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Clayton Williams Energy Announces 2011 Financial Results And Year-End Reserves

Stocks in this article: CWEI

Clayton Williams Energy, Inc. (the “Company”) (NASDAQ:CWEI) today reported its financial results for the quarter and year ended December 31, 2011, along with information about its proved oil and gas reserves as of December 31, 2011.

Highlights

  • 2011 Cash Flow from Operations of $280 Million, up 34%
  • Total Proved Reserves of 64.3 Million BOE, up 26%
  • 77% Oil and NGL and 61% Proved Developed
  • 384% of 2011 Production Replaced by Reserve Additions

Financial Results for Fiscal Year 2011

Net income attributable to Company stockholders for fiscal 2011 was $93.8 million, or $7.71 per share, as compared to net income of $36.9 million, or $3.04 per share, for fiscal 2010. Cash flow from operations for 2011 was $280 million as compared to $208.3 million for 2010. The key factors affecting the comparability of the two years were:

  • Oil and gas sales increased $78.9 million in 2011 compared to 2010. Price variances accounted for $63.8 million of the increase and production variances accounted for the remaining $15.1 million. Average realized oil prices were $92.43 per barrel in 2011 versus $76.44 per barrel in 2010, and average realized gas prices were $5.30 per Mcf in 2011 versus $5.17 per Mcf in 2010. Although combined oil and gas production for 2011 remained relatively constant on a barrel of oil equivalent (“BOE”) basis compared to 2010, oil and NGL production accounted for 74% of total production in 2011 versus 67% in 2010. Oil production increased 10% compared to 2010, while gas production declined 20%. On a comparable basis, after giving effect to the sale of properties in North Louisiana in June 2010, oil and gas production in 2011 on a BOE basis was 4% higher than 2010.
  • Gain on derivatives for 2011 was $47 million ($42.5 million gain on settled contracts and a $4.5 million non-cash mark-to-market gain) versus a gain in 2010 of $0.7 million ($9.9 million realized gain on settled contracts and a $9.2 million non-cash mark-to-market loss). See accompanying tables for additional information about the Company’s accounting for derivatives.
  • Production costs increased 22% to $101.1 million in 2011 from $83.1 million in 2010. Production costs excluding production taxes, referred to as lifting costs, accounted for $14.7 million of the increase due to a combination of more producing wells and rising costs of field services, and production taxes accounted for the remaining $3.3 million of the increase due to higher oil and gas sales.
  • Exploration expenses related to abandonments and impairments were $20.8 million in 2011 compared to $9.1 million in 2010. The expense for 2011 includes a charge of $11.8 million for the abandonment of the Hamill Foundation #1, an exploratory well in Leon County, Texas targeting the Deep Bossier gas formation, and $5 million of leasehold impairments related to the abandonment of the well. Based on the results of a recent stimulation procedure, the Company determined that the well was uneconomic.
  • Interest expense increased to $32.9 million in 2011 from $24.4 million in 2010 due primarily to the increase in the total aggregate principal amount of the Senior Notes from $225 million to $350 million. The Company also recorded a $5.5 million loss on early extinguishment of long-term debt related to the redemption of the 2013 Senior Notes in 2011.
  • Net gain on sales of assets and impairment of inventory was a $14.1 million gain in 2011 compared to a gain of $1.9 million in 2010. In 2011, the Company sold two 2,000 horsepower drilling rigs and related equipment for a gain of $13.2 million.
  • General and administrative expenses for 2011 were $41.6 million versus $35.6 million in 2010. Non-cash employee compensation related to non-equity incentive plans totaled $12.9 million in 2011 versus $13.9 million in 2010. Excluding non-cash employee compensation, general and administrative expenses increased to $28.7 million in 2011 versus $21.7 million in 2010 due to a combination of higher personnel costs and costs associated with the proposed merger with affiliated partnerships.

Financial Results for the Fourth Quarter of 2011

Net loss attributable to Company stockholders for the fourth quarter of 2011 (“4Q11”) was $15.5 million, or $1.27 per share, as compared to a net loss of $5.3 million, or $.44 per share, for the fourth quarter of 2010 (“4Q10”). Cash flow from operations for 4Q11 was $104.8 million as compared to $54.1 million for 4Q10. The key factors affecting the comparability of the two quarters were:

  • Oil and gas sales increased $16.3 million in 4Q11 versus 4Q10. Price variances accounted for $9.8 million of the increase while production variances accounted for the remaining $6.5 million. Average realized oil prices were $91.70 per barrel in 4Q11 versus $82.07 per barrel in 4Q10, and average realized gas prices were $4.91 per Mcf in 4Q11 versus $5.02 per Mcf in 4Q10. Combined oil and gas production for 4Q11 was 5% higher on a BOE basis than in 4Q10. Oil production increased 11% compared to 4Q10, while gas production declined 3%.
  • Production costs increased 22% to $25.9 million in 4Q11 from $21.1 million in 4Q10. Production costs excluding production taxes, referred to as lifting costs, accounted for $4.1 million of the increase due to a combination of more producing wells and rising costs of field services, and production taxes accounted for the remaining $0.7 million of the increase due to higher oil and gas sales.
  • Loss on derivatives for 4Q11 was $27.1 million ($77.5 million non-cash mark-to-market loss offset in part by a $50.4 million realized gain on settled contracts) versus a loss in 4Q10 of $26.6 million ($27 million non-cash mark-to-market loss net of a $0.4 million realized gain on settled contracts). See accompanying tables for additional information about the Company’s accounting for derivatives.
  • Exploration expenses related to abandonments and impairments were $18.5 million in 4Q11 compared to $2.9 million in 4Q10. The expense for 4Q11 includes charges related to the previously discussed abandonment of the Hamill Foundation #1.
  • General and administrative expenses for 4Q11 were $18.9 million versus $12.8 million in 4Q10. Non-cash employee compensation related to non-equity incentive plans totaled $6.8 million in 4Q11 versus $5.8 million in 4Q10. Excluding non-cash employee compensation, general and administrative expenses increased to $12.1 million in 4Q11 versus $7 million in 4Q10 due to a combination of higher personnel costs and costs associated with the proposed merger with affiliated partnerships.

Reserves

The Company reported that its total estimated proved oil and gas reserves as of December 31, 2011 were 64.3 million barrels of oil equivalent (“MMBOE”), consisting of 49.5 million barrels of oil and NGL and 88.9 Bcf of natural gas. On a BOE basis, oil and NGL comprised 77% of total proved reserves at year-end 2011 versus 74% at year-end 2010. Proved developed reserves at year-end 2011 were 39.3 MMBOE, or 61% of total proved reserves, as compared to 34.5 MMBOE, or 68% of total proved reserves, at year-end 2010. The present value of estimated future net cash flows from total proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10%, (referred to as “PV-10 Value”) totaled $1.4 billion for year-end 2011 as compared to $992 million for year-end 2010. For a reconciliation of PV-10 Value (a non-GAAP measure) to standardized measure of discounted future net cash flows, see accompanying tables.

The following table summarizes the changes in total proved reserves during 2011 on an MMBOE basis.

      MMBOE  
Total proved reserves, December 31, 2010   51.1
Extensions and discoveries 20.9
Revisions (2.1 )
Sales of reserves (0.2 )
Production   (5.4 )  
Total proved reserves, December 31, 2011   64.3    
 

The Company replaced 384% of its 2011 oil and gas production through extensions and discoveries. Most of the 20.9 MMBOE of reserve additions in 2011 were derived from growth through the drill bit in the Permian Basin drilling Wolfberry and Wolfbone wells. Oil and NGL accounted for 84% of the 2011 reserve additions.

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