UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

Form 10-K

 

 

Commission file number 001-33801

 

APPROACH RESOURCES INC.

(Exact name of registrant as specified in its charter)

 

 

(817) 989-9000

(Registrant’s telephone number, including area code)

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

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 o     No þ

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o     No þ

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

 

Indicate by check mark 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.  o

 

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. (Check one):

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).  Yes o     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 30, 2008 (based on the closing price on the Nasdaq Global Market on such date) was $273.4 million. The number of shares of the registrant’s common stock, par value $0.01, outstanding as of March 6, 2009 was 20,731,429.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the registrant’s proxy statement for its 2009 annual meeting of stockholders are incorporated by reference in Part III, Items 10-14 of this report.

 

 

APPROACH RESOURCES INC.

 

Unless the context otherwise indicates, all references in this report to “Approach,” the “Company,” “we,” “us” or “our” are to Approach Resources Inc. and its subsidiaries. Unless otherwise noted, all information in this report relating to oil and natural gas reserves and the estimated future net cash flows attributable to those reserves are based on estimates and are net to our interest. If you are not familiar with the oil and gas terms used in this report, please refer to the definitions of these terms under the caption “Glossary” at the end of Item 15 of this report.

 

TABLE OF CONTENTS

 

 

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. 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, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project” or their negatives, other similar expressions or the statements that include those words, it usually is a forward-looking statement.

 

The forward-looking statements contained in this report 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 do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. 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:

 

 

Items 1. and 2.  Business and Properties.

 

General

 

We are an independent energy company engaged in the exploration, development, production and acquisition of unconventional natural gas and oil properties in the United States and British Columbia. We focus on natural gas and oil reserves in tight sands and shale and have assembled leasehold interests aggregating approximately 300,334 gross (199,818 net) acres as of December 31, 2008. Our management team has a proven track record of finding and exploiting unconventional reservoirs through advanced completion, fracturing and drilling techniques. As the operator of over 90% of our production and proved reserves, we have a high degree of control over capital expenditures and other operating matters.

 

We currently operate or have interests in the following areas:

 

West Texas

 

 

East Texas

 

 

Southwest Kentucky

 

 

Northeast British Columbia

 

 

Northern New Mexico

 

 

At December 31, 2008, we owned working interests in 445 producing oil and gas wells, had estimated proved reserves of approximately 211.1 Bcfe and were producing 28.0 MMcfe/d (based on production for the month of December 2008). Our average daily net production in 2009 (through February) was 26.5 MMcfe/d.

 

As of December 31, 2008, all of our proved reserves and production were located in Ozona Northeast and Cinco Terry in West Texas and in North Bald Prairie in East Texas. At year end 2008, our proved reserves were 82% natural gas, 48% proved developed and had a reserve life index of over 20 years (based on 2008 production of 8,755 MMcfe). In addition to our producing wells, we have identified 1,205 total drilling locations in Ozona Northeast, Cinco Terry and North Bald Prairie at December 31, 2008, of which 312 are proved.

 

The standardized measure of discounted future net cash flows of our proved reserves at December 31, 2008 was $142.6 million, and our PV-10 was $221.1 million. PV-10 is a non-GAAP financial measure as defined by the Securities and Exchange Commission, or the SEC, and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because PV-10 does not include the effects of income taxes on future net revenues. See Items 1. and 2., “Business and Properties — Reconciliation of non-GAAP financial measure (PV-10)” for our definition of PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows.

 

In December 2008, in response to a decline in oil, gas and NGL prices and uncertain market conditions, we announced that we were reducing our capital expenditure budget to an estimated $43.8 million in 2009, compared to $100.1 million of actual capital expenditures in 2008 (including $10.3 million in exploration and development costs related to the acquisition of the deep rights in Ozona Northeast in July 2008). We have reduced the number of our operating rigs from five in June 2008 to two at February 28, 2009. We intend to fund 2009 capital expenditures (excluding any acquisitions) with internally generated cash flow, with any excess cash flow applied towards debt, working capital or strategic acquisitions. We will continue to monitor commodity prices and operating expenses to determine any further adjustments to the capital budget and,

unless commodity prices strengthen, we will materially reduce our 2009 capital expenditures and number of operated rigs from the $43.8 million capital budget announced in December 2008.

 

Approach was 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. In December 2008, our common stock became listed on the NASDAQ Global Select Market. Our principal executive offices are located at One Ridgmar Centre, 6500 W. Freeway, Suite 800, Fort Worth, Texas 76116. Our telephone number is (817) 989-9000.

 

Strategy

 

Our objective is to build long-term stockholder value through growth in reserves and production in a cost-efficient manner. We intend to accomplish this objective by using a balanced program of (1) developing our core properties, (2) increasing our acreage, reserves and production through joint ventures, (3) completing strategic acquisitions, (4) maintaining financial flexibility, and (5) exploring and exploiting our undeveloped properties. The following are key elements of our strategy:

 

 

 

Oil and gas properties and operations

 

West Texas

 

Ozona Northeast (Wolfcamp, Canyon Sands, Strawn and Ellenburger)

 

The Ozona Northeast field in Crockett and Schleicher counties, Texas, is our largest operating area on the basis of proved reserves and production. In 2004, we began operations in the field through a farmout arrangement and have increased our total acreage position to 49,169 gross (44,044 net) acres. Beginning with our first well in February 2004, through December 31, 2008, we have drilled 311 successful wells out of 332 total wells drilled, for a 94% success rate. As of December 31, 2008, we had estimated proved reserves of 144.4 Bcfe from Ozona Northeast.

 

On July 1, 2008, we acquired an additional 95% working interest in all depths below the top of the Strawn formation, compression facilities and rights to approximately 75 miles of gathering lines in Ozona Northeast. As a result of the acquisition, we now own substantially all working interests in all depths of the subsurface in Ozona Northeast and have a net revenue interest of approximately 80% in Ozona Northeast. Including the 75 miles of gathering lines acquired on July 1, 2008, we own and operate approximately 150 miles of gas gathering lines in the area.

 

Average daily production in 2008 from Ozona Northeast was 16.4 MMcfe/d (net), or a total of 5,975 MMcfe. Average daily production in 2009 (through February) from Ozona Northeast was 16.0 MMcfe/d (net). We have identified 660 additional drilling locations in Ozona Northeast as of December 31, 2008, of which 192 are proved.

