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

Form 10-K

 

 

Commission file number: 001-33801

APPROACH RESOURCES INC.

(Exact name of registrant as specified in its charter)

 

 

(Registrant’s telephone number, including area code)
(817) 989-9000

 

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

 

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

 

 

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

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates (excluding voting shares held by officers and directors) as of June 30, 2009 was $81.9 million. This amount is based on the closing price of the registrant’s common stock on the NASDAQ Global Select Market on that date.

 

The number of shares of the registrant’s common stock, par value $0.01, outstanding as of March 5, 2010 was 20,998,389.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the registrant’s proxy statement for its 2010 annual meeting of stockholders are incorporated by reference in Part III, Items 10-14 of this report.

 

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

 

 

APPROACH RESOURCES INC.

 

Unless the context otherwise indicates, all references in this report to “Approach,” the “Company,” “we,” “us,” “our” or “ours” are to Approach Resources Inc. and its subsidiaries. Unless otherwise noted, (i) all information in this report relating to oil and natural gas reserves and the estimated future net cash flows attributable to reserves is based on estimates and is net to our interest, and (ii) all information in this report relating to oil and natural gas production is 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 within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects, typical well economics and our future reserves, production, revenues, costs, income, capital spending, 3-D seismic operations, interpretation and results and obtaining permits and regulatory approvals. When used in this report, the words “will,” “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

 

These forward-looking statements are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. We caution all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Risk Factors” section and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We expressly disclaim all responsibility 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:

 

 

 

 

General

 

We are an independent energy company engaged in the exploration, development, production and acquisition of natural gas and oil properties. We focus on natural gas and oil reserves in tight sands and shale and have leasehold interests totaling approximately 273,482 gross (196,634 net) acres as of December 31, 2009. Our management and technical team has a proven track record of finding and exploiting unconventional reservoirs through advanced completion, fracturing and drilling techniques. As the operator of all of our production and estimated 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

 

 

Northern New Mexico

 

 

Southwest Kentucky

 

 

At December 31, 2009, we owned working interests in 467 producing oil and gas wells, had estimated proved reserves of approximately 218.9 Bcfe and were producing 21.7 MMcfe/d, based on production for December 2009. Our 2010 average daily production through February was 22 MMcfe/d.

 

At December 31, 2009, 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 2009, our proved reserves were 77% natural gas, 43% proved developed and had a reserve life index of over 20 years, based on 2009 production of 8,808 MMcfe. In addition to our producing wells, we have identified 1,311 total drilling locations in Ozona Northeast, Cinco Terry and North Bald Prairie at December 31, 2009, of which 385 are proved.

 

Approach was incorporated in 2002. Our common stock began trading on the NASDAQ Global Market in the United States under the symbol “AREX” on November 8, 2007. In December 2008, our common stock became listed on the NASDAQ Global Select Market, or NASDAQ. Our principal executive offices are located at One Ridgmar Centre, 6500 West Freeway, Suite 800, Fort Worth, Texas 76116. Our telephone number is (817) 989-9000.

 

Business Strategy

 

Our objective is to build long-term stockholder value through growth in reserves and production in a cost-efficient manner. We intend to accomplish this objective by using a balanced program of (1) developing our core properties, (2) completing strategic acquisitions, (3) increasing our acreage, reserves and production

through joint ventures, (4) operating as a low cost producer, (5) maintaining financial flexibility, and (6) exploring and exploiting our undeveloped properties. The following are key elements of our strategy:

 

 

2009 Activity

 

In December 2008, we announced a capital expenditure budget of $43.8 million for 2009. Due to the extended decline of natural gas prices, in March 2009 we announced that we would not extend the contracts for our two remaining drilling rigs after March 31, 2009, and we released these rigs during the first week of April 2009. Overall for 2009, we increased production slightly from 8,755 MMcfe (23.9 MMcfe/d) in 2008 to 8,808 MMcfe (24.1 MMcfe/d) in 2009. However, the reduced drilling activity in the second and third quarters of 2009 and the natural decline of our tight gas fields resulted in a decline in our average daily production from 28.1 MMcfe/d for the three months ended March 31, 2009, to 21.6 MMcfe/d for the three months ended December 31, 2009.

 

A severe decline in natural gas, oil and NGL prices in 2009 adversely affected our results of operations. Our average realized price for natural gas, oil and NGLs (before the effect of commodity derivatives transactions) decreased 55.4%, 41.4% and 37.7%, respectively, from 2008 to 2009. Despite this adverse price environment, we were able to pay down our long-term debt and increase our liquidity by over 40%, from $60.5 million at December 31, 2008 to $85.4 million at December 31, 2009. We define liquidity as funds

available under our credit facility plus year-end cash and cash equivalents. At December 31, 2009, we had $32.3 million in long-term debt outstanding under our revolving credit facility, compared to $43.5 million in long-term debt outstanding at December 31, 2008. The following table summarizes our liquidity position at December 31, 2009 compared to December 31, 2008:

 

 

In addition, as the result of our drilling in Cinco Terry, in 2009 we were able to increase our estimated proved reserves, net of production, by 4%, from 211,068 MMcfe at December 31, 2008, to 218,928 MMcfe at December 31, 2009. See Items 1. and 2. “Business and Properties — Proved Oil and Gas Reserves” for more information regarding our estimated proved reserves.

 

We resumed drilling during September 2009. Also during the fourth quarter of 2009, we began acquiring 3-D seismic data across 128.4 square miles, or 82,176 acres, in our Cinco Terry field.

 

Plans for 2010 Activity

 

At February 28, 2010, we were operating three rigs in our core Permian Basin development areas: two in Cinco Terry and one in Ozona Northeast. Our 2010 capital budget for development and exploration expenditures is $53 million. As we did during 2008 and 2009, we will continue to monitor commodity prices, operating expenses and drilling success to determine adjustments to the 2010 capital budget. The 2010 capital budget allocates $48.5 million to our core development properties in the Permian Basin and includes two rigs in Cinco Terry and one rig in Ozona Northeast until mid-year 2010, when we plan to add one rig in Ozona Northeast. The 2010 capital budget also allocates approximately $3.1 million to our exploratory prospects in Northern New Mexico and Southwest Kentucky. We intend to fund 2010 capital expenditures, excluding any acquisitions, primarily out of internally-generated cash flows and, as necessary, borrowings under our revolving credit facility.

 

We completed the acquisition of 3-D seismic data across our Cinco Terry field in February 2010. Our 3-D seismic data inventory now covers over 135,000 acres in the Permian Basin. Interpretation of the data is expected to be complete by June 2010.

 

We realize higher oil and NGL volumes in Cinco Terry than in Ozona Northeast (where we have a contract that does not include processing of NGLs) or North Bald Prairie (where substantially all of our production is dry gas). Therefore, as we have continued to develop Cinco Terry, we have increased the oil and NGL component of our overall production and reserves. In addition, our contract in Ozona Northeast expires in the first quarter of 2011, after which time we will begin processing our gas in Ozona Northeast. Excluding the effect of any future acquisitions, we expect that continued development of Cinco Terry in 2010 and beyond, along with processing gas in Ozona Northeast in 2011 and beyond, will continue to increase the oil and NGL component of our production and reserves in the future. NGLs are sold by the gallon, and in reporting proved reserves and production of NGLs, we convert NGLs to barrels of oil at the rate of 42 gallons per one Bbl of oil.

