EX-99.1 2 d71260exv99w1.htm EX-99.1 exv99w1
EXHIBIT 99.1
     
(APPROACH LOGO)   One Ridgmar Centre
6500 West Freeway, Suite 800
Fort Worth, Texas 76116
817.989.9000 telephone
817.989.9001 facsimile
www.approachresources.com
News Release
Approach Resources Inc.
Announces 2009 Reserves and Production
     Fort Worth, Texas, February 23, 2010 — Approach Resources Inc. (NASDAQ: AREX) today reported year-end 2009 proved oil and gas reserves of 218.9 Bcfe. At December 31, 2009, proved reserves consisted of 77% natural gas and 23% oil, condensate and natural gas liquids (“NGLs”), and had a reserve life index of over 20 years based on 2009 production of 8.8 Bcfe. The proved developed portion of year-end 2009 proved reserves was 43%.
     For the year, we replaced 345% of 2009 production from drilling alone. From all sources, we replaced approximately 190% of 2009 production.
     During 2009, the Company reduced capital expenditures and drilling activity due to the extended decline in natural gas prices. As a result, we were able to pay down our long-term debt and increase our liquidity (funds available under our credit facility plus year-end cash and cash equivalents). The following table is a summary of selected, unaudited results from 2009:
                 
    2009   2008
Proved reserves (MMcfe)
     218,928       211,068  
 
                
Production (MMcfe)
     8,808       8,755  
Production (MMcfe/d)
     24.1       23.9  
 
                
Long-term debt ($ millions)
   $ 32.3     $ 43.5  
Liquidity
   $ 85.4     $ 60.5  
 
                
Costs incurred ($ millions)
   $ 30.7     $ 104.1  
Drill-bit finding and development cost ($/Mcfe)
   $ 0.97     $ 2.11  
Year-End 2009 Proved Reserves
     The following table is a reconciliation of the changes in our proved reserves between December 31, 2008 and December 31, 2009:
                         
    Natural Gas     Oil and NGLs     Total  
    (MMcf)     (MBbl)     (MMcfe)  
Balance — December 31, 2008
     172,867       6,367       211,068  
Extensions and discoveries
     14,301       2,682       30,395  
Purchases of minerals in place
     —       —       —  
Production
     (6,320 )     (415 )     (8,808 )
Revisions to previous estimates
                        
Performance-related revisions
     (2,590 )     (164 )     (3,575 )
Price-related revisions
     (9,924 )     (38 )     (10,152 )
 
                  
Balance — December 31, 2009
     168,334       8,432       218,928  
 
                  
Proved developed reserves at December 31, 2009
     74,804       3,118       93,512  
 
                  

 

 

     At December 31, 2009, 93% of the Company’s proved reserves were located in our core operating area in the Permian Basin. Year-end 2009 proved reserves in our Cinco Terry field in West Texas totaled 68.7 Bcfe, representing an increase of 50% from year-end 2008 proved reserves of 45.9 Bcfe. Year-end 2009 proved reserves in our Ozona Northeast field in West Texas totaled 134.7 Bcfe. Year-end 2009 proved reserves in our North Bald Prairie field in East Texas totaled 15.5 Bcfe.
     The standardized measure of discounted future net cash flows for our proved reserves at December 31, 2009, was $80.0 million. The PV-10, or pre-tax present value of our proved reserves discounted at 10%, was estimated at $128.9 million. The independent engineering firm DeGolyer and MacNaughton prepared our year-end 2009 reserve report and PV-10 estimate for the Current Price Case (defined below). PV-10 is a non-GAAP measure. See “Supplemental Non-GAAP Measures” below for our definition of PV-10 and a reconciliation to the standardized measure (GAAP).
     Under the Securities and Exchange Commission’s (“SEC”) new reserve reporting rules, year-end 2009 proved reserves and PV-10 were calculated based on the first-of-the-month, 12-month average price for natural gas, oil and NGLs, or $3.87 per MMBtu, $61.04 per Bbl of oil and $27.20 per Bbl of NGLs, respectively. Our reservoir engineers also calculated our estimated reserves and PV-10 based on the SEC’s previous reserve reporting rules, or the year-end 2009 spot price of $5.79 per MMBtu, $76.00 per Bbl of oil and $42.94 per Bbl of NGLs. The following table is a comparison of our year-end 2009 reserves and PV-10 calculated based on the current SEC reserve reporting rules (“Current Price Case”) and the SEC’s previous reserve reporting rules (“Previous Price Case”):
                                 
