Clayton Williams Energy Announces Third Quarter 2013 Financial Results And Operations Update

Clayton Williams Energy, Inc. (the “Company”) (NASDAQ:CWEI) today reported its financial results for the third quarter 2013.

Financial Results for the Third Quarter of 2013

Net income attributable to Company stockholders for the third quarter of 2013 (“3Q13”) was $11 million, or $0.90 per share, as compared to a net loss of $7.2 million, or $0.59 per share, for the third quarter of 2012 (“3Q12”). Cash flow from operations for 3Q13 was $71 million as compared to $60.6 million for 3Q12.

For the nine-months ended September 30, 2013, net loss attributable to Company stockholders was $31.3 million, or $2.57 per share, as compared to net income of $33.4 million, or $2.75 per share, for the same period in 2012. Cash flow from operations for the nine-month period in 2013 was $153.9 million as compared to $157.9 million during the same period in 2012. The 2013 period included non-cash, pre-tax charges totaling $89.8 million to write down the carrying value of certain proved properties to their estimated fair value. The Company's adjusted net income, excluding the non-recurring charge, was $27.1 million.

The key factors affecting the comparability of financial results for 3Q13 versus 3Q12 were:
  • In April 2013, the Company sold 95% of its oil and gas reserves, leasehold interests and facilities located in Andrews County, Texas for $215.2 million, subject to customary closing adjustments, with $26.5 million being placed in escrow pending resolution of certain title requirements which the Company believes will be cured. As a result, reported oil and gas production, revenues and operating costs for the quarter and nine months ended September 30, 2013 are not comparable to reported amounts for periods in 2012.
  • Oil and gas sales, excluding amortized deferred revenues, increased $2.7 million in 3Q13 versus 3Q12. Price variances accounted for a $13.3 million increase, and production variances accounted for a $10.6 million decrease. Average realized oil prices were $103.75 per barrel in 3Q13 versus $89.48 per barrel in 3Q12, and average realized gas prices were $3.49 per Mcf in 3Q13 versus $3.29 per Mcf in 3Q12. Oil and gas sales in 3Q13 also include $2.2 million of amortized deferred revenue versus $2.5 million in 3Q12 attributable to a volumetric production payment ("VPP"). Reported production and related average realized sales prices exclude volumes associated with the VPP.
  • Oil, gas and natural gas liquids ("NGL") production per barrel of oil equivalent ("BOE") declined 12% in 3Q13 as compared to 3Q12, with oil production decreasing 10% to 9,674 barrels per day, gas production decreasing 24% to 16,598 Mcf per day, and NGL production increasing 9% to 1,359 barrels per day. Oil and NGL production accounted for approximately 80% of the Company's total BOE production in 3Q13 versus 77% in 3Q12. See accompanying tables for additional information about the Company's oil and gas production.
  • After giving effect to the Andrews sale discussed above, oil and gas production per BOE increased 4% in 3Q13 as compared to 3Q12, with oil production increasing 587 barrels per day, gas production decreasing 3,511 Mcf per day and NGL production increasing 500 barrels per day.
  • Production costs decreased 21% to $25.7 million in 3Q13 from $32.6 million in 3Q12. After giving effect to the Andrews sale, production costs declined $1.8 million, or 6%, due primarily to lower salt water disposal costs and other cost savings resulting from infrastructure improvements in the Reeves County Wolfbone area.
  • Loss on derivatives for 3Q13 was $8.3 million ($7.8 million non-cash mark-to-market loss and $455,000 realized loss on settled contracts) versus a loss in 3Q12 of $21.9 million ($20.5 million non-cash mark-to-market loss and $1.4 million realized loss on settled contracts). See accompanying tables for additional information about the Company's accounting for derivatives.
  • General and administrative ("G&A") expenses were $10 million in 3Q13 versus $5.8 million in 3Q12. G&A expenses in 3Q12 related to accrued compensation expense from the Company's APO reward plans included a non-cash reversal of previously accrued compensation expense totaling $2.2 million as compared to a charge of $1.2 million in 3Q13.

