Commission file number 001-33801

 

 

(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.   þ

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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 registrant was not a publicly reporting entity as of the last business day of its most recently completed second quarter and, therefore, cannot calculate the aggregate market value of its voting and non-voting common equity held by non-affiliates as of such date. The aggregate market value of the registrant’s common voting and non-voting common equity held by non-affiliates as of December 31, 2007 (based on the closing price on the Nasdaq Global Market on such date) was $117.5 million. The number of shares of the registrant’s common stock, par value $0.01, outstanding as of March 27, 2008 was 20,622,746.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the registrant’s proxy statement for its 2008 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 natural gas and oil 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 onshore in the United States and British Columbia. We focus our growth efforts primarily on finding and developing natural gas reserves in known tight sands and shale gas areas and have assembled leasehold interests aggregating approximately 273,800 gross (191,182 net) acres. 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 substantially all of our 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

 

 

Northeast British Columbia

 

 

North New Mexico

 

 

Southwest Kentucky

 

 

At December 31, 2007, we owned working interests in 293 producing oil and gas wells, had estimated proved reserves of approximately 180.4 Bcfe and were producing 20.2 MMcfe/d (based on production for the month of December 2007). Our average daily net production for the months of January and February 2008 was 20.3 MMcfe/d and 22.4 MMcfe/d, respectively.

 

As of December 31, 2007, all of our proved reserves and production were located in the Ozona Northeast and Cinco Terry in West Texas and in North Bald Prairie in East Texas. At year end 2007, our proved reserves were 89% natural gas, 43% proved developed and had a reserve life index of 21 years (based on estimated 2008 production of 8.3 Bcfe). In addition to our producing wells, we have identified 859 total drilling locations in Ozona Northeast, Cinco Terry and North Bald Prairie at December 31, 2007, of which 265 are proved.

 

The standardized measure of discounted future net cash flows of our proved reserves at December 31, 2007 was $216.0 million, and our PV-10 was $345.7 million. PV-10 may be considered a non-GAAP financial measure as defined by the Securities and Exchange Commission (the “SEC”) 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 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.

 

Approach was incorporated in 2002. We farmed into the Ozona Northeast field in 2004 and since that time have added 180.4 Bcfe of proved reserves through our own drilling efforts in Ozona Northeast, Cinco Terry and North Bald Prairie. 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.

Initial public offering and Neo Canyon acquisition

 

In November 2007 we completed an initial public offering (“IPO”) of 8.8 million shares of our common stock. In connection with the IPO, we acquired the 30% working interest in Ozona Northeast (the “Neo Canyon interest”) that we did not already own from Neo Canyon Exploration, L.P. Neo Canyon received shares of our common stock for the Neo Canyon interest and was the sole selling stockholder in our IPO. See Note 2 to our consolidated financial statements.

 

Strategy

 

Our objective is to build 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 developmental properties, (2) exploring and exploiting our undeveloped properties, (3) completing strategic acquisitions and (4) maintaining financial flexibility. The following are key elements of our strategy:

 

 

Oil and gas properties and operations

 

West Texas

 

Ozona Northeast (Canyon Sands)

 

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 44,600 gross (44,000 net) acres. Beginning with our first well in February 2004, through December 31, 2007, we have drilled 285 successful wells out of 303 total wells drilled, for a 94% success rate. As of December 31, 2007, we had estimated proved reserves of 140.7 Bcfe from Ozona Northeast. We have a 100% working interest and a net revenue interest of approximately 80% in Ozona Northeast. Average daily production for January and February 2008 from Ozona Northeast was 17.6 MMcfe/d (net) and 17.3 MMcfe/d (net), respectively. We have identified 679 additional drilling locations in Ozona Northeast as of December 31, 2007, of which 196 are proved. We own and operate 65 miles of gas gathering lines in the area that transport our gas to several regional pipeline systems.

 

Cinco Terry (Wolfcamp, Canyon Sands and Ellenburger)

 

Since late 2005, we have leased and acquired options to lease 21,900 gross (9,507 net) acres in our Cinco Terry project, two miles northwest of the Ozona Northeast border, to evaluate the Wolfcamp, Canyon and Ellenburger formations. As of December 31, 2007, we had drilled and completed six Canyon wells and seven Ellenburger wells and had estimated proved reserves of 18.3 Bcfe in Cinco Terry. We have approximately a 50% working interest and 39% net revenue interest in our Cinco Terry project. Average daily production for January and February 2008 from Cinco Terry was 2.3 MMcfe/d (net) and 3.6 MMcfe/d (net), respectively. We have identified 119 additional drilling locations in our Cinco Terry acreage as of December 31, 2007, of which 36 are proved. We own and operate seven miles of gas gathering lines in the area that transport our gas to several regional pipeline systems.

 

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 10,300 gross (4,850 net) acres. We began drilling operations on the initial North Bald Prairie well in August 2007. As of February 29, 2008, we had drilled and completed all five wells. We have a 50% working interest and approximately a 40% net revenue interest in our North Bald Prairie project. Under our carry and earning agreement with EnCana, we drilled and we operate the initial five wells in North Bald Prairie. However, EnCana has the right to elect to operate the initial five wells. Either party may propose to drill and operate future wells under the joint operating agreement between us and EnCana. Average daily production for January and February 2008 from North Bald Prairie was 0.5 MMcfe/d (net) and 1.5 MMcfe/d (net), respectively. 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 61 potential drilling locations in North Bald Prairie as of December 31, 2007, of which 33 are proved.