The following table summarizes our overall production and reserves over the past three years.

 

 

Oil and Gas Properties and Operations

 

West Texas

 

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

 

The Ozona Northeast field in Crockett and Schleicher counties, Texas, is our largest operating area on the basis of proved reserves and production. We began operations in the field through a farm-in arrangement in 2004, and have increased our total acreage position to 49,850 gross (43,553 net) acres. We own substantially all working interests in all depths of the subsurface and have a net revenue interest of approximately 80% in Ozona Northeast. We also operate approximately 150 miles of gas gathering lines in the area. Beginning with our first well in February 2004, through December 31, 2009, we have drilled 312 successful wells out of 334 total wells drilled, for a 93% success rate. As of December 31, 2009, we had estimated proved reserves of 134.8 Bcfe in Ozona Northeast. As of February 28, 2010, we had one rig operating in Ozona Northeast.

 

Average daily production in 2009 was 14 MMcfe/d, or a total of 5,096 MMcfe. Average daily production in 2010 (through February) was 12.7 MMcfe/d. We have identified 660 additional drilling locations as of December 31, 2009, of which 204 are proved.

 

Cinco Terry (Wolfcamp, Canyon Sands and Ellenburger)

 

Since late 2005, we have leased and acquired options to lease 50,281 gross (23,818 net) acres in our Cinco Terry project, two miles northwest of Ozona Northeast, to explore the Wolfcamp, Canyon and Ellenburger formations. We have approximately a 52% working interest and 39% net revenue interest in Cinco Terry. Beginning with our first well in March 2006, through December 31, 2009, we have drilled 87 successful wells out of 100 total wells drilled, for an 87% success rate. As of December 31, 2009, we had estimated proved reserves of 68.7 Bcfe in Cinco Terry. As of February 28, 2010, we had two rigs operating in Cinco Terry.

 

Average daily production in 2009 was 9.3 MMcfe/d, or a total of 3,394 MMcfe. Average daily production in 2010 (through February) was 8.6 MMcfe/d. We have identified 558 additional drilling locations as of December 31, 2009, of which 157 are proved. We also own and operate seven miles of gas gathering lines in the area.

 

East Texas

 

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

 

In July 2007, we entered into a joint drilling venture with EnCana Oil & Gas (USA) Inc., or EnCana, 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 the project. We began drilling operations in August 2007. As of December 31, 2009, we had drilled and completed 11 gross wells, including one well completed as a saltwater disposal well. We have a 50% working interest and approximately 40% net revenue interest. As of December 31, 2009, we had estimated proved reserves of 15.5 Bcfe in North Bald Prairie. Average daily

production in 2009 was 0.9 MMcf/d, or a total of 318 MMcf. Average daily production in 2010 (through February) was 0.7 MMcf/d.

 

We believe the potential exists for producing from multiple zones in this area. Our primary targets are the Cotton Valley Sand, Bossier Shale and Cotton Valley Lime, all unconventional tight gas formations where we believe we can apply our geological, technical and operational expertise to successfully recover gas. Secondary targets include the shallower Rodessa, Pettit and Travis Peak formations. We have identified 93 potential drilling locations as of December 31, 2009.

 

We currently have no rigs running in North Bald Prairie. As previously reported, in December 2008, EnCana notified us that it was exercising its right to become the operator of record for joint interest wells in North Bald Prairie under the carry and earning agreement between the parties. We have continued to remain the operator of record pending payment by EnCana of joint interest billings owed to us under the joint operating agreement. In July 2009, our operating subsidiary filed a lawsuit against EnCana for failure to pay joint interest billings under the joint operating agreement. This proceeding is described in more detail in Part I, Item 3, “Legal Proceedings,” and Note 10 to our consolidated financial statements in this report. The joint operating agreement, or JOA, allows either party to propose wells in the drilling project. In addition, we have re-leased or renewed approximately 2,461 net acres in the project at working interests of 100% as such acreage has expired or come up for renewal and EnCana has elected not to participate in such leases. We will continue to monitor commodity prices and offset acreage development to determine when to resume drilling in North Bald Prairie.

 

Northern New Mexico

 

El Vado East (Mancos Shale)

 

Our El Vado East prospect is a 90,357 gross (79,793 net) acre Mancos Shale play located in the Chama Basin in Northern New Mexico in proximity to several productive fields, including the Puerto Chiquito West, Puerto Chiquito East and the Boulder fields. Our primary objective in El Vado East is the Mancos Shale at 2,000 to 3,000 feet. We have a 90% working interest and a net revenue interest of approximately 72% in our El Vado East prospect. At December 31, 2009, we had no estimated proved reserves recorded for El Vado East.

 

Since Rio Arriba County, or the County, imposed a moratorium on permits for new oil and gas development on private lands in the County in April 2008, regulatory proceedings and an inability to timely obtain permits have delayed our drilling plans in El Vado East. In May 2009, the County lifted the drilling moratorium and enacted an oil and gas ordinance regulating oil and gas operations on private lands in the County. In addition to obtaining permits to drill from the State of New Mexico, we are now required to obtain special use permits from the County for drilling locations in El Vado East. The “force majeure” provisions of our mineral lease for El Vado East provide that if our drilling operations are delayed or prevented as a result of a governmental or regulatory order or by failure to obtain permits, then our commitments under the lease, including our initial drilling commitment of eight wells, will be extended for the period of force majeure, as long as the primary term of the lease is not extended by more than four years, or April 2013. We have invoked our right to assert force majeure under the lease and have received conditional approvals from the State for permits to drill 11 locations. We also have applied for special use permits from the County to drill eight locations. See Items 1. and 2. “Business and Properties — Regulation — New Mexico” for additional information on our New Mexico lease and the delays in drilling in New Mexico.

 

Southwest Kentucky

 

Boomerang (New Albany Shale)

 

Our Boomerang prospect is a 74,988 gross (44,759 net) acre New Albany Shale play located in Southwest Kentucky in the Illinois Basin. We have a 60% working interest and a net revenue interest of approximately 50%. Our capital budget for 2010 provides for the completion of two, previously-drilled wells in the New Albany Shale during 2010. Our technical team is also analyzing data from offset wells drilled to

deeper formations and evaluating the purchase of 2-D seismic data to help define potentially deeper target zones. At December 31, 2009, we had no estimated proved reserves recorded for Boomerang.

 

Northeast British Columbia

 

Montney Tight Gas and Doig Shale

 

In August 2007, we acquired a non-operating, working interest ranging from 11.9% to 25% in a lease acquisition and drilling project targeting unconventional gas reserves in the emerging Montney tight gas and Doig Shale play in Northeast British Columbia.

 

We review our long-lived assets to be held and used, including proved and unproved oil and gas properties, accounted for under the successful efforts method of accounting. Based on the review of the recoverability of the carrying value of our unproved properties in Northeast British Columbia, we have recorded an impairment expense from a write-off of $3 million, related to all of our remaining carrying costs in this project. At December 31, 2009, we had no estimated proved reserves recorded for Northeast British Columbia, and no plans to develop the project. Acreage amounts in this report exclude Northeast British Columbia.