 

Cinco Terry (Wolfcamp, Canyon Sands and Ellenburger)

 

Since late 2005, we have leased and acquired options to lease 45,288 gross (19,466 net) acres in our Cinco Terry project, two miles northwest of the Ozona Northeast border, to explore the Wolfcamp, Canyon and Ellenburger formations. As of December 31, 2008, we had estimated proved reserves of 45.9 Bcfe in Cinco Terry, compared to 18.3 Bcfe of estimated proved reserves at December 31, 2007. We have approximately a 52% working interest and 39% net revenue interest in our Cinco Terry project. Average daily production in 2008 from Cinco Terry was 6.4 MMcfe/d (net), or a total of 2,333 MMcfe. Average daily production in 2009 (through February) from Cinco Terry was 9.3 MMcfe/d (net). We have identified 456 additional drilling locations in our Cinco Terry acreage as of December 31, 2008, of which 89 are proved. We own and operate seven miles of gas gathering lines in the area.

 

East Texas

 

North Bald Prairie (Cotton Valley Sands, Bossier and Cotton Valley Lime)

 

In July 2007, we entered into a joint drilling venture with EnCana Oil & Gas (USA) Inc. in the East Texas Cotton Valley/Bossier trend. As part of the joint venture, we agreed to drill up to five wells at our cost to earn a 50% working interest in approximately 9,301 gross (4,361 net) acres. We began drilling operations on the initial North Bald Prairie well in August 2007. As of December 31, 2008, we had drilled and completed 10 wells. We have a 50% working interest and approximately a 40% net revenue interest in our North Bald Prairie project. Average daily production in 2008 from North Bald Prairie was 1.2 MMcf/d, or a total of 447 MMcf. Average daily production in 2009 (through February) from North Bald Prairie was 1.2 MMcf/d (net). We believe the potential exists for producing from multiple zones in this area. Our primary targets are the Cotton Valley Sands, Bossier and Cotton Valley Lime, all unconventional tight gas formations where we believe we can apply our technical and operational expertise to successfully recover natural gas. Secondary targets include the shallower Rodessa, Pettit and Travis Peak formations. We have identified 89 potential

drilling locations in North Bald Prairie as of December 31, 2008, of which 31 are proved. In December 2008, EnCana notified us that EnCana was exercising its right to become the operator of record for joint interest wells in North Bald Prairie under the carry and earning agreement. Either party may propose wells under the joint operating agreement between the parties.

 

Southwest Kentucky

 

Boomerang (New Albany Shale)

 

Our Boomerang prospect is a 74,988 gross (44,759 net) acre New Albany Shale play located in Southwest Kentucky in the Illinois Basin. We have a 60% working interest and a net revenue interest of approximately 50% in our Boomerang prospect. We recorded an impairment expense from a non-cash write-off of $2.3 million of drilling costs incurred for three test wells we drilled in 2007. We currently are formulating a development plan for this prospect.

 

Northeast British Columbia

 

Montney Tight Gas and Doig Shale

 

In August 2007, we acquired a non-operating, working interest ranging from 11.9% to 25% in a lease acquisition and drilling project targeting unconventional gas reserves in the emerging Montney tight gas and Doig Shale play in Northeast British Columbia. The project covers 31,231 gross (7,395 net) acres. The primary targets are Triassic-aged tight gas and shale gas. The Canadian operator has drilled three wells since the project began in August 2007, without commercial success. We have written off the carrying value of our minority equity investment in the Canadian operator by recognizing a non-cash write-off of $917,000. We also recorded an impairment expense from a non-cash write-off of $4.1 million, which represents our share of the drilling and completion costs related to our interest in the joint drilling project. We plan to continue to explore ways to recover our remaining carrying costs in this project, including potential development of shallower productive zones (such as the Doig Sand, North Pine, Halfway and Baldonnel) in addition to the primary targets, change of operator and the potential sale or farm-out of part or all of the parties’ joint interest in the project.

 

Northern New Mexico

 

El Vado East (Mancos Shale)

 

Our El Vado East prospect is a 90,357 gross (79,793 net) acre Mancos Shale play located in the Chama Basin in Northern New Mexico in proximity to several productive fields, including the Puerto Chiquito West, Puerto Chiquito East and the Boulder fields, which collectively have produced in excess of 29 MMBoe of oil and gas. Our primary objective in El Vado East is the Mancos Shale at 2,000 to 3,000 feet. We have a 90% working interest and a net revenue interest of approximately 72% in our El Vado East prospect.

 

Since April 2008 our leasehold in Northern New Mexico has been the subject of regulatory proceedings and delays, including a moratorium on all drilling on private lands in Rio Arriba County, a proposed county drilling ordinance and potential state rulemaking. In light of these regulatory proceedings and continued expected delays in 2009, we currently have not allocated any capital to El Vado East for 2009.

Natural gas and oil reserves

 

The following table sets forth summary information regarding our estimated proved reserves as of December 31, 2008 and 2007. See Note 13 — Disclosures about Oil and Gas Producing Activities (unaudited) to our consolidated financial statements for additional information. Our estimated total proved reserves of natural gas and oil as of December 31, 2008 were 211.1 Bcfe. The 2008 reserves are composed of 82% natural gas and 18% oil, condensate and NGLs. The proved developed portion of total proved reserves at year end 2008 was 48%. Our reserve estimates and PV-10 (defined below) for the years ended December 31, 2008 and 2007 are based on an independent engineering study of our oil and gas properties prepared by DeGolyer and MacNaughton, our independent reserve engineers.

 

The standardized measure of discounted future net cash flows for our proved reserves at December 31, 2008 was $142.6 million.

 

The present value of our proved reserves, discounted at 10% (PV-10), was estimated at $221.1 million, based on year end weighted average prices of $6.04 per Mcf for natural gas, $39.60 per Bbl for oil and $23.00 per Bbl for NGLs. PV-10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. See “Reconciliation of non-GAAP financial measure (PV-10)” below for our definition of PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows.

 

On December 31, 2008, the SEC released a Final Rule, Modernization of Oil and Gas Reporting, updating its oil and gas reporting requirements, including reserve reporting. The new reporting requirements will be effective for our 2009 year-end proved reserve estimates. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 1 — Summary of Significant Accounting Policies for our discussion of the SEC’s new oil and gas reporting requirements.

 

Reconciliation of non-GAAP financial measure (PV-10)

 

The following table shows our reconciliation of our PV-10 to our standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with generally accepted accounting principles, or GAAP). 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. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” 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 the non-GAAP financial measure 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.

 

PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

 

 

No estimates of our reserves have been filed with or included in reports to another federal authority or agency since year end.

Net production, unit prices and costs

 

The following table sets forth summary information regarding our production results, average sales prices and average production costs during the years ended December 31, 2008, 2007 and 2006:

 

 

Productive wells

 

The following table sets forth the number of productive oil and gas wells in which we owned a working interest at December 31, 2008.

 

Acreage

 

The following table summarizes our developed and undeveloped acreage as of December 31, 2008.