 

Northeast British Columbia

 

Montney Tight Gas and Doig Shale

 

In August 2007, we acquired a non-operating, working interest ranging from 12.3% 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 32,700 gross (7,425 net) acres. Our primary targets are Triassic-aged tight gas and shale gas. We participated in one (0.25 net) vertical Montney Sand

exploratory well in 2007. In January 2008, we participated in one (0.25 net) vertical exploratory well. The Canadian operator plans to frac and complete both the Montney Sand and Doig Shale zones. A third (0.25 net) well, a horizontal Montney Sand development well, has been drilled, cased and is waiting on completion. Royalties are variable month to month depending on price, volume and product. Royalties for our current prospects range from a low of less than 10% at low volumes and low prices to a high of approximately 27% at more substantial prices and volumes.

 

North New Mexico

 

El Vado East (Mancos Shale)

 

Our El Vado East prospect is a 90,300 gross (81,000 net) acre Mancos Shale play located in the Chama Basin in North New Mexico in proximity to several productive fields, including the Puerto Chiquito West and Puerto Chiquito East fields and the Boulder field, 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 expect that in the second quarter of 2008 we will spud the first of eight vertical test wells to be drilled in El Vado East before April 2009. We have a 90% working interest and a net revenue interest of approximately 72% in our El Vado East prospect.

 

Southwest Kentucky

 

Boomerang (New Albany Shale)

 

Our Boomerang prospect is a 74,000 gross (44,400 net) acre New Albany Shale play located in Southwest Kentucky in the Illinois Basin. In the first quarter of 2007, we drilled three vertical test wells and analyzed cores from these wells. We currently are formulating a development plan for this prospect. We have a 60% working interest and a net revenue interest of approximately 50% in our Boomerang prospect.

Natural gas and oil reserves

 

The following table sets forth summary information regarding our estimated proved reserves as of December 31, 2007 and 2006. See Note 12 “Disclosures about Oil and Gas Producing Activities (unaudited)” to our consolidated financial statements for additional information. The company’s estimated total proved reserves of natural gas and oil as of December 31, 2007 were 180.4 Bcfe. The 2007 reserves are composed of 89% natural gas and 11% oil, condensate and natural gas liquids. The proved developed portion of total proved reserves at year end 2007 was 43%. The company’s reserve estimates and PV-10 (defined below) are based on an independent engineering study of our oil and gas properties prepared by DeGolyer and MacNaughton, our independent reserve engineers.

 

 

Pro forma for the acquisition of the Neo Canyon interest, our proved reserves at December 31, 2006 were 148.8 Bcfe.

 

The standardized measure of discounted future net cash flows for our proved reserves at December 31, 2007 was $216.0 million.

The present value of our proved reserves, discounted at 10% (PV-10), was estimated at $345.7 million, based on year end weighted average prices of $8.10 per Mcf for natural gas, $93.30 per Bbl for oil and $60.09 per Bbl for natural gas liquids. 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.

 

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 estimated proved 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 gas and oil 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 presents certain information with respect to natural gas and oil production attributable to all our interests in all of our operating areas, the revenue derived from the sale of such production, average sales prices received and average production costs during the years ended December 31, 2007, 2006 and 2005:

 

 

Productive wells

 

The following table sets forth the number of productive gas and oil wells in which we owned a working interest at December 31, 2007.

 

 

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2007 that will expire over the next three years by region unless production is established within the spacing 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 acquisition of 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 demand for, gas and oil. The price we receive for our gas and oil production depends on numerous factors beyond our control, including seasonality, the conditions of the United States economy, particularly in the manufacturing sector, political conditions in other oil and gas producing countries, the extent of domestic production and imports of gas and oil, the proximity and capacity of gas pipelines and other transportation facilities, demand for oil and gas, the marketing of competitive fuels and the effects of state and federal 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, 2007, Ozona Pipeline, an affiliate of Neo Canyon Exploration, L.P., the selling stockholder in our IPO, was our most significant purchaser, accounting for approximately 85.9% of our total 2007 gas and oil 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 gas and oil 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 “change in fair value of 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 gas and oil 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. To date, the 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.

The 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 and the regulation of the spacing, 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

 

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

 

 

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, imposes 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 results of operations and financial position.

 

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.

 

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.

Other 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.

 

Employees

 

At March 14, 2008, we had 25 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 materially adverse effect on our financial position or 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 the Audit Committee and the Compensation and Nominating Committee, and the 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 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.

 

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

 

Gas and oil 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 gas and oil. 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 gas and oil fluctuate widely in response to relatively minor changes in the supply and demand for gas and oil, market uncertainty and a variety of additional factors beyond our control, such as:

 

 

Further, gas prices and oil prices do not necessarily fluctuate in direct relationship to each other. Because more than 89% of our estimated proved reserves as of December 31, 2007 were gas reserves, our financial results are more sensitive to movements in gas prices. In the past, the price of gas has been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2007, the NYMEX gas spot price ranged from a high of $8.64 per MMBtu to a low of $5.38 per MMBtu. The NYMEX gas spot price at December 31, 2007 was $7.47 per MMBtu. At March 19, 2008, the NYMEX gas spot price was $9.02 per MMBtu.

