| 2,109 |
Transfers to evaluated |
|
| (44,511) |
|
| (42,990) |
|
| (200) |
End of period balance |
| $ | 142,525 |
| $ | 43,222 |
| $ | 68,776 |
Accumulated depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
|
Beginning of period balance |
| $ | 1,420,612 |
| $ | 1,296,265 |
| $ | 1,208,331 |
Provision charged to expense |
|
| 56,663 |
|
| 42,251 |
|
| 48,524 |
Sale of mineral interests |
|
| 1,080 |
|
| 82,096 |
|
| 39,410 |
End of period balance |
| $ | 1,478,355 |
| $ | 1,420,612 |
| $ | 1,296,265 |
(a) | For more information on acquisitions refer to Note 3 |
| 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 lease sales, unevaluated drilling costs, seismic, capitalized interest and certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved properties and major development projects.properties. 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
Subsequent to
Depletion per unit-of-production, (BOE)on a BOE basis, amounted to
Under the full-costfull cost accounting rules, of the SEC, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of 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 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-costfull cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas market prices based on closing prices on the first day of each month and require a write-down if the “ceiling” is exceeded.net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices remain at current levels or decline significantly,further, even if only for a short period of time, it is possible that write-downs of oil and natural gas properties could occur in the future. For the years ended
83
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit data) |
Estimated Reserves
The Company’s proved oil and natural gas reserves at
December 31, 2014 have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum engineers. The Company’s proved oil and natural gas reserves at December 31, 2013There 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’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.
Changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States and offshore within the Gulf of Mexico (prior to December 31, 2013), are as follows:
|
|
|
|
|
|
|
|
| Reserve Quantities | ||||
|
| For the Year Ended December 31, | ||||
|
| 2014 |
| 2013 |
| 2012 |
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
Oil (MBbls): |
|
|
|
|
|
|
Beginning of period |
| 11,898 |
| 10,780 |
| 10,075 |
Revisions to previous estimates |
| (243) |
| (2,540) |
| (488) |
Purchase of reserves in place |
| 3,223 |
| 150 |
| 38 |
Sale of reserves in place |
| - |
| (3,294) |
| (504) |
Extensions and discoveries |
| 12,547 |
| 7,713 |
| 2,636 |
Production |
| (1,692) |
| (911) |
| (977) |
End of period |
| 25,733 |
| 11,898 |
| 10,780 |
Natural Gas (MMcf): |
|
|
|
|
|
|
Beginning of period |
| 17,751 |
| 19,753 |
| 35,118 |
Revisions to previous estimates |
| (215) |
| (5,351) |
| (10,838) |
Purchase of reserves in place |
| 8,591 |
| 317 |
| 115 |
Sale of reserves in place |
| - |
| (4,576) |
| (4,404) |
Extensions and discoveries |
| 18,641 |
| 10,619 |
| 3,350 |
Production |
| (2,220) |
| (3,011) |
| (3,588) |
End of period |
| 42,548 |
| 17,751 |
| 19,753 |
|
|
|
|
|
|
|
Proved developed reserves: |
|
|
|
|
|
|
Oil (MBbls): |
|
|
|
|
|
|
Beginning of period |
| 5,960 |
| 4,955 |
| 5,069 |
End of period |
| 14,006 |
| 5,960 |
| 4,955 |
Natural gas (MMcf): |
|
|
|
|
|
|
Beginning of period |
| 9,059 |
| 10,680 |
| 11,605 |
End of period |
| 25,171 |
| 9,059 |
| 10,680 |
MBOE: |
|
|
|
|
|
|
Beginning of period |
| 7,470 |
| 6,735 |
| 7,003 |
End of period |
| 18,201 |
| 7,470 |
| 6,735 |
Proved undeveloped reserves: |