 

 

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2008 that will expire over the next three years by region unless production is established within the spacing or producing units covering the acreage prior to the expiration dates:

 

 

 

 

Drilling activity

 

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.

 

 

 

 

Wells drilled in 2007 are pro forma for the November 14, 2007 acquisition of Neo Canyon Exploration, L.P.’s 30% working interest in Ozona Northeast, which we refer to as the Neo Canyon interest, as if the acquisition occurred on January 1, 2007.

 

Markets and customers

 

The revenues generated by our operations are highly dependent upon the prices of, and supply and demand for, oil and gas. The price we receive for our oil and gas production depends on numerous factors beyond our control, including seasonality, the condition of the United States 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 and gas, the proximity and capacity of gas pipelines and other transportation facilities, supply and demand for oil 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.

 

During the year ended December 31, 2008, Ozona Pipeline Energy Company, which we refer to as Ozona Pipeline, and WTG Benedum/Belvan Partners, LP, were our most significant purchasers, accounting for approximately 61.9% and 15.8%, respectively, of our total 2008 oil and gas sales excluding realized commodity derivative settlements.

 

Commodity derivative activity

 

We enter into financial swaps and collars 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. For qualifying cash-flow commodity derivatives, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) 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 (loss) 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 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.

 

Competition

 

The oil and gas industry is highly competitive, and we compete 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 resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and gas properties, and obtaining purchasers and transporters of the oil and gas we produce. There is also competition between producers of oil and gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the United States government. However, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil and gas and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.

 

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 United States Department of Interior, and the United States Department of Transportation (Office of Pipeline Safety). 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 and penalties or otherwise subject us to the various remedies as are

available to these federal, state and local authorities. However, we believe that we are currently in material compliance with these federal, state and local rules, regulations and procedures.

 

Transportation and sale of gas

 

The Federal Energy Regulation Commission, or FERC, regulates interstate gas pipeline transportation rates and service conditions. Although the FERC does not regulate gas producers such as us, the agency’s actions are intended to foster increased competition within all phases of the 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 pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the gas industry will have on our gas sales efforts.

 

FERC or other federal or state regulatory agencies may consider additional proposals or proceedings that might affect the gas industry. In addition, new legislation may affect the industries and markets in which we operate. We cannot predict when or if these proposals will become effective or any effect they may have on our operations. We do not believe, however, that any of these proposals will affect us any differently than other gas producers with which we compete.

 

Regulation of production

 

Oil 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 states in which we own and operate properties have 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, each state generally imposes an ad valorem, production or severance tax with respect to production and sale of oil, gas and gas liquids within its jurisdiction.

 

Environmental 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. Similar environmental laws exist in Canada. These laws and regulations may, among other things:

 

 

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. 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 laws, rules and regulations to which our business operations are subject.

 

Comprehensive Environmental Response, Compensation and Liability Act

 

The Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, also known as the Superfund law, and comparable state statutes impose strict, 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 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, or 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 federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development, exploitation 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 result in an increase in our operating expenses, which could have a material adverse effect on our business, financial condition and results of operations.

 

We currently own or lease, and have in the past owned or leased, 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 the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of hazardous and toxic air pollutants at specified sources. These regulatory programs may require us to obtain permits before commencing construction on a new source of air emissions and may require us to reduce emissions at existing facilities. As a result, we may be required to incur increased capital and operating costs. Additionally, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and analogous state laws and regulations.

In February 2005, the Kyoto Protocol to the United Nations Framework Convention on Climate Change entered into force. Pursuant to the Protocol, adopting countries are required to implement national programs to reduce emissions of certain gases, generally referred to as greenhouse gases, which are suspected of contributing to global warming. The United States is not currently a participant in the Protocol. However, Congress has enacted legislation directed at reducing greenhouse gas emissions and the EPA may be required to regulate greenhouse gas emissions, and many states have already adopted legislation or undertaken regulatory initiatives addressing greenhouse gas emissions from various sources. The oil and gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions would likely adversely impact our future operations, results of operations and financial condition. At this time, although it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business, passage of such laws or regulation affecting areas in which we conduct business could have an adverse effect on our operations.

 

Water discharges

 

The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of 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 or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

 

OSHA and other laws and regulations

 

We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

 

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 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, 2008. In addition, as of the date of this annual report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2009. However, the passage of 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. For example, see our discussion of current regulatory proceedings in New Mexico below.

 

New Mexico

 

In April 2008, the Board of County Commissioners of Rio Arriba County, New Mexico imposed a moratorium on all oil and gas drilling on private lands in Rio Arriba County, pending the adoption of an ordinance that would regulate oil and gas operations. The moratorium covers all of our El Vado East prospect in Rio Arriba County. In February 2009, the Board of Commissioners extended the moratorium through May 19, 2009.

 

In January 2009, the Board of Commissioners published a draft oil and gas drilling ordinance for the county. The draft ordinance is broad in its scope and application and would require submission of applications for a special use and development permits, along with a number of reports, plans, assessments and other supporting materials.

In addition to the county moratorium and proposed county regulations, in July 2008, the Governor of New Mexico directed the New Mexico Oil Conservation Division, or OCD, to propose special rules for oil and gas operations in Eastern Rio Arriba County, including our leasehold in El Vado East. Under the Governor’s directive, these new rules would be proposed and adopted in a rulemaking proceeding through the New Mexico Oil Conservation Commission. The OCD recently has proposed special rules for portions of Santa Fe County and the Galisteo Basin that will materially increase the time and cost to conduct drilling operations in that area.

 

In light of the regulatory proceedings impacting our leasehold in Rio Arriba County, we currently have not allocated any capital to El Vado East for 2009. If adopted, the state and county rules and ordinances will increase the time and cost to explore for oil and gas in El Vado East and may render the project uneconomic for us.

 

In addition, ongoing delays in New Mexico affect our mineral lease for El Vado East. Our lease currently requires us to drill a minimum of eight wells before the primary term of the lease expires on April 2, 2009. The lease also provides that if our drilling operations are delayed or prevented as a result of a governmental or regulatory order or by failure to obtain permits, which are events of “force majeure,” then our drilling commitment will be extended until 60 days after the cause of the delay is removed, as long as the primary term of the lease is not extended by more than four years. We have notified the lessor of the delays in El Vado East, which began in April 2008, and invoked the force majeure provision of the lease. Our inability to meet this drilling commitment, as extended by force majeure, or otherwise negotiate appropriate extensions under the lease, could result in the expiration of the lease and write-off of our investment in El Vado East, the current carrying value of which is $2.7 million.

 

Employees

 

At February 28, 2009, we had 36 full-time employees. 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 We make available, free of charge, on our website, the 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 W. 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 Securities Exchange Act of 1934 (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.

