CLAYTON WILLIAMS ENERGY INC /DE - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - July 28, 2011

Attached files

file filename
8-K - CLAYTON WILLIAMS ENERGY, INC. 8-K - CLAYTON WILLIAMS ENERGY INC /DEa6809943.htm

Exhibit 99.1

Clayton Williams Energy Announces Second Quarter 2011 Financial Results

MIDLAND, Texas--(BUSINESS WIRE)--July 28, 2011--Clayton Williams Energy, Inc. (the “Company”) (NASDAQ: CWEI) today reported its financial results for the second quarter of 2011 and its outlook for capital spending and production for the remainder of 2011.

Financial Results for the Second Quarter of 2011

Net income attributable to Company stockholders for the second quarter of 2011 (“2Q11”) was $42.7 million, or $3.51 per share, as compared to net income of $14 million, or $1.15 per share, for the second quarter of 2010 (“2Q10”). Cash flow from operations for 2Q11 was $86.4 million as compared to $66.3 million for 2Q10.

For the six months ended June 30, 2011, net income attributable to Company stockholders was $34.8 million, or $2.86 per share, as compared to a net income of $30.6 million, or $2.52 per share, for the same period in 2010. Cash flow from operations for the six-month period in 2011 was $119.7 million as compared to $96.7 million during the same period in 2010.

The key factors affecting the comparability of financial results for 2Q11 versus 2Q10 were:

  • Oil and gas sales increased $28.9 million in 2Q11 versus 2Q10. Price variances accounted for $25.2 million of the increase and production variances accounted for the remaining $3.7 million. Average realized oil prices were $100.07 per barrel in 2Q11 versus $74.27 per barrel in 2Q10, and average realized gas prices were $5.56 per Mcf in 2Q11 versus $5.14 per Mcf in 2Q10.
  • Oil production increased 10% in 2Q11 versus 2Q10 while gas production declined 19%. Oil and gas production per barrel of oil equivalent (“BOE”) was constant in 2Q11 as compared to 2Q10. Oil production increased to 886,000 barrels, or 9,736 barrels per day, as compared to 808,000 barrels, or 8,879 barrels per day, while gas production declined to 2.3 Bcf, or 24,846 Mcf per day as compared to 2.8 Bcf or 30,846 Mcf per day for 2Q10. On a comparable basis, after giving effect to the sale of properties in North Louisiana in June 2010, oil and gas production in 2Q11 on a BOE basis was 8% higher than 2Q10. The increase in oil production and the decline in gas production are indicative of the Company’s current emphasis on the development of oil reserves in the Permian Basin.
  • Production costs increased 27% from $20.6 million in 2Q10 to $26.1 million in 2Q11 due to a combination of more producing wells, rising costs of field services and increased production taxes on higher oil and gas sales.
  • Gain on derivatives for 2Q11 was $28.2 million ($35.6 million non-cash mark-to-market gain and a $7.4 million realized loss on settled contracts) versus a gain in 2Q10 of $21 million ($17.3 million non-cash mark-to-market gain and a $3.7 million realized gain on settled contracts). See accompanying tables for additional information about the Company’s accounting for derivatives.
  • Interest expense increased to $9.2 million in 2Q11 compared to $6.2 million in 2Q10 due in part to the increase in the total aggregate principal amount of the Company’s Senior Notes.
  • G&A expenses were $3 million in 2Q11 versus $7.8 million in 2Q10. Non-cash employee compensation expense from incentive compensation plans accounted for a $2.4 million credit to expense in 2Q11 versus a $3.1 million charge for 2Q10. Excluding non-cash employee compensation expense, G&A expenses increased 15% in 2Q11 compared to 2Q10.
  • Non-cash impairments of property and equipment were $4.4 million in 2Q11 versus $11.1 million in 2Q10. The 2Q11 impairment related to certain non-core oil and gas properties in the Permian Basin.

Comparisons to Guidance

Oil and gas production for 2Q11 was 14,679 BOE per day, just slightly below the low end of the Company’s guidance range of 14,892 BOE per day and 5% below the mid-point of the guidance range of 15,375 BOE per day. Production shortfalls in Andrews County totaling approximately 1,000 BOE per day were partially offset by surplus production from other areas of approximately 300 BOE per day. Just over half of the Andrews County shortfall resulted from a combination of completion delays and production disruptions caused by wildfires. In addition, the pipelines carrying the Company’s natural gas production in this area is at maximum capacity, causing oil and gas production to be choked back due to high line pressures. The Company is considering various actions to alleviate this operating condition.