 

The results of higher investment in the exploration for and production of gas and other factors may cause the price of gas to drop. Lower gas and oil prices may not only cause our revenues to decrease but also may reduce the amount of gas and oil that we can produce economically. Substantial decreases in gas and oil 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 financial condition, results of operations and cash flow.

 

Drilling and exploring for, and producing, gas and oil 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, develop and exploit 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 predrilling expenditures than traditional drilling strategies.

 

In addition, higher gas and oil prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, such drilling equipment, services and personnel. Such shortages could restrict our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could adversely affect our ability to increase our reserves and production and reduce our revenues.

 

Currently, all of our producing properties are located in four counties in Texas, and our proved reserves are primarily attributable to one field, 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 one field in that area, Ozona Northeast. 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, 2007, 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 2008 and 2015. Options covering approximately 11,600 gross acres in our Cinco Terry project are scheduled to expire before June 1, 2008. 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. For the year ended December 31, 2007, we recorded an

impairment expense of $267,000 related to the write-off of 2,284 acres in the northwest portion of Ozona Northeast. This acreage is due to expire in April 2008 and we plan to let the acreage expire at that time.

 

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 gas and oil.

 

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 gas and oil 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 gas and oil reserves, our reserves and production will decline.

 

Our future gas and oil 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 gas and oil 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 gas and oil 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 gas and oil reserve information included in this report represents estimates. Petroleum engineering is a subjective process of estimating underground accumulations of gas and oil that cannot be measured in an exact manner. Estimates of economically recoverable gas and oil 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, 2007, approximately 57% 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 cash flows 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 discounted future net cash flows included in this report should not be considered as the current market value of the estimated gas and oil reserves attributable to our properties. As required by the SEC the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the measurement (December 31, 2007), while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

 

 

In addition, the 10% discount factor, which is required by the SEC to be used to calculate discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

 

You should not assume that the present value of future net revenues from our proved reserves referred to in this report is the current market value of our estimated gas and oil reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If gas prices decline by $1.00 per Mcf from $8.10 per Mcf to $7.10 per Mcf, then our PV-10 as of December 31, 2007 would decrease from $345.7 million to $288.5 million. The average market price received for our natural gas production for the month of December 31, 2007, after basis and Btu adjustments, was $7.20 per Mcf.

 

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. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. As a result of historically strong prices of gas, the demand for oilfield and drilling services has risen, and the costs of these services may increase. We are particularly sensitive to higher rig costs and drilling rig availability, as we presently have three rigs under contract, two of which are on a well-to-well basis. 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 gas and oil 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 2007, Ozona Pipeline Energy Company, which we refer to as Ozona Pipeline, and Conoco Phillips accounted for approximately 85.9% and 12.1%, respectively, of our total gas and oil sales excluding realized commodity derivative settlements. To the extent that Ozona Pipeline or Conoco Phillips 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. Ozona Pipeline’s or Conoco Phillips’ 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 Senior Vice President — 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 controlling interest in our company, whose interests may differ from your interests and who will be able to determine the outcome of matters voted upon by our stockholders.

 

At December 31, 2007, 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 45.6% of our outstanding common stock in the aggregate. In addition, one Yorktown representative serves on our board of directors, and our non-Yorktown directors, management team and employees beneficially own or control approximately 11.4% 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 the vote in any election of directors. Yorktown, together with our board and management, also has control over our decisions to enter into significant corporate transactions and, in their capacity as our majority stockholders, these stockholders have the ability to prevent 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, 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 non-employee 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, gas and oil, 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.”

 

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 gas and oil markets or delay our production.

 

Market conditions, the unavailability of satisfactory gas and oil processing and transportation may hinder our access to gas and oil markets or delay our production. Although currently we control the pipeline operations for a majority of our production in the Ozona Northeast field, we do not have such control in other areas where we expect to conduct operations. The availability of a ready market for our gas and oil production depends on a number of factors, including the demand for and supply of gas and oil and the proximity of reserves to pipelines or trucking and terminal facilities. In addition, the amount of gas and oil 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, 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 gas and oil 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. 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 gas and oil 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 production or our operations or financial position. 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 gas and oil, potentially putting downward pressure on demand for our services and causing a reduction in our revenue. Gas and oil 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 gas and oil 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 implement fully 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 capital budget, which is expected to be approximately $64.3 million for 2008. As of December 31, 2007, approximately 57% 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, 2007, no outstanding borrowings existed under our revolving credit facility. A portion of the proceeds from our initial public offering repaid a portion of the outstanding balance under our revolving credit facility. We currently have $13.8 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 gas and oil production, we enter into gas and oil 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 gas and oil 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.