 

Proved Oil and Gas Reserves

 

Proved Reserves Reporting

 

On December 31, 2008, the Securities and Exchange Commission, or the SEC, released a Final Rule, Modernization of Oil and Gas Reporting, approving revisions designed to modernize oil and gas reserve reporting requirements. The new reserve rules are effective for our financial statements for the year ended December 31, 2009 and our 2009 year-end proved reserve estimates. The most significant revisions to the reporting requirements include:

 

 

We adopted the rules effective December 31, 2009, as required by the SEC.

 

Proved Reserves Table

 

The following table sets forth summary information regarding our estimated proved reserves as of December 31, 2009. See Note 12 to our consolidated financial statements for additional information. Our estimated total proved reserves of natural gas, oil and NGLs as of December 31, 2009 were 218.9 Bcfe. The 2009 reserves are composed of 77% natural gas and 23% oil, condensate and NGLs. The proved developed portion of total proved reserves at year end 2009 was 43%. We determined the natural gas equivalent of oil,

condensate and NGLs by using a conversion ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs.

 

The standardized measure of discounted future net cash flows for our proved reserves at December 31, 2009 was $80 million. The PV-10 of our estimated proved reserves at December 31, 2009, was $128.9 million.

 

Summary of Oil and Gas Reserves as of Fiscal-Year End
Based on Average Fiscal-Year Prices

 

 

Effect of New Proved Reserves Reporting Requirements

 

The new reserve rules resulted in the use of lower prices for natural gas, oil and NGLs than would have resulted under the previous reporting requirements. Under the previous reserve rules, our estimated total proved reserves of natural gas, oil and NGLs would have been 231.2 Bcfe. Therefore, the effect of the new reserve rules was a negative revision of 12.3 Bcfe.

 

The new reserve rules limit the recording and maintaining of proved undeveloped reserves locations to those scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time. This new reserve rules did not affect our estimates of proved reserves.

 

Preparation of Proved Reserves Estimates

 

Internal Controls Over Preparation of Proved Reserves Estimates

 

Our policies regarding internal controls over the recording of reserve estimates require reserve estimates to be in compliance with SEC rules, regulations and guidance and prepared in accordance with generally accepted petroleum engineering principles. Our Manger of Reservoir Engineering, John J. Marting, P.E., is the individual responsible for overseeing the preparation of our reserve estimates and for internal compliance of our reserve estimates with SEC rules, regulations and generally accepted petroleum engineering principles. Mr. Marting has a Bachelor of Science degree in Petroleum Engineering (Cum Laude) from the University of Missouri-Rolla and over 30 years of industry experience. Mr. Marting reports directly to our Chief Executive Officer. Our senior management, including our Chief Executive Officer and Chief Financial Officer, reviews our reserves estimates before these estimates are finalized and disclosed in a public filing or presentation.

 

For the years ended December 31, 2009, 2008 and 2007, we engaged DeGolyer and MacNaughton, independent petroleum engineers, to prepare independent estimates of the extent and value of the proved

reserves associated with certain of our oil and gas properties. See Third Party Reports below for further information regarding DeGolyer & MacNaughton’s report.

 

Technologies Used in Preparation of Proved Reserves Estimates

 

Estimates of reserves were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

 

When applicable, the volumetric method was used to estimate the original oil in place, or OOIP, and the original gas in place, or OGIP. Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

 

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure and gas-oil ratio behavior, was used in the estimation of reserves.

 

Because our proved reserves are located in depletion-type reservoirs and reservoirs whose performance demonstrates a reliable decline in producing-rate trends, reserves were also estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-declining curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses or leases as appropriate.

 

Third Party Reports

 

For the years ended December 31, 2009, 2008 and 2007, we engaged DeGolyer and MacNaughton, independent, third-party reserves engineers, to prepare estimates of the extent and value of the proved reserves of certain of our oil and gas properties. The estimates for 2009, 2008 and 2007 included a detailed review of our Ozona Northeast, Cinco Terry and North Bald Prairie fields, or 100% of our total proved reserves. DeGolyer and MacNaughton’s report for 2009 is included as Exhibit 99.1 to this annual report on Form 10-K.

 

Reserves Sensitivity Analysis

 

The following table provides an estimate of our proved reserves based on a “Current Price Case” calculated under the new reserve rules, and a “Previous Price Case” calculated under the previous reserve rules.

 

Sensitivity of Reserves to Prices by Principal Product Type and Price Scenario

 

 

Proved reserve volumes and PV-10 in the Current Price Case were estimated based on the unweighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to December 31, 2009 for natural gas, oil and NGLs. Natural gas volumes were calculated based on the average Henry Hub spot price of $3.87 per MMBtu. Oil volumes were calculated based on the average West Texas

Intermediate, or WTI, posted price of $61.04 per Bbl. NGL volumes were calculated based on the average price received on the first day of each month during 2009 of $27.20 per Bbl. All prices were adjusted for energy content, quality and basis differentials by field and were held constant through the lives of the properties.

 

Proved reserve volumes and PV-10 in the Previous Price Case were estimated based on the posted spot price as of December 31, 2009, for natural gas, oil and NGLs. Natural gas volumes were calculated based on the Henry Hub spot price of $5.79 per MMBtu. Oil volumes were calculated based on the WTI posted price of $76.00 per Bbl. NGL volumes were calculated based on the Mont Belvieu posted price of $42.94 per Bbl. All prices were adjusted for energy content, quality and basis differentials by field and were held constant through the lives of the properties.

 

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

 

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

 

 

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

 

Proved Undeveloped Reserves

 

As of December 31, 2009, we had 125.4 Bcfe of proved undeveloped reserves, or PUDs, which is an increase of 16.7 Bcfe or 15.3%, compared with 108.8 Bcfe of PUDs at December 31, 2008. Approximately 89% of our PUDs at December 31, 2009 were associated with our core development properties in the Permian Basin: Ozona Northeast (56%) and Cinco Terry (33%). The remaining 11% of our PUDs at year-end 2009 were associated with our North Bald Prairie field in East Texas.

 

We added 25.7 Bcfe of PUDs in 2009 through our drilling program, consisting of 20.6 Bcfe of extensions and discoveries in Cinco Terry and 5.1 Bcfe of extensions and discoveries in Ozona Northeast. Partially offsetting extensions and discoveries was a negative revision of 3.5 Bcfe in Ozona Northeast and North Bald Prairie due to lower commodity prices. We also removed 5.6 Bcfe of PUDs due to performance revisions primarily attributable to North Bald Prairie.

We invested approximately $3.5 million to convert 1 Bcfe of PUDs in Cinco Terry to proved developed in 2009. Estimated future development costs relating to the development of PUDs are projected to be approximately $59.8 million in 2010, $55.4 million in 2011 and $45.6 million in 2012. All PUDs are scheduled to be drilled before the end of 2014.