|
|
|
|
|
|
Oil (MBbls): |
|
|
|
|
|
|
Beginning of period |
| 5,938 |
| 5,825 |
| 5,006 |
End of period |
| 11,727 |
| 5,938 |
| 5,825 |
Natural gas (MMcf): |
|
|
|
|
|
|
Beginning of period |
| 8,692 |
| 9,073 |
| 23,513 |
End of period |
| 17,377 |
| 8,692 |
| 9,073 |
MBOE: |
|
|
|
|
|
|
Beginning of period |
| 7,387 |
| 7,337 |
| 8,925 |
End of period |
| 14,623 |
| 7,387 |
| 7,337 |
84
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit data) |
Reserve Quantities For the year ended December 31, | ||||||||
| 2013 | 2012 | 2011 | ||||||
| Proved developed and undeveloped reserves: | ||||||||
| Oil (MBbls): | ||||||||
| Beginning of period | 10,780 | 10,075 | 8,149 | |||||
| Revisions to previous estimates | (2,540 | ) | (488 | ) | (110 | ) | ||
| Purchase of reserves in place | 150 | 38 | — | |||||
| Sale of reserves in place | (3,294 | ) | (504 | ) | (30 | ) | ||
| Extensions and discoveries | 7,713 | 2,636 | 3,062 | |||||
| Production | (911 | ) | (977 | ) | (996 | ) | ||
| End of period | 11,898 | 10,780 | 10,075 | |||||
| Natural Gas (MMcf): | ||||||||
| Beginning of period | 19,753 | 35,118 | 32,957 | |||||
| Revisions to previous estimates | (5,351 | ) | (10,838 | ) | 486 | |||
| Purchase of reserves in place | 317 | 115 | — | |||||
| Sale of reserves in place | (4,576 | ) | (4,404 | ) | (308 | ) | ||
| Extensions and discoveries | 10,619 | 3,350 | 7,064 | |||||
| Production | (3,011 | ) | (3,588 | ) | (5,081 | ) | ||
| End of period | 17,751 | 19,753 | 35,118 | |||||
| Proved developed reserves: | ||||||||
| Oil (MBbls): | ||||||||
| Beginning of period | 4,955 | 5,069 | 4,503 | |||||
| End of period | 5,960 | 4,955 | 5,069 | |||||
| Natural Gas (MMcf): | ||||||||
| Beginning of period | 10,680 | 11,605 | 12,715 | |||||
| End of period | 9,059 | 10,680 | 11,605 | |||||
| MBOE: | ||||||||
| Beginning of period | 6,735 | 7,003 | 6,622 | |||||
| End of period | 7,470 | 6,735 | 7,003 | |||||
| Proved undeveloped reserves: | ||||||||
| Oil (MBbls): | ||||||||
| Beginning of period | 5,825 | 5,006 | 3,645 | |||||
| End of period | 5,938 | 5,825 | 5,006 | |||||
| Natural Gas (MMcf): | ||||||||
| Beginning of period | 9,073 | 23,513 | 20,241 | |||||
| End of period | 8,692 | 9,073 | 23,513 | |||||
| MBOE | ||||||||
| Beginning of period | 7,337 | 8,925 | 7,019 | |||||
| End of period | 7,387 | 7,337 | 8,925 | |||||
Total Proved Reserves:The Company ended 2014 with estimated net proved reserves of 32,824 MBOE, representing a 121% increase over 2013 year-end estimated net proved reserves of 14,857 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, on which it drilled a total of 34 gross (28.7 net) wells, and acquisitions made during 2014. This increase was primarily offset by 2014 production and revisions.
The Company ended 2013 with estimated net proved reserves of 14,857 MBOE, representing a 6% increase over 2012 year-end estimated net proved reserves of 14,072 MBOE. The increase iswas primarily due the Company’s development of its properties in the Permian basin, on which it drilled a total of 26 oil wells during 2013. The increase isBasin 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.
The Company ended 2012 with estimated net proved reserves of 14,072 MBOE, representing a 12% decrease over 2011 year-end estimated net proved reserves of 15,928 MBOE. The decrease was 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 27 oil wells during 2012.
Extrapolation of performance history and material balance estimates were utilized by the Company’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 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, and to a small extent, horizontal PDP and PUD categories.