    Proved Reserves    
Price Case   Natural Gas (MMcf)   Oil and NGLs (MBbls)   Total (MMcfe)   PV-10
Current Price Case
     168,334       8,432       218,928     $ 128,936  
Previous Price Case
     178,354       8,806       231,190     $ 317,440  
     Preliminary unaudited estimates of 2009 costs incurred totaled $30.7 million, and included $29.6 million for exploration and development drilling and $1.1 million for property acquisitions. Exploration and development costs included $170,000 in non-cash asset retirement obligations recorded in 2009. Based on 2009 exploration and development expenditures of $29.6 million and proved reserve additions of 30.4 Bcfe, drill-bit finding and development (“F&D”) costs were $0.97 per Mcfe. Based on 2009 total costs incurred of $30.7 million and net proved reserve additions of 16.7 Bcfe, all-in F&D costs were $1.84 per Mcfe.
     F&D cost is a non-GAAP measure. See “Supplemental Non-GAAP Measures” below for our definition of F&D costs and a reconciliation to the information required by ASC 932-235.
Production and Operations Update
     Production for the fourth quarter totaled 1,991 MMcfe (21.6 MMcfe/d). Production for fourth quarter of 2009 was 71% natural gas and 29% oil and NGLs.
     During the fourth quarter of 2009, we drilled 13 (6.5 net) wells in Cinco Terry, of which nine (4.5 net) wells were completed as producers, two (one net) wells were plugged and abandoned for mechanical reasons and two (one net) wells were waiting on completion at December 31, 2009. We estimate that

 

 

drilling in our Cinco Terry field during the fourth quarter of 2009 de-risked approximately 8,000 (4,080 net) acres. We also drilled four (four net) wells in Ozona Northeast, of which two (two net) wells were completed as producers and two (two net) wells were waiting on completion at December 31, 2009.
     Production for 2009 totaled 8,808 MMcfe (24.1 MMcfe/d). Production for the year ended December 31, 2009 was 72% natural gas and 28% oil and NGLs.
     During 2009, we drilled 32 (18 net) wells in the Permian Basin, of which 24 (13 net) wells were completed as producers, two (one net) wells were abandoned for mechanical reasons, two (one net) wells were abandoned as non-productive and four (three net) wells were waiting on completion at December 31, 2009. The four (three net) wells waiting on completion at December 31, 2009, were completed as producers during the first quarter of 2010. We expect to drill 84 (60 net) wells in the Permian Basin during 2010.
     Estimated average daily production for January 2010 was 21.4 MMcfe/d. Estimated average daily production for February 2010 currently is 22.6 MMcfe/d.
     We have completed the acquisition of 3-D seismic data across our Cinco Terry field. Our 3-D seismic data inventory now covers over 135,000 acres in the Permian Basin. We currently are processing the 3-D seismic data from Cinco Terry and expect to see preliminary results in March 2010. Interpretation of the 3-D seismic data is expected to be complete by June 2010.
Expected 2009 Impairments
     In accordance with ASC 360, 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 year-end 2009 proved reserves, we do not expect to record an impairment of proved properties. However, based on the review of the recoverability of the carrying value of our unproved properties, we do expect to report a non-cash impairment charge to unproved oil and gas properties of $2.7 million to $3.0 million in 2009, related to all of our remaining carrying costs in Northeast British Columbia.
Forward-Looking Statements and Cautionary Statements
     This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Forward-looking statements are typically identified by the use of terms such as “may,” “will,” “expect,” “anticipate,” “believe,” “estimate” and similar words, although some forward-looking statements may be expressed differently. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including 2010 drilling plans, 3-D seismic operations, interpretation and results, the amount of acreage proved up by drilling activity and expected 2009 impairment charges. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Further information on such assumptions, risks and uncertainties is available in the Company’s SEC filings. Our SEC filings are available on our website at

 

 

www.approachresources.com. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
     Information in this release regarding the standardized measure, costs incurred for oil and gas properties and expected impairment charges is preliminary and unaudited. Final and audited results will be provided in our annual report on Form 10-K for the year ended December 31, 2009, to be filed on or before March 16, 2010.
About Approach Resources Inc.
     Approach Resources Inc. is an independent energy company engaged in the exploration, development, production and acquisition of natural gas and oil properties in the United States. The Company operates in Texas, Kentucky and New Mexico. For more information about the Company, please visit www.approachresources.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.
Supplemental Non-GAAP Measures
     This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations within this release of the non-GAAP financial measures to the most directly comparable GAAP financial measures. These non-GAAP financial measures should be considered in addition to, but not as a substitute for, measures of financial performance prepared in accordance with GAAP that are presented in this release.
PV-10
     The present value of our proved reserves, discounted at 10% (PV-10), was estimated at $128.9 million at December 31, 2009. Under the Current Price Case, PV-10 was calculated based on the first-of-the-month, 12-month average for natural gas, oil and NGLs, or $3.87 per MMBtu, $61.04 per Bbl of oil and $27.20 per Bbl of NGLs, respectively.
     PV-10 based the Previous Price Case totaled $317.4 million and assumed the posted spot price as of December 31, 2009, for natural gas, oil and NGLs, or $5.79 per MMBtu, $76.00 per Bbl of oil and $42.94 per Bbl of NGLs, respectively.
     PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and 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 the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry.
     The following table reconciles PV-10 to our standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with GAAP). PV-

 

 

10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.
                 