 

We have 2.6 Bcfe of PUDs, or approximately 1% of our total proved reserves, that have been booked for five years or longer. These reserves are located in Ozona Northeast. As discussed in Items 1. and 2. “Business and Properties — 2009 Activity,” of this report, we reduced our drilling activity in 2009 in response to a sharp decline in natural gas prices. As of February 28, 2010, we had resumed drilling in Ozona Northeast with one rig. We plan to add a second rig in Ozona Northeast by mid-year 2010 and drill a total of 36 gross wells in 2010. Despite the expected increase in drilling in Ozona Northeast in 2010, the volume of PUDs in Ozona Northeast that will have been booked for five years or longer at December 31, 2010, will increase from December 31, 2009 and, depending on the timing and selection of locations to be drilled in Ozona Northeast in 2010, such increase might be material. We have a history of significant development activity in Ozona Northeast, as we have drilled over 330 gross (over 250 net) wells there since our first well in February 2004, and we intend to continue the development of PUDs in Ozona Northeast over time.

 

Oil and Gas Production, Production Prices and Production Costs

 

The following table sets forth summary information regarding natural gas, oil and NGL production, average sales prices and average production costs, by geographic area, for the last three years. We determined the natural gas equivalent of oil, condensate and NGLs by using a conversion ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs.

 

 

 

 

 

Producing Wells

 

The following table sets forth the number of producing wells in which we owned a working interest at December 31, 2009. Wells are classified as natural gas or oil according to their predominant production stream.

 

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.

 

 

Of the 28 gross productive wells drilling 2009, four (three net) wells were waiting on completion at December 31, 2009, and have since been completed as producers.

 

Of the 11 gross development non-productive wells drilled in 2008, one well was completed as a saltwater disposal well in North Bald Prairie during 2009. The two gross exploratory, non-productive wells drilled in 2008 were drilled by the Canadian operator of our Northeast British Columbia project.

 

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

 

Acreage

 

The following table summarizes our developed and undeveloped acreage as of December 31, 2009.

 

Undeveloped Acreage Expirations

 

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2009 that will expire over the next three years by project area unless production is established prior to the expiration dates:

 

 

Undeveloped acreage in our Boomerang prospect assumes the exercise of options to extend the current primary terms by four to five additional years (beginning June 2010 through May 2012) on 67,340 gross (40,171 net) acres. Options to extend 58,548 gross (35,027 net) acres have an exercise price of $2 per year per net acre for five total available years. Options to extend 5,860 gross (3,480 net) acres have an exercise price of $6 per year per net acre for five total available years. Options to extend 1,650 gross (894 net) acres have an exercise price of $7 per year per net acre for five total available years. Options to extend the remaining 1,282 gross (769 net) acres have a weighted average exercise price of $38 per net acre for four to five total available years.

 

Undeveloped acreage in our El Vado East prospect is subject to an eight-well drilling commitment during the primary term of the mineral lease, which expired in April 2009. As of the filing of this annual report on Form 10-K, the primary term was extended by force majeure under the lease, up to April 2013. If we meet the drilling commitment (as extended by force majeure), we will have two options to extend the primary term by one year each for $15 per net acre, for a total extension of two years at $30 per net acre. If we are not able to meet the drilling commitment, during the extended primary term, and we are otherwise not able to negotiate appropriate extensions under the lease, the lease will expire. See Items 1. and 2. “Business and Properties — Regulation — New Mexico” for additional information on our New Mexico lease and the delays in drilling in New Mexico.

 

Markets and Customers

 

The revenues generated by our operations are highly dependent upon the prices of, and supply and demand for, oil and gas. The price we receive for our oil and gas production depends on numerous factors beyond our control, including seasonality, the condition of the United States and global economies, particularly in the manufacturing sectors, political conditions in other oil and gas producing countries, the extent of domestic production and imports of oil and gas, the proximity and capacity of gas pipelines and other transportation facilities, supply and demand for oil and gas, the marketing of competitive fuels and the effects of federal, state and local regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

 

During the year ended December 31, 2009, Ozona Pipeline Energy Company, which we refer to as Ozona Pipeline, WTG Benedum/Belvan Partners, LP and Shell Trading U.S. Company, which we refer to as Shell, were our most significant purchasers, accounting for approximately 43.3%, 26.1% and 22.4%, respectively, of our total 2009 oil and gas sales excluding realized commodity derivative settlements.

 

Commodity Derivative Activity

 

We enter into financial swaps and collars to mitigate portions of the risk of market price fluctuations related to future oil and gas production.

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

 

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

 

Title to Properties

 

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

 

We believe that we have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we make a general investigation of title at the time we acquire undeveloped properties. We receive title opinions of counsel before we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use of the properties in the operation of our business.

 

Competition

 

The oil and gas industry is highly competitive, and we compete for prospective properties, producing properties and personnel 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, attracting highly-skilled personnel and obtaining purchasers and transporters of the oil and gas we produce. We also face competition from alternative fuel sources, including coal, heating oil, imported LNG, nuclear and other nonrenewable fuel sources, and renewable fuel sources such as wind, solar, geothermal, hydropower and biomass. Competitive conditions may also be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the United States government. However, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil and gas and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.

 

Regulation

 

The oil and gas industry in the United States is subject to extensive regulation by federal, state and local authorities. At the federal level, various federal rules, regulations and procedures apply, including those issued by the United States Department of Interior, and the United States Department of Transportation (Office of

Pipeline Safety). At the state and local level, various agencies and commissions regulate drilling, production and midstream activities. These federal, state and local authorities have various permitting, licensing and bonding requirements. Various remedies are available for enforcement of these federal, state and local rules, regulations and procedures, including fines, penalties, revocation of permits and licenses, actions affecting the value of leases, wells or other assets, and suspension of production. As a result, there can be no assurance that we will not incur liability for fines and penalties or otherwise subject us to the various remedies as are available to these federal, state and local authorities. However, we believe that we are currently in material compliance with these federal, state and local rules, regulations and procedures.

 

Transportation and Sale of Gas

 

The Federal Energy Regulatory Commission, or FERC, regulates interstate gas pipeline transportation rates and service conditions. Although FERC does not regulate gas producers such as us, the agency’s actions are intended to foster increased competition within all phases of the gas industry and its regulation of third-party pipelines and facilities could indirectly affect our ability to transport or market our production. To date, FERC’s pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the gas industry will have on our gas sales efforts.

 

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

 

Regulation of Production

 

Oil and gas production is regulated under a wide range of federal and state statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the regulation of spacing, and requirements for plugging and abandonment of wells. Also, each state generally imposes an ad valorem, production or severance tax with respect to production and sale of oil, gas and gas liquids within its jurisdiction.

 

Environmental Regulations

 

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

 

 

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

Governmental authorities have the power to enforce compliance with environmental laws, regulations and permits, and violations are subject to injunction, as well as administrative, civil and criminal penalties. The effects of existing and future laws and regulations could have a material adverse impact on our business, financial condition and results of operations. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this will continue in the future.

 

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

 

Comprehensive Environmental Response, Compensation and Liability Act

 

The Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, also known as the Superfund law, and comparable state statutes impose strict, and under certain circumstances, joint and several liability, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to strict, joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA.

 

Waste Handling

 

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development, exploitation and production of oil or gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our operating expenses, which could have a material adverse effect on our business, financial condition and results of operations.

 

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

 

Air Emissions

 

The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of hazardous and toxic air pollutants at specified sources. These regulatory programs may require us to obtain permits before

commencing construction on a new source of air emissions and may require us to reduce emissions at existing facilities. As a result, we may be required to incur increased capital and operating costs. Additionally, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and analogous state laws and regulations.

