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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
| 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 001-34574
Matador Resources Company
(Exact name of registrant as specified in its charter)
| Texas | 27-4662601 | |
| (State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) | |
| 5400 LBJ Freeway, Suite 1500 Dallas, Texas 75240 |
75240 | |
| (Address of principal executive offices) | (Zip Code) | |
Registrant’s telephone number, including area code: (972) 371-5200
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class |
Name of each exchange on which registered | |
| Common Stock, par value $0.01 per share | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T 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 registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | ¨ | Accelerated filer | x | |||
| Non-accelerated filer | ¨ (Do not check if a smaller reporting company) | Smaller reporting company | ¨ | |||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $454,393,967.
As of March 14, 2013, there were 55,894,438 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this annual report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2013 Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this annual report on Form 10-K relates.
Table of Contents
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012
TABLE OF CONTENTS
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Cautionary Note Regarding Forward-Looking Statements
Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the meaning of applicable U.S. securities legislation. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “potential,” “predict,” “project,” “should” or other similar words.
By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: changes in oil or natural gas prices, the success of our drilling program, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this Annual Report on Form 10-K and in other documents that we file with or furnish to the U.S. Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about:
| • | our business strategy; |
| • | our reserves; |
| • | our technology; |
| • | our cash flows and liquidity; |
| • | our financial strategy, budget, projections and operating results; |
| • | our oil and natural gas realized prices; |
| • | the timing and amount of future production of oil and natural gas; |
| • | the availability of drilling and production equipment; |
| • | the availability of oil field labor; |
| • | the amount, nature and timing of capital expenditures, including future exploration and development costs; |
| • | the availability and terms of capital; |
| • | our drilling of wells; |
| • | government regulation and taxation of the oil and natural gas industry; |
| • | our marketing of oil and natural gas; |
| • | our exploitation projects or property acquisitions; |
| • | our costs of exploiting and developing our properties and conducting other operations; |
| • | general economic conditions; |
| • | competition in the oil and natural gas industry; |
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| • | the effectiveness of our risk management and hedging activities; |
| • | environmental liabilities; |
| • | counterparty credit risk; |
| • | developments in oil-producing and natural gas-producing countries; |
| • | our future operating results; |
| • | estimated future reserves and the present value thereof; and |
| • | our plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K that are not historical. |
Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.
You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.
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PART I
| Item 1. | Business. |
In this Annual Report on Form 10-K, references to “we,” “our” or “the Company” refer to Matador Resources Company and its subsidiaries before the completion of our corporate reorganization on August 9, 2011 and Matador Holdco, Inc. and its subsidiaries after the completion of our corporate reorganization on August 9, 2011. Prior to August 9, 2011, Matador Holdco, Inc. was a wholly-owned subsidiary of Matador Resources Company, now known as MRC Energy Company. Pursuant to the terms of our corporate reorganization, former Matador Resources Company became a wholly-owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company.
Unless the context otherwise requires, the term “common stock” refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering on February 7, 2012, as the Class A common stock then became the only class of common stock authorized, and the term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering.
For certain oil and natural gas terms used in this Annual Report on Form 10-K, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report on Form 10-K.
General
We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Our current operations are focused primarily on the oil and liquids rich portion of the Eagle Ford shale play in South Texas and in the Haynesville shale play in Northwest Louisiana. In 2012, more than 90% of our total capital expenditures of $334.6 million were directed to our operations in South Texas, primarily in the Eagle Ford shale, as we sought to transition to a more balanced commodity portfolio through the drilling of wells that were prospective for oil and liquids. For the year ended December 31, 2012, approximately 37% of our total production by volume (using a conversion ratio of one Bbl of oil per 6 Mcf of natural gas) and 79% of our total oil and natural gas revenues were attributable to oil production, primarily from the Eagle Ford shale. In 2013, we expect that approximately 82% of our estimated capital expenditures of $310.0 million will be directed to increasing our oil production and oil reserves in South Texas, primarily in the Eagle Ford shale play. Although we did not drill any operated Haynesville shale natural gas wells during 2012, we directed approximately 3% of our capital expenditures to the Haynesville shale in 2012 to participate in several non-operated wells. In addition to these primary operating areas, we have a growing acreage position in Southeast New Mexico and West Texas where we plan to drill three exploratory wells to test the Wolfcamp and Bone Spring plays during 2013. We also have a large exploratory leasehold position in Southwest Wyoming and adjacent areas in Utah and Idaho where we are testing the Meade Peak shale.
We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman, President and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million.
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On February 2, 2012, our common stock began trading on the NYSE under the symbol “MTDR.” On February 7, 2012, we completed our initial public offering of 14,883,334 shares of common stock at $12.00 per share. We sold 12,209,167 shares of common stock in this offering and certain selling shareholders sold 2,674,167 shares of common stock, including shares sold pursuant to the partial exercise of the underwriters’ over-allotment option on March 7, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock.
In 2012, our operations were primarily focused on the exploration and development of our Eagle Ford shale properties in South Texas, as we continued to execute our strategy to significantly increase our oil production and oil reserves during 2012. During the year ended December 31, 2012, we completed and began producing oil and natural gas from 28 gross/24.5 net Eagle Ford shale wells, including 25 gross/23.7 net operated and 3 gross/0.8 net non-operated Eagle Ford shale wells. We also completed and began producing oil and natural gas from 2 gross/2.0 net wells in the upper Austin Chalk and the lower Austin Chalk/upper Eagle Ford, or “Chalkleford,” intervals in 2012. In addition, during 2012, we completed and began producing natural gas from 28 gross/1.1 net non-operated Haynesville shale wells. We also re-entered and drilled a horizontal lateral from the previously suspended Crawford Federal #1 vertical well in Southwest Wyoming; we plan to complete this well in the third quarter of 2013.
We had two contracted drilling rigs operating in South Texas throughout 2012 (except for a brief period near the end of the second quarter when we added a third rig to execute a two-well contract), and almost all of our operated drilling and completion activities were focused on the Eagle Ford shale. We did not drill any operated wells in the Haynesville shale play in Northwest Louisiana during 2012 as a result of the decline in natural gas prices compared to recent years. At March 14, 2013, we continued to have two contracted drilling rigs operating in South Texas: one in LaSalle County and one in DeWitt County.
Our average daily production for the year ended December 31, 2012 was approximately 9,000 BOE per day, including 3,317 Bbl of oil per day and 34.1 MMcf of natural gas per day, as compared to 7,049 BOE per day, including 422 Bbl of oil per day and 39.8 MMcf of natural gas per day for the year ended December 31, 2011. Our total oil production increased almost eight-fold to just over 1.2 million Bbl of oil during the year ended December 31, 2012 from approximately 154,000 Bbl of oil during the year ended December 31, 2011. This increased oil production is a direct result of our drilling operations in the Eagle Ford shale. Oil production comprised approximately 37% of our total production for the year ended December 31, 2012, as compared to only 6% of our total production for the year ended December 31, 2011.
During the three months ended December 31, 2012, specifically, our average daily production was 10,385 BOE per day, including 4,630 Bbl of oil per day and 34.5 MMcf of natural gas per day. This was an increase of almost 50% compared to our average daily production for the three months ended December 31, 2011 of 6,953 BOE per day, including 448 Bbl of oil per day and 39.0 MMcf of natural gas per day. Our total oil production increased ten-fold to 426,000 Bbl of oil during the three months ended December 31, 2012, as compared to total oil production of 41,000 Bbl of oil during the three months ended December 31, 2011. Our average daily production for the fourth quarter of 2012 was a sequential increase of 18% from the average daily production of 8,838 BOE per day, including 3,291 Bbl of oil per day and 33.3 MMcf of natural gas per day, achieved during the third quarter of 2012. For the three months ended December 31, 2012, our oil production grew 41% sequentially, as compared to the three months ended September 30, 2012.
At December 31, 2012, our estimated total proved reserves were 23.8 million BOE, including 10.5 million Bbl of oil and 80.0 Bcf of natural gas (13.3 million BOE). At December 31, 2012, 58% of our total proved reserves were proved developed reserves compared to 34% at December 31, 2011. At December 31, 2012, 44% of our total proved reserves were oil and 56% of our total proved reserves were
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natural gas, as compared to 12% oil and 88% natural gas at December 31, 2011. Our proved oil reserves grew 176% (almost three-fold) from 3.8 million Bbl at December 31, 2011 to 10.5 million Bbl at December 31, 2012. This growth in oil reserves was attributable to our drilling program in the Eagle Ford shale during 2012. Our proved natural gas reserves declined to 80.0 Bcf at December 31, 2012 from 170.4 Bcf at December 31, 2011. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012, and these proved undeveloped reserves were likewise not included in our estimated total proved reserves at December 31, 2012. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries.
The PV-10 of our estimated total proved reserves was $423.2 million at December 31, 2012 compared to a PV-10 of $248.7 million at December 31, 2011, an increase of 70% despite lower commodity prices used to estimate PV-10 in 2012 compared to 2011. The PV-10 at December 31, 2012 was determined using the 12-month unweighted average of first-day-of-the-month oil and natural gas prices for 2012 of $91.21 per barrel and $2.757 per MMBtu, respectively, adjusted by lease for quality, energy content, regional price differentials and other expenses as needed compared to average oil and natural gas prices of $92.71 per barrel and $4.118 per MMBtu, respectively, adjusted as further described above, used to determine PV-10 at December 31, 2011. The Standardized Measure of estimated future net cash flows from our total proved reserves, including estimated future income tax expenses, was $394.6 million at December 31, 2012 and $215.5 million at December 31, 2011. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.”
For the year ended December 31, 2012, our oil and natural gas revenues were approximately $156.0 million, or an increase of about 133%, as compared to approximately $67.0 million for the year ended December 31, 2011. Our oil revenues increased over eight-fold to approximately $123.7 million for the year ended December 31, 2012, as compared to $14.5 million for the year ended December 31, 2011. Our total realized revenues for 2012, including realized gain on derivatives, were approximately $170.0 million, or an increase of about 129%, as compared to $74.1 million for 2011. For the year ended December 31, 2012, our Adjusted EBITDA was approximately $115.9 million, or an increase of about 132%, as compared to an Adjusted EBITDA of approximately $49.9 million for the year ended December 31, 2011. Adjusted EBITDA is a non-GAAP financial measure. For a reconciliation of Adjusted EBITDA to net income (loss) and net cash flow provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.”
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The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2012:
| Net Acreage | Producing Wells |
Total Identified Drilling Locations(1) |
Estimated Net Proved Reserves(2) |
Avg. Daily Production (BOE/d)(3) |
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| Gross | Net | Gross | Net | MBOE(3) | % Developed |
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| South Texas: |
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| Eagle Ford |
27,911 | 37.0 | 31.7 | 274.0 | 221.0 | 14,331 | 45.5 | 3,908 | ||||||||||||||||||||||||
| Austin Chalk(4) |
17,465 | 4.0 | 4.0 | 17.0 | 17.0 | 20 | 100.0 | 20 | ||||||||||||||||||||||||
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| Area Total(5) |
27,911 | 41.0 | 35.7 | 291.0 | 238.0 | 14,351 | 45.6 | 3,928 | ||||||||||||||||||||||||
| NW Louisiana/E Texas: |
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| Haynesville |
14,173 | 134.0 | 12.7 | 472.0 | 101.1 | 7,856 | 71.5 | 4,336 | ||||||||||||||||||||||||
| Cotton Valley(6) |
22,469 | 106.0 | 69.7 | 71.0 | 49.3 | 1,512 | 100.0 | 706 | ||||||||||||||||||||||||
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| Area Total(7) |
24,968 | 240.0 | 82.4 | 543.0 | 150.4 | 9,368 | 76.1 | 5,042 | ||||||||||||||||||||||||
| SE New Mexico, West Texas(8) |
7,591 | 13.0 | 5.7 | 39.0 | 25.1 | 100 | 100.0 | 30 | ||||||||||||||||||||||||
| SW Wyoming, NE Utah, SE Idaho |
27,180 | – | – | – | – | – | – | – | ||||||||||||||||||||||||
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| Total |
87,650 | 294.0 | 123.8 | 873.0 | 413.5 | 23,819 | 57.8 | 9,000 | ||||||||||||||||||||||||
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| (1) | These locations have been identified for potential future drilling and are not currently producing. In addition, the total net identified drilling locations is calculated by multiplying the gross identified drilling locations in an operating area by our working interest participation in such locations. At December 31, 2012, these identified drilling locations included 30 gross and 26.8 net locations to which we have assigned proved undeveloped reserves in the Eagle Ford and 2 gross and 1.9 net locations to which we have assigned proved undeveloped reserves in the Haynesville. We had no proved undeveloped reserves assigned to identified drilling locations in the Austin Chalk or Cotton Valley or in the Wolfcamp or Bone Spring plays in Southeast New Mexico and West Texas at December 31, 2012. |
| (2) | These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. |
| (3) | Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. |
| (4) | Includes two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. |
| (5) | Some of the same leases cover the net acres shown for both the Eagle Ford formation and the Austin Chalk formation, a shallower formation than the Eagle Ford formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for South Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. |
| (6) | Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. |
| (7) | Some of the same leases cover the net acres shown for both the Haynesville formation and the Cotton Valley formation, a shallower formation than the Haynesville formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. |
| (8) | Includes potential future drilling locations identified in either the Wolfcamp or Bone Spring plays on our acreage in Southeast New Mexico and West Texas at December 31, 2012. |
At December 31, 2012, our properties included approximately 42,500 gross acres and 27,900 net acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, LaSalle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids production. In addition, we believe that portions of this acreage may also be prospective for other targets, such as the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. Approximately 70% of our Eagle Ford acreage was held by production at December 31, 2012, and approximately 84% of our Eagle Ford acreage was either held by production at December 31, 2012 or not burdened by lease expirations before 2014.
At December 31, 2012, we had 37 gross and 31.7 net wells producing from the Eagle Ford shale in South Texas, and we have identified 274 gross locations and 221.0 net locations for potential future drilling
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on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Of the 274 gross and 221.0 net locations identified for potential future drilling in the Eagle Ford shale at December 31, 2012, we consider 155 gross and 125.1 net locations as Tier 1 locations. We define Tier 1 Eagle Ford locations as those locations that we anticipate to have estimated ultimate recoveries of 225,000 Bbl of oil or greater. Of these Tier 1 locations, 115 gross locations and 109.1 net locations would be operated by us. These identified locations presume that we will be able to develop our Eagle Ford properties on 40-acre to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate that our acreage in central and northern LaSalle County and in northern Karnes County can be developed on 40-acre spacing in the Eagle Ford, while our other properties may be more likely developed on 80-acre spacing. We are currently drilling on 80-acre spacing on most of our properties. Although we had not yet drilled any wells on 40-acre spacing at December 31, 2012, we have several tests on less than 80-acre spacing planned on certain of our properties during 2013. We define Tier 2 Eagle Ford locations, including 119 gross and 95.9 net locations, as those locations that we anticipate to have estimated ultimate recoveries of between 150,000 Bbl and 225,000 Bbl of oil, locations that are primarily prospective for natural gas or other locations on properties already held by existing production. At December 31, 2012, Tier 2 locations were identified primarily on our acreage in Zavala County and in southern LaSalle County; we have identified no potential future Eagle Ford drilling locations on our Atascosa County acreage. All of these Tier 2 locations would be operated by us, and approximately 85% of these locations are located on properties already held by production from the Eagle Ford or other producing horizons. Although we have no plans to drill any of these Tier 2 locations in 2013, as long as these properties remain held by production, these locations remain available for us to drill at a later time should commodity prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. Certain of these properties, such as our properties in Zavala and Atascosa Counties, also offer the opportunity to explore horizons other than the Eagle Ford, including the Austin Chalk, Buda, Edwards or Pearsall, and we may develop new prospects on these properties in the future. As we explore and develop all of our Eagle Ford acreage further, we believe it is possible that we may identify additional locations for future drilling, particularly on those properties where we now presume development on 80-acre spacing. At December 31, 2012, these 274 gross and 221.0 net potential future drilling locations included 30 gross and 26.8 net locations to which we have assigned proved undeveloped reserves.
In addition, at December 31, 2012, we had approximately 22,300 gross acres and 14,200 net acres in the Haynesville shale play, primarily in Northwest Louisiana. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data, information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, approximately 5,700 of our net acres are located in what we believe is the core area of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Almost all of our Haynesville acreage is held by production from the Haynesville or other formations, and we believe much of it is also prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe approximately 1,700 of these net acres are prospective for the Middle Bossier shale play, although as of December 31, 2012, we had not tested the Middle Bossier shale on our acreage.
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At December 31, 2012, we had identified 472 gross locations and 101.1 net locations for potential future drilling on our Haynesville acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 472 gross locations identified for future drilling, 397 of these locations (50.2 net locations) have been identified within the approximately 5,700 net acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Haynesville acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2012, these identified potential future drilling locations included only 2 gross and 1.9 net locations in the Haynesville shale play to which we have assigned proved undeveloped reserves. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012, most of which were attributable to non-operated properties, including 100 gross and 14.8 net locations to which we had previously assigned proved undeveloped reserves. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes and the corresponding potential drilling locations remain available to be developed by us or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries.
At December 31, 2012, our properties also included approximately 15,900 gross and 7,600 net acres in the Delaware Basin in Southeast New Mexico and West Texas where we are developing new oil prospects. We believe that approximately 8,200 gross and 5,500 net acres are prospective for the Wolfcamp shale and Bone Spring formations, as well as other potential uphole targets including the Delaware sands and the Avalon shale. We believe that the Wolfcamp, Bone Spring, Avalon and Delaware formations are all prospective primarily for oil and that multiple target intervals may be prospective within each formation. At December 31, 2012, approximately 6,000 gross and 3,900 net of these acres were already held by production from other producing horizons. We expect to begin exploring this acreage position during the second and third quarters of 2013 and plan to drill a total of three test wells on this acreage in 2013. Two wells will test the Wolfcamp shale and one well will test the Second Bone Spring formation. At December 31, 2012, we had identified 39 gross and 25.1 net locations for potential future drilling in the Wolfcamp or Bone Spring plays on our acreage in Southeast New Mexico and West Texas, including the three exploratory test wells planned for 2013. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from nearby wells producing from the Wolfcamp and Bone Spring formations based on available public data, drilling densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Because we are just beginning the exploration of our properties in Southeast New Mexico and West Texas in 2013, our identified well locations at December 31, 2012 presume that only one horizon in the Wolfcamp or the Bone Spring may be developed at any one surface location and that these properties may be developed on 160-acre well spacing, although we believe that multiple intervals may be prospective at any one surface location and that denser well spacing may be possible. In addition, although our potential future drilling locations presume the drilling of horizontal wells, we also believe that certain portions of our acreage could lend itself to development with vertical wells. As a result, as we explore and develop our Southeast New Mexico and West Texas acreage further, we believe it is possible that we may identify additional locations
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for future drilling. At December 31, 2012, we had not assigned proved undeveloped reserves to any of these potential drilling locations in the Wolfcamp or Bone Spring formations. Although we believe that prospective well locations exist on this acreage for the Avalon shale and the Delaware sands, we had not included any Avalon or Delaware locations in our identified well locations at December 31, 2012.
At December 31, 2012, we also had a large unevaluated acreage position, including approximately 55,300 gross and 27,200 net acres in Southwest Wyoming and adjacent areas in Utah and Idaho, where we began drilling our initial well in February 2011 to test the Meade Peak natural gas shale. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September 2011 and completed drilling and coring operations in November 2011. After taking time to review and analyze the extensive well log and core data collected in this well, we re-entered the vertical well and drilled an approximately 2,500-ft horizontal lateral in the Meade Peak shale during the fourth quarter of 2012. Operations on this well are temporarily suspended, but we plan to complete and test the horizontal lateral portion of this well beginning in the third quarter of 2013.
We are active both as an operator and as a co-working interest owner with larger industry participants, including affiliates of EOG Resources, Inc., Royal Dutch Shell plc, Chesapeake Energy Corporation and others. At December 31, 2012, we were the operator for approximately 91% of our Eagle Ford and 70% of our Haynesville acreage, including approximately 22% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by a subsidiary of Chesapeake Energy Corporation. We also operate the vast majority of our acreage in Southeast New Mexico and West Texas, as well as all of our acreage in Southwest Wyoming and the adjacent areas of Utah and Idaho. In those wells where we are not the operator, our working interest is relatively small, particularly in the Haynesville shale.
