10-K 1 d447613d10k.htm FORM 10-K Form 10-K
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark one)

 

      þ

   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: 001-33801

APPROACH RESOURCES INC.

(Exact name of registrant as specified in its charter)

 

Delaware   51-0424817

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification Number)

One Ridgmar Centre

6500 West Freeway, Suite 800

Fort Worth, Texas

  76116
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code

(817) 989-9000

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   NASDAQ Global Select Market

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  ¨

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  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  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer  þ   Accelerated filer  ¨   Non-accelerated filer  ¨   Smaller reporting company  ¨

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates (excluding voting shares held by officers and directors) as of June 29, 2012 was $758.4 million. This amount is based on the closing price of the registrant’s common stock on the NASDAQ Global Select Market on that date.

The number of shares of the registrant’s common stock, par value $0.01, outstanding as of February 22, 2013 was 39,024,869.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement for its 2013 annual meeting of stockholders are incorporated by reference in Part III, Items 10-14 of this report.

Certain exhibits previously filed with the Securities and Exchange Commission are incorporated by reference into Part IV of this report.

 

 

 


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APPROACH RESOURCES INC.

Unless the context otherwise indicates, all references in this report to “Approach,” the “Company,” “we,” “us,” “our” or “ours” are to Approach Resources Inc. and its subsidiaries. Unless otherwise noted, (i) all information in this report relating to oil, NGLs and natural gas reserves and the estimated future net cash flows attributable to reserves is based on estimates and is net to our interest, and (ii) all information in this report relating to oil, NGLs and natural gas production is net to our interest. Natural gas is converted throughout this report at a rate of six Mcf of gas to one barrel of oil equivalent (“Boe”). NGLs are converted throughout this report at a rate of one barrel of NGLs to one Boe. The ratios of six Mcf of gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe of natural gas or NGLs may differ significantly from the price of a barrel of oil. If you are not familiar with the oil and gas terms or abbreviations used in this report, please refer to the definitions of these terms and abbreviations under the caption “Glossary” at the end of Item 15 of this report.

TABLE OF CONTENTS

 

         Page  
PART I   

Item 1.

  Business      1   

Item 1A.

  Risk Factors      12   

Item 1B.

  Unresolved Staff Comments      23   

Item 2.

  Properties      24   

Item 3.

  Legal Proceedings      32   

Item 4.

  Mine Safety Disclosures      32   
PART II   

Item 5.

  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities      33   

Item 6.

  Selected Financial Data      36   

Item 7.

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

Item 7A.

  Quantitative and Qualitative Disclosures About Market Risk      53   

Item 8.

  Financial Statements and Supplementary Data      55   

Item 9.

  Changes in and Disagreements With Accountants on Accounting and Financial Disclosure      56   

Item 9A.

  Controls and Procedures      56   

Item 9B.

  Other Information      56   
PART III   

Item 10.

  Directors, Executive Officers and Corporate Governance      57   

Item 11.

  Executive Compensation      57   

Item 12.

  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      57   

Item 13.

  Certain Relationships and Related Transactions, and Director Independence      57   

Item 14.

  Principal Accounting Fees and Services      57   
PART IV   

Item 15.

  Exhibits, Financial Statement Schedules      58   

Signatures

     65   

Index to Financial Statements of Approach Resources Inc.

     F-1   

Index to Exhibits

     66   

 

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Cautionary Statement Regarding Forward-Looking Statements

Various statements in this report, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The forward-looking statements may include projections and estimates concerning the timing and success of specific projects, typical well economics and our future reserves, production, revenues, costs, income, capital spending, 3-D seismic operations, interpretation and results and obtaining permits and regulatory approvals. When used in this report, the words “will,” “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” “potential” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

These forward-looking statements are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. We caution all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Risk Factors” section and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We disclaim any obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, unless required by law. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingencies and uncertainties relate to, among other matters, the following:

 

   

uncertainties in drilling, exploring for and producing oil and gas;

 

   

uncertainty of commodity prices in oil, NGLs and gas;

 

   

overall United States and global economic and financial market conditions;

 

   

domestic and foreign demand and supply for oil, NGLs, gas and the products derived from such hydrocarbons;

 

   

our inability to obtain additional financing necessary to fund our operations and capital expenditures and to meet our other obligations;

 

   

the effects of government regulation and permitting and other legal requirements, including laws or regulations that could restrict or prohibit hydraulic fracturing;

 

   

disruption of credit and capital markets;

 

   

our financial position;

 

   

our cash flows and liquidity;

 

   

disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our oil, NGLs and gas and other processing and transportation considerations;

 

   

marketing of oil, NGLs and gas;

 

   

high costs, shortages, delivery delays or unavailability of drilling and completion equipment, materials, labor or other services;

 

   

competition in the oil and gas industry;

 

   

uncertainty regarding our future operating results;

 

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interpretation of 3-D seismic data;

 

   

replacing our oil, NGL and gas reserves;

 

   

our ability to retain and attract key personnel;

 

   

our business strategy, including our ability to recover oil, NGLs and gas in place associated with our Wolfcamp oil shale resource play in the Permian Basin;

 

   

development of our current asset base or property acquisitions;

 

   

estimated quantities of oil, NGL and gas reserves;

 

   

plans, objectives, expectations and intentions contained in this report that are not historical; and

 

   

other factors discussed under Item 1A. “Risk Factors” in this report.

 

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PART I

ITEM 1.    BUSINESS

General

Approach Resources Inc. is an independent energy company engaged in the exploration, development, production and acquisition of oil and gas properties. We focus on oil and gas reserves in oil shale and tight gas sands in the Midland Basin of the greater Permian Basin in West Texas, where we lease approximately 148,000 net acres. Our drilling targets include the Clearfork, Wolfcamp shale, Canyon Sands, Strawn and Ellenburger zones. We sometimes refer to the Clearfork and Wolfcamp zones together as the “Wolffork,” and our development project in the Permian Basin as “Project Pangea,” which includes the northwestern portion of Project Pangea that we refer to as “Pangea West.” Our management and technical team have a proven track record of finding and developing reserves through advanced drilling and completion techniques. As the operator of all of our estimated proved reserves and production, we have a high degree of control over capital expenditures and other operating matters.

At December 31, 2012, our estimated proved reserves were 95.5 million barrels of oil equivalent (“MMBoe”). Substantially all of our proved reserves are located in Crockett and Schleicher Counties, Texas. Important characteristics of our proved reserves at December 31, 2012, include:

 

   

39% oil, 30% NGLs and 31% natural gas;

 

   

34% proved developed;

 

   

100% operated;

 

   

Reserve life of more than 30 years based on 2012 production of 2.9 MMBoe;

 

   

Standardized measure of discounted future net cash flows (“Standardized Measure”) of $494.2 million; and

 

   

PV-10 of $830.9 million.

PV-10 is our estimate of the present value of future net revenues from proved oil, NGL and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates for future income taxes. Estimated future net revenues are discounted at an annual rate of 10% to determine their present value. PV-10 is a financial measure that is not determined in accordance with accounting principles generally accepted in the United States (“GAAP”), and generally differs from the Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the Standardized Measure, as computed under GAAP. See Item 2. “Properties — Proved Oil and Gas Reserves” for a reconciliation of PV-10 to the Standardized Measure.

At December 31, 2012, we owned and operated 594 producing oil and gas wells in the Permian Basin, and we had an estimated 2,983 identified drilling and recompletion locations, of which 359 were proved.

We were incorporated in 2002. Our common stock began trading on the NASDAQ Global Market in the United States under the symbol “AREX” on November 8, 2007, and is now listed on the NASDAQ Global Select Market (“NASDAQ”). Our principal executive offices are located at One Ridgmar Centre, 6500 West Freeway, Suite 800, Fort Worth, Texas 76116. Our telephone number is (817) 989-9000.

2012 Activity

Our operations in 2012 focused on horizontal drilling in our Wolfcamp oil shale resource play in the Permian Basin. We drilled 26 horizontal wells in 2012, compared to 13 horizontal wells in 2011. Our early

 

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results in the Wolfcamp play led us to invest in building an infrastructure system that we believe will reduce drilling and completion costs, improve drilling and completion efficiencies, reduce fresh water use and ensure transportation for our crude oil production to market. We plan to continue to develop the Wolfcamp shale in Project Pangea in 2013. Focusing on the Wolfcamp shale allows us to use our operating, technical and regional expertise that is important to interpreting geological and operating trends, enhancing production rates and maximizing well recovery.

Production Growth

Production for 2012 totaled 2.9 MMBoe (7.9 MBoe/d), compared to 2.3 MMBoe (6.4 MBoe/d) in 2011, a 24% increase. Production for 2012 was 34% oil, 31% NGLs and 35% natural gas. Our continued development of Project Pangea increased oil production 101% in 2012, compared to 2011. On average, we operated two horizontal rigs and one vertical rig in 2012, and drilled a total of 46 gross (45.8 net) wells, of which 10 gross (9.9 net) were waiting on completion at December 31, 2012. We also recompleted 19 gross (19 net) wells in the Wolffork in 2012.

Reserve Growth

In 2012, our estimated proved reserves increased 24%, or 18.5 MMBoe, to 95.5 MMBoe from 77.0 MMBoe. Our proved reserves at year-end 2012 were 39% oil, 30% NGLs and 31% natural gas, compared to 23% oil, 38% NGLs and 39% natural gas at year-end 2011. During 2012, our proved oil reserves increased 19.2 MMBbls, or 106%, to 37.3 MMBbls from 18.1 MMBbls in 2011. Reserve growth, and especially our oil reserve growth, in 2012 was driven by results in our Wolfcamp oil shale resource play.

2012 Equity Offering

In September 2012, we sold 5.0 million shares of common stock in an underwritten public equity offering at $30.50 per share. In October 2012, the underwriters exercised their option and purchased an additional 325,000 shares. After deducting underwriting discounts and transaction costs of approximately $8.0 million, we received net proceeds of approximately $154.4 million. We used the proceeds of the 2012 equity offering to repay outstanding borrowings under our revolving credit facility, fund our capital expenditures for the development of our Wolfcamp oil shale resource play and for general working capital needs.

Plans for 2013

In September 2012, we announced a 2013 capital budget of $260 million, which includes three rigs to drill horizontal wells targeting the Wolfcamp shale. We expect that our horizontal drilling in Project Pangea in 2013 will include pad drilling, which we believe will improve operating efficiencies and resource recoveries, while reducing facilities costs and surface impact. We also may drill vertical wells targeting the Wolffork or recomplete Canyon Sands wells in the Wolffork during 2013. Our objectives for 2013 include advancing our understanding of optimal well spacing, testing multi-zone potential to enhance hydrocarbon recovery in our Wolffork targets and improving our cost structure.

Our 2013 capital budget is subject to change depending upon a number of factors, including additional data on our Wolfcamp oil shale resource play, results of horizontal and vertical drilling, completions and recompletions, including pad drilling, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil, NGLs and gas, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.

Markets and Customers

The revenues generated by our operations are highly dependent upon the prices of, and supply and demand for, oil, NGLs and gas. The price we receive for our oil, NGL and gas production depends on numerous factors

 

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beyond our control, including seasonality, the condition of the domestic and global economies, particularly in the manufacturing sectors, political conditions in other oil and gas producing countries, the extent of domestic production and imports of oil, NGLs and gas, the proximity and capacity of gas pipelines and other transportation facilities, supply and demand for oil, NGLs and gas, the marketing of competitive fuels and the effects of federal, state and local regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

The following table summarizes the top five purchasers of our oil, NGL and gas sales for 2012, excluding realized commodity derivative settlements.

 

Purchaser

   Percent of Oil, NGL
and Gas Sales
 

Shell Trading (US) Company (“Shell”)

                   22

BML, Inc. (“BML”)

     22   

Belvan Partners, LP (“WTG”)

     20   

DCP Midstream, LLC (“DCP”)

     17   

Plains Marketing, LP (“Plains”)

     6   
  

 

 

 

Total

     87
  

 

 

 

As of December 31, 2012, we had dedicated all of our oil production from northern Project Pangea and Pangea West for 10 years to an oil pipeline joint venture in which we own a 50% equity interest. In addition, as of December 31, 2012, we had contracted to sell all of our NGLs and natural gas production from Project Pangea to DCP through January 2016.

Commodity Derivative Activity

We enter into financial swaps and options to mitigate portions of the risk of market price fluctuations related to future oil and gas production. All derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are currently recognized in the statement of operations unless specific commodity derivative accounting criteria are met and contracts have been designated as cash flow hedge instruments. For qualifying cash-flow commodity derivatives, the gain or loss on the derivative is deferred in accumulated other comprehensive income to the extent the commodity derivative is effective. The ineffective portion of the commodity derivative is recognized immediately in the statement of operations. Gains and losses on commodity derivative instruments included in accumulated other comprehensive income are reclassified to oil and gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for commodity derivative accounting treatment are recorded as derivative assets and liabilities at fair value in the balance sheet, and the associated unrealized gains and losses are recorded as current income or expense in the statement of operations.

Historically, we have not designated our derivative instruments as cash-flow commodity derivatives. We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized gain (loss) on commodity derivatives.”

Title to Properties

Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business.

We believe that we have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we make a general investigation of title at the time we acquire undeveloped

 

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properties. We receive title opinions of counsel before we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use of the properties in the operation of our business.

Oil and Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil, NGLs and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 20% to 25%, resulting in a net revenue interest to us generally ranging from 80% to 75%.

Seasonality

Demand for oil, NGLs and natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Competition

The oil and gas industry is highly competitive, and we compete for personnel, prospective properties, producing properties and services with a substantial number of other companies that have greater resources. Many of these companies explore for, produce and market oil and gas, carry on refining operations and market the end products on a worldwide basis. We also face competition from alternative fuel sources, including coal, heating oil, imported LNG, nuclear and other nonrenewable fuel sources, and renewable fuel sources such as wind, solar, geothermal, hydropower and biomass. Competitive conditions may also be substantially affected by various forms of energy legislation and/or regulation considered from time-to-time by the United States government. It is not possible to predict whether such legislation or regulation may ultimately be adopted or its precise effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil, NGLs and gas and may prevent or delay the commencement or continuation of our operations.

Hydraulic Fracturing

Hydraulic fracturing is an important process and has been commonly used in the completion of unconventional oil and gas wells in shale and tight sand formations since the 1950s. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate oil and gas production. It is important to us because it provides access to oil and gas reserves that previously were uneconomical to produce.

We currently use hydraulic fracturing to complete both horizontal and vertical wells in the Permian Basin. We engage third parties to provide hydraulic fracturing services to us for completion of these wells. While hydraulic fracturing is not required to maintain our leasehold acreage that is currently held by production from existing wells, it will be required in the future to develop the proved non-producing and proved undeveloped reserves associated with this acreage. All of our proved non-producing and proved undeveloped reserves associated with future drilling, completion and recompletion projects will require hydraulic fracturing.

We believe we have followed, and intend to continue to follow, applicable industry standard practices and legal requirements for groundwater protection in our operations that are subject to supervision by state regulators.

 

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These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by applicable state regulatory agencies, and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design is intended to prevent contact between the fracturing fluid and any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure-tested before perforating the new completion interval.

Injection rates and pressures are monitored at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. We believe we have adequate procedures in place to address abrupt changes to the injection pressure or annular pressure.

Texas regulations currently require disclosure of the components in the solutions used in hydraulic fracturing operations. Over 99% (by mass) of the ingredients we use in hydraulic fracturing are water and sand. The remainder of the ingredients are chemical additives that are managed and used in accordance with applicable requirements.

Hydraulic fracturing requires the use of a significant amount of water. Upon flowback of the water, we dispose of it in a way that we believe minimizes the impact to nearby surface water by disposing into approved disposal facilities or injection wells. Currently our primary sources of water in Project Pangea are the nonpotable Santa Rosa and potable Edwards-Trinity (Plateau) aquifers. We use water from on-lease water wells that we have drilled, and we purchase water from off-lease water wells. We also plan to reuse and recycle flow-back and produced water in 2013.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read “Business — Regulation — Environmental Laws and Regulation” and “Business — Regulation — Hydraulic Fracturing.” For related risks to our stockholders, please read “Risk Factors — Federal and state legislation and regulatory initiatives and private litigation relating to hydraulic fracturing could stop or delay our development project and result in materially increased costs and additional operating restrictions.”

Regulation

The oil and gas industry in the United States is subject to extensive regulation by federal, state and local authorities. At the federal level, various federal rules, regulations and procedures apply, including those issued by the U.S. Department of Interior, the U.S. Department of Transportation (the “DOT”) (Office of Pipeline Safety) and the U.S. Environmental Protection Agency (the “EPA”). At the state and local level, various agencies and commissions regulate drilling, production and midstream activities. These federal, state and local authorities have various permitting, licensing and bonding requirements. Various remedies are available for enforcement of these federal, state and local rules, regulations and procedures, including fines, penalties, revocation of permits and licenses, actions affecting the value of leases, wells or other assets, and suspension of production. As a result, there can be no assurance that we will not incur liability for fines, penalties or other remedies that are available to these federal, state and local authorities. However, we believe that we are currently in material compliance with federal, state and local rules, regulations and procedures, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations.

Transportation and Sale of Oil

Sales of crude oil and condensate are not currently regulated and are made at negotiated prices. Our sales of crude oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by the Federal Energy Regulation Commission (“FERC”) pursuant to the Interstate Commerce Act (“ICA”), Energy Policy Act of 1992 (“EPAct 1992”), and the rules and regulations promulgated under those laws. The ICA and its regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products, be just and reasonable and non-discriminatory and that such rates, terms and conditions of service be filed with FERC.

 

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Intrastate oil pipeline transportation rates are also subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state-to-state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

The transportation of oil by truck is also subject to federal, state and local rules and regulations, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials and are administered by the DOT.

Transportation and Sale of Natural Gas and NGLs

FERC regulates interstate gas pipeline transportation rates and service conditions under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those statutes. FERC also regulates interstate NGL pipelines under various federal laws and regulations. Although FERC does not regulate oil and gas producers such as us, FERC’s actions are intended to facilitate increased competition within all phases of the oil and gas industry and its regulation of third-party pipelines and facilities could indirectly affect our ability to transport or market our production. To date, FERC’s policies have not materially affected our business or operations.

Regulation of Production

Oil, NGL and gas production is regulated under a wide range of federal and state statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The state in which we operate, Texas, has regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the regulation of spacing, and requirements for plugging and abandonment of wells. Also, Texas imposes a severance tax on production and sales of oil, NGLs and gas within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental Laws and Regulations

In the United States, the exploration for and development of oil and gas and the drilling and operation of wells, fields and gathering systems are subject to extensive federal, state and local laws and regulations governing environmental protection as well as discharge of materials into the environment. These laws and regulations may, among other things:

 

   

require the acquisition of various permits before drilling begins;

 

   

require the installation of expensive pollution controls or emissions monitoring equipment;

 

   

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, completion, production, transportation and processing activities;

 

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suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, endangered species habitat, and other protected areas; and

 

   

require remedial measures to mitigate and remediate pollution from historical and ongoing operations, such as the closure of waste pits and plugging of abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.