 

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

 

Water Discharges

 

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

 

OSHA and Other Laws and Regulations

 

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

 

We believe that we are in substantial compliance with all existing environmental laws and regulations that apply to our current operations and that our ongoing compliance with existing requirements will not have a material adverse effect on our financial condition or results of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2009. In addition, as of the date of this annual report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2010. However, the passage of more stringent laws or regulations in the future could have a negative effect on our business, financial condition and results of operations, including our ability to develop our undeveloped acreage. For example, see our discussion of current regulatory proceedings in New Mexico below.

 

New Mexico

 

In April 2008, the Board of County Commissioners of Rio Arriba County, New Mexico, or the County, imposed a moratorium on all oil and gas drilling on private lands the County, pending the adoption of an ordinance that would regulate oil and gas operations. The moratorium covered all of our El Vado East prospect in the County. In May 2009, the Board of County Commissioners lifted the moratorium and adopted a final oil and gas drilling ordinance. The ordinance requires special use permits for oil and gas operations in the eastern part of the County where our El Vado East prospect is located.

Our mineral lease for El Vado East currently requires us to drill a minimum of eight wells before the end of the primary term of the lease, which originally was set to expire on April 2, 2009. However, the drilling moratorium, regulatory proceedings and an inability to obtain permits delayed our drilling plans in El Vado East and, accordingly, we have invoked our right to assert “force majeure” under our mineral lease and extended the primary term of the lease during the period of force majeure, up to a maximum of four years past the original primary term, or April 2, 2013.

 

In November 2009, the New Mexico Oil Conservation Division conditionally approved our applications for permits to drill for 11 locations in El Vado East. In December 2009, the County’s Planning & Zoning Commission conditionally approved our applications for special use permits for five drilling locations in El Vado East. We have filed applications for special use permits with the County for a total of eight drilling locations. These applications are subject to final approval of the County’s Board of County Commissioners.

 

Assuming no further, unexpected delays in the permitting process, we believe we will be able to satisfy our initial drilling commitment before the end of the primary term as extended by force majeure. However, our inability to timely meet this drilling commitment or negotiate appropriate extensions under the lease could result in the termination of the lease and write-off of our investment in El Vado East, the current carrying value of which is $2.9 million.

 

Employees

 

At February 28, 2010, we had 45 full-time employees, 19 of whom are field personnel. We regularly use independent contractors and consultants to perform various field and other services. None of our employees are represented by a labor union or covered by any collective bargaining agreement. We believe that our relations with our employees are excellent.

 

Insurance Matters

 

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

 

Available Information

 

We maintain an internet website under the name www.approachresources.com. The information on our website is not a part of this report. We make available, free of charge, on our website, the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee and Compensation and Nominating Committee, and our Code of Conduct, are available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at One Ridgmar Centre, 6500 West Freeway, Suite 800, Fort Worth, Texas 76116.

 

We file annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including Approach, that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov. Information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

 

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

 

Risks Related to the Oil and Natural Gas Industry and Our Business

 

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

 

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

 

 

Further, oil prices and gas prices do not necessarily fluctuate in direct relationship to each other. Because more than 77% of our estimated proved reserves as of December 31, 2009 were gas reserves, our financial results are more sensitive to movements in gas prices. Recent gas prices have been extremely volatile and we expect this volatility to continue. For example, from January 1, 2009 to December 31, 2009, the NYMEX gas spot price ranged from a high of $6.07 per MMBtu to a low of $2.51 per MMBtu.

 

The results of higher investment in the exploration for and production of oil and gas and other factors, such as global economic and financial conditions discussed below, may cause the price of gas to fall. Lower oil and gas prices may not only cause our revenues to decrease but also may reduce the amount of oil and gas that we can produce economically. Substantial decreases in oil and gas prices would render uneconomic some or all of our drilling locations. This may result in our having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our business, financial condition and results of operations. Further, if oil and gas prices significantly decline for an extended period of time, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future debt or obtain additional capital on attractive terms, all of which can affect the value of our common stock.

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

 

The reference or regional index prices that we use to price our oil and gas sales sometimes reflect a discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict oil and gas differentials. Changes in differentials between the benchmark price for oil and gas and the reference or regional index price we reference in our sales contracts could have a material adverse effect on our results of operations and financial condition.

 

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

 

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

 

Difficult conditions in the credit and capital markets may limit our ability to obtain funding under our current revolving credit facility or other sources of debt or equity financing. The inability to obtain funding could prevent us from meeting our future capital needs to fund our development program.

 

Credit and capital markets have experienced unprecedented volatility and disruption. Although markets began to recover in 2009, they may remain volatile and unpredictable, particularly if weaker than expected economic growth persists. We have a significant inventory of development properties that will require substantial future investment. We will need financing to fund these and other activities. Our future access to capital could be limited if the credit or broader capital markets are constrained. This could prevent or significantly delay development of our assets.

 

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

 

At December 31, 2009, we had approximately $32.3 million of outstanding debt under our revolving credit facility, and our borrowing base was $115 million. The borrowing base limitation under our credit facility is semi-annually redetermined based upon a number of factors, including commodity prices and reserve levels. In addition to such semi-annual redeterminations, our lenders may request one additional redetermination during any 12-month period. Upon a redetermination, our borrowing base could be substantially reduced, and if the amount outstanding under our credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings. We use cash flow from operations and bank borrowings to fund our exploration and development activities. A reduction in our borrowing base could limit those activities. In addition, we may significantly change our capital structure to make future acquisitions or develop our properties. Changes in capital structure may significantly increase our debt. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance, which is affected by general economic conditions and financial, business and other factors, many of which are beyond our control.

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

 

Drilling and exploration are the main methods we use to replace our reserves. However, drilling and exploration operations may not result in any increases in reserves for various reasons. Exploration activities involve numerous risks, including the risk that no commercially productive oil or gas 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:

 

 

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

 

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

 

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

 

All of our producing properties and estimated proved reserves are geographically concentrated in three counties in Texas, Crockett, Schleicher and Limestone. Our current production is primarily attributable to three fields in Crockett and Schleicher Counties, Ozona Northeast and the Angus and Holt fields in Cinco Terry. As a result of this concentration, we are disproportionately exposed to the natural decline of production from these fields, and particularly Ozona Northeast, as well as the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailments of production, natural disasters, interruption of transportation of gas produced from the wells in these fields or other events that impact these areas.

Identified drilling locations that we decide to drill may not yield oil or gas 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 before drilling and testing whether any particular drilling location will yield oil or gas 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 oil or gas will be present or, if present, whether oil or gas will be present in commercial quantities. The analysis that we perform may not be useful in predicting the characteristics and potential reserves associated with our drilling locations. As a result, we may not find commercially viable quantities of oil and gas.

 

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

 

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

 

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

 

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

 

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

 

 

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

 

 

 

As of December 31, 2009, 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 future net revenues based on the same available data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material. The PV-10 included in this report should not be considered as the current market value of the estimated oil and gas reserves attributable to our properties. PV-10 is based on the unweighted, arithmetic average of the closing price on the first day of the month for the 12-month period prior to fiscal year end, while actual future prices and costs may be materially higher or lower. If natural gas, oil and NGL prices decline by 10% from the Current Price Case ($3.87 per MMBtu, $61.04 per Bbl of oil and $27.20 per Bbl of NGLs to $3.48 per MMBtu, $54.94 per Bbl of oil and $24.48 per Bbl of NGLs), then our PV-10 as of December 31, 2009, would decrease from $128.9 million to $86.4 million. The average market price received for our production for the month of December 31, 2009 was $5.84 per Mcf (after basis and Btu adjustments), $70.61 per Bbl of oil and $43.12 per Bbl of NGLs.