Outlook

The Company expects to provide an update to its financial guidance disclosures for 2011 in August. As a result of its shift in focus to the Reeves County Wolfbone play, the Company expects capital spending to increase and production to decrease from the existing guidance estimates.

Drilling and completion costs are expected to increase to a range of $440 million to $460 million, as compared to existing guidance of $410 million. The following factors contributed to the upward cost revision:

  • Increase in the rig count in the Wolfbone play to 11 in the near term, from four rigs in the existing guidance, while reducing the rig count in the Andrews Wolfberry play from seven rigs to one rig, and reducing the rig count in the Austin Chalk area from two rigs to one rig;
  • Increase in the estimated cost to drill and complete Wolfbone wells from $3.5 million to $4 million; and
  • Current plans to incur approximately $10 million to begin construction of pipelines and infrastructure for gathering and disposition of produced oil, gas and water.

Near-term production estimates are expected to decrease as the Company’s drilling focus transitions from the Wolfberry play to the Wolfbone play. The Company’s share of production from initial Wolfbone wells is substantially less than its share of Wolfberry production due to the terms of a drill-to-earn farm-out agreement with Chesapeake Exploration which requires the Company to carry Chesapeake on specified wells in order to earn acreage. The effect of this structure is that the Company gives up a portion of its initial production in lieu of paying substantial upfront acreage costs.

Scheduled Conference Call

The Company will host a conference call to discuss these results and other forward-looking items today, July 28th at 1:30 pm CT (2:30 pm ET). The dial-in conference number is: 800-901-5213, passcode 66471213. The replay will be available for one week at 888-286-8010, passcode 92233345.

To access the conference call via Internet webcast, please go to the Investor Relations section of the Company’s website at www.claytonwilliams.com and click on “Live Webcast.” Following the live webcast, the call will be archived for a period of 90 days on the Company’s website.

Clayton Williams Energy, Inc. is an independent energy company located in Midland, Texas.

This 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 or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. The Company cautions that its future natural gas and liquids production, revenues, cash flows, liquidity, plans for future operations, expenses, outlook for oil and natural gas prices, timing of capital expenditures and other forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and gas.

These risks include, but are not limited to, the possibility of unsuccessful exploration and development drilling activities, our ability to replace and sustain production, commodity price volatility, domestic and worldwide economic conditions, the availability of capital on economic terms to fund our capital expenditures and acquisitions, our level of indebtedness, the impact of the current economic recession on our business operations, financial condition and ability to raise capital, declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our credit facility and impairments, the ability of financial counterparties to perform or fulfill their obligations under existing agreements, the uncertainty inherent in estimating proved oil and gas reserves and in projecting future rates of production and timing of development expenditures, drilling and other operating risks, lack of availability of goods and services, regulatory and environmental risks associated with drilling and production activities, the adverse effects of changes in applicable tax, environmental and other regulatory legislation, and other risks and uncertainties are described in the Company's filings with the Securities and Exchange Commission. The Company undertakes no obligation to publicly update or revise any forward-looking statements.

 
 
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per share)
 
 
  Three Months Ended   Six Months Ended
June 30, June 30,
2011   2010 2011   2010
REVENUES
Oil and gas sales $ 105,804 $ 76,918 $ 200,736 $ 155,960
Natural gas services 365 452 774 955
Drilling rig services 2,425 - 2,685 -
Gain on sales of assets   949     113     14,521     399  
Total revenues   109,543     77,483     218,716     157,314  
 
COSTS AND EXPENSES
Production 26,133 20,567 50,953 41,494
Exploration:
Abandonments and impairments 174 2,891 1,051 5,769
Seismic and other 2,167 974 3,445 2,634
Natural gas services 285 306 548 654
Drilling rig services 1,919 419 2,705 1,081
Depreciation, depletion and amortization 25,342 25,437 49,086 51,049
Impairment of property and equipment 4,424 11,114 4,424 11,114
Accretion of abandonment obligations 697 647 1,371 1,294
General and administrative 3,037 7,832 15,536 14,056
Loss on sales of assets and impairment of inventory   107     1,443     303     1,443  
Total costs and expenses   64,285     71,630     129,422     130,588  
Operating income   45,258     5,853     89,294     26,726  
 