Governmental authorities have the power to enforce compliance with environmental laws, regulations and permits, and violations are subject to injunction, as well as administrative, civil and criminal penalties. The effects of existing and future laws and regulations could have a material adverse impact on our business, financial condition and results of operations. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretations 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 business, financial condition or results of operations. Moreover, accidental releases or spills and ground water contamination may occur in the course of our operations, and we may incur significant costs and liabilities as a result of such releases, spills or contamination, including any third-party claims for damage to property, natural resources or persons. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this will continue in the future.

The following is a summary of some of the existing environmental laws, rules and regulations that apply to our business operations.

Hazardous Substance Release

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as the Superfund law, and comparable state statutes impose strict liability, and under certain circumstances, joint and several liability, 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 strict, joint and several liabilities for the costs of investigating releases of hazardous substances, 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. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA.

Waste Handling

The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of 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 water and most of the other wastes associated with the exploration, development and production of oil or gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could increase our operating expenses, which could have a material adverse effect on our business, financial condition and results of operations.

 

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We currently own or lease properties that for many years have been used for oil and gas exploration, production and development activities. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on, under or from the properties owned or leased by us or on, under or from other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or released on, at, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or contamination, or to perform remedial activities to prevent future contamination.

Air Emissions

The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions at specified sources. In particular, on April 18, 2012, the EPA issued new regulations under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”). The new regulations are designed to reduce volatile organic compound (“VOC”) emissions from hydraulically-fractured natural gas wells, storage tanks and other equipment. The regulations established a phase-in period that extends until January 2015. During the phase-in period, owners and operators of hydraulically-fractured natural gas wells (wells drilled principally for the production of natural gas) must either flare their emissions or use so-called “green completion” technology. Green completions allow for the recovery of natural gas that formerly would have been vented or flared. After January 2015, all newly fractured natural gas wells must use green completion technology. We do not expect that the NSPS or NESHAP will have a material adverse effect on our business, financial condition or results of operations. However, any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements or use specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.

Greenhouse Gas Emissions

Congress has, from time-to-time, considered legislation to reduce emissions of GHGs. The current Congress is likely to continue to consider similar bills. Moreover, almost half of the states have already taken legal measures to reduce emissions of GHGs through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs or other mechanisms. Most 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 gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Many states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.

In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to human 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. These findings by the EPA allow the agency to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In response to its endangerment finding, the EPA has adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which would regulate

 

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emissions of GHGs from large stationary sources of emissions such as power plants or industrial facilities. The motor vehicle rule was finalized in April 2010 and became effective in January 2011, but it does not require immediate reductions in GHG emissions. In March 2012, the EPA proposed GHG emissions standards for fossil fuel-powered electric utility generating units that would require new plants to meet an output-based standard of 1,000 pounds of carbon dioxide equivalent per megawatt-hour. If the proposed regulation is adopted, it could have a significant impact on the electrical generation industry and may favor the use of natural gas over other fossil fuels such as coal in new plants. The EPA has also indicated that it will propose new GHG emissions standards for refineries, but specific proposed regulations are not expected to be issued until mid-2013.

In December 2010, the EPA enacted final rules on mandatory reporting of GHGs. In November and December 2011, the EPA published amendments to the rule containing technical and clarifying changes to certain GHG reporting requirements and a six-month extension for reporting GHG emissions from petroleum and natural gas industry sources. Under the amended rule, certain onshore oil and natural gas production, processing, transmission, storage and distribution facilities are required to report their GHG emissions on an annual basis beginning on September 28, 2012. Our operations in the Permian Basin are subject to the EPA’s mandatory reporting rules and we believe that we are in substantial compliance with such rules. We do not expect that the EPA’s mandatory GHG reporting requirements will have a material adverse effect on our business, financial condition or results of operations.

The adoption of additional legislation or regulatory programs to monitor or reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory requirements. In addition, the EPA has stated that the data collected from GHG emissions reporting programs may be the basis for future regulatory action to establish substantive GHG emissions factors. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our future business, financial condition and results of operations.

Water Discharges

The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws, impose restrictions and strict controls on the discharge of pollutants and fill material, including spills and leaks of oil and other substances into regulated waters, including wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, an analogous state agency, or, in the case of fill material, the United States Army Corps of Engineers. 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.

In October 2011, the EPA announced that it intends to develop national standards for wastewater discharges produced by natural gas extraction from shale and coalbed methane formations. The EPA is expected to issue proposed regulations establishing wastewater discharge standards for coalbed methane wastewater in 2013 and for shale gas wastewater in 2014. For shale gas wastewater, the EPA will consider imposing pre-treatment standards for discharges to a wastewater treatment facility. Produced and other flowback water from our current operations in the Permian Basin is typically re-injected into underground formations that do not contain potable water. To the extent that re-injection is not available for our operations and discharge to wastewater treatment facilities is required, new standards from the EPA could increase the cost of disposing wastewater in connection with our operations.

The Safe Drinking Water Act, Groundwater Protection and the Underground Injection Control Program

The federal Safe Drinking Water Act (“SDWA”) and the Underground Injection Control program (the “UIC program”) promulgated under the SDWA and state programs regulate the drilling and operation of salt water

 

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disposal wells. The EPA has delegated administration of the UIC program in Texas to the Railroad Commission of Texas (“RRC”). Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater. Contamination of groundwater by oil and gas drilling, production and related operations may result in fines, penalties and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third-party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages and bodily injury.

Hydraulic Fracturing

Hydraulic fracturing is the subject of significant focus among some environmentalists, regulators and the general public. Concerns over potential hazards associated with the use of hydraulic fracturing and its impact on the environment have been raised at all levels, including federal, state and local, as well as internationally. There have been claims that hydraulic fracturing may contaminate groundwater, reduce air quality or cause earthquakes. Hydraulic fracturing requires the use and disposal of water, and public concern has been growing over its possible effects on drinking water supplies, as well as the adequacy of water supply.

The Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. In the past, legislation has been introduced in, but not passed by, Congress that would amend the SDWA to repeal this exemption. If similar legislation were enacted, it 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. Future federal legislation could also require the reporting and public disclosure of chemical additives used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemical additives used in the fracturing process could adversely affect groundwater. If federal legislation regulating hydraulic fracturing is adopted in the future, it could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

In 2010, the EPA asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the UIC program by posting a requirement on its website that requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations. Industry groups filed suit challenging the EPA’s decision as a “final agency action” and, therefore, a violation of the notice-and-comment rulemaking procedures of the Administrative Procedures Act. In February 2012, the EPA and industry reached a settlement under which the EPA will modify the informal policy posted on its website concerning the need for permits under the UIC program. However, the settlement does not reflect agreement on the issue of hydraulic fracturing regulation under the SDWA, and the EPA’s continued assertion of its regulatory authority under the SDWA could result in extensive requirements that could cause additional costs and delays in the hydraulic fracturing process.

In addition to the above actions of the EPA, certain members of the Congress have called upon (i) the Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; (ii) the Securities and Exchange Commission (the “SEC”) to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale by means of hydraulic fracturing; and (iii) the Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. The SEC has issued subpoenas to certain shale gas producers requesting information on proved reserve estimates from shale gas wells and the actual productivity of producing shale gas wells. The media has also reported that the New York attorney general has issued subpoenas to certain oil and gas companies seeking information regarding shale gas wells.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing. The White House Council on Environmental Quality is coordinating an

 

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administration-wide review of hydraulic fracturing, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has also begun a study of the potential environmental impacts of hydraulic fracturing. The EPA issued a progress report in December 2012, and final results are expected in 2014. In addition, the U.S. Department of Energy conducted an investigation into practices the agency could recommend to better protect the environment from using hydraulic fracturing. The Shale Gas Subcommittee of the Secretary of Energy Advisory Board released its “90-day” report on August 18, 2011, and its final report on November 18, 2011, proposing recommendations to reduce the potential environmental impacts from shale gas production. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. These ongoing or proposed investigations and studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in hydraulic fracturing. For example, pursuant to legislation adopted by the State of Texas in June 2011, the RRC enacted a rule in December 2011, requiring disclosure to the RRC and the public of certain information regarding additives, chemical ingredients, concentrations and water volumes used in hydraulic fracturing. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general and hydraulic fracturing in particular.

If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted, it could become more difficult or costly for us to drill and produce oil and gas from shale and tight sands formations and become easier for third parties opposing hydraulic fracturing to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to delays, additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and higher costs. These new laws or regulations could cause us to incur substantial delays or suspensions of operations and compliance costs and could have a material adverse effect on our business, financial condition and results of operations.

Compliance

We believe that we are in substantial compliance with all existing environmental laws and regulations that apply to our current operations and that our ongoing compliance with existing requirements will not have a material adverse effect on our business, financial condition or results of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2012. In addition, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital or operating expenditures during 2013. However, the passage of additional or more stringent laws or regulations in the future could have a negative effect on our business, financial condition and results of operations, including our ability to develop our undeveloped acreage.

Threatened and Endangered Species, Migratory Birds and Natural Resources

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. The United States Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where takings of, or harm to, species or damages to wetlands, habitat or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and gas exploration activities or

 

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seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and may seek natural resources damages and, in some cases, criminal penalties.

OSHA and Other Laws and Regulations

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 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. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Employees

As of February 15, 2013, we had 95 full-time employees, 53 of whom are field personnel. We regularly use independent contractors and consultants to perform various field and other services. None of our employees are represented by a labor union or covered by any collective bargaining agreement. We believe that our relations with our employees are excellent.

Insurance Matters

As is common in the oil and gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Available Information

We maintain an internet website under the name www.approachresources.com. The information on our website is not a part of this report. We make available, free of charge, on 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 and Compensation and Nominating Committee, and our Code of Conduct, are available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at One Ridgmar Centre, 6500 West Freeway, Suite 800, Fort Worth, Texas 76116.

We file annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 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 an internet website that contains reports, proxy and information statements, and other information regarding issuers, including Approach, that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov. Information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

ITEM 1A.    RISK FACTORS

You should carefully consider the risk factors set forth below as well as the other information contained in this report before investing in our common stock. Any of the following risks could materially and adversely affect our business, financial condition and results of operations. In such a case, you may lose all or part of your investment. The risks described below are not the only ones we face. Additional risks and uncertainties not currently known to us or those we currently view to be immaterial may also materially adversely affect our business, financial condition and results of operations.

 

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Risks Related to the Oil and Gas Industry and Our Business

Drilling, exploring for and producing oil and gas are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

Our future financial condition and results of operations will depend on the success of our drilling, exploration and production activities. These activities are subject to numerous risks beyond our control, including the risk that drilling will not result in economic oil and gas production or increases in reserves. Many factors may curtail, delay or cancel our scheduled development projects, including:

 

   

decline in oil, NGL and gas prices;

 

   

compliance with governmental regulations, which may include limitations on hydraulic fracturing, access to water or the discharge of greenhouse gases;

 

   

inadequate capital resources;

 

   

limited transportation services and infrastructure to deliver the oil and gas we produce to market;

 

   

inability to attract and retain qualified personnel;

 

   

unavailability or high cost of drilling and completion equipment, services or materials;

 

   

unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents;

 

   

lack of acceptable prospective acreage;

 

   

adverse weather conditions;

 

   

surface access restrictions;

 

   

title problems; and

 

   

mechanical difficulties.

Oil, NGL and gas prices are volatile, and a decline in oil, NGL or gas prices could significantly affect our business, financial condition and results of operations and our ability to meet our capital expenditure requirements and financial commitments.

Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil, NGLs and gas. The markets for these commodities are volatile, and even relatively modest drops in prices can affect significantly our financial results and impede our growth. Prices for oil, NGLs and gas fluctuate widely in response to relatively minor changes in the supply and demand for these commodities, market uncertainty and a variety of additional factors beyond our control, such as:

 

   

domestic and foreign supply of oil, NGLs and gas;

 

   

domestic and foreign consumer demand for oil, NGLs and gas;

 

   

overall United States and global economic conditions;

 

   

commodity processing, gathering and transportation availability and the availability of refining capacity;

 

   

price and availability of alternative fuels;

 

   

price and quantity of foreign imports;

 

   

domestic and foreign governmental regulations;

 

   

political conditions in or affecting other gas producing and oil producing countries;

 

   

weather conditions, including unseasonably warm winter weather and tropical storms; and

 

   

technological advances affecting oil, NGL and gas consumption.

 

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Further, oil, NGL and gas prices do not necessarily fluctuate in direct relationship to each other, and these prices continued to be volatile in 2012. Advanced drilling and completion technologies, such as horizontal drilling and hydraulic fracturing, have resulted in increased investment by oil and gas producers in developing U.S. shale gas and, more recently, tight oil projects. The results of higher investment in the exploration for and production of oil and gas and other factors, such as global economic and financial conditions discussed below, may cause the price of oil and gas to fall. Lower oil and gas prices may not only cause our revenues to decrease but also may reduce the amount of oil and gas that we can produce economically. Substantial decreases in oil and gas prices would render uneconomic some or all of our drilling locations. This may result in our having to impair our estimated proved reserves and could have a material adverse effect on our business, financial condition and results of operations. Further, if oil, NGL or gas prices significantly decline for an extended period of time, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future debt or obtain additional capital on attractive terms, all of which can affect the value of our common stock.

Future economic conditions in the U.S. and international markets could materially and adversely affect our business, financial condition and results of operations.

The U.S. and other world economies continue to experience the after-effects of a global recession and credit market crisis. More volatility may occur before a sustainable growth rate is achieved either domestically or globally. Even if such growth rate is achieved, such a rate may be lower than the U.S. and international economies have experienced in the past. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower, future economic growth rate will result in decreased demand for our oil, NGL and gas production and lower commodity prices, and consequently reduce our revenues, cash flows from operations and our profitability.

If gas prices remain low or decline further, or if oil and NGL prices decline, we may be required to write down the carrying values of our properties. Current SEC rules also could require us to write down our proved undeveloped reserves in the future.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down is a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. In addition, current SEC rules require that proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years, unless specific circumstances justify a longer time. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our development projects. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required timeframe. For example, for the year ended December 31, 2012, we reclassified 8.9 MMBoe of proved undeveloped reserves as probable undeveloped. These reserves were attributable to vertical Canyon locations in southeast Project Pangea. We postponed development of these deeper locations beyond five years from initial booking to integrate their development with the shallower Wolfcamp and Wolffork target zones.

Changes in the differential between benchmark prices of oil and gas and the reference or regional index price used to price our actual oil and gas sales could have a material adverse effect on our financial condition and results of operations.

The reference or regional index prices that we use to price our oil and gas sales sometimes reflect a discount to other, relevant benchmark prices, such as WTI NYMEX or WTI Cushing. The difference between a benchmark price and the price we reference in our sales contracts is called a basis differential. For example, due to increasing oil production in the Permian Basin and shortage of takeaway capacity in the area, the average monthly difference between WTI Cushing and WTI Midland (which is typically subtracted from our crude oil

 

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sales price) reached a high of approximately $14.00/Bbl in the first quarter of 2013. Although this differential narrowed in the latter part of the first quarter of 2013, we cannot accurately predict movement of oil and gas differentials and we may not be able to effectively manage this risk through derivatives or hedging transactions.

We engage in commodity derivative transactions which involve risks that can harm our business.

To manage our exposure to price risks in the marketing of our production, we enter into oil, NGL and gas price and basis differential commodity derivative agreements. While intended to reduce the effects of volatile commodity prices and basis differentials, such transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the commodity derivative, or if the basis spread changes substantially from the basis differential established by the commodity derivative. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which our production is lower than expected, there is change of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative arrangement or the counterparties to the commodity derivative agreements fail to perform under the contracts.

We are subject to complex governmental laws and regulations that may adversely affect the cost, manner and feasibility of doing business.

Our oil and gas drilling, production and gathering operations are subject to complex and stringent laws and regulations. To operate in compliance with these laws and regulations, we must obtain and maintain numerous permits and approvals from various federal, state and local governmental authorities. We may incur substantial costs to comply with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations apply to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by government authorities, could have a material adverse effect on our business, financial condition and results of operations. See “Business — Regulation” for a further description of the laws and regulations that affect us.

Federal and state legislation and regulatory initiatives and private litigation relating to hydraulic fracturing could stop or delay our development project and result in materially increased costs and additional operating restrictions.

All of our proved non-producing and proved undeveloped reserves associated with future drilling, completion and recompletion projects will require hydraulic fracturing. See Item 1. “Business — Hydraulic Fracturing” for a discussion of the importance of hydraulic fracturing to our business, and Item 1. “Business — Regulation — Hydraulic Fracturing” for a discussion of regulatory developments regarding hydraulic fracturing. If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to drill and produce from, as well as make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to permitting delays and increases in costs. These developments, as well as new laws or regulations, could cause us to incur substantial compliance costs, and compliance or the consequences of our failure to comply could have a material adverse effect on our financial condition and results of operations. In addition, if we are unable to use hydraulic fracturing in completing our wells or hydraulic fracturing becomes prohibited or significantly regulated or restricted, we could lose the ability to drill and complete the projects for our proved reserves and maintain our current leasehold acreage, which would have a material adverse effect on our future business, financial condition and operating results.

 

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Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner.

Water is an essential component of our drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local landowners and other sources for use in our operations. During the last two years, West Texas has experienced extreme drought conditions. As a result of the severe drought, some local water districts may begin restricting the use of water under their jurisdiction for drilling and hydraulic fracturing to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, NGLs and gas, which could have an adverse effect on our business, financial condition and results of operations.

Moreover, new environmental initiatives and regulations could include restrictions on 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 gas. Compliance with environmental regulations and permit requirements for the withdrawal, storage and use of surface water or ground water necessary for hydraulic fracturing of our wells may increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations and cash flows.

Climate change legislation or regulations regulating emissions of GHGs and VOCs could result in increased operating costs and reduced demand for the oil and gas we produce.

Both houses of Congress have actively considered legislation to reduce emissions of GHGs, and some states have already taken measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs. Most of these cap-and-trade programs require either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances are expected to escalate significantly in cost over time.

In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to human 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. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has also issued final regulations under the NSPS and NESHAP designed to reduce VOCs. See Item 1. “Business — Regulation — Environmental Laws and Regulations — Greenhouse Gase Emissions” and “— Air Emissions” for a discussion of regulatory developments regarding GHG and VOC emissions.

