CPE-2012.12.31-10K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-K
for the year ended
December 31, 2012
[X]
Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2012, or
[   ]
Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from____ to____
Commission File Number 001-14039
CALLON PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
64-0844345
(I.R.S. Employer Identification No.)
200 North Canal Street
Natchez, Mississippi
(Address of principal executive offices)
 39120
(Zip Code)
601-442-1601
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class:
Name of each exchange on which registered:
Common Stock, $.01 par value
New York Stock Exchange
Securities registered pursuant to section 12 (g) of the Act: None
Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes   [   ]
No   [ X ]
Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes   [   ]
No   [ X ]
 
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   [ X ]
No   [   ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes   [ X ]
No   [   ]

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):
Large accelerated filer [   ]
Accelerated filer [ X ]
Non-accelerated filer [  ]
Smaller reporting company [   ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes   [   ]
No   [ X ]
The aggregate market value of the voting and non-voting common equity stock held by non-affiliates of the registrant was $162.0 million as of June 30, 2012.
As of March 8, 2013, 39,870,136 shares of the Registrant’s common stock, par value $.01 per share, were outstanding.
Documents Incorporated by Reference 
Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2012) relating to the Annual Meeting of Stockholders to be held on May 16, 2013, which are incorporated into Part III of this Form 10-K.

Table of Contents

 
 
TABLE OF CONTENTS
 
 
 
 
Page(s)
Special Note Regarding Forward-Looking Statements
Definitions
Part I
 
Items 1 and 2.
 
 
 
 
Crude Oil and Natural Gas Properties
 
 
 
 
 
 
 
 
 
 
Part II
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Consolidated Statements of Stockholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Part III
 
 
 
Part IV
 
 
 
 
 

2

Special Note Regarding Forward Looking Statements
 
All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve quantities, present value and growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.
 
Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10-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 commodities (including regional basis differentials),
•
our ability to transport our production to the most favorable markets or at all,
•
the timing and extent of our success in discovering, developing, producing and estimating reserves,
•
our ability to respond to low natural gas prices,
•
our ability to fund our planned capital investments,
•
the impact of government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over-the-counter derivatives,
•
the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services,
•
our future property acquisition or divestiture activities,
•
the effects of weather,
•
increased competition,
•
the financial impact of accounting regulations and critical accounting policies,
•
the comparative cost of alternative fuels,
•
conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed,
•
credit risk relating to the risk of loss as a result of non-performance by our counterparties, and
•
any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission (“SEC”).

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, 2012 and all quarterly reports on Form 10-Q filed subsequently thereto (“Form 10-Qs”).

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

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


3
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DEFINITIONS

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

•
3-D: three-dimensional.
•
ARO:  Asset Retirement Obligation.
•
Bbl or Bbls:  barrel or barrels of oil or natural gas liquids.
•
Bcf:  billion cubic feet.
•
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.
•
Boe/d:  Boe per day.
•
BLM: Bureau of Land Management.
•
BOEM:  Bureau of Ocean Energy Management, Regulation and Enforcement; formerly the Minerals Management Service ("MMS").
•
Btu:  a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
•
BSEE: Bureau of Safety and Environmental Enforcement.
•
DOI: Department of Interior.
•
EPA: Environmental Protection Agency.
•
GHG: greenhouse gases.
•
LIBOR:  London Interbank Offered Rate.
•
Mbbls:  thousand barrels of oil.
•
Mboe:  thousand boe.
•
Mboe/d:  Mboe per day.
•
Mcf:  thousand cubic feet of natural gas.
•
Mcfe:  thousand cubic feet of natural gas equivalents.
•
Mcf/d:  Mcf per day.
•
MMbbls:  million barrels of oil.
•
MMboe:  million boe.
•
MMBtu:  million Btu.
•
MMcf:  million cubic feet of natural gas.
•
MMcf/d:  MMcf per day.
•
MMS: Minerals Management Service.
•
NGL or NGLs:  natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.
•
NYMEX:  New York Mercantile Exchange.
•
OCS: outer continental shelf.
•
Oil: includes crude oil and condensate.
•
ONRR: Office of Natural Resources Revenue.
•
PDPs:  proved developed producing reserves.
•
PDNPs: proved developed non-producing reserves.
•
PUDs:  proved undeveloped reserves.
•
Reserve life: a measurement of the time it will take to produce our proved reserves calculated by dividing our estimate net equivalent reserves at December 31, 2012 by our total production during 2012 on an equivalent basis.
•
SEC:  United States Securities and Exchange Commission.
•
US GAAP: Generally Accepted Accounting Principles in the United States

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


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PART I.

Items 1 and 2 - Business and Properties

Overview and Business Strategy

Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950.  The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management.  As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.

In 2009, the Company began to shift its operational focus from exploration, development and production in the Gulf of Mexico to the acquisition and development of onshore properties. Currently, our onshore properties located in the Permian Basin in Texas are the foundation of our onshore strategy.  As of December 31, 2012, we had estimated net proved reserves of 10.8 MMbbls and 19.8 Bcf, or 14.1 MMboe.  Of these reserves and on an MMboe basis, approximately 68% were located onshore in the Permian Basin, compared with approximately 61% located onshore at December 31, 2011. Additionally, 77% of our proved reserve volumes were crude oil at year-end 2012 compared to 63% at year-end 2011.

Our Business Strategy

Our goal is to increase stockholder value by:

•
Continuing to build our onshore production base through:
◦
conversion of our existing Permian acreage position to production
◦
leveraging our technical and operational teams across a larger production base
◦
pursuing opportunistic producing property and leasehold acquisitions

•
Focusing on capital efficiency through:
◦
exploiting Permian resources through repeatable program drilling
◦
continuing to invest in supporting infrastructure
◦
high-grading of capital allocation across our expanded drilling portfolio continuing to refine our vertical and horizontal completion techniques and target zones

•
Delivering on asset growth potential through:
◦
focusing on an established production base from vertical Wolfberry wells
◦
the drilling inventory of horizontal locations identified in 2012 from our evaluation efforts in the southern Midland basin from horizontal locations developed in 2012
◦
exploration activities on our acreage in the northern Midland basin



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Our Strengths

We believe that we are well positioned to achieve our business objectives and to execute our strategy due to the following factors:

•
We have assembled a Permian leasehold position of over 32,900 net acres that are prospective for the exploration, development and exploitation of multiple oil-bearing intervals through both vertical and horizontal drilling.

•
Our initial horizontal drilling efforts commenced in 2012 have resulted in a large inventory of drillable locations in the southern Midland basin for future development of two zones of the Wolfcamp shale, complementing our existing vertical drilling program. We continue to evaluate other intervals prospective for horizontal development that may add to this inventory depending on evaluation results by us and other industry players.

•
We continue to replace high decline-rate, natural gas production from the Gulf of Mexico shelf area with longer reserve life, liquids-rich production from our Permian drilling programs. As a result, we have increased our reserve life 185% to 8.9 years at year-end 2012 from 4.8 years at year-end 2008.

•
Our offshore properties generate substantial cash flow, which we can redeploy in the acquisition, exploration and development of onshore properties. Since initiating our onshore transition strategy in 2009, we have invested nearly $263 million of offshore cash flow into our onshore initiatives.
 
•
Effective December 28, 2012, we sold our interest in the Habanero field for net cash consideration of $39.4 million, accelerating our cash flows from this offshore property and monetizing the value of additional undeveloped reserve potential. These proceeds allowed us to substantially reduce the outstanding balance on our Senior Secured Revolving Credit Facility (the "Credit Facility"), strengthening our liquidity in 2013 to support our Permian-focused capital development program.

•
On December 31, 2012, our total liquidity position was approximately $56.1 million, including $1.1 million of available cash and $55 million of unused borrowing base available under our Credit Facility.  The $65 million borrowing base at December 31, 2012 increased by $20 million or 44% over the base at December 31, 2011.

•
We have assembled a management team experienced in oil and natural gas acquisitions, exploration, development and production in the areas in which we focus our operations, with an average of 28 years of experience in their relevant fields of expertise. Our technical and operational teams continue to benefit from the knowledge gained from our increased level of activity in the Permian basin and from the addition of new employees with significant industry experience.

Exploration and Development Activities

Our 2012 capital expenditures approximated $147 million, and represented a 39% increase over 2011 actual capital expenditures. Of the $147 million, approximately 88% was allocated to onshore drilling, development and leasehold acquisition activity in the Permian basin. During 2012, capital expenditures on an accrual basis for exploration and development costs related to oil and natural gas properties included the following expenditures (in millions):
Southern Midland basin
 
$
70.3

Northern Midland basin
 
21.4

Leasehold acquisitions and seismic
 
37.2

Plugging and abandonment costs in the Gulf of Mexico
 
2.3

Capitalized interest
 
2.0

Capitalized general and administrative costs allocated directly to exploration and development projects
 
13.3

Total capital expenditures
 
$
146.5


With our continued operational focus onshore, primarily in the Permian basin, we expect that over 92% of our 2013 capital expenditures will be focused on the acquisition, exploration, development and operation of onshore properties, with only 8% of capital expenditures directed towards our offshore properties, excluding the capital required for the subsea development project discussed below. In addition to the 2013 capital program, which is outlined within Management's Discussion and Analysis (Part II, Item 7), we have received various long-lead time requests for capital expenditures related to the proposed subsea development of the Medusa field, and we expect to receive additional requests throughout 2013. The operator plans to begin drilling these

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wells will begin in the first quarter of 2014. For additional information, please refer to our Offshore - Deepwater discussion, which is also located within Management's Discussion and Analysis.

Recent Developments

Acquisitions

During the first quarter of 2012, the Company acquired approximately 16,233 gross (14,653 net) acres in Borden county, Texas, which is located in the northern Midland basin. The northern Midland basin has had limited drilling activity compared with the southern Midland basin (where our current production is located), increasing the risk of success for these drilling activities. The purchase price of $14.5 million 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 $4.8 million.

