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Clayton Williams Energy Announces 2014 Financial Results and Year-End Reserves

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Clayton Williams Energy, Inc. (the “Company”) (NYSE:CWEI) today reported its financial results for the quarter and year ended December 31, 2014.

Highlights

Fiscal 2014

  • Oil and Gas Production of 5.8 Million BOE, up 21% pro forma
  • Adjusted Net Income1 (non-GAAP) of $56.4 million
  • EBITDA2 (non-GAAP) of $299.3 million, up 18%

Year-End 2014

  • Total Proved Reserves of 75.4 Million BOE
  • 405% of 2014 Production Replaced by Reserve Additions
  • 83% Oil and NGL and 56% Proved Developed

Financial Results for Fiscal Year 2014

The Company reported net income for fiscal 2014 of $43.9 million, or $3.61 per share, as compared to a net loss of $24.9 million, or $2.04 per share, for fiscal 2013. Adjusted net income1 (non-GAAP) for 2014 was $56.4 million, or $4.63 per share, as compared to $35 million, or $2.88 per share, for 2013. Cash flow from operations for 2014 was $258.1 million as compared to $220.6 million for 2013. EBITDA2 (non-GAAP) for 2014 was $299.3 million as compared to $254.7 million for 2013. The 2014 period included non-cash, pre-tax charges totaling $12 million to write down the carrying value of certain proved properties to their estimated fair value.

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

  • The Company sold all of its interests in certain non-core Austin Chalk/Eagle Ford assets in March 2014 and sold 95% of its Andrews County Wolfberry assets in April 2013. As a result, reported oil and gas production, revenues and operating costs for the quarter and year ended December 31, 2014 are not comparable to reported amounts for periods in 2013. See accompanying tables for additional information about the Company’s oil and gas production related to these sold assets.
  • Oil and gas sales, excluding amortized deferred revenues, increased $19.4 million in 2014 compared to 2013. Production variances accounted for an increase of $50.3 million, and price variances accounted for a decrease of $30.9 million. Average realized oil prices were $86.81 per barrel in 2014 versus $95.05 per barrel in 2013, average realized gas prices were $4.35 per Mcf in 2014 versus $3.59 per Mcf in 2013, and average realized natural gas liquids (“NGL”) prices were $32.17 per barrel in 2014 versus $33.26 per barrel in 2013. Oil and gas sales in 2014 also include $7.7 million of amortized deferred revenue versus $8.7 million in 2013 attributable to a volumetric production payment (“VPP”). Reported production and related average realized sales prices exclude volumes associated with the VPP.
  • Before giving effect to the asset sales discussed above, oil, gas and NGL production for 2014 on a barrel of oil equivalent (“BOE”) basis increased 10% compared to 2013 with oil production increasing 14% to 11,490 barrels per day, gas production decreasing 5% to 16,167 Mcf per day, and NGL production increasing 10% to 1,603 barrels per day. Oil and NGL production accounted for 83% of total production in 2014 versus 80% in 2013. See accompanying tables for additional information about the Company’s oil and gas production.
  • After giving effect to the asset sales, total production per BOE increased 21% in 2014 as compared to 2013, with oil production increasing 2,457 barrels per day (27%), gas production decreasing 206 Mcf per day (1%) and NGL production increasing 260 barrels per day (19%).
  • Production costs decreased 3% to $105.3 million in 2014 from $108.4 million in 2013 due primarily to a reduction in operating costs associated with the Austin Chalk/Eagle Ford and Andrews County Wolfberry sales, offset in part by increased production taxes related to the increase in oil and gas sales.
  • Gain on derivatives for 2014 was $4.8 million (including a $7.1 million gain on settled contracts) versus a loss in 2013 of $8.7 million (net of a $0.7 million gain on settled contracts). See accompanying tables for additional information about the Company’s accounting for derivatives.
  • Interest expense increased to $50.9 million in 2014 from $43.1 million in 2013 due primarily to the issuance in October 2013 of $250 million aggregate principal amount of 7.75% Senior Notes due 2019.
  • We recorded a provision for impairment of property and equipment during 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. During 2013, we recorded an impairment of property and equipment of $89.8 million related to the transaction to monetize our Andrews County Wolfberry assets and certain non-core Permian Basin properties to reduce the carrying value of those properties to their estimated fair values.
  • We recorded exploration expense related to abandonment and impairment costs during 2014 of $20.6 million compared to $5.9 million in 2013. 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 2014 were $34.5 million versus $33.3 million in 2013. Changes in compensation expense attributable to the Company’s APO reward plans accounted for a net increase of $2.5 million ($4.6 million in 2014 versus $2.1 million in 2013) offset by lower professional costs in 2014.