The adoption of legislation or regulatory programs to reduce GHG or VOC emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries 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 GHG or VOC emissions could have a material adverse effect on our business, financial condition and results of operations.

Environmental laws and regulations may expose us to significant costs and liabilities.

There is inherent risk of incurring significant environmental costs and liabilities in our oil and gas operations due to the handling of petroleum hydrocarbons and generated wastes, the occurrence of air emissions and water discharges from work-related activities and the legacy of pollution from historical industry operations

 

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and waste disposal practices. We may incur joint and several or strict liability under these environmental laws and regulations in connection with spills, leaks or releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities, some of which have been used for exploration, production or development activities for many years and by third parties not under our control. In particular, the number of private, civil lawsuits involving hydraulic fracturing has risen in recent years. Since late 2009, multiple private lawsuits alleging ground water contamination have been filed in the U.S. against oil and gas companies, primarily by landowners who leased oil and gas rights to defendants, or by landowners who live close to areas where hydraulic fracturing has taken place. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business, financial condition and results of operations. We may not be able to recover some or any of these costs from insurance.

Changes in tax laws may adversely affect our results of operations and cash flows.

The President’s proposed budget for fiscal year 2013 contains proposed legislation that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key United States federal income tax incentives currently available to oil and gas exploration and production companies. These changes include (i) elimination of current deductions for intangible drilling costs (“IDCs”); (ii) repeal of the percentage depletion allowance for oil and gas properties; (iii) elimination of the deduction for certain U.S. production activities; and (iv) extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or otherwise limit certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively impact our financial condition and results of operations. In particular, we estimate that the elimination of the current deductibility of IDCs could impact our cash flows from operations by over $400 million over a five-year period from 2013 through 2017.

Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all.

Our exploration, development and acquisition activities require substantial capital expenditures. For example, according to our year-end 2012 reserve report, the estimated capital required to develop our current proved oil and gas reserves is $1 billion. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings under our credit facility and public equity financings. Future cash flows are subject to a number of variables, including the production from existing wells, prices of oil, NGLs and gas and our success in developing and producing new reserves. We do not expect our cash flow from operations to be sufficient to cover our current expected capital expenditure budget and we may have limited ability to obtain the additional capital necessary to sustain our operations at current levels. We may not be able to obtain debt or equity financing on favorable terms or at all. The failure to obtain additional financing could cause us to scale back our exploration and development operations, which in turn could lead to a decline in our oil and gas production and reserves, and in some areas a loss of properties.

Our lenders can limit our borrowing capabilities, which may materially impact our operations.

At December 31, 2012, we had $106 million outstanding under our revolving credit facility, and our borrowing base was $280 million. The borrowing base under our revolving credit facility is redetermined semi-annually based upon a number of factors, including commodity prices and reserve levels. In addition to such semi-annual redeterminations, our lenders may request one additional redetermination during any 12-month period. Upon a redetermination, our borrowing base could be substantially reduced, and if the amount outstanding under our credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings. We use cash flow from operations and bank borrowings to fund our exploration, development and acquisition activities. A reduction in our borrowing base could limit those

 

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activities. In addition, we may significantly change our capital structure to make future acquisitions or develop our properties. Changes in capital structure may significantly increase our debt. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance, which is affected by general economic conditions and financial, business and other factors, many of which are beyond our control.

Our future reserve and production growth depends on the success of our Wolfcamp oil shale resource play, which has a limited operational history and is subject to change.

We began drilling wells in the Wolfcamp play relatively recently. The wells that have been drilled or recompleted in these areas represent a very small sample of our large acreage position, and we cannot assure you that our new horizontal or vertical wells or recompletions of existing Canyon wells will be successful. As of December 31, 2012, we had proved reserves of 60.1 MMBoe attributable to the Wolfcamp play. Accordingly, we have limited information on the amount of reserves that will ultimately be recovered from our Wolfcamp wells. We continue to gather data about our prospects in the Wolfcamp play, and it is possible that additional information may cause us to change our drilling schedule or determine that prospects in some portion of our acreage position should not be developed at all.

Failure to effectively execute and manage our single major development project, Project Pangea, could result in significant delays, cost overruns, limitation of our growth, damage to our reputation and a material adverse effect on our business, financial condition and results of operations.

We have an extensive inventory of identified drilling locations in our development project (Project Pangea) in the Wolfcamp oil shale resource play major; however, Project Pangea is our core asset and our only development project. As we achieve more results in Project Pangea, we have expanded our horizontal development project there. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal operating and financial controls. Our ability to successfully develop and manage this project will depend on, among other things:

 

   

the extent of our success in drilling and completing horizontal Wolfcamp wells;

 

   

our ability to control costs and manage drilling and completion risks;

 

   

our ability to finance development of the project;

 

   

our ability to attract, retain and train qualified personnel with the skills required to develop the project in a timely and cost-effective manner; and

 

   

our ability to implement and maintain effective operating and financial controls and reporting systems necessary to develop and operate the project.

We may not be able to compensate for, or fully mitigate, these risks.

Currently, substantially all of our producing properties are located in two counties in Texas, making us vulnerable to risks associated with having our production concentrated in a small area.

Substantially all of our producing properties and estimated proved reserves are concentrated in two counties in Texas: Crockett and Schleicher. As a result of this concentration, we are disproportionately exposed to the natural decline of production from these fields as well as the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailments of production, service delays, natural disasters or other events that impact this area.

 

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Because of our geographic concentration, our purchaser base is limited, and the loss of one of our key purchasers or their inability to take our oil, NGLs or gas or could adversely affect our financial results.

In 2012, Shell, BML, WTG, DCP and Plains collectively accounted for 87% of our total oil, NGL and gas sales, excluding realized commodity derivative settlements. As of December 31, 2012, we had dedicated all of our oil production from northern Project Pangea and Pangea West for 10 years to an oil pipeline joint venture in which we own a 50% equity interest. In addition, as of December 31, 2012, we had contracted to sell all of our NGL and natural gas production from Project Pangea to DCP through January 2016. To the extent that any of our major purchasers reduces their purchases of oil, NGLs or gas, is unable to take our oil, NGLs or gas due to infrastructure or capacity limitations or defaults on their obligations to us, we would be adversely affected unless we were able to make comparably favorable arrangements with other purchasers. These purchasers’ default or non-performance could be caused by factors beyond our control. A default could occur as a result of circumstances relating directly to one or more of these customers, or due to circumstances related to other market participants with which the customer has a direct or indirect relationship.

We depend on our management team and other key personnel. The loss of any of these individuals, or the inability to attract, train and retain additional qualified personnel, could adversely affect our business, financial condition and the results of operations and future growth.

Our success largely depends on the skills, experience and efforts of our management team and other key personnel and the ability to attract, train and retain additional qualified personnel. The loss of the services of one or more members of our senior management team or of our other employees with critical skills needed to operate our business could have a negative effect on our business, financial condition, results of operations and future growth. In January 2011, we entered into amended and restated employment agreements with J. Ross Craft, P.E., our President and Chief Executive Officer; and Steven P. Smart, our Executive Vice President and Chief Financial Officer; and new employment agreements with Qingming Yang, our Chief Operating Officer; J. Curtis Henderson, our Executive Vice President and General Counsel; and Ralph P. Manoushagian, our Executive Vice President — Land. If any of these officers or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. In addition, our ability to manage our growth, if any, will require us to effectively train, motivate and manage our existing employees and to attract, motivate and retain additional qualified personnel. Competition for these types of personnel is intense, and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.

Market conditions or transportation and infrastructure impediments may hinder our access to oil, NGL and gas markets or delay our production or sales.

Market conditions or the unavailability of satisfactory oil, NGL and gas processing and transportation services and infrastructure may hinder our access to oil, NGL and gas markets or delay our production or sales. Although currently we control the gathering systems for our operations in the Permian Basin, we do not have such control over the regional or downstream pipelines in and out of the Permian Basin. The availability of a ready market for our oil, NGL and gas production depends on a number of factors, including market demand and the proximity of our reserves to pipelines or trucking and rail terminal facilities. In addition, the amount of oil, NGLs and gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. As a result, we may not be able to sell, or may have to transport by more expensive means, the oil, NGL and gas that we produce, or we may be required to shut in oil or gas wells or delay initial production until the necessary gathering and transportation systems are available. Any significant curtailment in gathering system, transportation, pipeline capacity or significant delay in construction of necessary gathering and transportation facilities, could adversely affect our business, financial condition and results of operations.

 

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The unavailability or high cost of drilling rigs, equipment, materials, personnel and oilfield services could adversely affect our ability to execute our drilling and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs and delivery times of equipment, oilfield services and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling and completion crews rise as the number of active rigs in service increases. Increasing levels of exploration and production will increase the demand for oilfield services, and the costs of these services may increase, while the quality of these services may suffer. If the availability of equipment, crews, materials and services in the Permian Basin is particularly severe, our business, results of operations and financial condition could be materially and adversely affected because our operations and properties are concentrated in the Permian Basin.

Competition in the oil and gas industry is intense, and many of our competitors have resources that are greater than ours.

We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil and gas and securing equipment and skilled personnel. Many of our competitors are major and large independent oil and gas companies that have financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to develop and operate our current project, acquire additional prospects and discover reserves in the future will depend on our ability to hire and retain qualified personnel, evaluate and select suitable properties and consummate transactions and in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may not be able to compete successfully in the future in attracting and retaining qualified personnel, acquiring prospective reserves, developing reserves, marketing oil, NGLs and gas and raising additional capital.

Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. In certain instances, this could prevent drilling and production before the expiration date of leases for such locations.

Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil, NGL and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the identified drilling locations we have identified will ever be drilled or if we will be able to produce oil or gas from these or any other identified drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are obtained, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.

The use of geoscientific, petrophysical and engineering analyses and other technical or operating data to evaluate drilling prospects is uncertain and does not guarantee drilling success or recovery of economically producible reserves.

Our decisions to explore, develop and acquire prospects or properties targeting Wolfcamp and other zones in the Permian Basin and other areas depend on data obtained through geoscientific, petrophysical and engineering analyses, the results of which can be uncertain. Even when properly used and interpreted, data from whole cores, regional well log analyses, 3-D seismic and micro-seismic only assist our technical team in identifying hydrocarbon indicators and subsurface structures and estimating hydrocarbons in place. They do not

 

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allow us to know conclusively the amount of hydrocarbons in place and if those hydrocarbons are producible economically. In addition, the use of advanced drilling and completion technologies for our Wolfcamp development, such as horizontal drilling and multi-stage fracture stimulations, requires greater expenditures than our traditional development drilling strategies. Our ability to commercially recover and produce the hydrocarbons that we believe are in place and attributable to the Wolfcamp and other zones will depend on the effective use of advanced drilling and completion techniques, the scope of our development project (which will be directly affected by the availability of capital), drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approval and geological and mechanical factors affecting recovery rates. Our estimates of unproved reserves, estimated ultimate recoveries per well, hydrocarbons in place and resource potential may change significantly as development of our oil and gas assets provides additional data.

Unless we replace our oil and gas reserves, our reserves and production will decline.

Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues and cash flows will be adversely affected. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced, unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves.

We have leases and options for undeveloped acreage that may expire in the near future.

As of December 31, 2012, we held mineral leases or options in each of our areas of operations that are still within their original lease term and are not currently held by production. Unless we establish commercial production on the properties subject to these leases, most of these leases will expire between 2013 and 2016. If these leases or options expire, we will lose our right to develop the related properties. See Item 2. “Properties — Undeveloped Acreage Expirations” for a table summarizing the expiration schedule of our undeveloped acreage over the next three years. Acreage set to expire over the next three years accounts for 95% of our net undeveloped acreage, 17.2% of our proved undeveloped reserves and 11.3% of our total proved reserves.

Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of our proved reserves. We may experience production that is less than estimated and drilling costs that are greater than estimated in our reserve reports. These differences may be material.

The proved oil, NGL and gas reserves data included in this report are estimates. Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil, NGL and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

 

   

historical production from the area compared with production from other similar producing areas;

 

   

the assumed effects of regulations by governmental agencies;

 

   

assumptions concerning future oil, NGL and gas prices; and

 

   

assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.

Because all reserves estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:

 

   

the quantities of oil, NGL and gas that are ultimately recovered;

 

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the production and operating costs incurred;

 

   

the amount and timing of future development expenditures; and

 

   

future oil, NGL and gas prices.

As of December 31, 2012, approximately 66% of our proved reserves were proved undeveloped. Estimates of proved undeveloped reserves are even less reliable than estimates of proved developed reserves. Furthermore, different reserve engineers may make different estimates of reserves and future net revenues based on the same available data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material.

The PV-10 included in this report should not be considered as the current market value of the estimated oil and gas reserves attributable to our properties.

The non-GAAP financial measure, PV-10, is based on the average of the closing price on the first day of the month for the 12-month period prior to fiscal year end, while actual future prices and costs may be materially higher or lower. If oil, NGL and gas prices decline by 10% from $94.71 per Bbl of oil, $37.88 per Bbl of NGLs and $2.74 per MMBtu of gas, to $85.24 per Bbl of oil, $34.09 per Bbl of NGLs and $2.47 per MMBtu of gas, then our PV-10 as of December 31, 2012, would decrease from $830.9 million to approximately $633.7 million. The average market price received for our production for the month of December 2012 was $76.47 per Bbl of oil, $28.71 per Bbl of NGLs and $3.22 per Mcf of gas (after basis differential and Btu adjustments). Actual future net revenues also will be affected by factors such as the amount and timing of actual production, prevailing operating and development costs, supply and demand for oil and gas, increases or decreases in consumption and changes in governmental regulations or taxation.

Severe weather could have a material adverse impact on our business.

Our business could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:

 

   

curtailment of services;

 

   

weather-related damage to drilling rigs, resulting in suspension of operations;

 

   

weather-related damage to our producing wells or facilities;

 

   

inability to deliver materials to jobsites in accordance with contract schedules; and

 

   

loss of production.

Operating hazards or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.

The oil and gas business involves certain operating hazards such as well blowouts, cratering, explosions, uncontrollable flows of gas, oil or well fluids, fires, surface and subsurface pollution and contamination, and releases of toxic gas. The occurrence of one of the above may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. Our insurance might be inadequate to cover our liabilities. The insurance market in general and the energy insurance market in particular have been difficult markets over the past several years. Insurance costs are expected to continue to increase over the next few years, and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we incur liability at a time when we are not able to obtain liability insurance, then our business, results of operations and financial condition could be materially adversely affected.

 

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Our results are subject to quarterly and seasonal fluctuations.

Our quarterly operating results have fluctuated in the past and could be negatively impacted in the future as a result of a number of factors, including seasonal variations in oil, NGL and gas prices, variations in levels of production and the completion of development projects.

We have renounced any interest in specified business opportunities, and certain members of our board of directors and certain of our stockholders generally have no obligation to offer us those opportunities.

In accordance with Delaware law, we have renounced any interest or expectancy in any business opportunity, transaction or other matter in which our outside directors and certain of our stockholders, each referred to as a Designated Party, participates or desires to participate in that involves any aspect of the exploration and production business in the oil and gas industry. If any such business opportunity is presented to a Designated Party who also serves as a member of our board of directors, the Designated Party has no obligation to communicate or offer that opportunity to us, and the Designated Party may pursue the opportunity as he sees fit, unless:

 

   

it was presented to the Designated Party solely in that person’s capacity as a director of our Company and with respect to which, at the time of such presentment, no other Designated Party has independently received notice of, or otherwise identified the business opportunity; or

 

   

the opportunity was identified by the Designated Party solely through the disclosure of information by or on behalf of us.

As a result of this renunciation, our outside directors should not be deemed to have breached any fiduciary duty to us if they or their affiliates or associates pursue opportunities as described above and our future competitive position and growth potential could be adversely affected.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

As of the date of this filing, we have no unresolved comments from the staff of the SEC.

 

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ITEM 2.    PROPERTIES

Our operations are focused on the Wolfcamp oil shale resource play in the Permian Basin in West Texas. We also have minor operations in the East Texas Basin in East Texas. The following table is a summary of data for our operating areas for the year ended December 31, 2012.

 

Operating Area

   Total Gross
Acres
     Total Net
Acres
     Average
Daily
Production
(Boe/d)
     Percentage
of
Production
    Proved
Reserves
(MBoe)
     Percentage
of Proved
Reserves
 

Permian Basin

     167,407         147,537         7.84         99.4     95,342         99.9

East Texas Basin

     6,194         3,389         0.05         0.6     137         0.1
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

     173,601         150,926         7.89         100.0     95,479         100.0
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Permian Basin — Project Pangea and Pangea West

Our properties in the Permian Basin are located in Crockett and Schleicher Counties, Texas. We began operations in the Permian Basin through a farm-in agreement for 27,000 net acres in 2004 and have since increased our total acreage position to approximately 167,000 gross (148,000 net) acres as of year-end 2012. At December 31, 2012, we owned interests in approximately 594 gross (583.2 net) wells, all of which we operate. As of December 31, 2012, we had working and net revenue interests of approximately 100% and 76%, respectively, across Project Pangea and Pangea West.

Our acreage position in the Permian Basin is characterized by several commercial hydrocarbon zones. Our drilling targets include the Clearfork, Wolfcamp shale, Canyon Sands, Strawn and Ellenburger zones. Since we began drilling our Permian Basin properties in 2004, we have primarily produced our reserves from the Canyon Sands, Strawn and Ellenburger formations at depths ranging from 7,250 feet to 8,900 feet. The Canyon Sands were deposited in submarine fan and are tight sandstone reservoirs characterized by low permeability. We use a specialized foamed fracture stimulation treatment to increase permeability, which enhances production rates and well recovery. The Strawn formation is a fractured carbonate reservoir between the Canyon Sands and Ellenburger zones. The Ellenburger formation is a fractured carbonate and dolomite reservoir that does not require a specialized fracture stimulation treatment.

In 2010, we performed a detailed geological and petrophysical evaluation of the Clearfork, Dean and Wolfcamp shale formations, or “Wolffork,” above the Canyon Sands, Strawn and Ellenburger. In our evaluation we used logs, 3-D seismic, whole core data and regional mapping. The Wolffork is made up of three stacked pay zones, the Clearfork, Dean and Wolfcamp Shale formations with combined gross pay thickness of approximately 2,500 feet, which were deposited across Project Pangea and Pangea West by a combination of suspension, debris flow and turbidite processes. The Clearfork formation across our acreage position is a siltstone, shale and carbonate reservoir approximately 1,400 feet thick. Similarly, the Dean formation, which is approximately 150 feet thick, is a siltstone, shale and carbonate reservoir.