During the second quarter of 2012, the Company signed a purchase and sale agreement to acquire 2,319 gross (1,762 net) acres in southern Reagan county, Texas for a total purchase price of $12.0 million, which was financed with a draw on the Company's Credit Facility. The transaction had an effective date of May 1, 2012 and closed on July 5, 2012.

Divestitures

On December 28, 2012, we closed the sale of our 11.25% working interest in the Habanero field (Garden Banks Block 341) to Shell Offshore Inc., a subsidiary of Royal Dutch Shell Plc, for an estimated net cash consideration of $39.4 million after customary purchase price adjustments. We used the proceeds from the sale to reduce outstanding borrowings on our Credit Facility, providing additional liquidity to fund our 2013 capital program. The borrowing base under our Credit Facility was revised to $65 million following the Habanero sale, and was redetermined as scheduled in the first quarter of 2013 based upon the evaluation of year-end proved reserves.



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Table of Contents

Crude Oil and Natural Gas Properties

As of December 31, 2012, our estimated net proved reserves totaled 14.1 MMBoe and included 10.8 MMBbls and 19.8 Bcf, with a pre-tax present value, discounted at 10%, of $250.1 million.  Pre-tax present value is a non-US GAAP financial measure, which we reconcile to the US GAAP standardized measure of $231.1 million in note (d) to the table below.  Oil constitutes approximately 77% of our total estimated equivalent net proved reserves and approximately 48% of our total estimated equivalent proved developed reserves.

The following table sets forth certain information about our estimated net proved reserves prepared by our independent petroleum reserve engineers by major field and for all other properties combined at December 31, 2012: 
 
 
 
 
 
 
 
 
 
Pre-tax
Discounted
 
 
 
Estimated Net Proved Reserves
 
Present
 
Operator
 
Oil
(MBbls)
 
Natural Gas
(MMcf)
 
Total
(MBoe)
 
Value
($000)
 
 
 
 
 
 
 
(a)
 
(b)(c)(d)
Onshore:
 
 
 
 
 
 
 
 
 
   Permian basin
Callon
 
7,209

 
13,242

 
9,416

 
$
78,950

   Haynesville shale
Callon
 
—

 
1,231

 
205

 
$
666

     Total Onshore
 
 
7,209

 
14,473

 
9,621

 
$
79,616

 
 
 
 
 
 
 
 
 
 
Gulf of Mexico Deepwater:
 
 
 
 
 
 
 
 
 
  Mississippi Canyon 538/582
 
 
 
 
 
 
 
 
 
    “Medusa”
Murphy
 
3,551

 
2,083

 
3,898

 
$
179,967

     Total Gulf of Mexico Deepwater
 
 
3,551

 
2,083

 
3,898

 
$
179,967

 
 
 
 
 
 
 
 
 
 
Gulf of Mexico Shelf and Other:
 
 
 
 
 
 
 
 
 
  West Cameron Block 295
Apache
 
5

 
954

 
164

 
$
1,081

   East Cameron Block 2
Apache
 
5

 
487

 
86

 
633

   East Cameron Block 257
SandRidge Energy
 
—

 
1,182

 
197

 
(718
)
   Other (c)
Various
 
10

 
574

 
106

 
(10,482
)
     Total Gulf of Mexico Shelf and Other
 
 
20

 
3,197

 
553

 
$
(9,486
)
 
 
 
 
 
 
 
 
 
 
Total Net Proved Reserves
 
 
10,780

 
19,753

 
14,072

 
$
250,097


(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 an Mcf of natural gas compared with a Bbl of oil or NGLs.  On a market price equivalence basis, a barrel of oil or NGLs has a substantially higher price than six Mcf of natural gas.
(b)
Represents the present value of future net cash flows before deduction of federal income taxes, discounted at 10%, attributable to estimated net proved reserves as of December 31, 2012, as set forth in the Company’s reserve reports prepared by its independent petroleum reserve engineers, Huddleston & Co., Inc.
(c)
Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2012, in accordance with accounting for asset retirement obligations rules.   The negative Pre-Tax Discounted Present Value of the “Other” reflects plugging and abandonment obligations exceeding the future net cash flows, with most of such obligations estimated to occur within the next five years.
(d)
The Company uses the financial measure “Pre Tax Discounted Present Value” which is a non-US GAAP financial measure.  The Company believes that Pre Tax Discounted Present Value, while not a financial measure in accordance with US GAAP, is an important financial measure used by investors and independent oil and gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially.  The total standardized measure calculated in accordance with the guidance issued by the FASB for disclosures about oil and gas producing activities for our proved reserves as of December 31, 2012 was $231.1 million inclusive of the $18.9 million discounted estimated future income taxes relating to such future net revenues.  The projected per Mcf natural gas price of $4.81 used in the 2012 reserve estimates has been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected per barrel oil price of $94.68 used in the 2012 reserve estimates has been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.


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Onshore Properties
 
Onshore proved reserves accounted for approximately 68% of year-end 2012 proved reserves on a Boe basis as compared to 61% of 2011 reserves on a Boe basis, consistent with our strategy of using our offshore cash flow to explore and develop our onshore properties and following the sale of our offshore interest in the Habanero field.
 
Permian Basin

As of December 31, 2012, we owned approximately 32,962 net acres in the Permian basin, where we are exclusively focused on the Midland sub-basin. Our reserves in the Permian basin represent approximately 67% of our total proved reserves at year-end 2012 as compared to 48% at year-end 2011. Average net production from the Company's Permian basin properties increased 67% to 1,614 Boe/d in 2012 from 967 Boe/d in 2011.

We describe our activities in the Permian basin based on two geographic areas, the southern and northern Midland basin, given their relative stages of development.

The southern portion of our position (located in Texas counties of Crockett, Upton, Midland, Ector, Reagan and Glasscock) represents the vast majority of our current Permian production. We have been pursuing a vertical development program in this area since our entry into the Permian in 2009, drilling 71 gross (63 net) vertical wells over that period. In 2012, we commenced the horizontal drilling of our properties in Upton and Reagan counties, drilling three net wells targeting the Wolfcamp B shale.

Our northern Midland basin position was established in 2012 with the acquisition of 24,328 gross (21,617 net) acres in Borden and Lynn counties. We began our exploration program in Borden county during the second half of 2012, drilling one gross (0.8 net) vertical and two gross (1.8 net) horizontal wells, targeting the Cline and Mississippi lime.

The following table summarizes our wells drilled and completed by area during 2012:

Property
 
Drilling
 
Completion
 
 
Gross
 
Net
 
Gross
 
Net
Southern Midland basin vertical wells
 
15

 
10.7

 
22

 
16.0

Southern Midland basin horizontal wells
 
3

 
2.8

 
2

 
2.0

     Total
 
18

 
13.5

 
24

 
18.0

 
 
 
 
 
 
 
 
 
Property
 
Drilling
 
Completion
 
 
Gross
 
Net
 
Gross
 
Net
Northern Midland basin vertical wells
 
1

 
0.8

 
—

 
—

Northern Midland basin horizontal wells
 
2

 
1.8

 
1

 
1.0

     Total
 
3

 
2.6

 
1

 
1.0


Other

We own a 69% working interest in a 429 net acre unit of the Haynesville shale natural gas unit located in southern Bossier parish, Louisiana. As of December 31, 2012, our Haynesville shale proved reserves were reduced by 90% compared to year-end 2011 due to low natural gas prices. During 2012, our one producing well produced 3% of our total production on an equivalent basis. Also during 2012, this well was shut-in for a combined 112 days during the fourth quarter of 2011 and the first quarter of 2012 due to well interference from an offsetting well. Production was restored in mid-March 2012 following a successful remediation operation and, as of December 31, 2012, our Haynesville well was producing approximately 751 Mcf of natural gas per day. We currently have no drilling obligations related to this lease position and will wait for natural gas prices to return to a level that would justify capital allocation within our portfolio before recommencing our development of the field.



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Gulf of Mexico Deepwater

Medusa, Mississippi Canyon Blocks 538/582

The Medusa field, in which we own a 15% working interest, is located in 2,235 feet of water approximately 50 miles offshore Louisiana, and currently produces from eight existing wellbores. Murphy Exploration & Production Company (“Murphy”), the operator, owns a 60% working interest and ENI Deepwater, LLC, owns the remaining 25% working interest. Since the field entered production in 2003, cumulative gross volumes have approximated 58 MMBoe.

During 2012, the Medusa field produced 464 MBoe net to Callon from eight wells which accounted for 29% of our total production. Six of the field's wells continue to produce from their initial completions as of December 31, 2012. We project that 1.1 MMBoe of net PDNPs can be accessed by recompletions in the existing wells. These up-hole recompletions in existing wellbores are expected to occur as existing completions deplete to a level that is uneconomic to justify continued production. We anticipate the development of our current net 1.3 MMBoe of PUD reserves in conjunction with a subsea development program to be commenced during 2014.

Gulf of Mexico Shelf

Approximately 4% of our year-end 2012 proved reserves were attributable to the shelf area of the Gulf of Mexico and other properties. We own interests in 14 producing wells in eight oil and natural gas fields in the shelf area of the Gulf of Mexico area. These wells produced 340 MBoe net to our interest in 2012, which accounted for 22% of our total production.

For additional information regarding the Company's properties, including its 2013 capital expenditures program and future development plans, please refer to the Properties discussion within Management's Discussion and Analysis, which is located in Part II, Item 7 of this filing.



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Proved Reserves
 
Estimates of volumes of proved reserves, net to our interest, at year end are presented in MBbls for oil and in MMcf for natural gas, including NGLs, at a pressure base of 15.025 pounds per square inch.  Total volumes are presented in MBoe.  For the MBoe computation, 6,000 cubic feet of gas are the equivalent of one barrel of oil.

The following table sets forth certain information about our estimated net proved reserves.  All of our proved reserves are located in the continental United States and in federal and state waters in the Gulf of Mexico.
 