At December 31, 2012, we were a non-operating working interest participant with affiliates of Chesapeake Energy Corporation, Royal Dutch Shell plc and several other companies in the Haynesville shale and with EOG Resources, Inc. and Hunt Oil Company in the Eagle Ford shale. We have entered into a joint operating agreement with an affiliate of Chesapeake Energy Corporation governing the Haynesville operations underlying our Elm Grove/Caspiana properties in Southern Caddo Parish, Louisiana and joint operating agreements with EOG Resources, Inc. and Hunt Oil Company governing operations on our joint acreage in Atascosa and Wilson Counties, Texas, respectively. We have not entered into a joint operating agreement with Royal Dutch Shell plc or certain other operators of wells in the Haynesville area in which we have a minority working interest. Particularly when our working interest is small, we do not always enter into formal operating agreements with the operators, and in such cases, we rely on applicable legal and statutory authority to govern our arrangement in accordance with industry standard practices.
Where we do have joint operating agreements with affiliates of other companies, these agreements call for significant penalties should we elect not to participate in the drilling and completion of a well proposed by the operator, or a non-consent well. These non-consent penalties typically allow the operator to recover up to 400% of its costs to drill, complete and equip the non-consent well from the well’s future net revenue prior to us being allowed to participate in the non-consent well for our original working interest. Ultimately, the amount of these penalties may result in us having no participation at all in the non-consent well. We also have the right to propose wells under these joint operating agreements, and the same non-consent penalties apply to the operator should it elect not to consent to a well that we propose.
While we do not have direct access to our operating partners’ drilling plans with respect to future well locations, we do attempt to maintain ongoing communications with the technical staff of these operators in
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an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves.
We currently intend to allocate approximately 82% of our estimated 2013 capital expenditure budget of $310.0 million to the exploration, development and acquisition of additional interests in South Texas, primarily in the Eagle Ford shale play. We also plan to allocate about 16% of our 2013 capital expenditure budget to the exploration and acquisition of additional interests in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. As a result of these anticipated capital expenditures in South Texas and in Southeast New Mexico and West Texas, we plan to dedicate about 98% of our 2013 anticipated capital expenditure budget to opportunities prospective for oil and liquids production. While we have budgeted approximately $310.0 million for 2013, the aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill scheduled wells, our drilling results and our ability to obtain capital. Since approximately 84% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2014, 79% of our Wolfcamp and Bone Spring acreage was either held by production or not burdened by lease expirations before 2014 and almost all of our Haynesville acreage was held by production at December 31, 2012, we possess the financial flexibility to allocate our capital when and where we believe it is economical and justified.
Recent Developments
On March 11, 2013, the borrowing base under our Credit Agreement was increased to $255.0 million based on the lenders’ review of our proved oil and natural gas reserves at December 31, 2012. At that time, we also amended our Credit Agreement to include Capital One, N.A., BMO Harris Financing, Inc. (Bank of Montreal) and IberiaBank in our lending group, which also includes Royal Bank of Canada (“RBC”), as administrative agent, Comerica Bank, Citibank, N.A., The Bank of Nova Scotia and SunTrust Bank. At March 14, 2013, we had $180.0 million in borrowings and $1.3 million in letters of credit outstanding under our Credit Agreement.
Principal Areas of Interest
Our focus since inception has been the exploration for oil and natural gas in unconventional resource plays with a particular focus in recent years in the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana. During 2012, we devoted most of our efforts and most of our capital investment to our drilling operations in the Eagle Ford shale in South Texas as we sought to increase our oil production and reserves. Since our inception, our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our prospects, as well as to explore for more conventional targets in addition to the unconventional resource plays.
At December 31, 2012, our principal areas of interest consisted of (1) the Eagle Ford shale play in South Texas, (2) the Haynesville shale play, including the Middle Bossier shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations in Northwest Louisiana and East Texas, (3) the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas, particularly in the Delaware Basin, and (4) the Meade Peak shale play in Southwest Wyoming and the adjacent areas of Utah and Idaho.
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South Texas
Eagle Ford Shale and Other Formations
The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces wet natural gas with condensate. We believe that approximately 88% of our South Texas acreage at December 31, 2012 lies within those portions of the Eagle Ford shale that are prone to produce oil or wet natural gas with condensate.
During 2012, our operations were primarily focused on the exploration and development of our Eagle Ford shale properties in South Texas as we continued executing our strategy to significantly increase our oil production and oil reserves. In 2012, we completed and began producing oil and natural gas from 28 gross/24.5 net operated Eagle Ford shale wells, including 25 gross/23.7 net operated and 3 gross/0.8 net non-operated Eagle Ford shale wells. We had two contracted drilling rigs operating in South Texas throughout 2012 (except for a brief period near the end of the second quarter when we added a third rig to execute a two-well contract). At March 14, 2013, we continued to have two contracted drilling rigs operating in South Texas: one in LaSalle County and one in DeWitt County. More than 90% of our 2012 total capital expenditures of $334.6 million were directed to our operations in South Texas, primarily in the Eagle Ford shale.
For the year ended December 31, 2012, about 43% of our daily production, or 3,908 BOE per day, including 3,246 Bbl of oil per day and 4.0 MMcf of natural gas per day, was produced from the Eagle Ford shale in South Texas. Almost all of our oil production in 2012 was attributed to the Eagle Ford shale. The Eagle Ford contributed 98% of our daily oil production and about 12% of our daily natural gas production during 2012 as compared to 78% of our daily oil production and 3% of our daily natural gas production during 2011. During the year ended December 31, 2011, only about 8% of our daily production, or 548 BOE per day, including 331 Bbl of oil per day and 1.3 MMcf of natural gas per day, was attributable to the Eagle Ford shale. This growth in oil and natural gas production from the Eagle Ford shale over the past year reflects our ongoing drilling and completion program in the Eagle Ford shale.
At December 31, 2012, approximately 60% of our estimated total proved oil and natural gas reserves, or 14.3 million BOE, was attributable to the Eagle Ford shale, including approximately 10.4 million Bbl of oil and 23.8 Bcf of natural gas. Our proved reserves attributable to the Eagle Ford shale increased just over three-fold for the year to 14.3 million BOE for the year ended December 31, 2012, as compared to 4.7 million BOE for the year ended December 31, 2011. Our Eagle Ford proved reserves at December 31, 2012 comprised approximately 99% of our proved oil reserves and 30% of our proved natural gas reserves, as compared to approximately 96% of our proved oil reserves and 4% of our proved natural gas reserves at December 31, 2011. The PV-10 of our proved reserves in the Eagle Ford at December 31, 2012 was $393.2 million, or about 93% of the PV-10 of our total proved reserves of $423.2 million. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “— Estimated Proved Reserves.” We anticipate that the percentage of our daily production and proved reserves attributable to the Eagle Ford shale will continue to grow in 2013 as we intend to allocate approximately 82% of our 2013
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capital expenditure budget to the exploration, development and acquisition of additional interests in South Texas, primarily in the Eagle Ford shale play, in an effort to continue growing the oil and liquids component of our production and reserves.
At December 31, 2012, we had drilled and completed a total of 32 gross/30.5 net Eagle Ford wells on our operated properties, and all of these wells were producing to sales. At December 31, 2012, we had also participated in 3 gross/0.6 net Eagle Ford wells with EOG Resources, Inc. as operator, on portions of our Atascosa County acreage and 2 gross/0.6 net Eagle Ford wells with Hunt Oil Company as operator, on portions of our Wilson County acreage.
During the year ended December 31, 2012, we completed and began producing oil and natural gas from 25 gross/23.7 net operated Eagle Ford wells drilled on our acreage position in South Texas. As we completed and began producing oil and natural gas from these wells during 2012, our Eagle Ford production increased significantly. During the fourth quarter of 2011, our daily production from the Eagle Ford shale averaged 584 BOE per day, including 378 Bbl of oil per day and 1.2 MMcf of natural gas per day. By comparison, during the fourth quarter of 2012, our daily oil production from the Eagle Ford shale averaged 5,363 BOE per day, including 4,545 Bbl of oil per day and 4.9 MMcf of natural gas per day. Natural gas produced from most of our Eagle Ford shale wells is a liquids-rich gas and our purchasers process this natural gas for us at their processing facilities to remove the natural gas liquids, such as ethane, propane and other heavier natural gas liquids components. Our Eagle Ford wells typically yield three to seven gallons of natural gas liquids per thousand cubic feet of natural gas produced at the wellhead depending on the specific property.
During the year ended December 31, 2012, we believe that we increased our technical knowledge on how to drill, complete and produce Eagle Ford shale wells. Eagle Ford wells drilled on the eastern portion of our acreage in Karnes and DeWitt Counties are typically 1,000 to 2,500 feet deeper than wells drilled on the western portion of our acreage in LaSalle County. At December 31, 2012, the typical drilling time for wells on the western portion of our acreage ranged from 10 to 15 days from spud to rig release and the typical drilling time for wells on the eastern portion of our acreage ranged from 15 to 20 days from spud to rig release. These drilling times compared to 20 to 30 days from spud to rig release for wells drilled in the earlier months of 2012. As a result of more efficient drilling and reduced completion costs, the overall drilling and completion costs associated with our Eagle Ford wells declined during 2012. At December 31, 2012, we estimate that the cost for us to drill and complete a 5,000-ft Eagle Ford shale well was approximately $6 million to $7 million on the western portion of our acreage in LaSalle County and approximately $8 million to $10 million on the eastern portion of our acreage in Karnes and DeWitt Counties. We believe the reduction in drilling and completion costs we achieved during 2012 was due in part to improved efficiencies in our own operations, as well as to declining service costs associated with an increase in the supply of drilling and completion services in South Texas during 2012. We do not anticipate that service costs will decline to the same extent in 2013, although we will continue to look for ways to improve the costs associated with our operations.
At December 31, 2012, our aggregate leasehold interests consisted of approximately 42,500 gross acres and 27,900 net acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, LaSalle, Wilson and Zavala Counties in South Texas. We believe portions of this acreage may also be prospective for the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce
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predominantly oil and liquids. In particular, the Austin Chalk formation, which is a naturally fractured carbonate typically ranging in thickness from 200 to 400 feet, and the Buda formation, which is a naturally fractured carbonate typically ranging in thickness from 90 to 160 feet, have produced from several fields on or nearby portions of our acreage.
During the year ended December 31, 2012, we acquired approximately 5,500 gross and 3,400 net acres in the Eagle Ford shale play that we consider to be prospective primarily for oil production. This acreage essentially replaced the acreage upon which we drilled and established oil and natural gas production and reserves during 2012. We also allowed approximately 11,800 gross and 4,300 net acres of our Eagle Ford leasehold position, primarily in Atascosa County, but also including acreage in northeast Webb and southeast Dimmit Counties, to expire undrilled during the year ended December 31, 2012, as we no longer considered this acreage to be economic for further exploration and development in the Eagle Ford shale at then-current commodity prices.
At December 31, 2012, we owned a 100% working interest in approximately 26,900 gross acres and 24,100 net acres in Gonzales, Karnes, LaSalle, Wilson and Zavala Counties and a 50% working interest in approximately 2,800 gross and 1,400 net acres in DeWitt County and are the operator of this acreage. We also owned an approximate 21% working interest in approximately 12,800 gross acres in Atascosa County operated by EOG Resources, Inc. At December 31, 2012, approximately 84% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2014.
Between March and July 2011, we acquired leasehold interests in approximately 6,300 gross and 4,800 net acres in DeWitt, Gonzales, Karnes and Wilson Counties in the Eagle Ford shale play from Orca ICI Development, JV (“Orca”). We initially acquired a 50% working interest in the acreage (approximately 2,800 gross and 1,400 net acres) in DeWitt County and are the operator. We currently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net acres) in Gonzales, Karnes and Wilson Counties and are the operator. At December 31, 2012, we had drilled and completed 15 gross/12.7 net wells on this acreage.
At December 31, 2012, we had paid 100% of the costs to drill and complete the first six wells drilled on the acreage in DeWitt County. We have an 85% working interest in these six wells until we have recovered all of our acquisition, drilling, completion, facilities and operating costs from each well, at which time Orca’s working interest will increase to 50%. After we have recovered all of our acquisition, drilling, completion, facilities and operating costs, when the cumulative production from any of these first six wells reaches 500,000 BOE, on a well-by-well basis, then Orca’s working interest in that well will increase to 55%. If the cumulative production from any of the first six wells reaches 750,000 BOE, on a well-by-well basis, then Orca’s working interest in that well will increase to 70%. Orca retains the right to pay its share of the costs and to participate for a 50% working interest in all subsequent wells drilled on the acreage in DeWitt County, and we have no further obligation to carry any of Orca’s costs in any subsequent well drilled on the acreage. Should Orca elect not to participate in a subsequent well that we propose to drill on the acreage, we will own a 100% working interest in the well until such time as we have recovered 400% of our acquisition, drilling, completion, facilities and operating costs from such well, at which time Orca’s working interest will increase to 50%. As of December 31, 2012, Orca had declined to participate in one subsequent well we drilled in DeWitt County, and we own an initial 100% working interest in this well.
At December 31, 2012, we had paid 100% of the costs to drill and complete the first five wells drilled on the acreage in Gonzales, Karnes and Wilson Counties. We have a 100% working interest in these wells until we have recovered all of our acquisition, drilling, completion, facilities and operating costs from each of these five wells. After we have recovered all of our acquisition, drilling, completion, facilities and
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operating costs from any of these five wells, Orca may elect, on a well-by-well basis, to back-in for a 25% working interest in such wells. In addition, Orca retained a one-time election for a short period of time after we completed these first five wells to participate for a 25% working interest in all subsequent wells drilled on this acreage by paying a purchase price equal to 25% of our costs to acquire the acreage in Gonzales, Karnes and Wilson Counties. Following the completion of these first five wells, Orca declined to exercise its right to participate in all future wells drilled on this acreage. As a result, we will have a 100% working interest, and Orca will have no interest, in all subsequent wells drilled on this acreage. At December 31, 2012, we had drilled or participated in a total of 8 gross/6.6 net wells on this specific acreage.
As we continue to explore and develop our leasehold positions in the Eagle Ford shale in South Texas, we may face challenges with establishing operations in new areas and securing the necessary services to drill and complete wells and with securing the necessary pipeline and natural gas processing capabilities to process, transport and market the oil and natural gas we produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure on our leases throughout the area. We believe that we have successfully secured the necessary drilling and completion services for our current Eagle Ford operations. We did not experience difficulties in securing completion, and in particular hydraulic fracturing, services for our newly drilled wells during the year ended December 31, 2012, although we experienced these problems at various times during 2011 in South Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling and completion services and reducing drilling and completion costs will be essential to the successful development and profitability of the Eagle Ford shale play. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans Within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.”
We did experience temporary pipeline and natural gas processing interruptions from time to time during the year ended December 31, 2012 associated with natural gas production from our Eagle Ford shale wells. To alleviate most of the interruptions and processing capacity constraints we experienced during 2012, effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. No assurance can be made that this agreement will alleviate these issues completely, and if we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. We may experience similar interruptions and processing capacity constraints as we begin to explore and develop our Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas in 2013. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.”
In addition to the Eagle Ford potential on our acreage, we believe that approximately 22,800 gross acres and 17,500 net acres in South Texas are prospective primarily for the Austin Chalk and 15,600 gross and 10,500 net acres are prospective primarily for the Buda formation, which have historically been targeted by operators in South Texas. During the year ended December 31, 2012, we completed and began
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producing oil and natural gas from 2 gross/2.0 net wells in the upper Austin Chalk and the lower Austin Chalk/upper Eagle Ford, or “Chalkleford,” intervals. Both of these wells were drilled on our acreage in Zavala County, which is in the heart of the historic Pearsall (Austin Chalk) Field where significant volumes of oil and natural gas have previously been produced from the Austin Chalk. Both of these wells are producing oil, but the results of these wells did not meet our expectations, with the upper Austin Chalk well apparently largely depleted by previous Austin Chalk production from nearby wells. We have not yet drilled an Austin Chalk well at any other location on our leasehold positions in South Texas, and although we believe that other prospective Austin Chalk well locations exist on this acreage, we have only included 17 gross and 17.0 net Austin Chalk well locations in our total identified drilling locations at December 31, 2012. We plan to drill an operated Austin Chalk exploratory test well on one of our leases in Gonzales County during 2013. At December 31, 2012, we had not included any Buda locations in our identified future drilling locations, although we do plan to participate in the drilling of an exploratory Buda test well on one of our leases in Atascosa County operated by EOG Resources, Inc. during the first quarter of 2013.
Northwest Louisiana and East Texas
As a result of substantially lower natural gas prices in 2012, we did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during the year ended December 31, 2012. We did, however, participate in the drilling and completion of 28 gross/1.1 net non-operated Haynesville shale wells in 2012, comprising about 3% of our total capital expenditures. We do not plan to drill any operated Haynesville wells in 2013, but we have budgeted capital expenditures of approximately $5.1 million for our participation in approximately 10 gross/0.5 net wells that we anticipate may be drilled by other operators on certain of our non-operated properties in 2013. We operate all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. Of the approximately 5,700 net acres that we consider to be in the core area of the Haynesville play, we operate about 22% of that acreage.
For the year ended December 31, 2012, about 56% of our average daily production, or 5,042 BOE per day, including 31 Bbl of oil per day and 30.1 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. The vast majority of our natural gas production in 2012 was attributable to these properties. Natural gas production from these properties comprised approximately 88% of our daily natural gas production, but oil production from these properties only comprised about 1% of our daily oil production during 2012, as compared to 96% of our daily natural gas production and 15% of our daily oil production during 2011. During the year ended December 31, 2011, approximately 92% of our daily production, or 6,459 BOE per day, including 64 Bbl of oil per day and 38.4 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. The decline in oil and particularly natural gas production from these properties over the past year reflects (i) the natural decline in production from these properties, (ii) the voluntary curtailment by the operators of natural gas production from some of our non-operated Haynesville shale wells in Northwest Louisiana at various times during 2012 and (iii) our decision not to drill any operated Haynesville shale or Cotton Valley wells during 2012.
For the year ended December 31, 2012, about 76% of our daily natural gas production, or 26.0 MMcf of natural gas per day, was produced from the Haynesville shale, with another 12%, or 4.1 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations in this area. For the year ended December 31, 2011, about 81% of our daily natural gas production, or 32.3 MMcf of natural gas per day, was produced from the Haynesville shale, with another 15%, or 6.1 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties.
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At December 31, 2012, approximately 33% of our estimated total proved reserves, or 7.9 million BOE, were attributable to the Haynesville shale underlying this acreage with another 6% of our proved reserves, or 1.5 million BOE, associated with the Cotton Valley and shallower formations. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (or 16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012, most of which were attributable to non-operated properties. These proved undeveloped natural gas reserves were likewise not included in our estimated total proved reserves at December 31, 2012. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries.
During 2012, natural gas prices declined to their lowest levels in many years, ranging from a low of approximately $1.91 per MMBtu in mid-April to a high of approximately $3.90 per MMBtu in late November, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices had declined again since late November 2012, before increasing to $3.81 per MMBtu at March 14, 2013, based upon the NYMEX Henry Hub natural gas futures contract for the earliest delivery date. We would not expect to drill any operated natural gas wells in either our Haynesville or Cotton Valley properties until natural gas prices improve further from these levels, the costs to drill and complete these wells decline further from their recent levels or new technologies are developed that increase expected recoveries. See “Risk Factors — Our Identified Drilling Locations Are Scheduled out over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.”
Haynesville and Middle Bossier Shales
The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics with the deeper Haynesville shale. Although there is some overlap between the Haynesville and Bossier shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation.
At December 31, 2012, we had leasehold and mineral interests in approximately 22,300 gross and 14,200 net acres prospective for the Haynesville shale. This acreage includes approximately 5,700 net acres in what we believe is the core area of the play. Over 99% of our Haynesville acreage is held by production or consists of fee mineral interests that we own and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,700 net acres are prospective for the Middle Bossier shale play as well. We have not yet drilled a Middle Bossier shale well, and, although we believe that prospective well locations exist on this acreage, we have not included any Middle Bossier locations in our identified drilling locations at December 31, 2012.
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Within the 5,700 net acres that we believe to be in the core area of the Haynesville shale play, we are the operator of approximately 1,200 net acres in two sections where we have working interests of 95% and 100%, respectively, in all wells to be drilled. We have identified 12 gross and 11.7 net potential additional Haynesville locations that we may drill and operate in the future in these two sections. The remainder of our acreage in the core area of the Haynesville shale play, about 4,500 net acres, is operated by other companies, including approximately half of our non-operated Haynesville acreage in this area of the play that is operated by a subsidiary of Chesapeake following a sale of a portion of our interest in July 2008. Including the acreage operated by a subsidiary of Chesapeake, our non-operated Haynesville acreage is attributable to leasehold interests that we hold in 81 sections in Caddo, DeSoto, Bossier and Red River Parishes in Northwest Louisiana. Our working interests in the Haynesville wells in these sections range from less than 1% to more than 30%.
Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations
Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in Northwest Louisiana and East Texas were attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in Northwest Louisiana and East Texas.
