UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

For the fiscal year ended December 31, 2012

or

For the transition period from                                           to                                          

 

Commission file number: 1-33615

 

Concho Resources Inc.

(Exact name of registrant as specified in its charter)

 

 

 

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 þ  No o 

 

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 o  No þ  

 

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 þ No o 

 

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ  No o  

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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.  þ 

 

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

 

 

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

 

 

 

 

 

TABLE OF CONTENTS

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS .................................................................. 1

 

PART I ............................................................................................................................................................................................................. 2

Item 1. Business ...................................................................................................................................................................................... 2

General ............................................................................................................................................................................................... 2

Acquisitions ....................................................................................................................................................................................... 2

Divestitures ........................................................................................................................................................................................ 3

Business and Properties ................................................................................................................................................................. 3

Summary of Core Operating Areas and Other Plays ............................................................................................................... 5

Drilling Activities ............................................................................................................................................................................. 7

Our Production, Prices and Expenses .......................................................................................................................................... 8               

Productive Wells .............................................................................................................................................................................. 9               

Marketing Arrangements ............................................................................................................................................................... 10               

Our Principal Customers ................................................................................................................................................................ 10               

Competition ...................................................................................................................................................................................... 10

Applicable Laws and Regulations ............................................................................................................................................... 11               

Our Employees .............................................................................................................................................................................. 17               

Available Information ................................................................................................................................................................. 17               

Non-GAAP Financial Measures and Reconciliations ............................................................................................................ 18               

Item 1A. Risk Factors ..............................................................................................................................................................20 

Risks Related to Our Business .................................................................................................................................................... 20               

Risks Related to Our Common Stock ....................................................................................................................................... 33

Item 1B. Unresolved Staff Comments ............................................................................................................................................ 33

Item 2. Properties ................................................................................................................................................................................ 34

Our Oil and Natural Gas Reserves ............................................................................................................................................. 34               

Developed and Undeveloped Acreage ..................................................................................................................................... 38

Title to Our Properties .................................................................................................................................................................. 38               

Item 3. Legal Proceeding .................................................................................................................................................................. 38

Item 4. Mine Safety Disclosure......................................................................................................................................................... 38

 

PART II ......................................................................................................................................................................................................... 39

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

Equity Securities ................................................................................................................................................................... 39

Market Information ..................................................................................................................................................................... 39               

Dividend Policy ............................................................................................................................................................................. 39

Repurchase of Equity Securities ................................................................................................................................................ 39

Item 6. Selected Financial Data ....................................................................................................................................................... 40

Selected Historical Financial Information ............................................................................................................................... 40

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ............................. 43

Overview ......................................................................................................................................................................................... 43

Financial and Operating Performance ...................................................................................................................................... 44

Commodity Prices ........................................................................................................................................................................ 44

Recent Events ............................................................................................................................................................................... 46

Derivative Financial Instruments .............................................................................................................................................. 47

Results of Operations ................................................................................................................................................................... 48

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 ............................................................ 51

 

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 ............................................................ 56

Capital Commitments, Capital Resources and Liquidity ..................................................................................................... 61

Critical Accounting Policies and Practices ............................................................................................................................... 66

Recent Accounting Pronouncements ........................................................................................................................................ 69

Item 7A. Quantitative and Qualitative Disclosure About Market Risk ................................................................................. 70

Credit risk ....................................................................................................................................................................................... 70

Commodity price risk .................................................................................................................................................................. 70

Interest rate risk ............................................................................................................................................................................ 71

Item 8. Financial Statements and Supplementary Data ............................................................................................................ 72

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ............................. 72

Item 9A. Quantitative and Qualitative Disclosure About Market Risk ................................................................................. 72

Evaluation of Disclosure Controls and Procedures ................................................................................................................ 72

Changes in Internal Control over Financial Reporting .......................................................................................................... 72

Item 9B. Other Information .............................................................................................................................................................. 75

 

PART III ........................................................................................................................................................................................................ 76