 
Years Ended December 31,
 
 
2012
 
2011
 
2010
Proved developed:
 
 
 
 
 
 
Oil (MBbls)
 
4,955

 
5,069

 
4,503

Natural gas (MMcf)
 
10,680

 
11,605

 
12,715

MBoe
 
6,735

 
7,003

 
6,622

Proved undeveloped:
 
 
 
 
 
 
Oil (MBbls)
 
5,825

 
5,006

 
3,645

Natural gas (MMcf)
 
9,073

 
23,513

 
20,241

MBoe
 
7,337

 
8,925

 
7,019

Total proved:
 
 
 
 
 
 
Oil (MBbls)
 
10,780

 
10,075

 
8,149

Natural gas (MMcf)
 
19,753

 
35,118

 
32,957

MBoe
 
14,072

 
15,928

 
13,641

Estimated pre-tax future net cash flows (a)
 
$
592,424

 
$
568,798

 
$
379,448

Pre-tax discounted present value (a) (b)
 
$
250,097

 
$
309,890

 
$
205,532

Standardized measure of discounted future net cash flows(a) (b)
 
$
231,148

 
$
270,357

 
$
198,916


(a)
Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2012, in accordance with accounting for asset retirement obligations rules.
(b)
The Company uses the financial measure “Pre-tax discounted present value” which is a non-US GAAP financial measure. The Company believes that Pre-tax discounted present value, while not a financial measure in accordance with US GAAP, is an important financial measure used by investors and independent oil and gas producers for evaluating the relative value of crude oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The total standardized measure calculated in accordance with the guidance issued by the FASB for disclosures about oil and gas producing activities for our proved reserves as of December 31, 2012 was $231.1 million inclusive of the $18.9 million discounted estimated future income taxes relating to such future net revenues. The natural gas Mcf prices of $4.81 used in the 2012 reserve estimates have been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected crude oil prices of $94.68 used in the 2012 reserve estimates have been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.

See Note 14 of our Consolidated Financial Statements for the additional information regarding the Company’s reserves including its estimates of proved reserves, PDPs, PUDs and the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves.

Estimated net proved reserves at December 31, 2012, represented a 12% decrease over 2011 year-end estimated net proved reserves primarily due to the sale of the Company's interest in the Habanero field and the downward revision of our Haynesville Shale undeveloped reserves at year-end 2012, which were reduced due to low natural gas pricing assumptions. These decreases were partially offset by the Company's development of a portion of its Permian basin, on which it added 7 PDP and 19 PUD wells during 2012.



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Proved Undeveloped Reserves ("PUDs")
 
Annually, the Company reviews its PUDs to ensure appropriate plans exist for development. Except as noted below, reserves are recognized as PUDs only if the Company has plans to convert the PUDs into PDPs within five years of the date they are first recorded as PUDs.   The basis for our development plans include the allocation of capital to projects included within our 2013 capital budget and, in subsequent years, the allocation of capital within our long-range business plan. Generally, our 2013 capital budget and our long-range capital plans are governed by our expectations of internally generated cash flow and Credit Facility borrowing availability.  Reserve calculations at any end-of-year period are representative of our development plans at that time.  Changes in commodity pricing, oilfield service costs and availability, and other economic factors may lead to changes in development plans.

The following table summarizes the Company’s recorded PUDs:
 
PUDs (MBoe) at December 31,
 
2012
 
2011
 
2010
Permian basin
6,040

 
4,861

 
2,928

Haynesville shale
—

 
1,730

 
1,757

   Total Onshore PUDs
6,040

 
6,591

 
4,685

Medusa
1,297

 
1,186

 
1,186

Habanero (a)
—

 
1,148

 
1,148

   Total Deepwater PUDs
1,297

 
2,334

 
2,334

   Total PUDs
7,337

 
8,925

 
7,019


(a)
Effective December 28, 2012, we sold our interest in the Habanero field. See Note 12 for additional information.

The Company's PUDs decreased 18% to 7,337 MBoe from 8,925 MBoe at December 31, 2012 and 2011, respectively. Additions during the year added 2,344 MBoe to the Company'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 our year-end 2011 PUD reserves, 6% were converted to proved developed producing reserves by year end 2012, at a total cost of approximately $19 million, net.

Our 1,297 MBoe of deepwater PUDs have been classified as PUDs for more than five years, though we expect to develop these PUDs within the next two years. Our decision to classify these reserves as PUDs was primarily based on (1) our ongoing development planning in the area, (2) our historical record of completing development of comparable long-term projects, (3) the amount of time which we have maintained the leases or booked reserves without significant development activities and (4) the extent to which we have followed previously adopted development plans. Our discussions with the field's operator have resulted in the modification of certain development plans for Medusa to drill or sidetrack PUDs within a shorter period of time than originally estimated. The Company expects to drill a new well in 2014 within the Medusa field to access the PUD reserves of 1,297 MBoe. During 2012, the Company did not convert any offshore PUDs to PDPs. 

The Company's plans to develop its onshore, Permian basin PUDs as part of a multi-year drilling program, which is expected to be completed on existing acreage within five years of the initial recording of any PUD. 

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 30 years of industry experience including 25 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"), a Texas registered engineering firm, as our independent petroleum and geological firm.   The Company provided to Huddleston information about our oil and gas properties, including production profiles, prices and costs, and Huddleston prepared its own estimates of the reserves attributable to the Company’s properties.  All of the information regarding reserves in this annual report is derived from Huddleston’s report. Huddleston's reserve report letter is included as an Exhibit to this annual report.  The principal engineer at Huddleston who is

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responsible for preparing the Company’s reserve estimates has over 30 years of experience in the oil and gas industry and is a Texas Licensed Professional Engineer.  Further professional qualifications include a degree in petroleum engineering.
 
To further enhance the control environment over the reserve estimation process, our Board of Directors includes a Strategic Planning Committee whose purpose, as stated in the Committee's charter, includes assisting management and the Board with its oversight of the integrity of the determination of the Company's oil, natural gas and natural gas liquids reserves and work of the Huddleston. The Committee's charter also specifies that the Committee shall perform, in consultation with the Company's management and senior reserves and reservoir engineering personnel, the following responsibilities:

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

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

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

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

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



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Production Volumes, Average Sales Prices and Average Operating Costs

The following table sets forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, the Company’s sale of crude oil and natural gas for the periods indicated.
 
Years Ended December 31,
 
2012
 
2011
 
2010
 
(in thousands, except per unit data)
Production
 
 
 
 
 
Natural gas and NGLs (Mcf)
3,588

 
5,081

 
4,892

Crude oil (MBbl)
977

 
996

 
859

Total (MBoe)
1,575

 
1,843

 
1,674

 
 
 
 
 
 
Revenues
 

 
 

 
 

Natural gas and NGL sales
$
14,149

 
$
26,682

 
24,639

Crude oil sales
96,584

 
100,962

 
65,243

Total revenues
$
110,733

 
$
127,644

 
$
89,882

 
 
 
 
 
 
Lease Operating Expenses
 

 
 

 
 

Production costs
$
22,981

 
$
17,693

 
$
15,770

Severance/production taxes
2,430

 
1,826

 
816

Gathering
349

 
592

 
802

Ad Valorem
794

 
236

 
324

Total lease operating expenses
$
26,554

 
$
20,347

 
$
17,712

 
 
 
 
 
 
Realized prices
 

 
 

 
 

Natural gas ($/Mcf, including realized gains (losses) on derivatives) (a)
$
3.94

 
$
5.25

 
$
5.04

Natural gas ($/Mcf, excluding realized gains (losses) on derivatives) (a)
3.94

 
5.25

 
4.91

Crude oil ($/Bbl, including realized gains (losses) on derivatives) (b)
98.86

 
101.34

 
75.97

Crude oil ($/Bbl, excluding realized gains (losses) on derivatives) (b)
97.41

 
101.72

 
75.97

 
 
 
 
 
 
Operating costs per Boe - Total Consolidated
 

 
 

 
 

Production costs
$
14.59

 
$
9.60

 
$
9.61

Severance/production taxes
1.54

 
0.99

 
0.49

Gathering
0.22

 
0.32

 
0.48

Ad Valorem
0.50

 
0.13

 
0.19

Total operating costs per Boe
$
16.85

 
$
11.04

 
$
10.77


(a)
Natural gas prices exceeded the related NYMEX prices, which are quoted on an MMBtu basis, primarily due to the value of the NGLs in our liquids-rich natural gas stream, primarily from our Permian basin and deepwater production.

(b)
Crude oil prices for production from our two deepwater fields reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production and Argus Bonita WTI differential for Habanero production, prior to the sale of Habanero during December 2012.



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Present Activities and Productive Wells
 
The following table sets forth the wells drilled and completed during the periods indicated. All such wells were drilled in the continental United States and in federal and state waters in the Gulf of Mexico. At December 31, 2012, the Company was in the process of drilling one exploratory well (which is excluded from the table below) and had four wells awaiting fracture stimulation.
 
Years ended December 31,
 
2012
 
2011
 
2010
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development:
 
 
 
 
 
 
 
 
 
 
 
Crude oil
14

 
9.70

 
36

 
32.77

 
20

 
19.37

Natural gas
—

 
—

 
—

 
—

 
1

 
0.69

Non-productive
—

 
—

 
—

 
—

 
—

 
—

   Total
14

 
9.70

 
36

 
32.77

 
21

 
20.06

 
 
 
 
 
 
 
 
 
 
 
 
Exploration:
 
 
 
 
 
 
 
 
 
 
 
Crude oil
7

 
6.20

 
—

 
—

 
—

 
—

Natural gas
—

 
—

 
—

 
—

 
—

 
—

Non-productive
—

 
—

 
—

 
—

 
—

 
—

   Total
7

 
6.20

 
—

 
—

 
—

 
—


Wells drilled within the productive boundaries of statistical plays, such as on our southern Midland basin acreage, have been classified as development wells.