 

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

 

 

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

 

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production will increase the demand for oilfield services, and the costs of these services may increase, while the quality of these services may suffer. We currently are experiencing increased demand for drilling rigs, crews and certain oilfield services in the Permian Basin, our primary area of operation. If the unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel becomes particularly severe in the Permian Basin, we could be materially and adversely affected because our operations and properties are concentrated in the Permian Basin.

 

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

 

As of December 31, 2009, we held mineral leases or options in each of our areas of operations that are still within their original lease term and are not currently held by production. Unless we establish commercial production on the properties subject to these leases, most of these leases will expire between 2010 and 2015. If these leases or options expire, we will lose our right to develop the related properties. See Items 1. and 2. “Business and Properties — Undeveloped Acreage Expirations” for a table summarizing the expiration schedule of our undeveloped acreage over the next three years.

 

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

 

We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil and gas and securing equipment and trained personnel. Many of our competitors are major and large independent oil and gas companies that possess and employ financial, technical and personnel resources

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

 

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

 

In 2009, Ozona Pipeline, WTG Benedum/Belvan Partners, LP and Shell accounted for approximately 43.3%, 26.1% and 22.4%, respectively, of our total oil and gas sales excluding realized commodity derivative settlements. To the extent that Ozona Pipeline, WTG Benedum/Belvan Partners or Shell reduces their purchases in gas or oil or defaults on their obligations to us, we would be adversely affected unless we were able to make comparably favorable arrangements with other customers. These purchasers’ default or non-performance could be caused by factors beyond our control. A default could occur as a result of circumstances relating directly to one or both of these customers, or due to circumstances related to other market participants with which the customer has a direct or indirect relationship.

 

We depend on our management team and other key personnel. Accordingly, the loss of any of these individuals could adversely affect our business, financial condition and the results of operations and future growth.

 

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

 

We have three affiliated stockholders who, together with our board and management, have a 42% interest in our company, whose interests may differ from your interests and who will be able to control or substantially influence the outcome of matters voted upon by our stockholders.

 

At December 31, 2009, Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P. and Yorktown Energy Partners VII, L.P., or collectively, Yorktown, which are under common management, beneficially owned approximately 32% of our outstanding common stock in the aggregate, together with a Yorktown representative who serves on our board of directors. In addition, our non-Yorktown directors and management team beneficially own or control approximately 10% of our common stock outstanding. As a result of this ownership and control, Yorktown, together with our board and management, has the ability to control or substantially influence the vote in any election of directors. Yorktown, together with our board and management, also has control or substantial influence over our decisions to enter into significant corporate transactions and, in their capacity as our majority stockholders, these stockholders may have the ability to effectively block any transactions that they do not believe are in Yorktown’s or management’s best interest. As

a result, Yorktown, together with our board and management, is able to control, directly or indirectly and subject to applicable law, or substantially influence all matters affecting us, including the following:

 

 

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

 

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

 

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

 

 

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

 

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

 

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

encounter reductions in reserves or be required to make large and unanticipated capital expenditures to comply with governmental laws and regulations, such as:

 

 

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

 

 

Our operations could be significantly delayed or curtailed, and our cost of operations could significantly increase as a result of environmental safety and other regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects. Intricate and changing environmental and other regulatory requirements may require substantial expenditures to obtain and maintain permits. If a project is unable to function as planned, for example, due to costly or changing requirements or local opposition, it may create expensive delays, extended periods of non-operation or significant loss of value in a project. See Items 1. and 2., “Business and Properties — Regulation.”

 

Possible regulation related to global warming and climate change could have an adverse effect on our business, financial condition or results of operations and demand for natural gas and oil.

 

In June 2009, the United States House of Representatives passed the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill or ACESA. Further, on November 5, 2009, the United States Senate passed out of committee the Clean Energy Jobs and American Power Act, also known as the Boxer-Kerry Bill. These bills contain provisions that would establish a cap and trade system for restricting greenhouse gas emissions in the United States. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. Under such a system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The ultimate outcome of this federal legislative initiative remains uncertain.

 

In addition to pending climate legislation, the Environmental Protection Agency, or EPA, has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding could lead to regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. EPA has proposed such greenhouse gas regulations and may issue final rules this year.

In the courts, several decisions have been issued that could increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people and property.

 

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gas that we produce.

 

Legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs, additional operating restrictions or delays or lower returns on our capital investments.

 

Congress currently is considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing, or “fracing,” process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us for many of the wells that we drill and operate. Supporters of legislation currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process may adversely impact drinking water. The proposed legislation could lead to (i) additional legal challenges to the fracing process based on alleged impact to drinking water or (ii) restrictions on the fluids that can be used in the process. Additional regulation and legal challenges could lead to operational delays and increased compliance and operating costs. Restrictions on fluids used in the fracing process could negatively impact the productivity of our future drilling locations, lower our return on capital expenditures and have a material adverse effect on our business, financial condition, results of operations and quantities of oil and gas reserves that may be economically produced.

 

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

 

President Obama’s Proposed Fiscal Year 2011 Budget includes proposed legislation that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key United States federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to:

 

 

It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or otherwise limit certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact our financial condition and results of operations.

 

Derivatives regulation could restrict our ability to execute commodity derivative transactions to protect against risk associated with fluctuating commodity prices.

 

Various measures are being proposed by committees of Congress, the U.S. Treasury Department, and other agencies to restrict the use of over-the-counter, or OTC, derivative instruments. These proposals include, but are not limited to, requiring cash collateral on all OTC derivatives and requiring all OTC derivatives to be executed and settled through an exchange system. Although we do not currently know the exact form any final legislation or rule-making activity will take, any restriction on the use of OTC instruments could have a significant impact on our business. Limits on the use of OTC instruments could significantly reduce our ability

to execute strategic commodity derivatives transactions to reduce price uncertainty and to protect cash flows. In addition, cash collateral requirements could create significant burdens on our liquidity and exchange system trades may restrict our ability to execute derivative instruments to fit our strategic needs.

 

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

 

The oil and gas business involves certain operating hazards such as:

 

 

The occurrence of one of the above may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties.

 

In addition, our operations in Texas are especially susceptible to damage from natural disasters such as tornados and involve increased risks of personal injury, property damage and marketing interruptions. Any of these operating hazards could cause serious injuries, fatalities or property damage, which could expose us to liabilities. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration, development, exploitation and acquisition, or could result in a loss of our properties. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. Our insurance might be inadequate to cover our liabilities. The insurance market in general and the energy insurance market in particular have been difficult markets over the past several years. Insurance costs are expected to continue to increase over the next few years and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we incur liability at a time when we are not able to obtain liability insurance, then our business, results of operations and financial condition could be materially adversely affected.

 

Our results are subject to quarterly and seasonal fluctuations.