Item 10. Directors, Executive Officers and Corporate Governance ..................................................................................... 76

Item 11. Executive Compensation .................................................................................................................................................. 76

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder

 Matters .................................................................................................................................................................................. 76

Equity Compensation Plans ....................................................................................................................................................... 76

Item 13. Certain Relationships and Related Transactions, and Director Independence ................................................... 76

Item 14. Principal Accounting Fees and Services ....................................................................................................................... 76

 

PART IV ........................................................................................................................................................................................................ 77

Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K .................................................................... 77

 

GLOSSARY OF TERMS ............................................................................................................................................................................. 83

SIGNATURES ............................................................................................................................................................................................... 87

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS ............................................................................................................. F-1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil and natural gas reserves, drilling program, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ materially from those implied or expressed by the forward-looking statements. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made. We disclaim any obligation to update or revise these statements unless required by law, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in “Item 1A. Risk Factors,” as well as those factors summarized below:

·         sustained or further declines in the prices we receive for our oil and natural gas;

·         uncertainties about the estimated quantities of oil and natural gas reserves;

·         drilling and operating risks, including risks related to properties where we do not serve as the operator and risks related to hydraulic fracturing activities;

·         the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our credit facility;

·         the effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing;

·         difficult and adverse conditions in the domestic and global capital and credit markets;

·         risks related to the concentration of our operations in the Permian Basin of Southeast New Mexico and West Texas;

·         shortages of oilfield equipment, supplies, services and qualified personnel and increased costs for such equipment, supplies, services and personnel;

·         potential financial losses or earnings reductions from our commodity price management program;

·         risks and liabilities associated with acquired properties or businesses;

·         uncertainties about our ability to successfully execute our business and financial plans and strategies;

·         uncertainties about our ability to replace reserves and economically develop our current reserves;

·         general economic and business conditions, either internationally or domestically or in the jurisdictions in which we operate;

·         competition in the oil and natural gas industry; and

·         uncertainty concerning our assumed or possible future results of operations.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.   

                                                                  

 

PART I

 

Item 1. Business

 

General

 

Concho Resources Inc., a Delaware corporation (“Concho,” the “Company,” “we,” “us” and “our”) formed in February 2006, is an independent oil and natural gas company engaged in the acquisition, development and exploration of oil and natural gas properties. Our core operating areas are located in the Permian Basin region of Southeast New Mexico and West Texas, a large onshore oil and natural gas basin in the United States. The Permian Basin is one of the most prolific oil and natural gas producing regions in the United States and is characterized by an extensive production history, long reserve life, multiple producing horizons and enhanced recovery potential. We refer to our three core operating areas as the (i) New Mexico Shelf, where we primarily target the Yeso  formation, (ii) Delaware Basin, where we primarily target the Bone Spring formation (including the Avalon shale and the Bone Spring sands) and the Wolfcamp shale, and (iii) Texas Permian, where we primarily target the Wolfberry, a term applied to the combined Wolfcamp and Spraberry horizons. We intend to grow our reserves and production through development drilling and exploration activities on our multi-year project inventory and through acquisitions that meet our strategic and financial objectives.

 

Acquisitions

 

Three Rivers Acquisition  

 

In July 2012, we completed an acquisition of producing and non-producing assets from Three Rivers Operating Company LLC and certain affiliated entities (the “Three Rivers Acquisition”) for cash consideration of approximately $1.0 billion. We estimated that the Three Rivers Acquisition had approximately 45.5 MMBoe of proved reserves at closing. The Three Rivers Acquisition was primarily funded with borrowings under our credit facility.

 

PDC Acquisition  

 

In February 2012, we completed an acquisition of producing and non-producing assets in the Wolfberry trend in the Permian Basin from Petroleum Development Corporation (the “PDC Acquisition”) for approximately $189.2 million in cash. We estimated that the PDC Acquisition had approximately 9.8 MMBoe of proved reserves at closing. The PDC Acquisition was primarily funded with borrowings under our credit facility.