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’s PUDs increased 1%98% to 14,623 MBOE from 7,387 MBOE at December 31, 2014 and 2013, respectively. The Company added 10,125 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 1,757 MBOE, or 24%, included in the year-end 2013 PUD reserves, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $34,619, net. Also offsetting the increase was the removal of 1,132 MBOE of PUDs, including the impact from the reclassification of previous vertical PUDs to the horizontal probable category given our focus on horizontal development.
The Company’s PUDs increased 1% to 7,387 MBOE from 7,337 MBOE at December 31, 2013 and 2012,, 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 reserves, 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 nowwere 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’sCompany'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 to the Company’sCompany's PUDs, offset by (1) 557 MBOE primarily comprised of transfers to PDPs as a result of our development program, (2) 1,148 MBOE related to the sale of Habanero, and (3) 2,227 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 million, net.
85
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except per unit data) |
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,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2014 |
|
| 2013 |
|
| 2012 |
Average 12-month price, net of differentials, per Mcf of natural gas |
| $ | 6.38 |
| $ | 5.45 |
| $ | 4.81 |
Average 12-month price, net of differentials, per barrel of oil |
| $ | 86.30 |
| $ | 92.16 |
| $ | 94.68 |
| 2013 | 2012 | 2011 | ||||||||||
| Average 12-month price, net of differentials, per Mcf of natural gas | $ | 5.45 | $ | 4.81 | $ | 5.60 | ||||||
| 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 Basin and former deepwater offshore properties has a high Btu content of separator natural gas. The natural gas per Mcf prices of $6.38, $5.45 and $4.81 used in the
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Standardized Measure | |||||||
|
| For the Year Ended December 31, | |||||||
|
| 2014 |
| 2013 |
| 2012 | |||
Future cash inflows |
| $ | 2,492,178 |
| $ | 1,193,299 |
| $ | 1,115,570 |
Future costs |
|
|
|
|
|
|
|
|
|
Production |
|
| (873,469) |
|
| (357,005) |
|
| (249,329) |
Development and net abandonment |
|
| (288,081) |
|
| (155,667) |
|
| (273,817) |
Future net inflows before income taxes |
|
| 1,330,628 |
|
| 680,627 |
|
| 592,424 |
Future income taxes |
|
| (164,490) |
|
| (68,239) |
|
| (55,772) |
Future net cash flows |
|
| 1,166,138 |
|
| 612,388 |
|
| 536,652 |
10% discount factor |
|
| (586,596) |
|
| (328,442) |
|
| (305,504) |
Standardized measure of discounted future net cash flows |
| $ | 579,542 |
| $ | 283,946 |
| $ | 231,148 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Changes in Standardized Measure | |||||||
|
| For the Year Ended December 31, | |||||||
|
| 2014 |
| 2013 |
| 2012 | |||
Standardized measure at the beginning of the period |
| $ | 283,946 |
| $ | 231,148 |
|
| 270,357 |
Sales and transfers, net of production costs |
|
| (120,518) |
|
| (78,661) |
|
| (84,044) |
Net change in sales and transfer prices, net of production costs |
|
| (156,066) |
|
| (46,088) |
|
| 47,261 |
Net change due to purchases and sales of in place reserves |
|
| 111,331 |
|
| (145,711) |
|
| (35,665) |
Extensions, discoveries, and improved recovery, net of future production and development costs incurred |
|
| 299,192 |
|
| 212,431 |
|
| 53,446 |
Changes in future development cost |
|
| 186,605 |
|
| 153,983 |
|
| 39,815 |
Revisions of quantity estimates |
|
| (7,673) |
|
| (68,958) |
|
| (77,322) |
Accretion of discount |
|
| 30,114 |
|
| 25,010 |
|
| 30,989 |
Net change in income taxes |
|
| (32,940) |
|
| 1,751 |
|
| 13,969 |
Changes in production rates, timing and other |
|
| (14,449) |
|
| (959) |
|
| (27,658) |
Aggregate change |
|
| 295,596 |
|
| 52,798 |
|
| (39,209) |