All of the shallow rights underlying our acreage in our Elm Grove/Caspiana properties in Northwest Louisiana, approximately 10,000 gross and net acres at December 31, 2012, is held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to discovery of the Haynesville shale. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%.
In January 2011, we completed our first horizontal Cotton Valley well, the Tigner Walker H #1-Alt. on our Elm Grove/Caspiana properties, in DeSoto Parish and commenced sales of natural gas from this well. Based on the performance of this well and data available from public sources on other Cotton Valley horizontal wells drilled in this area of Northwest Louisiana, we believe that Cotton Valley horizontal wells drilled on our Elm Grove/Caspiana properties may have estimated ultimate natural gas recoveries of 4 to 6 Bcf. Prior to drilling this well, we had only drilled and completed vertical Cotton Valley and Hosston wells on these properties. We are the operator and have a 100% working interest in this well. We have identified 71 gross and 49.3 net additional drilling locations for future Cotton Valley horizontal wells on our Elm Grove/Caspiana properties. We did not drill any of these locations in 2012 and do not plan to drill any of these locations in 2013. As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the deeper Haynesville shale wells, however, these Cotton Valley natural gas volumes remain available to be developed by us at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries.
We also continue to hold the shallow rights by existing production or by leases that are still in their primary terms in our Central and Southwest Pine Island, Longwood, Woodlawn and other prospect areas in Northwest Louisiana and East Texas. At December 31, 2012, we held an estimated 11,500 net leasehold and mineral acres by existing production in these areas.
Southeast New Mexico and West Texas — Delaware Basin
During 2012, we added to our acreage position in the Delaware Basin in Southeast New Mexico and West Texas, which is a mature exploration and production province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of
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development in this basin has focused on relatively conventional reservoir targets, but we believe the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin.
One example of such an opportunity appears to be the so-called “Wolf-Bone” play of the Delaware Basin. Together, the Lower Permian age Bone Spring (also called Leonardian) and Wolfcamp formations span several thousand feet of stacked shales, sandstones, limestones and dolomites, representing complex and dynamic submarine depositional systems that include several organic rich source rocks. Throughout these intervals, oil and natural gas have been produced primarily from conventional sandstone and carbonate reservoirs even though hydrocarbons are trapped in the tight sands, limestones and dolomites interbedded within organic rich shale. Recently, these hydrocarbon-bearing zones have been recognized by a number of operators as targets for horizontal drilling and multi-stage hydraulic fracturing techniques. As a result, several large industry players are expanding positions and conducting drilling programs throughout Eddy and Lea Counties in Southeast New Mexico and Loving, Pecos, Reeves and Ward Counties in West Texas.
For the year ended December 31, 2012, less than 1% of our average daily production, or only about 30 BOE per day, including 25 Bbl of oil per day and 30 Mcf of natural gas per day, was attributable to our leasehold properties in Southeast New Mexico and West Texas. At December 31, 2012, we held leasehold interests in approximately 15,900 gross and 7,600 net acres in Southeast New Mexico and West Texas where we are developing new oil prospects. In particular, in August 2012, we acquired approximately 4,900 gross and 2,900 net acres prospective for the Wolfcamp and Bone Spring formations in Loving County, Texas, almost all of which is held by production from uphole formations to which we did not acquire the exploration and development rights. Subsequent to that time, we have added additional interests in this immediate area and at December 31, 2012, we held approximately 5,200 gross and 3,000 net acres in this leasehold position in Loving County. We have budgeted approximately $15.0 million of our anticipated 2013 capital expenditures to acquire additional leasehold interests prospective for oil and liquids production in Southeast New Mexico and West Texas. A portion of our leasehold interests in this area, including approximately 7,700 gross and 2,100 net acres in Winkler County, Texas, is no longer considered to be prospective by us, and we plan to let this acreage expire without drilling.
At December 31, 2012, we believe that approximately 8,200 gross and 5,500 net acres of our leasehold interests in the Delaware Basin are prospective for the Wolfcamp and Bone Spring formations, as well as other potential uphole targets, including the Avalon shale and Delaware sands, of which approximately 6,000 gross and 3,900 net acres are already held by existing production from other horizons by us or other operators. We believe that the Wolfcamp, Bone Spring, Avalon and Delaware formations are all prospective primarily for oil and that multiple intervals may be prospective within each target formation. We expect to begin exploring this acreage position during the second and third quarters of 2013, with plans to drill three exploratory test wells on this acreage in 2013. We have allocated approximately $35.6 million of our 2013 capital expenditure budget for these drilling and completion operations, including an estimated $5.4 million for pipelines, production facilities and related infrastructure. Two of these wells will test the Wolfcamp and one well will test the Second Bone Spring formation.
Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale
The Meade Peak shale is an organic-rich member of the Phosphoria formation, a source rock that is believed to have sourced much of the oil and natural gas in conventional reservoirs in the western Wyoming and eastern Utah area. The Phosphoria/Meade Peak shale has an observed shale thickness of 70 to 350 feet, total organic carbon values of 3% to 14% and vitrinite reflectance values ranging from 1.8% to 2.7%. The
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formation is encountered at depths of 3,000 to 14,000 feet, with the majority of our acreage in the depth range of 3,000 to 10,000 feet. The shale has been penetrated by over 100 wells in the area, most of which have natural gas shows.
We believe there have been no previous attempts to drill horizontally or to hydraulically fracture the Meade Peak shale in this area. Our focus to date has been to confirm the physical characteristics of the Meade Peak shale and evaluate its production potential. We have gathered well log data in the area, conducted a series of mapping evaluations of structural disposition and studied the petrophysical characteristics of the Meade Peak shale. In addition, we have purchased 2-D seismic data and conducted surface mapping studies using a structural geologist who has experience in the immediate area to better understand the area’s tectonic history.
At December 31, 2012, we held leasehold interests in approximately 55,300 gross and 27,200 net acres in Southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploration prospect targeting the Meade Peak shale. These leasehold interests are a combination of federal, state and fee mineral interests. We have entered into a participation and joint operating agreement with other parties covering the initial exploration effort, and if successful, the future development of this acreage. We are the operator of this prospect. We had no production, no proved reserves and no identified drilling locations attributable to this acreage at December 31, 2012.
At December 31, 2011, we held leasehold interests in approximately 144,000 gross and 136,000 net acres in this prospect, of which approximately 102,000 gross and 93,000 net acres were scheduled to expire at various times during 2012. Although we elected to take extensions or new leases on some portions of this expiring acreage during 2012, certain leases, particularly those taken on state lands, did not offer the opportunity for automatic extension and expired during 2012. Should we desire to reacquire mineral rights on these lands, we would need to seek new leases.
Along with our partners, we began drilling the initial test well on this prospect, the Crawford Federal #1 well in Lincoln County, Wyoming, in February 2011. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September 2011 and completed drilling, well logging and coring operations in November 2011. During 2012, we conducted detailed evaluations of the well logs and conducted special core analysis tests to better understand the petrophysical characteristics of the Meade Peak shale.
In September 2012, we entered into an agreement with our principal partner related to the ongoing exploration of the Meade Peak shale, pursuant to which our principal partner (i) paid us a prospect fee of $1.0 million, (ii) agreed to provide up to a total cost of $3.0 million (carrying our 50% share) for extensions of expiring leases and new leasing in the prospect in which we will have a 50% working interest at no cost to us and (iii) agreed to carry our 50% share of the drilling and completion costs associated with the horizontal lateral up to a total cost for these operations of $5.0 million, with each party paying 50% of all drilling and completion costs in excess of $5.0 million. In return for this consideration, in December 2012, we assigned 50% of our gross and net leasehold interests in the prospect to our principal partner.
In November 2012, we re-entered the Crawford Federal #1 vertical well and drilled a horizontal lateral from that wellbore into the Meade Peak shale approximately 2,500 feet in length. We temporarily suspended this well following drilling operations. We expect to return to this well in the third quarter of 2013 to conduct the completion operations on the horizontal lateral, which we expect will consist of three to
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four hydraulic fracture treatments along the length of the lateral. After the horizontal lateral is completed, we and our partners plan to test and evaluate this well before making further decisions concerning the future exploration of the Meade Peak shale in this prospect.
Operating Summary
The following table sets forth certain unaudited production data for the years ended December 31, 2012, 2011 and 2010:
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Unaudited Production Data |
||||||||||||
| Net Production Volumes: |
||||||||||||
| Oil (MBbl) |
1,214 | 154 | 33 | |||||||||
| Natural gas (Bcf) |
12.5 | 14.5 | 8.4 | |||||||||
| Total oil equivalent (MBOE)(1) |
3,294 | 2,573 | 1,433 | |||||||||
| Average daily production (BOE/d)(1) |
9,000 | 7,049 | 3,926 | |||||||||
| Average Sales Prices: |
||||||||||||
| Oil, with realized derivatives (per Bbl) |
$ | 103.55 | $ | 93.80 | $ | 76.39 | ||||||
| Oil, without realized derivatives (per Bbl) |
$ | 101.86 | $ | 93.80 | $ | 76.39 | ||||||
| Natural gas, with realized derivatives (per Mcf) |
$ | 3.55 | $ | 4.11 | $ | 4.38 | ||||||
| Natural gas, without realized derivatives (per Mcf) |
$ | 2.59 | $ | 3.62 | $ | 3.75 | ||||||
| Operating Expenses (per BOE): |
||||||||||||
| Production taxes and marketing |
$ | 3.54 | $ | 2.44 | $ | 1.38 | ||||||
| Lease operating |
$ | 8.56 | $ | 2.82 | $ | 3.69 | ||||||
| Depletion, depreciation and amortization |
$ | 24.43 | $ | 12.34 | $ | 10.89 | ||||||
| General and administrative |
$ | 4.42 | $ | 5.21 | $ | 6.77 | ||||||
| (1) | Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. |
The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2012 from our primary operating areas:
| Average Net Daily Production | Total
Net Production (MBOE)(1) |
Percentage of Total Net Production |
||||||||||||||||||
| Oil (Bbl/d) |
Gas (Mcf/d) |
Oil Equivalent (BOE/d)(1) |
||||||||||||||||||
| South Texas: |
||||||||||||||||||||
| Eagle Ford |
3,246 | 3,976 | 3,908 | 1,431 | 43.4 | % | ||||||||||||||
| Austin Chalk(2) |
15 | 31 | 20 | 7 | 0.3 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Area Total |
3,261 | 4,007 | 3,928 | 1,438 | 43.7 | |||||||||||||||
| NW Louisiana/E Texas: |
||||||||||||||||||||
| Haynesville |
1 | 26,007 | 4,336 | 1,587 | 48.2 | |||||||||||||||
| Cotton Valley(3) |
30 | 4,051 | 706 | 258 | 7.8 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Area Total |
31 | 30,058 | 5,042 | 1,845 | 56.0 | |||||||||||||||
| SE New Mexico, West Texas |
25 | 30 | 30 | 11 | 0.3 | |||||||||||||||
| SW Wyoming, NE Utah, SE Idaho(4) |
– | – | – | – | – | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
3,317 | 34,095 | 9,000 | 3,294 | 100.0 | % | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| (1) | Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. |
| (2) | Includes two wells producing small volumes of natural gas from the San Miguel formation in Zavala County, Texas. |
| (3) | Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. |
| (4) | We currently have no production from our acreage in Southwest Wyoming and adjacent areas of Utah and Idaho. |
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The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2011 from our primary operating areas:
| Average Net Daily Production | Total
Net Production (MBOE)(1) |
Percentage of Total Net Production |
||||||||||||||||||
| Oil (Bbl/d) |
Gas (Mcf/d) |
Oil Equivalent (BOE/d)(1) |
||||||||||||||||||
| South Texas: |
||||||||||||||||||||
| Eagle Ford |
331 | 1,298 | 548 | 200 | 7.8 | % | ||||||||||||||
| Austin Chalk(2) |
– | 30 | 5 | 2 | 0.1 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Area Total |
331 | 1,328 | 553 | 202 | 7.9 | |||||||||||||||
| NW Louisiana/E Texas: |
||||||||||||||||||||
| Haynesville |
– | 32,319 | 5,387 | 1,966 | 76.4 | |||||||||||||||
| Cotton Valley(3) |
64 | 6,054 | 1,072 | 392 | 15.2 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Area Total |
64 | 38,373 | 6,459 | 2,358 | 91.6 | |||||||||||||||
| SE New Mexico, West Texas |
27 | 59 | 37 | 13 | 0.5 | |||||||||||||||
| SW Wyoming, NE Utah, SE Idaho(4) |
– | – | – | – | – | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
422 | 39,760 | 7,049 | 2,573 | 100.0 | % | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| (1) | Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. |
| (2) | Includes two wells producing small volumes of natural gas from the San Miguel formation in Zavala County, Texas. |
| (3) | Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. |
| (4) | We currently have no production from our acreage in Southwest Wyoming and adjacent areas of Utah and Idaho. |
Our total production of approximately 3.3 million BOE for the year ended December 31, 2012 was an increase of 28% over our total production of approximately 2.6 million BOE for the year ended December 31, 2011. This increased production was primarily due to drilling operations in the Eagle Ford shale. Our average daily production for the year ended December 31, 2012 was 9,000 BOE per day, as compared to 7,049 BOE per day for the year ended December 31, 2011. Our average daily oil production for the year ended December 31, 2012 was 3,317 Bbl of oil per day, an approximate eight-fold increase from 422 Bbl of oil per day for the year ended December 31, 2011.
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Producing Wells
The following table sets forth information relating to producing wells at December 31, 2012. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We do not have any currently active dual completions. We have an approximate average working interest of 93% in all wells that we operate. For wells where we are not the operator, our working interests range from less than 1% to as much as 44%, and average approximately 8%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells.
| Oil Wells | Natural Gas Wells | Total Wells | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| South Texas: |
||||||||||||||||||||||||
| Eagle Ford |
35.0 | 29.7 | 2.0 | 2.0 | 37.0 | 31.7 | ||||||||||||||||||
| Austin Chalk(1) |
2.0 | 2.0 | 2.0 | 2.0 | 4.0 | 4.0 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Area Total |
37.0 | 31.7 | 4.0 | 4.0 | 41.0 | 35.7 | ||||||||||||||||||
| NW Louisiana/E Texas: |
||||||||||||||||||||||||
| Haynesville |
– | – | 134.0 | 12.7 | 134.0 | 12.7 | ||||||||||||||||||
| Cotton Valley(2) |
2.0 | 2.0 | 104.0 | 67.7 | 106.0 | 69.7 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Area Total |
2.0 | 2.0 | 238.0 | 80.4 | 240.0 | 82.4 | ||||||||||||||||||
| SE New Mexico, West Texas |
12.0 | 5.1 | 1.0 | 0.6 | 13.0 | 5.7 | ||||||||||||||||||
| SW Wyoming, NE Utah, SE Idaho(3) |
– | – | – | – | – | – | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total |
51.0 | 38.8 | 243.0 | 85.0 | 294.0 | 123.8 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| (1) | Includes two wells producing small volumes of natural gas from the San Miguel formation in Zavala County, Texas. |
| (2) | Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. |
| (3) | We currently have no production from our acreage in Southwest Wyoming and adjacent areas of Utah and Idaho. |
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Estimated Proved Reserves
The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2012, 2011 and 2010. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
| At December 31,(1) | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Estimated Proved Reserves Data:(2) |
||||||||||||
| Estimated proved reserves: |
||||||||||||
| Oil (MBbl) |
10,485 | 3,794 | 152 | |||||||||
| Natural Gas (Bcf) |
80.0 | 170.4 | 127.4 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total (MBOE)(3) |
23,819 | 32,196 | 21,387 | |||||||||
|
|
|
|
|
|
|
|||||||
| Estimated proved developed reserves: |
||||||||||||
| Oil (MBbl) |
4,764 | 1,419 | 152 | |||||||||
| Natural Gas (Bcf) |
54.0 | 56.5 | 43.1 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total (MBOE)(3) |
13,771 | 10,843 | 7,342 | |||||||||
|
|
|
|
|
|
|
|||||||
| Percent Developed |
57.8 | % | 33.7 | % | 34.3 | % | ||||||
| Estimated proved undeveloped reserves: |
||||||||||||
| Oil (MBbl) |
5,721 | 2,375 | – | |||||||||
| Natural Gas (Bcf) |
26.0 | 113.9 | 84.3 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total (MBOE)(3) |
10,048 | 21,353 | 14,045 | |||||||||
|
|
|
|
|
|
|
|||||||
| PV-10(4) (in millions) |
$ | 423.2 | $ | 248.7 | $ | 119.9 | ||||||
| Standardized Measure(5) (in millions) |
$ | 394.6 | $ | 215.5 | $ | 111.1 | ||||||
| (1) | Numbers in table may not total due to rounding. |
| (2) | Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2010 were $75.96 per Bbl for oil and $4.376 per MMBtu for natural gas, for the 12 months ended December 31, 2011 were $92.71 per Bbl for oil and $4.118 per MMBtu for natural gas, and for the 12 months ended December 31, 2012 were $91.21 per Bbl for oil and $2.757 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. |
| (3) | Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. |
| (4) | PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2010, 2011 and 2012 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2010, 2011 and 2012 were, in millions, $8.8, $33.2, and $28.6, respectively. |
| (5) | Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. |
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Our proved oil reserves grew 176% (almost three-fold) from approximately 3.8 million Bbl at December 31, 2011 to approximately 10.5 million Bbl at December 31, 2012. This increase is attributable to proved oil reserves added due to our drilling operations in the Eagle Ford shale in South Texas. Proved oil reserves at December 31, 2012 comprised 44% of our total proved reserves as compared to only 12% at December 31, 2011.
Our total proved oil and natural gas reserves decreased from 32.2 million BOE at December 31, 2011 to 23.8 million BOE at December 31, 2012, reflecting primarily the decrease in our proved natural gas reserves from 170.4 Bcf at December 31, 2011 to 80.0 Bcf at December 31, 2012. This decrease in our proved natural gas reserves was primarily attributable to the decrease in our proved undeveloped natural gas reserves from 113.9 Bcf at December 31, 2011 to 26.0 Bcf at December 31, 2012. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012, most of which were attributable to non-operated properties. These proved undeveloped natural gas reserves were likewise not included in our estimated total proved reserves at December 31, 2012. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. The PV-10 of our total proved oil and natural gas reserves increased by 70% from $248.7 million at December 31, 2011 to $423.2 million at December 31, 2012. Our total proved reserves at December 31, 2012 were made up of approximately 44% oil and 56% natural gas as compared to 12% oil and 88% natural gas at December 31, 2011.
Our proved developed oil and natural gas reserves increased from 10.8 million BOE at December 31, 2011 to 13.8 million BOE at December 31, 2012 due primarily to additions resulting from our drilling operations in the Eagle Ford shale. Our proved developed oil reserves increased from 1.4 million Bbl at December 31, 2011 to 4.8 million Bbl at December 31, 2012 as a result of our drilling operations in the Eagle Ford shale. Our proved developed natural gas reserves declined from 56.5 Bcf (9.4 million BOE) at December 31, 2011 to 54.0 Bcf (9.0 million BOE) at December 31, 2012. The net increase of 3.0 million BOE in our proved developed reserves from December 31, 2011 to December 31, 2012 was composed of (1) additions of 7.4 million BOE, including 4.7 million Bbl of oil and 16.2 Bcf of natural gas (2.7 million BOE), plus conversions of 0.4 million BOE, including 0.3 million Bbl of oil and 0.8 Bcf of natural gas (0.1 million BOE) from proved undeveloped to proved developed reserves, less (2) net oil and natural gas production of 3.3 million BOE, including 1.2 million Bbl of oil and 12.5 Bcf of natural gas (2.1 million BOE), less (3) downward revisions of proved developed reserves by 1.5 million BOE, including 0.5 million Bbl of oil and 6.2 Bcf of natural gas (1.0 million BOE). The downward revisions in proved developed natural gas reserves were primarily attributable to the lower natural gas prices used to estimate proved reserves at December 31, 2012 as compared to December 31, 2011. During the year ended December 31, 2012, we recorded no changes to proved developed reserves as a result of the acquisition or divestment of reserves.