 

Delaware Basin Acquisitions

 

OGX Acquisition. In November 2011, we acquired three entities affiliated with OGX Holdings II, LLC (collectively the “OGX Acquisition”) for cash consideration of approximately $252.0 million. The OGX Acquisition consisted of producing and non-producing acreage in the Delaware Basin of Southeast New Mexico and West Texas. We estimate that the OGX Acquisition contained approximately 5.7 MMBoe of proved reserves at closing. The OGX Acquisition was primarily funded with borrowings under our credit facility.

 

Other Delaware Basin Acquisitions. In the third and fourth quarters of 2011, in four acquisitions, we acquired for approximately $79.0 million in cash additional non-producing acreage in the Delaware Basin. These acquisitions were primarily funded with borrowings under our credit facility. We collectively refer to these acquisitions and the OGX Acquisition as the “Delaware Basin Acquisitions.”

 

Marbob and Settlement Acquisitions

 

In July 2010, we entered into an asset purchase agreement to acquire certain of the oil and natural gas leases, interests, properties and related assets owned by Marbob Energy Corporation and its affiliates (collectively, “Marbob”) for aggregate consideration of (i) cash in the amount of $1.45 billion, (ii) the issuance to Marbob of a $150 million 8.0% senior note due 2018, which was repaid in May

 

of 2011 with borrowings under our credit facility, and (iii) the issuance to Marbob of approximately 1.1 million shares of our common stock, subject to purchase price adjustments, which included downward purchase price adjustments based on the exercise by third parties of contractual preferential purchase rights in properties to be acquired from Marbob (the “Marbob Acquisition”).

  

On October 7, 2010, we closed the Marbob Acquisition. At closing, we paid approximately $1.1 billion in cash plus the senior note and common stock described above for a total purchase price of approximately $1.4 billion. The total purchase price as originally announced was reduced due to third party contractual preferential purchase rights in the Marbob properties. Certain of the third parties’ contractual preferential purchase rights became subject to litigation.

 

We funded the cash consideration in the Marbob Acquisition with (a) borrowings under our credit facility and (b) net proceeds of $292.7 million from a private placement of approximately 6.6 million shares of our common stock at a price of $45.30 per share that closed on October 7, 2010.

 

On October 15, 2010, we resolved the litigation related to the disputed contractual preferential purchase rights. As a result of the settlement, we acquired a non-operated interest in substantially all of the oil and natural gas assets subject to the litigation for approximately $286 million in cash (the “Settlement Acquisition”). We funded the Settlement Acquisition with borrowings under our credit facility.

 

The properties acquired in the Marbob and Settlement Acquisitions are primarily located in the Permian Basin of Southeast New Mexico, including a large acreage position contiguous to our core Yeso play on the southeast New Mexico Shelf and a significant acreage position in the Delaware Basin. We estimate that the assets acquired in the Marbob and Settlement Acquisitions contained approximately 72.4 MMBoe of proved reserves at closing.

 

Divestitures

 

In December 2012, we sold certain of our non-core assets, some of which were acquired in the Three Rivers Acquisition, for cash consideration of approximately $488.1 million, subject to customary post-closing adjustments, and recognized a pre-tax loss on the disposition of assets (included in discontinued operations) of approximately $18.7 million. For the year ended December 31, 2012, these assets produced an average of 4,937 Boe per day, which was approximately 63 percent oil. We estimate that the proved reserves of these assets at closing were approximately 35.3 MMBoe.

 

In March 2011, we sold our Bakken assets for cash consideration of approximately $195.9 million and recognized a pre-tax gain on the disposition of assets (included in discontinued operations) of approximately $135.9 million. For the first quarter of 2011, these assets produced an average of 1,369 Boe per day. We estimate that the proved reserves of the Bakken assets at closing were approximately 8.4 MMBoe.

 

In December 2010, we sold certain of our non-core Permian Basin assets for cash consideration of approximately $103.3 million and recognized a pre-tax gain on the disposition of assets (included in discontinued operations) of approximately $29.1 million. For 2010, these assets produced an average of 1,393 Boe per day. We estimate that the proved reserves of these assets at closing were approximately 6.0 MMBoe.  