The following table sets forth productive wells as of December 31, 2012:
 
Crude Oil Wells
 
Natural Gas Wells
 
Gross
 
Net
 
Gross
 
Net
Working interest
103

 
84.50

 
10

 
4.30

Royalty interest
3

 
0.10

 
2

 
0.08

Total
106

 
84.60

 
12

 
4.38

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

For the periods presented, the following table sets forth by major field(s) net production volumes and estimated proved reserves:
 
 
Year ended December 31,
 
 
Production Volumes (MBoe)
 
% of Total Proved Reserves at 12/31/2012
Offshore - Gulf of Mexico:
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
Medusa
 
464

 
641

 
593

 
28
%
 
27
%
 
33
%
Habanero
 
134

 
197

 
233

 
—
%
 
8
%
 
10
%
Shelf and other
 
340

 
551

 
616

 
4
%
 
4
%
 
7
%
Total offshore:
 
938

 
1,389

 
1,442

 
32
%

39
%
 
50
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Onshore:
 
 
 
 
 
 
 
 
 
 
 
 
Permian basin
 
591

 
353

 
150

 
67
%
 
48
%
 
33
%
Haynesville shale
 
46

 
101

 
82

 
1
%
 
13
%
 
17
%
Total onshore:
 
637

 
454

 
232

 
68
%

61
%
 
50
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
1,575

 
1,843

 
1,674

 
100
%

100
%
 
100
%



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Leasehold Acreage

The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2012.  
 
Developed
 
Undeveloped
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Louisiana
1,741

 
681

 
233

 
167

 
1,974

 
848

Texas (a)
10,891

 
8,914

 
27,236

 
24,048

 
38,127

 
32,962

Federal onshore (b)
—

 
—

 
64,963

 
64,963

 
64,963

 
64,963

Federal waters (c)
44,920

 
17,136

 
23,715

 
7,599

 
68,635

 
24,735

   Total
57,552

 
26,731

 
116,147

 
96,777

 
173,699

 
123,508


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

(b)
The Company's lease of this acreage, located in Nevada, has approximately six years remaining, and had a carrying value at December 31, 2012 of approximately $2.6 million included in the Company's unevaluated properties balance. The lease requires no drilling activity to hold the acreage, and we continue to monitor the activity of other operators conducting drilling in the area.

(c)
The Company's federal waters acreage is held by production.

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

•
royalties and other burdens and obligations, express or implied, under oil and natural gas leases,
•
overriding royalties and other burdens created by us or our predecessors in title,
•
a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the properties or their titles,
•
back-ins and reversionary interests existing under purchase agreements and leasehold assignments,
•
liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements,
•
pooling, unitization and communitization agreements, declarations and orders, and
•
easements, restrictions, rights-of-way and other matters that commonly affect property.

To the extent that such burdens and obligations affect the Company'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 both onshore and offshore operations (including sudden and accidental pollution), physical damage to its offshore oil and natural gas properties, aviation liability, auto liability, worker's compensation, employer's liability, and maritime employers liability. The company carries control of well insurance for all offshore wells, though unless contractually bound to do so, the Company does not carry control of well insurance for onshore operations. At the depths and in the areas in which the Company operates, and in light of the vertical and horizontal drilling that it undertakes, the Company typically does not encounter high pressures or extreme drilling conditions onshore.

Currently, the Company has general liability insurance coverage up to $1 million per occurrence and $2 million per policy in the aggregate, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties

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arising from its operations. The Company's insurance policies contain high policy limits, and in most cases, deductibles (generally ranging from $0 to $1.5 million) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, the Company maintains up to $100 million in excess liability coverage, which is in addition to and triggered if the underlying liability limits have been reached.

The Company requires all of its third-party contractors to sign master service agreements in which they agree to indemnify the Company for injuries and deaths of the service provider'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 future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.

Major Customers

Our production is sold generally on month-to-month contracts at prevailing prices.  The following table identifies customers to whom we sold a significant percentage of our total oil and natural gas production, on an equivalent basis, during each of the 12-month periods ended:
 
December 31,
 
2012
 
2011
 
2010
Shell Trading Company
39
%
 
45
%
 
44
%
Plains Marketing, L.P.
15
%
 
17
%
 
20
%
Enterprise Crude Oil, LLC
32
%
 
16
%
 
—
%
Louis Dreyfus Energy Services
2
%
 
4
%
 
13
%
Other
12
%
 
18
%
 
23
%
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 87 employees as of December 31, 2012, which included 13 petroleum engineers and four petroleum geoscientists.  None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees.



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Regulations

General. The oil and natural gas industry is subject to regulation at the federal, state and local level, and some of the laws, rules and regulations that govern our operations carry substantial penalties for non-compliance. Rules and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and the potential for financial sanctions for noncompliance. This regulatory burden increases our cost of doing business and, consequently, affects our profitability.

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

•
the location and spacing of wells,
•
the method of drilling and completing and operating wells,
•
the rate and method of production,
•
the surface use and restoration of properties upon which wells are drilled and other exploration activities,
•
notice to surface owners and other third parties,
•
the plugging and abandoning of wells,
•
the discharge of contaminants into water and the emission of contaminants into air,
•
the disposal of fluids used or other wastes obtained in connection with operations,
•
the marketing, transportation and reporting of production, and
•
the valuation and payment of royalties.

For instance, our OCS leases in federal waters are administered by three Bureaus of the Department of Interior "DOI". In response to concerns that the former MMS revenue-generating and resource development functions were at odds with its safety and environmental regulatory functions, the DOI reorganized the MMS into three separate agencies: the BOEM, to be the resource manager for conventional and renewable energy and mineral resources on the OCS; the BSEE, to promote and enforce safety in offshore energy exploration and production operations; and the ONRR, to collect and distribute royalties, rents, fees and other revenues, including the development of regulations with respect to revenue valuation and collection and enforcement activities. In this “Exploration and Production” section, we refer to actions of one or more of the foregoing agencies as actions of “the DOI Bureaus”.

The DOI Bureaus require compliance with detailed regulations and orders. Lessees must obtain DOI Bureau approval for exploration, exploitation and production plans and applications for permits to drill prior to the commencement of such operations. Since the April 20, 2010 blowout and oil spill at the BP Deepwater Horizon Macondo oil well, the DOI Bureaus have issued numerous rules, Notices to Lessees and other guidance documents augmenting the existing regulations with more stringent safety, engineering and environmental requirements. The DOI Bureaus have also issued a rule requiring that all operators in the OCS formulate detailed Safety and Environmental Management Systems to improve the safety of their operations on the OCS. Current DOI Bureau regulations restrict the flaring or venting of natural gas, and prohibit the flaring of liquid hydrocarbons and oil without prior authorization. The DOI Bureaus are considering whether to require flaring rather than venting, where practical, to reduce the potential effect of greenhouse gas emissions.

DOI Bureau policies concerning the volume of production that a lessee must have to maintain an offshore lease beyond its primary term also are applicable to Callon. Similarly, the DOI Bureaus have promulgated other regulations and Notices to Lessees governing the plugging and abandonment of wells located offshore and the installation and decommissioning of production facilities. To cover the various obligations of lessees on the OCS, the DOI Bureaus generally requires that lessees post bonds, letters of credit, or other acceptable assurances that such obligations will be met. The cost of these bonds or other surety can be substantial, and there is no assurance that bonds or other surety can be obtained in all cases. Under some circumstances, the DOI Bureaus may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial conditions and results of operations.

As stated above, the April 20, 2010 blowout and oil spill at the BP Deepwater Horizon oil rig has prompted the federal government to impose heightened regulation of oil and natural gas exploration and production on the OCS. Especially with respect to deepwater operations, the DOI Bureaus have issued rules that are more stringent than the rules issued by the MMS, and have announced their intention to issue additional safety rules and be more scrupulous in implementing existing environmental requirements in the future. Legislation has been introduced in the United States Congress to toughen the regulation of oil and natural gas exploration and production on the OCS. In addition, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, whose members were appointed by President Obama, issued a report proposing, among other things, fundamental reform of the regulation of oil and natural gas exploration and production on the OCS. The tightening of regulation on the OCS could impose

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higher costs on, and render it more difficult to timely obtain regulatory approval of our proposed activities on the OCS, especially as to deepwater projects.

Operations conducted on federal or state oil and natural gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the 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 Regulation.    Various federal, state and local laws and regulations concerning the release of contaminants into the environment, including the discharge of contaminants into water and the emission of contaminants into the air, the generation, storage, treatment, transportation and disposal of wastes, and the protection of public health, welfare, and safety, and the environment, including natural resources, affect our exploration, development and production operations, including operations of our processing facilities. We must take into account the cost of complying with environmental regulations in planning, designing, drilling, constructing, operating and abandoning wells. Regulatory requirements relate to, among other things, the handling and disposal of drilling and production waste products, the control of water and air pollution and the removal, investigation, and remediation of petroleum-product contamination. In addition, our operations may require us to obtain permits for, among other things,

•
air emissions,
•
discharges into surface waters (including wetlands), and
•
the construction and operations of underground injection wells or surface pits to treat, re-use or dispose of produced water and other nonhazardous oilfield wastes.
 
In the event of an unauthorized discharge (e.g., to land or water), emission (e.g., to air) or other activity, we may be liable for, among other things, penalties, costs and damages, and subject to injunctive relief, and we could be required to cleanup or mitigate the environmental impacts of those discharges, emissions or activities. Also, under federal, and certain state, laws, the present and certain past owners and operators of a site, and persons that treated, disposed of or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, for the release of hazardous substances into the environment and damage to natural resources caused by such release. The Environmental Protection Agency, state environmental agencies and, in some cases third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such actions. We therefore could be required to remove or remediate previously disposed wastes and remediate contamination, including contamination in surface water, soil or groundwater, caused by disposal of that waste, irrespective of whether disposal or release were unlawful. We could be responsible for wastes disposed of or released by us or prior owners or operators at properties owned or leased by us or at locations where wastes have been taken for disposal also irrespective of whether disposal or release were authorized. We could also be required to suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or cleanups to prevent future contamination.