The Wolfcamp shale has gross pay thickness of approximately 1,000 to 1,200 feet across our acreage position. The Wolfcamp shale is a source rock that we believe has significant potential for hydrocarbons. The Wolfcamp shale is located in the oil-to-wet gas window across our Permian acreage position and is naturally fractured due to its proximity to the Ouachita-Marathon thrust belt and mineralogy, specifically the carbonate and quartz minerals. To better define and study this extensive column of rock, we have classified the Wolfcamp into four zones or “benches,” the A, B, C and D. Effectively developing the Wolfcamp shale may involve up to three lateral wellbores, each targeting a different interval, the Wolfcamp A, B and C.

We currently estimate that we have 2,983 drilling and recompletion locations targeting the horizontal Wolfcamp shale and the vertical Wolffork, 189 of which are proved, including:

 

   

2,096 horizontal Wolfcamp locations;

 

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329 vertical Wolffork locations;

 

   

398 vertical Canyon Wolffork locations; and

 

   

160 Wolffork recompletions

We also have identified 170 proved drilling locations targeting the Canyon Sands and deeper zones, and therefore our proved drilling locations in the Permian Basin total 359. The timing of drilling our identified locations is subject to a number of uncertainties and will be influenced by several factors, including commodity prices, capital requirements, well-spacing requirements and a continuation of the results from both our horizontal and vertical drilling.

In the Permian Basin, we consider the Wolffork interval to be a resource play. As such, the mapping of the gross interval for each of the producing formations under our acreage position is the main factor we considered in identifying our locations. In the general region and immediately around our acreage position, publicly available well data exists from a large number of vertical wells that have allowed us to define the areal extent of each of the producing intervals, whether the whole vertical Wolffork section or the targeted Clearfork and Wolfcamp shale. In addition to this publicly available well data, we have also used internally generated information from cores, 3-D seismic, open-hole logging and reservoir engineering to estimate the extent of the targeted intervals, the ability of such intervals to produce commercial quantities of hydrocarbons and the viability of identified locations. The timing of drilling our identified locations will be influenced by several factors, including commodity prices, capital requirements, RRC well-spacing requirements and a continuation of the positive results from both our horizontal and vertical drilling and development activities.

As of December 31, 2012, we had estimated proved reserves of 95.3 MMBoe in the Permian Basin, made up of 39% oil, 31% NGLs and 30% natural gas. Our Permian proved reserves increased 24%, and oil proved reserves increased 106%, over year-end 2011. Reserve growth in 2012 was driven by results in our Wolfcamp oil shale resource play.

During 2012 in the Permian Basin, we incurred $240.8 million to drill 46 gross (45.8 net) wells, of which 10 gross (9.9 net) wells were waiting on completion at December 31, 2012.

East Texas Basin — North Bald Prairie

Cotton Valley Sands and Cotton Valley Lime

In July 2007, we entered into a joint venture with EnCana Oil & Gas (USA) Inc. (“EnCana”) in Limestone and Robertson Counties, Texas, in the East Texas Cotton Valley trend. We began drilling operations in August 2007. We have drilled and completed 11 gross wells, including one well completed as a saltwater disposal well. We have a 50% working interest and approximately 40% net revenue interest in the approximately 6,200 gross (3,400 net) acre project. In 2012, EnCana assigned its interest in the project to a third party. As of December 31, 2012, we had estimated proved reserves of 820 MMcf in North Bald Prairie. Average daily production in 2012 was 320 Mcf/d, or a total of 117 MMcf.

Our primary targets in North Bald Prairie are the Cotton Valley Sands and Cotton Valley Lime. These are unconventional tight gas formations where we believe we can apply our geological, technical and operational expertise to improve production and recovery rates. Secondary targets include the shallower Rodessa, Pettit and Travis Peak formations. We currently have no rigs running in North Bald Prairie.

Proved Oil and Gas Reserves

The following table sets forth summary information regarding our estimated proved reserves as of December 31, 2012. See Note 10 to our consolidated financial statements in this report for additional

 

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information. Our estimated total proved reserves of oil, NGLs and natural gas as of December 31, 2012, were 95.5 MMBoe, made up of 39% oil, 30% NGLs and 31% natural gas. The proved developed portion of total proved reserves at year end 2012 was 34%. Natural gas is converted at a rate of six Mcf of gas to one barrel of oil equivalent (“Boe”). NGLs are converted at a rate of one barrel of NGLs to one Boe. The ratios of six Mcf of gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe of natural gas or NGLs may differ significantly from the price of a barrel of oil.

Summary of Oil and Gas Reserves as of Fiscal-Year End

Based on Average Fiscal-Year Prices

 

     Reserves                

Reserves Category

   Oil
(MBbls)
     NGLs
(MBbls)
     Natural Gas
(MMcf)
     Total
(MBoe)
     Percent
(%)
 

Proved Developed

              

Permian Basin

     8,816         11,761         72,359         32,637         34.2

East Texas Basin

                     819         137         0.1   

Proved Undeveloped

              

Permian Basin

     28,436         17,339         101,582         62,705         65.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved Reserves

     37,252         29,100         174,760         95,479         100.0
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

The following table sets forth our estimated proved reserves, PV-10 and a reconciliation of PV-10 to the Standardized Measure at December 31, 2012. Our reserve estimates and our calculation of Standardized Measure and PV-10 are based on the 12-month average of the first-day-of-the-month pricing of $94.71 per Bbl West Texas Intermediate posted oil price, $37.88 per Bbl received for NGLs and $2.74 per MMBtu Henry Hub spot natural gas price during 2012. All prices were adjusted for energy content, quality and basis differentials by area and were held constant through the lives of the properties.

 

     December 31, 2012  

Operating Area

   Oil
(MBbls)
     NGLs
(MBbls)
     Natural
Gas
(MMcf)
     Total
(MBoe)
     PV-10
(in millions)
 

Permian Basin

     37,252         29,100         173,940         95,342       $ 830,435   

East Texas Basin

                     820         137         487   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     37,252         29,100         174,760         95,479         830,922   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Present value of future income tax discounted at 10%

  

     (336,702
              

 

 

 

Standardized measure of discounted future net cash flows

  

   $ 494,220   
              

 

 

 

PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. PV-10 is a non-GAAP, financial measure and generally differs from the Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the Standardized Measure as computed under GAAP.

We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis.

 

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Table of Contents

Changes to Proved Reserves

The following table sets forth the changes in our proved reserve volumes by operating area during the year ended December 31, 2012 (in MBoe).

 

Operating Area

   Production     Extensions
and
Discoveries
     Revisions to
Previous
Estimates
 

Permian Basin

     (2,868     38,861         (17,413

East Texas Basin

     (20             (56
  

 

 

   

 

 

    

 

 

 

Total

     (2,888     38,861         (17,469
  

 

 

   

 

 

    

 

 

 

We produced 2.9 MMBoe during 2012, 99% of which is attributable to our assets in the Permian Basin. Extensions and discoveries for 2012 of 38.9 MMBoe were primarily attributable to our development project in the Wolfcamp oil shale resource play in the Permian Basin. During 2012, we recorded downward revisions totaling 17.5 MMBoe, including the reclassification of 8.9 MMBoe of proved undeveloped reserves to probable undeveloped. These reserves were attributable to vertical Canyon locations in southeast Project Pangea. Due to our horizontal Wolfcamp development project, including pad drilling, postponement of these deeper locations beyond five years from initial booking is necessary to integrate their development with the shallower Wolfcamp and Wolffork target zones. We expect this integrated development to minimize surface impact and maximize reservoir recoveries. Revisions also include 3.3 MMBoe of performance revisions primarily related to vertical Canyon wells in Project Pangea, 2.9 MMBoe of revisions resulting from technical evaluations and revisions of 2.4 MMBoe due to lower natural gas and NGL prices.

Preparation of Proved Reserves Estimates

Internal Controls Over Preparation of Proved Reserves Estimates

Our policies regarding internal controls over the recording of reserve estimates require reserve estimates to be in compliance with SEC rules, regulations and guidance and prepared in accordance with “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)” promulgated by the Society of Petroleum Engineers (“SPE standards”). Our proved reserves are estimated at the property level and compiled for reporting purposes by our corporate reservoir engineering staff, all of whom are independent of our operations team. We maintain our internal evaluations of our reserves in a secure reserve engineering database. The corporate reservoir engineering staff interacts with our internal staff of operations engineers and geoscience professionals and with accounting employees to obtain the necessary data for the reserves estimation process. Our internal professional staff works closely with our external engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves.

Our Manager of Reservoir Engineering, Brandon L. Hudson, is the individual responsible for overseeing the preparation of our reserve estimates and for internal compliance of our reserve estimates with SEC rules, regulations and SPE standards. Mr. Hudson has a Bachelor of Science degree in Mechanical Engineering from University of Texas at Austin and a Master of Science degree in Petroleum Engineering from Louisiana State University and 10 years of industry experience. Mr. Hudson reports directly to our Chief Executive Officer. Our senior management, including our Chief Executive Officer and Chief Financial Officer, reviews and approves our reserves estimates, including future development costs, before these estimates are finalized and disclosed in a public filing or presentation. Our Chief Executive Officer, J. Ross Craft, P.E., is a licensed Professional Engineer with a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University and more than 30 years of industry experience. Our Chief Financial Officer, Steven P. Smart, is a licensed Certified Public Accountant with more than 30 years of industry experience.

 

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Table of Contents

For the years ended December 31, 2012, 2011, and 2010, we engaged DeGolyer and MacNaughton, independent petroleum engineers, to prepare independent estimates of the extent and value of the proved reserves associated with certain of our oil and gas properties. In 2012, DeGolyer and MacNaughton reported to the Audit Committee of our Board of Directors and to our Manager of Reservoir Engineering. The Audit Committee meets with the independent engineering firm before the preparation of the firm’s final report to, among other things, review and consider the processes used by the engineers in the preparation of the report and any matters of importance that arose in the preparation of the report, including whether the independent engineering firm encountered any material problems or difficulties in the preparation of their report. The Audit Committee’s review specifically includes difficulties with the scope or timeliness of the information furnished to them by the Company or any restrictions or access to information placed upon them by any Company personnel, any other difficulties in dealing with any Company personnel in the preparation of the report and any other matters of concern relating to the preparation of the report. The Audit Committee also determines whether the Company or its management or senior engineering personnel had similar or other problems or concerns regarding the independent engineering firm and the preparation of their report. See Third Party Reports below for further information regarding DeGolyer and MacNaughton’s report.

Technologies Used in Preparation of Proved Reserves Estimates

Estimates of reserves were prepared in compliance with SEC rules, regulations and guidance and SPE standards. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history. For our properties, structure and isopach maps were constructed to delineate each reservoir. Electrical logs, radioactivity logs, seismic data and other available data were used to prepare these maps. Parameters of area, porosity and water saturation were estimated and applied to the isopach maps to obtain estimates of original oil in place or original gas in place. For developed producing wells whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were determined using decline curve analysis. Reserves for producing wells whose performance was not yet established and for undeveloped locations were estimated using type curves. The parameters needed to develop these type curves such as initial decline rate, “b” factor and final decline rate were based on nearby wells producing from the same reservoir and with a similar completion for which more data were available.

Reporting of Natural Gas Liquids (“NGLs”)

We produce NGLs as part of the processing of our natural gas. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. At December 31, 2012, NGLs represented approximately 30% of our total proved reserves on a Boe basis. NGLs are products sold by the gallon. In reporting proved reserves and production of NGLs, we include these volumes and production as Boe. The prices we received for a standard barrel of NGLs in 2012 averaged approximately 60% lower than the average prices for equivalent volumes of oil. We report all production information related to natural gas net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs.

Third-Party Reports

For the years ended December 31, 2012, 2011, and 2010, we engaged DeGolyer and MacNaughton, independent, third-party reserves engineers, to prepare estimates of the extent and value of the proved reserves of certain of our oil and gas properties, including 100% of our total reported proved reserves. DeGolyer and MacNaughton’s report for 2012 is included as Exhibit 99.1 to this annual report on Form 10-K.

Proved Undeveloped Reserves

As of December 31, 2012, we had 62.7 MMBoe of proved undeveloped (“PUD”) reserves, which is an increase of 19.3 MMBoe or 44%, compared with 43.4 MMBoe of PUD reserves at December 31, 2011. All of

 

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Table of Contents

our PUD reserves at December 31, 2012, were associated with our core development project, Project Pangea. As a percent of our total proved reserves, our PUD reserves increased from 56% in 2011 to 66% in 2012 due to our ongoing development of our Wolfcamp oil shale resource play.

The following table summarizes the changes in our PUD reserves during 2012.

 

      Oil
(MBbls)
    NGLs
(MBbls)
    Natural
Gas
(MMcf)
    Total
(MBoe)
 

Balance — December 31, 2011

     12,509        15,178        94,064        43,364   

Extensions and discoveries

     18,514        7,349        41,781        32,827   

Revisions to previous estimates

     (1,301     (4,520     (30,581     (10,918

Conversion to proved developed reserves

     (1,286     (668     (3,682     (2,568
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance — December 31, 2012

     28,436        17,339        101,582        62,705   
  

 

 

   

 

 

   

 

 

   

 

 

 

The following table sets forth our PUD reserves converted to proved developed reserves during 2012, 2011 and 2010 and the net investment required to convert PUD reserves to proved developed reserves during the year.

 

     Proved Undeveloped Reserves
Converted to Proved Developed
Reserves
     Investment in Conversion of
Proved Undeveloped
Reserves to Proved
Developed Reserves
 

Year Ended

December 31,

   Oil
(MBbls)
     NGLs
(MBbls)
     Natural
Gas
(MMcf)
     Total
(MBoe)
     (in thousands)  

2010

     589         2,134         12,728         4,845       $ 37,070   

2011

     263         660         3,583         1,520         33,783   

2012

     1,286         668         3,682         2,568         52,008   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     2,138         3,462         19,993         8,933       $ 122,861   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Estimated future development costs relating to the development of PUD reserves are projected to be approximately $239.6 million in 2013, $291.2 million in 2014 and $335.5 million in 2015. We monitor fluctuations in commodity prices, drilling and completion costs, operating expenses and drilling success to determine adjustments to our drilling and development program. Based on current expectations for cash flows, commodity prices and operating costs and expenses, all PUD reserves are scheduled to be drilled before the end of 2017.

At December 31, 2012, we had 4.5 MMBoe of PUD reserves, or 4.7% of our total proved reserves and 7.2% of our total PUD reserves, that have been booked for five years or longer. Substantially all of the PUD reserves that have been booked for five years or longer are associated with our deep, tight sandstone (Canyon Sands) locations in Project Pangea. This tight sandstone reservoir is approximately 7,250 to 8,500 feet deep and lies under approximately 100,000 gross acres across Project Pangea.

We have a historical record of drilling our deep, tight sandstone reserves in Project Pangea. From 2004 through December 31, 2012, we have drilled and completed more than 500 tight sands wells in the Permian Basin since 2004. According to IHS, a provider of global market and economic information, this makes us the second most active driller of tight sands (Canyon Sands) wells in West Texas since we began drilling in the area in 2004.

Based on our more recent Wolfcamp and Wolffork drilling activity in Project Pangea since 2010, we believe that the PUD reserves that have been booked for five years or longer have additional reserves above the tight sands. To maximize wellbore utility and reservoir potential, our objective is to develop these multi-zone reserves

 

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Table of Contents

together as part of Project Pangea. Developing these reserves on an integrated basis should allow us to maximize reservoir potential, prevent waste and minimize surface impact and use of other critical resources such as fresh water for fracture stimulation.

To prepare for larger scale development of Project Pangea, in 2012 we accelerated our investment in infrastructure in Project Pangea, spending $44.3 million on infrastructure, projects and equipment, plus an additional $10 million in equity investment in a joint venture for pipeline and facilities construction, for a total of $54.3 million. This represents 18% of total capital costs and equity investment in Project Pangea in 2012.

Oil and Gas Production, Production Prices and Production Costs

The following table sets forth summary information regarding oil, NGL and gas production, average sales prices and average production costs for the last three years. We determined the Boe using the ratio of six Mcf of natural gas to one Boe, and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas or NGLs may differ significantly from the price for a barrel of oil.

 

     Years Ended December 31,  
      2012     2011      2010  

Production

       

Oil (MBbls)

     969        482         246   

NGLs (MBbls)

     904        798         261   

Gas (MMcf)

     6,089        6,345         6,290   
  

 

 

   

 

 

    

 

 

 

Total (MBoe)

     2,888        2,338         1,556   

Total (MBoe/d)

     7.9        6.4         4.3   

Average prices

       

Oil (per Bbl)

   $ 84.70      $ 88.18       $ 75.67   

NGLs (per Bbl)

     34.09        51.39         41.19   

Gas (per Mcf)

     2.63        3.92         4.48   
  

 

 

   

 

 

    

 

 

 

Total (per Boe)

     44.63        46.37         37.00   

Realized gain on commodity derivatives (per Boe)

     (0.03     1.44         3.72   
  

 

 

   

 

 

    

 

 

 

Total including derivative impact (per Boe)

   $ 44.60      $ 47.81       $ 40.72   
  

 

 

   

 

 

    

 

 

 

Production costs (per Boe)(1)

   $ 6.58      $ 4.57       $ 4.25   
  

 

 

   

 

 

    

 

 

 

 

(1) Production cost per Boe is made up of lease operating expenses. Production cost per Boe excludes production and ad valorem taxes.

 

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Table of Contents

Drilling Activity — Prior Three Years

The following table sets forth information on our drilling activity for the last three years. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

 

     Years Ended December 31,  
     2012      2011      2010  
     Gross      Net      Gross      Net      Gross      Net  

Development wells:

                 

Productive

     46.0         45.8         69.0         64.2         91.0         56.2   

Dry

                     2.0         2.0                   

Exploratory wells:

                 

Productive

                                               

Dry

                                               

Total wells:

                 

Productive

     46.0         45.8         69.0         64.2         91.0         56.2   

Dry

                     2.0         2.0                   

Of the 46 gross (45.8 net) wells drilled in 2012, 10 gross (9.9 net) wells were waiting on completion at December 31, 2012. Of the two gross (two net) dry wells drilled in 2011, one was completed as a salt water disposal well and one replacement well was drilled during the first three months of 2012.

Although a well may be classified as productive upon completion, future changes in oil, NGL and gas prices, operating costs and production may result in the well becoming uneconomical.

Drilling Activity — Current

As of the date of this report, we had three horizontal rigs running in the Permian Basin and targeting the Wolfcamp shale.

Delivery Commitments

We are not committed to provide a fixed and determinable quantity of oil, NGLs or gas in the near future under existing agreements. However, as of December 31, 2012, we had (1) dedicated all of our oil production from northern Project Pangea and Pangea West for 10 years to an oil pipeline joint venture in which we own a 50% equity interest, and (2) contracted to sell all of our NGLs and natural gas production from Project Pangea to DCP through January 2016.