 

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 or results of operations. In such a case, you may lose all or part of your investment. The risks described below are not the only risks facing us. 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 or results of operations.

 

Risks related to the oil and natural gas industry and our business

 

Oil and gas prices are volatile, and a decline in gas or oil prices could significantly affect our business, financial condition or 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 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 and gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control, such as:

 

 

Further, oil prices and gas prices do not necessarily fluctuate in direct relationship to each other. Because more than 82% of our estimated proved reserves as of December 31, 2008 were gas reserves, our financial results are more sensitive to movements in gas prices. Recent gas prices have been extremely volatile and we expect this volatility to continue. For example, from January 1, 2008 to December 31, 2008, the NYMEX gas spot price ranged from a high of $13.58 per MMBtu to a low of $5.29 per MMBtu.

 

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 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 make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our business, financial condition and results of operations. Further, if oil and 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.

The deterioration of global economic and financial conditions and an extended decline in the price of oil and natural gas would negatively impact our business, financial condition and results of operations.

 

The global economic and financial crisis could lead to an extended national or global economic recession. The slowdown in economic activity caused by the current recession will likely reduce national and worldwide demand for oil and natural gas and result in lower commodity prices. Substantial decreases in oil and natural gas prices could have a material adverse effect on our business, financial condition and results of operations, limit our access to liquidity and credit and hinder our ability to fund our development program. The inability to execute our development program could also lead to low production and reserve growth.

 

If credit and capital markets do not improve, we may not be able to obtain funding under our current revolving credit facility or fund on acceptable terms. The inability to obtain funding could deter or prevent us from meeting our future capital needs to fund our development program.

 

Capital and credit markets have experienced unprecedented volatility and disruption and continue to be unpredictable. Given the current levels of market volatility and disruption, the availability of funds from those markets has diminished substantially. Further, arising from concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of accessing the credit markets has increased as many lenders have raised interest rates, enacted tighter lending standards or altogether ceased to provide funding to borrowers. Additionally, even if lenders are able to provide funding to borrowers, interest rates may rise in the future and therefore increase the cost of outstanding borrowings that we may incur under our revolving credit facility.

 

Moreover, we may be unable to obtain adequate funding under our current revolving credit facility. First, our lenders may be unwilling or unable to meet their funding commitments. Second, our borrowing base under our current revolving credit facility is redetermined semiannually. Our lenders have substantial ability to reduce our borrowing base on the basis of subjective factors. If oil and gas prices significantly decline for an extended period of time, our lenders could redetermine the borrowing base by evaluating our reserves at substantially lower oil and gas prices. Such determination could result in a negative revision to our proved reserve value and reduce our borrowing base.

 

Due to these capital and credit market conditions, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our development program, grow our existing business through acquisitions or joint ventures or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our business, financial condition and results of operations.

 

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

 

At December 31, 2008, we had approximately $43.5 million of outstanding debt under our revolving credit facility, and our borrowing base was $100.0 million. The borrowing base limitation under our credit facility is semi-annually redetermined 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 twelve-month period. Upon a redetermination, our borrowing base could be substantially reduced, and in the event 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 utilize cash flow from operations and bank borrowings to fund our exploration and development activities. A reduction in our borrowing base could limit our activities. In addition, we may significantly alter our capitalization in order to make future acquisitions or develop our properties. These changes in capitalization may significantly increase our level of 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.

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

 

Drilling and exploration are the main methods we use to replace our reserves. However, drilling and exploration operations may not result in any increases in reserves for various reasons. Exploration activities involve numerous risks, including the risk that no commercially productive gas or oil reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

 

Our decisions to purchase, explore and develop prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. Even when used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or producible economically. In addition, the use of 3-D seismic and other advanced technologies require greater pre-drilling expenditures than traditional drilling strategies.

 

Currently, all of our producing properties are located in four counties in Texas, and our proved reserves are primarily attributable to three fields, making us vulnerable to risks associated with having our production concentrated in a small area.

 

All of our producing properties are geographically concentrated in four counties in Texas, and our proved reserves are primarily attributable to three fields in that area, Ozona Northeast and the Angus and Holt fields in Cinco Terry. As a result of this concentration, we are disproportionately exposed to the natural decline of production from these fields, and particularly Ozona Northeast, 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, natural disasters, interruption of transportation of gas produced from the wells in these basins or other events that impact these areas.

 

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

 

As of December 31, 2008, we held mineral leases 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 2009 and 2015. Options covering approximately 3,118 gross acres in our Cinco Terry project are scheduled to expire during 2009. If these leases or options expire, we will lose our right to develop the related properties. See Items 1. and 2. “Business and Properties — Acreage” for a table summarizing the expiration schedule of our undeveloped acreage over the next three years.

Identified drilling locations that we decide to drill may not yield gas or oil in commercially viable quantities and are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

 

Our drilling locations are in various stages of evaluation, ranging from locations that are ready to be drilled to locations that will require substantial additional evaluation and interpretation. There is no way to predict in advance of drilling and testing whether any particular drilling location will yield gas or oil in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively before drilling whether gas or oil will be present or, if present, whether gas or oil will be present in commercial quantities. The analysis that we perform may not be useful in predicting the characteristics and potential reserves associated with our drilling locations. As a result, we may not find commercially viable quantities of oil and gas.

 

Our drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including oil and gas prices, costs, the availability of capital, seasonal conditions, regulatory approvals and drilling results. Because of these uncertainties, we do not know when the unproved drilling locations we have identified will be drilled or if they will ever be drilled or if we will be able to produce gas or oil from these or any proved drilling locations. As such, our actual drilling activities may be materially different from those presently identified, which could adversely affect our business, results of operations or financial condition.

 

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 level of production and cash flows will be affected adversely. 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 impaired 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.

 

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 and gas reserve information included in this report represents 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 and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

 

 

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

 

 

As of December 31, 2008, approximately 52% 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. As required by the SEC, PV-10 is generally based on prices and costs as of the date of the measurement (December 31, 2008), while actual future prices and costs may be materially higher or lower. If gas prices decline by $1.00 per Mcf from $6.04 per Mcf to $5.04 per Mcf, then our PV-10 as of December 31, 2008 would decrease from $221.1 million to $163.2 million. The average market price received for our natural gas production for the month of December 31, 2008, after basis and Btu adjustments, was $6.02 per Mcf.

 

Actual future net revenues also will be affected by factors such as:

 

 

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

 

Our industry is cyclical, and from time to time there is a shortage of drilling rigs, equipment, supplies and qualified personnel. Although commodity prices weakened considerably in the second half of 2008, creating more availability of rigs, equipment and personnel, during periods of strong commodity prices, the costs and delivery times of rigs, equipment and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel were particularly severe in the areas where we operate, we could be materially and adversely affected.