Federal, and certain state, laws also impose duties and liabilities on certain “responsible parties” related specifically to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. These laws assign liability, which generally is joint and several, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses and limitations exist to the liability imposed under these laws, they are limited. In the event of an oil discharge or substantial threat of discharge, we could be liable for costs and damages.


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The Environmental Protection Agency and various state agencies have limited the disposal options for hazardous and nonhazardous wastes thereby increasing the costs of disposal. Furthermore, certain wastes generated by our oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements.
 
Federal and state occupational safety and health laws require us to organize information about hazardous materials used, released or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.

There are federal and certain state laws that impose restrictions on activities adversely affecting the habitat of certain plant and animal species. In the event of an unauthorized impact or taking of a protected species or its habitat, we could be liable for penalties, costs and damages, and subject to injunctive relief, and we could be required to mitigate those impacts. A critical habitat or suitable habitat designation also could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development.
 
Oil and natural gas exploration and production activities are being subjected to additional regulatory scrutiny under the Clean Air Act (“CAA”). On April 17, 2012, the EPA issued final rules to subject oil and gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured gas wells and also existing gas wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from certain compressors, controllers, dehydrators, storage tanks, natural gas processing plants and other equipment based upon equipment types, locations, and emission thresholds. These rules may require changes to our operations, including the installation of new equipment to control emissions.

We have made and will continue to make expenditures to comply with environmental regulations and requirements. These are necessary costs of doing business within the oil and natural gas industry. Although we are not fully insured against all environmental risks, we maintain insurance coverage which we believe is customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental laws and regulations, as well as claims for damages to property or persons resulting from company operations, could result in substantial costs and liabilities. We believe we are in compliance with existing environmental regulations, and that, absent the occurrence of an extraordinary event the effect of which cannot be predicted, any noncompliance will not have a material adverse effect on our operations or earnings.

Greenhouse Gas (“GHG”) Regulation. Although federal legislation regarding the control of greenhouse gasses, or GHGs, thus far has been unsuccessful, the EPA has moved forward with rulemaking to regulate GHGs as pollutants under the CAA. These GHG regulations may require us to incur increased operating costs and may have an adverse effect on demand for the oil and natural gas we produce.

The EPA, as of January 2, 2011, requires the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs in a multi-step process, with the largest sources first subject to permitting. Those permitting provisions, should they become applicable to our operations, could require controls or other measures to reduce GHG emissions from new or modified sources, and we could incur additional costs to satisfy those requirements. On November 30, 2010, EPA published a rule establishing GHG reporting requirements for sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions if the total emissions within a basin exceed 25,000 metric tons CO2 equivalent per year. Although this rule does not limit the amount of GHGs that can be emitted, it will require us to incur costs to monitor, keep records of, and potentially report GHG emissions associated with our operations if the reporting threshold is reached with production growth.
 
In addition to federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential regional and state initiatives may result in so-called "Cap-and-Trade programs", under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, such as by being required to purchase or to surrender allowances for GHGs resulting from our operations. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

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Application of the Safe Drinking Water Act to Hydraulic Fracturing. Congress has considered but has not passed legislation to amend the federal Safe Drinking Water Act to remove the exemption for hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. A number of state, local and regional regulatory authorities have or are considering hydraulic fracturing regulation. For example, Texas has adopted regulations requiring the disclosure of hydraulic fracturing chemicals. Potential federal as well as existing and potential state regulation could cause us to incur substantial compliance costs, and the requirement could negatively affect our ability to conduct fracturing activities on our assets.

In addition, the EPA has recently been taking actions to assert federal regulatory authority over hydraulic fracturing using diesel under the Safe Drinking Water Act's Underground Injection Control Program. Further, in March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. A progress report was issued in December 2012, with final results expected in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming. This study remains subject to review. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Consequently, these studies and initiatives could spur further legislative or regulatory action regarding hydraulic fracturing or other production operations. Further, the BLM has indicated that it will engage in rulemaking to regulate hydraulic fracturing on federal lands.

Further, EPA has announced an initiative under the Toxic Substances Control Act (“TSCA”) to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals.

All of the acreage and undeveloped reserves within the Permian basin are subject to hydraulic fracturing procedures as the process is required to economically develop the Wolfberry formation. The hydraulic fracturing process is integral to the Company's overall drilling and completion costs in the Permian basin and represented approximately 34% or $0.8 million of the total drilling/completion costs per vertical well drilled during 2012.

The hydraulic fracturing activity is limited to the oil and natural gas bearing formations, which are found at depths ranging between 6,000 and 12,000 feet from the surface in Midland, Ector and Upton counties, Texas. The Railroad Commission of Texas has defined potable water sources in this area as usable-quality ground water from the surface to a depth of 250 feet for our acreage in Midland and Ector counties and to a depth of 425 feet for our acreage in Upton counties.

The Company diligently reviews best practices and industry standards, and complies with all regulatory requirements in the protection of these potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time, and disposing of all non-commercially produced fluids in certified disposal wells at depths below the potable water sources.

Based on current drilling techniques, a typical fracturing procedure for a vertical well in the Wolfberry formation uses approximately 1.8 million gallons of fresh water, approximately 1.2 million pounds of sand and other elements including enzymes and guar, a common food additive. Horizontal wells typically use 9.5 million gallons of water and approximately 6.2 million pounds of sand.

In compliance with the law enacted in Texas in June 2011 and regulations adopted in December 2011, the Company will disclose hydraulic fracturing data to the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission chemical registry effective January 2, 2012. This disclosure is required for each chemical ingredient that is subject to the requirements of OSHA regulations, as well as the total volume of water used in the hydraulic fracturing treatment. A copy of the completed form is uploaded into the Chemical Disclosure Registry also known as FracFocus, which is a publically accessible website.

There have not been any incidents, citations or suits related to the Company's hydraulic fracturing activities involving environmental concerns.

The Federal Water Pollution Control Act, also known as the “Clean Water Act” and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S.

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Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and cleanup and response costs.

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.

Mineral Lease 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 interests in numerous federal onshore oil and natural gas leases. 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 Regulations. If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements. Certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the BLM, the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental Enforcement, or other appropriate federal, state, or tribal agencies.

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 polices included, and claims for damages to property, employees, other persons, and the environment resulting from the Company's operations could have on its activities. See Note 15 for additional information.

Available Information

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

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


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Item 1A.  Risk Factors
Risk Factors
Depressed oil and natural gas prices may adversely affect our results of operations and financial condition. Our success is highly dependent on prices for oil and natural gas, which are extremely volatile, and the oil and natural gas markets are cyclical. Extended periods of low prices for oil or natural gas will have a material adverse effect on us. The prices of oil and natural gas depend on factors we cannot control such as weather, economic conditions, and levels of production, actions by OPEC and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business:
•
our revenues, cash flows and earnings;
•
the amount of oil and natural gas that we are economically able to produce;
•
our ability to attract capital to finance our operations and the cost of the capital;
•
the amount we are allowed to borrow under our Credit Facility;
•
the profit or loss we incur in exploring for and developing our reserves; and
•
the value of our oil and natural gas properties.

Natural gas prices have been depressed recently and have the potential to remain depressed for the next several years, which may have an adverse effect on our financial condition and results of operations. Natural gas prices have been depressed for the last several years as a result of over-supply caused by, among other things, increased drilling in unconventional reservoirs, reduced economic activity associated with a recession and weather conditions. We expect natural gas prices to be depressed during the foreseeable future. Approximately 23% of our estimated net proved reserves at December 31, 2012 are natural gas, and 38% of our production in 2012 was natural gas. A sustained reduction in natural gas prices could have an adverse effect on our results of operations and financial condition.

If oil and natural gas prices decrease or remain depressed for extended periods of time, we may be required to take additional writedowns of the carrying value of our oil and natural gas properties. We may be required to writedown the carrying value of our oil and natural gas properties when oil and natural gas prices are low or if we have substantial downward adjustments to our estimated net proved reserves, increases in our estimates of development costs or if we experience deterioration in our exploration results. Under the full-cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using the preceding 12-months' average oil and natural gas prices based on closing prices on the first day of each month, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and natural gas properties exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders' equity. We review the carrying value of our properties quarterly, based on the pricing noted above. Once incurred, a writedown of oil and natural gas properties is not reversible at a later date, even if prices increase. See Note 14 to our Consolidated Financial Statements.
 
Our actual recovery of reserves may substantially differ from our proved reserve estimates. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. Additionally, our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities.

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

•
Expected reservoir characteristics based on geological, geophysical and engineering assessments;
•
Future production rates based on historical performance and expected future operation investment activities;
•
Future oil and natural gas prices and quality and locational differences; and
•
Future development and operating costs.


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You should not assume that any present value of future net cash flows from our producing reserves contained in this Form 10-K represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2012 on average 12-month prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. At December 31, 2012, approximately 14% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented 52% of total proved reserves by volume, and approximately 18% of our PUDs were attributable to our deepwater property. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these undeveloped reserves and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general.

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

Unless we are able to replace reserves that we have produced, our cash flows and production will decrease over time. The high-rate production characteristics of our Gulf of Mexico properties subject us to high reserve replacement needs. In general, the volume of production from oil and natural gas properties declines as reserves are depleted. The decline rates depend on reservoir characteristics. Gulf of Mexico reservoirs tend to be recovered quickly through production with associated steep declines, while declines in other regions after initial flush production tend to be relatively low. Our Gulf of Mexico, deepwater properties accounted for approximately 38% of our production which included the Habanero property during 2012 and 28% of our estimated proved reserves at December 31, 2012 excluding the Habanero property. Similarly, our Gulf of Mexico shelf properties accounted for approximately 22% of our production during 2012 and 4% of our estimated proved reserves at December 31, 2012. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future natural gas and oil production is highly dependent upon our level of success in finding or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices. Without successful exploration or acquisition activities, our reserves, production and revenues will decline.