OTHER INCOME (EXPENSE)
 
Interest expense (9,175 ) (6,244 ) (15,587 ) (12,353 )
Loss on early extinguishment of long-term debt - - (4,594 ) -
Gain (loss) on derivatives 28,187 20,983 (18,158 ) 31,284
Other 1,900 1,016 2,987 1,844
       
Total other income (expense)   20,912     15,755     (35,352 )   20,775  
 
Income before income taxes 66,170 21,608 53,942 47,501
 
Income tax expense (23,502 ) (7,645 ) (19,149 ) (16,863 )
       
NET INCOME $ 42,668   $ 13,963   $ 34,793   $ 30,638  
 
 
Net income per common share:
Basic $ 3.51   $ 1.15   $ 2.86   $ 2.52  
Diluted $ 3.51   $ 1.15   $ 2.86   $ 2.52  
 
Weighted average common shares outstanding:
Basic   12,162     12,146     12,159     12,146  
Diluted   12,163     12,146     12,159     12,146  

 

 
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands)
 
ASSETS
  June 30,   December 31,
2011 2010
(Unaudited)
CURRENT ASSETS
Cash and cash equivalents $ 18,079 $ 8,720
Accounts receivable:
Oil and gas sales 30,629 35,361
Joint interest and other, net 7,757 9,893
Affiliates 600 796
Inventory 34,732 39,218
Deferred income taxes 3,808 5,074
Assets held for sale - 8,762
Prepaids and other   16,532     5,997  
  112,137     113,821  
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method 1,873,222 1,707,252
Natural gas gathering and processing systems 18,439 18,153
Contract drilling equipment 72,930 58,486
Other   18,512     17,425  
1,983,103 1,801,316
Less accumulated depreciation, depletion and amortization   (1,092,607 )   (1,034,227 )
Property and equipment, net   890,496     767,089  
 
OTHER ASSETS
Debt issue costs, net 13,064 8,323
Other   1,938     1,684  
  15,002     10,007  
 
$ 1,017,635   $ 890,917  
 
LIABILITIES AND STOCKHOLDERS' EQUITY
 
CURRENT LIABILITIES
Accounts payable:
Trade $ 63,242 $ 74,123
Oil and gas sales 33,215 28,920
Affiliates 1,683 1,251
Fair value of derivatives 11,712 7,224
Accrued liabilities and other   29,384     22,202  
  139,236     133,720  
 
NON-CURRENT LIABILITIES
Long-term debt 448,347 385,000
Deferred income taxes 96,106 78,035
Fair value of derivatives 7,990 3,409
Other   41,498     41,301  
  593,941     507,745  
 
STOCKHOLDERS' EQUITY
Preferred stock, par value $.10 per share - -
Common stock, par value $.10 per share 1,216 1,215
Additional paid-in capital 152,502 152,290
Retained earnings   130,740     95,947  
Total stockholders' equity   284,458     249,452  
 
$ 1,017,635   $ 890,917  

 

 
CLAYTON WILLIAMS ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
 
 
      Three Months Ended   Six Months Ended
June 30, June 30,
2011   2010 2011   2010
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 42,668 $ 13,963 $ 34,793 $ 30,638
Adjustments to reconcile net income to cash
provided by operating activities:
Depreciation, depletion and amortization 25,342 25,437 49,086 51,049
Impairment of property and equipment 4,424 11,114 4,424 11,114
Exploration costs 174 2,891 1,051 5,769
(Gain) loss on sales of assets and impairment of inventory, net (842 ) 1,330 (14,218 ) 1,044
Deferred income tax expense 23,502 7,645 19,149 16,863
Non-cash employee compensation (2,438 ) 3,069 4,963 5,079
Unrealized (gain) loss on derivatives (35,558 ) (17,269 ) 9,069 (25,871 )
Accretion of abandonment obligations 697 647 1,371 1,294
Amortization of debt issue costs 562 439 1,130 774
Loss on early extinguishment of long-term debt - - 4,594 -
 