Our proved undeveloped oil and natural gas reserves decreased from 21.4 million BOE at December 31, 2011 to 10.1 million BOE at December 31, 2012. Our proved undeveloped oil reserves increased from 2.4 million Bbl at December 31, 2011 to 5.7 million Bbl at December 31, 2012 as a result of our drilling operations in the Eagle Ford shale. Our proved undeveloped natural gas reserves decreased from 113.9 Bcf (19.0 million BOE) at December 31, 2011 to 26.0 Bcf (4.3 million BOE) at December 31, 2012 due primarily to the removal of 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana as a result of lower natural gas prices in 2012. The net decrease of 11.3 million BOE in our proved undeveloped reserves from December 31,
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2011 to December 31, 2012 is composed of (1) additions to proved undeveloped reserves of 5.5 million BOE, including 4.0 million Bbl of oil and 9.3 Bcf of natural gas (1.5 million BOE) identified through drilling operations, less (2) the conversion of 0.4 million BOE of proved undeveloped reserves to proved developed reserves, including 0.3 million Bbl of oil and 0.8 Bcf of natural gas (0.1 million BOE), less (3) the net downward revisions of proved undeveloped reserves by 16.4 million BOE in the period, including 0.3 million Bbl of oil and 96.4 Bcf (16.1 million BOE). During the year ended December 31, 2012, we recorded no changes to proved undeveloped reserves as a result of the acquisition or divestment of reserves. At December 31, 2012, we had no proved reserves in our estimates that remained undeveloped for five years or more following their initial booking.
The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2012:
| Net Proved Reserves(1) | ||||||||||||||||||||
| Oil | Gas | Oil Equivalent |
PV-10 (2) | Standardized Measure(3) |
||||||||||||||||
| (MBbl) | (Bcf) | (MBOE)(4) | (in millions) | (in millions) | ||||||||||||||||
| South Texas: |
||||||||||||||||||||
| Eagle Ford |
10,358 | 23.8 | 14,331 | 393.2 | 366.6 | |||||||||||||||
| Austin Chalk(5) |
7 | 0.1 | 20 | 0.4 | 0.4 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Area Total |
10,365 | 23.9 | 14,351 | 393.6 | 367.0 | |||||||||||||||
| NW Louisiana/E Texas: |
||||||||||||||||||||
| Haynesville |
– | 47.1 | 7,856 | 21.8 | 20.3 | |||||||||||||||
| Cotton Valley(6) |
34 | 8.9 | 1,512 | 5.8 | 5.4 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Area Total |
34 | 56.0 | 9,368 | 27.6 | 25.7 | |||||||||||||||
| SE New Mexico, West Texas |
86 | 0.1 | 100 | 2.0 | 1.9 | |||||||||||||||
| SW Wyoming, NE Utah, SE Idaho(7) |
– | – | – | – | – | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
10,485 | 80.0 | 23,819 | 423.2 | 394.6 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| (1) | Numbers in table may not total due to rounding. |
| (2) | PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2012 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2012 were approximately $28.6 million. |
| (3) | Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. |
| (4) | Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. |
| (5) | Includes two wells producing small volumes of natural gas from the San Miguel formation in Zavala County, Texas. |
| (6) | Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. |
| (7) | At December 31, 2012, we had no proved reserves attributable to our acreage in Southwest Wyoming and adjacent areas of Utah and Idaho. |
Technology Used to Establish Reserves
Under current SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty
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can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods.
Internal Control Over Reserves Estimation Process
We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Reserves Manager is primarily responsible for overseeing the preparation of our reserves estimates and has over 16 years of industry experience. Our Reserves Manager received his Ph.D. degree in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and received a certificate of completion in a prescribed course of study in Reserves and Evaluation from Texas A&M University in May 2009. Our Vice President – Reservoir Engineering is responsible for reviewing and approving our reserves estimates and has over 35 years of industry experience. Following the preparation of our reserves estimates, we had our reserves estimates audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. The Engineering Committee of our board of directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by members of our board of directors, including members of our Audit Committee.
Acreage Summary
The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2012. At that date, about 44% of our total net acreage had been developed, although these percentages are somewhat higher in South Texas and much higher in Northwest Louisiana and East Texas.
| Developed Acres | Undeveloped Acres | Total Acres | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| South Texas: |
||||||||||||||||||||||||
| Eagle Ford |
18,236 | 15,736 | 24,220 | 12,175 | 42,456 | 27,911 | ||||||||||||||||||
| Austin Chalk |
8,892 | 8,892 | 13,893 | 8,573 | 22,785 | 17,465 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Area Total(1) |
18,236 | 15,736 | 24,220 | 12,175 | 42,456 | 27,911 | ||||||||||||||||||
| NW Louisiana/E Texas: |
||||||||||||||||||||||||
| Haynesville |
19,286 | 11,178 | 2,995 | 2,995 | 22,281 | 14,173 | ||||||||||||||||||
| Cotton Valley(2) |
22,085 | 19,435 | 3,370 | 3,034 | 25,455 | 22,469 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Area Total(3) |
24,749 | 21,859 | 3,444 | 3,109 | 28,193 | 24,968 | ||||||||||||||||||
| SE New Mexico, West Texas |
1,160 | 991 | 14,700 | 6,600 | 15,860 | 7,591 | ||||||||||||||||||
| SW Wyoming, NE Utah, SE Idaho |
– | – | 55,273 | 27,180 | 55,273 | 27,180 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total |
44,145 | 38,586 | 97,637 | 49,064 | 141,782 | 87,650 | ||||||||||||||||||
|
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|
|
|
|
|
|
|
|
|||||||||||||
| (1) | Some of the same leases cover the gross and net acreage shown for both the Eagle Ford shale and the Austin Chalk formation, a shallower formation than the Eagle Ford shale. Therefore, the sum of the total gross and net acreage for both formations is not equal to the total gross and net acreage for South Texas. |
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| (2) | Includes shallower zones and also includes acreage surrounding one well producing from the Frio formation in Orange County, Texas. |
| (3) | Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the Cotton Valley formation, a shallower formation than the Haynesville shale. Therefore, the sum of the net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. |
Undeveloped Acreage Expiration
The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2012 that will expire prior to December 31, 2014 by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates or unless the existing leases are renewed prior to expiration or unless continued operations maintain the leases beyond the expiration of each respective primary term.
| Acres Expiring 2013 |
Acres Expiring 2014 |
|||||||||||||||
| Gross | Net | Gross | Net | |||||||||||||
| South Texas: |
||||||||||||||||
| Eagle Ford |
8,832 | 4,455 | 3,903 | 613 | ||||||||||||
| Austin Chalk |
5,260 | 3,689 | 589 | 89 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Area Total(1) |
8,832 | 4,455 | 3,903 | 613 | ||||||||||||
| NW Louisiana/E Texas: |
||||||||||||||||
| Haynesville |
– | – | 33 | 33 | ||||||||||||
| Cotton Valley |
– | – | – | – | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Area Total(2) |
– | – | 33 | 33 | ||||||||||||
| SE New Mexico, West Texas |
8,717 | 2,658 | 7,514 | 497 | ||||||||||||
| SW Wyoming, NE Utah, SE Idaho |
5,882 | 2,861 | – | – | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
23,431 | 9,974 | 11,450 | 1,143 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| (1) | Some of the same leases cover the gross and net acreage shown for both the Eagle Ford shale and the Austin Chalk formation, a shallower formation than the Eagle Ford shale. Therefore, the sum of the total gross and net acreage for both formations is not equal to the total gross and net acreage for South Texas. |
| (2) | Some of the same leases cover the gross and net acreage shown for the Haynesville shale and the Cotton Valley formation, a shallower formation than the Haynesville shale. Therefore, the sum of the total gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. |
Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted which will serve to maintain the respective leases in effect beyond the expiration of the primary term or unless production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. Our leases are mainly fee leases with three to five years of primary term. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests.
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Drilling Results
The following table summarizes our drilling activity for the years ended December 31, 2012, 2011 and 2010:
| Year Ended December 31, | ||||||||||||||||||||||||
| 2012 | 2011 | 2010 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| Development Wells |
||||||||||||||||||||||||
| Productive |
36 | 17.1 | 30 | 0.6 | 5 | 1.7 | ||||||||||||||||||
| Dry |
– | – | – | – | – | – | ||||||||||||||||||
| Exploration Wells |
||||||||||||||||||||||||
| Productive |
22 | 10.4 | 30 | 10.2 | 36 | 3.4 | ||||||||||||||||||
| Dry |
– | – | – | – | – | – | ||||||||||||||||||
| Total Wells |
||||||||||||||||||||||||
| Productive |
58 | 27.6 | 60 | 10.8 | 41 | 5.1 | ||||||||||||||||||
| Dry |
– | – | – | – | – | – | ||||||||||||||||||
Marketing
Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids.
Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated mid-stream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees. When there is an opportunity to do so, the mid-stream companies may, at our request, process our natural gas at a processing facility and extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the mid-stream companies’ sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees.
The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include the level of demand for oil and natural gas, weather conditions, hurricanes in the Gulf Coast region, natural gas storage levels, domestic and foreign governmental regulations, the actions of OPEC, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices do adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production do occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.”
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For the years ended December 31, 2012, 2011 and 2010, we had three significant purchasers that accounted for approximately 74%, 60% and 70%, respectively, of our total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time.
Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its firm natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue we receive varies with the quality of natural gas transported to the processing facilities and the contract period.
Under this agreement, if we do not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, we will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. We believe that our current and anticipated production from the wells covered by this agreement is sufficient to meet 80% of the maximum thermal quantity transportation and processing commitments under this agreement.
We were also party to one natural gas transportation agreement at December 31, 2012 that requires us to deliver a specified volume of natural gas through a pipeline for a fixed period of time. If we fail to meet the volume requirement, we are required to pay an amount to the owners of the pipeline to offset a portion of the expenses they incurred in building the pipeline to our well location. This contract does not constitute a material commitment. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.”
Title to Properties
We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, where required, or making lease rental payments or by producing oil and natural gas from wells in paying quantities prior to expiration of various time periods to avoid lease termination. Certain of the leases that we have obtained to date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.”
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Competition
The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Most of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment.
Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while our competitors have a longer history of operations, and most of them have also demonstrated the ability to operate through industry cycles.
The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel.”
Regulation
Oil and Natural Gas Regulation
Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations.
Texas, New Mexico, Louisiana, Wyoming, Idaho and Utah and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
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Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases.
Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue.
In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for the sale or transportation of physical natural gas in interstate commerce and to significantly increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims.
Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated.
The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations.
In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future laws or regulations or their impact.
U.S. Federal and State Taxation
The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated
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with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has proposed sweeping changes to federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. Among other issues, President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.”
Hydraulic Fracturing Policies and Procedures
We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately 50% of the drilling and completion costs for our horizontal wells are associated with hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.”
The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management (“BLM”) with respect to federal acreage).
Although rare, if and when the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue, running diagnostic tools, including cement bond logs, temperature logs and pressure testing, followed by pumping remedial cement jobs and other appropriate remedial measures.
The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in the fracturing operation as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of the fracturing operation in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures.
While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters.
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Environmental Regulation
The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and expect that these laws and regulations will not have a material adverse impact on us.
The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and related to liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable requirements under the OPA 90 will not have a material adverse effect on us.
The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. Certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the U.S. Environmental Protection Agency, or the EPA, has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require certain oil-storing facilities to prepare plans and meet construction and operating standards.
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CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that may be classified as hazardous substances under CERCLA. Many states have adopted similar statutes. Certain state statutes may impose liability for a broader range of contaminants and may not contain a similar exemption for petroleum. Furthermore, we may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed to, prior releases of hazardous substances or other materials requiring remediation.
RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes.
The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On April 17, 2012, the EPA issued final rules to subject oil and natural 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 volatile organic compound (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 wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We are currently evaluating the effect these rules will have on our business.
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Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas.
The EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, on October 30, 2009, the EPA published a rule requiring the reporting of greenhouse gas emissions from specified sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a rule that expands its final rule on greenhouse gas emissions reporting to include owners and operators of onshore and offshore oil and natural gas production, onshore natural gas processing, natural gas storage, natural gas transmission and natural gas distribution facilities. Reporting of greenhouse gas emissions from such onshore production was first required on an annual basis in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our profits or could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas.
Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or state or regional greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less significant sources of emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. We currently own and operate five underground injection wells and expect to own other similar wells. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties.
Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “— Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing
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regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection (unless diesel is a component of the fracturing fluid) on the federal level pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of chemicals used in the hydraulic fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition, results of operations and cash flows.
In addition, in some states and localities, there has been a push to place additional regulatory burdens upon hydraulic fracturing activities and, in some areas, to severely restrict or prohibit those activities. At the state level, Texas and Wyoming, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. In addition, at least a few local governments or regional authorities have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations.
The EPA has recently asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. The EPA is currently conducting a study on the effects of hydraulic fracturing on drinking water resources. A progress report was released 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, but such studies could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. The BLM has indicated that it is considering proposed rules to regulate hydraulic fracturing on federal lands. Further, the EPA has announced an initiative under the Toxic Substance Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals.
Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability.
Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas,
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have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us.
We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain 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 OSHA workplace standards.
The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. If a portion of our leases were designated as critical or suitable habitat, our ability to maximize production from our leases may be adversely impacted.
We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, including Complex Environmental Laws, Which Could Require Significant Expenditures.”
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The EPA has announced that one of its enforcement initiatives for 2011 to 2013 is to focus on compliance by the energy extraction sector. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons.
We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows.
Office Lease
Our corporate headquarters are located in approximately 36,500 square feet of office space at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas. The initial lease, as amended, expires on
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June 30, 2022 and at December 31, 2012 covered approximately 29,000 square feet. On January 16, 2013, we entered into a fourth amendment to our office lease agreement to include approximately 7,800 square feet of additional space, increasing the size of our corporate headquarters from approximately 28,700 square feet to approximately 36,500 square feet.
Employees
At December 31, 2012, we had 50 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, production operations, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities.
Available Information
Our Internet website address is www.matadorresources.com. We make available, free of charge, through our website, our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance Committee, Executive Committee and Nominating, Compensation and Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report on Form 10-K or any other report or document we file and any reference to our website is intended to be an inactive textual reference only.
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| Item 1A. | Risk Factors. |
Risks Related to the Oil and Natural Gas Industry and Our Business
Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.
The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include the following:
| • | the domestic and foreign supply of oil and natural gas; |
| • | the domestic and foreign demand for oil and natural gas; |
| • | the prices and availability of competitors’ supplies of oil and natural gas; |
| • | the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls; |
| • | the price and quantity of foreign imports; |
| • | the impact of U.S. dollar exchange rates on oil and natural gas prices; |
| • | domestic and foreign governmental regulations and taxes; |
| • | speculative trading of oil and natural gas futures contracts; |
| • | the availability, proximity and capacity of gathering, processing and transportation systems for natural gas; |
| • | the availability of refining capacity; |
| • | the prices and availability of alternative fuel sources; |
| • | weather conditions and natural disasters; |
| • | political conditions in or affecting oil and natural gas producing regions, including the Middle East and South America; |
| • | the continued threat of terrorism and the impact of military action and civil unrest; |
| • | public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities; |
| • | the level of global oil and natural gas inventories and exploration and production activity; |
| • | the impact of energy conservation efforts; |
| • | technological advances affecting energy consumption; and |
| • | overall worldwide economic conditions. |
Approximately 63% of our production during the year ended December 31, 2012 and 56% of our proved reserves at December 31, 2012 were attributable to natural gas. In addition, three of our largest assets or prospects — the Haynesville shale, Cotton Valley and Meade Peak shale — currently produce or are expected to produce predominantly natural gas. As a result, they are sensitive to fluctuations in natural gas prices.
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During 2012, natural gas prices declined to their lowest levels in many years, ranging from a low of approximately $1.91 per MMBtu in mid-April to a high of approximately $3.90 per MMBtu in late November, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices had declined again since late November 2012 before increasing to $3.81 per MMBtu at March 14, 2013, based upon the NYMEX Henry Hub natural gas futures contract for the earliest delivery date. We would not expect to drill any operated natural gas wells, except for natural gas wells in specific exploration prospects like the Meade Peak shale, until natural gas prices improve further from these levels, the costs to drill and complete these wells decline further from their recent levels or new technologies are developed that increase expected recoveries.
In 2011, we began to focus on increasing our oil and liquids production. Specifically, our drilling opportunities in the Eagle Ford shale play in South Texas and our planned drilling opportunities in the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas focus on oil and liquids. Approximately 37% of our production during the year ended December 31, 2012 and 44% of our proved reserves at December 31, 2012 were attributable to oil. We currently intend to allocate approximately 98% of our 2013 capital expenditure budget to opportunities prospective for oil and liquids production, including primarily the Eagle Ford shale and the Wolfcamp and Bone Spring plays. These opportunities are sensitive to changes in oil prices.
Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil prices decrease to economically unattractive levels and remain there for an extended period of time or should natural gas prices decline further or remain at current levels, we may elect in the future to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, each of which would have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months.
Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business.
Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling, completing and operating processes. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly.
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If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. Whether a well is ultimately productive and profitable depends on a number of additional factors, including the following:
| • | general economic and industry conditions, including the prices received for oil and natural gas; |
| • | shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; |
| • | potential drainage by operators on adjacent properties; |
| • | loss of or damage to oilfield development and service tools; |
| • | problems with title to the underlying properties; |
| • | increases in severance taxes; |
| • | adverse weather conditions that delay drilling activities or cause producing wells to be shut in; |
| • | domestic and foreign governmental regulations; and |
| • | proximity to and capacity of gathering, processing and transportation facilities. |
If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected.
Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.
Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash, operating cash flows and potential future borrowings under our Credit Agreement or otherwise may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable.
Although we currently have no plans to do so, we may sell additional equity securities or issue debt securities to raise capital. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities.
Our cash flows from operations and access to capital are subject to a number of variables, including:
| • | our estimated proved oil and natural gas reserves; |
| • | the amount of oil and natural gas we produce from existing wells; |
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| • | the prices at which we sell our production; |
| • | the costs of developing and producing our oil and natural gas reserves; |
| • | our ability to acquire, locate and produce new reserves; |
| • | the ability and willingness of banks to lend to us; and |
| • | our ability to access the equity and debt capital markets. |
In addition, future events, such as terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets have caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future.
If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain exploration opportunities. Alternatively, to fund an acquisition, increase our rate of growth or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise to meet any increase in capital spending. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and future results of operations could be adversely affected.
We May Incur Additional Indebtedness Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations and Our Unit Costs.
At March 14, 2013, we had available borrowings of approximately $73.7 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future acquired oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by substantially all of our interests in our oil and natural gas properties and other assets and contains covenants restricting our ability to incur additional indebtedness, which may limit our ability to obtain additional financing. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a lower borrowing base, we could be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments.
In the future, we may incur significant amounts of additional indebtedness, including under our Credit Agreement, in order to make acquisitions or to develop our properties. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. Our level of indebtedness could affect our operations in several ways, including the following:
| • | a significant portion of our cash flows could be used to service our indebtedness; |
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| • | a high level of debt would increase our vulnerability to general adverse economic and industry conditions; |
| • | any covenants contained in the agreements governing our outstanding indebtedness could limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; |
| • | a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness may prevent us from pursuing; |
| • | our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; and |
| • | a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes. |
A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. We may not be able to generate sufficient cash flows to pay the principal of or interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or debt securities or a refinancing of our debt include financial market conditions, the value of our assets, our oil and natural gas production and our performance at the time we need capital. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets or have a portion of our assets foreclosed upon which could have a material adverse effect on our business and financial results.
Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May Not Be Adequately Insured.
There are numerous operational hazards inherent in oil and natural gas exploration, development, production and gathering, including:
| • | unusual or unexpected geologic formations; |
| • | natural disasters; |
| • | adverse weather conditions; |
| • | unanticipated pressures; |
| • | loss of drilling fluid circulation; |
| • | blowouts where oil or natural gas flows uncontrolled at a wellhead; |
| • | cratering or collapse of the formation; |
| • | pipe or cement leaks, failures or casing collapses; |
| • | fires or explosions; |
| • | releases of hazardous substances or other waste materials that cause environmental damage; |
| • | pressures or irregularities in formations; and |
| • | equipment failures or accidents. |
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In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.
Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We May Have Accidents, Equipment Failures or Mechanical Problems While Drilling or Completing Wells or in Production Activities, Which Could Adversely Affect Our Business.
While we are drilling and completing oil or natural gas wells or involved in production activities, we may have accidents or experience equipment failures or mechanical problems in a well that cause us to be unable to drill and complete the well or to continue to produce the well according to our plans. We may also damage a potentially hydrocarbon-bearing formation during drilling and completion operations. Such incidents may result in a reduction of our production and reserves from, or abandonment of, the well.
Because Our Reserves and Production Are Concentrated in a Small Number of Properties, Problems in Production and Markets Relating to Any Property Could Have a Material Impact on Our Business.
Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in South Texas and in Northwest Louisiana and East Texas. For the year ended December 31, 2012, 44% of our oil and natural gas production, including 99% of our average daily oil production was attributable to our properties in South Texas. At December 31, 2012, approximately 93% of the PV-10 of our proved reserves and 99% of our total proved oil reserves were attributable to our properties in South Texas, primarily in the Eagle Ford shale. We expect that most of our operations in the near future will be primarily in South Texas.