Financial Results for the Fourth Quarter of 2014

The Company reported a net loss for the fourth quarter of 2014 (“4Q14″) of $4.3 million, or $0.35 per share, as compared to net income of $6.4 million, or $0.53 per share, for the fourth quarter of 2013 (“4Q13″). Adjusted net income1 (non-GAAP) for 4Q14 was $4 million, or $0.33 per share, as compared to $7.7 million, or $0.64 per share, for 4Q13. Cash flow from operations for 4Q14 was $46.4 million as compared to $66.7 million for 4Q13. EBITDA2 (non-GAAP) for 4Q14 was $62.8 million as compared to $70.7 million for 4Q13.

The key factors affecting the comparability of financial results for 4Q14 versus 4Q13 were:

  • Oil and gas sales, excluding amortized deferred revenues, decreased $16.6 million in 4Q14 versus 4Q13. Price variances accounted for a $27.6 million decrease, and production variances accounted for an $11 million increase. Average realized oil prices were $68.04 per barrel in 4Q14 versus $92.03 per barrel in 4Q13, average realized gas prices were $3.86 per Mcf in 4Q14 versus $3.68 per Mcf in 4Q13, and average realized NGL prices were $25.90 per barrel in 4Q14 versus $35.73 per barrel in 4Q13. Oil and gas sales in 4Q14 also include $1.9 million of amortized deferred revenue versus $2.1 million in 4Q13 attributable to a VPP. Reported production and related average realized sales prices exclude volumes associated with the VPP.
  • Before giving effect to the sale of certain Austin Chalk/Eagle Ford assets in March 2014, oil, gas and NGL production per BOE increased 11% in 4Q14 as compared to 4Q13, with oil production increasing 10% to 11,967 barrels per day, gas production increasing 12% to 17,478 Mcf per day, and NGL production increasing 13% to 1,641 barrels per day. Oil and NGL production accounted for approximately 82% of the Company’s total BOE production in 4Q14 versus 83% in 4Q13. See accompanying tables for additional information about the Company’s oil and gas production.
  • After giving effect to the asset sale, oil, gas and NGL production per BOE increased 17% in 4Q14 as compared to 4Q13, with oil production increasing 1,837 barrels per day (18%), gas production increasing 1,978 Mcf per day (13%) and NGL production increasing 217 barrels per day (15%).
  • Production costs increased 12% to $28.3 million in 4Q14 from $25.2 million in 4Q13 due primarily to increased costs attributable to incremental wells on production and increased well maintenance, offset in part by reductions in production taxes due to the decrease in oil and gas sales.
  • Gain on derivatives for 4Q14 was $8.5 million (including an $11.9 million gain on settled contracts) versus a gain in 4Q13 of $1.2 million (including a $2.1 million gain on settled contracts). See accompanying tables for additional information about the Company’s accounting for derivatives.
  • We recorded a provision for impairment of property and equipment during 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.
  • We recorded exploration expense related to abandonment and impairment costs during 4Q14 of $11.9 million compared to $2.9 million in 4Q13. 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 4Q14 were $0.5 million versus $12.9 million for 4Q13. Changes in compensation expense attributable to the Company’s APO reward plans accounted for a net decrease of $10.8 million ($7.8 million credit in 4Q14 versus $3 million expense in 4Q13). The credit in 4Q14 resulted from reversals of previously accrued compensation expense due primarily to lower product prices. The remaining decrease was attributable primarily to lower professional costs in 4Q14 than in 4Q13.