Capitalization and Liquidity

In September 2013, we issued an additional $250 million of aggregate principal amount of 7.75% Senior Notes due 2019. The notes were sold at 100% of par to yield 7.75% to maturity. The offering closed on October 1, 2013. The new notes and the 7.75% Senior Notes due 2019 originally issued on March 16, 2011 and April 29, 2011 will be treated as a single class of debt securities under the same indenture. The net proceeds from the offering was used to repay borrowings under our revolving credit facility.

In October 2013, the Company entered into swap agreements with a counterparty covering 1 million barrels of its 2014 oil production at a price of $96.10 per barrel. See accompanying tables.

Operations Update

Delaware Basin

To date, the Company has drilled 70 vertical and 20 horizontal wells in its Delaware Basin resource play in Reeves, Loving, Ward and Winkler Counties, Texas, where the Company currently holds approximately 91,000 net acres and expects to earn up to 10,000 additional net acres under an existing farmout agreement. Presently, the Company is focused on drilling horizontal wells in the Wolfcamp A shale interval in Reeves County, with seven Wolfcamp A wells currently on production, two wells waiting on completion and three wells being drilled. The following table summarizes production and ownership data for the first five of the Company’s Wolfcamp A wells.
  Peak 30-Day       CWEI Net
Rate Revenue
(BOE/day)(a) % Oil % NGL Interest
 
Mean 501 80% 10% 65%
Median 461 75% 12% 76%
Low 296 82% 10% 75%
High 782 84% 8% 56%

____(a) Oil, residue gas and NGL; gas converted to BOE at 6:1.

The peak 30-day rate for the last two wells included in the above table averaged 684 BOE/day, an increase of 48% over the median well. The Company attributes this improvement in production rates to more efficient hydraulic fracturing procedures based on data obtained through open-hole logs in the laterals.

The sixth Wolfcamp A well has been on production for less than 30 days, and to date has achieved a peak 10-day production rate of 977 BOE/day, and the seventh well is currently flowing back load water.

The Company plans to continue utilizing three drilling rigs in Reeves County with the primary target being the Wolfcamp A shale interval. Recent activity by offset operators suggests that the Wolfcamp B and C intervals could be commercially productive in the region, so the Company may also test those intervals to determine the feasibility of developmental drilling in multiple Wolfcamp shale intervals.

Eagle Ford Shale

The Company is concentrating its Eagle Ford Shale development activities in the northern portion of its legacy Austin Chalk acreage block in Robertson, Brazos, Burleson and Lee Counties, Texas. The following table summarizes production and ownership data for the eight horizontal wells completed by the Company in this area.
  Peak 30-Day     CWEI Net
Rate Revenue
(BOE/day)(a) % Oil Interest
 
Mean 554 95% 79%
Median 537 95% 80%
Low 322 100% 80%
High 872 93% 80%

____(a) Oil and casinghead gas; gas converted to BOE at 6:1.

The Company believes that more than 100,000 net acres of its extensive Austin Chalk acreage position is prospective for Eagle Ford Shale development and presently plans to resume drilling in this area with one rig in November 2013 and a second rig in the first quarter of 2014.

Scheduled Conference Call

The Company will host a conference call to discuss these results and other forward-looking items today, October 24th at 1:30 p.m. CT (2:30 p.m. ET). The dial-in conference number is: 877-868-1835, passcode 80129148. The replay will be available for one week at 855-859-2056, passcode 80129148.

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 30 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 Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
REVENUES
Oil and gas sales $ 104,004 $ 101,638 $ 296,146 $ 308,116
Midstream services 1,146 671 3,373 1,305
Drilling rig services 4,044 5,348 12,896 11,478
Other operating revenues   1,971     106     4,533     543  
Total revenues   111,165     107,763     316,948     321,442  
 
COSTS AND EXPENSES
Production 25,651 32,564 83,254 93,937
Exploration:
Abandonments and impairments 609 306 2,980 2,292
Seismic and other 177 2,710 3,541 5,445
Midstream services 392 508 1,318 956
Drilling rig services 3,239 5,335 12,704 12,164
Depreciation, depletion and amortization 34,928 37,661 109,863 103,486
Impairment of property and equipment 709 - 89,811 5,711
Accretion of asset retirement obligations 1,049 1,069 3,169 2,628
General and administrative 10,030 5,830 20,401 25,133
Other operating expenses   463     207     1,869     485  
Total costs and expenses   77,247     86,190     328,910     252,237  
Operating income (loss)   33,918     21,573     (11,962 )   69,205  
 