 

 

 

PART II

 

Comparison of cumulative return

 

The following graph compares the cumulative return on a $100 investment in our common stock from November 8, 2007 (the date our common stock trading began on Nasdaq) or October 31, 2007 in the applicable index, through December 31, 2007, 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 (the “Securities Act”) or the Securities Exchange Act of 1934 (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 Since November 8, 2007
Among Approach Resources Inc., the Standard & Poor’s 500 Index and
the Dow Jones Wilshire Exploration & Production Index

 

 

 

Recent sales of unregistered securities

 

In the three years preceding the filing of this report on Form 10-K, we issued and sold the following securities that were not registered under the Securities Act:

 

 

 

Issuer repurchases of equity securities

 

Except as discussed above under “Recent sales of unregistered securities” with respect to the repurchase of 2,021,148 shares of our common stock from the selling stockholder in November 2007 for approximately $22.5 million, we made no repurchases of our common stock during the year ended December 31, 2007.

 

 

The following table sets forth selected financial information for the five years ended December 31, 2007. 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 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 onshore in the United States and British Columbia. We are focusing our growth efforts primarily on finding and developing natural gas reserves in known tight gas sands and shale areas and have assembled leasehold interests aggregating approximately 273,800 gross (191,182 net) acres. 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 substantially all of our 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

 

 

Northeast British Columbia

 

 

North New Mexico

 

 

Southwest Kentucky

 

 

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, 2007, we owned working interests in 293 producing oil and gas wells, had estimated proved reserves of approximately 180.4 Bcfe and were producing 20.2 MMcfe/d (based on production for the month of December 2007). Our average daily net production for the months of January and February 2008 was 20.3 MMcfe/d and 22.4 MMcfe/d, respectively.

 

As of December 31, 2007, 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 2007, our proved reserves were 89% natural gas, 43% proved developed and had a reserve life index of 21 years (based on estimated 2008 production of 8.3 Bcfe). In addition to our producing wells, we had identified 859 total drilling locations in Ozona Northeast, Cinco Terry and North Bald Prairie at December 31, 2007.

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, inventory storage levels, gas price differentials and other factors. 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. 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.

 

Higher oil and gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services and have caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher drilling and operating costs. Given the inherent volatility of gas prices, which are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions, which generally are lower than the average sales prices received. 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. At the completion of our IPO, we repaid all amounts outstanding under our revolving credit facility plus accrued interest. 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.

 

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

 

Accounting for oil and gas activities is subject to special, unique rules. We use the successful efforts method for 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, 2007 proved reserves volumes would have resulted in approximately $1.4 million of additional depletion expense for the year ended December 31, 2007.

 

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

 

Derivative instruments and commodity derivative activities

 

All derivative instruments are recorded on the balance sheet at fair value. We determine the fair value of our derivatives by estimating the present value of future net cash flows expected from those contracts. We compute the estimate by multiplying the notional quantities specified in our contracts by the difference between exchange-quoted forward prices and the strike price specified in our contracts. We then compute the present value of those cash flows using our credit-adjusted risk-free rate under our credit agreement. 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 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 “change in fair value of 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, 2007, we recognized an unrealized loss of $3.6 million from the change in the fair value of commodity derivatives. For the year ended December 31, 2006, we recognized an unrealized gain of $8.7 million from the change in the fair value of commodity derivatives. A 10% increase in the NYMEX floating prices would have resulted in a $2.1 million decrease in the December 31, 2007 fair value recorded on our balance sheet, and a corresponding increase to loss on commodity derivatives in our statement of operations.

 

Share-based compensation

 

Prior to January 1, 2006, we accounted for stock option awards granted under our 2003 Stock Option Plan in accordance with the recognition and measurement provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees and related Interpretations, as permitted by Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”). Share-based employee compensation expense was not recognized in the our consolidated statements of operations prior to January 1, 2006, as all stock option awards granted had an exercise price equal to or greater than the estimated fair market value of the common stock on the date of the grant. As permitted by SFAS No. 123, we reported in the notes to our consolidated financial statements the pro forma disclosures presenting results and earnings (loss) per share as if we had used the fair value recognition provisions of SFAS No. 123. Share-based

compensation related to non-employees and modifications of options granted were accounted for based on the fair value of the related stock or options in accordance with SFAS No. 123 and its interpretations.

 

Effective January 1, 2006, we adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment (“SFAS No. 123(R)”), which requires the measurement and recognition of compensation expense for all share-based payment awards to employees and directors based on estimated fair values. We adopted SFAS No. 123(R) using the modified prospective transition method. In accordance with the modified prospective application provisions of SFAS No. 123(R), compensation cost for the portion of awards that were outstanding as of January 1, 2006, for which the requisite service was not rendered, are recognized as the requisite service is rendered, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). Additionally, compensation costs for awards granted after January 1, 2006 are recognized over the requisite service period based on the grant-date fair value. In accordance with the modified prospective transition method, our consolidated financial statements for prior periods have not been restated to reflect the impact of SFAS No. 123(R).

 

The fair value of each option granted was estimated using an option-pricing model with the following weighted average assumptions during the year ended December 31, 2007. There were no options granted during the years ended December 31, 2006 and 2005:

 

 

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 the IPO 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 No. 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 have been immaterial to share-based compensation expense for the year ended December 31, 2007.

 

Recent accounting pronouncements

 

In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of FASB Statement No. 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 No. 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 No. 141 (revised 2007), Business Combinations (“SFAS No. 141(R)”). SFAS No. 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 No. 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 No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51 (“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.