Changes in operating working capital:
Accounts receivable 12,785 6,702 7,064 5,234
Accounts payable 7,931 5,586 (4,023 ) (3,403 )
Other   7,186     4,747     1,271     (2,907 )
Net cash provided by operating activities   86,433     66,301     119,724     96,677  
 
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment (97,288 ) (77,252 ) (180,281 ) (135,528 )
Proceeds from sales of assets 1,103 72,532 12,105 73,011
Change in equipment inventory (5,733 ) (1,152 ) 4,783 1,300
Other   10     (3 )   (110 )   (98 )
Net cash used in investing activities   (101,908 )   (5,875 )   (163,503 )   (61,315 )
 
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 48,855 - 341,855 -
Repayments of long-term debt (30,000 ) (65,000 ) (286,165 ) (39,000 )
Premium on early extinguishment of long-term debt - - (2,765 ) -
Proceeds from exercise of stock options   187     -     213     -  
Net cash provided by (used in) financing activities   19,042     (65,000 )   53,138     (39,000 )
 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

3,567 (4,574 ) 9,359 (3,638 )
 
CASH AND CASH EQUIVALENTS
Beginning of period 14,512 14,949 8,720 14,013
       
End of period $ 18,079   $ 10,375   $ 18,079   $ 10,375  

 

 
CLAYTON WILLIAMS ENERGY, INC.
COMPUTATION OF EBITDAX
(Unaudited)
(In thousands)
 
 
 
EBITDAX is presented as a supplemental non-GAAP financial measure because of its wide acceptance by financial analysts, investors, debt holders, banks, rating agencies and other financial statement users as an indication of an entity's ability to meet its debt service obligations and to internally fund its exploration and development activities.
 
 
The Company defines EBITDAX as net income (loss) before interest expense, income taxes, exploration costs, (gain) loss on sales of assets and impairment of inventory, loss on early extinguishment of debt and all non-cash items in the Company's statements of operations, including depreciation, depletion and amortization, impairment of property and equipment, accretion of abandonment obligations, certain employee compensation and changes in fair value of derivatives. EBITDAX is not an alternative to net income (loss) or cash flow from operating activities, or any other measure of financial performance presented in conformity with GAAP.
 
 
 
The following table reconciles net income to EBITDAX:
 
      Three Months Ended   Six Months Ended
June 30, June 30,
2011   2010 2011   2010
 
Net income $ 42,668 $ 13,963 $ 34,793 $ 30,638
Interest expense 9,175 6,244 15,587 12,353
Income tax expense 23,502 7,645 19,149 16,863
Exploration:
Abandonments and impairments 174 2,891 1,051 5,769
Seismic and other 2,167 974 3,445 2,634
Net (gain) loss on sales of assets and impairment of inventory (842 ) 1,330 (14,218 ) 1,044
Loss on early extinguishment of debt - - 4,594 -
Depreciation, depletion and amortization 25,342 25,437 49,086 51,049
Impairment of property and equipment 4,424 11,114 4,424 11,114
Accretion of abandonment obligations 697 647 1,371 1,294
Non-cash employee compensation (2,438 ) 3,069 4,963 5,079
Non-cash changes in fair value of derivatives (35,558 ) (17,269 ) 9,069 (25,871 )
       
$ 69,311   $ 56,045   $ 133,314   $ 111,966  

 

 
Clayton Williams Energy, Inc.
Summary Production and Price Data
(Unaudited)
 
 
    Three Months Ended   Six Months Ended
June 30, June 30,
2011   2010 2011   2010
 
Oil and Gas Production Data:
Oil (MBbls) 886 808 1,785 1,560
Gas (MMcf) 2,261 2,807 4,374 6,135
Natural gas liquids (MBbls) 73 60 156 117
Total (MBOE) 1,336 1,336 2,670 2,700
 

Average Realized Prices (a):

Oil ($/Bbl) $ 100.07   $ 74.27   $ 94.47   $ 75.10  
Gas ($/Mcf) $ 5.56   $ 5.14   $ 5.40   $ 5.48  
Natural gas liquids ($/Bbl) $ 57.16   $ 40.13   $ 52.47   $ 43.08  
 