 

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 trained personnel. Many of our competitors are major and large independent oil and gas companies that possess and employ 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 acquire additional prospects and discover reserves in the future will depend on our ability to evaluate and select suitable properties and consummate transactions 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 acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

 

Our customer base is concentrated, and the loss of our key customers could, therefore, adversely affect our financial results.

 

In 2008, Ozona Pipeline and WTG Benedum/Belvan Partners, LP accounted for approximately 61.9% and 15.8%, respectively, of our total oil and gas sales excluding realized commodity derivative settlements. To the extent that Ozona Pipeline or WTG Benedum/Belvan Partners reduces their purchases in gas or oil or defaults on their obligations to us, we would be adversely affected unless we were able to make comparably favorable arrangements with other customers. 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 both 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. Accordingly, the loss of any of these individuals 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. 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. We have entered into employment agreements with J. Ross Craft, our President and Chief Executive Officer, Steven P. Smart, our Executive Vice President and Chief Financial Officer and Glenn W. Reed, our Executive Vice President — Engineering and Operations. 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. Our ability to manage our growth, if any, will require us to continue to train, motivate and manage our 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.

 

We have three affiliated stockholders who, together with our board and management, have a 42.5% interest in our company, whose interests may differ from your interests and who will be able to control or substantially influence the outcome of matters voted upon by our stockholders.

 

At December 31, 2008, Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P. and Yorktown Energy Partners VII, L.P., or collectively, Yorktown, which are under common management, beneficially owned approximately 32.5% of our outstanding common stock in the aggregate, together with a Yorktown representative who serves on our board of directors. In addition, our non-Yorktown directors and management team beneficially own or control approximately 10.0% of our common stock outstanding. As a result of this ownership and control, Yorktown, together with our board and management, has the ability to control or substantially influence the vote in any election of directors. Yorktown, together with our board and management, also has control or substantial influence over our decisions to enter into significant corporate transactions and, in their capacity as our majority stockholders, these stockholders may have the ability to effectively block any transactions that they do not believe are in Yorktown’s or management’s best interest. As a result, Yorktown, together with our board and management, is able to control, directly or indirectly and subject to applicable law, or substantially influence all matters affecting us, including the following:

 

 

Yorktown, together with our board and management, also may have an interest in pursuing transactions that, in their judgment, enhance the value of their respective equity investments in our company, even though those transactions may involve risks to you as a minority stockholder. In addition, circumstances could arise under which their interests could be in conflict with the interests of our other stockholders or you, a minority stockholder. Also, Yorktown and their affiliates have and may in the future make significant investments in other companies, some of which may be competitors. Yorktown and its affiliates are not obligated to advise us of any investment or business opportunities of which they are aware, and they are not restricted or prohibited from competing with us.

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 non-employee 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 industry. If any such business opportunity is presented to a Designated Person 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:

 

 

As a result of this renunciation, our outside directors should not be deemed to be breaching 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.

 

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

 

Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and gas, and operating safety, and protection of the environment, including those relating to air emissions, wastewater discharges, land use, storage and disposal of wastes and remediation of contaminated soil and groundwater. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may harm our business, results of operations and financial condition. We may encounter reductions in reserves or be required to make large and unanticipated capital expenditures to comply with governmental laws and regulations, such as:

 

 

Under these laws and regulations, we could be liable for:

 

 

Our operations could be significantly delayed or curtailed, and our cost of operations could significantly increase as a result of environmental safety and other regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be

unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects. Intricate and changing environmental and other regulatory requirements may require substantial expenditures to obtain and maintain permits. If a project is unable to function as planned, for example, due to costly or changing requirements or local opposition, it may create expensive delays, extended periods of non-operation or significant loss of value in a project. See Items 1. and 2., “Business and Properties — Regulation.”

 

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

 

Under current federal tax laws, we are entitled to certain deductions relating to our operations, including deductions for intangible drilling costs, or IDCs, and depletion deductions. The President’s budget for the fiscal year 2010 outlines proposals to eliminate several oil and gas federal income tax incentives, including deductions for IDCs and percentage depletion allowance for oil and natural gas. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could adversely our results of operations and cash flows.

 

Operating hazards, natural disasters 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:

 

 

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.

 

In addition, our operations in Texas are especially susceptible to damage from natural disasters such as tornados and involve increased risks of personal injury, property damage and marketing interruptions. Any of these operating hazards could cause serious injuries, fatalities or property damage, which could expose us to liabilities. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration, development, exploitation and acquisition, or could result in a loss of our properties. 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.

 

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:

 

 

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

 

Market conditions and the unavailability of satisfactory oil and gas processing and transportation may hinder our access to oil and gas markets or delay our production. Although currently we control the gathering system operations for a majority of our production in the Ozona Northeast field, we do not have such control over the regional or downstream pipelines in Ozona Northeast or in other areas where we operate or expect to conduct operations. The availability of a ready market for our oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines or trucking and terminal facilities. In addition, the amount of oil and gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled 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 and gas production from wells or we may be required to shut in gas wells or delay initial production until the necessary gathering and transportation systems are available. For example, in 2008 we reported that production in Ozona Northeast was shut-in and curtailed due to the impact of Hurricane Ike on downstream natural gas processing facilities and, separately, the rupture of a third-party pipeline. Any significant curtailment in gathering system or pipeline capacity, or significant delay in construction of necessary gathering and transportation facilities, could adversely affect our business, financial condition or results of operations.

 

Environmental liabilities 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 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, many of which have been used for exploration, production or development activities for many years, oftentimes by third parties not under our control. Private parties, including the owners of properties upon which we conduct drilling and production activities as well as facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. 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. See Items 1. and 2., “Business and Properties — Regulation.”

 

Our growth strategy could fail or present unanticipated problems for our business in the future, which could adversely affect our ability to make acquisitions or realize anticipated benefits of those acquisitions.

 

Our growth strategy may include acquiring oil and gas businesses and properties. We may not be able to identify suitable acquisition opportunities or finance and complete any particular acquisition successfully.

 

Furthermore, acquisitions involve a number of risks and challenges, including:

 

 

Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows from the acquired businesses or realize other anticipated benefits of those acquisitions.

 

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:

 

 

A terrorist attack or armed conflict could harm our business.

 

Terrorist activities, anti-terrorist efforts and other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenue. Oil and gas related facilities could be direct targets for terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities we use for the production, transportation or marketing of our oil and gas production are destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become difficult to obtain, if available at all.

 

Risks related to our financial condition

 

We will require additional capital to fund our future activities. If we fail to obtain additional capital, we may not be able to fully implement our business plan, which could lead to a decline in reserves.