 

In September 2006, Statement of Financial Accounting Standards No. 157, Fair Value Measurements (“SFAS 157”), was issued. SFAS 157 provides guidance for using fair value to measure assets and liabilities. It applies whenever other standards require or permit assets or liabilities to be measured at fair value, but it does not expand the use of fair value in any new circumstances. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007. The effect of adopting SFAS 157 is not expected to have a significant effect on our reported financial position or earnings, but it will require additional disclosure regarding our derivative instruments when adopted.

 

In February 2007, SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities -Including an Amendment of FASB Statement No. 115 (“SFAS 159”), was issued. SFAS 159 permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair value at specified election dates. Unrealized gains and losses on items for which the fair value option has been elected are to be recognized in earnings at each subsequent reporting date. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The effect of adopting SFAS 159 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, 2007, 2006 or 2005. 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 management and key employees. Granting of awards may increase our general and administrative expenses subject to the size and timing of the grants. See Note 5 to our consolidated financial statements.

 

Public company expenses

 

Our general and administrative expenses increased in connection with the completion of our IPO and as a result of us operating as a public company. This increase consisted of legal and accounting fees and additional expenses associated with compliance with the Sarbanes Oxley Act of 2002 and other regulations. We anticipate

that our ongoing general and administrative expenses also will increase as a result of being a publicly traded company. This increase will be due primarily to the cost of accounting support services, filing annual and quarterly reports with the SEC, investor relations, directors’ fees, directors’ and officers’ insurance and registrar and transfer agent fees. As a result, we believe that our general and administrative expenses for future periods will increase significantly.

 

Results of operations

 

Years ended December 31, 2007 and 2006

 

 

Oil and gas sales.   Oil and gas sales decreased $7.6 million, or 16.2%, for the year ended December 31, 2007 to $39.1 million from $46.7 million for the year ended December 31, 2006. The decrease in sales principally resulted from a 21.3% decrease in production, as we drilled and completed 51 gross (46 net) wells in 2007 compared to the 81 gross (53.3 net) wells drilled and completed in 2006. The effects of decreased production were partially offset by an increase in price. The average price before the effect of commodity derivatives increased $0.45 per Mcfe, or 6.5%, from $6.92 per Mcfe in 2006 to $7.37 per Mcfe in 2007. Gas sales represented 85.6% of the total oil and gas sales in 2007 compared to 89.7% in 2006.

 

Commodity derivative activities.   Realized gains from our commodity derivative activity increased our earnings $4.7 million and $6.2 million for the years ended December 31, 2007 and 2006, respectively. The change in fair value of commodity derivatives was a $3.6 million decrease for the year ended December 31, 2007 and an $8.7 million increase for the year ended December 31, 2006. During the years ended December 31, 2007 and 2006, we used gas swaps to mitigate commodity price risk. The general improvement

in underlying commodity prices caused the decrease in realized gains in 2007 compared to 2006. During 2007 and 2006, commodity prices tended to be lower than the notional prices specified in our swap agreements, which resulted in a gain to us. Additionally, we are entering into a mix of swaps and collars in 2007, which results in less volatility to the results of operations.

 

Lease operating expense.   Our lease operating expenses decreased $74,000, or 1.9%, for the year ended December 31, 2007 to $3.8 million from $3.9 million for the year ended December 31, 2006. The primary factor in the slight decrease in lease operating expense was the release in mid-2006 of one of our seven rented compressors and an amine unit, which was partially offset by higher ad valorem taxes in the year ended December 31, 2007.

 

Severance and production taxes.   Our production taxes decreased $77,000, or 4.4%, for the year ended December 31, 2007 to $1.7 million from $1.7 million for the year ended December 31, 2006. The decrease in production taxes is a function of decreased oil and gas revenues that were more than offset by refunds received in 2006 applicable to prior years. Severance and production taxes were 4.2% and 3.7% as a percentage of oil and gas sales for the years ended December 31, 2007 and December 31, 2006, respectively. Our natural gas production from the Ozona Northeast field is afforded a severance tax rate lower than the normal rate (7.5%). However, we are required to file abatement requests with the State of Texas to receive the lower rate. Until the abatement requests are approved, we are required to pay the normal rate.

 

Exploration and impairment of non-producing properties.   Our exploration costs decreased $757,000 to $883,000 for the year ended December 31, 2007 from $1.6 million for the year ended December 31, 2006. The 2007 period included dry hole costs of $623,000 from a well in our Boomerang prospect and $263,000 from a well in our Cinco Terry project. The 2006 period included dry hole costs of $1.3 million related to two wells drilled on a prospect in Pecos County, Texas, $195,000 from one well in Ozona Northeast and $165,000 from a well in our Boomerang prospect.

 

Our impairment of non-producing properties of $267,000 and $558,000 in 2007 and 2006, respectively, arose from the abandonment of a leasehold position in Ozona Northeast in 2007 and the abandonment of our leasehold position in Pecos County in 2006. As a result of the abandonment in Pecos County, we no longer anticipate incurring any future costs related to these leaseholds.

 

General and administrative.   Our general and administrative expenses increased $10.3 million, or 424.3%, to $12.7 million for the year ended December 31, 2007 from $2.4 million for the year ended December 31, 2006. 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. General and administrative expenses for 2007 also increased over the prior year as a result of higher professional, staffing and public company expenses.