 

Our quarterly operating results have fluctuated in the past and could be negatively impacted in the future as a result of a number of factors, including:

 

 

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

 

Market conditions and the unavailability of satisfactory oil and gas processing and transportation may hinder our access to oil and gas markets or delay our production. Although currently we control the gathering system operations for a majority of our production in Ozona Northeast, we do not have such control over the regional or downstream pipelines in Ozona Northeast or in other areas where we operate or expect to conduct operations. The availability of a ready market for our oil and gas production depends on a number of factors,

including the demand for and supply of oil and gas and the proximity of reserves to pipelines or trucking and terminal facilities. In addition, the amount of oil and gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases we are provided with limited, if any, notice as to when these circumstances will arise and their duration. As a result, we may not be able to sell, or may have to transport by more expensive means, the oil and gas production from wells or we may be required to shut in gas wells or delay initial production until the necessary gathering and transportation systems are available. Any significant curtailment in gathering system or pipeline capacity, or significant delay in construction of necessary gathering and transportation facilities, could adversely affect our business, financial condition or results of operations.

 

Environmental liabilities may expose us to significant costs and liabilities.

 

There is inherent risk of incurring significant environmental costs and liabilities in our oil and gas operations due to the handling of petroleum hydrocarbons and generated wastes, the occurrence of air emissions and water discharges from work-related activities and the legacy of pollution from historical industry operations and waste disposal practices. We may incur joint and several or strict liability under these environmental laws and regulations in connection with spills, leaks or releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities, many of which have been used for exploration, production or development activities for many years, oftentimes by third parties not under our control. Private parties, including the owners of properties upon which we conduct drilling and production activities as well as facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business, financial condition and results of operations. We may not be able to recover some or any of these costs from insurance. See Items 1. and 2., “Business and Properties — Regulation.”

 

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

 

Our growth strategy may include acquiring oil and gas businesses and properties. We may not be able to identify suitable acquisition opportunities or finance and complete any particular acquisition successfully. Furthermore, acquisitions involve a number of risks and challenges, including:

 

 

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

 

Joint drilling ventures and similar arrangements could expose us to risks.

 

As the operator in a joint drilling venture, we could be exposed to a risk of loss if a non-operating participant fails to meet its obligations to fund its portion of the drilling and operating costs as agreed under a joint operating or other applicable agreement. In addition, as a non-operator in a joint drilling venture, we could have limited or no ability to influence or control the future development of non-operated properties or

the amount of capital expenditures that we are required to fund. The failure of an operator to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues and increase our capital expenditures and operating costs. When we are the non-operator, our dependence on an operator and our limited ability to influence or control operations and future development could have a material adverse effect on our business, financial condition or results of operations.

 

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 occurs or escalates, the resulting political instability and societal disruption could reduce overall demand for oil and gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenue. Oil and gas related facilities could be direct targets for terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities we use for the production, transportation or marketing of our oil and gas production are destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become difficult to obtain, if available at all.

 

Risks Related to Our Financial Condition

 

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

 

We depend on our ability to obtain financing beyond our cash flow from operations. Historically, we have financed our business plan and operations primarily with internally generated cash flows, borrowings under our revolving credit facility and issuances of common stock. We also require capital to fund our exploration and development budget. As of December 31, 2009, approximately 57% of our total estimated proved reserves were undeveloped. Recovery of such reserves will require significant capital expenditures and successful drilling operations. According to our year-end 2009 reserve report, the estimated capital required to develop our current proved developed and proved undeveloped oil and gas reserves is $213 million. 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 oil and gas reserves.

 

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

 

At December 31, 2009, we had $32.3 million in outstanding borrowings under our revolving credit facility, and our borrowing base was $115 million. The borrowing base under our revolving credit facility is redetermined semi-annually. Redeterminations are based upon information contained in an annual reserve 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, exploration and acquisition activities with cash flow from operations, borrowings under our revolving credit facility and other financing activities. In addition, we may significantly alter our capital structure to make future acquisitions or develop our properties. Changes in our capital structure 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 debt level 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 production, we enter into gas price and basis differential commodity derivative agreements. While intended to reduce the effects of volatile gas prices and basis differentials, such transactions may limit our potential gains and increase our potential losses if gas prices were to rise substantially over the price established by the commodity derivative, or if the basis spread decreases substantially from the basis differential established by the commodity derivative. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which our production is 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. In addition, as discussed above in this Item 1A. “Risk Factors,” proposed legislation relating to derivatives transactions may restrict our ability to execute transactions to protect against risks of fluctuating commodity prices.

Risks Related to Our Common Stock

 

Our stock price may fluctuate significantly.

 

Our common stock began trading on the NASDAQ Global Market in November 2007. In December 2008, our common stock began trading on the NASDAQ Global Select Market. An active trading market may not be sustained. In 2009, the average daily trading volume of our common stock was 62,721 shares, or 0.3% of our weighted average shares outstanding for the year. The market price of our common stock could fluctuate significantly as a result of:

 

 

Many of these factors are beyond our control and we cannot predict their potential effects on the price of our common stock. In addition, the stock markets in general can experience considerable price and volume fluctuations.

 

Future sales of our common stock may cause our stock price to decline.

 

Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of these shares could impair our ability to raise capital through the sale of additional common or preferred stock.

 

Common stockholders will be diluted if additional shares are issued.

 

In our initial public offering in November 2007, we sold 8.8 million shares of common stock to repay $51.1 million outstanding on our revolving credit facility and to repurchase 2 million shares of common stock from the selling stockholder. In connection with the offering, we also acquired the 30% working interest in Ozona Northeast that we did not already own from the selling stockholder in exchange for 4.2 million shares of common stock. We may issue additional shares of common stock, preferred stock, depositary shares, warrants, rights, units and debt securities for general corporate purposes, including repayment or refinancing of borrowings, working capital, capital expenditures, investments and acquisitions. We also issue restricted stock to our executive officers, employees and independent directors as part of their compensation. If we issue additional shares of our common stock in the future, it may have a dilutive effect on our current outstanding stockholders.

 

The equity trading markets may be volatile, which could result in losses for our stockholders.

 

The equity trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of equity securities. The market price of our common stock could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition.

 

 

None.

 

Approach Operating, LLC v. EnCana Oil & Gas (USA) Inc., Cause No. 29.070A, District Court of Limestone County, Texas. On July 2, 2009 our operating subsidiary filed a lawsuit against EnCana Oil & Gas (USA) Inc., or EnCana, for breach of the joint operating agreement, or JOA, covering our North Bald Prairie project in East Texas and seeking damages for nonpayment of amounts owed under the JOA as well as declaratory relief. We contend that such amounts owed by EnCana are at least $2.1 million, plus attorneys’ fees, costs and other amounts to which we might be entitled under law or in equity. As we previously have disclosed, in December 2008, EnCana notified us that it was exercising its right to become operator of record for joint interest wells in North Bald Prairie under an operator election agreement between the parties. EnCana contends that it does not owe us for part or all of joint interest billings incurred after EnCana provided us with notice of EnCana’s election to assume operatorship in December 2008. EnCana also contends that certain of the disputed operations were unnecessary, while other charges are improper because we failed to obtain EnCana’s consent under the JOA prior to undertaking the operations. We have informed the Court that we will transfer operatorship to EnCana when EnCana has made all payments it owes under the JOA.