 

We depend on our ability to obtain financing beyond our cash flow from operations. Historically, we have financed our business plan and operations primarily with internally generated cash flows, borrowings under our revolving credit facility and issuances of common stock. We also require capital to fund our exploration and development budget. As of December 31, 2008, approximately 52% of our total estimated proved reserves were undeveloped. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We will be required to meet our needs from our internally generated cash flows, debt financings and equity financings.

 

If our revenues decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. Our revolving credit facility contains covenants restricting our ability to incur additional indebtedness without lender consent. There can be no assurance that our bank lenders will provide this consent or as to the availability or terms of any additional financing. If we incur additional debt, the related risks that we now face could intensify.

 

Even if additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations and available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our projects, which in turn could lead to a possible loss of properties and a decline in our gas reserves.

 

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

 

At December 31, 2008, we had $43.5 million in outstanding borrowings under our revolving credit facility. At February 28, 2009, we had $47.4 million in long-term debt outstanding under our revolving credit facility. The borrowing base limitation under our revolving credit facility is redetermined semi-annually.

Redeterminations are based upon information contained in an annual engineering report prepared by an independent petroleum engineering firm and a mid-year report prepared by our own engineers. In addition, as is typical in the oil and gas industry, our bank lenders have substantial flexibility to reduce our borrowing base on the basis of subjective factors. Upon a redetermination, we could be required to repay a portion of our outstanding borrowings, including the total face amounts of all outstanding letters of credit and the amount of all unpaid reimbursement obligations, to the extent such amounts exceed the redetermined borrowing base. We may not have sufficient funds to make such required repayment, which could result in a default under the terms of the revolving credit facility and an acceleration of the loan. We intend to finance our development, acquisition and exploration activities with cash flow from operations, borrowings under our revolving credit facility and other financing activities. In addition, we may significantly alter our capitalization to make future acquisitions or develop our properties. These changes in capitalization may significantly increase our level of 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 will be affected by general economic conditions and financial, business and other factors. Many of these factors are beyond our control. Our level of debt affects our operations in several important ways, including the following:

 

 

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 oil and gas production, we enter into oil and gas price commodity derivative agreements. While intended to reduce the effects of volatile oil and gas prices, such transactions may limit our potential gains and increase our potential losses if oil and gas prices were to rise substantially over the price 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 less than expected, there is a widening 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.

 

 

None.

 

 

We are involved in various legal and regulatory proceedings arising in the normal course of business. We do not believe that an adverse result in any pending legal or regulatory proceeding, together or in the aggregate, would be material to our business, financial condition or results of operations.

 

 

None.

 

 

Trading market and range of common stock

 

Our common stock is traded on the NASDAQ Global Select Market, or Nasdaq, in the United States under the symbol “AREX.” During 2008, trading volume averaged 134,407 shares per day. The following table shows the quarterly high and low sale prices of our common stock as reported on Nasdaq since our initial public offering on November 8, 2007, which refer to as the IPO.

 

 

 

 

Holders of record

 

As of February 28, 2009, there were 27 record holders of our common stock. In many instances, a registered stockholder 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 in 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.

Comparison of cumulative return

 

The following graph compares the cumulative return on a $100 investment in our common stock from November 8, 2007, through December 31, 2008, to that of the cumulative return on a $100 investment in the Standard & Poor’s 500 Index and the Dow Jones Wilshire Exploration & Production Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act of 1933, which we refer to as 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.

 

Comparison of Total Return from November 8, 2007 through December 31, 2008
Among Approach Resources Inc., the Standard & Poor’s 500 Index and
the Dow Jones Wilshire Exploration & Production Index

 

 

Recent sales of unregistered securities

 

We did not sell any securities during the year ended December 31, 2008 that were not registered under the Securities Act.

 

Issuer repurchases of equity securities

 

 

Note: We adopted the Approach Resources Inc. 2007 Stock Incentive Plan, effective as of June 28, 2007 and amended it effective December 31, 2008. The 2007 Stock Incentive Plan allows us to withhold shares of common stock to pay withholding taxes payable upon vesting of a restricted stock grant. The number of shares of common stock available for grants under the 2007 Stock Incentive Plan is increased by the number of shares withheld as payment of such withholding taxes. On November 14, 2008, we withheld 5,621 shares of common stock as the market closing price of $9.60 per share to satisfy the income tax withholding obligations arising upon the vesting of 21,250 restricted shares issued to an executive officer in March 2007 under the 2007 Stock Incentive Plan.

 

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, 2008.

 

 

The following table sets forth selected financial information for the five years ended December 31, 2008. All weighted average shares and per share data have been adjusted for the three-for-one stock split, and the stock issuance resulting from the combination of Approach Oil & Gas Inc., or AOG, under a contribution agreement effective November 14, 2007. 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.

 

 

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 1.A for additional discussion of some of these factors and risks.

 

Overview

 

We are an independent energy company engaged in the exploration, development, production and acquisition of unconventional natural gas and oil properties in the United States and British Columbia. We focus on tight gas sands and shale and have assembled leasehold interests aggregating approximately 300,334 gross (199,818 net) acres as of December 31, 2008. We expect to leverage our management team’s proven track record of finding and exploiting unconventional reservoirs through advanced completion, fracturing and drilling techniques. As the operator of over 90% of our production and proved reserves, we have a high degree of control over capital expenditures and other operating matters.

 

We currently operate or have interests in the following areas:

 

West Texas

 

 

East Texas

 

 

Southwest Kentucky

 

 

Northeast British Columbia

 

 

Northern New Mexico

 

 

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

 

At December 31, 2008, we owned working interests in 445 producing oil and gas wells, had estimated proved reserves of approximately 211.1 Bcfe and were producing 28.0 MMcfe/d (based on production for the month of December 2008). Our average daily net production for 2009 (through February) was 26.5 MMcfe/d.

 

As of December 31, 2008, all of our proved reserves and production were located in Ozona Northeast and Cinco Terry in West Texas and in North Bald Prairie in East Texas. At year end 2008, our proved reserves were 82% natural gas, 48% proved developed and had a reserve life index of over twenty years (based on 2008 production of 8,755 MMcfe). In addition to our producing wells, we had identified 1,205 total drilling locations in Ozona Northeast, Cinco Terry and North Bald Prairie at December 31, 2008, of which 312 are proved.

 

Our financial results depend upon many factors, particularly the price of oil and gas. Commodity prices are affected by changes in market demand, which is impacted by overall economic activity, weather, pipeline

capacity constraints, estimates of inventory storage levels, gas price differentials and other factors. A factor potentially impacting the future supply balance is the recent increase in the United States LNG import capacity. Significant LNG capacity increases have been announced that may result in increased price volatility. As a result, we cannot accurately predict future oil 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 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 the capital market.