 

Business and Properties

 

Our core operations are focused in the Permian Basin of Southeast New Mexico and West Texas. It underlies an area of Southeast New Mexico and West Texas approximately 250 miles wide and 300 miles long. Commercial accumulations of hydrocarbons occur in multiple stratigraphic horizons, at depths ranging from approximately 1,000 feet to over 25,000 feet. At December 31, 2012, substantially all of our 447.2 MMBoe total estimated proved reserves were located in our core operating areas and consisted of approximately 61.2 percent oil and 38.8 percent natural gas. We have assembled a multi-year inventory of development drilling and exploration projects, including projects to further evaluate (i) the areal extent of the Yeso formation and the Wolfberry play and (ii) the Bone Spring and Wolfcamp formations in the Delaware Basin, which we believe will allow us to grow our proved reserves and production.

 

 

We continually evaluate opportunities that could develop into an emerging play. We view an emerging play as an area where we can acquire large undeveloped acreage positions and apply horizontal drilling and/or advanced fracture stimulation technologies to achieve economic and repeatable production results. We have assembled an exploration team to target such emerging plays.

 

The following table sets forth information with respect to drilling of wells commenced during the periods indicated:

 

 

In 2012, we drilled approximately 27% of our wells horizontally.  We will continue to evaluate converting our identified vertical locations to horizontal opportunities, where possible. We believe horizontal drilling is more capital efficient than vertical drilling, in many situations.  In 2013, we plan to spend approximately $900 million of our $1.4 billion drilling and completion costs budget on horizontal drilling opportunities.

 

We produced approximately 29.8 MMBoe, 23.6 MMBoe and 15.6 MMBoe of oil and natural gas during 2012, 2011 and 2010, respectively. Included in those production amounts are 1,807 MBoe, 1,679 MBoe and 2,345 MBoe of production related to our discontinued operations during 2012, 2011 and 2010, respectively. In addition, we increased our average daily production from 66.2 MBoe during the fourth quarter of 2011 to 84.7 MBoe during the fourth quarter of 2012. During 2012, we increased our total estimated proved reserves by approximately 60.7 MMBoe, after giving effect to (i) acquisitions of 56.5 MMBoe and (ii) sales of minerals-in-place of 35.3 MMBoe.

 

Summary of Core Operating Areas and Other Plays

 

The following is a summary of information regarding our core operating areas and other plays that are further described below:

 

 

(a)      Our Standardized Measure at December 31, 2012 was $5.8 billion. The present value of estimated future net revenues discounted at an annual rate of 10 percent (“PV-10”) is not a GAAP financial measure and is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. PV-10, however, is not a substitute for the Standardized Measure. Our PV-10 measure and the Standardized Measure do not purport to present the fair value of our oil and natural gas reserves.  See “Item 1. Business —Non-GAAP Financial Measures and Reconciliations.”

 

(b)     Of the 12,269 gross identified drilling locations, 2,326 locations were associated with proved reserves.

 

(c)      Includes production of 1,807 MBoe (an average of 4,937 Boe per day for the year) for the non-core assets divested in December 2012.

__________________________________________________________________________________________________________________________________

 

Core operating areas

 

New Mexico Shelf.  This area represents our most significant concentration of assets and, at December 31, 2012, we had estimated proved reserves in this area of 224.4 MMBoe, representing 50.2 percent of our total proved reserves and 55.7 percent of our PV-10.

 

Within this area our primary objectives are the Yeso, San Andres and Grayburg formations, with producing depths ranging from approximately 900 feet to 7,500 feet. We have drilled and plan to continue to evaluate drilling horizontally in the Yeso. During 2012, we continued our development of the Yeso formation on 10 acre spacing.