 

Regardless of the outcome of this proceeding, the JOA provides that either party (operator or non-operator) may propose the drilling of wells.

 

We also are involved in various other legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flows; however, an unfavorable outcome could have a material adverse effect on our results of operations for a specific interim period or year.

 

 

 

Market Information

 

Our common stock is traded on NASDAQ in the United States under the symbol “AREX.” During 2009, trading volume averaged 62,721 shares per day. The following table shows the quarterly high and low sale prices of our common stock as reported on NASDAQ for the past two years.

 

 

Holders

 

As of February 28, 2010, there were 37 record holders of our common stock. In many instances, a record holder is a broker or other entity holding shares in street name for one or more customers who beneficially own the shares.

 

Dividends

 

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

 

Securities Authorized for Issuance under Equity Compensation Plans

 

The following table sets forth information regarding securities authorized for issuance under equity compensation plans and individual compensation arrangements as of December 31, 2009.

 

Performance Graph

 

The following graph compares the cumulative return on a $100 investment in our common stock from November 8, 2007, through December 31, 2009, to that of the cumulative return on a $100 investment in the Standard & Poor’s 500, or S&P 500, index and the Dow Jones U.S. Exploration & Production Total Stock Market, or TSM, index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing.

 

Comparison of Total Return from November 8, 2007 through December 31, 2009
Among Approach Resources Inc., the S&P 500 Index and
the Dow Jones U.S. Exploration & Production TSM Index

 

 

 

Recent Sales of Unregistered Securities; Uses of Proceeds From Registered Securities

 

We did not sell any securities during the year ended December 31, 2009 that were not registered under the Securities Act.

 

Issuer Repurchases of Equity Securities

 

We adopted the Approach Resources Inc. 2007 Stock Incentive Plan effective as of June 28, 2007, and amended it effective December 31, 2008. The 2007 Stock Incentive Plan allows us to withhold shares of common stock to pay withholding taxes payable upon vesting of a restricted stock grant. The number of shares of common stock available for grants under the 2007 Stock Incentive Plan is increased by the number of shares withheld as payment of such withholding taxes. The following table shows the number of shares of

common stock withheld to satisfy the income tax withholding obligations arising upon the vesting of restricted shares issued to employees under the 2007 Stock Incentive Plan.

 

 

The following table sets forth selected financial information for the five years ended December 31, 2009. All weighted average shares and per share data have been adjusted for the three-for-one stock split and the stock issuance resulting from the combination of Approach Oil & Gas Inc., or AOG, under a contribution agreement effective November 14, 2007. This information should be read in conjunction with Item 7 of this report, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated financial statements, related notes and other financial information included in this report.

 

 

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

 

Overview

 

We are an independent energy company engaged in the exploration, development, production and acquisition of natural gas and oil properties. We focus on natural gas and oil reserves in tight sands and shale and have leasehold interests totaling approximately 273,482 gross (196,634 net) acres as of December 31, 2009. Our management team has a proven track record of finding and exploiting unconventional reservoirs through advanced completion, fracturing and drilling techniques. As the operator all of our production and proved reserves, we have a high degree of control over capital expenditures and other operating matters.

 

We currently operate or have interests in the following areas:

 

West Texas

 

 

East Texas

 

 

Northern New Mexico

 

 

Southwest Kentucky

 

 

At December 31, 2009, we owned working interests in 467 producing oil and gas wells, had estimated proved reserves of approximately 218.9 Bcfe and were producing 21.7 MMcfe/d, based on production for December 2009. Our 2010 average daily production through February was 22 MMcfe/d.

 

At December 31, 2009, 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 2009, our proved reserves were 77% natural gas, 43% proved developed and had a reserve life index of over 20 years, based on 2009 production of 8,808 MMcfe. In addition to our producing wells, we had identified 1,311 total drilling locations in Ozona Northeast, Cinco Terry and North Bald Prairie at December 31, 2009, of which 385 are proved.

 

Our average realized price for natural gas, oil and NGLs (before the effect of commodity derivatives transactions) decreased 55.4%, 41.4% and 37.7%, respectively, from 2008 to 2009. As a result, we reduced capital expenditures and drilling activity, paid down long-term debt and increased our liquidity by over 40%, from $60.5 million at December 31, 2008 to $85.4 million at December 31, 2009. We define liquidity as funds available under our credit facility plus year-end cash and cash equivalents. At December 31, 2009, we had $32.3 million in long-term debt outstanding under our revolving credit facility, compared to $43.5 million at December 31, 2008. Another result of reduced drilling activity, plus the natural decline of our tight gas fields, was a decline in our average daily production. Average daily production declined from 28.1 MMcfe/d for the three months ended March 31, 2009, to 21.6 MMcfe/d for the three months ended December 31, 2009.

We resumed drilling during September 2009 and currently are operating two rigs in Cinco Terry and one rig in Ozona Northeast. Also in the fourth quarter of 2009, we began acquiring 3-D seismic data across 128.4 square miles, or 82,176 acres, in our Cinco Terry field. We completed the acquisition of 3-D seismic data across our Cinco Terry field in February 2010. Our 3-D seismic data inventory now covers over 135,000 acres in the Permian Basin. Interpretation of the data is expected to be complete by June 2010.

 

We realize higher oil and NGL volumes in Cinco Terry than in Ozona Northeast (where we have a sales contract that does not include processing of NGLs) or North Bald Prairie (where substantially all of our production is dry gas). Therefore, as we have continued to develop Cinco Terry, we have increased the oil and NGL component of our overall production and reserves. In addition, our contract in Ozona Northeast expires in the first quarter of 2011, after which time we expect to begin processing NGLs in Ozona Northeast. Excluding the effect of any future acquisitions, we expect that further development of Cinco Terry in 2010 and beyond, along with processing gas in Ozona Northeast in 2011 and beyond, will continue to increase the oil and NGL component of our production and reserve in the future.

 

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.

 

Our financial results depend upon many factors, particularly the price of oil and gas. Commodity prices are affected by changes in market demand, which is impacted by overall economic activity, weather, pipeline capacity constraints, estimates of inventory storage levels, gas price differentials and other factors. As a result, we cannot accurately predict future oil and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. A substantial or extended decline in oil and gas prices could have a material adverse effect on our business, financial condition, results of operations, quantities of oil and gas reserves that may be economically produced and liquidity that may be accessed through our borrowing base under our revolving credit facility and through capital markets.

 

In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success. Future finding and development costs are subject to changes in the industry, including the costs of acquiring, drilling and completing our projects. We focus our efforts on increasing oil and gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flow from operations will depend on our ability to manage our overall cost structure.

 

Like all oil and gas production companies, we face the challenge of natural production declines. Oil and gas production from a given well naturally decreases over time. Additionally, our reserves have a rapid initial decline. We attempt to overcome this natural decline by drilling to develop and identify additional reserves, farm-ins or other joint drilling ventures, and by acquisitions. However, during times of severe price declines, we may from time to time reduce current capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially reduce our production volumes and revenues from pre-2009 levels and increase future expected costs necessary to develop existing reserves. As discussed above, due to the extended decline of oil and natural gas prices, we released our remaining rigs during the first week of April 2009. The natural decline of our tight gas fields and reduced drilling activity has caused a decline in our average daily production since the three months ended March 31, 2009.

 

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