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

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

Balance Sheet and Liquidity

As of December 31, 2014, total long-term debt was $704.7 million, consisting of $105 million of secured debt under a revolving credit facility and $599.7 million of 7.75% Senior Notes due 2019. The borrowing base established by the banks under the credit facility was $600 million at December 31, 2014, and the aggregate lender commitment was $500 million. Liquidity, consisting of cash plus funds available on the bank credit facility, totaled $417.1 million.

The credit facility previously contained a leverage ratio covenant that limited the Company’s consolidated indebtedness to 4.0 times annual consolidated EBITDA. The Company’s leverage ratio at December 31, 2014 was in compliance with the covenant at 2.4 times. In February 2015, the credit facility was amended to temporarily redefine the leverage ratio to limit consolidated senior debt to 2.5 times consolidated EBITDA and to add a consolidated interest coverage ratio of 1.5 times consolidated EBITDA. These temporary amendments apply to each quarterly period from January 1, 2015 through June 30, 2016.

To limit its exposure to any further declines in oil prices for the remainder of 2015, the Company entered into commodity swaps in February 2015 covering 1,737,000 barrels of oil production from May 2015 through December 2015 at an average price of $55.65 per barrel.

Reserves

The Company reported that its total estimated proved oil and gas reserves as of December 31, 2014 were 75.4 million barrels of oil equivalent (“MMBOE”), consisting of 53.9 million barrels of oil, 8.9 million barrels of NGL and 75.6 Bcf of natural gas. On a BOE basis, oil and NGL comprised 83% of total proved reserves at year-end 2014 versus 82% at year-end 2013. Proved developed reserves at year-end 2014 were 42.2 MMBOE, or 56% of total proved reserves, versus 38.3 MMBOE, or 55% of total proved reserves, at year-end 2013. 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″) remained unchanged at $1.4 billion for year-end 2014 compared to year-end 2013. 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 2014 on an MMBOE basis.

MMBOE
Total proved reserves, December 31, 2013 70.0
Extensions and discoveries 23.3
Revisions (10.1 )
Sales of reserves (2.0 )
Production (5.8 )
Total proved reserves, December 31, 2014 75.4

The Company replaced 405% of its 2014 oil and gas production through extensions and discoveries. Most of the 23.3 MMBOE of reserve additions in 2014 are attributable to the Company’s Eagle Ford and Delaware Basin programs. Oil and NGL accounted for 91.4% of the 2014 reserve additions.

The 10.1 MMBOE of net downward revisions in proved reserves resulted from a combination of (1) reclassifications of 4.9 MMBOE of proved undeveloped reserves to probable reserves due solely to the SEC 5-year development rule, (2) other net downward revisions of 4.8 MMBOE related primarily to proved undeveloped reserves associated with vertical locations in Reeves County, Texas originally assigned prior to the Company’s conversion to horizontal drilling in this area, and (3) downward revisions of 0.4 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 price for the 12-month period prior to the effective date of each reserve estimate. The benchmark averages for 2014 were $94.99 per barrel of oil and $4.35 per MMBtu of natural gas, as compared to $96.78 per barrel and $3.67 per MMBtu for 2013. 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 $90.48 per barrel of oil, $31.54 per barrel of NGL and $4.27 per Mcf of natural gas for year-end 2014, as compared to $94.88 per barrel of oil, $31.63 per barrel of NGL and $3.59 per Mcf of natural gas for year-end 2013.

Scheduled Conference Call

The Company will host a conference call to discuss these results and other forward-looking items today, February 26th at 1:30 p.m. CT (2:30 p.m. ET). The dial-in conference number is: 877-868-1835, conference ID 89149363. The replay will be available from 3:30 p.m. CT (4:30 p.m. ET) on February 26th until March 5th at 855-859-2056, conference ID 89149363.

To access the conference call via Internet webcast, please go to the “Investors” section of the Company’s website at www.claytonwilliams.com and click on the webcast link. 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 December 31, Year Ended December 31,
2014 2013 2014 2013
REVENUES
Oil and gas sales $ 86,961 $ 103,804 $ 418,330 $ 399,950
Midstream services 1,369 1,592 6,705 4,965
Drilling rig services 5,590 4,916 28,028 17,812
Other operating revenues 753 1,955 15,393 6,488
Total revenues 94,673 112,267 468,456 429,215
COSTS AND EXPENSES
Production 28,290 25,151 105,296 108,405
Exploration:
Abandonments and impairments 11,895 2,907 20,647 5,887
Seismic and other 359 365 2,314 3,906
Midstream services 564 498 2,212 1,816
Drilling rig services 4,264 3,586 19,232 16,290
Depreciation, depletion and amortization 42,114 41,039 154,356 150,902
Impairment of property and equipment 8,621 12,027 89,811
Accretion of asset retirement obligations 939 1,034 3,662 4,203
General and administrative 544 12,878 34,524 33,279
Other operating expenses 327 232 2,547 2,101
Total costs and expenses 97,917 87,690 356,817 416,600
Operating income (loss) (3,244 ) 24,577 111,639 12,615
OTHER INCOME (EXPENSE)
Interest expense (12,932 ) (12,973 ) (50,907 ) (43,079 )
Gain (loss) on derivatives 8,504 1,188 4,789 (8,731 )
Other 773 (102 ) 3,047 1,905
Total other expense (3,655 ) (11,887 ) (43,071 ) (49,905 )
Income (loss) before income taxes (6,899 ) 12,690 68,568 (37,290 )
Income tax (expense) benefit 2,632 (6,265 ) (24,687 ) 12,428
NET INCOME (LOSS) $ (4,267 ) $ 6,425 $ 43,881 $ (24,862 )
Net income (loss) per common share:
Basic $ (0.35 ) $ 0.53 $ 3.61 $ (2.04 )
Diluted $ (0.35 ) $ 0.53 $ 3.61 $ (2.04 )
Weighted average common shares outstanding:
Basic 12,170 12,165 12,167 12,165
Diluted 12,170 12,165 12,167 12,165
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands)
ASSETS
December 31, December 31,
2014 2013
CURRENT ASSETS (Unaudited)
Cash and cash equivalents $ 28,016 $ 26,623
Accounts receivable:
Oil and gas sales 36,526 39,268
Joint interest and other, net 14,550 17,121
Affiliates 322 264
Inventory 42,087 39,183
Deferred income taxes 6,911 7,581
Fair value of derivatives 2,518
Prepaids and other 4,208 5,753
132,620 138,311
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method 2,684,913 2,403,277
Pipelines and other midstream facilities 59,542 54,800
Contract drilling equipment 122,751 96,270
Other 20,915 20,620
2,888,121 2,574,967
Less accumulated depreciation, depletion and amortization (1,539,237 ) (1,375,860 )
Property and equipment, net 1,348,884 1,199,107
OTHER ASSETS
Debt issue costs, net 12,712 12,785
Investments and other 16,669 16,534
29,381 29,319
$ 1,510,885 $ 1,366,737
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade $ 93,650 $ 75,872
Oil and gas sales 41,328 37,834
Affiliates 717 874
Fair value of derivatives 208
Accrued liabilities and other 20,658 21,607
156,353 136,395
NON-CURRENT LIABILITIES
Long-term debt 704,696 639,638
Deferred income taxes 164,599 140,809
Asset retirement obligations 45,697 49,981
Deferred revenue from volumetric production payment 23,129 29,770
Accrued compensation under non-equity award plans 17,866 15,469
Other 751 892
956,738 876,559
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share
Common stock, par value $.10 per share 1,216 1,216
Additional paid-in capital 152,686 152,556
Retained earnings 243,892 200,011
Total stockholders’ equity 397,794 353,783
$ 1,510,885 $ 1,366,737
CLAYTON WILLIAMS ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
Three Months Ended December 31, Year Ended December 31,
2014 2013 2014 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (4,267 ) $ 6,425 $ 43,881 $ (24,862 )
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization 42,114 41,039 154,356 150,902
Impairment of property and equipment 8,621 12,027 89,811
Abandonments and impairments 11,895 2,907 20,647 5,887
Gain on sales of assets and impairment of inventory, net (69 ) (1,497 ) (9,138 ) (3,024 )
Deferred income tax expense (benefit) (2,859 ) 4,651 24,460 (14,042 )
Non-cash employee compensation (8,582 ) 2,404 1,397 (3,493 )
(Gain) loss on derivatives (8,504 ) (1,188 ) (4,789 ) 8,731
Cash settlements of derivatives 11,876 2,054 7,099 690
Accretion of asset retirement obligations 939 1,034 3,662 4,203
Amortization of debt issue costs and original issue discount 701 985 3,030 3,266
Amortization of deferred revenue from volumetric production payment (1,853 ) (2,107 ) (7,708 ) (8,746 )
Changes in operating working capital:
Accounts receivable 6,689 (6,975 ) 5,255 (7,163 )
Accounts payable 1,022 16,800 4,561 12,740
Other (11,347 ) 163 (619 ) 5,676
Net cash provided by operating activities 46,376 66,695 258,121 220,576
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment (110,505 ) (80,111 ) (422,473 ) (288,133 )
Proceeds from volumetric production payment 257 298 1,067 1,332
Proceeds from sales of assets (105 ) 61,858 104,529 259,799
Increase in equipment inventory (11,541 ) (6,544 ) (1,886 ) (726 )
Other 91 (146 ) (234 ) (1,315 )
Net cash used in investing activities (121,803 ) (24,645 ) (318,997 ) (29,043 )
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 72,617 225,335 102,139 268,335
Repayments of long-term debt (264,000 ) (40,000 ) (444,000 )
Proceeds from exercise of stock options 29 130 29
Net cash provided by (used in) financing activities 72,617 (38,636 ) 62,269 (175,636 )
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (2,810 ) 3,414 1,393 15,897
CASH AND CASH EQUIVALENTS
Beginning of period 30,826 23,209 26,623 10,726
End of period $ 28,016 $ 26,623 $ 28,016 $ 26,623
CLAYTON WILLIAMS ENERGY, INC.
COMPUTATION OF ADJUSTED NET INCOME (NON-GAAP)
(Unaudited)
(In thousands, except per share)
Adjusted net income 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 is not an alternative to net income (loss) presented in conformity with GAAP.
The Company defines adjusted net income as net income (loss) before changes in fair value of derivatives, abandonments and impairments of property and equipment, net gain 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 (non-GAAP):
Three Months Ended Year Ended
December 31, December 31,
2014 2013 2014 2013
Net income (loss) $ (4,267 ) $ 6,425 $ 43,881 $ (24,862 )
(Gain) loss on derivatives (8,504 ) (1,188 ) (4,789 ) 8,731
Cash settlements of derivatives 11,876 2,054 7,099 690
Abandonments and impairments 11,895 2,907 20,647 5,887
Impairment of property and equipment 8,621 12,027 89,811
Gain on sales of assets and impairment of inventory (69 ) (1,497 ) (9,138 ) (3,024 )
Amortization of deferred revenue from volumetric production payment (1,853 ) (2,107 ) (7,708 ) (8,746 )
Non-cash employee compensation (8,582 ) 2,404 1,397 (3,493 )
Tax impact (a) (5,106 ) (1,270 ) (7,033 ) (29,947 )
Adjusted net income $ 4,011 $ 7,728 $ 56,383 $ 35,047
Adjusted earnings per share:
Diluted $ 0.33 $ 0.64 $ 4.63 $ 2.88
Weighted average common shares outstanding:
Diluted 12,170 12,165 12,167 12,165
Effective tax rates 38.2 % 49.4 % 36.0 % 33.3 %
_______

(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 EBITDA (NON-GAAP)
(Unaudited)
(In thousands)
EBITDA 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. EBITDA 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 EBITDA as net income (loss) before interest expense, income taxes, exploration costs, net gain 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.
The following table reconciles net income (loss) to EBITDA:
Three Months Ended December 31, Year Ended December 31,
2014 2013 2014 2013
Net income (loss) $ (4,267 ) $ 6,425 $ 43,881 $ (24,862 )
Interest expense 12,932 12,973 50,907 43,079
Income tax expense (benefit) (2,632 ) 6,265 24,687 (12,428 )
Exploration:
Abandonments and impairments 11,895 2,907 20,647 5,887
Seismic and other 359 365 2,314 3,906
Net gain on sales of assets and impairment of inventory (69 ) (1,497 ) (9,138 ) (3,024 )
Depreciation, depletion and amortization 42,114 41,039 154,356 150,902
Impairment of property and equipment 8,621 12,027 89,811
Accretion of asset retirement obligations 939 1,034 3,662 4,203
Amortization of deferred revenue from volumetric production payment (1,853 ) (2,107 ) (7,708 ) (8,746 )
Non-cash employee compensation (8,582 ) 2,404 1,397 (3,493 )
(Gain) loss on derivatives (8,504 ) (1,188 ) (4,789 ) 8,731
Cash settlements of derivatives 11,876 2,054 7,099 690
EBITDA (a) $ 62,829 $ 70,674 $ 299,342 $ 254,656
The following table reconciles net cash provided by operating activities to EBITDA:
Net cash provided by operating activities $ 46,376 $ 66,695 $ 258,121 $ 220,576
Changes in operating working capital 3,636 (9,988 ) (9,197 ) (11,253 )
Seismic and other 359 365 2,314 3,906
Current income tax provision 227 1,614 227 1,614
Cash interest expense 12,231 11,988 47,877 39,813

$ 62,829 $ 70,674 $ 299,342 $ 254,656

______

(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 for the three months ended December 31, 2013 was $4.8 million, and for the year ended December 31, 2014 and 2013 was $2.5 million and $23.2 million, respectively. In April 2013, the Company sold 95% of its Andrews County Wolfberry assets. Revenue, net of direct expenses, associated with the sold properties for the year ended December 31, 2013 was $8.7 million.

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

Three Months Ended
December 31,

Year Ended
December 31,

2014 2013 2014 2013
Oil and Gas Production Data:
Oil (MBbls) 1,101 997 4,194 3,692
Gas (MMcf) 1,608 1,435 5,901 6,188
Natural gas liquids (MBbls) 151 133 585 532
Total (MBOE) 1,520 1,369 5,763 5,255
Total (BOE/d) 16,521 14,883 15,788 14,399
Average Realized Prices (a) (b):
Oil ($/Bbl) $ 68.04 $ 92.03 $ 86.81 $ 95.05
Gas ($/Mcf) $ 3.86 $ 3.68 $ 4.35 $ 3.59
Natural gas liquids ($/Bbl) $ 25.90 $ 35.73 $ 32.17 $ 33.26
Gain (Loss) on Settled Derivative Contracts (b):
($ in thousands, except per unit)
Oil:
Cash settlements paid $ 11,876 $ 2,142 $ 7,099 $ 1,162
Per unit produced ($/Bbl) $ 10.79 $ 2.15 $ 1.69 $ 0.31
Gas:
Cash settlements paid $ $ (89 ) $ $ (472 )
Per unit produced ($/Mcf) $ $ (0.06 ) $ $ (0.08 )
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin 2,730 2,843 3,224 2,127
Other (c) 3,162 3,843 3,286 3,952
Austin Chalk (c) 1,915 2,392 2,033 2,581
Eagle Ford Shale (c) 3,785 1,354 2,529 1,136
Other 375 405 418 319
Total 11,967 10,837 11,490 10,115
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin 2,615 2,129 2,671 1,720
Other (c) 7,209 7,167 6,932 7,963
Austin Chalk (c) 1,706 2,057 1,766 2,043
Eagle Ford Shale (c) 766 86 464 78
Other 5,182 4,159 4,334 5,149
Total 17,478 15,598 16,167 16,953
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin 366 369 449 316
Other (c) 846 809 820 880
Austin Chalk (c) 203 228 189 223
Eagle Ford Shale (c) 169 20 111 19
Other 57 20 34 20
Total 1,641 1,446 1,603 1,458
BOE:
Permian Basin Area:
Delaware Basin 3,532 3,567 4,118 2,730
Other (c) 5,209 5,847 5,261 6,159
Austin Chalk (c) 2,402 2,963 2,517 3,145
Eagle Ford Shale (c) 4,082 1,388 2,717 1,168
Other 1,296 1,118 1,175 1,197
Total 16,521 14,883 15,788 14,399
Oil and Gas Costs ($/BOE Produced):
Production costs $ 18.61 $ 18.37 $ 18.27 $ 20.63
Production costs (excluding production taxes) $ 15.71 $ 14.39 $ 14.57 $ 16.75
Oil and gas depletion $ 25.93 $ 27.78 $ 24.73 $ 26.13
______