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 if our cash flows from operations decline or external sources of capital become limited or unavailable. As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures, currently expected to be in excess of three times the cost, as compared to the drilling of a traditional vertical well. The incremental capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores. We cannot assure you that our future exploitation, exploration, development, and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. We cannot assure you that we will be able to find and develop or acquire additional reserves at an acceptable cost.

The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget. Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies or qualified personnel can materially and adversely affect our operations and profitability.
A significant portion of our production and reserves is concentrated in our deepwater offshore property, and any production problems or inaccuracies in reserve estimates related to this property would adversely impact our business. During 2012, approximately 29% of our daily production came from our Medusa field, which is currently our only deepwater property located in the Gulf of Mexico. In addition, at December 31, 2012, approximately 28% of our total net proved reserves were located within this field. If mechanical problems, storms or other events curtailed a substantial portion of this production, or if the actual reserves associated with this producing property are less than our estimated reserves, our results of operations and financial condition could be adversely affected.

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Our exploration projects increase the risks inherent in our oil and natural gas activities. We may seek to replace reserves through exploration, where the risks are greater than in acquisitions and development drilling. During 2012, we purchased 24,328 net acres in the northern portion of the Midland basin, an area that has seen only limited development activity. We expect to conduct substantial exploration of this acreage over the next several years. Although we have been successful in exploration in the past, we cannot assure you that we will continue to increase reserves through exploration or at an acceptable cost. Additionally, we are often uncertain as to the future costs and timing of drilling, completing and producing wells. Our exploration drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

•
receipt of additional seismic data or other geophysical data or the reprocessing of existing data;
•
material changes in oil or natural gas prices;
•
the costs and availability of drilling rigs;
•
the success or failure of wells drilled in similar formations or which would use the same production facilities;
•
availability and cost of capital;
•
changes in the estimates of the costs to drill or complete wells;
•
our ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks;
•
decisions of our joint working interest owners; and
•
changes to governmental regulations.

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

In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. The cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including:

•
unexpected drilling conditions;
•
pressure or irregularities in formations;
•
equipment failures or accidents and shortages or delays in the availability of drilling rigs and the delivery of equipment; and
•
compliance with governmental requirements.

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

•
operating a larger combined organization and adding operations;
•
difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new business segment or geographic area;
•
risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;
•
loss of significant key employees from the acquired business:
•
diversion of management'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.


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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.

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

There is competition for available oil and natural gas properties.   Our competitors include major oil and gas companies, independent oil and gas companies and financial buyers. Some of our competitors may have greater and more diverse resources than we do. High commodity prices and stiff competition for acquisitions have in the past, and may in the future, significantly increase the cost of available properties. The increased competition and rising prices for available properties could limit or impede our ability to identify acquisition opportunities that are economic for a company our size and that are necessary to grow our reserves or replace reserves produced.

We do not operate and have limited influence over the operations of our deepwater property. Our lack of control could result in the following:

•
the operator may initiate exploration or development at a faster or slower pace than we prefer or that we anticipate in preparing our reserve estimates;
•
the operator may propose to drill more wells or build more facilities on a project than we have funds for or that we deem appropriate, which may mean that we are unable to participate in the project or share in the revenues generated by the project even though we paid our share of exploration costs; and
•
if an operator refuses to initiate a project, we may be unable to pursue the project.

Any of these events could materially impact the value of our non-operated properties.
Weather, 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;
•
hurricanes, storms and other 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, platforms, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of:

•
injury or loss of life;
•
severe damage to and destruction of property, natural resources and equipment;
•
pollution and other environmental damage;
•
clean-up responsibilities;
•
regulatory investigation and penalties;
•
suspension of our operations; and
•
repairs to resume operations.

Offshore operations are also subject to a variety of additional operating risks peculiar to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for development or leasehold acquisitions, or result in loss of equipment and properties.

We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells for which we are the operator. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under federal and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. In March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. A progress report was issued in December 2012, with final results expected in 2014. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative, could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

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

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

•
the extent of domestic production and imports of oil and natural gas;
•
the proximity of the natural gas production to natural gas and NGL pipelines;
•
the availability of pipeline capacity;
•
the demand for oil and natural gas by utilities and other end users;
•
the availability of alternative fuel sources;
•
the effects of inclement weather;
•
state and federal regulation of oil and natural gas marketing; and
•
federal regulation of natural gas sold or transported in interstate commerce.

In particular, in areas with increasing non-conventional shale drilling activity, capacity may be limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built.
Part of our strategy involves drilling in new or emerging shale formations using horizontal drilling and completion techniques. The results of our planned drilling program in these formations may be subject to more uncertainties than conventional drilling programs in more established formations and may not meet our expectations for reserves or production. The results of our recent horizontal drilling efforts in new or emerging formations, including the Wolfcamp shale, Cline shale, and Mississippian lime in the Permian basin, are generally more uncertain than drilling results in areas that are developed and have established production. Because new or emerging formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis predict our future drilling results. The ultimate success of these drilling and completion strategies and techniques will be better evaluated over time as more wells are drilled and production profiles are better established. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated

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or we are unable to execute our drilling program because of capital constraints, access to gathering systems and takeaway capacity or otherwise, and/or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material writedowns of unevaluated properties and the value of our undeveloped acreage could decline in the future.

The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas from proved properties and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees and our third party consultants, none of whom are subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.

We may not be insured against all of the operating risks to which our business in exposed. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover losses or liabilities. We experienced Gulf of Mexico production interruption in 2005, 2006, 2007, and 2012 from Hurricanes Katrina, Rita, and Isaac and in 2008 and 2009 from Hurricanes Gustav and Ike for which we had no production interruption insurance. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable and may elect none or minimal insurance coverage. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse affect 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 as well as numerous independents, including many that have significantly greater resources. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. Factors that affect our ability to compete in the marketplace include:
•
our access to the capital necessary to drill wells and acquire properties;
•
our ability to acquire and analyze seismic, geological and other information relating to a property;
•
our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;
•
our ability to procure materials, equipment and services required to explore, develop and operate our properties, including the ability to procure fracture stimulation services on wells drilled; and
•
our ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production.

Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

During 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”).  Among other things, the Act requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market.  

In its rulemaking under the new legislation, the CFTC has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions); the CFTC's final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the CFTC to resolve ambiguity as to whether statutory requirements for such limits to be determined necessary and appropriate were satisfied. As a result, the rule has not yet taken effect, although the CFTC has indicated that it intends to appeal the court's decision and that it believes the Dodd-Frank Act requires it to impose position limits. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions.

In addition, the Act does not explicitly exempt end users (such as us) from the requirement to use cleared exchanges, rather than hedging over-the-counter, and the requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when the CFTC will finalize certain other related rules and regulations, the Act and related regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although whether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain

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capital levels, the cost of which could be passed through to us, or impose other requirements that are more burdensome than current regulations, our hedging would become more expensive and we may decide to alter our hedging strategy.

The financial reform legislation may also require the counterparties to derivative instruments to spin off some of their derivative activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts reduce the availability of derivatives to protect against risks we encounter, restrict our flexibility in conducting trading and hedging activity and increase our exposure to less creditworthy counterparties.  If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural-gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas.  Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

We may not have production to offset hedges; by hedging, we may not benefit from price increases. Part of our business strategy is to reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged. Additionally, we are required to pay the difference between the floating price and the fixed price when the floating price exceeds the fixed price regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage of increases in oil or natural gas prices above the fixed amount specified in the hedge.

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.
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, wilderness areas or coral reefs; and
•
require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned production facilities.

Under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of and increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. We could also be affected by more stringent laws and regulations adopted in the future, including any related climate change, greenhouse gases and hydraulic fracturing. Under the common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from properties in the event of environmental incidents.


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Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for the oil and natural gas we produce. The EPA has adopted its so-called "GHG tailoring rule" that will phase in federal PSD permit requirements for greenhouse gas emissions from new sources and modification of existing sources, federal Title V operating permit requirements for all sources, based upon their potential to emit specific quantities of GHGs. These permitting provisions to the extent applicable to our operations could require us to implement emission controls or other measures to reduce GHG emissions and we could incur additional costs to satisfy those requirements.
  
In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published its amendments to the greenhouse gas reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. Reporting of greenhouse gas emissions from such facilities is required on an annual basis if the total emissions within a basin exceed 25,000 metric tons CO2 equivalent per year. We will have to incur costs associated with this monitoring obligation and potentially additional reporting costs if production growth triggers the emission threshold.

In addition, the United States Congress has considered legislation to reduce emissions of GHGs and many states have already taken or have considered legal measures to reduce or measure GHG emissions, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs would require major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. These allowances would be expected to escalate significantly in cost over time. The adoption and implementation of any legislation or regulatory programs imposing GHG reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGS associated with our operations or could adversely affect demand for the oil and natural gas that we produce.
Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects. In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect affect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. Should drought conditions occur, our ability to obtain water in sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.
Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions but is not subject to regulation at the federal level (except for fracturing activity involving the use of diesel). The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. A progress report was issued in December 2012, and final results anticipated in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming; this study remains subject to review. A committee of the U.S. House of Representatives conducted an investigation of hydraulic fracturing practices. Legislation was introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states and local or regional regulatory authorities have adopted or are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has imposed a de facto moratorium on the issuance of permits for high-volume, horizontal hydraulic fracturing until state-administered environmental studies are finalized. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. While we have no operations in either New York or Pennsylvania, any other new laws or regulations that significantly restrict hydraulic fracturing in areas in which we do operate could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect the determination of whether a well is commercially viable. Further, EPA has announced an initiative under TSCA to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals, and the BLM has indicated that it will continue with rulemaking to regulate hydraulic fracturing on federal lands. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional

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permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation. In recent years, the Obama administration'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.

ITEM 1B.  Unresolved Staff Comments

None.
ITEM 3.  Legal Proceedings

We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business.  We do not believe the ultimate resolution of any such actions will have a material effect on our financial position or results of operations.