Even though we have entered into a firm five-year natural gas processing and transportation agreement covering the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas, we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in these areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation,
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natural disasters, adverse weather conditions or plant closures for scheduled maintenance. In addition, the increased industry focus on the Eagle Ford shale may adversely impact our ability to process and transport our production due to increased competition for these facilities.
Our operations in South Texas may also be adversely affected by hurricanes and tropical storms resulting in delays in exploration and drilling, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition, results of operations and cash flows.
The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.
Shortages or the high cost of drilling rigs, completion equipment and services, supplies or personnel could delay or adversely affect our operations. When drilling activity in the United States increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. These costs may increase, and necessary equipment and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows.
In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs could result and could adversely affect our business, financial condition, results of operations and cash flows.
If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired.
We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our business, financial condition, results of operations and cash flows.
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Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.
The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing primarily on increasing our production and reserves from the Eagle Ford shale play, an area in which our competitors have been active. As a result of this activity, we may have difficulty expanding our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic. In addition, it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected.
Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.
The process of estimating accumulations of oil and natural gas is complex and inexact, due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of:
| • | the quality and quantity of available data; |
| • | the interpretation of that data; |
| • | the judgment of the persons preparing the estimate; and |
| • | the accuracy of the assumptions. |
The accuracy of any estimates of proved reserves generally increases with the length of production history. Due to the limited production history of many of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance to our estimates could materially affect the quantities and present value of our reserves.
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The Calculated Present Value of Future Net Revenues from Our Proved Oil and Natural Gas Reserves Will Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves.
It should not be assumed that the present value of future net cash flows included in this Annual Report on Form 10-K is the current market value of our estimated proved oil and natural gas reserves. We generally base the estimated discounted future net cash flows from proved reserves on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as:
| • | actual prices we receive for oil and natural gas; |
| • | actual costs and timing of development and production expenditures; |
| • | the amount and timing of actual production; and |
| • | changes in governmental regulations or taxation. |
In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under Generally Accepted Accounting Principles, or GAAP, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general.
Approximately 43% of Our Total Proved Reserves at December 31, 2012 Consisted of Undeveloped and Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced.
At December 31, 2012, approximately 42% of our total proved reserves were undeveloped and approximately 1% were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced or such reserves may not be developed or produced within the time periods we have projected or at the costs we have budgeted. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves, which could materially affect our business, financial condition, results of operations and cash flows.
Our Identified Drilling Locations Are Scheduled out over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.
Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including assessment of risks, costs, drilling results, oil and natural gas prices, the availability of equipment and capital, approval by regulators and seasonal conditions. The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this Annual Report on Form 10-K as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our financial condition, results of operations and cash flows.
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Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases That Will Expire over the Next Several Years Unless Production Is Established on Units Containing the Acreage.
At December 31, 2012, we had leasehold interests in approximately 11,000 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to December 31, 2014. Unless we establish production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. If our leases expire, we will lose our right to develop the related properties. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third party leases may have been taken and could become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows.
We May Not Increase Our Acreage Positions in Areas with Exposure to Oil, Condensate and Natural Gas Liquids.
If we are unable to increase our acreage positions in the Eagle Ford shale in South Texas or in the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas, this may detract from our efforts to realize our growth strategy in oil and liquids-rich plays. Additionally, we may be unable to find or consummate other opportunities in these areas or in other areas with similar exposure to oil, condensate and natural gas liquids on similar terms or at all.
The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate Exploration Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect Our Results of Operations and Cash Flows.
We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Poor results from our exploration activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows.
We Currently Own Only a Limited Amount of Seismic and Other Geological Data and May Have Difficulty Obtaining Additional Data at a Reasonable Cost, Which Could Adversely Affect Our Results of Operations and Cash Flows.
We currently own only a limited amount of seismic and other geological data to assist us in exploration and development activities. We intend to obtain access to additional data in our areas of interest through licensing arrangements with companies that own or have access to that data or by paying to obtain that data directly. Seismic and geological data can be expensive to license or obtain. We may not be able to license or obtain such data at an acceptable cost.
Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also,
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there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our Competitors May Use Superior Technology and Data Resources That We May Be Unable to Afford or That Would Require a Costly Investment by Us in Order to Compete with Them More Effectively.
Our industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, many of our competitors will have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may become obsolete, and we may be adversely affected.
Strategic Relationships upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations.
Our ability to explore, develop and produce oil and natural gas resources successfully and acquire oil and natural gas interests and acreage depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired.
To develop our business, we will endeavor to use the business relationships of our management, board and special board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies, including those that supply equipment and other resources that we expect to use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.
The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.
The unavailability of satisfactory oil, natural gas and natural gas liquids gathering, processing and transportation arrangements may hinder our access to oil, natural gas and natural gas liquids markets or
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delay production from our wells. The availability of a ready market for our oil, natural gas and natural gas liquids production depends on a number of factors, including the demand for, and supply of, oil, natural gas and natural gas liquids and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations owned and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases.
The disruption of third party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and natural gas liquids. The third parties control when or if such facilities are restored and what prices will be charged. We experienced temporary pipeline interruptions from time to time during the year ended December 31, 2012 associated with natural gas production from our Eagle Ford shale wells. While we have entered into a firm five-year natural gas processing and transportation agreement covering the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas, no assurance can be given that this agreement will alleviate these issues completely. We may experience similar interruptions and processing capacity constraints as we begin to explore and develop our Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas in 2013. If we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it would have a material adverse effect on our business, financial condition, results of operations and cash flows.
Financial Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third Party Operators or Other Third Parties Could Decrease Our Cash Flows from Operations and Adversely Affect the Exploration and Development of Our Prospects and Assets.
We derive essentially all of our revenues from the sale of our oil, natural gas and natural gas liquids to unaffiliated third party purchasers, independent marketing companies and mid-stream companies. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations and cash flows.
Liquidity and cash flow problems encountered by our working interest co-owners or the third party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary to fund either of these contingencies or that we would be able to find a new farmout party.
The Third Parties on Whom We Rely for Gathering, Processing and Transportation Services Are Subject to Complex Federal, State and Other Laws that Could Adversely Affect the Cost, Manner or Feasibility of Conducting Our Business.
The operations of the third parties on whom we rely for gathering, processing and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities.
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These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Business — Regulation.”
We Have Limited Control over Activities on Properties We Do Not Operate.
We are not the operator on some of our properties, particularly in the Haynesville shale. As a result of our sale of certain assets to a subsidiary of Chesapeake Energy Corporation in 2008, we do not operate one of our most significant natural gas assets in the Haynesville shale. We also have other non-operated acreage positions in Northwest Louisiana, South Texas, Southeast New Mexico and West Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including:
| • | timing and amount of capital expenditures; |
| • | the operator’s expertise and financial resources; |
| • | the rate of production of reserves, if any; |
| • | approval of other participants in drilling wells; and |
| • | selection and implementation or execution of technology. |
In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production.
A Component of Our Growth May Come through Acquisitions, and Our Failure to Identify or Complete Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth.
We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Our financial
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position, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. If we are not successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted.
We may engage in bidding and negotiating to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise. Our Credit Agreement includes covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas.
We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know About or That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could Adversely Affect Our Results of Operations.
Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities.
We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.
If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the mineral interest desired or other title deficiencies, our interest would be worth less than what we paid and may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost.
It is our practice in acquiring oil and natural gas leases, or undivided interests in oil and natural gas leases, not to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, we rely upon the judgment of oil and natural gas lease brokers and/or landmen who perform the field work in examining records in the appropriate governmental office before attempting to acquire a lease on a specific mineral interest.
Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and
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such curative work entails expense. Our failure to cure any title defects may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash flows.
We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules and These Write-Downs Could Adversely Affect Our Financial Condition.
There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low. In addition, non-cash write-downs may occur if we have:
| • | downward adjustments to our estimated proved reserves; |
| • | increases in our estimates of development costs; or |
| • | deterioration in our exploration and development results. |
We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is based on the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity and could lower the value of our common stock.
Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses.
To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or natural gas liquids prices rise above the maximum price established by the call option and may offer protection if prices fall below the minimum price established by the put option only to the extent of the volumes then hedged.
In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option contracts fail to perform under the contracts.
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Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions.
Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and natural gas liquids prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful.
An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.
The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark prices and the prices we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead prices we receive could adversely affect our business, financial condition, results of operations and cash flows. We do not have, and may not have in the future, any derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials.
We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.
The exploration, development, production and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation and environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. These expenditures could include payments for:
| • | personal injuries; |
| • | property damage; |
| • | containment and clean-up of oil and other spills; |
| • | management and disposal of hazardous materials; |
| • | remediation, clean-up costs and natural resource damages; and |
| • | other environmental damages. |
We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements.
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These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations.
We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.
The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals.
Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. President Obama has proposed sweeping changes in federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. President Obama has proposed to eliminate allowing small oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. The passage of any legislation as a result of the budget proposals or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows.
Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.
In past sessions, Congress has considered, but did not pass, legislation to amend the Safe Drinking Water Act, or SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to produce oil, natural gas and natural gas liquids from formations such as the Eagle Ford and the Haynesville shales, where we focus our operations, and we anticipate using hydraulic fracturing in the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas. The EPA is conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water and groundwater. A progress report was released in December 2012, with final results expected in 2014. In addition, in
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December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution of a natural gas field in Wyoming. Consequently, even if federal legislation is not adopted soon or at all, the performance of the hydraulic fracturing study by the EPA could spur further action towards federal legislation and regulation of hydraulic fracturing or similar production operations. Also at the federal level, the BLM has indicated that it is considering proposed rules to regulate hydraulic fracturing on federal lands. Additionally, the EPA has announced an initiative under the Toxic Substances Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals.
In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, which could include a moratorium on drilling and effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. Texas and Wyoming have adopted legislation that requires the disclosure of information regarding the substances used in the hydraulic fracturing process. This legislation and any implementing regulations could increase our costs of compliance and doing business.
The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional resource plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.
Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and Natural Gas Liquids We Produce while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects.
The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Accordingly, the EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. 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 released a final rule that expands its rule on reporting of greenhouse gas emissions to include owners and operators of petroleum and natural gas systems. Monitoring of those newly covered emissions commenced on January 1, 2011, with the first annual reports filed in 2012.
In an interpretative guidance on climate change disclosures, the SEC indicated 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, there is the potential for our exploration and production operations 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, 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 effect 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
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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. See “—If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.
New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs.
On April 17, 2012, the EPA issued final rules to subject oil and natural 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 volatile organic compound (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 wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We are currently evaluating the effect these rules will have on our business.
The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Any such legislation could adversely affect demand for the oil, natural gas and natural gas liquids that we produce.
A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy by It May Result in Increased Regulation of Our Assets, Which May Cause Our Revenues to Decline and Operating Expenses to Increase.
Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. A change in the jurisdictional characterization by FERC, the courts or Congress or a change in policy by FERC or Congress may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
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Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and Orders, We Could Be Subject to Substantial Penalties and Fines.
Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. The nature of our gathering facilities is such that we have not yet been regulated by FERC as a natural gas company subject to the provisions of the NGA. It is possible, however, that laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability.
The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business.
On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, sets forth a framework for regulating certain derivative products including commodity hedges of the type we use, but many aspects of this law are subject to further rulemaking and will take effect over several years. As a result, it is difficult to anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to continue entering into and maintaining such commodity hedges and the terms thereof. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future.
If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our ability to conduct acquisitions.
We May Have Difficulty Managing Growth in Our Business, Which Could Have a Material Adverse Effect on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our Business Plan in a Timely Fashion.
Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our activities, including our planned increase in oil exploration, development and production, and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers and landmen, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion.
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Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our Chairman of the Board, Chief Executive Officer and President, Management and Technical Team, the Members of Our Board of Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board Advisor Could Disrupt Our Business Operations.
Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman, President and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
We have an active board of directors that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our board of directors work closely with management to identify potential prospects, acquisitions and areas for further development. Many of our directors have been involved with us since our inception and have a deep understanding of our operations and culture. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected.
In addition, our board consults regularly with our special advisors regarding our business and the evaluation, exploration, engineering and development of our prospects. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected.
Our Management Team Owns Approximately 11% of Our Common Stock, Which Could Give Them Influence in Corporate Transactions and Other Matters, and the Interests of Our Management Could Differ from Other Shareholders.
Our directors and officers beneficially own approximately 11% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and officers may be able to remain entrenched in their positions.
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Risks Relating to Our Common Stock
The Price of Our Common Stock Has Fluctuated Substantially and May Fluctuate Substantially in the Future.
Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2012, our stock price fluctuated between a high of $12.33 and a low of $7.70. In the future, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.
Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include:
| • | our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; |
| • | quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; |
| • | changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; |
| • | speculation in the press or investment community; |
| • | public reaction to our press releases, announcements and filings with the SEC; |
| • | sales of our common stock by us or shareholders, or the perception that such sales may occur; |
| • | general financial market conditions and oil and natural gas industry market conditions, including fluctuations in commodity prices; |
| • | the realization of any of the risk factors presented in this Annual Report on Form 10-K; |
| • | the recruitment or departure of key personnel; |
| • | commencement of or involvement in litigation; |
| • | the prices of oil, natural gas and natural gas liquids; |
| • | the success of our exploration and development operations, and the marketing of any oil, natural gas and natural gas liquids we produce; |
| • | changes in market valuations of companies similar to ours; and |
| • | domestic and international economic, legal and regulatory factors unrelated to our performance. |
The Requirements of Being a Public Company, Including Compliance with the Reporting Requirements of the Securities Exchange Act of 1934, as Amended, and the Requirements of the Sarbanes-Oxley Act of 2002, Have Increased Our Costs and Occupy a Significant Amount of Management’s Time.
As a public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the New York Stock Exchange, or the NYSE. Complying
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with these statutes, regulations and requirements is difficult and occupies a significant amount of time of our board of directors and management and has significantly increased our costs and expenses.
If We Fail to Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected.
Until February 2012, we were a private company and maintained internal controls and procedures in accordance with being a private company. We maintained limited accounting personnel to perform our accounting processes and limited supervisory resources with which to address our internal control over financial reporting. In connection with our audits for the years ended December 31, 2011 and 2010, our independent registered public accountants identified and communicated material weaknesses. There were no material weaknesses identified in connection with our audit for the year ended December 31, 2012.
A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual and interim financial statements will not be prevented or detected and corrected on a timely basis.
Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Further, our remediation efforts may not enable us to avoid material weaknesses in the future. Any failure to maintain effective controls could result in material misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information and adversely affect our business and our stock price.
We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock.
We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our board of directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. In addition, certain covenants in our Credit Agreement may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid.
The Trading Volume of Our Common Stock Has Been Low, and the Sale of a Substantial Number of Shares in the Public Market Could Depress the Price of Our Common Stock.
Our common stock is listed on the NYSE, but since the completion of our initial public offering, it has had a low average daily trading volume relative to many other stocks. Thinly traded stock can be more volatile than stock trading in an active public market, which can lead to significant price swings even when a relatively small number of shares are being traded and can limit an investor’s ability to quickly sell blocks of stock.
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Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our Common Stock by Us Could Depress the Price of Our Common Stock.
The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock.
We may also sell additional shares of common stock or securities convertible into common stock. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock.
Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects That Could Prevent a Change in Control Even if It Might Be Beneficial to Our Shareholders.
Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include:
| • | authorization for our board of directors to issue preferred stock without shareholder approval; |
| • | a classified board of directors so that not all members of our board of directors are elected at one time; |
| • | the prohibition of cumulative voting in the election of directors; and |
| • | a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock. |
Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or any affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our board of directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder.
Our Board of Directors Can Authorize the Issuance of Preferred Stock, which Could Diminish the Rights of Holders of Our Common Stock and Make a Change of Control of the Company More Difficult Even if It Might Benefit Our Shareholders.
Our board of directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the company, even if that change of control might benefit our shareholders.
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| Item 1B. | Unresolved Staff Comments. |
Not applicable.
| Item 2. | Properties. |
See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See “Note 13 – Commitments and Contingencies” to the consolidated financial statements in this Annual Report on Form 10-K for the future minimum rental payments. Such information is incorporated herein by reference.
| Item 3. | Legal Proceedings. |
See “Note 13 – Commitments and Contingencies” to the consolidated financial statements in this Annual Report on Form 10-K. Such information is incorporated herein by reference.
| 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. |
General Market Information
Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock.
On March 14, 2013, we had 55,894,438 shares of common stock outstanding held by approximately 444 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name.
The following table sets forth the high and low sales prices of our common stock as reported by the NYSE for the periods indicated:
| 2012 | ||||||||
| High | Low | |||||||
| First Quarter |
$ | 12.33 | $ | 10.85 | ||||
| Second Quarter |
12.09 | 8.63 | ||||||
| Third Quarter |
11.53 | 9.41 | ||||||
| Fourth Quarter |
10.50 | 7.70 | ||||||
On March 14, 2013, the last reported sales price of our common stock on the NYSE was $8.80 per share.
Dividend Policy
We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, certain covenants in our Credit Agreement may limit our ability to pay dividends on our common stock.
Prior to the consummation of our initial public offering on February 7, 2012, the holders of our Class B common stock were entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These dividends accrued and were payable quarterly at the rate of $0.06-2/3 per share of Class B common stock outstanding. For the year ended December 31, 2011, we declared dividends on our outstanding shares of Class B common stock totaling $274,853. Upon the automatic conversion of the outstanding shares of Class B common stock at the closing of our initial public offering, the right of the holders of Class B common stock to dividends was terminated and such holders were paid approximately $28,000 during the first quarter of 2012 for all accrued but unpaid dividends existing at the time of such conversion.
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Equity Compensation Plan Information
The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2012.
| Equity Compensation Plan Information |
||||||||||||
| Plan Category |
Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights |
Weighted- Average Exercise Price of Outstanding Options, Warrants and Rights ($) |
Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans |
|||||||||
| Equity compensation plans approved by security holders(1) (2) |
1,229,437 | $ | 10.19 | 3,056,957 | ||||||||
| Equity compensation plans not approved by security holders |
– | – | – | |||||||||
|
|
|
|
|
|
|
|||||||
| Total |
1,229,437 | $ | 10.19 | 3,056,957 | ||||||||
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| (1) | Our board of directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and Incentive Plan. |
| (2) | Our 2012 Long-Term Incentive Plan was approved by our board of directors in December 2011 and took effect on January 1, 2012. The 2012 Long-Term Incentive Plan was also approved by our shareholders at the Annual Meeting of Shareholders on June 7, 2012. For a description of our 2012 Long-Term Incentive Plan, see “Note 8 – Stock-Based Compensation” to the consolidated financial statements in this Annual Report on Form 10-K. |
Share Performance Graph
The following graph compares the cumulative return on a $100 investment in our common stock from February 2, 2012, the date our common stock began trading on the NYSE, through December 31, 2012, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, as amended (the “Exchange Act”), whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance.
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Comparison of Cumulative Total Return Among
Matador Resources Company, the Russell 2000 Index
and the Russell 2000 Energy Index
| Item 6. | Selected Financial Data. |
You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and related notes thereto included elsewhere in this Annual Report on Form 10-K. The financial information included in this Annual Report on Form 10-K may not be indicative of our future results of operations, financial position or cash flows.