OTHER INCOME (EXPENSE)
 
Interest expense (9,262 ) (9,786 ) (30,106 ) (27,817 )
Gain (loss) on derivatives (8,278 ) (21,901 ) (9,919 ) 9,856
Other 474 (559 ) 2,007 739
       
Total other income (expense)   (17,066 )   (32,246 )   (38,018 )   (17,222 )
 
Income (loss) before income taxes 16,852 (10,673 ) (49,980 ) 51,983
 
Income tax (expense) benefit (5,901 ) 3,497 18,693 (18,558 )
       
NET INCOME (LOSS) $ 10,951   $ (7,176 ) $ (31,287 ) $ 33,425  
 
 
Net income (loss) per common share:
Basic $ 0.90   $ (0.59 ) $ (2.57 ) $ 2.75  
Diluted $ 0.90   $ (0.59 ) $ (2.57 ) $ 2.75  
 
Weighted average common shares outstanding:
Basic   12,165     12,164     12,165     12,164  
Diluted   12,165     12,164     12,165     12,164  
 
 
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands)
   
ASSETS
September 30, December 31,
2013 2012
(Unaudited)
CURRENT ASSETS
Cash and cash equivalents $ 23,209 $ 10,726
Accounts receivable:
Oil and gas sales 37,828 32,371
Joint interest and other, net 10,173 16,767
Affiliates 27,544 353
Inventory 36,986 41,703
Deferred income taxes 10,623 8,560
Fair value of derivatives 2,139 7,495
Prepaids and other   8,219     6,495  
  156,721     124,470  
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method 2,364,117 2,570,803
Pipelines and other midstream facilities 52,693 49,839
Contract drilling equipment 94,260 91,163
Other   20,574     20,245  
2,531,644 2,732,050
Less accumulated depreciation, depletion and amortization   (1,334,165 )   (1,311,692 )
Property and equipment, net   1,197,479     1,420,358  
 
OTHER ASSETS
Debt issue costs, net 8,074 10,259
Fair value of derivatives 1,038 4,236
Investments and other   16,398     15,261  
  25,510     29,756  
 
$ 1,379,710   $ 1,574,584  
 
LIABILITIES AND STOCKHOLDERS' EQUITY
 
CURRENT LIABILITIES
Accounts payable:
Trade $ 67,232 $ 73,026
Oil and gas sales 35,458 32,146
Affiliates 647 164
Accrued liabilities and other   21,961     15,578  
  125,298     120,914  
 
NON-CURRENT LIABILITIES
Long-term debt 672,625 809,585
Deferred income taxes 139,202 155,830
Asset retirement obligations 49,647 51,477
Deferred revenue from volumetric production payment 31,579 37,184
Accrued compensation under non-equity award plans 13,121 20,058
Other   909     920  
  907,083     1,075,054  
 
STOCKHOLDERS' EQUITY
Preferred stock, par value $.10 per share - -
Common stock, par value $.10 per share 1,216 1,216
Additional paid-in capital 152,527 152,527
Retained earnings   193,586     224,873  
Total stockholders' equity   347,329     378,616  
 
$ 1,379,710   $ 1,574,584  
 
 
CLAYTON WILLIAMS ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
       
 
Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 10,951 $ (7,176 ) $ (31,287 ) $ 33,425
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation, depletion and amortization 34,928 37,661 109,863 103,486
Impairment of property and equipment 709 - 89,811 5,711
Exploration costs 609 306 2,980 2,292
(Gain) loss on sales of assets and impairment of inventory, net (1,810 ) 101 (1,527 ) (58 )
Deferred income tax expense (benefit) 5,901 (3,497 ) (18,693 ) 18,558
Non-cash employee compensation 1,204 (2,194 ) (5,897 ) 2,200
Unrealized (gain) loss on derivatives 7,823 20,511 8,555 (14,817 )
Accretion of asset retirement obligations 1,049 1,069 3,169 2,628
Amortization of debt issue costs and original issue discount 507 548 2,281 1,587
Amortization of deferred revenue from volumetric production payment (2,155 ) (2,479 ) (6,639 ) (5,862 )
 