Producing Wells

The following table sets forth the number of producing wells in which we owned a working interest at December 31, 2012. Wells are classified as natural gas or oil according to their predominant production stream.

 

     Natural Gas
Wells
     Oil
Wells
     Total Wells      Average
Working

Interest
 
     Gross      Net      Gross      Net      Gross      Net     

Permian Basin

     525.0         514.7         69.0         68.5         594.0         583.2         98.2

East Texas Basin

     5.0         2.5                         5.0         2.5         50.0
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     530.0         517.2         69.0         68.5         599.0         585.7         97.8
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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Table of Contents

Acreage

The following table summarizes our developed and undeveloped acreage as of December 31, 2012.

 

     Developed Acres      Undeveloped Acres      Total Acres  
     Gross      Net      Gross      Net      Gross      Net  

Permian Basin

     75,371         66,977         92,036         80,560         167,407         147,537   

East Texas Basin

     3,504         1,682         2,690         1,707         6,194         3,389   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     78,875         68,659         94,726         82,267         173,601         150,926   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Undeveloped Acreage Expirations

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2012, that will expire over the next three years by project area unless production is established before lease expiration dates. Gross amounts may be more than net amounts in a particular year due to timing of expirations.

 

     2013      2014      2015  
     Gross      Net      Gross      Net      Gross      Net  

Permian Basin

     21,157         17,028         41,018         35,250         26,143         24,461   

East Texas Basin

     393         274         2,298         1,428                 4   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     21,550         17,302         43,316         36,678         26,143         24,465   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

The expiring acreage set forth in the table above accounts for 95% of our net undeveloped acreage, 17.2% of our PUD reserves and 11.3% of our total proved reserves. We are continually engaged in a combination of drilling and development and discussions with mineral lessors for lease extensions, renewals, new drilling and development units and new leases to address the expiration of undeveloped acreage that occurs in the normal course of our business.

ITEM 3.    LEGAL PROCEEDINGS

We are involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our business, financial condition or cash flows.

ITEM 4.    MINE SAFETY DISCLOSURES

Not applicable.

 

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Table of Contents

PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our common stock is traded on NASDAQ in the United States under the symbol “AREX.” During 2012, trading volume averaged 534,757 shares per day. The following table shows the quarterly high and low sale prices of our common stock as reported on NASDAQ for the past two years.

 

     Price Per Share  
     High      Low  

2012

     

First quarter

   $ 38.92       $ 29.77   

Second quarter

     39.18         22.36   

Third quarter

     34.84         24.08   

Fourth quarter

     30.76         22.50   

2011

     

First quarter

   $ 34.72       $ 22.58   

Second quarter

     34.93         19.13   

Third quarter

     28.37         15.55   

Fourth quarter

     33.48         14.14   

Holders

As of February 25, 2013, there were 115 record holders of our common stock. In many instances, a record holder is a broker or other entity holding shares in street name for one or more customers who beneficially own the shares.

Dividends

We have not paid any cash dividends on our common stock. We do not expect to pay any cash or other dividends in the foreseeable future on our common stock, as we intend to reinvest cash flow generated by operations into our business. Our revolving credit facility currently restricts our ability to pay cash dividends on our common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that restrict or limit our ability to pay cash dividends on our common stock.

Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth information regarding securities authorized for issuance under equity compensation plans and individual compensation arrangements as of December 31, 2012.

 

Plan Category

   Number of
Securities to be
Issued Upon
Exercise of
Outstanding
Options, Warrants
and Rights

(a)
     Weighted-Average
Exercise Price of
Outstanding
Options, Warrants
and Rights

(b)
     Number of Securities
Remaining Available for
Future Issuance  under
Equity Compensation Plans
(Excluding Securities
Reflected in Column (a))(1)

(c)
 

Equity compensation plans approved by stockholders

     43,275       $ 12.38         2,062,854   

Equity compensation plans not approved by stockholders

                  

 

  

 

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Table of Contents

Performance Graph

The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2007, through December 31, 2012, to that of the cumulative return on a $100 investment in the Standard & Poor’s 500 (“S&P 500”) index and the Dow Jones U.S. Exploration & Production Total Stock Market 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 or 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.

COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN

Among Approach Resources Inc., the S&P 500 Index, and the Dow Jones U.S. Exploration &

Production Total Stock Market Index

 

LOGO

 

      12/31/2007      12/31/2008      12/31/2009      12/31/2010      12/31/2011              12/31/2012  

Approach Resources Inc.

   $ 100.00       $ 58.06       $ 61.32       $ 183.48       $ 233.60       $           194.48   

S&P 500

     100.00         59.95         75.81         87.23         89.07            108.59   

D J U.S. Exploration & Production

     100.00         59.62         84.37         99.89         95.80                  99.66   

 

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Table of Contents

Issuer Repurchases of Equity Securities

Our 2007 Plan allows us to withhold shares of common stock to pay withholding taxes payable upon vesting of a restricted stock grant. The following table shows the number of shares of common stock withheld to satisfy the income tax withholding obligations arising upon the vesting of restricted shares issued to employees under the 2007 Plan.

 

Period

   (a)
Total
Number
of Shares
Purchased
     (b)
Average
Price
Paid per
Share
     (c)
Total Number  of
Shares Purchased
as Part of
Publicly
Announced Plans
or Programs
     (d)
Maximum
Number (or
Approximate
Dollar Value) of
Shares that
May Yet Be
Purchased Under
the Plans or
Programs
 

October 1, 2012 — October 31, 2012

                               

November 1, 2012 — November 30, 2012

     962       $ 23.14                   

December 1, 2012 — December 31, 2012

     79,022       $ 24.92                   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     79,984       $ 24.84                   

 

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Table of Contents
ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected financial information for the five years ended December 31, 2012. This information should be read in conjunction with Item 7 of this report, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated financial statements, related notes and other financial information included in this report.

 

     Years Ended December 31,  
     2012     2011     2010     2009     2008  
     (in thousands, except per-share data)  

Operating Results Data

          

Revenues

          

Oil, NGL and gas sales

   $ 128,892      $ 108,387      $ 57,581      $ 40,648      $ 79,869   

Expenses

          

Lease operating(1)

     19,002        10,687        6,620        6,018        6,425   

Production and ad valorem taxes(1)

     9,255        8,447        4,925        3,755        5,398   

Exploration

     4,550        9,546        2,589        1,621        1,478   

Impairment

            18,476        2,622        2,964        6,379   

General and administrative

     24,903        17,900        11,422        10,617        8,881   

Depletion, depreciation and amortization

     60,381        32,475        22,224        24,660        23,710   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

     118,091        97,531        50,402        49,635        52,271   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     10,801        10,856        7,179        (8,987     27,598   

Other

          

Impairment of investment

                                 (917

Interest expense, net

     (4,737     (3,402     (2,189     (1,787     (1,269

Equity in losses of investee

     (108                            

Realized (loss) gain on commodity derivatives

     (108     3,375        5,784        14,659        2,936   

Unrealized gain (loss) on commodity derivatives

     3,874        (347     788        (9,899     7,149   

Gain on sale of oil and gas properties, net of foreign currency transaction loss

            248                        
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before provision (benefit) for income taxes

     9,722        10,730        11,562        (6,014     35,497   

Provision (benefit) for income taxes

     3,338        3,488        4,100        (785     12,111   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 6,384      $ 7,242      $ 7,462      $ (5,229   $ 23,386   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Earnings (loss) per share

          

Basic

   $ 0.18      $ 0.25      $ 0.34      $ (0.25   $ 1.13   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Diluted

   $ 0.18      $ 0.25      $ 0.34      $ (0.25   $ 1.12   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Statement of Cash Flows Data

          

Net cash provided by (used in)

          

Operating activities

   $ 90,585      $ 95,770      $ 42,377      $ 39,761      $ 56,381   

Investing activities

     (307,414     (284,758     (91,346     (29,553     (100,633

Financing activities

     217,295        165,843        69,748        (11,618     43,750   

Effect of Canadian exchange rate

            (19     1        18        (206

Balance Sheet Data

          

Cash and cash equivalents

   $ 767      $ 301      $ 23,465      $ 2,685      $ 4,077   

Other current assets

     14,889        11,085        17,865        9,318        30,760   

Property, equipment, net, successful efforts method

     828,467        595,284        369,210        304,483        303,404   

Equity method investment

     9,892                               

Other assets

     1,724        1,224        2,549        2,440          
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

   $ 855,739      $ 607,894      $ 413,089      $ 318,926      $ 338,241   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Current liabilities

   $ 60,247      $ 43,625      $ 29,240      $ 21,996      $ 30,775   

Long-term debt

     106,000        43,800               32,319        43,537   

Other long-term liabilities

     56,024        53,020        50,903        44,115        40,116   

Stockholders’ equity

     633,468        467,449        332,946        220,496        223,813   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities and stockholders’ equity

   $ 855,739      $ 607,894      $ 413,089      $ 318,926      $ 338,241   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Amounts related to ad valorem taxes have been reclassified from lease operating to production and ad valorem taxes for all years presented. This reclassification has no impact on net income (loss) reported herein.

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations and our financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this report contain additional information that should be referred to when reviewing this material. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed. See “Cautionary Statement Regarding Forward-Looking Statements” at the beginning of this report and “Risk Factors” in Item 1A. for additional discussion of some of these factors and risks.

Overview

Approach Resources Inc. is an independent energy company engaged in the exploration, development, production and acquisition of oil and gas properties. We focus on oil and gas reserves in oil shale and tight gas sands in the Permian Basin in West Texas, where we lease approximately 148,000 net acres. Our drilling targets include the Clearfork, Wolfcamp shale, Canyon Sands, Strawn and Ellenburger zones. We sometimes refer to the Clearfork and Wolfcamp zones together as the “Wolffork,” and our development project in the Permian Basin as “Project Pangea,” which includes “Pangea West.” Our management and technical team have a proven track record of finding and developing reserves through advanced drilling and completion techniques. As the operator of all of our estimated proved reserves and production, we have a high degree of control over capital expenditures and other operating matters.

At December 31, 2012, our estimated proved reserves were 95.5 million barrels of oil equivalent (“MMBoe”). Substantially all of our proved reserves are located in Crockett and Schleicher Counties, Texas. Important characteristics of our proved reserves at December 31, 2012, include:

 

   

39% oil, 30% NGLs and 31% natural gas;

 

   

34% proved developed;

 

   

100% operated;

 

   

Reserve life of more than 30 years based on 2012 production of 2.9 MMBoe;

 

   

Standardized Measure of $494.2 million; and

 

   

PV-10 of $830.9 million.

At December 31, 2012, we owned and operated 594 producing oil and gas wells in the Permian Basin, and we had an estimated 2,983 identified drilling and recompletion locations, of which 359 were proved. We also owned working interests in nine producing gas wells in the East Texas Basin.

2012 Activity

Our operations in 2012 focused on horizontal drilling in our Wolfcamp oil shale resource play in the Permian Basin. We drilled 26 horizontal wells in 2012, compared to 13 horizontal wells in 2011. Our early results in the Wolfcamp play led us to invest in building an infrastructure system that we believe will reduce drilling and completion costs, improve drilling and completion efficiencies, reduce fresh water use and ensure transportation for our crude oil production to market. We plan to continue to develop the Wolfcamp shale in Project Pangea in 2013. Focusing on the Wolfcamp shale allows us to use our operating, technical and regional expertise that is important to interpreting geological and operating trends, enhancing production rates and maximizing well recovery.

Production Growth

Production for 2012 totaled 2.9 MMBoe (7.9 MBoe/d), compared to 2.3 MMBoe (6.4 MBoe/d) in 2011, a 24% increase. Production for 2012 was 34% oil, 31% NGLs and 35% natural gas. Our continued development of

 

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Project Pangea increased oil production 101% in 2012, compared to 2011. On average, we operated two horizontal rigs and one vertical rig in 2012, and drilled a total of 46 gross (45.8 net) wells, of which 10 gross (9.9 net) were waiting on completion at December 31, 2012. We also recompleted 18 gross (18 net) wells in the Wolffork in 2012.

Reserve Growth

In 2012, our estimated proved reserves increased 24%, or 18.5 MMBoe, to 95.5 MMBoe from 77.0 MMBoe. Our proved reserves at year-end 2012 were 39% oil, 30% NGLs and 31% natural gas, compared to 23% oil, 38% NGLs and 39% natural gas at year-end 2011. During 2012, our proved oil reserves increased 19.2 MMBbls, or 106%, to 37.3 MMBbls from 18.1 MMBbls in 2011. Reserve growth, and especially our oil reserve growth, in 2012 was driven by results in our Wolfcamp oil shale resource play.

2012 Equity Offering

In September 2012, we completed the 2012 Offering and sold 5.0 million shares of common stock at $30.50 per share. In October 2012, the underwriters exercised their option and purchased an additional 325,000 shares. After deducting underwriting discounts and transaction costs of approximately $8.0 million, we received net proceeds of approximately $154.4 million. We used the proceeds of the 2012 equity offering to repay outstanding borrowings under our revolving credit facility, fund our capital expenditures for the development of our Wolfcamp oil shale resource play and for general working capital needs.

Plans for 2013

In September 2012, we announced a 2013 capital budget of $260 million, which includes three rigs to drill horizontal wells targeting the Wolfcamp shale. We expect that our horizontal drilling in Project Pangea in 2013 will include pad drilling, which we believe will improve operating efficiencies and resource recoveries, while reducing facilities costs and surface impact. We also may drill vertical wells targeting the Wolffork or recomplete Canyon Sands wells in the Wolffork during 2013. Our objectives for 2013 include advancing our understanding of optimal well spacing, testing multi-zone potential to enhance hydrocarbon recovery in our Wolffork targets and improving our cost structure.

Our 2013 capital budget is subject to change depending upon a number of factors, including additional data on our Wolfcamp oil shale resource play, results of horizontal and vertical drilling, completions and recompletions, including pad drilling, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil, NGLs and gas, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See Note 1 to our consolidated financial statements.

Segment reporting is not applicable to us as we have a single, company-wide management team that administers all significant properties as a whole, rather than by discrete operating segments. We track only basic

 

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operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis. We use the successful efforts method of accounting for our oil and gas activities.

Successful Efforts Method of Accounting

Accounting for oil and gas activities is subject to special, unique rules. We use the successful efforts method of accounting for our oil and gas activities. The significant principles for this method are:

 

   

geological and geophysical evaluation costs are expensed as incurred;

 

   

dry holes for exploratory wells are expensed and dry holes for development wells are capitalized; and

 

   

capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows.

Proved Reserves

For the year ended December 31, 2012, we engaged DeGolyer and MacNaughton, independent petroleum engineers, to prepare independent estimates of the extent and value of 100% of our reported proved reserves, in accordance with rules and guidelines established by the SEC.

Estimates of proved oil and gas reserves directly impact financial accounting estimates including depletion, depreciation and amortization expense, evaluation of impairment of properties and the calculation of plugging and abandonment liabilities. Proved oil and gas reserves are those quantities of oil and 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 process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for any reservoir may change substantially over time due to results from operational activity. Proved reserve volumes at December 31, 2012, were estimated based on the average of the closing price on the first day of each month for the 12-month period prior to December 31, 2012, for oil, NGLs and gas in accordance with SEC rules. Changes in commodity prices and operations costs may increase or decrease estimates of proved oil, NGL and natural gas reserves. Depletion expense for our oil and gas properties is determined using our estimates of proved oil, NGL and gas reserves. A hypothetical 10% decline in our December 31, 2012, estimated proved reserves would have increased our depletion expense by approximately $1.9 million for the year ended December 31, 2012.

See also Item 2. “Properties — Proved Oil and Gas Reserves” and Note 10 to our consolidated financial statements in this report for additional information regarding our estimated proved reserves.

Derivative Instruments and Commodity Derivative Activities

Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using

 

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industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.

We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.

Changes in the derivative’s fair value are currently recognized in the statement of operations unless specific commodity derivative hedge accounting criteria are met and such strategies are designated. For qualifying cash-flow commodity derivatives, the gain or loss on the derivative is deferred in accumulated other comprehensive income to the extent the commodity derivative is effective. The ineffective portion of the commodity derivative is recognized immediately in the statement of operations. Gains and losses on commodity derivative instruments included in accumulated other comprehensive income are reclassified to oil and gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for commodity derivative accounting treatment are recorded as derivative assets and liabilities at fair value in the balance sheet, and the associated unrealized gains and losses are recorded as current income or expense in the statement of operations.

Historically, we have not designated our derivative instruments as cash-flow hedges. We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized gain (loss) on commodity derivatives.”

Although we have not designated our derivative instruments as cash-flow hedges, we use those instruments to reduce our exposure to fluctuations in commodity prices related to our oil and gas production. Accordingly, we record realized gains and losses under those instruments in other revenues on our consolidated statements of operations. For the year ended December 31, 2011, we recognized an unrealized loss of $347,000 from the change in the fair value of commodity derivatives. For the years ended December 31, 2012 and 2010, we recognized an unrealized gain of $3.9 million and $788,000, respectively, from the change in the fair value of commodity derivatives. A hypothetical 10% increase in the NYMEX floating prices would have resulted in a $5.4 million decrease in the December 31, 2012, fair value recorded on our balance sheet and a corresponding decrease to the gain on commodity derivatives in our statement of operations.

Asset Retirement Obligation

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable federal, state and local laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.

Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation.

Impairment of Long-Lived Assets

All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may be greater than its future net cash flows. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil,

 

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NGLs and gas, future costs to produce these products, estimates of future oil and gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test an asset for impairment may result from significant declines in commodity prices or downward revisions to estimated quantities of oil and gas reserves. Any assets held for sale are reviewed for impairment when we approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded.

Provision for Income Taxes

We estimate our provision for income taxes using historical tax basis information from prior years’ income tax returns, along with the estimated changes to such bases from current period activity and enacted tax rates. Additionally, we compare liabilities to actual settlements of such assets or liabilities during the current period to identify considerations that might affect the current period’s estimate.

Valuation of Share-Based Compensation

Our 2007 Plan allows grants of stock and options to employees and outside directors. Granting of awards may increase our general and administrative expenses, subject to the size and timing of the grants. See Note 5 to our consolidated financial statements.

In accordance with GAAP, we calculate the fair value of share-based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. We use (i) the Black-Scholes option price model to measure the fair value of stock options, (ii) the closing stock price on the date of grant for the fair value of restricted stock awards, including performance-based awards, and (iii) the Monte Carlo simulation method for the fair value of market-based awards.