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The following selected financial information is summarized from our results of operations for the five-year period ended December 31, 2012 and selected consolidated balance sheet data at December 31, 2012, 2011, 2010, 2009 and 2008 and should be read in conjunction with the consolidated financial statements for the years ended December 31, 2012, 2011 and 2010 included herewith.
| Year Ended December 31, | ||||||||||||||||||||
| 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||
| (In thousands, except per share data) | ||||||||||||||||||||
| Statement of operations data: | ||||||||||||||||||||
| Revenues: |
||||||||||||||||||||
| Oil and natural gas revenues |
$ | 155,998 | $ | 67,000 | $ | 34,042 | $ | 19,039 | $ | 30,645 | ||||||||||
| Realized gain (loss) on derivatives |
13,960 | 7,106 | 5,299 | 7,625 | (1,326 | ) | ||||||||||||||
| Unrealized (loss) gain on derivatives |
(4,802 | ) | 5,138 | 3,139 | (2,375 | ) | 3,592 | |||||||||||||
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| Total revenues |
165,156 | 79,244 | 42,480 | 24,289 | 32,911 | |||||||||||||||
| Expenses: |
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| Production taxes and marketing |
11,672 | 6,278 | 1,982 | 1,077 | 1,639 | |||||||||||||||
| Lease operating |
28,184 | 7,244 | 5,284 | 4,725 | 4,667 | |||||||||||||||
| Depletion, depreciation and amortization |
80,454 | 31,754 | 15,596 | 10,743 | 12,127 | |||||||||||||||
| Accretion of asset retirement obligations |
256 | 209 | 155 | 137 | 92 | |||||||||||||||
| Full-cost ceiling impairment |
63,475 | 35,673 | – | 25,244 | 22,195 | |||||||||||||||
| General and administrative |
14,543 | 13,394 | 9,702 | 7,115 | 8,252 | |||||||||||||||
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| Total expenses |
198,584 | 94,552 | 32,719 | 49,041 | 48,972 | |||||||||||||||
| Operating (loss) income |
(33,428 | ) | (15,308 | ) | 9,761 | (24,752 | ) | (16,061 | ) | |||||||||||
| Other income (expense): |
||||||||||||||||||||
| Net (loss) gain on asset sales and inventory impairment |
(485 | ) | (154 | ) | (224 | ) | (379 | ) | 136,978 | |||||||||||
| Interest expense |
(1,002 | ) | (683 | ) | (3 | ) | – | – | ||||||||||||
| Interest and other income |
224 | 315 | 364 | 781 | 2,984 | |||||||||||||||
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| Total other (expense) income |
(1,263 | ) | (522 | ) | 137 | 402 | 139,962 | |||||||||||||
| Net (loss) income |
$ | (33,261 | ) | $ | (10,309 | ) | $ | 6,377 | $ | (14,425 | ) | $ | 103,878 | |||||||
| Earnings (loss) per common share |
||||||||||||||||||||
| Basic |
||||||||||||||||||||
| Class A |
$ | (0.62 | ) | $ | (0.25 | ) | $ | 0.15 | $ | (0.37 | ) | $ | 2.50 | |||||||
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| Class B |
$ | (0.35 | ) | $ | 0.02 | $ | 0.42 | $ | (0.10 | ) | $ | 2.77 | ||||||||
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| Diluted |
||||||||||||||||||||
| Class A |
$ | (0.62 | ) | $ | (0.25 | ) | $ | 0.15 | $ | (0.37 | ) | $ | 2.46 | |||||||
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| Class B |
$ | (0.35 | ) | $ | 0.02 | $ | 0.42 | $ | (0.10 | ) | $ | 2.73 | ||||||||
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| Class B dividend declared, per share |
$ | 0.27 | $ | 0.27 | $ | 0.27 | $ | 0.27 | $ | 0.27 | ||||||||||
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| At December 31, | ||||||||||||||||||||
| 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Balance sheet data: |
||||||||||||||||||||
| Cash and cash equivalents |
$ | 2,095 | $ | 10,284 | $ | 21,060 | $ | 104,230 | $ | 150,768 | ||||||||||
| Certificates of deposit |
230 | 1,335 | 2,349 | 15,675 | 20,782 | |||||||||||||||
| Net property and equipment |
591,090 | 399,865 | 303,880 | 142,078 | 125,261 | |||||||||||||||
| Total assets |
632,029 | 439,469 | 346,382 | 277,400 | 314,539 | |||||||||||||||
| Current liabilities |
96,492 | 74,576 | 30,097 | 8,868 | 35,475 | |||||||||||||||
| Long-term liabilities |
156,433 | 93,378 | 34,408 | 4,211 | 2,059 | |||||||||||||||
| Total shareholders’ equity |
$ | 379,104 | $ | 271,515 | $ | 281,877 | $ | 264,321 | $ | 277,005 | ||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Other financial data: |
||||||||||||||||||||
| Net cash provided by operating activities |
$ | 124,228 | $ | 61,868 | $ | 27,273 | $ | 1,791 | $ | 25,851 | ||||||||||
| Net cash (used in) provided by investing activities |
(306,916 | ) | (160,088 | ) | (147,334 | ) | (49,415 | ) | 115,481 | |||||||||||
| Oil and natural gas properties capital expenditures |
(300,689 | ) | (156,431 | ) | (159,050 | ) | (54,244 | ) | (104,119 | ) | ||||||||||
| Expenditures for other property and equipment |
(7,332 | ) | (4,671 | ) | (1,610 | ) | (307 | ) | (3,012 | ) | ||||||||||
| Net cash provided by financing activities |
174,499 | 87,444 | 36,891 | 1,086 | 419 | |||||||||||||||
| Adjusted EBITDA(1) |
$ | 115,923 | $ | 49,911 | $ | 23,635 | $ | 15,184 | $ | 18,411 | ||||||||||
| (1) | Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Non-GAAP Financial Measures” below. |
Non-GAAP Financial Measures
We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, including stock option and grant expense and restricted stock and restricted stock units expense and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.
Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA, because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired.
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively.
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| Year Ended December 31, | ||||||||||||||||||||
| 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Unaudited Adjusted EBITDA reconciliation to Net Income (Loss): |
||||||||||||||||||||
| Net (loss) income |
$ | (33,261 | ) | $ | (10,309 | ) | $ | 6,377 | $ | (14,425 | ) | $ | 103,878 | |||||||
| Interest expense |
1,002 | 683 | 3 | – | – | |||||||||||||||
| Total income tax (benefit) provision |
(1,430 | ) | (5,521 | ) | 3,521 | (9,925 | ) | 20,023 | ||||||||||||
| Depletion, depreciation and amortization |
80,454 | 31,754 | 15,596 | 10,743 | 12,127 | |||||||||||||||
| Accretion of asset retirement obligations |
256 | 209 | 155 | 137 | 92 | |||||||||||||||
| Full-cost ceiling impairment |
63,475 | 35,673 | – | 25,244 | 22,195 | |||||||||||||||
| Unrealized loss (gain) on derivatives |
4,802 | (5,138 | ) | (3,139 | ) | 2,375 | (3,592 | ) | ||||||||||||
| Stock option and grant expense |
(589 | ) | 2,362 | 824 | 622 | 605 | ||||||||||||||
| Restricted stock and restricted stock units expense |
729 | 44 | 74 | 34 | 60 | |||||||||||||||
| Net loss (gain) on asset sales and inventory impairment |
485 | 154 | 224 | 379 | (136,977 | ) | ||||||||||||||
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| Adjusted EBITDA |
$ | 115,923 | $ | 49,911 | $ | 23,635 | $ | 15,184 | $ | 18,411 | ||||||||||
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| Year Ended December 31, | ||||||||||||||||||||
| 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: |
||||||||||||||||||||
| Net cash provided by operating activities |
$ | 124,228 | $ | 61,868 | $ | 27,273 | $ | 1,791 | $ | 25,851 | ||||||||||
| Net change in operating assets and liabilities |
(9,307 | ) | (12,594 | ) | (2,230 | ) | 15,717 | (17,888 | ) | |||||||||||
| Interest expense |
1,002 | 683 | 3 | – | – | |||||||||||||||
| Current income tax (benefit) provision |
– | (46 | ) | (1,411 | ) | (2,324 | ) | 10,448 | ||||||||||||
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| Adjusted EBITDA |
$ | 115,923 | $ | 49,911 | $ | 23,635 | $ | 15,184 | $ | 18,411 | ||||||||||
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| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability of acquisitions, availability under our Credit Agreement borrowing base, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.”
Overview
We are an independent energy company founded in July 2003 and engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Our current operations are focused primarily on the oil and liquids rich portion of the Eagle Ford shale play in South Texas and in the Haynesville shale play in Northwest Louisiana. In 2012, more than 90% of our total capital expenditures of $334.6 million were directed to our operations in South Texas, primarily in the Eagle Ford shale, as we sought to transition to a more balanced commodity portfolio through the drilling of wells that were prospective for oil and liquids. For the year ended December 31, 2012, approximately 37% of our total production by volume (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) and 79% of our total oil and natural gas revenues were attributable to oil production, primarily from the Eagle Ford shale. In 2013, we expect that approximately 82% of our estimated capital expenditures of $310.0 million will be directed to increasing our oil production and oil reserves in South Texas, primarily in the Eagle Ford shale play. Although we did not drill any operated Haynesville shale natural gas wells during 2012, we directed approximately 3% of our capital expenditures to the Haynesville play in 2012 to participate in several non-operated wells. In addition to these primary operating areas, we have a growing acreage position in Southeast New Mexico and West Texas where we plan to drill three exploratory wells to test the Wolfcamp and Bone Spring plays during 2013. We also have a large exploratory leasehold position in Southwest Wyoming and adjacent areas in Utah and Idaho where we are testing the Meade Peak shale.
On February 2, 2012, our common stock began trading on the NYSE under the symbol “MTDR.” On February 7, 2012, we completed our initial public offering of 14,883,334 shares of common stock at $12.00 per share (the “Initial Public Offering”). We sold 12,209,167 shares of common stock in this offering and certain selling shareholders sold 2,674,167 shares of common stock, including shares sold pursuant to the partial exercise of the underwriters’ over-allotment option on March 7, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock.
Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy.
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Commodity price volatility, in particular, is a significant risk factor for us. Commodity prices are affected by changes in market supply and demand, which is impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. Prices for oil, natural gas and natural gas liquids will affect the cash flows available to us for capital expenditures and our ability to borrow and raise additional capital. Declines in oil, natural gas or natural gas liquids prices would not only reduce our revenues, but could also reduce the amount of oil, natural gas and/or natural gas liquids that we can produce economically, and as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves.
During 2012, natural gas prices declined to their lowest levels in many years, ranging from a low of approximately $1.91 per MMBtu in mid-April to a high of approximately $3.90 per MMBtu in late November, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices had declined again since late November 2012, before increasing to $3.81 per MMBtu at March 14, 2013, based upon the NYMEX Henry Hub natural gas futures contract for the earliest delivery date. We would not expect to drill any operated natural gas wells in either our Haynesville or Cotton Valley properties until natural gas prices improve further from these levels or unless the costs to drill and complete these wells decline further from their recent levels or new technologies are developed that increase expected recoveries. See “Risk Factors — Our Identified Drilling Locations Are Scheduled out over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.”
In 2012, our operations were primarily focused on the exploration and development of our Eagle Ford shale properties in South Texas, as we continued to execute our strategy to significantly increase our oil production and oil reserves during 2012. During the year ended December 31, 2012, we completed and began producing oil and natural gas from 28 gross/24.5 net Eagle Ford shale wells, including 25 gross/23.7 net operated and 3 gross/0.8 net non-operated Eagle Ford shale wells. We also completed and began producing oil and natural gas from 2 gross/2.0 net wells in the upper Austin Chalk and the lower Austin Chalk/upper Eagle Ford, or “Chalkleford,” intervals in 2012. In addition, during 2012, we completed and began producing natural gas from 28 gross/1.1 net non-operated Haynesville shale wells. We also re-entered and drilled a horizontal lateral from the previously suspended Crawford Federal #1 vertical well in Southwest Wyoming; we plan to complete this well in the third quarter of 2013.
We had two contracted drilling rigs operating in South Texas throughout 2012 (except for a brief period near the end of the second quarter when we added a third rig to execute a two-well contract), and almost all of our operated drilling and completion activities were focused on the Eagle Ford shale. We did not drill any operated wells in the Haynesville shale play in Northwest Louisiana during 2012 as a result of the decline in natural gas prices compared to recent years. At March 14, 2013, we continued to have two contracted drilling rigs operating in South Texas: one in LaSalle County and one in DeWitt County.
Our average daily production for the year ended December 31, 2012 was approximately 9,000 BOE per day, including 3,317 Bbl of oil per day and 34.1 MMcf of natural gas per day, as compared to 7,049 BOE per day, including 422 Bbl of oil per day and 39.8 MMcf of natural gas per day for the year ended December 31, 2011. Our total oil production increased almost eight-fold to just over 1.2 million Bbl of oil during the year ended December 31, 2012, from approximately 154,000 Bbl of oil during the year ended December 31, 2011. This increased oil production is a direct result of our drilling operations in the Eagle Ford shale. Oil production comprised approximately 37% of our total production for the year ended December 31, 2012, as compared to only 6% of our total production for the year ended December 31, 2011.
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During the three months ended December 31, 2012 specifically, our average daily production was 10,385 BOE per day, including 4,630 Bbl of oil per day and 34.5 MMcf of natural gas per day. This was an increase of almost 50% compared to our average daily production for the three months ended December 31, 2011 of 6,953 BOE per day, including 448 Bbl of oil per day and 39.0 MMcf of natural gas per day. Our total oil production increased ten-fold to 426,000 Bbl of oil during the three months ended December 31, 2012, as compared to total oil production of 41,000 Bbl of oil during the three months ended December 31, 2011. Our average daily production for the fourth quarter of 2012 was a sequential increase of 18% from the average daily production of 8,838 BOE per day, including 3,291 Bbl of oil per day and 33.3 MMcf of natural gas per day, achieved during the third quarter of 2012. For the three months ended December 31, 2012, our oil production grew 41% sequentially, as compared to the three months ended September 30, 2012.
At December 31, 2012, our estimated total proved reserves were 23.8 million BOE, including 10.5 million Bbl of oil and 80.0 Bcf of natural gas (13.3 million BOE). At December 31, 2012, 58% of our total proved reserves were proved developed reserves compared to 34% at December 31, 2011. At December 31, 2012, 44% of our total proved reserves were oil and 56% of our total proved reserves were natural gas, as compared to 12% oil and 88% natural gas at December 31, 2011. Our proved oil reserves grew 176% (almost three-fold) from 3.8 million Bbl at December 31, 2011 to 10.5 million Bbl at December 31, 2012. This growth in oil reserves was attributable to our drilling program in the Eagle Ford shale during 2012. Our proved natural gas reserves declined to 80.0 Bcf at December 31, 2012 from 170.4 Bcf at December 31, 2011. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012, and these proved undeveloped reserves were likewise not included in our estimated total proved reserves at December 31, 2012. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries.
The PV-10 of our estimated total proved reserves was $423.2 million at December 31, 2012 compared to a PV-10 of $248.7 million at December 31, 2011, an increase of 70% despite lower commodity prices used to estimate PV-10 in 2012 compared to 2011. The PV-10 at December 31, 2012 was determined using the 12-month unweighted average of first-day-of-the-month oil and natural gas prices for 2012 of $91.21 per barrel and $2.757 per MMBtu, respectively, adjusted by lease for quality, energy content, regional price differentials and other expenses as needed compared to average oil and natural gas prices of $92.71 per barrel and $4.118 per MMBtu, respectively, adjusted as further described above, used to determine PV-10 at December 31, 2011. The Standardized Measure of estimated future net cash flows from our total proved reserves, including estimated future income tax expenses, was $394.6 million at December 31, 2012 and $215.5 million at December 31, 2011, respectively. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business — Estimated Proved Reserves.”
For the year ended December 31, 2012, our oil and natural gas revenues were approximately $156.0 million, or an increase of about 133%, as compared to approximately $67.0 million for the year ended December 31, 2011. Our oil revenues increased over eight-fold to approximately $123.7 million for the year ended December 31, 2012, as compared to $14.5 million for the year ended December 31, 2011. Our total realized revenues for 2012, including realized gain on derivatives, were approximately $170.0 million, or an increase of about 129%, as compared to $74.1 million for 2011. For the year ended December 31, 2012, our Adjusted EBITDA was approximately $115.9 million, or an increase of about 132%, as compared to an
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Adjusted EBITDA of approximately $49.9 million for the year ended December 31, 2011. For a reconciliation of Adjusted EBITDA to net income (loss) and net cash provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.”
We currently intend to allocate approximately 82% of our 2013 capital expenditure budget to the exploration, development and acquisition of additional interests in South Texas, primarily in the Eagle Ford shale play. We also plan to allocate about 16% of our 2013 capital expenditure budget to the exploration and acquisition of additional interests in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. As a result of these anticipated capital expenditures in South Texas and in Southeast New Mexico and West Texas, we plan to dedicate approximately 98% of our 2013 anticipated capital expenditure budget to opportunities prospective for oil and liquids production. While we have budgeted capital expenditures of approximately $310.0 million for 2013, the aggregate amount we will expend may fluctuate materially based on market conditions, the actual costs to drill scheduled wells, our drilling results and our ability to obtain additional capital. Since approximately 84% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2014, 79% of our Wolfcamp and Bone Spring acreage was either held by production or not burdened by lease expirations before 2014 and almost all of our Haynesville acreage was held by production at December 31, 2012, we possess the financial flexibility to allocate our capital when and where we believe it is economical and justified.
As we continue to explore and develop our leasehold positions in the Eagle Ford shale in South Texas and as we begin to explore and develop our leasehold positions in the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas, we may face various challenges in establishing operations in new areas, including securing the necessary services to drill and complete wells and securing the necessary facilities to gather, process, transport and market the oil and natural gas that we produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure on our leases throughout the area. We believe that we have successfully secured the necessary drilling and completion services for our current Eagle Ford operations. We did not experience difficulties in securing completion, and in particular hydraulic fracturing, services for our newly drilled wells during the year ended December 31, 2012, although we experienced these problems at various times during 2011 in South Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling and completion services and reducing drilling and completion costs will be essential to the successful development and profitability of the Eagle Ford shale play, as well as the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.”
We did experience temporary pipeline and natural gas processing interruptions from time to time during the year ended December 31, 2012 associated with natural gas production from our Eagle Ford shale wells. To alleviate most of the interruptions and processing capacity constraints we experienced during 2012, effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. No assurance can be made that this agreement will alleviate these issues completely, and if we were required to shut in our
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production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. We may experience similar interruptions and processing capacity constraints as we begin to explore and develop our Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas in 2013. See “Risk Factors — The Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.”
Revenues
Our revenues are derived primarily from the sale of oil, natural gas and natural gas liquids production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in oil, natural gas or natural gas liquids prices.
Realized gain on derivatives. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices. This revenue item includes the net realized cash gains and losses associated with the settlement of these derivative financial instruments for a given reporting period.
Unrealized gain (loss) on derivatives. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices. This revenue item recognizes the non-cash change in the fair value of our open derivative contracts between reporting periods.
The following table summarizes our revenues and production data for the periods indicated:
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Operating Results: |
||||||||||||
| Revenues (in thousands): |
||||||||||||
| Oil |
$ | 123,654 | $ | 14,457 | $ | 2,507 | ||||||
| Natural gas |
32,344 | 52,543 | 31,535 | |||||||||
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|||||||
| Total oil and natural gas revenues |
155,998 | 67,000 | 34,042 | |||||||||
| Realized gain on derivatives |
13,960 | 7,106 | 5,299 | |||||||||
| Unrealized (loss) gain on derivatives |
(4,802 | ) | 5,138 | 3,139 | ||||||||
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| Total revenues |
$ | 165,156 | $ | 79,244 | $ | 42,480 | ||||||
| Net Production Volumes: |
||||||||||||
| Oil (MBbl) |
1,214 | 154 | 33 | |||||||||
| Natural gas (Bcf) |
12.5 | 14.5 | 8.4 | |||||||||
| Total oil equivalent (MBOE)(1) |
3,294 | 2,573 | 1,433 | |||||||||
| Average daily production (BOE/d)(1) |
9,000 | 7,049 | 3,926 | |||||||||
| Average Sales Prices: |
||||||||||||
| Oil, with realized derivatives (per Bbl) |
$ | 103.55 | $ | 93.80 | $ | 76.39 | ||||||
| Oil, without realized derivatives (per Bbl) |
$ | 101.86 | $ | 93.80 | $ | 76.39 | ||||||
| Natural gas, with realized derivatives (per Mcf) |
$ | 3.55 | $ | 4.11 | $ | 4.38 | ||||||
| Natural gas, without realized derivatives (per Mcf) |
$ | 2.59 | $ | 3.62 | $ | 3.75 | ||||||
| (1) | Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. |
Year Ended December 31, 2012 as Compared to Year Ended December 31, 2011
Oil and natural gas revenues. Our oil and natural gas revenues increased by $89.0 million to $156.0 million, or an increase of about 133%, for the year ended December 31, 2012, as compared to the year ended
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December 31, 2011. This increase in oil and natural gas revenues reflects an increase in our oil revenues of $109.2 million and a decrease in our natural gas revenues of $20.2 million for the year ended December 31, 2012, as compared to the year ended December 31, 2011. Our oil revenues increased over eight-fold to $123.7 million for the year ended December 31, 2012, as compared to $14.5 million for the year ended December 31, 2011. Our oil production also increased almost eight-fold to just over 1.2 million Bbl of oil, or about 3,317 Bbl of oil per day, from approximately 154,000 Bbl of oil, or about 422 Bbl of oil per day, during the comparable periods due to our drilling operations in the Eagle Ford shale. A portion of this increase in oil revenue also reflects a higher weighted average oil price of $101.86 per Bbl realized during the year ended December 31, 2012, as compared to a weighted average oil price of $93.80 per Bbl realized during the year ended December 31, 2011. The decrease in our natural gas revenues reflects a decline in our natural gas production by about 14% to approximately 12.5 Bcf for the year ended December 31, 2012, as compared to approximately 14.5 Bcf for the year ended December 31, 2011. This decline in natural gas production is due to several factors, including (i) the natural decline in natural gas production primarily from our existing Haynesville shale and Cotton Valley wells in Northwest Louisiana and East Texas, coupled with our decision not to drill any operated Haynesville shale or Cotton Valley wells in 2012, (ii) the voluntary curtailment by the operators of natural gas production from some of our non-operated Haynesville shale wells in Northwest Louisiana at various times during 2012 and (iii) delays in natural gas production from our newly completed Eagle Ford shale wells in South Texas as a result of natural gas pipeline and production facility constraints. This decrease in natural gas revenues also results from a significantly lower weighted average natural gas price of $2.59 per Mcf realized during the year ended December 31, 2012, as compared to a weighted average natural gas price of $3.62 per Mcf realized during the year ended December 31, 2011.