Standardized measure at the end of period |
| $ | 579,542 |
| $ | 283,946 |
| $ | 231,148 |
86
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except |
Standardized Measure For the year ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Future cash inflows | $ | 1,193,299 | $ | 1,115,570 | $ | 1,194,079 | |||||
| Future costs - | |||||||||||
| Production | (357,005 | ) | (249,329 | ) | (356,653 | ) | |||||
| Development and net abandonment | (155,667 | ) | (273,817 | ) | (268,628 | ) | |||||
| Future net inflows before income taxes | 680,627 | 592,424 | 568,798 | ||||||||
| Future income taxes | (68,239 | ) | (55,772 | ) | (78,813 | ) | |||||
| Future net cash flows | 612,388 | 536,652 | 489,985 | ||||||||
| 10% discount factor | (328,442 | ) | (305,504 | ) | (219,628 | ) | |||||
| Standardized measure of discounted future net cash flows | $ | 283,946 | $ | 231,148 | $ | 270,357 | |||||
Changes in Standardized Measure For the year ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Standardized measure at the beginning of the period | $ | 231,148 | $ | 270,357 | $ | 198,916 | |||||
| Changes | |||||||||||
| Sales and transfers, net of production costs | (78,661 | ) | (84,044 | ) | (107,297 | ) | |||||
| Net change in sales and transfer prices, net of production costs | (46,088 | ) | 47,261 | 125,518 | |||||||
| Net change due to purchases and sales of in place reserves | (145,711 | ) | (35,665 | ) | 1,275 | ||||||
| Extensions, discoveries, and improved recovery, net of future production and development costs incurred | 212,431 | 53,446 | 22,598 | ||||||||
| Changes in future development cost | 153,983 | 39,815 | (83,110 | ) | |||||||
| Revisions of quantity estimates | (68,958 | ) | (77,322 | ) | (949 | ) | |||||
| Accretion of discount | 25,010 | 30,989 | 68,384 | ||||||||
| Net change in income taxes | 1,751 | 13,969 | (32,918 | ) | |||||||
| Changes in production rates, timing and other | (959 | ) | (27,658 | ) | 77,940 | ||||||
| Aggregate change | 52,798 | (39,209 | ) | 71,441 | |||||||
| Standardized measure at the end of period | $ | 283,946 | $ | 231,148 | $ | 270,357 | |||||
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 policies 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
In April 2012, the Company contracted a drilling rig (the “Cactus 1 Rig”), which it subsequently renewed in December 2014 for a term of two years ending November 2016. In April 2014, the Company contracted an additional horizontal drilling rig (the “Cactus 2 Rig”), which it subsequently renewed in December 2014 for a term of two years ending in November 2016. The Cactus 2 Rig replaced a previously contracted horizontal drilling rig, which was cancelled in March 2014. In August 2014, the Company signed a one-year contract for a vertical drilling rig to be used as part of its horizontal drilling program, drilling the vertical section of horizontal wells. The rig lease agreements include early termination provisions that would reduce the minimum rentals under the agreement, and a joint interest partner entered into a settlement agreement relatedalso include provisions that would reduce the minimal rental payments assuming the lessor is able to various disputes. All matters were settledre-charter the rig and as resultstaffing personnel to another lessee. Subsequent to December 31, 2014, the Company decided to terminate its one-year contract for the vertical rig effective April 2015 and currently may be required to pay approximately $3,733 in reduced rental payments over the remainder of the settlement agreementlease term. Also subsequent to December 31, 2014, the Company received an interestextended the terms of its Cactus 1 Rig and Cactus 2 Rig to end in otherJuly 2018 and August 2018, respectively. Lease payments in 2014 were $17,877 and are expected to approximate $16,893 (including early termination payments), $10,980, $10,950 and $6,510 in 2015, 2016, 2017 and 2018, respectively.