 

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 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. Our future growth will depend upon our ability to continue to add oil and gas reserves in excess of production at a reasonable cost. We will maintain our focus on the costs of adding reserves through drilling and acquisitions as well as the costs necessary to produce such reserves.

 

We also face the challenge of financing future acquisitions. We believe we have adequate unused borrowing capacity under our revolving credit facility for possible acquisitions, temporary working capital needs and any expansion of our drilling program. Funding for future acquisitions also may require additional sources of financing, which may not be available.

 

Reduction in capital expenditures and drilling activities

 

In December 2008, in response to a decline in oil, gas and NGL prices and uncertain market conditions, we announced that we were reducing our capital expenditure budget to $43.8 million in 2009, compared to $100.1 million of actual capital expenditures in 2008 (including $10.3 million in exploration and development costs related to the acquisition of deep rights in Ozona Northeast in July 2008). We also have reduced the number of our operating rigs from five in June 2008 to two at February 28, 2009. We intend to fund 2009 capital expenditures (excluding any acquisitions) with internally-generated cash flow, with any excess cash flow applied towards debt, working capital or strategic acquisitions. We will continue to monitor commodity prices and operating expenses to determine any further adjustments to the capital budget and, unless commodity prices strengthen, we will materially reduce our 2009 capital expenditures and number of operated rigs. The previously-announced reduction in capital expenditures and drilling activities, along with any additional reductions undertaken by the Company, could materially reduce our production volumes and revenues from pre-2009 levels and increase future expected costs necessary to develop existing reserves.

 

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 accounting policies generally accepted in the United States. 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.

 

Oil and gas activities — successful efforts

 

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:

 

 

Our engineering 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 the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. 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 as a result of changing results from operational activity and results. Changes in commodity prices, operation costs and techniques may also affect the overall evaluation of reservoirs. A hypothetical 10% decline in our December 31, 2008 proved reserves volumes would have been insignificant to depletion expense for the year ended December 31, 2008 nor would it have resulted in an impairment of oil and gas properties.

 

Our estimated proved reserves as of December 31, 2008, 2007 and 2006 were prepared by DeGolyer and MacNaughton.

 

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 collar 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.

 

We are exposed to credit losses in the event of nonperformance by the counterparty on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparty 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. For qualifying cash-flow commodity

derivatives, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) 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 (loss) 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, 2008, we recognized an unrealized gain of $7.1 million from the change in the fair value of commodity derivatives. For the year ended December 31, 2007, we recognized an unrealized loss of $3.6 million from the change in the fair value of commodity derivatives. A 10% increase in the NYMEX floating prices would have resulted in a $1.7 million decrease in the December 31, 2008 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.

 

Share-based compensation

 

We measure and record compensation expense for all share-based payment awards to employees and outside directors based on estimated grant-date fair values. Compensation costs for awards granted are recognized over the requisite service period based on the grant-date fair value.

 

The fair value of each option granted was estimated using an option-pricing model with the following weighted average assumptions during the years ended December 31, 2008 and 2007. There were no options granted during the year ended December 31, 2006.

 

 

We have not paid out dividends historically, thus the dividend yields are estimated at zero percent.

Since our shares were not publicly traded prior to our initial public offering on November 8, 2007, we used an average of historical volatility rates based upon other companies within our industry. Management believes that these average historical volatility rates are currently the best available indicator of expected volatility.

 

The risk-free interest rate is the implied yield available for zero-coupon U.S. government issues with a remaining term of five years.

 

The expected lives of our options are determined based on the term of the option using the simplified method outlined in Staff Accounting Bulletin 110.

 

Assumptions are reviewed each time there is a new grant and may be impacted by actual fluctuation in our stock price, movements in market interest rates and option terms. The use of different assumptions produces a different fair value for the options granted or modified and impacts the amount of compensation expense recognized on the consolidated statement of operations.

 

A 10% or 20% increase in the volatility, risk-free interest rate or stock price would not have significantly impacted share-based compensation expense for the year ended December 31, 2008.

 

Recent accounting pronouncements

 

In March 2008, the Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standard 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement 133, or SFAS 161. SFAS 161 amends and expands the disclosure requirements of FASB Statement 133 with the intent to provide users of financial statement with an enhanced understanding of (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and the related hedged items are accounted for under FASB Statement 133 and its related interpretations, and (iii) how derivative instruments and related hedged items affect and entity’s financial position, financial performance and cash flows. SFAS 161 is effective for financial statements issued for years and interim periods beginning after November 15, 2008. The effect of adopting SFAS 161 is not expected to have a significant effect on our reported financial position or earnings.

 

In December 2007, FASB issued Statement of Financial Accounting Standards 141 (revised 2007), Business Combinations, or SFAS 141(R). SFAS 141(R), among other things, establishes principles and requirements for how the acquirer in a business combination (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquired business, (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. This standard will change our accounting treatment for business combinations on a prospective basis.

 

In December 2007, the FASB issued Statement of Financial Accounting Standards 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB 51, or SFAS 160. SFAS 160 establishes accounting and reporting standards for noncontrolling interests in a subsidiary and for the deconsolidation of a subsidiary. Minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. It also establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary and requires expanded disclosures. This statement is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. The effect of adopting SFAS 160 is not expected to have a significant effect on our reported financial position or earnings.

 

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, 2008, 2007 or 2006. 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, plant and equipment. It may also increase the cost of labor or

supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher prices.

 

Share-based compensation

 

Our 2007 Stock Incentive 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 6 to our consolidated financial statements.

 

Recent developments in reserve reporting

 

On December 31, 2008, the SEC released a Final Rule, Modernization of Oil and Gas Reporting, updating its oil and gas reporting requirements. The new reporting requirements will be effective for our financial statements for the year ending December 31, 2009 and our 2009 year-end proved reserve estimates. The new reporting requirements include provisions that:

 

 

We are currently evaluating the impact that these new reporting requirements will have for the year ended December 31, 2009.