Realized gain on derivatives. Our realized gain on derivatives increased by approximately $6.9 million to $14.0 million for the year ended December 31, 2012 from $7.1 million for the year ended December 31, 2011. For the year ended December 31, 2012, we realized a gain of approximately $11.9 million on our open natural gas derivative contracts and a gain of approximately $2.1 million on our open oil derivative contracts. As a result of declining natural gas prices between the comparable periods, we realized an average gain of approximately $1.45 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2012, as compared to $1.03 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2011. Our total natural gas volumes hedged for the year ended December 31, 2012 were also approximately 19% higher than the total natural gas volumes hedged for the year ended December 31, 2011. We realized an average gain of $1.74 per Bbl hedged on all of our open oil contracts during the year ended December 31, 2012. We had no open oil or NGL derivative contracts during the year ended December 31, 2011.
Unrealized gain (loss) on derivatives. Our unrealized loss on derivatives was approximately $4.8 million for the year ended December 31, 2012, as compared to an unrealized gain of $5.1 million for the year ended December 31, 2011. During the period from December 31, 2011 to December 31, 2012, the net fair value of our open oil, natural gas and natural gas liquids derivative contracts decreased from approximately $9.3 million to approximately $4.5 million, resulting in an unrealized loss on derivatives of approximately $4.8 million for the year ended December 31, 2012. During the year ended December 31, 2012, the net fair value of our open natural gas costless collar contracts decreased by $8.7 million due primarily to the gains realized on these contracts during 2012. The net fair value of our open oil derivative contracts increased $3.7 million during the year ended December 31, 2012 as a result of a decrease in oil prices at December 31, 2012 compared to December 31, 2011 and also as a result of two additional oil derivatives contracts we entered into during 2012. During the year ended December 31, 2012, we also entered into various NGL swap contracts which had a net fair value of approximately $0.2 million at December 31, 2012. We had no open NGL swap contracts during the year ended December 31, 2011.
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Year Ended December 31, 2011 as Compared to Year Ended December 31, 2010
Oil and natural gas revenues. Our oil and natural gas revenues increased by $33.0 million to $67.0 million, or an increase of about 97%, for the year ended December 31, 2011, as compared to the year ended December 31, 2010. This increase in oil and natural gas revenues corresponds with an increase of about 79% in our oil and natural gas production to 2.6 million BOE for the year ended December 31, 2011 from 1.4 million BOE for the year ended December 31, 2010. This increased production was almost entirely due to drilling operations in the Eagle Ford and Haynesville shales. A portion of the increase in oil and natural gas revenues reflects the approximate five-fold increase in our oil production for the year ended December 31, 2011 as compared to the year ended December 31, 2010, as well as a higher average oil price of $93.80 per Bbl realized during 2011, as compared to an average oil price of $76.39 per Bbl realized during 2010.
Realized gain on derivatives. Our realized gain on derivatives increased by approximately $1.8 million to $7.1 million for the year ended December 31, 2011 from $5.3 million for the year ended December 31, 2010. The realized gain from our open natural gas costless collar contracts increased primarily as a result of the decline in natural gas prices during the comparable periods. We realized approximately $1.03 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2011 as compared to $0.89 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2010. Our total natural gas volumes hedged for the year ended December 31, 2011 were also approximately 16% higher than the total natural gas volumes hedged for 2010.
Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $5.1 million for the year ended December 31, 2011, as compared to an unrealized gain of $3.1 million for the year ended December 31, 2010. During the period from December 31, 2010 to December 31, 2011, the net fair value of our open natural gas costless collar contracts increased by approximately $5.7 million, due primarily to a decrease in natural gas prices during 2011, as compared to 2010, as well as to an increase in the total number of our open natural gas costless collar contracts at December 31, 2011, as compared to December 31, 2010. The net fair value of our open oil derivative contracts decreased by approximately $0.6 million during the year ended December 31, 2011.
Expenses
Production taxes and marketing. Production taxes are paid on produced oil, natural gas and natural gas liquids based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We attempt to take advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay tend to correlate to the changes in our oil and natural gas revenues. Marketing expenses are fees charged by the purchasers of the oil and natural gas we produce and sell and principally include compression, processing, transportation and marketing fees.
Lease operating expenses. Lease operating expenses are the daily costs incurred to produce oil, natural gas and natural gas liquids, as well as the daily costs incurred to maintain our producing properties. Such costs also include field personnel costs, utilities, chemical additives, salt water disposal, maintenance, repairs and occasional workover expenses related to our oil and natural gas properties.
Depletion, depreciation and amortization. Depletion, depreciation and amortization includes the systematic expensing of the capitalized costs incurred in the acquisition, exploration and development of oil and natural gas. We use the full-cost method of accounting and, accordingly, we capitalize all costs associated with the acquisition, exploration and development of oil and natural gas properties, including unproved and unevaluated property costs. Internal costs are capitalized only to the extent they are directly
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related to acquisition, exploration or development activities and do not include any costs related to production, selling or general corporate administrative activities. Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved oil and natural gas reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion, depreciation and amortization.
Accretion of asset retirement obligations. Asset retirement obligations relate to the future costs associated with plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. We recognize the fair value of an asset retirement obligation in the period it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the balance sheet. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in our consolidated statements of operations.
Full-cost ceiling impairment. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center ceiling, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. The cost center ceiling is defined as the sum of (a) the present value discounted at 10 percent of future net revenues of proved oil and natural gas reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) income tax effects related to the properties involved. Future net revenues from proved non-producing and proved undeveloped reserves are reduced by the estimated costs of developing these reserves. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes.
General and administrative expenses. General and administrative expenses include, but are not limited to, compensation and benefits for our employees, costs of renting and maintaining our headquarters, office service contracts, board of directors fees, franchise taxes, stock-based compensation expense and accounting, legal and other professional fees.
Other Income (Expense)
Net gain (loss) on asset sales and inventory impairment. This other income (expense) item includes the net gain or loss we experience on infrequent asset sales or impairment charges associated with certain equipment held in inventory. This item also includes infrequent sales of oil and natural gas properties that we consider to be extraordinary when considered in relation to the normal course of our business.
Interest expense. Interest expense includes interest paid to our lenders as a result of borrowings under our revolving Credit Agreement. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under the Credit Agreement, and as a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. In addition, we include any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees), commitment or facility fees and annual agency fees as interest expense and in our interest rate calculations and related disclosures.
Interest and other income. Interest income includes interest earned periodically on the cash and cash equivalents we hold in money market accounts composed of U.S. Treasury securities offering daily liquidity and the interest earned periodically on our certificates of deposit. Other income includes income we receive for providing salt water disposal and natural gas transportation services to other working interest participants in wells that we operate.
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Total income tax provision (benefit). Total income tax provision (benefit) includes the net current and deferred portions of our estimated income tax liabilities. We file a U.S. federal income tax return and state tax returns in those states where we conduct oil and natural gas operations. The current portion of our income tax provision (benefit) reflects actual income tax payments made or refunds received by us as a result of filing these income tax returns. The deferred portion of our income tax provision is the result of temporary timing differences between the financial statement carrying values and the tax bases of our assets and liabilities.
The following table summarizes our operating expenses and other income (expense) for the periods indicated. As a result of the increasing significance of our oil production, all per unit expenses are presented as per BOE as compared to per Mcfe in prior reporting periods.
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| (In thousands, except expenses per BOE) | ||||||||||||
| Expenses: |
||||||||||||
| Production taxes and marketing |
$ | 11,672 | $ | 6,278 | $ | 1,982 | ||||||
| Lease operating |
28,184 | 7,244 | 5,284 | |||||||||
| Depletion, depreciation and amortization |
80,454 | 31,754 | 15,596 | |||||||||
| Accretion of asset retirement obligations |
256 | 209 | 155 | |||||||||
| Full-cost ceiling impairment |
63,475 | 35,673 | – | |||||||||
| General and administrative |
14,543 | 13,394 | 9,702 | |||||||||
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| Total expenses |
198,584 | 94,552 | 32,719 | |||||||||
| Operating (loss) income |
(33,428 | ) | (15,308 | ) | 9,761 | |||||||
| Other (expense) income: |
||||||||||||
| Net loss on asset sales and inventory impairment |
(485 | ) | (154 | ) | (224 | ) | ||||||
| Interest expense |
(1,002 | ) | (683 | ) | (3 | ) | ||||||
| Interest and other income |
224 | 315 | 364 | |||||||||
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| Total other (expense) income |
(1,263 | ) | (522 | ) | 137 | |||||||
| (Loss) income before income taxes |
(34,691 | ) | (15,830 | ) | 9,898 | |||||||
| Total income tax (benefit) provision |
(1,430 | ) | (5,521 | ) | 3,521 | |||||||
| Net (loss) income |
$ | (33,261 | ) | $ | (10,309 | ) | $ | 6,377 | ||||
| Expenses per BOE: |
||||||||||||
| Production taxes and marketing |
$ | 3.54 | $ | 2.44 | $ | 1.38 | ||||||
| Lease operating |
$ | 8.56 | $ | 2.82 | $ | 3.69 | ||||||
| Depletion, depreciation and amortization |
$ | 24.43 | $ | 12.34 | $ | 10.89 | ||||||
| General and administrative |
$ | 4.42 | $ | 5.21 | $ | 6.77 | ||||||
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Production taxes and marketing. Our production taxes and marketing expenses increased by $5.4 million to $11.7 million, or an increase of approximately 86%, for the year ended December 31, 2012, as compared to the year ended December 31, 2011. The increase in our production taxes and marketing expenses primarily reflects the increase in our total oil and natural gas revenues by 133% for the year ended December 31, 2012, as compared to the year ended December 31, 2011. The majority of this increase was attributable to increased production taxes associated with the large increase in our oil production during 2012 resulting from our drilling operations in the Eagle Ford shale in South Texas. Our total production was comprised of approximately 37% oil and 63% natural gas during the year ended December 31, 2012, as compared to approximately 6% oil and 94% natural gas during the year ended December 31, 2011. On a unit-of-production basis, our production taxes and marketing expenses increased by 45% to $3.54 per BOE for the year ended December 31, 2012, as compared to $2.44 per BOE for the year ended December 31, 2011.
Lease operating expenses. Our lease operating expenses increased by $20.9 million to $28.2 million, or an increase of about 289%, for the year ended December 31, 2012, as compared to the year ended
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December 31, 2011. Our total oil and natural gas production increased by about 28% to approximately 3.3 million BOE for the year ended December 31, 2012 from approximately 2.6 million BOE for the year ended December 31, 2011, but our oil production increased almost eight-fold to just over 1.2 million Bbl from approximately 154,000 Bbl during the respective period. The increase in lease operating expenses was primarily attributable to the increased costs associated with operating oil production resulting from drilling operations in the Eagle Ford shale in 2012, as compared to the lower lease operating expenses associated with operating primarily dry natural gas production from the Haynesville and Cotton Valley in 2011. In addition, oil production comprised 37% of our total production during the year ended December 31, 2012, as compared to only 6% for the year ended December 31, 2011, resulting in higher overall lease operating expenses during the year ended December 31, 2012. During the year ended December 31, 2012, we completed and initiated oil and natural gas production from 28 gross/24.5 net wells in the Eagle Ford shale (plus 2 gross/2.0 net Austin Chalk/“Chalkleford” wells), most of which were on properties where new production facilities were being installed or natural gas pipelines were awaiting completion. While these new facilities were being installed and tested, much of the oil and natural gas was produced through rental equipment monitored by 24-hour contract personnel, resulting in higher operating costs from these properties during the year ended December 31, 2012 than we anticipate going forward now that the permanent production facilities and natural gas pipeline connections on most of these properties are complete. Approximately one-third of our total lease operating expenses in 2012 were attributable to these extended flowback operations. As we continue to drill on new properties in the Eagle Ford shale and in Southeast New Mexico and West Texas throughout 2013, however, we also expect to produce new wells on these properties through similar rental test equipment until more permanent facilities can be constructed and installed. Our lease operating expenses per unit of production increased 204% to $8.56 per BOE for the year ended December 31, 2012, as compared to $2.82 per BOE for the year ended December 31, 2011.
Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $48.7 million to $80.5 million, or an increase of about 153%, for the year ended December 31, 2012, as compared to the year ended December 31, 2011. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased to $24.43 per BOE for the year ended December 31, 2012, as compared to $12.34 per BOE for the year ended December 31, 2011. This increase in our depletion, depreciation and amortization expenses was primarily attributable to the decrease in our total proved oil and natural gas reserves to 23.8 million BOE at December 31, 2012, as compared to 32.2 million BOE at December 31, 2011. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012, and these proved undeveloped reserves were likewise not included in our total proved reserves at December 31, 2012. The increase in depletion, depreciation and amortization expenses was also partially attributable to the increase of approximately 28% in our oil and natural gas production to approximately 3.3 million BOE for the year ended December 31, 2012, as compared to approximately 2.6 million BOE for the year ended December 31, 2011, as well as to the higher drilling and completion costs on a per BOE basis associated with oil reserves added in the Eagle Ford shale in South Texas as compared with our Haynesville shale natural gas assets in Northwest Louisiana.
Accretion of asset retirement obligations. Our accretion of asset retirement obligations expenses increased by approximately $47,000 to $256,000, or an increase of about 23%, for the year ended December 31, 2012, as compared to the year ended December 31, 2011. The increase in the accretion of our asset retirement obligations was due primarily to the addition of new wells through our drilling of operated wells and our participation in the drilling of non-operated wells, although, on the whole, this item is an insignificant component of our overall expenses.
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Full-cost ceiling impairment. At June 30, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $21.3 million. As a result, we recorded an impairment charge of $33.2 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $11.9 million. At September 30, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $2.3 million. As a result, we recorded an impairment charge of $3.6 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $1.3 million. At December 31, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $17.3 million. As a result, we recorded an impairment charge of $26.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $9.4 million. These full-cost ceiling impairment charges in 2012 were primarily attributable to declining natural gas prices throughout much of the year. As a result of substantially lower natural gas prices in 2012, we had downward revisions of our natural gas reserves totaling 103.4 Bcf (17.2 million BOE), including the removal of 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012. These impairment charges are reflected in our operating expenses for the year ended December 31, 2012. During the first quarter of 2011, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairment charge of $35.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $12.7 million, which is reflected in our operating expenses for the year ended December 31, 2011.
General and administrative. Our general and administrative expenses increased by $1.1 million to $14.5 million, or an increase of about 9%, for the year ended December 31, 2012, as compared to the year ended December 31, 2011. Our general and administrative expenses decreased by 15% on a unit-of-production basis to $4.42 per BOE for the year ended December 31, 2012, as compared to $5.21 per BOE for the year ended December 31, 2011. The increase in our general and administrative expenses was attributable to increased compensation, accounting, legal and other administrative expenses, most of which was associated with becoming a public company in February 2012, partially offset by a net decrease in non-cash stock-based compensation expense of $2.3 million for the year ended December 31, 2012, as compared to the year ended December 31, 2011.
Net gain (loss) on asset sales and inventory impairment. We incurred a loss on asset sales and inventory impairment of approximately $485,000 for the year ended December 31, 2012, as compared to a loss of $154,000 for the year ended December 31, 2011. The loss during 2012 was primarily related to the impairment of certain equipment held in inventory, mostly consisting of drilling rig parts. During the year ended December 31, 2011, the loss was primarily related to the sale of pipe and other equipment and the impairment of certain equipment held in inventory, mostly consisting of drilling rig parts.
Interest expense. For the year ended December 31, 2012, we incurred total interest expense of approximately $2.6 million. We capitalized approximately $1.6 million of our interest expense on certain qualifying projects for the year ended December 31, 2012 and expensed the remaining $1.0 million to operations. In February 2012, we repaid our borrowings then outstanding of $123.0 million under our Credit Agreement using a portion of the net proceeds received from our Initial Public Offering. From March 1 through December 31, 2012, we borrowed $150.0 million under our Credit Agreement to finance a portion of our working capital requirements and capital expenditures. Our total outstanding borrowings at December 31, 2012 were $150.0 million, and the effective interest rate on the borrowings was approximately 3.3%. At December 31, 2011, we had total borrowings of $113.0 million outstanding under
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our Credit Agreement, and we incurred total interest expense of approximately $2.0 million. We capitalized approximately $1.3 million of our interest expense on certain qualifying projects for the year ended December 31, 2011 and expensed the remaining $0.7 million to operations.
Interest and other income. Our interest and other income decreased by approximately $0.1 million to approximately $0.2 million, or a decrease of about 29%, for the year ended December 31, 2012, as compared to the year ended December 31, 2011. The decrease in our interest and other income was due primarily to a decrease in the natural gas transportation income received from third parties during the year ended December 31, 2012, as compared to the year ended December 31, 2011. Our cash and certificates of deposit decreased to approximately $2.3 million at December 31, 2012 from approximately $11.6 million at December 31, 2011.
Total income tax provision (benefit). We recorded a total income tax benefit of approximately $1.4 million for the year ended December 31, 2012, as compared to a total income tax benefit of approximately $5.5 million for the year ended December 31, 2011. During the year ended December 31, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $40.9 million. We recorded an impairment charge of $63.5 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $22.6 million. The increase in our deferred tax assets as a result of the impairment charges recorded during the year ended December 31, 2012 caused our deferred tax assets to exceed our deferred tax liabilities, resulting in the establishment of a valuation allowance of $10.3 million due to uncertainties regarding the future realization of our deferred tax assets. As a result, we recorded an income tax benefit of $1.4 million for the year ended December 31, 2012. The total income tax benefit for the year ended December 31, 2011 reflected deferred income taxes almost entirely, with the exception of a state of Louisiana income tax refund of approximately $46,000 recorded during this period. We had a net loss for the years ended December 31, 2012 and 2011.
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
Production taxes and marketing. Our production taxes and marketing expenses increased by $4.3 million to $6.3 million, or an increase of approximately 217% for the year ended December 31, 2011, as compared to the year ended December 31, 2010. The increase in our production taxes and marketing expenses reflects the increases in both our oil and natural gas production and revenues by 79% and 97%, respectively, during the year ended December 31, 2011, as compared to the year ended December 31, 2010. The majority of this increase was due to higher marketing, transportation and compression charges on portions of our non-operated Haynesville shale production in 2011 as compared to 2010. Some of this increase was also due to Haynesville shale wells completed in 2011, several of which were turned to sales or produced their first significant production volumes during 2011. Although we or outside operators applied for exemptions from initial production taxes on these Haynesville shale wells, some of these wells had not been approved for production tax exemptions at December 31, 2011. Thus, we paid or accrued for the associated production taxes on these wells during the year ended December 31, 2011, although these production taxes were refunded to us in future periods as expected. We adjusted our production taxes and marketing expenses accordingly during the future periods when these production tax exemptions were approved. The remainder of the increase in production taxes and marketing expenses for the year ended December 31, 2011 was due to production taxes paid on production from our initial Eagle Ford shale wells in South Texas.
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Lease operating expenses. Our lease operating expenses increased by $2.0 million to $7.2 million, or an increase of about 37%, for the year ended December 31, 2011, as compared to the year ended December 31, 2010. During these respective periods, however, our oil and natural gas production increased 79% from 1.4 million BOE to 2.6 million BOE. As a result, our lease operating expenses per unit of production decreased by 23% to $2.82 per BOE for the year ended December 31, 2011, as compared to $3.69 per BOE for the year ended December 31, 2010. During the year ended December 31, 2011, both our total Haynesville shale production, as well as the percentage of our Haynesville production for which we were the operator, increased as compared to the year ended December 31, 2010. The per unit lease operating expenses associated with the Haynesville production were much less than those associated with our Cotton Valley natural gas production, primarily due to the greater salt water disposal costs associated with the Cotton Valley production and given the early stages of production then associated with many of these Haynesville wells.
Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $16.2 million to $31.8 million, or an increase of about 104%, for the year ended December 31, 2011, as compared to the year ended December 31, 2010. The increase in our depletion, depreciation and amortization expenses was due primarily to an increase of approximately 79% in our oil and natural gas production from 1.4 million BOE to 2.6 million BOE during the respective time periods. Our depletion, depreciation and amortization expenses on a unit-of-production basis increased to $12.34 per BOE for the year ended December 31, 2011, or an increase of about 14%, from $10.89 per BOE for the year ended December 31, 2010. This per unit increase reflected increases in drilling and completion costs for wells drilled to the Haynesville shale during 2011, as well as higher drilling and completion costs on a per BOE basis associated with oil reserves added in the Eagle Ford shale in South Texas.