 

During the year ended December 31, 2012, we commenced drilling or participated in the drilling of 360 (257 net) wells in this area, of which 298 (223 net) wells were completed as producers, 2 (1 net) wells were unsuccessful and 60 (33 net) wells were in various stages of drilling and completion at December 31, 2012. During 2012, approximately 18 percent of the wells we commenced or participated in drilling were drilled horizontally.

 

At December 31, 2012, we had 228,936 gross (103,814 net) acres in this area. At December 31, 2012, on our assets in this area, we had identified 2,083 (1,401 net) drilling locations, with proved reserves attributed to 616 (457 net) of such locations. Of these 2,083 drilling locations, 1,044 locations target the Yeso formation vertically and 676 locations target the Yeso formation horizontally.

 

In 2013, we plan to spend approximately $285 million, or 21 percent, of our 2013 capital budget on drilling and completion costs on the New Mexico Shelf assets, with which we expect to drill 190 (116 net) wells. In 2013, we expect that approximately 31 percent of these wells will be drilled horizontally.

 

Delaware Basin.  At December 31, 2012, we had estimated proved reserves in the Delaware Basin of 81.7 MMBoe, representing  18.3 percent of our total proved reserves and 16.8 percent of our PV-10.

 

 

Within this area, we utilize horizontal drilling and fracturing technologies to target the oil-prone Bone Spring formation that includes three Bone Spring sandstone members, the Avalon shale member and the Wolfcamp shale. These formations produce from 4,700 feet to 13,500 feet for our currently targeted activity. Within the Delaware Basin, we have drilled and are also actively evaluating the Delaware sands and Penn shale opportunities on our acreage.

 

During the year ended December 31, 2012, we commenced drilling or participated in the drilling of 154 (76 net) wells in this area, of which 107 (51 net) wells were completed as producers, 2 (2 net) wells were unsuccessful and 45 (23 net) wells were in various stages of drilling and completion at December 31, 2012. During 2012, we continued (i) our development and step-out activity on the Avalon shale, Bone Spring sands and Wolfcamp shale and (ii) evaluation of our fracture stimulation procedures in the completion of certain horizontal wells. During 2012, approximately 99% of the wells we commenced or participated in drilling were drilled horizontally.

 

At December 31, 2012, we had 476,223 gross (315,742 net) acres in this area.  At December 31, 2012, we had identified 4,212 (1,949 net) drilling locations, with proved reserves attributed to 246 (128 net) of such locations. These locations include 2,462 targeting the Bone Spring sands, 1,016 targeting the Avalon shale and 734 targeting other formations.

 

In 2013, we plan to spend approximately $725 million, or 54 percent, of our 2013 capital budget on drilling and completion costs on the Delaware Basin assets, with which we expect to drill 175 (99 net) wells. In 2013, we expect that approximately 95 percent of these wells will be drilled horizontally.

 

Texas Permian.  At December 31, 2012, our estimated proved reserves of 141.0 MMBoe in this area accounted for 31.5 percent of our total proved reserves and 27.5 percent of our PV-10 value.

 

Our primary objective in the Texas Permian area is the Wolfberry in the Midland Basin. “Wolfberry” is the term applied to the combined production from the Spraberry and Wolfcamp horizons out of vertical wellbores, which are typically encountered at depths of 7,500 feet to 10,500 feet. These formations are comprised of a sequence of basinal, interbedded sands, shales and carbonates.  On our Texas Permian assets we are continuing to evaluate (i) our 20-acre downspacing on the Wolfberry assets, (ii) the potential of horizontal Wolfcamp drilling and (iii) the other potential zones on our acreage, such as the Cline shale (a Pennsylvanian age formation).

 

At December 31, 2012, we had 426,601 gross (155,490 net) acres in this area. In addition, at December 31, 2012, we had identified 5,974 (3,638 net) drilling locations, with proved reserves attributed to 1,464 (749 net) of such drilling locations. Of these 5,974 drilling locations, 1,955 target the Wolfberry play through 40-acre spacing, 2,486 target the Wolfberry play on 20-acre spacing, 1,410 target the shallow Wolfcamp vertically and the remaining drilling locations target other objectives.   