Other property and equipment
During 2012, the Company sold certain specialized deep water property and equipment. The Company recognized a gain of $5,041
87
Callon Petroleum Company | Notes to the Consolidated Financial Statements (All dollar amounts in thousands, except |
NOTE 14Note 15 – SSummarizedummarized Quarterly Financial Information (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
| First Quarter |
| Second Quarter |
| Third Quarter |
| Fourth Quarter | ||||
Total revenues |
| $ | 33,285 |
| $ | 40,502 |
| $ | 39,657 |
| $ | 38,418 |
Income from operations |
|
| 6,645 |
|
| 12,080 |
|
| 11,562 |
|
| 7,983 |
Net income |
|
| 1,863 |
|
| 4,740 |
|
| 12,201 |
|
| 18,962 |
Income (loss) available to common shares |
|
| (111) |
|
| 2,767 |
|
| 10,227 |
|
| 16,988 |
Income (loss) per common share - basic |
| $ | 0.00 |
| $ | 0.07 |
| $ | 0.24 |
| $ | 0.31 |
Income (loss) per common share - diluted |
| $ | 0.00 |
| $ | 0.07 |
| $ | 0.23 |
| $ | 0.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
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) |
| $ | — |
| $ | (0.02) |
| $ | 0.03 |
Income (loss) per common share - diluted |
| $ | (0.02) |
| $ | — |
| $ | (0.02) |
| $ | 0.03 |
88
| 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 | ) | ||||||
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.
Disclosure Controlscontrols and Procedures. 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’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’sOur Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’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, 20132014..
Management’s Reportreport on Internal Controlinternal control over Financial Reportingfinancial 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, 20132014 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (1992(2013 framework)(the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 20132014..
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’s independent registered public accounting firm has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of
December 31,Changes in Internal Controlinternal control over Financial Reporting. 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.
Submissions of Mattersmatters to a Votevote of the Security Holderssecurity holders
None.
89
The Board of Directors and Stockholders of
Callon Petroleum Company
We have audited Callon Petroleum Company’s internal control over financial reporting as of December 31, 20132014 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992(2013 framework)(the COSO criteria). Callon Petroleum Company’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’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’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’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’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’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, 2013,2014, 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, 20132014 and 2012,2013, and the related consolidated statements of operations, comprehensive income, cash flow, and changes in stockholders’ equity (deficit)and cash flows for each of the three years in the period ended December 31, 2013,2014, and our report dated
/s/Ernst & Young LLP
New Orleans, Louisiana
March 12, 2014
90
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 15, 201414, 2015 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 mailing address Post Office Box 1287, Natchez, Mississippi 39121.
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 15, 201414, 2015 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
ITEM 12. SecuritySecurity 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 15, 201414, 2015 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
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 15, 201414, 2015 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
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 15, 201414, 2015 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
91
The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10-K.
Number | ||||||
Exhibit | Description | |||||
1 | The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10-K. | |||||
Report of Independent Registered Public Accounting Firm | ||||||
Consolidated Balance Sheets as of December 31, | ||||||
Consolidated Statements of Operations for each of the three years in the period ended December 31, | ||||||
Consolidated Statements of Stockholders’ Equity (Deficit) for each of the three years in the Period Ended December 31, | ||||||
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, | ||||||
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 through January 17, 2014 (incorporated by reference to Exhibit 3.1 of the Company’s | |||||
3.2 | Certificate of Designation of Rights and Preferences of 10% Series A Cumulative Preferred Stock (incorporated by reference to Exhibit 3.5 of the Company’s Form 8-A filed on May 23, 2013. | |||||