Accretion of asset retirement obligations. Our accretion of asset retirement obligations expenses increased by approximately $54,000 to approximately $209,000, or an increase of about 35%, for the year ended December 31, 2011, as compared to the year ended December 31, 2010. The increase in the accretion of asset retirement obligations was due primarily to the addition of new wells through our drilling of operated wells and our participation in the drilling of non-operated wells, although, on the whole, this item is an insignificant component of our overall expenses.
Full-cost ceiling impairment. During the quarter ended March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairment charge of $35.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $12.7 million, which is reflected in our expenses for the year ended December 31, 2011. No impairment to the net carrying value of our oil and natural gas properties on the balance sheet resulting from the full-cost ceiling limitation was recorded for the year ended December 31, 2010.
General and administrative. Our general and administrative expenses increased by $3.7 million to $13.4 million, or an increase of about 38%, for the year ended December 31, 2011, as compared to the year ended December 31, 2010. The increase in our general and administrative expenses was due primarily to increased cash and non-cash compensation expenses and increased accounting expenses for the year ended December 31, 2011, as compared to the year ended December 31, 2010. We recorded approximately $2.4 million in non-cash compensation expense for the year ended December 31, 2011, as compared to approximately $0.9 million recorded for the year ended December 31, 2010. This increase was primarily due to a change in accounting method for valuing our outstanding stock options. We awarded no new stock options during 2011. As a result of our increased oil and natural gas production, however, our general and administrative expenses decreased by 27% on a unit-of-production basis to $5.21 per BOE for the year ended December 31, 2011, as compared to $6.77 per BOE for the year ended December 31, 2010.
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Net gain (loss) on asset sales and inventory impairment. We incurred a loss on asset sales and inventory impairment of approximately $154,000 for the year ended December 31, 2011, as compared to a loss of approximately $224,000 for the year ended December 31, 2010. During the year ended December 31, 2011, this loss was primarily related to the sale of pipe and other equipment and the impairment of certain equipment held in inventory, consisting primarily of drilling rig parts. During the year ended December 31, 2010, we wrote off the Boise South pipeline asset in Orange County, Texas and recognized a net loss of approximately $174,000. We also recognized an impairment of approximately $50,000 to some of our equipment held in inventory following a determination that the market value of the equipment, consisting primarily of drilling rig parts, was less than the cost.
Interest expense. For the year ended December 31, 2011, we incurred total interest expense of approximately $2.0 million. We capitalized approximately $1.3 million of our interest expense on certain qualifying projects for the year ended December 31, 2011 and expensed the remaining $0.7 million to operations. During the year ended December 31, 2011, we incurred incremental net borrowings of $88.0 million under our Credit Agreement to finance a portion of our working capital requirements and capital expenditures. Our total outstanding borrowings at December 31, 2011 were $113.0 million, and the interest rate on these borrowings was approximately 5.3% per annum. In early January 2012, we converted this $113.0 million base rate advance to a Eurodollar-based advance, which then bore interest at 3.5% per annum. In December 2010, we borrowed $25.0 million under our Credit Agreement to finance a portion of our working capital requirements and capital expenditures, which remained outstanding at December 31, 2010. We incurred interest expense of approximately $3,000 for the year ended December 31, 2010.
Interest and other income. Our interest and other income decreased by approximately $0.1 million to approximately $0.3 million, or a decrease of about 14%, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The decrease in our interest and other income was due primarily to a decrease in the average balances of our cash and cash equivalents and certificates of deposit on which we received interest income between the two periods. Our cash and cash equivalents and certificates of deposit decreased to approximately $11.6 million at December 31, 2011 from approximately $23.4 million at December 31, 2010, as we used cash and incremental borrowings to acquire additional leasehold acreage in the Eagle Ford shale play in South Texas and in the core area of the Haynesville shale play in Northwest Louisiana and to fund our operated and non-operated drilling and completion activities in both areas.
Total income tax provision (benefit). We recorded a total income tax benefit of approximately $5.5 million for the year ended December 31, 2011, as compared to a total income tax provision of approximately $3.5 million for the year ended December 31, 2010. The total income tax benefit for the year ended December 31, 2011 reflected deferred income taxes almost entirely, with the exception of a state of Louisiana income tax refund of approximately $46,000 recorded during this period. We recorded a total income tax provision of approximately $3.5 million for the year ended December 31, 2010. The total income tax provision for the year ended December 31, 2010 included a deferred income tax provision of approximately $4.9 million and a current income tax benefit of approximately $1.4 million, which was attributable to a refund of U.S. federal income taxes received by us. For the year ended December 31, 2010, the deferred income tax provision was consistent with our income before income taxes, which included approximately $3.1 million in unrealized hedging gains. We had a net loss for the year ended December 31, 2011, and our effective tax rate for the year ended December 31, 2010 was 35.57%.
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Liquidity and Capital Resources
Prior to the consummation of our Initial Public Offering on February 7, 2012, our primary sources of liquidity were capital contributions from private investors, our cash flows from operations, borrowings under our Credit Agreement and the proceeds from a significant sale of a portion of our assets in the Haynesville shale in 2008. Our primary use of capital has been, and will continue to be during 2013 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties. We continually evaluate potential capital sources, including equity and debt financings, additional borrowings and joint ventures, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital and to continue to grow our operating cash flows.
At December 31, 2012, we had cash and certificates of deposit totaling approximately $2.3 million, the borrowing base under our Credit Agreement was $215.0 million and we had $150.0 million of outstanding long-term borrowings and approximately $1.1 million in outstanding letters of credit. These borrowings bore interest at an effective interest rate of approximately 3.3% per annum. From January 1 through March 14, 2013, we borrowed an additional $30.0 million under our Credit Agreement to finance a portion of our working capital requirements and capital expenditures. At March 14, 2013, we had $180.0 million of outstanding long-term borrowings and approximately $1.3 million in outstanding letters of credit.
On September 28, 2012, we entered into the third amended and restated Credit Agreement which increased the maximum facility amount to $500.0 million from $400.0 million and increased the borrowing base from $125.0 million to $200.0 million as a result of our lenders’ review of our proved oil and natural gas reserves at June 30, 2012. The borrowing base under the Credit Agreement is scheduled to be redetermined automatically on May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at June 30 and December 31 of each year. Both we and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. During the fourth quarter of 2012, we requested one such unscheduled redetermination, and on December 20, 2012, the borrowing base was increased from $200.0 million to $215.0 million as a result of our lenders’ review of our proved oil and natural gas reserves at September 30, 2012. In addition, during the first quarter of 2013, our lenders completed their review of our proved oil and natural gas reserves at December 31, 2012, and as a result, on March 11, 2013, the borrowing base under our Credit Agreement was increased to $255.0 million. This most recent redetermination constitutes the regularly scheduled May 1 redetermination. We expect to request an unscheduled redetermination of our borrowing base between each scheduled redetermination date during 2013, which should result in approximately quarterly redeterminations of the borrowing base under our Credit Agreement throughout 2013. We expect additional increases to the borrowing base throughout 2013, primarily as a result of anticipated increases in our proved oil and natural gas reserves, and particularly our proved developed oil and natural gas reserves. As a result of this anticipated increase in borrowing capacity, together with our anticipated increases in oil production and related revenues, we expect to have sufficient cash flows from operations and future borrowing capacity under our Credit Agreement to fund our capital expenditure requirements for 2013. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. However, should our drilling activities be less successful than we anticipate or result in less growth in our proved oil and natural gas reserves or less cash flows than we anticipate in 2013, or should oil prices decline substantially, we may require additional sources of financing, including through potential joint ventures and potential issuances of equity or debt securities, which may not be available on terms reasonably acceptable to us or at all. To the extent such sources of financing are not available on terms reasonably acceptable to us, we may need to reduce our capital spending and rate of growth.
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Although a majority of our anticipated increase in cash flows from operations during the year ending December 31, 2013, as compared to our cash flows from operations in prior periods, is expected to come from development activities on proved properties in the Eagle Ford shale play at December 31, 2012, these development activities may be less successful than we anticipate. Further, a portion of our anticipated increase in cash flows from operations during the year ending December 31, 2013 is expected to come from exploration activities on currently unproved properties in the Eagle Ford shale in South Texas and in the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas, and these exploration activities may or may not be as successful as we anticipate. Additionally, any anticipated increases in our cash flows from operations are based upon current expectations of oil and natural gas prices for 2013 and the hedges we currently have in place. If our exploration and development activities result in less cash flows than anticipated, we may seek additional sources of capital, including through additional borrowings under our Credit Agreement, the sale of debt securities, the sale of assets or acreage or entering into one or more joint ventures, none of which may be available. In addition to future borrowings under our Credit Agreement, we may also seek to raise additional funds by selling shares of our common stock or securities convertible or exercisable into our common stock (including debt securities or other preferential securities) in the public markets or otherwise. It is likely that any such sales would dilute the ownership interest of our existing shareholders. There is no guarantee that we would be able to sell such debt or equity securities on terms acceptable to us. It is also possible that, to the extent we are not able to obtain additional sources of capital, we may modify our planned capital expenditure budget for 2013 accordingly or enter into one or more joint ventures or other alternative financings. Exploration and development activities are subject to a number of risks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows from operations and borrowing base under our Credit Agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth,” “Risk Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business” and “Risk Factors — Our Identified Drilling Locations Are Scheduled Out over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.”
Our cash flows for the years ended December 31, 2012, 2011 and 2010 are presented below:
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| (In thousands) | ||||||||||||
| Net cash provided by operating activities |
$ | 124,228 | $ | 61,868 | $ | 27,273 | ||||||
| Net cash used in investing activities |
(306,916 | ) | (160,088 | ) | (147,334 | ) | ||||||
| Net cash provided by financing activities |
174,499 | 87,444 | 36,891 | |||||||||
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|
|
|
|
|
|
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| Net change in cash and cash equivalents |
$ | (8,189 | ) | $ | (10,776 | ) | $ | (83,170 | ) | |||
Cash Flows Provided by Operating Activities
Net cash provided by operating activities increased by $62.3 million to $124.2 million for the year ended December 31, 2012, as compared to net cash provided by operating activities of $61.9 million for the year ended December 31, 2011. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased significantly to $114.9 million for the year ended December 31, 2012 from $49.3 million for the year ended December 31, 2011. This increase is primarily attributable to the almost eight-fold increase in our oil production to just over 1.2 million Bbl from approximately 154,000 Bbl during the respective periods. A portion of the increase in net cash provided by operating activities also reflects the
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higher weighted average oil price of $101.86 per Bbl realized during 2012, as compared to a weighted average oil price of $93.80 per Bbl realized during 2011. Changes in our operating assets and liabilities between December 31, 2011 and December 31, 2012 also resulted in a net decrease of approximately $3.3 million in net cash provided by operating activities for the year ended December 31, 2012, as compared to the year ended December 31, 2011. Our accounts payable and accrued liabilities increased to approximately $87.3 million at December 31, 2012 from approximately $44.3 million at December 31, 2011 due to our increased operating activity in South Texas. Our accounts receivable increased to $29.5 million at December 31, 2012, as compared to $13.2 million at December 31, 2011, due primarily to the increase in our oil production and associated revenues.
Net cash provided by operating activities increased by $34.6 million to $61.9 million for the year ended December 31, 2011, as compared to net cash provided by operating activities of $27.3 million for the year ended December 31, 2010. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased significantly to $49.3 million for the year ended December 31, 2011 from $25.0 million for the year ended December 31, 2010. This increase reflects primarily the 79% increase in our oil and natural gas production to 2.6 million BOE from 1.4 million BOE between the respective periods. A portion of the increase in net cash provided by operating activities also reflects the approximate five-fold increase in our oil production for the year ended December 31, 2011, as compared to the year ended December 31, 2010, as well as a higher weighted average oil price of $93.80 per Bbl realized during 2011, as compared to a weighted average oil price of $76.39 per Bbl realized during 2010. Some of this increase in net cash provided by operating activities is also due to changes in our operating assets and liabilities totaling approximately $10.3 million between December 31, 2010 and December 31, 2011. Our accounts payable and accrued liabilities increased to approximately $44.3 million at December 31, 2011 from approximately $27.0 million at December 31, 2010 due to our increased operating activity in South Texas. Our accounts receivable increased to $13.2 million at December 31, 2011, as compared to $11.6 million at December 31, 2010, due primarily to the increase in our oil and natural gas production and associated revenues.
Our operating cash flows are sensitive to a number of variables, including changes in our production and volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices. In addition, we attempt to avoid long-term service agreements in order to minimize ongoing future commitments. For additional information on the impact of changing prices on our financial position, see “Quantitative and Qualitative Disclosures About Market Risk” below. See also “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.”
Cash Flows Used in Investing Activities
Net cash used in investing activities increased by $146.8 million to $306.9 million for the year ended December 31, 2012 from $160.1 million for the year ended December 31, 2011. This increase in net cash used in investing activities reflected an increase of $144.3 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2012, as compared to the year ended December 31, 2011, and an increase of approximately $2.7 million in expenditures for other property and equipment, which includes new pipeline infrastructure associated with our initial wells in the Eagle Ford shale.
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Approximately 91% of our capital expenditures were allocated to drilling and completion operations and associated infrastructure and 9% to the acquisition of additional acreage for the year ended December 31, 2012, as compared to approximately 75% allocated to drilling and completion operations and associated infrastructure and 25% allocated to acquisition of additional acreage for the year ended December 31, 2011. Our oil and natural gas properties capital expenditures for the year ended December 31, 2012 were primarily due to expenditures associated with our operated drilling and completion activities and acreage acquisitions in the Eagle Ford shale, non-operated drilling and completion activities in the Eagle Ford and Haynesville shale plays and our acreage acquisitions in the Delaware Basin in West Texas.
Net cash used in investing activities increased by $12.8 million to $160.1 million for the year ended December 31, 2011 from $147.3 million for the year ended December 31, 2010. This increase in net cash used in investing activities reflected a decrease of $2.6 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2011, as compared to the year ended December 31, 2010, offset by an increase of approximately $3.0 million in expenditures for other property and equipment, which included new pipeline infrastructure associated with our initial wells in the Eagle Ford shale. Although our capital expenditures were relatively flat year-over-year, approximately 75% of our capital expenditures were allocated to drilling and completion operations and associated infrastructure and 25% to the acquisition of additional acreage for the year ended December 31, 2011, as compared to approximately 43% allocated to drilling and completion operations and associated infrastructure and 57% allocated to acquisition of additional acreage for the year ended December 31, 2010. Our oil and natural gas properties capital expenditures for the year ended December 31, 2011 were primarily due to expenditures associated with our operated and non-operated drilling and completion activities in the Eagle Ford shale and Haynesville shale plays and our acquisition of acreage prospective for the Eagle Ford shale in DeWitt, Gonzales, Karnes and Wilson Counties, Texas.
Expenditures for the acquisition, exploration and development of oil and natural gas properties are the primary use of our capital resources. We anticipate investing approximately $310.0 million in capital for acquisition, exploration and development activities in 2013 as follows:
| Amount (in millions) |
||||
| Exploration, development drilling and completion costs |
$ | 260.0 | ||
| Pipeline and infrastructure expenditures |
25.0 | |||
| Leasehold acquisition and 2-D and 3-D seismic data |
25.0 | |||
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|
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| Total |
$ | 310.0 | ||
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For further information regarding our anticipated capital expenditure budget in 2013, see “Business — General.”
Our 2013 capital expenditures may be adjusted as business conditions warrant. The amount, timing and allocation of our capital expenditures is largely discretionary and within our control. If oil or natural gas prices decline or costs increase significantly, we could defer a significant portion of our anticipated capital expenditures until later periods to conserve cash or to focus on those projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations and other factors both within and outside our control.
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Cash Flows Provided by Financing Activities
Net cash provided by financing activities was $174.5 million for the year ended December 31, 2012, as compared to net cash provided by financing activities of $87.4 million for the year ended December 31, 2011. The net cash provided by financing activities for the year ended December 31, 2012 was principally due to the total proceeds from the Initial Public Offering of $146.5 million and total incremental borrowings of $160.0 million under our Credit Agreement to fund a portion of our working capital requirements during the period, offset by the costs of the Initial Public Offering of $11.6 million incurred during the period and by the repayment of $123.0 million in borrowings during the period. We also received approximately $2.7 million from the exercise of stock options during the year ended December 31, 2012.
Net cash provided by financing activities was $87.4 million for the year ended December 31, 2011, as compared to net cash provided by financing activities of $36.9 million for the year ended December 31, 2010. The net cash provided by financing activities for the year ended December 31, 2011 was due almost entirely to additional borrowings of $88.0 million under our Credit Agreement to fund a portion of our working capital requirements as well as our acquisition of acreage prospective for the Eagle Ford shale play in DeWitt, Gonzales, Karnes and Wilson Counties, Texas. In January 2011, we sold 53,772 shares of our Class A common stock in a private placement and received net proceeds of approximately $0.6 million. During 2011, we also received proceeds from the exercise of stock options totaling approximately $0.8 million. For the year ended December 31, 2011, we also incurred cash expenditures related to preparation for our Initial Public Offering of approximately $1.7 million.
Net cash provided by financing activities was $36.9 million for the year ended December 31, 2010. For the year ended December 31, 2010, the most significant financing activities occurred in the fourth quarter of 2010. During that time, we sold approximately 1.9 million shares of our Class A common stock in a private placement and received net proceeds of approximately $21.0 million, and we borrowed $25.0 million under our Credit Agreement to fund a portion of our working capital requirements. In addition, in April 2010, we repurchased 1,000,000 shares of Class A common stock from five shareholders, all advised by Wellington Management Company, for a total of $9.0 million. We also received proceeds of approximately $2.0 million from the periodic exercise of stock options during the year ended December 31, 2010.
Credit Agreement
In December 2011, we entered into our second amended and restated senior secured revolving Credit Agreement for which Comerica Bank served as administrative agent. Among other things, this amendment increased the size of the facility and extended the term until December 2016. MRC Energy Company, a wholly-owned subsidiary of Matador Resources Company, was the borrower under the amended Credit Agreement. Borrowings were secured by mortgages on substantially all of our oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly-owned subsidiaries, which were also guarantors. In addition, all obligations under the Credit Agreement were guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging agreements with one of the lenders under the Credit Agreement (or an affiliate thereof) were also secured by the collateral of and guaranteed by the eligible subsidiaries of MRC Energy Company.
The amount of the borrowings under the second amended and restated Credit Agreement were limited to the lesser of $400.0 million or the borrowing base, which was determined by the lenders based primarily on the estimated value of our proved oil and natural gas reserves, but also on external factors, such as the lenders’ lending policies and the lenders’ estimates of future oil and natural gas prices, over which we have no control. At December 31, 2011, the borrowing base was $125.0 million and we had $113.0 million in
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outstanding borrowings under the Credit Agreement. In January 2012, we borrowed an additional $10.0 million to finance a portion of our working capital requirements, bringing the then-outstanding indebtedness under the Credit Agreement to $123.0 million. Following the completion of our Initial Public Offering, we used a portion of the net proceeds to repay the then-outstanding $123.0 million under our Credit Agreement in February 2012, at which time the borrowing base was reduced to $100.0 million. On February 28, 2012, the borrowing base was increased to $125.0 million pursuant to a special borrowing base redetermination made at our request. This borrowing base increase was determined by our lenders based upon, among other items, the increase in our proved oil and natural gas reserves at December 31, 2011.
On September 28, 2012, we entered into our third amended and restated senior secured revolving Credit Agreement, which matures in December 2016. Among other things, this amendment increased the maximum facility amount from $400.0 million to $500.0 million, increased the borrowing base from $125.0 million to $200.0 million and named RBC as administrative agent. In addition, the amendment provided for a conforming borrowing base of $165 million. The borrowing base will automatically be reduced to the conforming borrowing base on the earlier of (i) December 31, 2013 or (ii) the closing of a secondary public offering of equity interests that results in net cash proceeds to us in an amount greater than or equal to $25.0 million. MRC Energy Company is the borrower under the Credit Agreement. Borrowings are secured by mortgages on substantially all of our oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by the eligible subsidiaries of MRC Energy Company.
The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at June 30 and December 31 of each year. Both we and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the fourth quarter of 2012, we requested one such unscheduled redetermination, and on December 20, 2012, the borrowing base was increased from $200.0 million to $215.0 million as a result of our lenders’ review of our proved oil and natural gas reserves at September 30, 2012. In connection with this borrowing base redetermination, the conforming borrowing base was increased to $180.0 million at December 20,