 

During 2012, we commenced drilling or participated in the drilling of 326 (186 net) wells in this area, of which 270 (153 net) wells were completed as producers, 1 (1 net) well was unsuccessful and 55 (32 net) wells were in various stages of drilling and completion at December 31, 2012. During 2012, approximately 2 percent of the wells we commenced or participated in drilling were drilled horizontally.

 

In 2013, we plan to spend approximately $342 million, or 25 percent, of our 2013 capital budget on drilling and completion costs on the Texas Permian assets, with which we expect to drill 266 (165 net) wells. In 2013, we expect that approximately 3 percent of these wells will be drilled horizontally.

 

Drilling Activities

 

The following table sets forth information with respect to (i) wells drilled and completed during the periods indicated and (ii) wells drilled in a prior period but completed in the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.

 

 

The following table sets forth information about our wells for which drilling was in-progress or are pending completion at December 31, 2012, which are not included in the above table:

 

 

Our Production, Prices and Expenses

 

The following table sets forth summary information concerning our production and operating data from continuing operations for the years ended December 31, 2012, 2011 and 2010. The table below excludes production and operating data that we have classified as discontinued operations, which is more fully described in Note N of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.” The actual historical data in this table excludes results from the (i) Three Rivers Acquisition for periods prior to July 2012, (ii) PDC Acquisition for periods prior to March 2012, (iii) OGX Acquisition for periods prior to December 2011 and (iv) Marbob and Settlement Acquisitions for periods prior to their respective close dates in October 2010. Because of normal production declines, increased or decreased drilling activities and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.

 

 

Productive Wells

 

The following table sets forth the number of productive oil and natural gas wells on our properties at December 31, 2012, 2011 and 2010. This table does not include wells in which we own a royalty interest only.

 

 

Marketing Arrangements

 

General. We market our oil and natural gas in accordance with standard energy practices. The marketing effort is coordinated with our operations group as it relates to the planning and preparation of future drilling programs so that available markets can be assessed and secured. This planning also involves the coordination of access to the physical facilities necessary to connect new producing wells as efficiently as possible upon their completion.

 

Oil. We do not transport, refine or process the oil we produce. A significant portion of our oil in Southeast New Mexico, primarily on the New Mexico Shelf, is connected directly to oil gathering pipelines. Most of our gathered oil in this area is utilized in a two-refinery complex in Southeast New Mexico. A significant portion of our West Texas production is on pipeline. Most of this production is sweet crude and is transported by third parties to the Cushing, Oklahoma hub. The balance of our oil in these areas that is not directly connected to pipeline is (i) trucked to unloading stations on those same pipelines or (ii) railed to the Gulf Coast in lieu of transporting by pipeline. We sell the majority of the oil we produce under contracts using market-based pricing. This price is then adjusted for differentials based upon delivery location and oil quality.

 

Natural Gas. We consider all natural gas gathering and delivery infrastructure in the areas of our production and evaluate market options to obtain the best price reasonably available under the circumstances. We sell the majority of our natural gas under individually negotiated natural gas purchase contracts using market-based pricing. The majority of our natural gas is subject to term agreements that extend at least three years from the date of the subject contract.

 

The majority of the natural gas we sell is casinghead gas sold at the lease under a percentage of proceeds processing contract. The purchaser gathers our casinghead natural gas in the field where it is produced and transports it via pipeline to a natural gas processing plant where the natural gas liquid products are extracted and sold by the processor. The remaining natural gas product is residue gas, or dry gas, which is placed on residue pipeline systems available in the area. Under our percentage of proceeds contracts, we receive a percentage of the value for the extracted liquids and the residue gas. In a limited number of cases (typically dry gas production), the natural gas gathering and transportation is performed by a third party gathering company which transports the production from the production location to the purchaser’s mainline.

 

Our Principal Customers

 

We sell our oil and natural gas production principally to marketers and other purchasers that have access to pipeline facilities. In areas where there is no practical access to pipelines, oil is transported to storage facilities by trucks and rail owned or otherwise arranged by the marketers or purchasers. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.