 

Depletion, depreciation and amortization (DD&A).   Our DD&A expense decreased $1.5 million, or 10.0% to $13.1 million for the year ended December 31, 2007 from $14.6 million for the year ended December 31, 2006. This decrease was primarily attributable to decreased production partially offset by increased oil and gas property costs in 2007. Our DD&A expense per Mcfe produced increased by $0.31, or 14.4%, to $2.47 per Mcfe for the year ended December 31, 2007, as compared to $2.16 per Mcfe for the year ended December 31, 2006.

 

Interest expense, net.   Our interest expense increased $1.4 million, or 36.8%, to $5.2 million for the year ended December 31, 2007 from $3.8 million for the year ended December 31, 2006. Included in interest expense for the year ended December 31, 2007 were $1.5 million related to the beneficial conversion feature of our convertible notes and $548,000 relating to accrued interest on the convertible notes. Additionally, we had increased borrowings between the two periods to fund our development of the Ozona Northeast field. These increases in interest expense were partially offset by lower interest rates in the 2007 period.

Income taxes.   Income taxes decreased $11.9 million, or 100.9%, to a benefit of $108,000 for the year ended December 31, 2007 from a provision of $11.8 million for the year ended December 31, 2006. The effective tax rate was a benefit of 4.1% and an expense of 35.7% for the years ended December 31, 2007 and December 31, 2006, respectively. Income taxes decreased consistent with our income before tax and the realization of a $2.8 million tax benefit related to the release of a valuation allowance on net operating loss carryovers generated by AOG before the combination of AOG under the contribution agreement on November 14, 2007.

 

 

Oil and gas sales.   Oil and gas sales increased $3.4 million, or 7.9%, for the year ended December 31, 2006 to $46.7 million from $43.3 million for the year ended December 31, 2005. The increase in sales principally resulted from a 34.6% increase in production, as we drilled and completed 81 gross (53.3 net) wells in 2006. The effects of increased production were offset by a decrease in price. The average price before the effect of commodity derivatives decreased $1.71 per Mcfe, or 19.8%, from $8.63 per Mcfe in 2005 to $6.92 per Mcfe in 2006 as the 2005 period included the effects of the spike in gas prices after Hurricane Katrina and Hurricane Rita. Gas sales represented 89.7% of the total oil and gas sales in 2006 compared to 92.7% in 2005.

 

Commodity derivative activities.   Realized gains from our commodity derivative activity increased our earnings $6.2 million for the year ended December 31, 2006. In comparison, realized losses from our commodity derivative activity decreased our earnings $2.9 million for the year ended December 31, 2005. The change in fair value of commodity derivatives was an $8.7 million increase during the year ended

December 31, 2006 and a $4.2 million decrease during the year ended December 31, 2005. During the years ended December 31, 2005 and 2006, we used gas swaps to mitigate commodity price risk. During 2005, commodity prices tended to be higher than the notional prices specified in our swap agreements, which resulted in a loss to us. In contrast, during 2006, commodity prices tended to be lower than the prices specified in our swap agreements, which resulted in a gain to us.

 

Lease operating expense.   Our lease operating expenses increased $1.0 million, or 33.7%, for the year ended December 31, 2006 to $3.9 million from $2.9 million for the year ended December 31, 2005. This increase primarily was the result of a $765,000 increase in ad valorem taxes and from increased pumper costs of $200,000 from the continued development of the Ozona Northeast properties.

 

Severance and production taxes.   Our production taxes decreased $239,000, or 12.1%, for the year ended December 31, 2006 to $1.7 million from $2.0 million for the year ended December 31, 2005. The decrease in production taxes is a function of increased oil and gas revenues that were more than offset by refunds received applicable to prior years. Our natural gas production from the Ozona Northeast field is afforded a severance tax rate lower than the normal rate (7.5%). However, we are required to file abatement requests with the State of Texas to receive the lower rate. Until the abatement requests are approved, we are required to pay the normal rate. During 2005, we were still awaiting approvals for abatements on several of our Ozona Northeast wells. We received such approvals during 2006, which resulted in the refunds mentioned above.

 

Exploration and impairment of non-producing properties.   Our exploration costs increased $907,000 to $1.6 million for the year ended December 31, 2006 from $734,000 for the year ended December 31, 2005. The 2006 period included dry hole costs of $1.3 million related to two wells drilled on a prospect in Pecos County, Texas, $195,000 from one well in Ozona Northeast and $165,000 from a well in our Boomerang prospect. The 2005 period included dry hole costs of $902,000 from Pecos County and $285,000 from the same well mentioned above in Ozona Northeast. Additionally, the 2005 period included the recoupment of $564,000 of geological evaluation costs from a participant in the Pecos County project. The balance of the 2005 expense is geological and geophysical costs mostly attributable to Ozona Northeast.

 

Our impairment of non-producing properties of $558,000 in 2006 arose from the abandonment of our leasehold position in Pecos County. As a result of the abandonment, we no longer anticipate incurring any costs related to this area.