3.3 | Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) | |||||
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’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) | |||||
4.2 | ||||||
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 | ||||||
9 | ||||||
Voting trust agreement | ||||||
None | ||||||
10 | Material contracts | |||||
10.1 | ||||||
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) | ||||||
10.2 | ||||||
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) | ||||||
10.3 | 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) | |||||
10.4 | 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) | |||||
10.5 | 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) | |||||
92
10.6 | 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) | |||||
10.7 | 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) | |||||
10.8 | 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) | |||||
10.9 | 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) | |||||
10.10 | 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’s Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-14039) | |||||
10.11 | 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’s Current Report on Form 8-K filed on March 18, 2011) | |||||
10.12 | 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’s Current Report on Form 8-K filed on March 18, 2011) | |||||
10.13 | ||||||
Callon Petroleum Company 2011 Omnibus Incentive Plan (incorporated by reference from Exhibit A of the Company’s Definitive Proxy Statement on Schedule 14A filed March 21, 2011, File No. 14039) | ||||||
10.14 | ||||||
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) | ||||||
10.15 | Fifth Amended and Restated Credit Agreement among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders and parties named therein dated March 11, 2014 (incorporated by reference to Exhibit 10.1 to the Company’s Report on Form 10-Q/A filed June 11, 2014) | |||||
10.16 | Operator Resignation and Transition Agreement between Callon Petroleum Operating Company and Henry Resources LLC dated August 29, 2014 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed October 14, 2014) | |||||
10.17 | Purchase and Sale Agreement between Callon Petroleum Operating Company, as Purchaser, and NAWAB energy partners, lp and NAWAB WI, lp, as Sellers, dated August 29, 2014 (incorporated by reference to Exhibit 10.2 of the Company’s Report on Form 8-K filed October 14, 2014) | |||||
10.18 | Purchase and Sale Agreement between Callon Petroleum Operating Company, as Purchaser, and Hedloc Investment Co. LP, as Seller, dated August 29, 2014 (incorporated by reference to Exhibit 10.3 of the Company’s Report on Form 8-K filed October 14, 2014) | |||||
10.19 | Amendment No. 2 to Fifth Amended and Restated Credit Agreement among Callon Petroleum Company, JPMorgan Chase Bank, National Association, as administrative agent and the Lenders and parties named therein dated October 8, 2014 (incorporated by reference to Exhibit 10.4 of the Company’s Report on Form 8-K filed October 14, 2014) | |||||
10.20 | Second Lien Credit Agreement among Callon Petroleum Company, Royal Bank of Canada and the Lenders party thereto, dated October 8, 2014 (incorporated by reference to Exhibit 10.5 of the Company’s Report on Form 8-K filed October 14, 2014) | |||||
10.21 | Second Lien Intercreditor Agreement among Callon Petroleum Company, JPMorgan Chase Bank, National Association, Royal Bank of Canada, and the other parties named therein dated October 8, 2014 (incorporated by reference to Exhibit 10.6 of the Company’s Report on Form 8-K filed October 14, 2014) | |||||
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* | |||||
93
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 DeGolyer and MacNaughton, Inc. | |||||
23.3 | 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 | |||||
101 | Interactive Data Files ** | |||||
* | 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. |
94
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. | ||||
Callon Petroleum Company | ||||
Date: | March 4, 2015 | /s/ Joseph C. Gatto, Jr. | ||
By: Joseph C. Gatto, Jr., senior vice president, | ||||
chief financial officer (principal financial officer) and treasurer | ||||
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. | ||||
Date: | March 4, 2015 | |||
/s/ Fred L. Callon | ||||
Fred L. Callon (principal executive officer, director) | ||||
Date: | March | /s/ | ||
Joseph C. Gatto, Jr. (principal financial | ||||
Date: | March | /s/ | ||
Mitzi P. Conn (principal accounting officer) | ||||
Date: | March | /s/ L. Richard Flury | ||
L. Richard Flury (director) | ||||
Date: | March | /s/ John C. Wallace | ||
John C. Wallace (director) | ||||
Date: | March | /s/ Anthony J. Nocchiero | ||
Anthony J. Nocchiero (director) | ||||
Date: | March | /s/ Larry D. McVay | ||
Larry McVay (director) | ||||
Date: | March 4, 2015 | /s/ Matthew R. Bob | ||
Matthew R. Bob (director) | ||||
Date: | March 4, 2015 | /s/ James M. Trimble | ||
James M. Trimble (director) | ||||
95