Equity Method Investments

For investments in which we have the ability to exercise significant influence but do not have control, we follow the equity method of accounting. In September 2012, we entered into a joint venture to build an oil pipeline in Crockett and Reagan Counties, Texas, which will be used to transport our oil to market. In October 2012, we made an initial contribution of $10 million to the joint venture for pipeline and facilities construction. This initial contribution was recorded at cost. Our equity investment is classified as a noncurrent asset on our consolidated balance sheet at December 31, 2012. Our share of the investee’s losses was recorded on our consolidated statement of operations for the year ended December 31, 2012.

Effects of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2012, 2011 or 2010. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property and equipment. It may also increase the cost of labor or supplies.

 

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Results of Operations

The following table sets forth summary information regarding oil, NGL and gas revenues, production, average product prices and average production costs and expenses for the last three years. We determined the Boe using the ratio of six Mcf of natural gas to one Boe, and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas or NGLs may differ significantly from the price for a barrel of oil.

 

     Years Ended December 31,  
     2012     2011      2010  

Revenues (in thousands)

       

Oil

   $ 82,087      $ 42,463       $ 18,640   

NGLs

     30,811        41,029         10,765   

Gas

     15,994        24,895         28,176   
  

 

 

   

 

 

    

 

 

 

Total oil, NGL and gas sales

     128,892        108,387         57,581   

Realized (loss) gain on commodity derivatives

     (108     3,375         5,784   
  

 

 

   

 

 

    

 

 

 

Total oil, NGL and gas sales including derivative impact

   $ 128,784      $ 111,762       $ 63,365   
  

 

 

   

 

 

    

 

 

 

Production

       

Oil (MBbls)

     969        482         246   

NGLs (MBbls)

     904        798         261   

Gas (MMcf)

     6,089       6,345         6,290   
  

 

 

   

 

 

    

 

 

 

Total (MBoe)

     2,888        2,338         1,556   

Total (MBoe/d)

     7.9        6.4         4.3   

Average prices

       

Oil (per Bbl)

   $ 84.70      $ 88.18       $ 75.67   

NGLs (per Bbl)

     34.09        51.39         41.19   

Gas (per Mcf)

     2.63        3.92         4.48   
  

 

 

   

 

 

    

 

 

 

Total (per Boe)

   $ 44.63      $ 46.37       $ 37.00   

Realized (loss) gain on commodity derivatives (per Boe)

     (0.03     1.44         3.72   
  

 

 

   

 

 

    

 

 

 

Total including derivative impact (per Boe)

   $ 44.60      $ 47.81       $ 40.72   
  

 

 

   

 

 

    

 

 

 

Costs and expenses (per Boe)

       

Lease operating

   $ 6.58      $ 4.57       $ 4.25   

Production and ad valorem taxes(1)

     3.20        3.61         3.17   

Exploration

     1.58        4.08         1.66   

Impairment

            7.90         1.68   

General and administrative

     8.62        7.66         7.34   

Depletion, depreciation and amortization

     20.91        13.89         14.28   

 

(1) Amounts related to ad valorem taxes have been reclassified from lease operating to production and ad valorem taxes for all years presented. This reclassification has no impact on net income (loss) reported herein.

Oil, NGL and gas sales.    Oil, NGL and gas sales increased $20.5 million, or 19%, to $128.9 million from $108.4 million in 2011. The increase in oil, NGL and gas sales was due to an increase in production volumes, partially offset by a decrease in average prices received. Production volumes increased as a result of our development of Project Pangea in the Permian Basin. In 2012, the average price we received for our production, before the effect of commodity derivatives, decreased to $44.63 per Boe from $46.37 per Boe, or a 4% decrease. Subject to commodity prices, we expect oil, NGL and gas sales to increase in 2013 due to increased production volumes from our development project in the Permian Basin.

 

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Oil, NGL and gas sales increased $50.8 million, or 88%, in 2011 to $108.4 million from $57.6 million in 2010. Of the $50.8 million increase in oil, NGL and gas sales, approximately $48.6 million was attributable to an increase in production volumes and $2.2 million was attributable to an increase in prices. In 2011, the average price we received for our production, before the effect of commodity derivatives, increased to $46.37 per Boe from $37.00 per Boe, or a 25% increase.

The following table summarizes our oil, NGL and gas sales for each of the last three years (in thousands).

 

     Years Ended December 31,  

Revenues

   2012     2011      2010  

Oil

   $ 82,087      $ 42,463       $ 18,640   

NGLs

     30,811        41,029         10,765   

Gas

     15,994        24,895         28,176   
  

 

 

   

 

 

    

 

 

 

Total oil, NGL and gas sales

     128,892        108,387         57,581   

Realized (loss) gain on commodity derivatives

     (108     3,375         5,784   
  

 

 

   

 

 

    

 

 

 

Total oil, NGL and gas sales including derivative impact

   $ 128,784      $ 111,762       $ 63,365   
  

 

 

   

 

 

    

 

 

 

The following table summarizes the prices we received for oil, NGLs and gas for each of the last three years.

 

     Years Ended December 31,  

Average prices

   2012     2011      2010  

Oil (per Bbl)

   $ 84.70      $ 88.18       $ 75.67   

NGLs (per Bbl)

     34.09        51.39         41.19   

Gas (per Mcf)

     2.63        3.92         4.48   
  

 

 

   

 

 

    

 

 

 

Total (per Boe)

   $ 44.63      $ 46.37       $ 37.00   

Realized (loss) gain on commodity derivatives (per Boe)

     (0.03     1.44         3.72   
  

 

 

   

 

 

    

 

 

 

Total including derivative impact (per Boe)

   $ 44.60      $ 47.81       $ 40.72   
  

 

 

   

 

 

    

 

 

 

Net income.    Net income for 2012 was $6.4 million, or $0.18 per diluted share, compared to net income of $7.2 million, or $0.25 per diluted share for 2011 and net income of $7.5 million, or $0.34 per diluted share for 2010. Net income decreased slightly over the three-year period due to higher expenses, partially offset by higher revenues. Net income per share decreased over the three-year period due to higher weighted average shares outstanding resulting from equity financings in 2011 and 2012.

Oil, NGL and gas production.    Production for 2012 totaled 2,888 MBoe (7.9 MBoe/d), compared to 2,338 MBoe (6.4 MBoe/d) produced in 2011, an increase of 24%. Production for 2012 was 34% oil, 31% NGLs and 35% natural gas, compared to 21% oil, 34% NGLs and 45% natural gas in 2011. The increase in production in 2012 is the result of our continued development of our Permian Basin properties. We expect 2013 production will increase over 2012 due to our planned drilling and development activities in the Permian Basin.

Production for 2011 totaled 2,338 MBoe (6.4 MBoe/d), compared to 1,556 MBoe (4.3 MBoe/d) produced in 2010, an increase of 50%. Production for 2011 was 21% oil, 34% NGLs and 45% natural gas, compared to 16% oil, 17% NGLs and 67% natural gas in 2010. The increase in production in 2011 is the result of our continued development of our Permian Basin properties, the acquisition of the remaining 38% working interest in Project Pangea and NGL processing in the southeast portion of Project Pangea; however, production was impacted during the second half of 2011 by oil takeaway constraints due to increased industry activity in the Permian Basin and a shortage of oil trucking capacity.

 

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The following table summarizes our production for each of the last three years.

 

     Years Ended December 31,  

Production

     2012          2011          2010    

Oil (MBbls)

     969         482         246   

NGLs (MBbls)

     904         798         261   

Gas (MMcf)

     6,089         6,345         6,290   
  

 

 

    

 

 

    

 

 

 

Total (MBoe)

     2,888         2,338         1,556   

Total (MBoe/d)

     7.9         6.4         4.3   

Commodity derivative activities.    Realized loss from our commodity derivative activity decreased our earnings by $108,000 for 2012, compared to realized gains in 2011 and 2010 that increased our earnings by $3.4 million and $5.8 million, respectively. Realized gains and losses are derived from the relative movement of commodity prices in relation to the fixed notional pricing of our commodity derivatives positions or the range of prices in our collars for the respective years. The unrealized loss on commodity derivatives was $347,000 for 2011, and the unrealized gain on commodity derivatives was $3.9 million and $788,000 for 2012 and 2010, respectively. As commodity prices increase or decrease, the fair value of the open portion of those positions decreases or increases.

Historically, we have not designated our derivative instruments as cash-flow hedges. We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized gain (loss) on commodity derivatives.”

Lease operating expense.    Our lease operating expenses (“LOE”) increased $8.3 million, or 78%, for 2012, to $19.0 million ($6.58 per Boe) from $10.7 million ($4.57 per Boe) for 2011. The increase in LOE per Boe in 2012 over 2011 was primarily due to an increase in workover, compression, water hauling and well repair and maintenance expenses.

Our LOE for 2011 was $10.7 million ($4.57 per Boe), compared to $6.6 million ($4.25 per Boe) for 2010. The increase in LOE for 2011 was primarily attributable to the acquisition of the remaining 38% working interest in Project Pangea, which increased our working interest to approximately 100%. The increase in LOE per Boe in 2011 over 2010 was primarily due to an increase in well repair and maintenance, partially offset by a decrease in compressor rental and repair and water hauling, insurance and other LOE.

The following table summarizes LOE per Boe.

 

     Year Ended December 31,     Year Ended December 31,  
     2012      2011      Change     % Change     2011      2010      Change     % Change  

Compressor rental and repair

   $ 1.91       $ 1.36       $ 0.55        40.4   $ 1.36       $ 1.45       $ (0.09     (6.2 )% 

Water hauling, insurance and other

     1.61         1.08         0.53        49.1        1.08         1.06         0.02        1.9   

Well repair and maintenance

     1.31         1.00         0.31        31.0        1.00         0.64         0.36        56.3   

Pumpers and supervision

     1.00         1.05         (0.05     (4.8     1.05         1.01         0.04        4.0   

Workovers

     0.75         0.08         0.67        837.5        0.08         0.09         (0.01     (11.1
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Total

   $ 6.58       $ 4.57       $ 2.01        44.0   $ 4.57       $ 4.25       $ 0.32        7.5
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Production and ad valorem taxes.    Our 2012 production and ad valorem taxes increased approximately $808,000, or 9.6%, to $9.3 million from $8.4 million for 2011. The increase in production and ad valorem taxes was primarily the result of an increase in oil, NGL and gas sales over 2011. Production and ad valorem taxes were approximately 7.2% and 7.8% of oil, NGL and gas sales for the respective periods. Ad valorem taxes were reclassified from LOE to production and ad valorem taxes in 2012 for all periods presented.

 

 

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Our production and ad valorem taxes increased $3.5 million, or 71.4%, for 2011 to $8.4 million from $4.9 million for 2010. The increase in production and ad valorem taxes was primarily the result of an increase in oil, NGL and gas sales over 2010. Production and ad valorem taxes were approximately 7.8% and 8.6% of oil, NGL and gas sales for the respective periods.

Exploration expense.    We recorded $4.6 million of exploration expense for 2012. Exploration expense for 2012 resulted primarily from the acquisition of 3-D seismic data and lease extensions in the Permian Basin. We recorded $9.5 million and $2.6 million of exploration expense for 2011 and 2010, respectively. Exploration expense for 2011 resulted primarily from lease extensions and expirations in the Permian Basin and the acquisition of 3-D seismic data in Pangea West. During 2011, we extended the acreage terms for an additional four years for approximately 9,200 acres in the northwest area of Project Pangea for $3.2 million, or approximately $350 per acre. Further, approximately 5,000 acres in the southeast area of Project Pangea expired during 2011 resulting in approximately $1.2 million of exploration expense. Exploration expense for 2010 resulted primarily from 3-D seismic acquisition in northwest Project Pangea and lease renewals in Project Pangea and Kentucky.

Impairment.    We review our long-lived assets, including proved and unproved oil and gas properties, accounted for under the successful efforts method of accounting. We recorded no impairment expense during the twelve months ended December 31, 2012. We recorded an impairment of oil and gas properties of $18.5 million and $2.6 million in 2011 and 2010, respectively. Due to ongoing, low natural gas prices and to the further decline in natural gas prices during the twelve months ended December 31, 2011, we recorded an impairment expense to our oil and gas properties in the East Texas Basin of $15.2 million in 2011. At December 31, 2011, we had $2.7 million recorded for our properties in the East Texas Basin, which is the estimated fair value at December 31, 2011. We also recorded an impairment expense of $3.3 million, which was all of our remaining carrying costs associated with our unproved properties in Northern New Mexico. The 2010 impairment resulted from a write-off of $2.6 million in costs in our Southwest Kentucky project, and represented the remaining carrying value we had recorded for the project.

General and administrative expenses.    Our general and administrative expenses (“G&A”) increased $7.0 million, or 39%, to $24.9 million ($8.62 per Boe) for 2012 from $17.9 million ($7.66 per Boe) for 2011. The increase in G&A in 2012 over 2011 was primarily due to higher share-based compensation, professional fees and salaries and benefits. For 2013, we expect G&A to be higher, compared to 2012, as a result of higher share-based compensation and staffing increases. However, we expect G&A to be consistent on a per Boe basis.

Our G&A increased $6.5 million, or 57%, to $17.9 million ($7.66 per Boe) for 2011 from $11.4 million ($7.34 per Boe) for 2010. The increase in G&A in 2011 over 2010 was primarily due to higher salaries and benefits, and share-based compensation.

The following table summarizes G&A (in millions).

 

     Year Ended December 31,     Year Ended December 31,  
     2012      2011      Change      % Change     2011      2010      Change      % Change  

Salaries and benefits

   $ 10.5       $ 8.1       $ 2.4         29.6   $ 8.1       $ 5.3       $ 2.8         52.8

Share-based compensation

     7.5         4.7         2.8         59.6        4.7         2.6         2.1         80.8   

Professional fees

     2.1         1.4         0.7         50.0        1.4         1.3         0.1         7.7   

Other

     4.8         3.7         1.1         29.7        3.7         2.2         1.5         68.2   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 24.9       $ 17.9       $ 7.0         39.1   $ 17.9       $ 11.4       $ 6.5         57.0
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Depletion, depreciation and amortization expense.    Our depletion, depreciation and amortization expense (“DD&A”) increased $27.9 million, or 86%, to $60.4 million for 2012, from $32.5 million for 2011. Our DD&A per Boe increased by $7.02, or 51%, to $20.91 per Boe for 2012, compared to $13.89 per Boe for 2011. The

 

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increase in DD&A and DD&A per Boe in 2012 over 2011 was primarily attributable to increases in production and oil and gas property carrying costs, relative to estimated proved developed reserves. The increase in oil and gas property carrying costs reflects our drilling and development program of the Wolfcamp oil shale resource play.

DD&A increased $10.3 million, or 46%, to $32.5 million for 2011, from $22.2 million for 2010. Our DD&A per Boe decreased by $0.39, or 3%, to $13.89 per Boe for 2011, compared to $14.28 per Boe for 2010. The increase in DD&A was primarily attributable to higher capitalized costs over 2010, partially offset by an increase in estimated proved developed reserves.

Interest expense, net.    The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the years ended December 31, 2012, 2011 and 2010 (dollars in thousands). Interest expense below includes amortization of loan origination fees.

 

     Year Ended December 31,  
     2012     2011     2010  

Interest expense

   $ 4,737      $ 3,402      $ 2,189   

Weighted average interest rate

     3.2     3.1     3.4

Weighted average debt balance

   $ 108,296      $ 78,810      $ 41,374   

Income taxes.    Our effective income tax rate for 2012 and 2011 was 34.3% and 32.5%, respectively. The higher income tax rate in 2012 was a result of a decrease in permanent differences from book and taxable income.

Our income taxes decreased $612,000 to $3.5 million for 2011, from $4.1 million for 2010. The decrease in income taxes was due to lower pre-tax income in 2011 and a lower effective income tax rate. Our effective income tax rate for 2011 and 2010 was 32.5% and 35.5%, respectively. The lower income tax rate in 2011 was a result of an increase in the impact of permanent differences from book and taxable income.

Liquidity and Capital Resources

We generally will rely on cash generated from operations, borrowings under our revolving credit facility and, to the extent that credit and capital market conditions will allow, future public equity and debt offerings to satisfy our liquidity needs. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under our revolving credit facility, and more broadly, on the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot predict whether additional liquidity from equity or debt financings beyond our revolving credit facility will be available on acceptable terms, or at all, in the foreseeable future.

Our cash flow from operations is driven by commodity prices, production volumes and the effect of commodity derivatives. Prices for oil and gas are affected by national and international economic and political environments, national and global supply and demand for hydrocarbons, seasonal influences of weather and other factors beyond our control. Cash flows from operations are primarily used to fund exploration and development of our oil and gas properties.

We believe we have adequate liquidity from cash generated from operations and unused borrowing capacity under our revolving credit facility for current working capital needs and maintenance of our current development project. However, we may determine to use various financing sources, including the issuance of common stock, preferred stock, debt, convertible securities and other securities for future development of reserves, acquisitions, additional working capital or other liquidity needs, if such financing is available on acceptable terms. We cannot guarantee that such financing will be available on acceptable terms or at all. Using some of these financing sources may require approval from the lenders under our revolving credit facility.

 

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Liquidity

We define liquidity as funds available under our revolving credit facility plus year-end net cash and cash equivalents. We had $106.0 million and $43.8 million in long-term debt outstanding under our revolving credit facility at December 31, 2012, and 2011, respectively. We had no long-term debt outstanding under our revolving credit facility at December 31, 2010.

The following table summarizes our liquidity position at December 31, 2012, 2011 and 2010 (in thousands).

 

     Year Ended December 31,  
     2012     2011     2010  

Borrowing base

   $ 280,000      $ 260,000      $ 150,000   

Cash and cash equivalents

     767        301        23,465   

Long-term debt

     (106,000     (43,800       

Undrawn letters of credit

     (325     (350     (350
  

 

 

   

 

 

   

 

 

 

Liquidity

   $ 174,442      $ 216,151      $ 173,115   
  

 

 

   

 

 

   

 

 

 

Working Capital

Our working capital is affected primarily by our cash and cash equivalents balance and our capital spending program. At December 31, 2012, we had a working capital deficit of $44.6 million, compared to a working capital deficit of $32.2 million and a working capital surplus of $12.1 million at December 31, 2011 and 2010, respectively. The change in working capital during 2012 and 2011 is primarily attributable to increases in accounts payable and accrued liabilities to fund capital expended on our development project. Our working capital deficits have been historically attributable to accounts payable and accrued liabilities and have been more than offset by liquidity available under our revolving credit facility. To the extent we operate or end 2013 with a working capital deficit, we expect such deficit to be more than offset by liquidity available under our revolving credit facility.

Cash Flows

The following table summarizes our sources and uses of funds for the periods noted (in thousands).