 

General and administrative.   Our general and administrative expenses decreased $243,000, or 9.1%, to $2.4 million for the year ended December 31, 2006 from $2.7 million for the year ended December 31, 2005. The decrease in general and administrative expense was principally due to the accrual in 2005 of bonuses totaling approximately $800,000 that did not recur in 2006, offset by increases in 2006 for professional fees, the number of employees and increases in their compensation and benefits. Additionally, operating overhead recoveries in 2006 were $514,000 as compared to $408,000 in 2005.

 

Depletion, depreciation and amortization (DD&A).   Our DD&A expense increased $6.5 million, or 81.6%, to $14.5 million for the year ended December 31, 2006 from $8.0 million for the year ended December 31, 2005. Our DD&A expense per Mcfe produced increased by $0.56, or 35.0%, to $2.16 per Mcfe for the year ended December 31, 2006, as compared to $1.60 per Mcfe for the year ended December 31, 2005. This increase was primarily attributable to increased production and increased oil and gas property costs in 2006.

 

Interest expense, net.   Our interest expense increased $3.0 million, or 375%, to $3.8 million for the year ended December 31, 2006 from $802,000 for the year ended December 31, 2005. This significant increase was a function of increased borrowings under our revolving credit facility and an increase in interest rates during 2006. Interest rates attributable to amounts outstanding under our revolving credit facility amounted to 6.75% at December 31, 2005, compared with 7.75% at December 31, 2006.

 

Income taxes.   Income taxes increased $4.8 million, or 67.3%, to $11.8 million for the year ended December 31, 2006 from $7.0 million for the year ended December 31, 2005. Income taxes increased consistent with our income before tax, offset by a decrease in our effective tax rates, which amounted to 36.8% and 35.7% for the years ended December 31, 2005 and 2006, respectively. Our effective tax rate

decreased due primarily to a change in the tax law in the State of Texas which changed the tax from 4.5% of net income to 1% of our “margin,” as defined in the new law. Based on this change in the Texas tax law, we reduced our deferred tax liability by approximately $1.1 million for the year ended December 31, 2006.

 

Liquidity and capital resources

 

In connection with our IPO and exercise by the underwriters of their overallotment option, we sold 6,598,572 shares of our common stock in November 2007 at $12.00 per share. The gross proceeds of our IPO and over-allotment option were approximately $79.2 million, which resulted in net proceeds to the Company of $73.6 million after deducting underwriter discounts and commissions of approximately $5.6 million. The aggregate net proceeds of approximately $73.6 million received by the Company were used as follows (in millions):

 

 

For the year ended December 31, 2007, we used the $73.6 million proceeds from the IPO, $84.3 million of net proceeds from bank and convertible debt borrowings and cash flow from operations of $30.7 million to fund:

 

 

For the year ended 2006, we used $34.3 million of cash flow from operations and $3.5 million of proceeds from borrowings under a note with one of our stockholders and our revolving credit facility and available cash to fund $59.4 million for our drilling program and $1.3 million to repurchase shares.

 

Our primary sources of cash in 2007 were from financing and operating activities. Approximately $64.3 million from borrowings under our revolving credit facility, $72.4 million from the issuance of common stock, $20.0 million from proceeds from convertible notes and $30.7 million cash from operations were used to fund our drilling activities, repay our revolving credit facility and purchase 2,021,148 shares of our common stock from the selling stockholder in our initial public offering.

 

For the year ended December 31, 2006, our primary sources of cash were from financing and operating activities. Approximately $18.2 million from borrowings under our revolving credit facility, $6.5 million from the issuance of common stock, $3.5 million from a loan from one of our stockholders and $34.3 cash from operations were used to fund our drilling program, the acquisition of another working interest in the Ozona Northeast field and $1.3 million to repurchase shares and cancel stock options.

 

For the year ended December 31, 2005, cash flow from operations of $40.6 million, borrowings under our revolving credit facility of $29.3 million and $3.0 million from the issuance of common stock provided the funds to drill additional wells in the Ozona Northeast field.

 

Our cash flow from operations is driven by commodity prices and production volumes. Prices for oil and gas are driven by seasonal influences of weather, national and international economic and political environments and, increasingly, from heightened demand for hydrocarbons from emerging nations, particularly China and India. Our working capital is significantly influenced by changes in commodity prices and significant declines in prices could decrease our exploration and development expenditures. Cash flows from operations were primarily used to fund exploration and development of our mineral interests. In comparing 2006 and 2007, our cash flows from operations decreased due mostly to lower oil and gas sales and higher general and administrative expenses during the year ended December 31, 2007. In comparing 2005 and 2006, our cash

flows from operations declined slightly due to a $6.2 million decrease in working capital components partially offset by the increase in oil and gas sales in 2006.

 

The following table summarizes our sources and uses of funds for the periods noted:

 

 

Operating activities

 

For the year ended December 31, 2007, our cash flow from operations was used for drilling activities. The $30.7 million in cash flow generated during 2007 decreased $3.6 million from 2006 due mostly to lower oil and gas sales and higher general and administrative expenses in the 2007 period.

 

Net cash provided by operating activities decreased from $40.6 million in 2005 to $34.3 million in 2006. In comparing 2005 and 2006, our cash flows from operations declined $6.3 million in part due to a decrease in working capital components partially offset by the increase in oil and gas sales and net income in 2006 from our continued development of the Ozona Northeast field in West Texas.