Gain (Loss) on settled derivative contracts (a):

($ in thousands, except per unit)
Oil:
Net realized loss $ (11,919 ) $ (1,249 ) $ (18,697 ) $ (2,871 )
Per unit produced ($/Bbl) $ (13.45 ) $ (1.55 ) $ (10.47 ) $ (1.84 )
 
Gas:
Net realized gain $ 4,548 $ 4,964 $ 9,608 $ 8,283
Per unit produced ($/Mcf) $ 2.01 $ 1.77 $ 2.20 $ 1.35
 
Average Daily Production:
Oil (Bbls):
Permian Basin 5,680 5,390 5,927 5,151
Austin Chalk/ Eagle Ford Shale 3,335 2,835 3,333 2,717
South Louisiana 493 435 454 530
Other   228     219   (b)   148     221   (b)
Total   9,736     8,879     9,862     8,619  
 
Natural Gas (Mcf):
Permian Basin 12,176 13,263 13,043 13,586
Giddings Area:
Austin Chalk/ Eagle Ford Shale 2,177 1,810 2,060 2,169
Cotton Valley Reef Complex 2,931 4,072 2,942 3,802
South Louisiana 6,134 4,930 4,650 6,213
Other   1,428     6,771   (b)   1,471     8,125   (b)
Total   24,846     30,846     24,166     33,895  
 
Natural gas liquids (Bbls):
Permian Basin 519 356 568 314
Austin Chalk/ Eagle Ford Shale 183 185 205 228
South Louisiana 60 86 52 83
Other   40     32   (b)   37     21   (b)
Total   802     659     862     646  
 

 

Three Months Ended Six Months Ended
June 30, June 30,
  2011     2010     2011     2010  
 
Oil and Gas Costs ($/BOE Produced):
Production costs $ 19.56 $ 15.39 $ 19.08 $ 15.37
Production costs (excluding production taxes) $ 15.61 $ 12.25 $ 15.14 $ 12.22
Oil and gas depletion $ 18.31 $ 18.57 $ 17.89 $ 18.30
 
General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation $ 5,475 $ 4,763 $ 10,573 $ 8,977
Non-cash employee compensation (c)   (2,438 )   3,069     4,963     5,079  
Total $ 3,037   $ 7,832   $ 15,536   $ 14,056  
 

 

(a)

Hedging gains/losses are only included in the determination of the Company's average realized prices if the underlying derivative contracts are designated as cash flow hedges under applicable accounting standards. The Company did not designate any of its 2011 or 2010 derivative contracts as cash flow hedges. This means that the Company's derivatives for 2011 and 2010 have been marked-to-market through its statement of operations as other income/expense instead of through accumulated other comprehensive income on the Company's balance sheet. This also means that all realized gains/losses on these derivatives are reported in other income/expense instead of as a component of oil and gas sales.
 
(b) Other for 2010 includes production attributable to sold properties in North Louisiana as follows: Three months: Oil 137, Gas 5,747, NGL 26 and Six months: Oil 142, Gas 7,225, NGL 15.
 
(c) Non-cash employee compensation relates to the Company's non-equity award plans. In June 2011, the Compensation Committee of the Board of Directors approved the modification of certain existing reward plans. The impact of this modification resulted in a credit to expense of $2.4 million during 2Q11.

 

 
Clayton Williams Energy, Inc.
Summary of Open Commodity Derivatives
(Unaudited)
 
 
The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to June 30, 2011.
 
  Oil   Gas
Swaps: Bbls   Price MMBtu (a)   Price
Production Period:
3rd Quarter 2011 547,000 $ 83.78 1,560,000 $ 7.07
4th Quarter 2011 540,000 $ 83.78 1,500,000 $ 7.07
2012 1,864,000 $ 93.65 - $ -
2013 480,000 $ 96.70 - $ -
3,431,000 3,060,000
 
 
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

CONTACT:
Clayton Williams Energy, Inc.
Patti Hollums, 432-688-3419
Director of Investor Relations
or
Michael L. Pollard, 432-688-3029
Chief Financial Officer
e-mail: cwei@claytonwilliams.com
website: www.claytonwilliams.com

CLAYTON WILLIAMS ENERGY INC /DE Reports