 

For 2012, revenues from oil and natural gas sales to Holly Frontier Refining and Marketing, LLC and Phillips 66 (formerly the ConocoPhillips Company) accounted for approximately 26 percent and 14 percent, respectively, of our total operating revenues. While the loss of either of these purchasers may result in a temporary interruption in sales of, or a lower price for, our production, we believe that the loss of any of these purchasers would not have a material adverse effect on our operations, as there are alternative purchasers in our producing regions.

 

Competition

 

The oil and natural gas industry in the regions in which we operate is highly competitive. We encounter strong competition from numerous parties, ranging generally from small independent producers to major integrated companies. We primarily encounter significant competition in acquiring properties, contracting for drilling, pressure pumping and workover equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable properties, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

 

 

In addition to competition for drilling, pressure pumping and workover equipment, we are also affected by the availability of related equipment and materials. The oil and natural gas industry periodically experiences shortages of drilling and workover rigs, equipment, pipe, materials and personnel, which can delay drilling, workover and exploration activities and cause significant price increases. The shortages of personnel make it difficult to attract and retain personnel with experience in the oil and natural gas industry and caused us to increase our general and administrative budget. We are unable to predict the timing or duration of any such shortages.

 

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights. Although we regularly evaluate acquisition opportunities and submit bids as part of our growth strategy, we do not have any current agreements, understandings or arrangements with respect to any material acquisition.

 

Applicable Laws and Regulations

 

Regulation of the Oil and Natural Gas Industry

 

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

 

Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission (the “FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system that permits an oil pipeline, subject to limited challenges, to annually increase or decrease its transportation rates due to inflationary changes in costs using a FERC approved index, without making a cost of service filing. Every five years, the FERC reviews the appropriateness of the index in relation to industry costs. On December 16, 2010, the FERC established a new Producer Price Index for Finished Goods (the “PPI-FG”) of PPI-FG plus 2.65 percent for the five-year period beginning July 1, 2011. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

 

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

 

Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the Federal Trade Commission (“FTC”) issued a rule prohibiting market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of oil, gasoline or petroleum distillates at wholesale from knowingly engaging in any act, practice or course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or deceit upon any person, or intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A violation of this rule may result in civil penalties of up to $1 million per day per violation, in addition to any applicable penalty under the Federal Trade Commission Act.

 

Regulation of transportation and sale of natural gas.  Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (the “Natural Gas Act”), the Natural Gas Policy Act of 1978 (the “Natural Gas Policy Act”) and regulations issued under those acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future, and market participants are prohibited from engaging in market manipulation. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress

 

enacted the Natural Gas Wellhead Decontrol Act which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

 

The FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although these orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

 

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting.

 

In August 2005, Congress enacted the Energy Policy Act of 2005 (the “EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. The FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the Natural Gas Act or Natural Gas Policy Act up to $1 million per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales, gathering or production, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704, described below. EPAct 2005 therefore reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas. 

 

In December 2007, the FERC issued a rule (“Order No. 704”), as clarified in orders on rehearing, requiring that any market participant, including a producer such as us, that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million MMBtus during a calendar year to annually report, starting May 1, 2009, such sales and purchases to the FERC. These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation. We do not anticipate that we will be affected by these rules any differently than other producers of natural gas.

 

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

 

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, the FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting natural gas to point of sale locations.

 

 

Intrastate natural gas transportation is also 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. During the 2007 legislative session, the Texas State Legislature passed H.B. 3273 (the “Competition Bill”) and H.B. 1920 (the “LUG Bill”).  The Competition Bill gives the Railroad Commission of Texas the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and intrastate transportation pipelines in formal rate proceedings.  It also gives the Railroad Commission specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers.  The Competition Bill also provides producers with the unilateral option to determine whether or not confidentiality provisions are included in a contract to which a producer is a party for the sale, transportation or gathering of natural gas.  The LUG Bill modifies the informal complaint process at the Railroad Commission with procedures unique to lost and unaccounted for natural gas issues.  It extends the types of information that can be requested, provides producers with an annual audit right, and provides the Railroad Commission with the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007, and the Railroad Commission rules implementing the Railroad Commission’s authority pursuant to the bills became effective on April 28, 2008.