    Current     Previous  
As of December 31, 2009   Price Case     Price Case  
(In thousands)            
PV-10
   $ 128,936     $ 317,440  
Less income taxes:
                
Undiscounted future income taxes
     (88,796 )     (256,144 )
10% discount factor
     39,851       139,625  
 
            
Future discounted income taxes
     (48,945 )     (116,519 )
 
                
Standardized measure of discounted future net cash flows
   $ 79,991     $ 200,921  
 
            
Finding and Development Costs
     Drill-bit finding and development (“F&D”) costs are calculated by dividing the sum of exploration costs and development costs for the year by the total of reserve extensions and discoveries for the year.
     All-in F&D costs, including revisions, are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the year by the total of reserve extensions, discoveries and all revisions for the year.
     All-in F&D costs, including revisions and the change in future development costs, are calculated by dividing the sum of property acquisition costs, exploration costs, development costs and the change in future development costs from the prior year by the total of reserve extensions, discoveries and all revisions for the year.
     We believe that providing the above measures of F&D cost is useful to assist in an evaluation of how much it costs the Company, on a per Mcfe basis, to add proved reserves. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our previous SEC filings and to be included in our annual report on Form 10-K to be filed with the SEC on or before March 16, 2010. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are recorded, and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases.
     As a result of the above factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in our filings with the SEC, we cannot assure you that the Company’s future F&D costs will not differ materially from those set forth above. Further, the methods used by us to calculate F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D costs may not be comparable to similar measures provided by other companies.
     The following table reflects the reconciliation of our estimated F&D costs for the year ended December 31, 2009 to the information required by paragraphs 11 and 21 of ASC 932-235:

 

 

         
Cost summary (in thousands)
        
Property acquisition costs
        
Unproved properties
   $ 1,082  
Proved properties
     57  
Exploration costs
     1,483  
Development costs(1)
     28,121  
 
      
Total costs incurred
   $ 30,743  
 
        
Future development costs (in thousands)
        
2008
   $ 201,259  
2009
     213,161  
 
      
Change in future development costs
   $ 11,902  
 
        
Reserve summary (MMcfe)
        
Balance — December 31, 2008
     211,068  
Extensions and discoveries
     30,395  
Purchases of minerals in place
     —  
Production
     (8,808 )
Revisions to previous estimates
     (13,727 )
 
      
Balance — December 31, 2009
     218,928  
 
        
Finding and development costs ($/Mcfe)
        
Drill-bit F&D cost
   $ 0.97  
All-in F&D cost, including revisions
   $ 1.84  
All-in F&D costs, including revisions and change in future development costs
   $ 2.56  
 
(1)   Includes $170,000 in non-cash asset retirement obligations recorded in 2009.
Production Replacement Calculation
     Production replaced from drilling alone is calculated by dividing extensions and discoveries of 30.4 Bcfe by production of 8.8 Bcfe. Production replaced from all sources is calculated by dividing net proved reserve additions of 16.7 Bcfe (the sum of extensions and discoveries and revisions) by production of 8.8 Bcfe. We use production replacement ratios as an indicator of the Company’s potential ability to replace annual production volumes and grow our reserves. However, these production replacement ratios have limitations. These ratios can vary from year to year for the Company and among other oil and gas companies based on the extent and timing of discoveries and property acquisitions. In addition, since these ratios do not incorporate the cost or timing of future production of new reserves, they should not be used as a measure of value creation.
Glossary:
Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, used in reference to oil, condensate or NGLs.
Bcfe. Billion cubic feet of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs.
GAAP. Generally accepted accounting principles in the United States.
MBbl. Thousand barrels of oil, condensate or NGLs.
Mcf. Thousand cubic feet of natural gas.

 

 

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs.
MMcf. Million cubic feet of natural gas.
MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs.
NGLs. Natural gas liquids.
Reserve life index. An index calculated by dividing year-end 2009 reserves by 2009 production of 8,808 MMcfe to estimate the number of years of remaining production.
Contact:
Megan P. Brown, Investor Relations and Corporate Communications
Approach Resources Inc.
817.989.9000
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