 

Investing activities

 

The majority of our cash flows used in investing activities for the years ended 2007 and 2006 have been used for the continued development of the Ozona Northeast and Cinco Terry fields. The following is a summary of capital expenditures by prospect (in thousands):

 

 

 

 

The majority of our cash flows used in investing activities for the year ended December 31, 2005 were used for the development of the Ozona Northeast field.

 

We have established an exploratory and development budget of $64.3 million 2008. Our budgets are established based on expected volumes to be produced and commodity prices.

Financing activities

 

We borrowed $84.3 million under convertible notes and our revolving credit facility in 2007 as compared to $119.5 million net 2006. We repaid a total of $111.9 million and $101.4 million of amounts outstanding under our credit facility for the years ended December 31, 2007 and 2006, respectively. In addition, we spent $1.3 million in the first six months of 2006 to purchase common stock and related options from a former employee. For 2005, we borrowed $103.8 million from our revolving credit facility, repaid $74.5 million under the facility and received $3.0 million from the issuance of common stock.

 

In connection with our IPO and exercise by the underwriters of their overallotment option, we sold 6,598,572 shares of our common stock in November 2007 at $12.00 per share. The gross proceeds of our IPO and over-allotment option were approximately $79.2 million, which resulted in net proceeds to the Company of $73.6 million after deducting underwriter discounts and commissions of approximately $5.6 million. The aggregate net proceeds of approximately $73.6 million received by the Company were used as follows (in millions):

 

 

During 2006, we sold approximately $6.5 million of common stock. These proceeds were primarily used to fund the acquisition of our Boomerang prospect and drilling costs for our Cinco Terry project.

 

In February 2007, we entered into an amended and restated $100 million revolving credit facility with The Frost National Bank and JPMorgan Chase, NA. As of December 31, 2007, we had no outstanding balance under the credit facility with a borrowing base of $75 million. We currently have $13.8 million in long-term debt outstanding under our revolving credit facility. In January 2008, we entered into a $200 million revolving credit facility that superseded and terminated the prior $100 million revolving credit facility. The borrowing base under the new credit agreement remained $75 million at February 29, 2008. The borrowing base is subject to adjustment at least twice each year. The assessment by the bank petroleum engineers is based on their evaluation of the future cash flows from proved oil and gas reserves using the bank’s pricing parameters.

 

Our goal is to actively manage our borrowings to help us maintain the flexibility to expand and invest, and to avoid the problems associated with highly leveraged companies of large interest costs and possible debt reductions restricting ongoing operations.

 

We believe that cash flow from operations and borrowings under our revolving credit facility will finance substantially all of our anticipated drilling, exploration and capital needs in 2008. We may also use our revolving credit facility for possible acquisitions, temporary working capital needs and any expansion of our drilling program through 2008.

Future capital expenditures for 2008

 

The following table summarizes information regarding our historical 2007 and estimated 2008 capital expenditures. We will be required to meet our needs from our internally generated cash flow, debt financings and equity financings. The estimated capital expenditures are subject to change depending upon a number of factors, including the results of our development and exploration efforts, the availability of sufficient capital resources to us and other participants for drilling prospects, economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and gas and the availability of drilling rigs and crews, our financial results and the availability of leases on reasonable terms and our ability to obtain permits for the drilling locations.

 

 

Credit facility

 

In February 2007, we entered into an amended and restated $100 million revolving credit facility with The Frost National Bank and JPMorgan Chase, NA. In January 2008, we entered into a new $200 million revolving credit facility with The Frost National Bank and JPMorgan Chase, NA that superseded and terminated the prior revolving credit facility.

 

The availability of funds under our revolving credit facility is subject to a borrowing base which was initially set at, and currently is, $75 million. The borrowing base will be redetermined every six months or, upon the election by us or the bank, one additional time each calendar year.

 

Our revolving credit facility provides for interest on outstanding amounts to accrue at a rate calculated, at our option, at either (i) the base rate, which is the bank’s prime rate, or (ii) the sum of the LIBOR plus a margin which ranges from 1.25% to 2.0% per annum, as applicable, as amounts outstanding under our revolving credit facility increase as a percentage of the borrowing base. In addition, we pay an annual commitment fee of 0.375% of non-utilized borrowings available under our revolving credit facility.

 

We are subject to a financial covenant requiring maintenance of a minimum modified ratio of current assets to current liabilities. In addition, we are subject to covenants restricting cash dividends and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, assets sales, investments in other entities and liens on properties.

 

Loans under our revolving credit facility are secured by first priority liens on substantially all of our West Texas assets including a guarantee by two of our subsidiaries. All outstanding amounts under our revolving credit facility are due and payable in July 2010.

Contractual commitments

 

In April 2007, we signed a five-year lease for approximately 13,000 square feet of new office space in Fort Worth, Texas. In January 2008, we began rent payments of approximately $20,000 per month, including common area expenses. We have a lease for our prior space in Fort Worth, Texas that expires in May 2009. Our obligation under this lease is approximately $119,000 per year. At December 31, 2007, we had signed subleases for approximately two-thirds of our prior office space. In February 2008, we subleased the remainder of our prior office space.

 

The following table summarizes these commitments as of December 31, 2007 (in thousands):