 

Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

 

Regulation of production.  The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and the plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. 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. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

 

Environmental, Health and Safety Matters

 

General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

 

·         require the acquisition of various permits before drilling commences;

 

·         restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production and saltwater disposal activities;

 

·         limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

 

·         require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

 

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, environmental laws and regulations are revised frequently, and any changes that result

 

in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

 

The following is a summary of some of the existing laws, rules and regulations to which our business is subject.

 

Waste handling. The Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to regulatory guidance issued by the federal Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

 

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (the “CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. 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 the hazardous substances released into the environment.

 

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

 

Water discharges. The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

 

Air emissions. The federal Clean Air Act (“CAA”), and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

 

For example, in August 2012, the EPA adopted new rules that make all oil and gas operations (production, processing, transmission, storage and distribution) subject to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. These new EPA rules also impose NSPS standards for completions of hydraulically fractured gas wells. These standards include requirements for operators to use the reduced emission completion (“REC”) techniques developed in EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards are applicable to newly drilled and fractured wells as well as existing wells that are refractured. The requirement

 

for flaring of gas not sent to a gathering line became effective on October 15, 2012, and all operators are required to use REC techniques beginning January 1, 2015. Further, the new NESHAPS regulations impose maximum achievable control technology (“MACT”) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards.  We are currently evaluating the effect these rules could have on our business.

 

Climate change.   In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases”, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The EPA recently adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of GHGs are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules. In 2011, the EPA adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including certain onshore oil and natural gas facilities, on an annual basis beginning in 2012 for emissions occurring in 2011. We fulfilled our 2011 emissions reporting in 2012 as required by EPA’s rules.

 

In addition, Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs gases primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.  Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.

 

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce.  Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

 

Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel.  In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example, Texas adopted rules requiring public disclosure of non-confidential information regarding fluids used in hydraulic fracturing activities that became effective on February 1, 2012, and New Mexico adopted similar rules that became effective on February 15, 2012.  We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.  

 

 

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices.  The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and the EPA is performing a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and waste disposal.  The EPA has indicated that it expects to issue its study report in late 2014.  Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014.  Other governmental agencies, including the United States Department of Energy and the United States Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

 

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies may cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.  If new laws or regulations significantly restrict hydraulic fracturing activities or impose burdens on new permitting or operating requirements, our ability to utilize hydraulic fracturing may be curtailed and this may in turn reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. 

 

Endangered species.  The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species.  Some of our drilling operations are conducted in areas where protected species are known to exist.  In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species.  It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species.  The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete drilling and developmental operations and could adversely affect our future production from those areas.

 

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

 

OSHA and other laws and regulation. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety. We believe that we are in substantial compliance with the applicable requirements of OSHA and comparable laws.

 

We believe that we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities during 2012. Additionally, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2012. However, we cannot assure you that the passage or application of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operation.

 

Our Employees

 

Our corporate headquarters are located at One Concho Center, 600 West Illinois Avenue Midland, Texas 79701. We also maintain various field offices in Texas and New Mexico. At December 31, 2012, we had 745 employees, 290 of whom were employed in field operations. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be good. We also utilize the services of independent contractors to perform various field and other services.

 

Available Information

 

We file or furnish annual, quarterly and current reports, proxy statements and other documents with the United States Securities and Exchange Commission (the “SEC”) under the Exchange Act. The public may read and copy any materials that we file or furnish with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file or furnish electronically with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov. 

 

We also make available free of charge through our website, www.concho.com, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

 

Non-GAAP Financial Measures and Reconciliations

 

PV-10

 

PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.

 

The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2012, 2011 and 2010: