Clayton Williams Energy Announces 2015 Financial Results and Year-End Reserves

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 March 9, 2016 - 9:25 PM EST
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Clayton Williams Energy Announces 2015 Financial Results and Year-End Reserves

Clayton Williams Energy, Inc. (the “Company”) (NYSE: CWEI) today reported its financial results for the quarter and year ended December 31, 2015.

Highlights

Fiscal 2015 Results

  • Oil and Gas Production of 15.8 MBOE/d
  • Adjusted Net Loss1 (non-GAAP) of $70.4 million
  • EBITDAX2 (non-GAAP) of $112.1 million

Year-End 2015 Reserves

  • Total Proved Reserves of 46.6 MMBOE
  • 61% of 2015 Production Replaced by Reserve Additions
  • 83% Oil and NGL and 78% Proved Developed

Recent Financing Transactions

  • New $350 million five-year 2nd lien term loan, fully funded at closing
  • Proceeds to repay outstanding balance on revolver
  • Reduces 1st lein bank facility to $100 million commitment
  • Provides a dedicated source of liquidity
  • Significantly eases financial covenants for three years

Financial Results for Fiscal Year 2015

The Company reported a net loss for fiscal 2015 of $98.2 million, or $8.07 per share, as compared to net income of $43.9 million, or $3.61 per share, for fiscal 2014. Adjusted net loss1 (non-GAAP) for 2015 was $70.4 million, or $5.78 per share, as compared to adjusted net income1 (non-GAAP) of $56.4 million, or $4.63 per share, for 2014. Cash flow from operations for 2015 was $52.2 million as compared to $258.1 million for 2014. EBITDAX2 (non-GAAP) for 2015 was $112.1 million as compared to $299.3 million for 2014. The 2015 and 2014 periods included non-cash, pre-tax charges totaling $37.9 million and $12 million, respectively, to write down the carrying value of certain proved properties to their estimated fair values and $4 million in 2015 to write down certain drilling rigs and related equipment to their estimated fair values.

The key factors affecting the comparability of the two years were:

  • The ongoing downturn in commodity prices continues to have a significant impact on our business and results of operations, having reduced our weighted average realized oil and gas prices by approximately 50% in fiscal 2015. As a result, we conducted limited drilling and completion activities in 2015 and expect to reduce capital spending further in 2016 pending an appreciable improvement in commodity prices.
  • Oil and gas sales, excluding amortized deferred revenues, decreased $197.7 million in 2015 compared to 2014. Price variances accounted for a $200.7 million decrease and production variances accounted for a $3 million increase. Average realized oil prices were $44.76 per barrel in 2015 versus $86.81 per barrel in 2014, average realized gas prices were $2.52 per Mcf in 2015 versus $4.35 per Mcf in 2014, and average realized natural gas liquids (“NGL”) prices were $13.07 per barrel in 2015 versus $32.17 per barrel in 2014. Oil and gas sales in 2015 includes $4.5 million of amortized deferred revenue compared to $7.7 million in 2014 attributable to a volumetric production payment (“VPP”). In August 2015, the Company terminated the VPP covering 277 MBOE of oil and gas production from August 2015 through December 2019 for $13.7 million. Reported production and related average realized sales prices exclude volumes associated with the VPP.
  • Oil, gas and NGL production per barrel of oil equivalent (“BOE”) remained unchanged in 2015 as compared to 2014, with oil production increasing 2% to 11,663 barrels per day, gas production decreasing 2% to 15,885 Mcf per day, and NGL production decreasing 6% to 1,507 barrels per day. Oil and NGL production accounted for approximately 83% of the Company’s total BOE production in 2015 and 2014. See accompanying tables for additional information about the Company’s oil and gas production.
  • Production costs in 2015 were $87.6 million versus $105.3 million in 2014 due to reductions in production taxes associated with lower oil and gas sales and reduced costs of field services. Production costs on a BOE basis, excluding production taxes, decreased 9% to $13.23 per BOE in 2015 versus $14.57 per BOE in 2014.
  • Gain on derivatives for 2015 was $12.5 million (including a $12.5 million gain on settled contracts) versus a gain on derivatives in 2014 of $4.8 million (including a $7.1 million gain on settled contracts). See accompanying tables for additional information about the Company’s accounting for derivatives.
  • Lower commodity prices also negatively impacted the Company’s results of operations due to asset impairments. The Company recorded impairments of property and equipment during 2015 of $41.9 million of which $37.9 million related primarily to impairments of proved non-core properties in the Permian Basin and Oklahoma and $4 million related to the impairment of certain drilling rigs and related equipment to reduce the carrying value to their estimated fair values. By comparison, the Company recorded an impairment of proved properties in 2014 of $12 million related to certain non-core properties located in the Permian Basin and North Dakota to reduce the carrying value of these properties to their estimated fair values. Also in 2015, the Company recorded charges of $10.4 million to other operating expenses for mark-to-market valuations of its tubular inventory and charges to other expense of $2.6 million to reduce the carrying value of its investment in Dalea Investment Group, LLC (“Dalea”) to its estimated fair value.
  • Exploration expense related to abandonment and impairment costs during 2015 were $6.5 million versus $20.6 million in 2014. The expense for 2015 includes a charge of $3.1 million for the abandonment of exploratory wells in South Louisiana and Oklahoma and $1.7 million related to unproved leasehold impairments in East Texas. By comparison, the expense for 2014 includes a charge of $8.6 million related to unproved leasehold impairments in California and $2.4 million for the abandonment of an exploratory well in South Louisiana.
  • General and administrative (“G&A”) expenses for 2015 were $22.8 million versus $34.5 million for 2014. Changes in compensation expense attributable to the Company’s APO reward plans accounted for a net decrease of $4.6 million. The remaining decrease was largely attributable to salary and personnel reductions.

Financial Results for the Fourth Quarter of 2015

The Company reported a net loss for the fourth quarter of 2015 (“4Q15”) of $47.2 million, or $3.88 per share, as compared to a net loss of $4.3 million, or $0.35 per share, for the fourth quarter of 2014 (“4Q14”). Adjusted net loss1 (non-GAAP) for 4Q15 was $22.1 million, or $1.82 per share, as compared to adjusted net income1 (non-GAAP) of $4 million, or $0.33 per share, for 4Q14. Cash flow from operations for 4Q15 was $(2.8) million as compared to $46.4 million for 4Q14. EBITDAX2 (non-GAAP) for 4Q15 was $20.7 million as compared to $62.8 million for 4Q14.

The key factors affecting the comparability of financial results for 4Q15 versus 4Q14 were:

  • Oil and gas sales for 4Q15, excluding amortized deferred revenues, decreased $46.4 million compared to 4Q14. Price variances accounted for a $32.9 million decrease and production variances accounted for a $13.5 million decrease. Average realized oil prices were $36.91 per barrel in 4Q15 versus $68.04 per barrel in 4Q14, average realized gas prices were $2.09 per Mcf in 4Q15 versus $3.86 per Mcf in 4Q14, and average realized NGL prices were $13.00 per barrel in 4Q15 versus $25.90 per barrel in 4Q14. Oil and gas sales in 4Q15 includes $0.3 million of amortized deferred revenue compared to $1.9 million in 4Q14 attributable to a terminated VPP. Reported production and related average realized sales prices exclude volumes associated with the VPP.
  • Oil, gas and NGL production per BOE decreased 16% in 4Q15 as compared to 4Q14, with oil production decreasing 16% to 10,076 barrels per day, gas production decreasing 17% to 14,565 Mcf per day, and NGL production decreasing 13% to 1,435 barrels per day. Oil and NGL production accounted for approximately 83% of the Company’s total BOE production in 4Q15 versus 82% in 4Q14. See accompanying tables for additional information about the Company’s oil and gas production.
  • Production costs in 4Q15 were $20.4 million versus $28.3 million in 4Q14 due primarily to lower oilfield service costs and reductions in production taxes associated with a decrease in commodity prices. Production costs on a BOE basis, excluding production taxes, decreased 10% to $14.07 per BOE in 4Q15 versus $15.71 per BOE in 4Q14.
  • Gain on derivatives for 4Q15 was $2.1 million (including a $7.9 million gain on settled contracts) versus a gain on derivatives in 4Q14 of $8.5 million (including an $11.9 million gain on settled contracts). See accompanying tables for additional information about the Company’s accounting for derivatives.
  • Lower commodity prices also negatively impacted the Company’s results of operations due to asset impairments. The Company recorded an impairment of proved properties in 4Q15 of $36.3 million, of which $32.3 million related primarily to impairments of proved non-core properties in the Permian Basin and Oklahoma and $4 million related to the impairment of certain drilling rigs and related equipment to reduce the carrying value to their estimated fair values. By comparison, the Company recorded an impairment of proved properties in 4Q14 of $8.6 million related to certain non-core properties located in the Permian Basin and North Dakota to reduce the carrying value of these properties to their estimated fair values. Also in 4Q15, the Company recorded a charge of $3 million to other operating expenses for a mark-to-market valuation of its tubular inventory and a charge to other expense of $1.2 million to reduce the carrying value of its investment in Dalea to its estimated fair value.
  • Exploration expense related to abandonment and impairment costs during 4Q15 were $1.5 million versus $11.9 million in 4Q14. The expense for 4Q15 includes a charge of $0.9 million related to the abandonment of exploratory wells in Oklahoma. The expense for 4Q14 includes a charge of $8.6 million related to unproved leasehold impairments in California and $2.4 million for the abandonment of an exploratory well in South Louisiana.
  • G&A expenses for 4Q15 were a $2.3 million credit versus $0.5 million expense for 4Q14. Most of the $2.8 million decrease in G&A expense was attributable to salary and personnel reductions offset by a net increase of $1.2 million related to changes in compensation expense attributable to the Company's APO reward plans.

1 See “Computation of Adjusted Net Income (Loss) (non-GAAP)” below for an explanation of how the Company calculates and uses adjusted net income (loss) (non-GAAP) and for a reconciliation of net income (loss) (GAAP) to adjusted net income (loss) (non-GAAP).

2 See “Computation of EBITDAX (non-GAAP)” below for an explanation of how the Company calculates and uses EBITDAX (non-GAAP) and for a reconciliation of net income (loss) (GAAP) to EBITDAX (non-GAAP).

Balance Sheet and Liquidity

As of December 31, 2015, total long-term debt was $749.8 million, consisting of $150 million of secured debt under a revolving credit facility and $599.8 million of 7.75% Senior Notes due 2019. The borrowing base established by the banks under the credit facility and the aggregate lender commitment was $450 million at December 31, 2015. The Company had $298.1 million of availability under the facility after allowing for outstanding letters of credit of $1.9 million. Liquidity, consisting of cash plus funds available on the bank credit facility, totaled $305.9 million.

As previously announced, the Company signed an agreement with funds managed by Ares Management, L.P. (NYSE: ARES) to issue a new $350 million secured 2nd lien term loan and warrants to purchase 2.25 million shares of the Company’s common stock at a price of $22 per share. Gross proceeds from the transaction, consisting of $333.2 million allocable to loans and $16.8 million allocable to warrants, will be used to fully repay the Company’s revolving credit facility and provide dedicated liquidity to fund the Company’s operations and future development. As part of the agreement, Ares will have the right to appoint two members to the Company’s Board of Directors. Closing of this transaction is expected to occur on or before March 31, 2016.

Concurrently, the Company amended its 1st lien secured revolving credit facility to reduce lender commitments to $100 million and ease financial covenants, among other changes.

At December 31, 2015, after giving effect to these transactions (excluding transaction costs), the Company’s pro forma total long-term debt, net of debt discount, would be $933 million, and its pro forma liquidity would remain at $305.9 million, consisting of $207.8 million cash and $98.1 million of availability on the revolving credit facility.

Reserves

The Company reported that its total estimated proved oil and gas reserves as of December 31, 2015 was 46.6 million barrels of oil equivalent (“MMBOE”), consisting of 33.1 million barrels of oil, 5.5 million barrels of NGL, and 48.1 Bcf of natural gas. On a BOE basis, oil and NGL comprised 83% of total proved reserves at year-end 2015 and 2014. Proved developed reserves at year-end 2015 were 36.3 MMBOE, or 78% of total proved reserves, versus 42.2 MMBOE, or 56% of total proved reserves, at year-end 2014. 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”), totaled $0.4 billion at year-end 2015 versus $1.4 billion at year-end 2014. See accompanying tables for a reconciliation of PV-10 (a non-GAAP financial measure) to standardized measure of discounted future net cash flows (a GAAP financial measure).

The following table summarizes the changes in total proved reserves during 2015 on an MMBOE basis.

     
MMBOE
Total proved reserves, December 31, 2014 75.4
Extensions and discoveries 3.5
Revisions (26.1 )
Sales of reserves (0.4 )
Production (5.8 )
Total proved reserves, December 31, 2015 46.6  
 

The Company replaced 61% of its 2015 oil and gas production through extensions and discoveries. Most of the 3.5 MMBOE of reserve additions in 2015 are attributable to the Company’s Delaware Basin program. Oil and NGL accounted for 86.8% of the 2015 reserve additions.

The 26.1 MMBOE of net downward revisions in proved reserves resulted from a combination of (1) reclassifications of 9.5 MMBOE of proved undeveloped reserves to probable reserves due solely to the SEC 5-year development rule, (2) net upward revisions of 12 MMBOE related to performance in the Company’s Delaware Basin reserves, and (3) downward revisions of 28.6 MMBOE related to the effects of lower commodity prices on the estimated quantities of proved reserves.

SEC guidelines require that the Company’s estimated proved reserves and related PV-10 be determined using benchmark commodity prices equal to the unweighted arithmetic average of the first-day-of-the-month prices for the 12-month period prior to the effective date of each reserve estimate. The benchmark averages for 2015 were $50.28 per barrel of oil and $2.58 per MMBtu of natural gas, as compared to $94.99 per barrel of oil and $4.35 per MMBtu of natural gas for 2014. These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to the Company’s properties, resulting in an average adjusted price over the remaining life of the proved reserves of $45.75 per barrel of oil, $15.84 per barrel of NGL and $2.52 per Mcf of natural gas for year-end 2015, as compared to $90.48 per barrel of oil, $31.54 per barrel of NGL and $4.27 per Mcf of natural gas for year-end 2014.

Scheduled Conference Call

The Company will host a conference call to discuss these results, the previously announced term loan transaction and other forward-looking items Thursday, March 10th at 10:30 a.m. CT (11:30 a.m. ET).

A live webcast for investors and analysts will be available on the Company’s website at www.claytonwilliams.com under the “Investors” section. The webcast will be archived on the site for 30 days following the call.

Participants should call (877) 868-1835 and indicate 59366986 as the conference passcode. A replay will be available from 4:30 p.m. CT (5:30 p.m. ET) on March 10th until March 17th. To listen to the replay dial (855) 859-2056 and enter passcode 59366986.

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
December 31,

Year Ended
December 31,

2015 2014 2015 2014
REVENUES
Oil and gas sales $ 38,946 $ 86,961 $ 217,485 $ 418,330
Midstream services 1,408 1,369 6,122 6,705
Drilling rig services — 5,590 23 28,028
Other operating revenues   64     753     8,742     15,393  
Total revenues   40,418     94,673     232,372     468,456  
 
COSTS AND EXPENSES
Production 20,369 28,290 87,557 105,296
Exploration:
Abandonments and impairments 1,504 11,895 6,509 20,647
Seismic and other 108 359 1,318 2,314
Midstream services 349 564 1,688 2,212
Drilling rig services 820 4,264 5,238 19,232
Depreciation, depletion and amortization 40,626 42,114 162,262 154,356
Impairment of property and equipment 36,297 8,621 41,917 12,027
Accretion of asset retirement obligations 1,009 939 3,945 3,662
General and administrative (2,314 ) 544 22,788 34,524
Other operating expenses   4,106     327     12,585     2,547  
Total costs and expenses   102,874     97,917     345,807     356,817  
Operating income (loss)   (62,456 )   (3,244 )   (113,435 )   111,639  
 
OTHER INCOME (EXPENSE)
Interest expense (13,971 ) (12,932 ) (54,422 ) (50,907 )
Gain on derivatives 2,088 8,504 12,519 4,789
Other   (304 )   773     2,003     3,047  
Total other income (expense)   (12,187 )   (3,655 )   (39,900 )   (43,071 )
Income (loss) before income taxes (74,643 ) (6,899 ) (153,335 ) 68,568
Income tax (expense) benefit   27,434     2,632     55,139     (24,687 )
NET INCOME (LOSS) $ (47,209 ) $ (4,267 ) $ (98,196 ) $ 43,881  
 
Net income (loss) per common share:
Basic $ (3.88 ) $ (0.35 ) $ (8.07 ) $ 3.61  
Diluted $ (3.88 ) $ (0.35 ) $ (8.07 ) $ 3.61  
Weighted average common shares outstanding:
Basic   12,170     12,170     12,170     12,167  
Diluted   12,170     12,170     12,170     12,167  
 
 
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands)
 
ASSETS
      December 31,     December 31,
2015 2014
CURRENT ASSETS (Unaudited)
 
Cash and cash equivalents $ 7,780 $ 28,016
Accounts receivable:
Oil and gas sales 16,660 36,526
Joint interest and other, net 3,661 14,550
Affiliates 260 322
Inventory 31,455 42,087
Deferred income taxes 6,526 6,911
Prepaids and other   2,463     4,208  
  68,805     132,620  
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method 2,585,502 2,684,913
Pipelines and other midstream facilities 60,120 59,542
Contract drilling equipment 123,876 122,751
Other   19,371     20,915  
2,788,869 2,888,121
Less accumulated depreciation, depletion and amortization   (1,587,585 )   (1,539,237 )
Property and equipment, net   1,201,284     1,348,884  
 
OTHER ASSETS
Debt issue costs, net 9,629 12,712
Investments and other   15,051     16,669  
  24,680     29,381  
$ 1,294,769   $ 1,510,885  
 
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade $ 29,197 $ 93,650
Oil and gas sales 19,490 41,328
Affiliates 383 717
Accrued liabilities and other   16,669     20,658  
  65,739     156,353  
NON-CURRENT LIABILITIES
Long-term debt 749,759 704,696
Deferred income taxes 108,996 164,599
Asset retirement obligations 48,728 45,697
Deferred revenue from volumetric production payment 5,470 23,129
Accrued compensation under non-equity award plans 16,254 17,866
Other   225     751  
  929,432     956,738  
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share — —
Common stock, par value $.10 per share 1,216 1,216
Additional paid-in capital 152,686 152,686
Retained earnings   145,696     243,892  
Total stockholders' equity   299,598     397,794  
$ 1,294,769   $ 1,510,885  
 
 
CLAYTON WILLIAMS ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
     

Three Months Ended
December 31,

   

Year Ended
December 31,

2015     2014 2015     2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (47,209 ) $ (4,267 ) $ (98,196 ) $ 43,881
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
Depreciation, depletion and amortization 40,626 42,114 162,262 154,356
Impairment of property and equipment 36,297 8,621 41,917 12,027
Abandonments and impairments 1,504 11,895 6,509 20,647
(Gain) loss on sales of assets and impairment of inventory, net 3,853 (69 ) 3,018 (9,138 )
Deferred income tax expense (benefit) (27,513 ) (2,859 ) (55,218 ) 24,460
Non-cash employee compensation (7,079 ) (8,582 ) (2,674 ) 1,397
Gain on derivatives (2,088 ) (8,504 ) (12,519 ) (4,789 )
Cash settlements of derivatives 7,934 11,876 12,519 7,099
Accretion of asset retirement obligations 1,009 939 3,945 3,662
Amortization of debt issue costs and original issue discount 1,005 701 3,246 3,030
Amortization of deferred revenue from volumetric production payment (1,641 ) (1,853 ) (6,822 ) (7,708 )
Other 873 — 1,542 —
Changes in operating working capital:
Accounts receivable 5,510 6,689 30,817 5,255
Accounts payable (3,803 ) 1,022 (35,860 ) 4,561
Other   (12,115 )   (11,347 )   (2,327 )   (619 )
Net cash provided by (used in) operating activities   (2,837 )   46,376     52,159     258,121  
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment (24,147 ) (110,505 ) (179,827 ) (422,473 )
Proceeds from volumetric production payment 1,356 257 2,866 1,067
Termination of volumetric production payment — — (13,703 ) —
Proceeds from sales of assets 23,976 (105 ) 71,460 104,529
(Increase) decrease in equipment inventory 603 (11,541 ) 1,733 (1,886 )
Other   87     91     76     (234 )
Net cash provided by (used in) investing activities   1,875     (121,803 )   (117,395 )   (318,997 )
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt — 72,617 45,000 102,139
Repayments of long-term debt — — — (40,000 )
Proceeds from exercise of stock options   —     —     —     130  
Net cash provided by financing activities   —     72,617     45,000     62,269  
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (962 ) (2,810 ) (20,236 ) 1,393
CASH AND CASH EQUIVALENTS
Beginning of period   8,742     30,826     28,016     26,623  
End of period $ 7,780   $ 28,016   $ 7,780   $ 28,016  
 
 

CLAYTON WILLIAMS ENERGY, INC.

COMPUTATION OF ADJUSTED NET INCOME (LOSS) (NON-GAAP)
(Unaudited)

(In thousands, except per share)

 
Adjusted net income (loss) 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 a tool for operating trends analysis and industry comparisons. Adjusted net income (loss) is not an alternative to net income (loss) presented in conformity with GAAP.
                 
The Company defines adjusted net income (loss) as net income (loss) before changes in fair value of derivatives, abandonments and impairments, impairments of property and equipment, net (gain) loss on sales of assets and impairment of inventory, amortization of deferred revenue from volumetric production payment, certain non-cash and unusual items and the impact on taxes of the adjustments for each period presented.
 
The following table is a reconciliation of net income (loss) (GAAP) to adjusted net income (loss) (non-GAAP):
 
Three Months Ended Year Ended
December 31, December 31,
2015 2014 2015 2014
Net income (loss) $ (47,209 ) $ (4,267 ) $ (98,196 ) $ 43,881
Gain on derivatives (2,088 ) (8,504 ) (12,519 ) (4,789 )
Cash settlements of derivatives 7,934 11,876 12,519 7,099
Abandonments and impairments 1,504 11,895 6,509 20,647
Impairment of property and equipment 36,297 8,621 41,917 12,027
Net (gain) loss on sales of assets and impairment of inventory 3,853 (69 ) 3,018 (9,138 )
Amortization of deferred revenue from volumetric production payment (1,641 ) (1,853 ) (6,822 ) (7,708 )
Non-cash employee compensation (7,079 ) (8,582 ) (2,674 ) 1,397
Other 873 — 1,542 —
Tax impact (a)   (14,592 )   (5,113 )   (15,656 )   (7,033 )
Adjusted net income (loss) $ (22,148 ) $ 4,004   $ (70,362 ) $ 56,383  
 
Adjusted earnings per share:
Diluted $ (1.82 ) $ 0.33 $ (5.78 ) $ 4.63
 
Weighted average common shares outstanding:
Diluted 12,170 12,170 12,170 12,167
 
Effective tax rates 36.8 % 38.2 % 36.0 % 36.0 %
_______

(a) The tax impact is computed utilizing the Company’s effective tax rate on the adjustments for each period presented.

 
 
CLAYTON WILLIAMS ENERGY, INC.
COMPUTATION OF EBITDAX (NON-GAAP)
(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. 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 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, changes in fair value of derivatives and certain non-cash and unusual items.
 
The following table reconciles net income (loss) to EBITDAX:
 
Three Months Ended Year Ended
December 31, December 31,
2015 2014 2015 2014
Net income (loss) $ (47,209 ) $ (4,267 ) $ (98,196 ) $ 43,881
Interest expense 13,971 12,932 54,422 50,907
Income tax expense (benefit) (27,434 ) (2,632 ) (55,139 ) 24,687
Exploration:
Abandonments and impairments 1,504 11,895 6,509 20,647
Seismic and other 108 359 1,318 2,314
Net (gain) loss on sales of assets and impairment of inventory 3,853 (69 ) 3,018 (9,138 )
Depreciation, depletion and amortization 40,626 42,114 162,262 154,356
Impairment of property and equipment 36,297 8,621 41,917 12,027
Accretion of asset retirement obligations 1,009 939 3,945 3,662
Amortization of deferred revenue from volumetric production payment (1,641 ) (1,853 ) (6,822 ) (7,708 )
Non-cash employee compensation (7,079 ) (8,582 ) (2,674 ) 1,397
Gain on derivatives (2,088 ) (8,504 ) (12,519 ) (4,789 )
Cash settlements of derivatives 7,934 11,876 12,519 7,099
Other   873     —     1,542     —  
EBITDAX (a) $ 20,724   $ 62,829   $ 112,102   $ 299,342  
 
The following table reconciles net cash provided by (used in) operating activities to EBITDAX:
 
Net cash provided by (used in) operating activities $ (2,837 ) $ 46,376 $ 52,159 $ 258,121
Changes in operating working capital 10,408 3,636 7,370 (9,197 )
Seismic and other 108 359 1,318 2,314
Current income tax provision 79 227 79 227
Cash interest expense   12,966     12,231     51,176     47,877  
______ $ 20,724   $ 62,829   $ 112,102   $ 299,342  

(a) In March 2014, the company sold interests in certain non-core Austin Chalk/Eagle Ford assets. Revenue, net of direct expenses, associated with the sold properties was $2.5 million for the year ended December 31, 2014.

 
         
CLAYTON WILLIAMS ENERGY, INC.
SUMMARY PRODUCTION AND PRICE DATA
(Unaudited)
 

Three Months Ended
December 31,

Year Ended
December 31,

2015     2014 2015     2014
Oil and Gas Production Data:
Oil (MBbls) 927 1,101 4,257 4,194
Gas (MMcf) 1,340 1,608 5,798 5,901
Natural gas liquids (MBbls) 132 151 550 585
Total (MBOE) 1,282 1,520 5,773 5,763
Total (BOE/d) 13,938 16,521 15,818 15,788
Average Realized Prices (a) (b):
Oil ($/Bbl) $ 36.91 $ 68.04 $ 44.76 $ 86.81
Gas ($/Mcf) $ 2.09 $ 3.86 $ 2.52 $ 4.35
Natural gas liquids ($/Bbl) $ 13.00 $ 25.90 $ 13.07 $ 32.17
Gain on Settled Derivative Contracts (b):
($ in thousands, except per unit)
Oil:
Cash settlements received $ 7,934 $ 11,876 $ 12,519 $ 7,099
Per unit produced ($/Bbl) $ 8.56 $ 10.79 $ 2.94 $ 1.69
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin 3,026 2,730 3,426 3,224
Other 2,896 3,162 3,083 3,286
Austin Chalk (c) 1,663 1,915 1,828 2,033
Eagle Ford Shale (c) 2,347 3,785 3,037 2,529
Other   144   375   289   418
Total   10,076   11,967   11,663   11,490
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin 3,206 2,615 3,078 2,671
Other 6,310 7,209 6,570 6,932
Austin Chalk (c) 1,687 1,706 1,725 1,766
Eagle Ford Shale (c) 444 766 516 464
Other   2,918   5,182   3,996   4,334
Total   14,565   17,478   15,885   16,167
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin 386 366 409 449
Other 752 846 784 820
Austin Chalk (c) 162 203 168 189
Eagle Ford Shale (c) 113 169 123 111
Other   22   57   23   34
Total   1,435   1,641   1,507   1,603
BOE:
Permian Basin Area:
Delaware Basin 3,946 3,532 4,348 4,118
Other 4,700 5,209 4,962 5,261
Austin Chalk (c) 2,106 2,402 2,284 2,517
Eagle Ford Shale (c) 2,534 4,082 3,246 2,717
Other   652   1,296   978   1,175
Total   13,938   16,521   15,818   15,788
 
Oil and Gas Costs ($/BOE Produced):
Production costs $ 15.89 $ 18.61 $ 15.17 $ 18.27
Production costs (excluding production taxes) $ 14.07 $ 15.71 $ 13.23 $ 14.57
Oil and gas depletion $ 28.83 $ 25.93 $ 25.54 $ 24.73

______

(a)   Oil and gas sales includes $0.3 million for the three months ended December 31, 2015, $1.9 million for the three months ended December 31, 2014, $4.5 million for the year ended December 31, 2015 and $7.7 million for the year ended December 31, 2014 of amortized deferred revenue attributable to a volumetric production payment (“VPP”) transaction effective March 1, 2012. In August 2015, the Company terminated the VPP covering 277 MBOE of oil and gas production from August 2015 through December 2019 for $13.7 million. The calculation of average realized sales prices excludes production of 24,469 barrels of oil and 11,784 Mcf of gas for the three months ended December 31, 2014, 53,026 barrels of oil and 35,735 Mcf of gas for the year ended December 31, 2015 and 102,011 barrels of oil and 45,392 Mcf of gas for the year ended December 31, 2014 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 2015 or 2014 derivative contracts as cash flow hedges. This means that the Company’s derivatives for 2015 and 2014 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) Average daily production related to interests in producing properties sold by the Company effective March 2014 totaled 98 BOE/day for the year ended December 31, 2014.
 

CLAYTON WILLIAMS ENERGY, INC.
SUMMARY OF EXPLORATION AND DEVELOPMENT EXPENDITURES
(Unaudited)

The following table summarizes, by area, the Company’s planned expenditures for exploration and development activities during 2016, as compared to actual expenditures in 2015.

             

Actual
Expenditures
Year Ended
December 31, 2015

Planned
Expenditures
Year Ending
December 31, 2016

2016
Percentage of Total
Planned
Expenditures

(In thousands)
Drilling and completion
Permian Basin Area:
Delaware Basin $ 36,900 $ 40,800

62

%
Other 12,900 — — %
Austin Chalk/Eagle Ford Shale 37,300 — — %
Other   7,500  

2,000

3

%
94,600

42,800

65 %
Leasing and seismic   29,900   22,900 35 %
Exploration and development $ 124,500 $

65,700

100 %
 

CLAYTON WILLIAMS ENERGY, INC.
SUMMARY OF OPEN COMMODITY DERIVATIVES
(Unaudited)

The following summarizes information concerning the Company’s net positions in open commodity derivatives, all of which were entered into in January 2016, applicable to periods subsequent to December 31, 2015. In connection with the swap agreement entered into in January 2016, the Company granted the counterparty the option to extend the agreement to cover an additional 739 MBbls of oil production during the second half of 2016 at the same price of $40.25 per barrel. The option to extend expires on June 30, 2016. Settlement prices of commodity derivatives are based on NYMEX futures prices.

     

Current Swaps:

 
Oil
MBbls     Price
Production Period:
1st Quarter 2016 421 $ 40.25
2nd Quarter 2016 394 $ 40.25
815
     

Swaps Subject to Optional Extension:

 
Oil
MBbls     Price
Production Period:
3rd Quarter 2016 378 $ 40.25
4th Quarter 2016 361 $ 40.25
739
 

CLAYTON WILLIAMS ENERGY, INC.
PROVED RESERVES
(Unaudited)

The following table sets forth the Company’s estimated quantities of proved reserves as of December 31, 2015 and 2014, all of which are located in the United States.

     
Proved Reserves
Reserve Category

Oil
(MBbls)

   

Natural Gas
Liquids
(MBbls)

   

Natural
Gas
(MMcf)

   

Total Oil
Equivalents (a)
(MBOE)

 
December 31, 2015:
Developed 25,349 4,266 39,987 36,280
Undeveloped 7,727 1,202 8,160 10,289
Total Proved 33,076 5,468 48,147 46,569
December 31, 2014:
Developed 29,059 4,668 51,072 42,239
Undeveloped 24,808 4,299 24,503 33,191
Total Proved 53,867 8,967 75,575 75,430
______

(a) Natural gas reserves have been converted to oil equivalents at the rate of six Mcf to one barrel of oil.

PV-10 totaled $0.4 billion at December 31, 2015 versus $1.4 billion at December 31, 2014. Commodity prices used at December 31, 2015 and 2014 were based on the 12-month weighted average of the first-day-of-the-month prices from January through December of the respective years and averaged $50.28 per barrel of oil and $2.58 per MMBtu of natural gas for 2015 and $94.99 per barrel of oil and $4.35 per MMBtu for 2014. These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to the Company’s properties, resulting in average adjusted commodity prices of $45.75 per barrel of oil, $15.84 per barrel of NGL and $2.52 per Mcf of natural gas for 2015 and $90.48 per barrel of oil, $31.54 per barrel of NGL and $4.27 per Mcf of natural gas for 2014.

PV-10 is a non-GAAP financial measure that the Company believes is useful as a supplemental disclosure to the standardized measure of discounted future net cash flows, a GAAP financial measure. While the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each entity, PV-10 is based on prices and discount factors that are consistent for all entities and can be used within the industry and by securities analysts to evaluate proved reserves on a more comparable basis. The following table reconciles PV-10 to the standardized measure of discounted future net cash flows.

     
As of December 31,
2015     2014
(In thousands)
PV-10, a non-GAAP financial measure $ 442,775 $ 1,379,979
Less present value, discounted at 10% of:
Estimated asset retirement obligations (35,406 ) (34,452 )
Estimated future income tax taxes   (16,342 )   (412,614 )
Standardized measure of discounted future net cash flows, a GAAP financial measure $ 391,027   $ 932,913  

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

Copyright Business Wire 2016

Source: Business Wire (March 9, 2016 - 9:25 PM EST)

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