ITEM 4.  Mine Safety Disclosures

Not applicable.

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PART II.

ITEM 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The Company’s 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.
 
 
 
 
 
 
Stock Price
 
 
2012
 
 
 
High
 
Low
First quarter
 
ended
 
March 31, 2012
 
$
7.95

 
$
5.09

Second quarter
 
ended
 
June 30, 2012
 
6.45

 
3.80

Third quarter
 
ended
 
September 30, 2012
 
6.55

 
4.11

Fourth quarter
 
ended
 
December 31, 2012
 
6.36

 
4.05

 
 
 
 
 
 
 
 
 
 
 
2011
 
 
 
 

 
 

First quarter
 
ended
 
March 31, 2011
 
$
9.36

 
$
5.81

Second quarter
 
ended
 
June 30, 2011
 
8.04

 
5.93

Third quarter
 
ended
 
September 30, 2011
 
7.73

 
3.79

Fourth quarter
 
ended
 
December 31, 2011
 
5.99

 
3.02


As of March 1, 2013 the Company had approximately 3,229 common stockholders of record.

The Company has never paid dividends on its common stock, and intends to retain its cash flow from operations for the future operation and development of its business.  In addition, the Company’s Credit Facility and the terms of our outstanding debt prohibit the payment of cash dividends on our common stock.

During the fourth quarter of 2012, neither the Company nor any affiliated purchasers made repurchases of Callon’s equity securities.

Equity Compensation Plan Information

The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2012 (securities amounts are presented in thousands).

 
 
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

 
1,669

Equity compensation plans not approved by security holders
 
30

 
7.90

 
—

Total
 
67

 
11.82

 
1,669


For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 8 and 9 to the Consolidated Financial Statements.



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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 two 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 compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the New York Stock Exchange Market Index and of the Morningstar Group Index (consisting of independent oil and gas drilling and exploration companies) from December 31, 2007, through December 31, 2012. 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.
 
 
For the Year Ended December 31,
Company/Market/Peer Group
 
2007
 
2008
 
2009
 
2010
 
2011
 
2012
Callon Petroleum Company
 
$
100.00

 
$
15.81

 
$
9.12

 
$
35.99

 
$
30.21

 
$
28.57

NYSE Composite Index
 
100.00

 
60.86

 
78.25

 
88.89

 
85.63

 
99.47

Morningstar Group Index
 
100.00

 
39.51

 
71.28

 
74.52

 
64.64

 
71.97



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ITEM 6.  Selected Financial Data
 
The following table sets forth, as of the dates and for the periods indicated, selected financial information about us.  The financial information for each of the five years in the period ended December 31, 2012 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. The information included in this table for the year ended December 31, 2011 include the effects of corrections on the previously reported financial statements, as further discussed in Note 1 to the Consolidated Financial Statements included in Part II, Item 8 of this filing. 
 
For the year ended December 31,
 
2012
 
2011
 
2010
 
2009
 
2008
Statement of Operations Data:
(In thousands, except per share amounts)
Operating revenues:
 
 
 
 
 
 
 
 
 
Oil and natural gas sales
$
110,733

 
$
127,644

 
$
89,882

 
$
101,259

 
$
141,312

Medusa BOEM royalty recoupment (a)
—

 
—

 
—

 
40,886

 
—

Total operating revenues
$
110,733

 
$
127,644

 
$
89,882

 
$
142,145

 
$
141,312

Operating expenses:
 
 
 
 
 
 
 
 
 
Non-impairment related operating expenses
$
100,043

 
$
88,022

 
$
68,703

 
$
68,692

 
$
97,497

Impairment of oil and gas properties (b)
—

 
—

 
—

 
—

 
485,498

Total operating expenses
$
100,043

 
$
88,022

 
$
68,703

 
$
68,692

 
$
582,995

Income (loss) from continuing operations
10,690

 
39,622

 
21,179

 
73,453

 
(441,683
)
Net income (loss) (c)
2,747

 
106,396

 
8,386

 
46,796

 
(438,893
)
Earnings (loss) per share ("EPS"):
 

 
 

 
 

 
 

 
 

Basic
$
0.07

 
$
2.81

 
$
0.29

 
$
2.12

 
$
(20.68
)
Diluted
$
0.07

 
$
2.76

 
$
0.28

 
$
2.11

 
$
(20.68
)
Weighted average number of shares outstanding for Basic EPS
39,522

 
37,908

 
28,817

 
22,072

 
21,222

Weighted average number of shares outstanding for Diluted EPS
40,337

 
38,582

 
29,476

 
22,200

 
21,222

Statement of Cash Flows Data:
 

 
 

 
 

 
 

 
 

Net cash provided by operating activities
$
51,290

 
$
79,167

 
$
100,102

 
$
19,698

 
$
89,054

Net cash used in investing activities
(93,703
)
 
(91,511
)
 
(59,738
)
 
(43,189
)
 
(4,511
)
Net cash provided by (used in) financing activities
(243
)
 
38,703

 
(26,252
)
 
10,000

 
(120,667
)
Balance Sheet Data:
 

 
 

 
 

 
 

 
 

Oil and natural gas properties, net
$
269,521

 
$
215,912

 
$
168,868

 
$
130,608

 
$
159,252

Total assets
378,173

 
369,707

 
218,326

 
227,991

 
266,090

Long-term debt (d)
120,668

 
125,345

 
165,504

 
179,174

 
272,855

Stockholder' equity (deficit)
205,971

 
201,202

 
15,810

 
(80,854
)
 
(129,804
)
Proved Reserves Data:
 

 
 

 
 

 
 

 
 

Total oil (MMBbls)
10,780

 
10,075

 
8,149

 
6,479

 
6,027

Total natural gas (MMcf)
19,753

 
35,118

 
32,957

 
19,103

 
18,652

Total proved reserves (MBoe)
14,072

 
15,928

 
13,641

 
9,663

 
9,136

Standardized measure
$
231,148

 
$
270,357

 
$
198,916

 
$
135,921

 
$
86,305


(a)
Following the decisions resulting from several court cases brought by another oil and gas company, the court ruled that the BOEM was not entitled to receive these royalty payments.  The amount above reflects royalty recoupments for production from the fields 2003 inception through December 31, 2008, which were accrued at December 31, 2009 and paid by the BOEM during 2010.  

(b)
In 2008, the Company recorded a $485.5 million impairment of oil and gas properties as a result of the ceiling test.  See Notes 2 and 12 to the Consolidated Financial Statements for a description of the relevant accounting policy and the Company’s oil and gas properties disclosures, respectively.

(c)
Net income for 2011 includes $69.3 million of income tax benefit related to the reversal of the Company's deferred tax asset valuation allowance. See Note 11 for additional information.

(d)
2012 and 2011 long-term debt includes a non-cash deferred credit of $13,707 and $18,384, respectively that will be amortized into earnings as a reduction to interest expense over the life of the 13% Senior Notes due 2016.  See Note 5 for additional information.

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ITEM 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations
 
General

The following management's discussion and analysis is intended to assist in understanding 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 of oil and gas properties since 1950. In 2009, we began to shift our operational focus from exploration in the Gulf of Mexico to building an onshore asset portfolio in order to provide a multi-year, low-risk drilling program in both oil and natural gas basins.  This onshore transition has been, and is expected to continue to be, primarily funded by reinvesting the cash flows from our Gulf of Mexico properties including, as previously discussed, the proceeds from the monetization of our interest in the deepwater Habanero field in the fourth quarter of 2012.

Well count information is presented gross unless otherwise indicated.

Overview and Outlook

During 2012, Callon realized net income and fully diluted earnings per share of $2.7 million and $0.07, respectively, compared to net income of $106.4 million and fully diluted earnings per share of $2.76, respectively for 2011.  Net income during 2011 benefited significantly from an income tax benefit of $69.3 million, that related primarily to the full reversal of a valuation allowance we previously recorded against our deferred tax assets (see Note 11 for additional information). The Company’s earnings, and the drivers of these earnings, are discussed in greater detail within the “Results of Operations” section included below.

During 2012, the Company continued to transition its asset base from primarily offshore to primarily onshore, seeking to replace high volume offshore production with long-lived onshore crude oil production. In addition to building upon its portfolio of unconventional drilling opportunities with a crude oil focus, the Company continued to expand upon its expertise as an onshore operator in the Permian basin while maintaining a strong financial position to facilitate future growth. Significant accomplishments for 2012 include:

•
Increased 2012 Permian basin production by 67% to 591 Mboe as compared to 2011,
•
Increased 2012 Permian basin proved reserves by 24% to 9.4 MMboe as compared to 2011,
•
Increased 2012 Permian basin leasehold position by 246% to 32,962 net acres as compared to 2011,
•
Commenced the horizontal development of our East Bloxom field in the southern portion of the Midland basin, with the drilling of two horizontal wells targeting the Wolfcamp B shale. The average initial (24-hour) production rate from these two wells was 801 Boe per day, with an oil composition of 83%,
•
Commenced the evaluation of our newly acquired northern Midland acreage position, testing numerous vertical and horizontal development concepts,
•
Accelerated offshore cash flows for onshore redeployment with the sale of our interest in the Habanero field for $39.4 million, and
•
Expanded our lending bank group to five institutions and increased our Credit Facility size by $20.0 million or 44% as compared to December 31, 2011.



35
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Highlights of our onshore activity and Gulf of Mexico operations include:
 
Onshore - Permian Basin

We expect that our production and reserve growth initiatives will continue to focus primarily on the Permian basin, in which we own approximately 38,127 gross (32,962 net) acres as of December 31, 2012.

Southern Portion: We currently own approximately 11,345 net acres in the southern portion of the Permian basin, an increase of 19% since year-end 2011. Our current production in the southern Midland basin (Crockett, Ector, Glasscock, Midland, and Upton counties in Texas) is primarily from the Wolfberry play, although we added production volumes from the horizontal development of the Wolfcamp B shale during 2012.