 

     Year Ended December 31,  
     2012     2011     2010  

Cash flows provided by operating activities

   $ 90,585      $ 95,770      $ 42,377   

Cash flows used in investing activities

     (307,414     (284,758     (91,346

Cash flows provided by financing activities

     217,295        165,843        69,748   

Effect of Canadian exchange rate

            (19     1   
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

   $ 466      $ (23,164   $ 20,780   
  

 

 

   

 

 

   

 

 

 

For 2012, our primary sources of cash were from operating activities and financing activities. Approximately $90.6 million of cash from operations and $217.3 million of cash from financing activities were used to fund our development project in the Permian Basin. In September, we sold 5.0 million shares of common stock, and in October 2012, the underwriters exercised their option and purchased an additional 325,000 shares. After deducting underwriting discounts and estimated transaction costs of approximately $8.0 million, we received net proceeds of approximately $154.4 million. We used the proceeds of the offering to repay outstanding borrowings under our revolving credit facility, fund our capital expenditures for the development of our Wolfcamp oil shale resource play and for general working capital needs.

For 2011, our primary sources of cash were from operating activities and financing activities. Approximately $95.8 million of cash from operations and $165.8 million of cash from financing activities were

 

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used to fund a portion of our development project and the Working Interest Acquisition. In November 2011, we sold 4.6 million shares of common stock. After deducting underwriting discounts and estimated transaction costs of approximately $6.6 million, we received net proceeds of approximately $122.2 million. We used the proceeds of the offering to repay outstanding borrowings under our revolving credit facility, fund our capital expenditures for the Wolfcamp oil shale resource play, fund working interest and leasehold acquisitions in the Permian Basin and for general working capital needs.

For 2010, our primary sources of cash were from operating activities and financing activities. Approximately $42.4 million of cash from operations was used to fund a portion of our development project and pay down our long-term debt. In November 2010, we sold 6.6 million shares of common stock. After deducting underwriting discounts and estimated transaction costs of approximately $5.7 million, we received net proceeds of approximately $101.8 million. We used a portion of the proceeds of the offering to repay all outstanding borrowings under our revolving credit facility, and to fund our capital expenditures for the Wolfcamp oil shale resource play, working interest and leasehold acquisitions in the Permian Basin and general working capital needs.

Operating Activities

For 2012, our cash flows from operations, borrowings under our revolving credit facility and available cash were used primarily for drilling and development activities and leasehold acquisitions in the Permian Basin. Cash flows from operating activities decreased by $5.2 million, or 5%, to $90.6 million in 2012 from $95.8 million in 2011. The decrease in cash flows from operating activities in 2012 versus 2011 was primarily due to a decrease in cash flows provided by working capital, lower average realized NGL and gas prices, partially offset by higher production volumes in 2012 due to our development project in the Wolfcamp oil shale resource play.

For 2011, our cash flows from operations, borrowings under our revolving credit facility and available cash were used primarily for drilling and development activities and leasehold acquisitions in the Permian Basin and the acquisition of 38% working interest in Project Pangea from non-operating partners for $70.8 million, after post-closing adjustments. Cash flows from operating activities increased by $53.4 million, or 126%, to $95.8 million from $42.4 million in 2010, primarily due to an 88% increase in oil, NGL and gas sales in 2011.

For 2010, our cash flows from operations, borrowings under our revolving credit facility and available cash were used primarily for drilling and development activities in Project Pangea, leasehold acquisitions and a 3-D seismic program in our Permian Basin operations. Cash flows from operating activities increased by 6.8%, or $2.7 million, to $42.4 million from 2009 partially due to a 42% increase in oil and gas sales in 2010. Cash flows provided by operating activities also were affected by an increase in cash flows used by working capital during 2010.

Investing Activities

During the years ended December 31, 2012, 2011 and 2010, we invested $296.9 million, $284.6 million and $91.0 million, respectively, for capital expenditures on oil and natural gas properties. Cash flows used in investing activities were higher during the year ended December 31, 2012 over 2011, primarily due to drilling and development ($240.4 million), infrastructure projects, equipment and 3-D seismic data acquisition ($47.5 million) and lease acquisitions and extensions ($9 million), all in Project Pangea. Cash flows used in investing activities were substantially higher during the year ended December 31, 2011 over 2010, primarily due to the acquisition of 38% working interest in Project Pangea from non-operating partners for $70.8 million, after post-closing adjustments, and expenditures for drilling and lease acquisitions and extensions in the Permian Basin.

 

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The following table is a summary of capital expenditures related to our oil and gas properties (in thousands).

 

     Years Ended December 31,  
     2012      2011      2010  

Permian Basin

   $ 240,357       $ 172,077       $ 56,211   

Permian Basin acquisitions

             70,827         21,179   
  

 

 

    

 

 

    

 

 

 

Subtotal

     240,357         242,904         77,390   

East Texas Basin

             560         101   

Exploratory projects

             445         285   

Infrastructure projects, equipment and inventory

     44,278         8,695         1,636   

Lease acquisition, geological and geophysical

     12,292         31,970         11,604   
  

 

 

    

 

 

    

 

 

 

Total

   $ 296,927       $ 284,574       $ 91,016   
  

 

 

    

 

 

    

 

 

 

Additionally, in September 2012, we entered into a joint venture to build an oil pipeline in Crockett and Reagan Counties, Texas, which will be used to transport our oil to market. In October 2012, we made an initial contribution of $10 million to the joint venture for pipeline and facilities construction. Future capital contributions are discretionary.

Financing Activities

The following is a description of our financing activities. During 2012, 2011 and 2010 we completed the following capital markets activities:

 

   

In September 2012, we completed a public offering of 5.0 million shares of our common stock at $30.50 per share, and in October 2012, the underwriters exercised their option and purchased an additional 325,000 shares. We received net proceeds of approximately $154.4 million, and used the proceeds to repay outstanding borrowings under our revolving credit facility, fund our capital expenditures for the development of our Wolfcamp oil shale resource play and for general working capital needs.

 

   

In November 2011, we completed an equity offering and issued an aggregate of 4.6 million shares of our common stock at $28 per share, and we received net proceeds of approximately $122.2 million. We used the proceeds of the 2011 equity offering to repay outstanding borrowings under our revolving credit facility, fund our capital expenditures for the Wolfcamp oil shale resource play, fund working interest and leasehold acquisitions in the Permian Basin and for general working capital needs.

 

   

In November 2010, we issued 6.6 million shares of our common stock at $16.25 per share, and we received net proceeds of approximately $101.8 million. We used the proceeds of the 2010 equity offering to repay all outstanding borrowings under our revolving credit facility, and to fund our capital expenditures for the Wolfcamp oil shale resource play, working interest and leasehold acquisitions in the Permian Basin and general working capital needs.

We borrowed $304.6 million under our revolving credit facility in 2012, compared to $246.8 million and $121.8 million in 2011 and 2010, respectively. We repaid a total of $242.4 million, $203 million and $154.1 million of amounts outstanding under our revolving credit facility for 2012, 2011 and 2010, respectively. Our current goal is to manage our borrowings to help us maintain financial flexibility and liquidity, and to avoid the problems associated with highly-leveraged companies with large interest costs and possible debt reductions restricting ongoing operations.

2013 Capital Expenditures

In September 2012, we announced a 2013 capital budget of $260 million, which includes three rigs to drill horizontal wells targeting the Wolfcamp shale. We expect that our horizontal drilling in Project Pangea in 2013

 

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will include pad drilling, which we believe will improve operating efficiencies and resource recoveries while reducing facilities costs and surface impact. We also may drill vertical wells targeting the Wolffork or recomplete Canyon Sands wells in the Wolffork during 2013. Our objectives for 2013 include advancing our understanding of optimal well spacing, testing multi-zone potential to enhance hydrocarbon recovery in our Wolffork targets and improving our cost structure.

Our 2013 capital budget is subject to change depending upon a number of factors, including additional data on our Wolfcamp oil shale resource play, results of horizontal and vertical drilling, completions and recompletions, including pad drilling, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil, NGLs and gas, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.

Revolving Credit Facility

We have a $300 million revolving credit facility with a borrowing base set at $280 million. The borrowing base is redetermined semi-annually on or before each April 1 and October 1 based on our oil and gas reserves. We or the lenders can each request one additional borrowing base redetermination each calendar year.

The maturity date under our revolving credit facility is July 31, 2014. Borrowings bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 0.75% to 1.75%, or the sum of the Eurodollar rate plus an applicable margin ranging from 1.75% to 2.75%. Margins vary based on the borrowings outstanding compared to the borrowing base. In addition, we pay an annual commitment of 0.50% of unused borrowings available under our revolving credit facility.

We had outstanding borrowings of $106 million and $43.8 million under our revolving credit facility at December 31, 2012, and 2011, respectively. The interest rate applicable to our revolving credit facility at December 31, 2012, and 2011, was 2.7% and 3.7%, respectively. We also had outstanding unused letters of credit under our revolving credit facility totaling $325,000 at December 31, 2012, which reduce amounts available for borrowing under our revolving credit facility.

Loans under our revolving credit facility are secured by first-priority liens on substantially all of our West Texas assets, a pledge of our equity interests in our subsidiaries, and are guaranteed by our subsidiaries.

Covenants

Our credit agreement contains two principal financial covenants:

 

   

a consolidated modified current ratio covenant that requires us to maintain a ratio of not less than 1.0 to 1.0 at all times. The consolidated modified current ratio is calculated by dividing Consolidated Current Assets (as defined in the credit agreement) by Consolidated Current Liabilities (as defined in the credit agreement). As defined more specifically in the credit agreement, the consolidated modified current ratio is calculated as current assets less current unrealized gains on commodity derivatives plus the available borrowing base at the respective balance sheet date, divided by current liabilities less current unrealized losses on commodity derivatives at the respective balance sheet date.

 

   

a consolidated funded debt-to-consolidated EBITDAX ratio covenant that requires us to maintain a ratio of not more than 4.0 to 1.0 at the end of each fiscal quarter. The consolidated funded debt to consolidated EBITDAX ratio is calculated by dividing Consolidated Funded Debt (as defined in the credit agreement) by Consolidated EBITDAX (as defined in the credit agreement). As defined more specifically in the credit agreement, consolidated EBITDAX is calculated as net income (loss), plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss on commodity derivatives, (5) interest expense, (6) income and franchise taxes and (7) certain other noncash expenses, less (1) gains or losses from sales or dispositions of assets,

 

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(2) unrealized gain on commodity derivatives and (3) extraordinary or nonrecurring gains. For purposes of calculating this ratio, consolidated EBITDAX for a fiscal quarter is annualized pursuant to the credit agreement.

Our credit agreement also restricts cash dividends and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, asset sales, investments in other entities and liens on properties.

In addition, our credit agreement contains customary events of default that would permit our lenders to accelerate the debt under our credit agreement if not cured within applicable grace periods, including, among others, failure to make payments of principal or interest when due, materially incorrect representations and warranties, failure to make mandatory prepayments in the event of borrowing base deficiencies, breach of covenants, defaults upon other obligations in excess of $500,000, events of bankruptcy, the occurrence of one or more unstayed judgments in excess of $500,000 not covered by an acceptable policy of insurance, failure to pay any obligation in excess of $500,000 owed under any derivatives transaction or in any amount if the obligation under the derivatives transaction is secured by collateral under the credit agreement, any event of default by the Company occurs under any agreement entered into in connection with a derivatives transaction, liens securing the loans under the credit agreement cease to be in place, a Change in Control (as defined in the credit agreement) of the Company occurs and dissolution of the Company.

At December 31, 2012, we were in compliance with all of our covenants and had not committed any acts of default under the credit agreement.

To date we have experienced no disruptions in our ability to access our revolving credit facility. However, our lenders have substantial ability to reduce our borrowing base on the basis of subjective factors, including the loan collateral value that each lender, in its discretion and using the methodology, assumptions and discount rates as such lender customarily uses in evaluating oil and gas properties, assigns to our properties.

Contractual Obligations

As of December 31, 2012, our contractual obligations include long-term debt, daywork drilling contracts, operating lease obligations, asset retirement obligations and employment agreements with our executive officers.

We periodically enter into contractual arrangements under which we are committed to expend funds to drill wells in the future, including agreements to secure drilling rig services, which require us to make future minimum payments to the rig operators. We record drilling commitments in the periods in which well capital expenditures are incurred or rig services are provided. Our commitment under daywork drilling contracts was $5.4 million at December 31, 2012.

In April 2007, we signed a five-year lease for approximately 13,000 square feet of office space in Fort Worth, Texas. In August 2008, we expanded our office space under an amendment to the lease to approximately 18,000 square feet. In December 2010, we expanded our office space under an amendment to the lease to approximately 23,400 square feet. In August 2012, we further expanded our office space under a third amendment to the lease to approximately 27,000 square feet and extended the term of the lease to December 31, 2017. In December 2012, we began rent payments under the third amendment, bringing our total office lease payment to approximately $51,000 per month.

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable federal, state and local laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.

 

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At December 31, 2012, we had outstanding employment agreements with each of our five executive officers that contained automatic renewal provisions providing that such agreements may be automatically renewed for successive terms of one year unless the employment is terminated at the end of the term by written notice given to the employee not less than 60 days prior to the end of such term. Our maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were each terminated without cause, was approximately $4.9 million at December 31, 2012.

The following table summarizes these commitments as of December 31, 2012 (in thousands).

 

     Payments Due By Period  

Contractual Obligations

   Total      Less than
1 year
     1-3 years      3-5 years      More than
5 years
 

Long-term debt(1)

   $ 106,000       $       $ 106,000       $       $   

Daywork drilling contracts(2)

     5,443         5,443                           

Operating lease obligations(3)

     3,221         633         1,949         639           

Asset retirement obligations(4)

     7,431                                 7,431   

Employment agreements with executive officers

     4,908         4,908                           
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 127,003       $ 10,984       $ 107,949       $ 639       $ 7,431   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Borrowings under our credit agreement.
(2) At December 31, 2012, daywork drilling contracts related to four drilling rigs were contracted through January 4, 2013, February 28, 2013, April 18, 2013 and July 6, 2013, respectively.
(3) Operating lease obligations are for office space and equipment.
(4) See Note 1 to our consolidated financial statements for a discussion of our asset retirement obligations.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2012, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit, operating lease agreements and gas transportation commitments. We do not believe that these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

General Trends and Outlook

Our financial results depend upon many factors, particularly the price of oil, NGLs and gas. Commodity prices are affected by changes in market demand, which is impacted by domestic and foreign supply of oil, NGLs and gas, overall domestic and global economic conditions, commodity processing, gathering and transportation availability and the availability of refining capacity, price and availability of alternative fuels, price and quantity of foreign imports, domestic and foreign governmental regulations, political conditions in or affecting other oil and gas producing countries, weather and technological advances affecting oil, NGL and gas consumption. As a result, we cannot accurately predict future oil, NGL and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. A substantial or extended decline in oil, NGL and gas prices could have a material adverse effect on our business, financial condition, results of operations, quantities of oil and gas reserves that may be economically produced and liquidity that may be accessed through our borrowing base under our revolving credit facility and through capital markets.

In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success. Future finding and development costs are subject to changes in the industry, including the costs of acquiring, drilling and completing our projects. We focus our efforts on increasing oil and gas reserves and production while controlling costs at a level that is

 

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appropriate for long-term operations. Our future cash flow from operations will depend on our ability to manage our overall cost structure.

Like all oil and gas production companies, we face the challenge of natural production declines. Oil and gas production from a given well naturally decreases over time. Additionally, our reserves have a rapid initial decline. We attempt to overcome this natural decline by drilling to develop and identify additional reserves, farm-ins or other joint drilling ventures, and by acquisitions. However, during times of severe price declines, we may from time-to-time reduce current capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially reduce our production volumes and revenues and increase future expected costs necessary to develop existing reserves.

We also face the challenge of financing exploration, development and future acquisitions. We believe we have adequate liquidity from cash generated from operations and unused borrowing capacity under our revolving credit facility for current working capital needs and maintenance of our current development project. However, we may determine to access the public or private equity or debt markets for future development of reserves, acquisitions, additional working capital or other liquidity needs, if such financing is available on acceptable terms. We cannot guarantee that such financing will be available on acceptable terms or at all.

 

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices, and other related factors. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for commodity derivative and investment purposes, not for trading purposes.

Proved Reserves

Estimates of proved oil and gas reserves directly impact financial accounting estimates including depletion, depreciation and amortization expense, evaluation of impairment of properties and the calculation of plugging and abandonment liabilities. Proved oil and gas reserves are those quantities of oil and 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 process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for any reservoir may change substantially over time due to results from operational activity. Proved reserve volumes at December 31, 2012, were estimated based on the average of the closing price on the first day of each month for the 12-month period prior to December 31, 2012, for oil, NGLs and natural gas in accordance with SEC rules. Changes in commodity prices and operations costs may increase or decrease estimates of proved oil, NGL and natural gas reserves. Depletion expense for our oil and gas properties is determined using our estimates of proved oil, NGL and natural gas reserves. A hypothetical 10% decline in our December 31, 2012, estimated proved reserves would have increased our depletion expense by approximately $1.9 million for the year ended December 31, 2012.

Commodity Price Risk

Given the current economic outlook, we expect commodity prices to remain volatile. Even modest decreases in commodity prices can materially affect our revenues and cash flow. In addition, if commodity prices remain suppressed for a significant amount of time, we could be required under successful efforts accounting rules to write down our oil and gas properties.

 

 

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We enter into financial swaps and options to reduce the risk of commodity price fluctuations. We do not designate such instruments as cash flow hedges. Accordingly, we record open commodity derivative positions on our consolidated balance sheets at fair value and recognize changes in such fair values as income (expense) on our consolidated statements of operations as they occur.

The table below summarizes our commodity derivatives positions outstanding at December 31, 2012.

 

Commodity and Time Period

   Contract
Type
         Volume Transacted          Contract Price

Crude Oil

        

2013

   Collar    650 Bbls/d    $90.00/Bbl – $105.80/Bbl

2013

   Collar    450 Bbls/d    $90.00/Bbl – $101.45/Bbl

2014

   Collar    550 Bbls/d    $90.00/Bbl – $105.50/Bbl

Natural Gas

        

2013

   Swap    200,000 MMBtu/month    $3.54/MMBtu

2013

   Swap    190,000 MMBtu/month    $3.80/MMBtu

Subsequent to December 31, 2012, we added to our 2013 commodity derivatives positions with a crude oil collar contract covering 1,200 Bbls/d for February 2013 through December 2013 at a contract floor of $90.35/Bbl and a ceiling of $100.35/Bbl. We also added to our 2013 commodity derivatives positions with a Midland/Cushing basis differential swap covering 2,300 Bbls/d from March 2013 through December 2013 at a price of $1.10/Bbl.