Changes in operating working capital:
Accounts receivable (3,407 ) 1,893 (188 ) 7,150
Accounts payable 7,463 7,055 (4,060 ) (5,772 )
Other   7,223     6,819     5,513     7,355  
Net cash provided by operating activities   70,995     60,617     153,881     157,883  
 
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment (74,916 ) (125,312 ) (208,022 ) (438,482 )
Proceeds from volumetric production payment 297 609 1,034 45,032
Proceeds from sales of assets 2,664 216 197,941 867
Decrease in equipment inventory 230 4,201 5,818 64
Other   (258 )   (181 )   (1,169 )   (195 )
Net cash used in investing activities   (71,983 )   (120,467 )   (4,398 )   (392,714 )
 
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 8,000 70,000 43,000 240,000
Repayments of long-term debt   -     -     (180,000 )   -  
Net cash provided by (used in) financing activities   8,000     70,000     (137,000 )   240,000  
 
 
NET INCREASE IN CASH AND CASH EQUIVALENTS 7,012 10,150 12,483 5,169
 
CASH AND CASH EQUIVALENTS
Beginning of period 16,197 12,544 10,726 17,525
       
End of period $ 23,209   $ 22,694   $ 23,209   $ 22,694  
 
 

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, net (gain) loss on sales of assets and impairment of inventory, and all non-cash items in the Company's statements of operations, including depreciation, depletion and amortization, impairment of property and equipment, accretion of asset retirement obligations, amortization of deferred revenue from volumetric production payment, 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 (loss) to EBITDAX:
       
 
Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
 
Net income (loss) $ 10,951 $ (7,176 ) $ (31,287 ) $ 33,425
Interest expense 9,262 9,786 30,106 27,817
Income tax expense (benefit) 5,901 (3,497 ) (18,693 ) 18,558
Exploration:
Abandonments and impairments 609 306 2,980 2,292
Seismic and other 177 2,710 3,541 5,445
Net (gain) loss on sales of assets and impairment of inventory (1,810 ) 101 (1,527 ) (58 )
Depreciation, depletion and amortization 34,928 37,661 109,863 103,486
Impairment of property and equipment 709 - 89,811 5,711
Accretion of asset retirement obligations 1,049 1,069 3,169 2,628
Amortization of deferred revenue from volumetric production payment (2,155 ) (2,479 ) (6,639 ) (5,862 )
Non-cash employee compensation 1,204 (2,194 ) (5,897 ) 2,200
Unrealized (gain) loss on derivatives   7,823     20,511     8,555     (14,817 )
EBITDAX (a) $ 68,648   $ 56,798   $ 183,982   $ 180,825  

 
 
(a) In April 2013, the Company sold 95% of its interests in certain properties in Andrews County, Texas. Revenue, net of direct expenses, associated with the sold properties for the three months ended September 30, 2012 were $10.4 million and the nine months ended September 30, 2013 and 2012 were $8.7 million and $38.8 million, respectively.
       
 
CLAYTON WILLIAMS ENERGY, INC.
SUMMARY PRODUCTION AND PRICE DATA
(Unaudited)
 
 
Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
 
Oil and Gas Production Data:
Oil (MBbls) 890 993 2,695 2,889
Gas (MMcf) 1,527 2,010 4,753 6,154
Natural gas liquids (MBbls) 125 115 399 304
Total (MBOE) 1,270 1,443 3,886 4,219
 

Average Realized Prices (a) (b):
Oil ($/Bbl) $ 103.75   $ 89.48   $ 96.16   $ 92.62  
Gas ($/Mcf) $ 3.49   $ 3.29   $ 3.56   $ 3.46  
Natural gas liquids ($/Bbl) $ 33.47   $ 31.37   $ 32.44   $ 40.05  
 