During 2012, we drilled 15 vertical wells and completed 22 vertical wells. As part of this program, we tested deeper target zones below the Atoka in the fourth quarter of 2012. Based on the results of this test, we are currently planning to add these deeper zones to our ongoing vertical Wolfberry-type drilling and completion program at our Pecan Acres and Carpe Diem fields.

In addition to this vertical drilling program, we commenced a horizontal oil shale drilling program at our East Bloxom field in the second quarter of 2012, initially targeting the Wolfcamp B formation. In 2012, we drilled and completed two horizontal wells on this acreage position, each with a lateral length of over 7,100 feet. In the first quarter of 2013, we drilled an additional three horizontal Wolfcamp shale wells at East Bloxom, with two wells targeting the Wolfcamp B shale and one targeting the Wolfcamp A shale.

In order to increase our exposure to horizontal development of the Wolfcamp B shale, we acquired 2,319 gross (1,762 net) acres in southern Reagan county, Texas, which closed on July 5, 2012, and is now referred to as our Taylor Draw field. We finished the drilling of our initial horizontal well, targeting the Wolfcamp B shale, in December 2012, completed the well in February 2013, and are currently evaluating the well results that include some positive indications.

Based on our initial results and the results of other industry participants, we are planning to increase our level of horizontal drilling activity in 2013 in this portion of the basin, drilling a total of 14 wells. Given this level of sustained activity, we are planning on executing these wells from drilling pads using batch completions in an effort to maximize capital efficiency. These development plans are currently expected to be focused on our East Bloxom and Taylor Draw fields.

Northern Portion: We currently own approximately 21,617 net acres in the northern portion of the Permian basin, which includes the 14,653 net acres in Borden county, Texas and an additional 6,964 net acres in Lynn county, Texas. These leasehold positions were acquired during the course of 2012 for a total consideration of $19.4 million, or $896 per net acre. These positions represent our effort to expand our drilling inventory in the Midland basin with exploration upside potential at a reasonable cost of entry.

After completing a 3-D seismic survey on our acreage position, we commenced the drilling of an exploratory vertical well in July 2012, followed by the drilling of two horizontal wells. The first horizontal well was drilled in the Cline shale and was completed in December 2012. The hydrocarbons from this well did not produce in economic quantities and the well was temporarily abandoned in February 2013. We drilled the second horizontal well, targeting the Mississippian lime interval, in November 2012, completed the well in February 2013 and are currently evaluating the well results.

Although the area has experienced a recent increase in drilling activity, the northern Midland basin has had limited drilling activity compared with the southern basin (where our current production is located), which significantly increases the risk associated with successful drilling activities in this area.

In addition to the $29.6 million consideration paid for each of the above referenced leasehold additions, the Company's unevaluated property balance of $68.8 million at December 31, 2012 includes $29.7 million of exploration and facility costs incurred in 2012 on these properties and $9.5 million of other related items. See Note 12 for additional information. Based on the Company's present development plans, the Company expects the majority of the exploration and facility costs will be transferred to evaluated properties during 2013.
 

36
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

Offshore - Deepwater

Our net interest in the Habanero field produced an average of 366 Boe per day for 2012. The field was shut-in for approximately 50 days during the year for scheduled maintenance, and hurricane-related issues. On December 28, 2012, we completed the sale of our interest in the Habanero field to Shell Offshore Inc., a subsidiary of Royal Dutch Shell Plc, for net cash consideration of $39.4 million.

Our remaining deepwater property, our 15% interest in the Medusa field, continues to play a key role in our portfolio. Our net interest in the Medusa field produced an average of 1,268 Boe per day during 2012, approximately 87% being crude oil that receives pricing based on Mars WTI crude. The Medusa platform was shut-in for 28 days during the second quarter of 2012 for planned construction activities on the West Delta 143 oil pipeline through which Medusa's production is transported. Due to Hurricane Isaac, the platform was once again shut-in from August 27, 2012 to September 4, 2012.

We anticipate that the future cash flows from Medusa will continue to contribute to the funding of our onshore activity. In addition, we believe that additional reserve potential exists as part of this project. The operator of the field, Murphy Oil Corporation, has sanctioned a two well subsea development for the Medusa field. One of these wells will be targeting the development of reserves associated with our existing PUD reserves in the T-4B sand with an uphole recomplete to the T-0A and T-0B sand. The remaining well will target probable reserves.  We anticipate that the drilling of these wells will begin in the first quarter of 2014.

Offshore – Shelf & Other Properties

We own interests in 14 producing wells in eight crude oil and natural gas fields in the shelf area of the Gulf of Mexico. These wells produced 340 MBoe net to our interest in 2012, which accounted for 22% of our total production. Production from the East Cameron Block 257 field, which contributed an average of 175 Boe per day of production prior to being shut-in in November 2011, is expected to recommence once the Stingray Pipeline is brought back online. The restart of flows on the pipeline is currently anticipated to occur in the second quarter of 2013.

Liquidity and Capital Resources

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities.  Cash and cash equivalents decreased by $42.7 million during 2012 to $1.1 million compared to $43.8 million at December 31, 2011.   The decrease in our cash balance is primarily attributable to 2012 capital expenditures of $133.3 million, representing a $33.1 million or 33% increase over the amount spent during the same period in 2011. While at December 31, 2012, our Balance Sheet reflects a working capital deficiency of $18.6 million, which is reflective of our current capital investment-driven growth strategy within our Permian properties, we believe that as discussed below our operating cash flows combined with the borrowing availability under our Credit Facility provides the liquidity necessary to meet our operational cashflow needs.

Senior Secured Credit Facility (the "Credit Facility")

On June 20, 2012, Regions Bank increased the Company's Credit Facility to $200 million with an associated borrowing base under the Credit Facility of $60 million and a maturity of July 31, 2014. Subsequently and in October 2012, the Credit Facility was further amended to increase the borrowing base to $80 million, extend the maturity to March 15, 2016 and add Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. Regions Bank continues to serve as Administrative Agent for the Credit Facility.

As of December 31, 2012 the borrowing base was revised to $65 million following the sale of our interest in the deepwater Habanero field. Proceeds from the sale, net cash consideration of $39.4 million after customary purchase price adjustments, were used to reduce outstanding borrowings on our Credit Facility. The borrowing base will be redetermined as scheduled in the first quarter of 2013 based upon the evaluation of year-end proved reserves.

Amounts borrowed under the Credit Facility may not exceed a borrowing base, which is generally reviewed on a semi-annual basis and is then eligible for re-determination. The Credit Facility is secured by mortgages covering the Company's major producing fields.

As of December 31, 2012, the balance outstanding under the Credit Facility was $10.0 million with a weighted average interest rate on the Credit Facility of 2.72% , calculated as the London Interbank Offered Rate (“LIBOR”) plus a tiered rate ranging from 2.5% to 3.0%, which is based on utilization of the Credit Facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly. As of March 13, 2013 , the balance outstanding

37
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

on the Credit Facility was $25 million as the Company drew an additional $15 million in support of the Company's ongoing capital development program.

Senior Notes due 2016

At December 31, 2012, following a $10 million principal redemption in June 2012, we had approximately $97 million principal amount of 13% Senior Notes due 2016 outstanding with interest payable quarterly.

2013 Capital Expenditures

For 2013, we designed a flexible capital spending program, which we plan to fund from cash on hand and cash flows from operations in addition to borrowings under our Credit Facility. However, depending on macroeconomic conditions or the Company's operational results, our capital budget may be adjusted up or down during the year.

Our 2013 capital budget has been established at $125.0 million with over 90% of our budgeted operating expenditures (including drilling, completion, infrastructure, and plugging and abandonment) allocated to our Midland basin operations.. The 15% decrease in total capital from 2011 reflects our primary focus on drilling and completion activities in the Permian basin and reduced emphasis on acreage acquisitions that were budgeted in 2012 to expand the Company's presence in the basin. Our budget includes further exploration and development of our Permian basin properties with plans to complete approximately 26 gross wells including 14 horizontal wells and 12 vertical wells. Components of the 2013 capital budget include (in millions):
Midland basin
$
97

Gulf of Mexico
10

Total projected operations budget
107

 
 
Capitalized general and administrative costs
14

Capitalized interest and other
4

Total projected capital expenditures budget
$
125


Our total liquidity at December 31, 2012 was $56.1 million, including $1.1 million of cash available and $55.0 million of availability under our Credit Facility. We believe that this liquidity position, combined with our expected operating cash flow based on current commodity prices and forecasted production, will be adequate to meet our forecasted capital expenditures, interest payments, and operating requirements for 2013.


38
Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following table includes the Company’s contractual obligations and purchase commitments as of December 31, 2012, at which date the Company had no product delivery commitments:
(amounts in thousands)
 
Payments due by Period
 
 
Total
 
< 1 Year
 
Years 2 - 3
 
Years 4 - 5
 
>5 Years
13% Senior Notes
 
$
96,961

 
$
—

 
$
—

 
$
96,961

 
$
—

Office space lease commitments
 
3,012

 
384

 
785

 
719

 
1,124

Drilling rig leases and related (a)
 
11,512

 
9,235

 
2,277

 
—

 
—

Other
 
40

 
13

 
27

 
—

 
—

Total
 
$
111,525

 
$
9,632

 
$
3,089

 
$
97,680

 
$
1,124


(a)
The agreement includes early termination provisions that would reduce the minimum rentals under the agreement, assuming the lessor is unable to re-charter the rig and staffing personnel to another lessee, as follows: <1 year of $5.8 million and 2-3 years of $1.4 million.

Summary cash flow information is provided as follows:

Operating Activities.   For the year ended December 31, 2012, net cash provided by operating activities was $51.3 million, compared to $79.2 million for the same period in 2011.  The decrease relates primarily to lower revenues from a 2% decrease in crude oil production, a 29% decrease in natural gas production and a 31% increase in lease operating expenses, partially offset by a