(a) Oil and gas sales includes $1.9 million for the three months ended December 31, 2014, $2.1 million for the three months ended December 31, 2013, $7.7 million for the year ended December 31, 2014, and $8.7 million for the year ended December 31, 2013 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 24,469 barrels of oil and 11,784 Mcf of gas for the three months ended December 31, 2014, 28,045 barrels of oil and 10,030 Mcf of gas for the three months ended December 31, 2013, 102,011 barrels of oil and 45,392 Mcf of gas for the year ended December 31, 2014 and 116,941 barrels of oil and 33,619 Mcf of gas for the year ended December 31, 2013 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 2014 or 2013 derivative contracts as cash flow hedges. This means that the Company’s derivatives for 2014 and 2013 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) Following is a recap of the average daily production related to interests in producing properties sold by the Company effective March 2014 (non-core Austin Chalk/Eagle Ford) and April 2013 (Andrews County Wolfberry).

Three Months Ended
December 31,

Year Ended
December 31,

2013 2014 2013
Average Daily Production:
Austin Chalk/Eagle Ford:
Oil (Bbls) 707 93 773
Natural gas (Mcf) 98 11 121
NGL (Bbls) 22 3 25
Total (BOE) 745 98 818
Andrews County Wolfberry:
Oil (Bbls) 403
Natural gas (Mcf) 447
NGL (Bbls) 88
Total (BOE) 566

CLAYTON WILLIAMS ENERGY, INC.

SUMMARY OF EXPLORATION AND DEVELOPMENT EXPENDITURES

(Unaudited)

The following table summarizes, by area, our planned expenditures for exploration and development activities during 2015, as compared to our actual expenditures in 2014.

Actual
Expenditures
Year Ended
December 31, 2014

Planned
Expenditures
Year Ending
December 31, 2015

2015
Percentage
of Total
Planned
Expenditures

(In thousands)
Drilling and Completion
Permian Basin Area:
Delaware Basin $ 152,200 $ 34,200 32 %
Other 26,800 11,900 11 %
Austin Chalk/Eagle Ford Shale 160,200 26,400 25 %
Other 8,900 4,900 4 %
348,100 77,400 72 %
Leasing and seismic 56,200 30,000 28 %
Exploration and development $ 404,300 $ 107,400 100 %

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 February 2015, applicable to periods subsequent to December 31, 2014. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

Oil
Bbls Price
Production Period:
2nd Qtr 2015 448,000 $ 55.65
3rd Qtr 2015 697,000 $ 55.65
4th Qtr 2015 592,000 $ 55.65
1,737,000

CLAYTON WILLIAMS ENERGY, INC.

PROVED RESERVES

(Unaudited)

The following table sets forth our estimated quantities of proved reserves as of December 31, 2014 and 2013, 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, 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
December 31, 2013:
Developed 25,989 4,293 47,839 38,255
Undeveloped 22,676 4,194 29,340 31,760
Total Proved 48,665 8,487 77,179 70,015
_____

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

PV-10 remained unchanged at $1.4 billion at December 31, 2014, compared to December 31, 2013. Commodity prices used at December 31, 2014 and December 31, 2013 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 $94.99 per barrel of oil and $4.35 per MMBtu of natural gas for 2014 and $96.78 per barrel of oil and $3.67 per MMBtu for 2013. 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 $90.48 per barrel of oil, $31.54 per barrel of NGL and $4.27 per Mcf of natural gas for 2014 and $94.88 per barrel of oil, $31.63 per barrel of NGL and $3.59 per Mcf of natural gas for 2013.

PV-10 is a non-GAAP financial measure that we believe 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 standardized measure of discounted future net cash flows.

As of December 31,
2014 2013
(In thousands)
PV-10, a non-GAAP financial measure $ 1,379,979 $ 1,380,948
Less present value, discounted at 10%, of:
Estimated asset retirement obligations (34,452 ) (38,518 )
Estimated future income taxes (412,614 ) (415,507 )

Standardized measure of discounted future net cash flows, a GAAP financial measure

$ 932,913 $ 926,923

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