Loss on Settled Derivative Contracts (b):
($ in thousands, except per unit)
Oil:
Net realized loss $ (367 ) $ (1,390 ) $ (981 ) $ (4,961 )
Per unit produced ($/Bbl) $ (0.41 ) $ (1.40 ) $ (0.36 ) $ (1.72 )
 
Gas:
Net realized loss $ (88 ) $ - $ (383 ) $ -
Per unit produced ($/Mcf) $ (0.06 ) $ - $ (0.08 ) $ -
 
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin 1,934 2,018 1,886 1,575
Other (c) 3,476 5,247 3,983 5,473
Austin Chalk/ Eagle Ford Shale 3,889 3,199 3,708 3,115
Other   375     329     295     378  
Total   9,674     10,793     9,872     10,541  
 
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin 1,695 1,449 1,582 780
Other (c) (d) 7,569 12,246 8,229 12,797
Austin Chalk/ Eagle Ford Shale 2,051 1,793 2,113 1,997
Other   5,283     6,360     5,486     6,881  
Total   16,598     21,848     17,410     22,455  
 
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin 348 257 299 117
Other (c) (d) 718 711 905 687
Austin Chalk/ Eagle Ford Shale 274 232 240 241
Other   19     50     18     63  
Total   1,359     1,250     1,462     1,108  
 
Oil and Gas Costs ($/BOE Produced):
Production costs $ 20.20 $ 22.57 $ 21.42 $ 22.27
Production costs (excluding production taxes) $ 15.98 $ 18.99 $ 17.57 $ 18.55
Oil and gas depletion $ 24.91 $ 24.36 $ 25.55 $ 23.16
 
General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation $ 8,826 $ 8,024 $ 26,298 $ 22,933
Non-cash employee compensation (e)   1,204     (2,194 )   (5,897 )   2,200  
Total $ 10,030   $ 5,830   $ 20,401   $ 25,133  
   
(a) Oil and gas sales for 2013 includes $2.2 million for the three months ended September 30, 2013, $2.5 million for the three months ended September 30, 2012, $6.6 million for the nine months ended September 30, 2013 and $5.9 million for the nine months ended September 30, 2012 of amortized deferred revenue attributable to a volumetric production payment ("VPP") transaction effective March 1, 2012. The calculation of average realized sales prices excludes production of 28,793 barrels of oil and 8,550 Mcf of gas for the three months ended September 30, 2013, 32,788 barrels of oil and 14,826 Mcf of gas for the three months ended September 30, 2012, 88,897 barrels of oil and 23,589 Mcf of gas for the nine months ended September 30, 2013 and 77,755 barrels of oil and 32,000 Mcf of gas for the nine months ended September 30, 2012 associated with the VPP.
 
(b) 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 2013 or 2012 derivative contracts as cash flow hedges. This means that the Company's derivatives for 2013 and 2012 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.
 
(c) In April 2013, the Company sold 95% of its interest in certain properties in Andrews County, Texas. Following is a recap of the average daily production related to the sold interests for periods prior to April 1, 2013.
     
Three Months Ended Nine Months Ended
September 30, September 30,
2012 2013 2012
Average daily production:
Oil (Bbls) 1,707 538 1,974
Natural gas (Mcf) 1,739 597 1,595
NGL (Bbls) 391 117 394
Total (Boe) 2,388 755 2,634
(d)   Prior to 2013, certain purchasers of the Company's casinghead gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, the Company began separating these products, when possible. Had these incremental NGL volumes been reported separately during the three months and nine months ended September 30, 2012, the Company estimates that its reported natural gas volumes would have decreased by 2,200 Mcf/day and that its reported NGL volumes would have increased by 600 Boe/day during each of the 2012 periods.
 
(e) Non-cash employee compensation relates to the Company's non-equity award plans.
 
 

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 September 30, 2013.
  Oil   Gas
Swaps: Bbls   Price MMBtu (a)   Price
Production Period:
4th Quarter 2013 300,000 $ 104.60 330,000 $ 3.34

2014
1,600,000 $ 97.30 - $ -
1,900,000 330,000
 
   
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

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