At December 31, 2012 and December 31, 2011, the fair value of our open derivative contracts was an asset of approximately $2.4 million and a liability of approximately $1.4 million, respectively.

JPMorgan Chase Bank, N.A. and KeyBank National Association are currently the only counterparties to our commodity derivatives positions. We are exposed to credit losses in the event of nonperformance by counterparties on our commodity derivatives positions. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions. JPMorgan is the administrative agent and a participant, and KeyBank is the documentation agent and a participant, in our revolving credit facility. The collateral for the outstanding borrowings under our revolving credit facility is used as collateral for our commodity derivatives.

Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.

For the years ended December 31, 2012 and 2010, we recognized an unrealized gain of $3.9 million and $788,000 from the change in the fair value of commodity derivatives, respectively. For the year ended December 31, 2011, we recognized an unrealized loss of $347,000 from the change in the fair value of commodity derivatives. A hypothetical 10% increase in the NYMEX floating prices would have resulted in a $5.4 million decrease in the December 31, 2012, fair value recorded on our balance sheet, and a corresponding decrease to the gain on commodity derivatives in our statement of operations.

 

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To estimate the fair value of our commodity derivatives positions, we use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to use the best available information. We determine the fair value based upon the hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

 

   

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At December 31, 2012, we had no Level 1 measurements.

 

   

Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At December 31, 2012, all of our commodity derivatives were valued using Level 2 measurements.

 

   

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At December 31, 2012, our Level 3 measurements were used to calculate our asset retirement obligation at December 31, 2012. Additionally, Level 3 measurements were used to calculate our estimated fair value of our oil and gas properties in the East Texas Basin. We valued these properties by estimating future discounted net cash flows of reserves using forward market prices adjusted for locational basis differentials and other costs.

 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our consolidated financial statements and supplemental data are included in this report beginning on page F-1.

 

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

We had no changes in, and no disagreements with, our accountants on accounting and financial disclosure.

 

ITEM 9A.  CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our President and Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2012. Based on this evaluation, our President and Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2012, our disclosure controls and procedures were effective, in that they ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management, including our President and Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

Management’s Annual Report on Internal Control Over Financial Reporting and Attestation Report of Registered Public Accounting Firm

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, we have included a report of management’s assessment of the design and effectiveness of our internal controls as part of this annual report on Form 10-K for the fiscal year ended December 31, 2012. Hein & Associates LLP (“Hein”), our independent registered public accounting firm, also attested to, and reported on, our internal control over financial reporting. Management’s report and Hein’s attestation report are referenced on page F-1 under the captions “Management’s Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm — Internal Control over Financial Reporting” and are incorporated herein by reference.

Changes in Internal Control over Financial Reporting

No changes to our internal control over financial reporting occurred during the quarter ended December 31, 2012, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act).

 

ITEM 9B.  OTHER INFORMATION

None.

 

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PART III

 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required under Item 10 of this report will be contained under the captions “Election of Directors — Directors,” “Executive Officers” and “Corporate Governance” to be provided in our proxy statement for our 2013 annual meeting of stockholders to be filed with the SEC on or before April 30, 2013, which are incorporated herein by reference. Additional information regarding our corporate governance guidelines as well as the complete texts of our Code of Conduct and the charters of our Audit Committee and our Compensation and Nominating Committee may be found on our website at www.approachresources.com.

 

ITEM 11. EXECUTIVE COMPENSATION

Information required by Item 11 of this report will be contained under the caption “Executive Compensation” in our definitive proxy statement for our 2013 annual meeting of stockholders to be filed with the SEC on or before April 30, 2013, which is incorporated herein by reference.

 

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by Item 12 of this report will be contained under the caption “Stock Ownership Matters” in our definitive proxy statement for our 2013 annual meeting of stockholders to be filed with the SEC on or before April 30, 2013, which is incorporated herein by reference.

 

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by Item 13 of this report will be contained under the captions “Certain Relationships and Related Party Transactions” and “Corporate Governance–Board Independence” in our definitive proxy statement for our 2013 annual meeting of stockholders to be filed with the SEC on or before April 30, 2013, which are incorporated herein by reference.

 

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required by Item 14 of this report will be contained under the caption “Independent Registered Public Accountants” in our definitive proxy statement for our 2013 annual meeting of stockholders to be filed with the SEC on or before April 30, 2013, which is incorporated herein by reference.

 

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PART IV

 

ITEM 15.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 

(a) Documents filed as part of this report

(1) and (2) Financial Statements and Financial Statement Schedules.

See “Index to Consolidated Financial Statements” on page F-1.

(3) Exhibits.

See “Index to Exhibits” on page 66 for a description of the exhibits filed as part of this report.

 

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GLOSSARY AND SELECTED ABBREVIATIONS

The following is a description of the meanings of some of the oil and gas industry terms used in this report.

 

3-D seismic

(Three Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two dimensional seismic data.

 

Basin

A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

 

Bbl

One stock tank barrel, of 42 U.S. gallons liquid volume, used to reference oil, condensate or NGLs.

 

Boe

Barrel of oil equivalent, determined using the ratio of six Mcf of gas to one Boe, and one Bbl of NGLs to one Boe.

 

Btu or British Thermal Unit

The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

 

Completion

The installation of permanent equipment for production of oil or gas, or, in the case of a dry well, for reporting to the appropriate authority that the well has been abandoned.

 

Developed acreage

The number of acres that are allocated or assignable to productive wells or wells that are capable of production.

 

Developed oil and gas reserves

Has the meaning given to such term in Rule 4-10(a)(6) of Regulation S-X, as follows:

 

  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

  (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

  (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

Development project

The means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

 

Development well

A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

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Dry hole or well

An exploratory, development or extension well that proved to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

 

Dry hole costs

Costs incurred in drilling a well, assuming a well is not successful, including plugging and abandonment costs.

 

Exploratory well

A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

 

Extension well

A well drilled to extend the limits of a known reservoir.

 

Farm-in

An arrangement in which the owner or lessee of mineral rights (the first party) assigns a working interest to an operator (the second party), the consideration for which is specified exploration and/or development activities. The first party retains an overriding royalty, working interest or other type of economic interest in the mineral production. The arrangement from the viewpoint of the second party is termed a “farm-in” arrangement.

 

Field

An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

Hydraulic fracturing

The technique designed to improve a well’s production rates by pumping a mixture of water and sand (in our case, over 99% by mass) and chemical additives (in our case, less than 1% by mass) into the formation and rupturing the rock, creating an artificial channel.

 

Gross acres or gross wells

The total acres or wells, as the case may be, in which a working interest is owned.

 

Lease operating expenses

The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short lived assets, maintenance, allocated overhead costs and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

 

LNG

Liquefied natural gas.

 

MBbls

Thousand barrels of oil or other liquid hydrocarbons.

 

MBoe

Thousand barrels of oil equivalent, determined using the ratio of six Mcf of gas to one Boe, and one Bbl of NGLs to one Boe.

 

Mcf

Thousand cubic feet of natural gas.

 

MMBoe

Million barrels of oil equivalent, determined using the ratio of six Mcf of gas to one Boe, and one Bbl of NGLs to one Boe.

 

MMBtu

Million British thermal units.

 

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MMcf

Million cubic feet of gas.

 

Net acres or net wells

The sum of the fractional working interests owned in gross acres or wells, as the case may be.

 

NGLs

Natural gas liquids. The portions of gas from a reservoir that are liquefied at the surface in separators, field facilities or gas processing plants.

 

NYMEX

New York Mercantile Exchange.

 

Play

A set of known or postulated oil and/or gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type.

 

Productive well

An exploratory, development or extension well that is not a dry well.

 

Prospect

A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

 

Proved developed producing reserves

Proved developed oil and gas reserves that are expected to be recovered:

 

  (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

  (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

Proved oil and gas reserves

Has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, as follows:

 

  Proved oil and gas reserves are those quantities of oil and 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 — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

  (i) The area of the reservoir considered as proved includes:

 

  (A) The area identified by drilling and limited by fluid contacts, if any, and

 

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  (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

  (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

  (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

  (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

  (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

  (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

  (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

PV-10

An estimate of the present value of the future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the

 

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properties. Estimates of PV-10 are made using oil and gas prices and operating costs at the date indicated and held constant for the life of the reserves.

 

“Recompletion” or to “recomplete” a well

The addition of production from another interval or formation in an existing wellbore.

 

Reserve life

This index is calculated by dividing year-end 2012 estimated proved reserves by 2012 production of 2,888 MBoe to estimate the number of years of remaining production.

 

Reservoir

A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

 

Spacing

The distance between wells producing from the same reservoir. Spacing is expressed in terms of acres, e.g., 40-acre spacing, and is established by regulatory agencies.

 

Standardized measure

The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the period end date) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depletion, depreciation and amortization and discounted using an annual discount rate of 10%. Standardized measure does not give effect to derivative transactions.

 

Tight gas sands

A sandstone formation with low permeability that produces natural gas with low flow rates for long periods of time.

 

Unconventional resources or reserves

Natural gas or oil resources or reserves from (i) low-permeability sandstone and shale formations, such as tight gas and gas shales, respectively, and (ii) coalbed methane.

 

Undeveloped acreage

Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether such acreage contains proved reserves.

 

Undeveloped oil and gas reserves

Has the meaning given to such term in Rule 4-10(a)(31) of Regulation S-X, which defines proved undeveloped reserves as follows:

 

  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

  (i)

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain

 

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  of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

  (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

 

  (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

 

Working interest

The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

 

Workover

Operations on a producing well to restore or increase production.

 

/d

“Per day” when used with volumetric units or dollars.

 

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

APPROACH RESOURCES INC.
By:   /s/ J. Ross Craft
  J. Ross Craft
  President and Chief Executive Officer

Date: February 28, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on February 28, 2013.

 

Signature

  

Title

/s/    J. Ross Craft        

   President, Chief Executive Officer and Director
(Principal Executive Officer)

J. Ross Craft

  

/s/    Steven P. Smart        

   Executive Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)

Steven P. Smart

  

/s/    Bryan H. Lawrence        

   Director and Chairman of the Board of Directors

Bryan H. Lawrence

  

/s/    Alan D. Bell        

   Director

Alan D. Bell

  

/s/    James H. Brandi        

   Director

James H. Brandi

  

/s/    James C. Crain        

   Director

James C. Crain

  

/s/    Sheldon B. Lubar        

   Director

Sheldon B. Lubar

  

/s/    Christopher J. Whyte        

   Director

Christopher J. Whyte

  

 

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS OF APPROACH RESOURCES INC.

 

     Page  

Management’s Report on Internal Control Over Financial Reporting

     F-2   

Report of Independent Registered Public Accounting Firm — Internal Control Over Financial Reporting

     F-3   

Report of Independent Registered Public Accounting Firm — Financial Statements

     F-4   

Consolidated Balance Sheets as of December 31, 2012 and 2011

     F-5   

Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010

     F-6   

Consolidated Statements of Changes in Stockholders’ Equity for the years ended December  31, 2010, 2011 and 2012

     F-7   

Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010

     F-8   

Notes to Consolidated Financial Statements

     F-9   

 

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance to management and our board of directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, we believe that, as of December 31, 2012, our internal control over financial reporting is effective based on those criteria.

 

By:    /s/    J. Ross Craft     By:    /s/    Steven P. Smart
  J. Ross Craft       Steven P. Smart
  President and Chief Executive Officer       Executive Vice President and Chief Financial Officer

Fort Worth, Texas

February 28, 2013

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Approach Resources Inc.

We have audited Approach Resources Inc. and subsidiaries’ (collectively, the “Company”) internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (c) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Approach Resources Inc. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012 and our report dated February 28, 2013 expressed an unqualified opinion.

 

/s/ HEIN & ASSOCIATES LLP
Dallas, Texas
February 28, 2013

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Approach Resources Inc.

We have audited the accompanying consolidated balance sheets of Approach Resources Inc. and subsidiaries (collectively, the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Approach Resources Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

 

/s/ HEIN & ASSOCIATES LLP
Dallas, Texas
February 28, 2013

 

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Table of Contents

Approach Resources Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands, except shares and per-share amounts)

 

     December 31,  
     2012     2011  
ASSETS   

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 767      $ 301   

Accounts receivable:

    

Joint interest owners

     215        179   

Oil, NGL and gas sales

     12,575        10,060   

Unrealized gain on commodity derivatives

     1,552          

Prepaid expenses and other current assets

     547        342   

Deferred income taxes — current

            504   
  

 

 

   

 

 

 

Total current assets

     15,656        11,386   

PROPERTIES AND EQUIPMENT:

    

Oil and gas properties, at cost, using the successful efforts method of accounting

     1,025,440        732,659   

Furniture, fixtures and equipment

     2,108        1,621   
  

 

 

   

 

 

 
     1,027,548        734,280   

Less accumulated depletion, depreciation and amortization

     (199,081     (138,996
  

 

 

   

 

 

 

Net properties and equipment

     828,467        595,284   

Equity method investment

     9,892          

Unrealized gain on commodity derivatives

     881          

Other assets

     843        1,224   
  

 

 

   

 

 

 

Total assets

   $ 855,739      $ 607,894   
  

 

 

   

 

 

 
LIABILITIES AND STOCKHOLDERS’ EQUITY   

CURRENT LIABILITIES:

    

Accounts payable

   $ 24,916      $ 12,599   

Oil, NGL and gas sales payable

     4,960        4,748   

Deferred income taxes — current

     531     

Accrued liabilities

     29,840        24,837   

Unrealized loss on commodity derivatives

            1,441   
  

 

 

   

 

 

 

Total current liabilities

     60,247        43,625   

NON-CURRENT LIABILITIES:

    

Long-term debt

     106,000        43,800   

Deferred income taxes

     48,593        46,290   

Asset retirement obligations

     7,431        6,730   
  

 

 

   

 

 

 

Total liabilities

     222,271        140,445   

COMMITMENTS AND CONTINGENCIES (Note 8)

    

STOCKHOLDERS’ EQUITY :

    

Preferred stock, $0.01 par value, 10,000,000 shares authorized none outstanding

              

Common stock, $0.01 par value, 90,000,000 shares authorized, 38,829,368 and 33,093,594 issued and outstanding, respectively

     388        331   

Additional paid-in capital

     560,468        400,890   

Retained earnings

     72,612        66,228   
  

 

 

   

 

 

 

Total stockholders’ equity

     633,468        467,449   
  

 

 

   

 

 

 

Total liabilities and stockholders’ equity

   $ 855,739      $ 607,894   
  

 

 

   

 

 

 

See accompanying notes to these consolidated financial statements.

 

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Table of Contents

Approach Resources Inc. and Subsidiaries

Consolidated Statements of Operations

(In thousands, except shares and per-share amounts)

 

     Years Ended December 31,  
     2012     2011     2010  

REVENUES:

      

Oil, NGL and gas sales

   $ 128,892      $ 108,387      $ 57,581   

EXPENSES:

      

Lease operating

     19,002        10,687        6,620   

Production and ad valorem taxes

     9,255        8,447        4,925   

Exploration

     4,550        9,546        2,589   

Impairment

            18,476        2,622   

General and administrative

     24,903        17,900        11,422   

Depletion, depreciation and amortization

     60,381        32,475        22,224   
  

 

 

   

 

 

   

 

 

 

Total expenses

     118,091        97,531        50,402   
  

 

 

   

 

 

   

 

 

 

OPERATING INCOME

     10,801        10,856        7,179   

OTHER:

      

Interest expense, net

     (4,737     (3,402     (2,189

Equity in losses of investee

     (108              

Realized (loss) gain on commodity derivatives

     (108     3,375        5,784   

Unrealized gain (loss) on commodity derivatives

     3,874        (347     788   

Gain on sale of oil and gas properties, net of foreign currency transaction loss

            248          
  

 

 

   

 

 

   

 

 

 

INCOME BEFORE INCOME TAX PROVISION

     9,722        10,730        11,562   

INCOME TAX PROVISION

     3,338        3,488        4,100   
  

 

 

   

 

 

   

 

 

 

NET INCOME

   $ 6,384      $ 7,242      $ 7,462   
  

 

 

   

 

 

   

 

 

 

EARNINGS PER SHARE:

      

Basic

   $ 0.18      $ 0.25      $ 0.34   
  

 

 

   

 

 

   

 

 

 

Diluted

   $ 0.18      $ 0.25      $ 0.34   
  

 

 

   

 

 

   

 

 

 

WEIGHTED AVERAGE SHARES OUTSTANDING:

      

Basic

     34,965,182        28,930,792        22,065,797   

Diluted

     35,030,323        29,158,598        22,214,070   

See accompanying notes to these consolidated financial statements.

 

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Table of Contents

Approach Resources Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity

for the Years Ended December 31, 2010, 2011 and 2012

(In thousands, except shares and per-share amounts)

 

                  Additional
Paid-in
Capital
    Retained
Earnings
    

Accumulated

Other

Comprehensive

    Total  
                  
     Common Stock            
     Shares     Amount           Income (Loss)    

BALANCES, January 1, 2010

     20,959,285      $ 209       $ 168,993      $ 51,524       $ (230   $ 220,496   

Issuance of common stock upon exercise of options

     58,798        1         750                       751   

Issuance of common stock, net of issuance costs

     6,612,500        66         101,698                       101,764   

Issuance of common shares to directors for compensation

     46,347                380                       380   

Restricted stock issuance, net of cancellations

     560,870        6         (6                      

Share-based compensation expense

                    2,248                       2,248   

Surrender of restricted shares for payment of income taxes

     (10,910             (89                    (89

Adjustment to additional paid-in capital for tax shortfall upon vesting of restricted shares

                    (62                    (62

Net income

                           7,462                7,462   

Foreign currency translation adjustments, net of related income tax of $2

                                   (4     (4
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

BALANCES, December 31, 2010

     28,226,890        282         273,912        58,986         (234   $ 332,946   

Issuance of common stock upon exercise of options

     74,241        1         1,008                       1,009   

Issuance of common stock, net of issuance costs

     4,600,000        46         122,104                       122,150   

Issuance of common shares to directors for compensation

     18,446                420                       420   

Restricted stock issuance, net of cancellations

     205,475        2         (2                      

Share-based compensation expense

                    4,263                       4,263   

Surrender of restricted shares for payment of income taxes

     (31,458             (815                    (815

Net income

                           7,242                7,242   

Foreign currency transaction and translation adjustments, net of related income tax of $85

                                   234        234   
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

BALANCES, December 31, 2011

     33,093,594        331         400,890        66,228                467,449   
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Issuance of common stock upon exercise of options

     216,822        2         796                       798   

Issuance of common stock, net of issuance costs

     5,325,000        53         154,364                       154,417   

Issuance of common shares to directors for compensation

     16,935                535                       535   

Restricted stock issuance, net of cancellations

     293,382        2         (2                      

Share-based compensation expense