Results of operations

 

Years ended December 31, 2008 and 2007

 

 

Oil and gas sales.  Oil and gas sales increased $40.8 million, or 104.2%, for the year ended December 31, 2008 to $79.9 million from $39.1 million for the year ended December 31, 2007. The increase in oil and gas sales principally resulted from our increased ownership in the Ozona Northeast field as a result of our acquisition of the Neo Canyon interest in the fourth quarter of 2007 and increased revenue from our Cinco Terry and North Bald Prairie fields. We now own substantially all of the working interest in Ozona Northeast. Of the 8,755 MMcfe of production reported for 2008, approximately 1,791 MMcfe was attributable to the interest acquired from Neo Canyon. The increase in oil and gas sales also resulted from continued development of our Cinco Terry and North Bald Prairie fields. Cinco Terry production increased by 2,097 MMcfe compared to the prior year. Production from North Bald Prairie accounted for 447 MMcfe in production for 2008. Further, the average price per Mcfe we received for our production increased from $7.37 to $9.12 per Mcfe as average oil and gas prices increased significantly between the two years. Of the $40.8 million increase in revenues, $32.8 million was attributable to growth in volume with the remaining $8.0 million due to oil and gas price increases. Natural gas sales represented 73.6% of the total oil and gas sales in 2008 compared to 85.6% in 2007, as our Cinco Terry field has a larger component of oil and NGLs in its production.

Commodity derivative activities.  Realized losses and gains from our commodity derivative activity increased our earnings by $2.9 million and $4.7 million for the years ended December 31, 2008 and 2007, respectively. Realized gains and losses are derived from the relative movement of gas prices in relation to the range of prices in our collars or the fixed notional pricing for the respective years. The unrealized gain on commodity derivatives was $7.1 million for 2008 and the unrealized loss on commodity derivatives was $3.6 million for 2007. As natural gas commodity prices increase, the fair value of the open portion of those positions decreases. As natural gas commodity prices decrease, the fair value of the open portion of those positions 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, or LOE, increased $3.8 million, or 99.8%, for the year ended December 31, 2008 to $7.6 million ($0.87 per Mcfe) from $3.8 million ($0.72 per Mcfe) for the year ended December 31, 2007. The increase in LOE over the prior year was primarily a result of the acquisition of the Neo Canyon 30% working interest and Strawn/Ellenburger deep rights in Ozona Northeast. The increase in 2008 was also attributable to initial startup costs, including compression and treating costs in Cinco Terry and North Bald Prairie, as well as a rise in repair and maintenance costs in Ozona Northeast. Following is a summary of lease operating expenses (per Mcfe):

 

 

Severance and production taxes.  Our production taxes increased $2.5 million, or 153.3%, for the year ended December 31, 2008 to $4.2 million from $1.7 million for the year ended December 31, 2007. The increase in production taxes was a function of the increase in oil and gas sales between the two periods. Severance and productions taxes amounted to approximately 5.3% and 4.2% of oil and gas sales for the respective years. The increase in the severance and production taxes as a percentage of oil and gas sales is due to higher severance tax rates for NGL revenues from Cinco Terry and higher estimated taxes after abatements for newer wells in Ozona Northeast and Cinco Terry.

 

Exploration.  We recorded $1.5 million of exploration expense for the year ended December 31, 2008, compared to $883,000 for the year ended December 31, 2007. Exploration expense for the 2008 period resulted from one dry hole drilled in Ozona Northeast and $965,000 of lease extensions in Ozona Northeast. We incur these costs to maintain our leasehold positions and accordingly, we expense them as incurred. Exploration expense for the 2007 period resulted from the drilling of two dry holes in our Boomerang project and Cinco Terry project.

 

Impairment of oil and gas properties.  In accordance with SFAS 144, we review our long-lived assets to be held and used, including proved and unproved oil and gas properties accounted for under the successful efforts method of accounting. As a result of this review of the recoverability of the carrying value of our assets, we recorded an impairment of oil and gas properties of $6.4 million and $267,000 in 2008 and 2007, respectively. The 2008 impairment resulted from a non-cash write-off of $2.3 million of drilling costs incurred for three test wells in our Boomerang project and $4.1 related to the drilling and completion of three wells in our Northeast British Columbia project. The 2007 impairment resulted from the abandonment of an expiring leasehold position in Ozona Northeast covering 2,282 acres.

General and administrative.  Our general and administrative expenses decreased $3.8 million, or 29.9%, to $8.9 million ($1.01 per Mcfe) for the year ended December 31, 2008 from $12.7 million ($2.39 per Mcfe) for the year ended December 31, 2007. General and administrative expenses for 2007 included $4.6 million in non-cash, share-based compensation (of which $3.9 million was related to the IPO), $2.4 million in cash incentive compensation to cover out-of-pocket taxes related to IPO stock awards, $1.0 million of cash incentive compensation related to the IPO and $0.7 million in cash incentive compensation to cover out-of-pocket taxes related to management’s exchange of common stock in 2007 to repay full recourse management notes before the IPO. Partially offsetting the higher expenses in 2007 was an increase in general and administrative expense in 2008 attributable to increased salaries and benefits of $2.0 million related to an increase in staff, professional fees of $900,000, share-based compensation of $1.1 million and cash incentive compensation of $967,000. Additionally, the 2007 period includes a severance obligation of $350,000 related to a former employee. Following is a summary of general and administrative expenses (in millions and per Mcfe):

 

 

Depletion, depreciation and amortization, or DD&A.  Our DD&A expense increased $10.6 million, or 81%, to $23.7 million for the year ended December 31, 2008 from $13.1 million for the year ended December 31, 2007. Our DD&A expense per Mcfe increased by $0.24, or 9.7%, to $2.71 per Mcfe for the year ended December 31, 2008, compared to $2.47 per Mcfe for the year ended December 31, 2007. The increase in DD&A was primarily attributable to increased production and higher capital costs, partially offset by an increase in our estimated proved reserves at December 31, 2008. The higher DD&A expense per Mcfe was primarily attributable to higher capital costs incurred in North Bald Prairie and reserve revisions in Ozona Northeast at December 31, 2007. In North Bald Prairie, we paid capital costs attributable to the 50% working interest owned by our working interest partner pursuant to our carry and earning agreement on the first five wells drilled.

 

Interest expense, net.  Our interest expense decreased $4.0 million, or 75.7%, to $1.3 million for the year ended December 31, 2008 from $5.2 million for the year ended December 31, 2007. This decrease was substantially the result of our lower average debt level and lower interest rates in 2008. Additionally, interest expense for the year ended December 31, 2007 included $1.5 million related to the beneficial conversion feature of our convertible notes and $548,000 relating to accrued interest on the convertible notes.

 

Income taxes.  Our provision for income taxes increased to $12.1 million for the year ended December 31, 2008, from a benefit of $108,000 for the year ended December 31, 2007. The increase in income tax expense was due to the increase in our income before income taxes. Our effective income tax rate for the year ended December 31, 2008 was 34.1%, compared with a benefit of 4.2% for the year ended December 31, 2007. The tax benefit for the year ended December 31, 2007 related to the release of a valuation allowance on net operating loss carryovers generated by AOG before the combination of AOG and Approach under the Contribution Agreement on November 14, 2007.

Years ended December 31, 2007 and 2006